[Federal Register Volume 87, Number 86 (Wednesday, May 4, 2022)]
[Proposed Rules]
[Pages 26504-26611]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2022-08973]
[[Page 26503]]
Vol. 87
Wednesday,
No. 86
May 4, 2022
Part IV
Department of Energy
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Federal Energy Regulatory Commission
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18 CFR Part 35
Building for the Future Through Electric Regional Transmission Planning
and Cost Allocation and Generator Interconnection; Proposed Rule
Federal Register / Vol. 87 , No. 86 / Wednesday, May 4, 2022 /
Proposed Rules
[[Page 26504]]
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DEPARTMENT OF ENERGY
Federal Energy Regulatory Commission
18 CFR Part 35
[Docket No. RM21-17-000]
Building for the Future Through Electric Regional Transmission
Planning and Cost Allocation and Generator Interconnection
AGENCY: Federal Energy Regulatory Commission.
ACTION: Notice of proposed rulemaking.
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SUMMARY: The Federal Energy Regulatory Commission (Commission) proposes
to reform both the pro forma Open Access Transmission Tariff and the
pro forma Large Generator Interconnection Agreement to remedy
deficiencies in the Commission's existing regional transmission
planning and cost allocation requirements. Specifically, the proposal
would require public utility transmission providers to; conduct long-
term regional transmission planning on a sufficiently forward-looking
basis to meet transmission needs driven by changes in the resource mix
and demand; more fully consider dynamic line ratings and advanced power
flow control devices in regional transmission planning processes; seek
the agreement of relevant state entities within the transmission
planning region regarding the cost allocation method or methods that
will apply to transmission facilities selected in the regional
transmission plan for purposes of cost allocation through long-term
regional transmission planning; adopt enhanced transparency
requirements for local transmission planning processes and improve
coordination between regional and local transmission planning with the
aim of identifying potential opportunities to ``right-size''
replacement transmission facilities; and revise their existing
interregional transmission coordination procedures to reflect the long-
term regional transmission planning reforms proposed in this NOPR. In
addition, the proposal would not permit public utility transmission
providers to take advantage of the construction-work-in-progress
incentive for regional transmission facilities selected for purposes of
cost allocation through long-term regional transmission planning and
would permit the exercise of federal rights of first refusal for
transmission facilities selected in a regional transmission plan for
purposes of cost allocation, conditioned on the incumbent transmission
provider with the federal right of first refusal for such regional
transmission facilities establishing joint ownership of the
transmission facilities.
DATES: Comments are due July 18, 2022 and Reply Comments are due August
17, 2022.
ADDRESSES: Comments, identified by docket number, may be filed in the
following ways. Electronic filing through https://www.ferc.gov, is
preferred.
Electronic Filing: Documents must be filed in acceptable
native applications and print-to-PDF, but not in scanned or picture
format.
For those unable to file electronically, comments may be
filed by USPS mail or by hand (including courier) delivery.
[cir] Mail via U.S. Postal Service Only: Addressed to: Federal
Energy Regulatory Commission, Secretary of the Commission, 888 First
Street NE, Washington, DC 20426.
[cir] Hand (including courier) delivery: Deliver to: Federal Energy
Regulatory Commission, 12225 Wilkins Avenue, Rockville, MD 20852.
The Comment Procedures Section of this document contains more
detailed filing procedures.
FOR FURTHER INFORMATION CONTACT:
David Borden (Technical Information), Office of Energy Policy and
Innovation, 888 First Street NE, Washington, DC 20426, (202) 502-8734,
[email protected]
Noah Lichtenstein (Technical Information), Office of Energy Market
Regulation, 888 First Street NE, Washington, DC 20426, (202) 502-8696,
[email protected]
Lina Naik (Legal Information), Office of the General Counsel, 888 First
Street NE, Washington, DC 20426, (202) 502-8882, [email protected]
SUPPLEMENTARY INFORMATION:
Table of Contents
Paragraph
Nos.
I. Introduction............................................. 1
II. Background.............................................. 12
A. Historical Framework: Order Nos. 888, 890, and 1000.... 12
B. ANOPR and Technical Conference......................... 18
C. Joint Federal-State Task Force on Electric Transmission 20
D. High-Level Overview of ANOPR Comments.................. 23
III. Need for Reform........................................ 24
A. Potential Benefits of Long-Term Regional Transmission 28
Planning and Cost Allocation to Identify and Plan for
Transmission Needs Driven by Changes in the Resource Mix
and Demand...............................................
B. Unjust and Unreasonable and Unduly Discriminatory and 34
Preferential Commission-Jurisdictional Rates.............
1. The Transmission Investment Landscape Today........ 36
2. Deficiencies in the Commission's Existing Regional 47
Transmission Planning and Cost Allocation
Requirements.........................................
IV. Regional Transmission Planning.......................... 56
A. Overview of Existing Regional Transmission Planning 57
Processes................................................
1. Reliability Needs.................................. 58
2. Economic Needs..................................... 59
3. Transmission Needs Driven by Public Policy 60
Requirements.........................................
B. Comments............................................... 61
C. Proposed Reforms....................................... 64
1. Long-Term Regional Transmission Planning........... 64
a. Need for Reform................................ 64
b. Proposed Reform................................ 68
i. Development of Long-Term Scenarios For Use 79
In Long-Term Regional Transmission Planning..
(a) Comments.............................. 80
(b) Proposed Reform....................... 84
(1) Long-Term Scenarios Requirements...... 91
(i) Transmission Planning Horizon and 92
Frequency................................
(01) Comments............................. 95
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(02) Proposed Requirement................. 97
(ii) Factors.............................. 101
(01) Comments............................. 103
(02) Proposed Requirement................. 104
(iii) Number and Range of Long-Term 113
Scenarios................................
(01) Comments............................. 118
(02) Proposed Requirement................. 121
(iv) Specificity of Data Inputs........... 127
(01) Comments............................. 129
(02) Proposed Requirement................. 130
(v) Identification of Geographic Zones.... 135
(01) Comments............................. 136
(02) Proposed Requirement................. 145
ii. Coordination of Regional Transmission 154
Planning and Generator Interconnection
Processes....................................
(a) ANOPR................................. 155
(b) Comments.............................. 157
(c) Need for Reform....................... 161
(d) Proposed Reform....................... 166
iii. Evaluation of the Benefits of Regional 175
Transmission Facilities......................
(a) Evaluations of Long-Term Regional 176
Transmission Benefits....................
(1) Comments.............................. 178
(2) Proposed Reform....................... 183
(3) Description of Long-Term Regional 189
Transmission Benefits....................
(b) Evaluation of Transmission Benefits 226
Over Longer Time Horizon.................
(1) Comments.............................. 226
(2) Proposed Reform....................... 227
(c) Evaluation of the Benefits of 231
Portfolios of Transmission Facilities....
(1) Comments.............................. 232
(2) Proposed Reform....................... 233
iv. Selection of Regional Transmission 236
Facilities...................................
(a) Comments.............................. 238
(b) Proposed Reform....................... 241
c. Implementation of Long-Term Regional 253
Transmission Planning............................
2. Consideration of Dynamic Line Ratings and Advanced 256
Power Flow Control Devices in Long-Term Regional
Transmission Planning................................
a. ANOPR.......................................... 256
b. Comments....................................... 257
c. Need for Reform................................ 267
d. Proposed Reform................................ 272
V. Regional Transmission Cost Allocation.................... 278
A. Background............................................. 280
B. ANOPR.................................................. 286
C. Comments............................................... 288
D. Need for Reform........................................ 297
E. Proposed Reform........................................ 302
1. State Involvement in Cost Allocation for Long-Term 302
Regional Transmission Facilities.....................
a. Agreement of Relevant State Entities........... 304
b. State Agreement Process........................ 311
2. Time Period in Long-Term Regional Transmission 319
Planning Cost Allocation Processes for State-
Negotiated Alternate Cost Allocation Method..........
3. Identification of Benefits Considered in Cost 325
Allocation for Long-Term Regional Transmission
Facilities...........................................
VI. Construction Work in Progress Incentive................. 328
A. Background............................................. 328
B. Need for Reform........................................ 330
C. Proposed Reform........................................ 333
VII. Exercise of a Federal Right of First Refusal in 335
Commission-Jurisdictional Tariffs and Agreements...........
A. Background............................................. 337
1. Order No. 1000's Nonincumbent Transmission 337
Developer Reforms and Federal Right of First Refusal
Elimination Mandate..................................
2. Experience Since Order No. 1000.................... 343
3. ANOPR.............................................. 345
4. Comments........................................... 346
B. Need for Reform........................................ 349
C. Proposed Reform........................................ 351
1. Approach to Reform................................. 351
2. Conditional Federal Rights of First Refusal for 358
Certain Jointly-Owned Transmission Facilities........
a. Background..................................... 359
b. Comments....................................... 360
c. Proposed Reform................................ 365
VIII. Enhanced Transparency of Local Transmission Planning 383
Inputs In the Regional Transmission Planning Process and
Identifying Potential Opportunities to Right-Size
Replacement Transmission Facilities........................
A. Background............................................. 383
B. ANOPR.................................................. 387
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C. Comments............................................... 390
D. Need for Reform........................................ 398
E. Proposed Reform........................................ 400
IX. Interregional Transmission Coordination and Cost 416
Allocation.................................................
A. Background............................................. 417
B. ANOPR.................................................. 422
C. Comments............................................... 423
D. Need for Reform........................................ 424
E. Proposed Reform........................................ 426
X. Proposed Compliance Procedures........................... 430
XI. Information Collection Statement........................ 434
XII. Environmental Analysis................................. 451
XIII. Regulatory Flexibility Act [Analysis or Certification] 452
XIV. Comment Procedures..................................... 460
XV. Document Availability................................... 463
Appendix A: Abbreviated Names of Commenters
Appendix B: Pro Forma Open Access Transmission Tariff
Attachment K
Appendix C: Pro forma Large Generator Interconnection
Procedures (LGIP)
I. Introduction
1. In this Notice of Proposed Rulemaking (NOPR), the Federal Energy
Regulatory Commission (Commission) is proposing, pursuant to its
authority under section 206 of the Federal Power Act (FPA),\1\ to
reform its electric regional transmission planning and cost allocation
requirements. The proposed reforms are intended to remedy deficiencies
in the Commission's existing regional transmission planning and cost
allocation requirements to ensure that Commission-jurisdictional rates
remain just and reasonable and not unduly discriminatory or
preferential.
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\1\ 16 U.S.C. 824e. Section 206 requires that Commission-
jurisdictional rates, terms, and conditions, including those for
transmission services, be just and reasonable and not unduly
discriminatory or preferential. The phrase ``Commission-
jurisdictional rates,'' as used in this NOPR, includes rates, terms,
and conditions.
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2. This NOPR builds on Order Nos. 888,\2\ 890,\3\ and 1000,\4\ in
which the Commission incrementally developed the requirements that
govern regional transmission planning and cost allocation processes to
ensure that Commission-jurisdictional rates remain just and reasonable
and not unduly discriminatory or preferential.
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\2\ Promoting Wholesale Competition Through Open Access Non-
Discriminatory Transmission Services by Pub. Utils.; Recovery of
Stranded Costs by Publ. Utils. & Transmitting Utils., Order No. 888,
61 FR 21540 (May 10, 1996), FERC Stats. & Regs. ] 31,036 (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 Group v. FERC, 225 F.3d 667 (D.C. Cir. 2000),
aff'd sub nom. N. Y. v. FERC, 535 U.S. 1 (2002).
\3\ Preventing Undue Discrimination & Preference in Transmission
Serv., Order No. 890, 72 FR 12266 (Mar. 15, 2007), 118 FERC ]
61,119, order on reh'g, Order No. 890-A, 73 FR 2984 (Jan. 16, 2008),
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, 74 FR 12540 (Mar.
25, 2009), 126 FERC ] 61,228, order on clarification, Order No. 890-
D, 129 FERC ] 61,126 (2009).
\4\ Transmission Planning & Cost Allocation by Transmission
Owning & Operating Pub. Utils., Order No. 1000, 76 FR 49842 (Aug.
11, 2011), 136 FERC ] 61,051 (2011), order on reh'g, Order No. 1000-
A, 77 FR 32184 (May 31, 2012), 139 FERC ] 61,132, order on reh'g and
clarification, Order No. 1000 -B, 141 FERC ] 61,044 (2012), aff'd
sub nom. S.C. Pub. Serv. Auth. v. FERC, 762 F.3d 41 (D.C. Cir.
2014).
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3. With respect to regional transmission planning, as discussed in
more detail below, the reforms proposed in this NOPR would require
public utility transmission providers to conduct long-term regional
transmission planning on a sufficiently forward-looking basis to meet
transmission needs driven by changes in the resource mix and demand.\5\
As part of this long-term regional transmission planning, public
utility transmission providers would be required to: (1) Identify
transmission needs driven by changes in the resource mix and demand
through the development of long-term scenarios that satisfy the
requirements set forth in this NOPR, including accounting for low-
frequency, high-impact events such as extreme weather events; (2)
evaluate the benefits of regional transmission facilities to meet these
needs over a time horizon that covers, at a minimum, 20 years starting
from the estimated in-service date of the transmission facilities; and
(3) establish transparent and not unduly discriminatory criteria to
select transmission facilities in the regional transmission plan for
purposes of cost allocation that more efficiently or cost-effectively
address these transmission needs in collaboration with states and other
stakeholders. We do not propose in this NOPR to change Order No. 1000's
requirements for public utility transmission providers with respect to
existing reliability and economic planning requirements. Additionally,
we propose to require that public utility transmission providers more
fully consider dynamic line ratings and advanced power flow control
devices in regional transmission planning processes.
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\5\ A public utility transmission provider means a public
utility that owns, controls, or operates transmission facilities.
The term public utility transmission provider should be read to
include a public utility transmission owner when the transmission
owner is separate from the transmission provider, as is the case in
regional transmission organizations (RTO) and independent system
operators (ISO). The term ``public utility'' means ``any person who
owns or operates facilities subject to the jurisdiction of the
Commission . . . .'' 16 U.S.C. 824(e).
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4. With respect to transmission cost allocation, the reforms
proposed in this NOPR would require that public utility transmission
providers in each transmission planning region seek the agreement of
relevant state entities within the transmission planning region
regarding the cost allocation method or methods that will apply to
transmission facilities selected in the regional transmission plan for
purposes of cost allocation through long-term regional transmission
planning \6\ and revise their OATTs to include those method or methods.
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\6\ This NOPR refers to such facilities as ``Long-Term Regional
Transmission Facilities''.
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5. We also propose to not permit public utility transmission
providers to take advantage of the construction-work-in-progress (CWIP)
incentive for regional transmission facilities selected for purposes of
cost allocation through long-term regional transmission planning.
6. With respect to federal rights of first refusal, the reforms
proposed in this NOPR would amend Order No. 1000's requirements, in
part, to permit
[[Page 26507]]
the exercise of federal rights of first refusal for transmission
facilities selected in a regional transmission plan for purposes of
cost allocation, conditioned on the incumbent transmission provider
with the federal right of first refusal for such regional transmission
facilities establishing joint ownership of the transmission facilities
consistent with the proposal below.
7. With respect to transparency and coordination, we propose to
require public utility transmission providers to adopt enhanced
transparency requirements for local transmission planning processes and
improve coordination between regional and local transmission planning
with the aim of identifying potential opportunities to ``right-size''
replacement transmission facilities.
8. With respect to interregional transmission coordination and cost
allocation, the reforms proposed in this NOPR would require that public
utility transmission providers revise their existing interregional
transmission coordination procedures to reflect the long-term regional
transmission planning reforms proposed in this NOPR.
9. The proposed reforms in this NOPR related to regional
transmission planning and cost allocation requirements, like those of
Order Nos. 890 and 1000, are focused on the transmission planning
process, and not on any substantive outcomes that may result from this
process. Taken together, these proposed reforms would work together to
remedy deficiencies in the Commission's existing regional transmission
planning and cost allocation requirements. This, in turn, would fulfill
our statutory obligation to ensure that Commission-jurisdictional rates
remain just and reasonable and not unduly discriminatory or
preferential.
10. The Advance Notice of Proposed Rulemaking (ANOPR),\7\ the
Commission also sought comment on reforms related to cost allocation
for interconnection-related network upgrades, interconnection queue
processes, interregional transmission coordination and planning, and
oversight of transmission planning and costs. While this NOPR does not
propose broad or comprehensive reforms directly related to these
topics, we will continue to review the record developed to date and
expect to address possible inadequacies through subsequent proceedings
that propose reforms, as warranted, related to these topics. In
addition, concurrent with the issuance of this NOPR, we notice a
technical conference on Transmission Planning and Cost Management.
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\7\ Building for the Future Through Electric Regional
Transmission Planning & Cost Allocation & Generator Interconnection,
86 FR 40266 (July 15, 2021), 176 FERC ] 61,024 (2021) (ANOPR); see
infra P 18 (briefly summarizing the ANOPR).
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11. We seek comment on the reforms proposed herein and encourage
commenters to identify enhancements to those reforms that could better
support development of more efficient or cost-effective transmission
facilities than is the case under the Commission's existing regional
transmission planning and cost allocation requirements.
II. Background
A. Historical Framework: Order Nos. 888, 890, and 1000
12. Over the last several decades, the Commission has taken
multiple significant actions on transmission planning and cost
allocation, including issuing Order Nos. 888, 890, and 1000. In 1996,
the Commission issued Order No. 888, which implemented open access to
transmission facilities owned, operated, or controlled by a public
utility and included certain minimum requirements for transmission
planning. In 2007, the Commission issued Order No. 890 to address
deficiencies in the pro forma OATT that it identified after more than
10 years of experience since Order No. 888. Among other OATT reforms,
the Commission required all public utility transmission providers'
local transmission planning processes to satisfy nine transmission
planning principles: (1) Coordination; (2) openness; (3) transparency;
(4) information exchange; (5) comparability; (6) dispute resolution;
(7) regional participation; (8) economic planning studies; and (9) cost
allocation for new projects.\8\
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\8\ Order No. 890, 118 FERC ] 61,119 at PP 418-601.
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13. Then, in 2011, the Commission recognized the need for further
transmission planning reforms with its issuance of Order No. 1000. The
Commission based the reforms it adopted in Order No. 1000 on changes in
the energy industry, its experience implementing Order No. 890, and a
robust record developed through technical conferences and comments from
a diverse range of stakeholders.\9\ The Commission stated in Order No.
1000 that ``the electric industry is currently facing the possibility
of substantial investment in future transmission facilities to meet the
challenge of maintaining reliable service at a reasonable cost.'' \10\
In establishing the requirements of Order No. 1000, the Commission
found that the existing requirements of Order No. 890 were not
adequate, noting that Order No. 1000 ``expands upon the reforms begun
in Order No. 890 by addressing new concerns that have become apparent
in the Commission's ongoing monitoring of these matters.'' \11\ The
Commission then enumerated multiple concerns that it had regarding
existing transmission planning practices, including concerns about: (1)
The lack of an affirmative obligation to develop a transmission plan
evaluating if a regional transmission facility ``may be more efficient
or cost-effective than solutions identified in local transmission
planning processes;'' (2) the lack of a requirement to address Public
Policy Requirements; \12\ (3) the federal right of first refusal for
incumbent transmission developers to build upgrades to their existing
transmission facilities; (4) the lack of procedures to identify and
evaluate the benefits of interregional transmission facilities; and (5)
cost allocation for regional and interregional transmission
facilities.\13\
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\9\ Order No. 1000, 136 FERC ] 61,051 at P 3. The term
``stakeholder'' means any interested party. Id. P 151 n.143.
\10\ Id. P 2.
\11\ Id. P 22.
\12\ Public Policy Requirements are requirements established by
local, state or federal laws or regulations (i.e., enacted statutes
passed by the legislature and signed by the executive and
regulations promulgated by a relevant jurisdiction, whether within a
state or at the federal level). Id. P 2. Order No. 1000-A clarified
that Public Policy Requirements include local laws or regulations
passed by a local governmental entity, such as a municipal or county
government. Order No. 1000-A, 139 FERC ] 61,132 at P 319.
\13\ Order No. 1000, 136 FERC ] 61,051 at P 3.
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14. Order No. 1000 included a package of reforms to ensure that the
transmission planning and cost allocation requirements embodied in the
pro forma OATT were adequate to support the development of more
efficient or cost-effective transmission facilities.\14\ The reforms in
Order No. 1000 fell into the following categories: Regional
transmission planning; transmission needs driven by Public Policy
Requirements; nonincumbent transmission developer reforms; regional and
interregional cost allocation, including a set of principles for each
category of cost allocation; and interregional transmission
coordination. The reforms focused on the process by which public
utility transmission providers engage in regional transmission planning
and associated cost allocation rather than on the outcomes of the
process.\15\
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\14\ Id. PP 11-12, 42-44; Order No. 1000-A, 139 FERC ] 61,132 at
PP 3, 4-6.
\15\ Order No. 1000, 136 FERC ] 61,051 at P 12.
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[[Page 26508]]
15. Among other regional transmission planning reforms in Order No.
1000, the Commission required that the following Order No. 890
transmission planning principles apply to regional transmission
planning processes: (1) Coordination; (2) openness; (3) transparency;
(4) information exchange; (5) comparability; (6) dispute resolution;
and (7) economic planning studies.\16\
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\16\ The Commission did not include the regional participation
or cost allocation transmission planning principles with respect to
regional transmission planning processes because those issues were
addressed by other reforms in Order No. 1000. Id. P 151.
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16. In addition, with respect to the Order No. 1000 reforms, there
is a distinction between a transmission facility ``included'' in a
regional transmission plan and a transmission facility ``selected'' in
a regional transmission plan for purposes of cost allocation. A
transmission facility selected in a regional transmission plan for
purposes of cost allocation is a transmission facility that has been
selected pursuant to a transmission planning region's \17\ Commission-
approved regional transmission planning process for inclusion in a
regional transmission plan for purposes of cost allocation because it
is a more efficient or cost-effective transmission facility needed to
meet regional transmission needs. Both regional transmission facilities
and interregional transmission facilities are eligible for potential
``selection'' in a regional transmission plan for purposes of cost
allocation.\18\ A regional transmission facility is a transmission
facility located entirely in one transmission planning region.\19\ An
interregional transmission facility is one that is located in two or
more transmission planning regions.\20\
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\17\ A transmission planning region is one in which public
utility transmission providers, in consultation with stakeholders
and affected states, have agreed to participate for purposes of
regional transmission planning and development of a single regional
transmission plan. Id. P 160.
\18\ Id. P 63.
\19\ Id. n.374.
\20\ Id.
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17. Transmission facilities selected in a regional transmission
plan for purposes of cost allocation often will not comprise all of the
transmission facilities that are included in a regional transmission
plan.\21\ Some transmission facilities are merely ``rolled up'' and
listed in a regional transmission plan without going through an
analysis at the regional level, and therefore, are not eligible for
selection and regional cost allocation.\22\ For example, a local
transmission facility is a transmission facility located solely within
a public utility transmission provider's retail distribution service
territory or footprint that is not selected in the regional
transmission plan for purposes of cost allocation.\23\ Thus, a local
transmission facility may be rolled up and ``included'' in a regional
transmission plan for informational purposes, but it is not
``selected'' in a regional transmission plan for purposes of cost
allocation.
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\21\ Id. P 63.
\22\ Id. PP 7, 226, 318.
\23\ Id. P 63. The Commission clarified in Order No. 1000-A that
a local transmission facility is one that is located within the
geographical boundaries of a public utility transmission provider's
retail distribution service territory, if it has one; otherwise the
area is defined by the public utility transmission provider's
footprint. In the case of an RTO/ISO whose footprint covers the
entire region, a local transmission facility is defined by reference
to the retail distribution service territories or footprints of its
underlying transmission owing members. Order No. 1000-A, 139 FERC ]
61,132 at P 429.
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B. ANOPR and Technical Conference
18. In July 2021, the Commission issued an ANOPR presenting
potential reforms to improve the regional transmission planning and
cost allocation and generator interconnection processes. In issuing the
ANOPR, the Commission noted that, more than a decade after Order No.
1000, it was time to review its regulations governing regional
transmission planning and cost allocation and generator interconnection
processes to determine whether reforms are needed to ensure Commission-
jurisdictional rates remain just and reasonable and not unduly
discriminatory or preferential.\24\ The Commission noted that the
electricity sector is transforming as the generation fleet shifts from
resources located close to population centers toward resources that may
often be located far from load centers. The Commission also highlighted
the growth of new resources seeking to interconnect to the transmission
system and that the differing characteristics of those resources are
creating new demands on the transmission system. The Commission
explained that ensuring just and reasonable Commission-jurisdictional
rates as the resource mix changes, while maintaining grid reliability,
remains the Commission's priority in adopting requirements for the
regional transmission planning and cost allocation and generator
interconnection processes. As a result, the Commission issued the ANOPR
to consider whether there should be changes in the regional
transmission planning and cost allocation and generator interconnection
processes and, if so, which changes are necessary to ensure that
Commission-jurisdictional rates remain just and reasonable and not
unduly discriminatory or preferential and that reliability is
maintained.
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\24\ ANOPR, 176 FERC ] 61,024 at P 3.
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19. On November 15, 2021, the Commission convened a staff-led
technical conference (November 2021 Technical Conference or Technical
Conference) to examine in detail issues and potential reforms related
to regional transmission planning as described in ANOPR. Specifically,
the Technical Conference included three panels covering issues related
to factors to consider in long-term scenarios, consideration of longer-
term scenarios in regional transmission planning processes, and
identifying geographic zones with high renewable resource potential for
use in regional transmission planning processes.\25\ After the
Technical Conference, the Commission invited all interested persons to
file comments after the Technical Conference to address issues raised
during the Technical Conference.
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\25\ Building for the Future Through Elec. Reg'l Transmission
Planning & Cost Allocation & Generator Interconnection, Further
Supplemental Notice of Technical Conference, Docket No. RM21-17-000
(issued Nov. 12, 2021) (attaching agenda).
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C. Joint Federal-State Task Force on Electric Transmission
20. 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.\26\ The
Commission explained that the development of new transmission
infrastructure implicates a host of different issues, including how to
plan and pay for these facilities. Given that federal and state
regulators each have authority over transmission-related issues and the
impact of transmission infrastructure development on numerous different
priorities of federal and state regulators, the Commission determined
that the area is ripe for greater federal-state coordination and
cooperation.\27\ 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.\28\
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\26\ Joint Fed.-State Task Force on Elec. Transmission, 175 FERC
] 61,224, at PP 1, 6 (2021).
\27\ Id. P 2.
\28\ 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.
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[[Page 26509]]
21. The Task Force will convene for multiple formal meetings and
has thus far met twice--on November 10, 2021, and on February 16, 2022.
The discussion at the November meeting was focused on incorporating
state perspectives into regional transmission planning. The Task Force
members discussed: Whether the existing regional transmission planning
processes adequately plan for future transmission needs, including
those of states in meeting their energy-related goals; what methods are
currently employed to provide states a role in regional transmission
planning processes and whether reforms are needed to increase
consideration and incorporation of state perspectives and energy-
related goals in those processes; transparency in existing regional
transmission planning processes; and criteria for use in selecting
transmission facilities, including the proper role for states in
selection of transmission facilities identified during regional
transmission planning processes.\29\
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\29\ Joint Fed.-State Task Force on Elec. Transmission, Notice
of Meeting, Docket No. AD21-15-000 (issued Oct. 27, 2021) (attaching
agenda).
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22. The February meeting included discussion of specific categories
and types of transmission benefits that transmission providers should
consider for the purposes of transmission planning and cost allocation.
The Task Force Members discussed: Whether and how the three categories
and types of transmission (to address transmission needs driven by
reliability, economic considerations, and Public Policy Requirements)
that are considered for the purposes of transmission planning and cost
allocation should be expanded or changed; whether these categories are
being adequately considered or can be improved upon; if there any
specific benefits being considered by public utility transmission
providers today that should be more widely adopted by other public
utility transmission providers and whether certain benefits are unique
to specific regions; and how the certainty of benefits should be
addressed, such as whether and how benefits need to be quantified. The
Task Force Members also discussed at the February meeting cost
allocation principles, methodologies, and decision processes, such as
whether the current cost allocation methodologies used by public
utility transmission providers allocate costs roughly commensurate with
estimated benefits, and if not, how should this be improved; under what
set of benefits--both existing and expanded--would states be amenable
to bearing the costs of transmission that is expected to deliver those
estimated benefits to ratepayers; and whether there is sufficient
opportunity for stakeholders, including states, to collaborate in the
development and approval of cost allocation methodologies to build
consensus among and increase buy-in from stakeholders within a
transmission planning region, and if not, how this can be improved.\30\
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\30\ Joint Fed.-State Task Force on Elec. Transmission, Notice
of Meeting, Docket No. AD21-15-000 (issued Feb. 2, 2022) (attaching
agenda).
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D. High-Level Overview of ANOPR Comments
23. The Commission received many comments from a diverse set of
parties in response to the ANOPR.\31\ One hundred and seventy five
parties, including federal agencies, state regulatory commissions,
state policy makers and other state representatives, ratepayer
advocates, municipalities, RTOs/ISOs, RTO/ISO market monitors, public
utility transmission providers, transmission-dependent utilities,
electric cooperatives, municipal power providers, independent power
producers, transmission developers, generation trade associations,
transmission trade associations, industry interest groups, consumer
interest groups, energy policy and law interest groups, individual
businesses, landowners, and individuals, filed initial comments that
totaled over 4,000 pages without attachments. A similarly diverse set
of 95 parties filed reply comments that totaled nearly 2,000 pages.
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\31\ See Appendix A for a list of commenters and the abbreviated
names of commenters that are used in this NOPR.
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III. Need for Reform
24. Over the last 25 years, the Commission has undertaken a series
of significant reforms to ensure that transmission planning and cost
allocation processes result in Commission-jurisdictional rates that are
just and reasonable and not unduly discriminatory or preferential.\32\
It has now been more than a decade since Order No. 1000--the
Commission's last significant regional transmission planning and cost
allocation rule--and there is mounting evidence that the Commission's
regional transmission planning and cost allocation requirements may be
inadequate to ensure Commission-jurisdictional rates remain just and
reasonable and not unduly discriminatory or preferential. In
particular, although public utility transmission providers are required
to participate in regional transmission planning and cost allocation
processes under Order No. 1000, we are concerned that those processes
may not be planning transmission on a sufficiently long-term, forward-
looking basis to meet transmission needs driven by changes in the
resource mix and demand.
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\32\ See supra PP 12-14.
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25. As a result, the regional transmission planning and cost
allocation processes that public utility transmission providers adopted
to comply with Order No. 1000 may not be identifying the more efficient
or cost-effective transmission facilities. We are concerned that the
absence of sufficiently long-term, comprehensive transmission planning
processes appears to be resulting in piecemeal transmission expansion
to address relatively near-term transmission needs. We are concerned
that continuing with the status quo approach may cause public utility
transmission providers to undertake relatively inefficient investments
in transmission infrastructure, the costs of which are ultimately
recovered through Commission-jurisdictional rates.\33\ That dynamic may
result in transmission customers paying more than necessary to meet
their transmission needs, customers forgoing benefits that outweigh
their costs, or some combination thereof--either or both of which could
potentially render Commission-jurisdictional rates unjust and
unreasonable or unduly discriminatory or preferential. As the
Commission has an obligation under the FPA to ensure that those rates
are just and reasonable and not unduly discriminatory or preferential,
we are proposing reforms to remedy these potential deficiencies in the
Commission's existing regional transmission planning and cost
allocation requirements.
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\33\ S.C. Pub. Serv. Auth., 762 F.3d at 56-59.
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26. As explained in the next section, we believe that there are
substantial potential benefits of long-term regional transmission
planning and cost allocation to identify and plan for transmission
needs driven by changes in the resource mix and demand. But, as
explained below, expansion of the high voltage transmission system is
apparently increasingly occurring outside of the regional transmission
planning process, and in a piecemeal fashion through other avenues,
such as the generator interconnection process primarily in response to
individual (or a small cluster of) interconnection requests rather than
through regional
[[Page 26510]]
transmission planning and cost allocation processes.
27. In light of those concerns, we propose reforms to require
public utility transmission providers to conduct long-term regional
transmission planning on a sufficiently long-term, forward-looking
basis to identify and plan for transmission needs driven by changes in
the resource mix and demand. Absent such reforms, we are concerned that
meeting transmission needs driven by changes in the resource mix and
demand through short-term, piecemeal transmission expansion will result
in unjust and unreasonable and unduly discriminatory and preferential
Commission-jurisdictional rates for customers. Specifically, without
these reforms, we believe that regional transmission planning processes
are unlikely to identify the more efficient or cost-effective solutions
to transmission needs driven by changes in the resource mix and demand.
Thus, we preliminarily find that these reforms are necessary to ensure
that Commission-jurisdictional rates remain just and reasonable and not
unduly discriminatory or preferential.
A. Potential Benefits of Long-Term Regional Transmission Planning and
Cost Allocation To Identify and Plan for Transmission Needs Driven by
Changes in the Resource Mix and Demand
28. A robust, well-planned transmission system is foundational to
ensuring an affordable, reliable supply of electricity.\34\ Due to
continuing changes in both supply and demand, ongoing investment in
transmission facilities is necessary to ensure the transmission system
continues to serve load in a reliable \35\ and economically efficient
fashion. Such investments also support enhanced reliability, as larger,
more integrated transmission systems result in a diversity of supply
and demand conditions and a certain degree of redundancy that allows
the system to better withstand failures during unexpected events.\36\
Proactive, forward-looking transmission planning that considers
evolving supply and demand conditions more comprehensively can enable
potential reliability problems and economic constraints to be
identified and resolved before they affect the transmission system,\37\
which can facilitate the selection of more efficient or cost-effective
transmission facilities to meet transmission needs.
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\34\ 16 U.S.C. 824, 824d, 824e; see also U.S. DOE Comments at 2
(stating that ``strengthening and expanding existing transmission
infrastructure, particularly the development of regional and inter-
regional transmission projects, is key to continued access to
reliable, resilient, lower-cost, and clean electricity for all'').
\35\ See, e.g., Testimony of James B. Robb Before the U.S.
Senate Energy and Natural Resources Committee, Reliability,
Resiliency, and Affordability of Electric Service in the United
States Amid the Changing Energy Mix and Extreme Weather Events, at 9
(Mar. 11, 2021), https://www.nerc.com/news/Headlines%20DL/NERC%20Reliability%20Hearing%20Testimony%203-11-21%20-%20Final.pdf
(testifying that more transmission infrastructure is required to
ensure reliability and resilience of the bulk power system in light
of changing conditions); MISO Comments at 40.
\36\ U.S. DOE Comments at 18; NERC Comments at 16-17; ACORE
Comments, Ex. 4, Transmission Makes the Power System Resilient to
Extreme Weather; Mark Chupka & Pearl Donohoo-Vallett, Recognizing
the Role of Transmission in Electric System Resilience (May 2018).
\37\ MISO's Multi-Value Project (MVP) regional transmission
planning process, for example, eliminated the need for approximately
$300 million in reliability transmission facilities, resolving
reliability violations and mitigating system instability conditions,
through a forward-looking approach. Midcontinent Independent System
Operator, MTEP17 MVP Triennial Review: A 2017 review of the public
policy, economic, and qualitative benefits of the Multi-Value
Project Portfolio, at 11, 33 (Sept. 2017) (MTEP17 Review).
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29. In addition, transmission can unlock the forces of competition,
changing who can sell to whom, eliminating barriers to entry, and
mitigating market power.\38\ That, in turn, can provide a host of
benefits for customers, including cost-savings from greater access to
low-cost power and a wider range of resources.\39\ Transmission
infrastructure can also serve as a form of insurance for the
uncertainties of the future, because a more robust, integrated
transmission system has the potential to afford consumers the benefits
of competition and enhanced reliability even if supply and demand
fundamentals change over time.\40\
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\38\ Johannes Pfeifenberger et al., The Brattle Group and Grid
Strategies, Transmission Planning for the 21st Century: Proven
Practices that Increase Value and Reduce Costs, at 48-49 (Oct.
2021), https://gridprogress.files.wordpress.com/2021/10/transmission-planning-for-the-21st-century-proven-practices-that-increase-value-and-reduce-costs-7.pdf (Brattle-Grid Strategies Oct.
2021 Report); Policy Integrity Comments at 13 (citing Mohamed Awad
et al., The California ISO Transmission Economic Assessment
Methodology (TEAM): Principles and Applications to Path 26, at 3
(``A new transmission project can enhance competition by both
increasing the total supply that can be delivered to consumers and
the number of suppliers that are available to serve load.'')); PIOs
Comments at 48 (quoting F.A. Wolak, World Bank, Managing Unilateral
Market Power in Electricity, Policy Research Working Paper; No.
3691, at 8 (2005) (``Expansion of the transmission network typically
increases the number of independent wholesale electricity suppliers
that are able to compete to supply electricity at locations in the
transmission network served by the upgrade . . . .'')).
\39\ See, e.g., PJM Interconnection, L.L.C., PJM Value
Proposition (2019), https://www.pjm.com/about-pjm/~/media/about-pjm/
pjm-value-proposition.ashx (PJM's planning of resource adequacy over
a large region is estimated to result in savings of $1.2-1.8
billion.); Midcontinent Independent System Operator, Value
Proposition (2020), https://www.misoenergy.org/about/miso-strategy-and-value-proposition/miso-value-proposition/ (MISO estimates $517-
572 million in savings from more efficient use of existing assets
and $2.5-3.2 billion from reduced need for additional assets.);
Southwest Power Pool, SPP's Value of Transmission: 2021 Report and
Update (Jan. 5, 2022) (SPP estimates $382.7 million in adjusted
product costs savings in 2020 due to transmission investment.).
\40\ U.S. Dep't of Energy, National Electric Transmission
Congestion Study, at 11 (Sept. 2015) (stating transmission expansion
can strengthen and increase the flexibility of the overall network
and ``create real options to use the transmission system in ways
that were not originally envisioned''); Vikram S. Budhraja et al.,
Improving Electricity Resource Planning Processes by Considering the
Strategic Benefits of Transmission, 22 ELEC. J. 54 (Mar. 2009),
(high voltage transmission affords ``mitigation of risks as a form
of insurance against extreme events'').
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30. Given these potential benefits, it should be no surprise that
investments in more efficient or cost-effective transmission
infrastructure can yield substantial benefits to consumers.\41\ For
example, MISO's MVP transmission planning process resulted in
transmission facilities that are estimated to generate $2.20 to $3.40
of benefit per dollar invested.\42\
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\41\ See, e.g., Southwest Power Pool, The Value of Transmission
(Jan. 2016), https://www.spp.org/value-of-transmission/ (A 2016
study of 348 transmission projects in SPP constructed between 2012
and 2014 found the overall ratio of benefits to costs to be at least
3.5 to 1.); NextEra Comments at 95 (citing ACEG, Texas as a National
Model for Bringing Clean Energy to the Grid (Oct. 2017), https://cleanenergygrid.org/texas-national-model-bringing-clean-energy-grid/
) (Transmission developed due to Texas's Competitive Renewable
Energy Zone planning process estimated to save $1.7 billion each
year in production costs alone, far surpassing its $6.9 billion
cost.); Brattle-Grid Strategies Oct. 2021 Report at 4-8 & app. A
(describing evidence showing that well-planned transmission
expansion resulted in lower total cost to construct the needed
transmission facilities).
\42\ MTEP17 Review at 4.
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31. MISO achieved these benefits by proactively planning over a 20-
year period for two key drivers of transmission needs: The impacts of
changing state laws on the resource mix, and a large increase in the
number of generator interconnection requests.\43\ To mitigate the
uncertainties of such projections of need, MISO relied on scenarios to
consider a range of potential future conditions \44\ and
[[Page 26511]]
disclosed the assumptions and inputs underlying each.\45\ The MVP
process then identified a portfolio of ``no regrets'' transmission
projects that were projected to provide multiple kinds of reliability
and economic benefits under all the alternate future scenarios
studied.\46\ At each stage of the MVP process, MISO invested in
significant stakeholder engagement and collaboration, from developing
the technical parameters underlying its scenarios and the weights to
give to each, to the metrics and methodology used to evaluate the
portfolio of transmission projects.\47\
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\43\ Midcontinent Independent System Operator, RGOS: Regional
Generation Outlet Study at 2 (Nov. 19, 2010) (RGOS Study). MISO
staff and stakeholders determined that allowing the transmission
expansion needed to accommodate these requests to occur through the
generator interconnection process ``would not be an efficient means
for building a cost-effective transmission system either
immediately, over the next 5-10 year period or in the foreseeable
future beyond that time-frame.'' Id.
\44\ MISO relied on stakeholder surveys of likely renewable
energy needs over the next 20 years, and calculations of the new
generation that would be needed in order to achieve state renewable
portfolio standards by 2027. MISO also identified the location of
expected ``renewable energy zones'' with potential to achieve high
capacity factors for use in its analysis. Id. at 26-29.
\45\ See, e.g., MTEP17 Review at 16.
\46\ Id. at 13.
\47\ MISO Comments at 9.
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32. Although, as illustrated by the MVP example, transmission
infrastructure can provide significant benefits to consumers, there are
often substantial barriers to developing more efficient or cost-
effective transmission facilities. For example, as the Commission has
long recognized, ``vertically-integrated utilities do not have an
incentive to expand the grid to accommodate new entries or to
facilitate the dispatch of more efficient competitors.'' \48\ Further,
because large-scale transmission investments that geographically extend
or strengthen the integration of the transmission system are both
costly and tend to produce widespread benefits, there is significant
risk that free ridership problems inhibit their development.\49\ In any
event, the logistics alone of coordinating among multiple public
utility transmission providers within a region, seeking support across
what is often multiple state jurisdictions, and attaining sufficient
certainty over who will pay the costs of the needed transmission
facilities can thwart investments in more efficient or cost-effective
transmission expansion.\50\
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\48\ Order No. 890, 118 FERC ] 61,119 at P 57.
\49\ Order No. 1000, 136 FERC ] 61,051 at P 486.
\50\ Id. PP 498-501.
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33. We are concerned that these barriers continue to stymie
investment in more efficient or cost-effective transmission facilities.
In particular, we are concerned that public utility transmission
providers are not engaging in the type of long-term, more comprehensive
regional transmission planning and cost allocation processes--like the
process used to plan the MISO MVPs--that is necessary to increase the
likelihood that such highly beneficial transmission infrastructure is
developed. Without this kind of transmission planning and cost
allocation process, opportunities to meet transmission needs more
efficiently or cost-effectively may be lost. Customers may be forced to
pay for less efficient or cost-effective investment in transmission
facilities that, for example, achieve lower cost-benefit ratios than
would otherwise be achieved with long-term, more comprehensive regional
transmission planning and cost allocation. In short, absent reforms, we
are concerned customers may be paying more for less.
B. Unjust and Unreasonable and Unduly Discriminatory and Preferential
Commission-Jurisdictional Rates
34. The evidence suggests that sufficiently long-term, forward-
looking regional transmission planning and cost allocation to meet
transmission needs driven by changes in the resource mix and demand is
not occurring in most transmission planning regions on a regular or
consistent basis. As such, consumers may not be seeing the benefits
such as enhanced reliability, improved resource adequacy, access to
lower cost and diverse resources, and other benefits that result from
regional transmission planning and cost allocation processes that
identify, select, and allocate the costs of the more efficient or cost-
effective transmission solutions to transmission needs driven by
changes in the resource mix and demand. We preliminarily find that the
failure of existing regional transmission planning and cost allocation
processes to perform this type of transmission planning and cost
allocation is resulting in unjust, unreasonable, unduly discriminatory,
and preferential Commission-jurisdictional rates.
35. More specifically, we preliminarily find that reforms are
needed to the Commission's existing regional transmission planning and
cost allocation requirements because they fail to require public
utility transmission providers to: (1) Perform a sufficiently long-term
assessment of transmission needs; (2) adequately account on a forward-
looking basis for known determinants of transmission needs driven by
changes in the resource mix and demand; and (3) consider the broader
set of benefits and beneficiaries of transmission facilities planned to
meet those transmission needs. We believe that these deficiencies may
be resulting in unjust and unreasonable and unduly discriminatory and
preferential Commission-jurisdictional rates to the extent that they
lead to public utility transmission providers failing to identify
transmission needs driven by changes in the resource mix and demand,
failing to select more efficient or cost-effective transmission
facilities to meet those transmission needs, and failing to allocate
the costs of transmission facilities selected in the regional
transmission plan for purposes of cost allocation to meet those
transmission needs in a manner that is at least roughly commensurate
with the estimated benefits.
1. The Transmission Investment Landscape Today
36. We begin with the facts on the ground: The evidence suggests
that long-term regional transmission planning and cost allocation to
identify and plan for transmission needs driven by changes in the
resource mix and demand is not occurring in most transmission planning
regions on a regular or consistent basis. Rather, the status quo
appears to be resulting in a disproportionate share of transmission
facilities to meet transmission needs driven by changes in the resource
mix and demand being developed outside regional transmission planning
and cost allocation processes, resulting in less efficient and cost-
effective transmission development. Significant expansion of the
transmission system instead appears to occur through interconnection-
related network upgrades \51\ constructed as a result of generator
interconnection requests. Because the generator interconnection process
is not designed to consider how to more efficiently or cost-effectively
address transmission needs beyond the interconnection request(s) being
studied, it cannot achieve the economies of scale in transmission
investment needed to
[[Page 26512]]
integrate significant quantities of new generation resources while
maintaining Commission-jurisdictional rates that are just and
reasonable and not unduly discriminatory or preferential. Transmission
expansion in this incremental manner may miss the potential for more
efficient or cost-effective transmission facilities to solve
transmission needs driven by changes in the resource mix and demand, as
well as to afford system-wide benefits that may not be achieved through
piecemeal, one-off transmission upgrades. Robust long-term regional
transmission planning, on the other hand, may enable the same needs to
be met more efficiently or cost-effectively, or identify transmission
facilities that meet those same needs while generating additional
benefits. Today's incremental transmission planning may also fail to
consider opportunities to ``right size'' certain replacement
transmission facilities and thereby fail to identify the potential for
more efficient or cost-effective regional transmission facilities.
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\51\ The Commission's pro forma large generator interconnection
agreement (LGIA) defines Network Upgrades as: ``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 LGIA Art. 1 (Definitions); see also
Standardization of Generator Interconnection Agreements & Proc.,
Order No. 2003, 68 FR 49846 (Aug. 19, 2003), 104 FERC ] 61,103, at P
21 (2003) (describing network upgrades developed through the
generator interconnection process as those interconnection
facilities located at or beyond the point where the interconnection
customer's generating facility interconnects to the transmission
provider's transmission system), order on reh'g, Order No. 2003-A,
106 FERC ] 61,220, order on reh'g, Order No. 2003-B, 109 FERC ]
61,287 (2004), order on reh'g, Order No. 2003-C, 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), cert. denied, 552 U.S. 1230 (2008).
We refer to network upgrades developed through the generator
interconnection process as interconnection-related network upgrades.
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37. The problems with the status quo are evident in the dramatic
increase in recent years (and continuing upward trend) in investment in
transmission facilities through the generator interconnection process
in the form of interconnection-related network upgrades. The evidence
demonstrates a sharp growth in both the total cost of interconnection-
related network upgrades and in the cost of such upgrades relative to
generation project costs. It appears that the average cost of
interconnection-related network upgrades is increasing over time as the
transmission system is fully subscribed and demand for interconnection
service outpaces transmission investment. Recent studies of the total
cost of network upgrades needed to interconnect new generation
resources reflect this trend. In the generator interconnection study
MISO published in July 2020, MISO identified the need for nearly $2.5
billion in interconnection-related network upgrades to interconnect 9.2
GW of generation in MISO South.\52\ In MISO's 2020 interconnection
queue outlook, MISO reported that it expects new generation resources
in MISO West will need over $3 billion in interconnection-related
network upgrades and noted a similar trend in other MISO sub-
regions.\53\ In its most recent system impact study for generator
interconnection, published in April 2021, SPP identified the need for
over $4.6 billion in network upgrades to interconnect 10.4 GW of
generation.\54\
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\52\ ICF Resources, LLC, Just and Reasonable? Transmission
Upgrades Charged to Interconnecting Generators Are Delivering
System-Wide Benefits, at 2 (Sept. 9, 2021), https://acore.org/wp-content/uploads/2021/09/Just-Reasonable-Transmission-Upgrades-Charged-to-Interconnecting-Generators-Are-Delivering-System-Wide-Benefits.pdf (ICF Sept. 2021 Report) (attached to ACORE Comments as
Exhibit 5).
\53\ Americans For A Clean Energy Grid, Disconnected: The Need
for a New Generator Interconnection Policy, at 14 (Jan. 2021),
https://acore.org/wp-content/uploads/2021/01/Disconnected-The-Need-for-a-New-Generator-Interconnection-Policy-1.14.21.pdf (ACEG Jan.
2021 Interconnection Report) (attached to ACORE Comments as Exhibit
2); NextEra Comments at 16 (citing Midcontinent Independent System
Operator, 2020 Interconnection Queue Outlook, at 9 (2020), https://cdn.misoenergy.org/MISO2020InterconnectionQueueOutlook445829.pdf
(MISO 2020 Queue Outlook)).
\54\ ICF Sept. 2021 Report at 2.
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38. The dramatic increase in the cost of interconnection-related
network upgrades per kilowatt (kW) of an interconnection customer's
generating capacity may also be problematic. For example,
interconnection-related network upgrade costs in MISO West went from
approximately $300/kW in 2016 to nearly $1,000/kW in 2017.\55\ The
trend is evident in other parts of the country as well.\56\ The costs
of interconnection-related network upgrades seem to have become an
ever-growing percentage of the total capital costs of new generation
projects. According to one report, interconnection costs for new
renewable resources were less than 10% of total generation project
costs until a few years ago, but recently these costs have risen to as
much as 50-100% of the total generation project costs.\57\ At the same
time, interconnection-related network upgrades appear to have
transitioned from primarily small transmission facilities that serve
the needs of a limited number of interconnection customers to the size
and scope of what has traditionally been considered high voltage
transmission facilities. For example, interconnection-related network
upgrades have recently included demolishing and rebuilding multiple 500
kV transmission lines \58\ and constructing long, double-circuit, 765
kV transmission lines,\59\ all at significant cost to the
interconnection customer--and ultimately to consumers.
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\55\ ACEG Jan. 2021 Interconnection Report at 14; NextEra
Comments at 16 (citing MISO 2020 Queue Outlook at fig. 7).
\56\ E.g., ACEG Jan. 2021 Interconnection Report at 14 & tbl. 2
(showing that, as of 2019, interconnection costs in PJM for
constructed wind and solar projects were $19.07/kW and 61.83/kW,
respectively, as compared to a greater than 100% increase to $54/kW
and $131.90/kW, respectively, for projects newly proposed today);
NextEra Comments at 16-17 (stating that interconnection-related
network upgrade cost estimates have nearly tripled for newly
proposed wind projects, and more than doubled for solar projects in
PJM); see also ACEG Jan. 2021 Interconnection Report at 16
(illustrating an increase in average interconnection-related network
upgrade costs in NYISO from $67/kW in 2013 to $124/kW in 2019).
Compare ACEG Jan. 2021 Interconnection Report at 15 (identifying
interconnection-related network upgrade costs in 2013 in SPP as $89/
kW) with ICF Sept. 2021 Report at 2 (citing interconnection-related
network upgrade costs of $448/kW for interconnection customers
studied in SPP's system impact study published in April 2021).
\57\ ACEG Jan. 2021 Interconnection Report at 6; see also id. at
13 (stating that the rising interconnection costs of wind projects
in MISO recently reached approximately 23% of the capital cost of
the project); id. at 15 (identifying the increase in
interconnection-related network upgrade costs in SPP between 2013
and 2017 as representing an increase from around 8% to over 43% of
the capital cost of wind generation); NextEra Comments at 17
(similar).
\58\ See ACEG Jan. 2021 Interconnection Report at 15 (describing
interconnection-related network upgrades for a 120 MW solar plus
storage project in southern Virginia to interconnect to PJM that
cost as much as $12,086/kW).
\59\ See id. (describing one interconnection-related network
upgrade in SPP identified in the system impact study published in
April 2021); ICF Sept. 2021 Report at 3 (same); NextEra Comments at
17 (same).
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39. In contrast to the significant investment in transmission
facilities through the generator interconnection process, the regional
transmission planning and cost allocation processes have yielded
limited investment in regional transmission facilities. Transmission
developers in the United States invested $20 to $25 billion annually in
transmission facilities from 2013 to 2020.\60\ Yet only a limited
portion of these investments have gone toward regional transmission
facilities since Order No. 1000. In fact, investment in regional
transmission facilities in some regions has declined compared to prior
Order No. 1000.\61\ Moreover, across all the non-RTO/ISO regions, there
has not yet been a single transmission facility selected in a regional
transmission plan for purposes
[[Page 26513]]
of cost allocation since implementation of Order No. 1000.\62\
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\60\ Brattle-Grid Strategies Oct. 2021 Report at 2 (citing
Johannes Pfeifenberger & John Tsoukalis, The Brattle Group,
Transmission Investment Needs and Challenges, at slide 2 (June 1,
2021), https://www.brattle.com/wp-content/uploads/2021/10/Transmission-Investment-Needs-and-Challenges.pdf); Johannes
Pfeifenberger et al., The Brattle Group, Cost Savings Offered by
Competition in Electric Transmission: Experience to Date and the
Potential for Additional Customer Value, at 2-3 & fig.1 (Apr. 2019),
https://www.brattle.com/wp-content/uploads/2021/05/16726_cost_savings_offered_by_competition_in_electric_transmission.pdf (Brattle Apr. 2019 Competition Report).
\61\ See, e.g., Rob Gramlich & Jay Caspary, Americans for a
Clean Energy Grid, Planning for the Future, at 25 & fig. 8 (Jan.
2021) (included as Ex. 1 to ACORE Comments) (ACEG Jan. 2021 Planning
Report) (charting the annual investment in regional transmission
facilities in RTOs/ISOs from 2010 to 2018); ACORE Comments at 4
(citing Ex. 1, ACEG Jan. 2021 Planning Report at 25).
\62\ LS Power Oct. 12 Comments, app. I, at 18 & n.57; FERC,
Staff Report, 2017 Transmission Metrics, at 19 (Oct. 6, 2017),
https://www.ferc.gov/sites/default/files/2020-05/transmission-investment-metrics.pdf.
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40. The vast majority of investment in transmission facilities
since the issuance of Order No. 1000 has been in local transmission
facilities.\63\ For example, transmission investment to resolve local
needs accounted for almost 80% of total transmission investment in MISO
from 2018 to 2020.\64\ Similarly, in PJM, about two-thirds of the total
transmission investment in the region went to resolving local
needs.\65\
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\63\ See generally ACEG Jan. 2021 Planning Report at 25-26, 71
(describing investment in local transmission facilities nationwide
since implementation of Order No. 1000). In MISO, investment in
local transmission facilities went from $1.1 billion per year from
2010 to 2013, to $2.7 billion per year from 2014 to 2019. Harvard
ELI Comments at 20 & n.89; see also ACEG Jan. 2021 Planning Report
at 104 (charting MISO transmission investment by project type from
2010 to 2019); ACPA and ESA Comments at 22 (showing $247 million
invested in nine regional transmission projects versus $16.6 billion
in 2,165 local transmission projects in MISO between 2016 and 2020).
In PJM, investment in local transmission facilities went from $1.25
billion per year from 2005 to 2013, to $3.79 billion per year from
2014 to 2020. During the same time periods, investment in regional
transmission facilities decreased from $2.76 billion per year to
$1.65 billion per year. Harvard ELI Comments at 21 n.92; PIOs
Comments at 33 n.98 (citing PJM Transmission Expansion Advisory
Committee, Project Statistics (May 12, 2020)); Ari Peskoe, Is the
Utility Transmission Syndicate Forever?, 42 Energy L.J. 1, 51 n.324
(2021), https://www.eba-net.org/assets/1/6/5_-_%5BPeskoe%5D%5B1-66%5D.pdf.
\64\ Brattle-Grid Strategies Oct. 2021 Report at 2-3.
\65\ LS Power October 12 Comments, Ex. 9, at 7.
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41. This evidence runs counter to the Commission's expectation
that, in light of growing demand for transmission, the regional
transmission planning and cost allocation reforms adopted in Order No.
1000 should have resulted in investment in more efficient or cost-
effective transmission facilities over time. In Order No. 1000, the
Commission recognized a growing need for transmission investment to
ensure reliability and integrate new resources in light of industry
trends changing the demands placed on the transmission system.\66\ The
Commission concluded that increasing transmission needs amplified the
need for and importance of effective transmission planning and cost
allocation processes to identify transmission needs and select regional
transmission facilities where they are more efficient or cost-effective
than the alternatives.\67\
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\66\ See Order No. 1000-A, 139 FERC ] 61,132 at P 5.
\67\ See id.
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42. In sum, the evidence suggests that improvements to the
Commission's regional transmission planning and cost allocation
requirements may be needed to realize the full potential of the
benefits to be achieved through the planning and development of
regional transmission facilities. Today, transmission needs driven by
changes in the resource mix and demand appear to be largely addressed
outside the regional transmission process--e.g., through generator
interconnection processes--through mechanisms that are not designed to
consider regional transmission needs and identify and select the more
efficient or cost-effective transmission facility to meet those needs.
We believe that this may result in an inefficient expansion of the
transmission system to meet transmission needs driven by changes in the
resource mix and demand.
43. To the extent public utility transmission providers may not be
identifying the more efficient or cost-effective transmission
facilities needed to meet underlying transmission needs, including
needs driven by changes in the resource mix and demand, over time,
consumers may ultimately bear the costs of inefficient piecemeal
transmission expansion. Moreover, this concern may be exacerbated when
wholesale electricity rates reflect the costs of the interconnection-
related network upgrades that address needs that could have been more
efficiently or cost-effectively addressed through effective regional
transmission planning and cost allocation. Additionally, relying on
generator interconnection processes to identify transmission facilities
to address transmission needs driven by changes in the resource mix and
demand leaves other benefits on the table as well, as described
earlier,\68\ some of which are almost always (if not exclusively)
achieved through the development of regional transmission facilities
(e.g., avoiding emergency operations and lost load, especially during
extreme weather events, and increased wholesale market competition). We
preliminarily find that this paradigm results in Commission-
jurisdictional rates that are unjust and unreasonable and unduly
discriminatory and preferential.
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\68\ See supra PP 28-32.
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44. While the reforms adopted in Order No. 1000 were an important
first step towards improved regional transmission planning and cost
allocation, we preliminarily find that further reforms are necessary to
ensure that public utility transmission providers engage in regional
transmission planning and cost allocation on a sufficiently long-term,
forward-looking basis to meet transmission needs driven by changes in
the resource mix and demand. In Order No. 1000, the Commission was
focused in particular on: The lack of an affirmative obligation for
public utility transmission providers ``to develop a regional
transmission plan that reflects the evaluation of whether alternative
regional solutions may be more efficient or cost-effective than
solutions identified in local transmission planning processes;'' the
absence of a ``requirement that public utility transmission providers
consider transmission needs at the local or regional level driven by
Public Policy Requirements;'' the potential for federal rights of first
refusal to discourage investment by nonincumbent transmission
developers; the limited procedures in place for interregional
transmission coordination and cost allocation; and the failure of many
cost allocation methods ``to account for the beneficiaries of new
transmission facilities.'' \69\ Order No. 1000 was aimed at ensuring
two things: (1) That regional transmission planning processes
``consider and evaluate, on a non-discriminatory basis, possible
transmission alternatives and produce a transmission plan that can meet
transmission needs more efficiently and cost-effectively;'' and (2)
``that the costs of transmission solutions chosen to meet regional
transmission needs are allocated fairly to those who receive benefits
from them.'' \70\ To that end, the Commission adopted reforms that set
forth the minimum requirements to achieve these goals, requirements
that were noteworthy at the time and required public utility
transmission providers to expend substantial time and effort to comply.
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\69\ Order No. 1000, 136 FERC ] 61,051 at P 3.
\70\ Id. P 4. The interregional transmission coordination and
cost allocation requirements were aimed at the same objectives with
respect to possible transmission solutions located in neighboring
transmission planning regions. Id.
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45. We believe that it is time to take the next step. The
generation fleet is changing rapidly. In many cases, this is taking the
form of a shift from large, centralized resources located close to
population centers toward renewable resources (sometimes in combination
with electric storage resources) that are often, but not always,
located far from load centers where access to their fuel source, such
as the wind or the sun, is greatest.\71\ The growth in these resource
[[Page 26514]]
types is driven by many factors, including: (1) The improved economics
of certain renewable resources; \72\ (2) increased customer demand for
such resources, including among major corporations; \73\ (3) utility
commitments to procure most or all of their electricity from renewable
and/or non-emitting resources; \74\ and (4) federal, state, and local
policies incentivizing various forms of generation resources and other
technologies.\75\ Similarly, changes in electric demand and associated
load profiles are occurring as load-serving entities shift to meet
increasing needs due to the electrification of our power system as well
as new large loads associated with evolving industrial and commercial
needs such as the growth in data centers.\76\ Moreover, transmission
system operators are also increasing their reliance on regional and
interregional transmission facilities to ensure operational stability
in light of the rising share of variable resources in the resource mix
and increasingly frequent extreme weather events.\77\ Lastly, in
recognition of the benefits of regional power markets, regional
integration efforts have expanded since Order No. 1000, as illustrated
by the creation of the Western Energy Imbalance Market (EIM) and SPP
Integrated Marketplace in 2014.\78\ These changes in the resource mix
and demand, operational challenges, and increasing regional integration
increase the importance of engaging in regional transmission planning
and cost allocation to meet long-term transmission needs more
efficiently or cost-effectively.
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\71\ In its 2021 Long-Term Reliability Assessment, NERC reports
over 504 GW of nameplate capacity from new solar and wind in
development through 2031. In contrast, confirmed coal-fired,
nuclear, and natural-gas-fired retirements through the year 2026
total approximately 48.4 GW. NERC, 2021 Long-Term Reliability
Assessment, at 30, 35 (Dec. 2021).
\72\ See Lawrence Berkeley National Laboratory, Wind Energy
Technology Data Update: 2020 Edition, at 66 (Aug. 2020) (noting the
average levelized cost of wind energy for commercial wind generation
has decreased from $90 per MWh in 2009, to $35 per MWh in 2019);
Lawrence Berkeley National Laboratory, Utility-Scale Solar Data
Update: 2020 Edition, at 32 (Nov. 2020) (noting the average
levelized power purchase agreement price for utility-scale solar
generation has decreased from approximately $160 per MWh in 2009, to
approximately $40 per MWh in 2020).
\73\ See National Renewable Energy Laboratory (NREL), H2 2020
Solar Industry Update, at 31 (2021) (stating that U.S. corporate
solar contracts were up 34% annually in 2020, and 7.4 times higher
over 5 years).
\74\ See Deloitte, Insights, Utility Decarbonization Strategies,
Renew, Reshape, and Refuel to Zero, at 4 (2020) (indicating 43 of 55
utilities surveyed have emissions reductions targets and 22 have
net-zero or carbon-free electricity goals); Esther Whieldon, S&P
Global Market Intelligence, Path to net zero: 70% of biggest US
utilities have deep decarbonization targets, at 3-6 (2020)
(indicating based on a review of utilities' climate goals and
decarbonization plans that, as of December 2020, 70% of the 30
largest utilities have net-zero carbon targets, or are moving to
comply with similarly aggressive state mandates).
\75\ See Lawrence Berkeley National Laboratory, U.S. Renewables
Portfolio Standards 2021 Status Update: Early Release, at 9 (Feb.
2021) (stating renewable portfolio standards exist in 30 states and
the District of Columbia, and apply to 58% of total U.S. retail
electricity sales).
\76\ For example, the electrification of end uses that currently
rely on other energy sources is expected, under a moderate scenario
that does not factor in public policy drivers, to increase
electricity demand by 2050 to about 25% above today's level. ACEG
Jan. 2021 Planning Report at 35 (discussing National Renewable
Energy Laboratory's ``medium electrification'' case); see also AEE
Comments at 14-18 (describing local, state, and federal policies,
technical and economic trends that are leading to increased
electrification).
\77\ For example, during Winter Storm Uri in February 2021, SPP
and MISO were able to avoid major power shortfalls during the
extreme cold by importing electricity from the east. During the
event, MISO imported nearly 9,000 MW from PJM and several thousand
MW from the Tennessee Valley Authority. ACORE Comments, Ex. 4,
Transmission Makes the Power System Resilient to Extreme Weather, at
7.
\78\ Moreover, we note that efforts for further regional
integration of power markets continue today. See, e.g., Kassia
Micek, Megawatt Daily, Three Colorado utilities to join SPP's
Western Energy Imbalance Service Market (Jan. 26, 2022) (``Three
Colorado utilities announced plans to join [SPP's] Western Energy
Imbalance Service market and continue studying long-term solutions
to join or develop an organized wholesale market.'').
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46. A diverse range of stakeholders, including state and regulatory
entities,\79\ consumer interest groups,\80\ transmission owners,\81\
independent power producers,\82\ and various trade \83\ and non-
government organizations,\84\ identify the need to build on existing
regional transmission planning and cost allocation processes. A still
broader range of stakeholders acknowledge, at a minimum, that there is
scope for improvements in existing regional transmission planning and
cost allocation processes.\85\ While RTOs/ISOs defend the sufficiency
of their regional transmission planning and cost allocation processes,
all recognize the potential for reforms to respond to ongoing
developments in the electric industry \86\ and, in some instances, they
have initiated analysis and other early steps toward proposing
reforms.\87\
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\79\ See, e.g., NARUC Comments at 5 (``NARUC identifies
opportunities for reforms that may result in more efficient
transmission planning and investment to the benefit of consumers,
all while preserving jurisdictional authorities.''); NASEO Comments
at 1 (``NASEO shares the Commission's concern that the current
approach to planning and allocating the costs of transmission
facilities may lead to an inefficient, piecemeal expansion of the
transmission grid.''); NESCOE Comments at 35 (``NESCOE appreciates
the Commission's leadership in recognizing a need for longer-term
and comprehensive regional transmission analysis to account for this
changing resource mix.''); Kansas Commission Comments at 5 (stating
``the KCC believes that improvements can be made to optimize
regional transmission planning policies and proceedings'').
\80\ Iowa Consumer Advocate Comments at 1 (recognizing ``an
urgent need to review existing processes and identify opportunities
for reform'' and that failure to do so could ``negatively impact
reliability, and result in rates that are unjust and
unreasonable''); Consumers Council Comments at 3-4 (stating reforms
are ``crucial'' and that ``since Order No. 1000 was implemented,
several inefficiencies and unintended consequences have emerged in
transmission planning''); District of Columbia's Office of the
People's Counsel Comments at 2 (arguing there are ``significant
flaws'' in the regional transmission planning process in PJM).
\81\ See, e.g., NY TOs Comments at 14 (``In conclusion, the NY
TOs support the ANOPR's goals of proactive, multi-value scenario
modeling and recognize that further refinements to New York's
transmission planning processes and modeling will likely be needed
to integrate renewables and to maintain reliability.''); SoCal
Edison Comments at 3 (asserting that ``enhancements are necessary''
to CAISO's regional transmission planning structure); AEP Comments
at 2 (encouraging the Commission ``to consider broad reforms for
both transmission planning and generator interconnections'').
\82\ See, e.g., Enel Comments, attach. (Plugging In: A Roadmap
for Modernizing & Integrating Interconnection and Transmission
Planning) at 4 (arguing certain deficiencies result in inadequate
building of transmission and result in cost-inefficient solutions
for load); Northwest and Intermountain Comments at 3-4 (pointing to
limitations in existing Order No. 1000 processes and advocating
additional reforms are needed to ensure just and reasonable
transmission rates).
\83\ See, e.g., Joint Statement in Support of Large Scale
Transmission at 1 (ACORE, ACPA, ACEG, AEE, National Electrical
Manufacturers Association, and SEIA, among other signatories,
support reforms to transmission planning and cost allocation
policies); WIRES Comments at 7-18 (advocating for several reforms to
regional transmission planning and cost allocation processes, and
against others).
\84\ See, e.g., R Street Comments at 1 (stating ``planning
processes require an overhaul''); Policy Integrity Comments at 1
(arguing ``current approaches to transmission planning and cost
allocation are failing to capture [ ] large potential benefits'').
\85\ See, e.g., EPSA Comments at 2, 4 (asserting reforms will be
necessary to accommodate the evolving transmission system and
longer-term regional transmission planning is warranted); Industrial
Customers Comments at 13 (stating ``[t]o be sure, there is room for
improvement''); Northern VA Coop Comments at 2 (noting ``improvement
is possible'').
\86\ MISO Comments at 7 (arguing its transmission planning
process is serving its intended purpose but acknowledging
``improvements may be made''); SPP Comments at 9 (stating ``SPP
realized there was a need to more strategically consider broader
changes to SPP's transmission planning process''); PJM Reply
Comments at 6 (stating ``it is appropriate to enhance the long-term
planning process to consider scenario planning and the interaction
of many system enhancement drivers''); ISO-NE Comments at 26 (noting
``improvements may be needed to optimize transmission solutions for
reliability, economic, and public policy based needs''); NYISO
Comments at 2 (``NYISO sees an opportunity to build on the existing
successes of its processes and to evolve them to address current
conditions.''); CAISO Comments at 2 (supporting the goal of
enhancing regional transmission planning and generator
interconnection processes to account for the transmission needs of a
changing resource mix).
\87\ See, e.g., SPP Comments at 10 (SPP Board of Directors-
appointed team identified critical issues with existing transmission
planning process including sub-optimal transmission plans;
deficiency in collective quantification of cost-causers and
beneficiaries which create free rider situations; and failure to
consider congestion costs and other economic impacts in processes
used to identify needed upgrades.); ISO-NE Comments at 14-16
(initiating a 2050 Transmission Study at the request of ISO-NE
states and efforts to incorporate a new forward-looking, scenario-
based transmission planning tool).
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[[Page 26515]]
2. Deficiencies in the Commission's Existing Regional Transmission
Planning and Cost Allocation Requirements
47. We preliminarily find deficiencies in the Commission's existing
regional transmission planning and cost allocation requirements are
resulting in Commission-jurisdictional rates that are unjust and
unreasonable and unduly discriminatory and preferential. In particular,
we preliminarily find that the Commission's regional transmission
planning and cost allocation requirements fail to require public
utility transmission providers to: (1) Perform a sufficiently long-term
assessment of transmission needs; (2) adequately account on a forward-
looking basis for known determinants of transmission needs driven by
changes in the resource mix and demand; and (3) consider the broader
set of benefits and beneficiaries of regional transmission facilities
planned to meet those transmission needs. We believe that these
deficiencies may be resulting in unjust and unreasonable and unduly
discriminatory and preferential Commission-jurisdictional rates to the
extent that they lead public utility transmission providers to fail to
identify transmission needs driven by changes in the resource mix and
demand, select more efficient or cost-effective transmission facilities
to meet those transmission needs, and allocate the costs of
transmission facilities selected in the regional transmission plan for
purposes of cost allocation to meet those transmission needs in a
manner that is at least roughly commensurate with the estimated
benefits. We address each deficiency in turn.
48. The first deficiency--that the Commission's existing regional
transmission planning and cost allocation requirements do not require
public utility transmission providers to perform a sufficiently long-
term assessment of transmission needs--is reflected across multiple
components of existing regional transmission planning processes, from
the degree to which studies that inform assessment of transmission
needs are forward looking, to whether forward-looking assessments
actually inform selection and cost allocation of regional transmission
facilities. Existing regional transmission planning and cost allocation
processes typically look out and plan for transmission needs based on a
relatively near-term horizon. While some existing regional transmission
planning and cost allocation processes may incorporate studies or
assessments that have a longer forward-looking period, these are
typically for informational purposes and do not result in
identification of long-term regional transmission needs, assessment of
transmission alternatives to meet those needs, or selection of
transmission facilities in the regional transmission plan for purposes
of cost allocation.\88\ Such studies or assessments may be one-off,
available only upon request, or conducted at irregular intervals.\89\
Additionally, many forward-looking studies treat key variables that
affect transmission needs, such as generation additions and
retirements, as fixed over the full time horizon of the study, even
though these variables are likely to change.\90\ Such studies are
therefore unlikely to adequately assess transmission needs over the
longer-term horizon, as they do not attempt to assess the likelihood
that conditions contributing to transmission needs change.\91\
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\88\ For example, SPP is required under its tariff to conduct a
20-year study of transmission at least every five years but is
prohibited from using that study as the basis for authorizing
construction of a transmission solution. SPP Market Monitor Comments
at 4 (citing SPP, OATT, attach. O, Sec. IV.2 (8.0.0), Sec. IV.2.a)
\89\ For example, in response to state requests, ISO-NE recently
initiated a stakeholder process to respond to the problem that
``[t]he current processes do not support the performance of state-
requested transmission analysis based on state-developed scenarios,
inputs and assumptions, nor do they support transmission analysis
beyond the ten-year horizon.'' ISO-NE, Attachment K Revisions:
Extended-Term Planning, Transmission Committee, at slide 3 (Sept.
28, 2021), https://www.iso-ne.com/static-assets/documents/2021/09/a07_tc_2021_09_28_attk_ext_trans_presentation.pdf; see also
Indicated PJM TOs Comments at 25 (stating ``the PJM Tariff does not
provide concrete time windows for scenario planning'').
\90\ Policy Integrity Comments at 29.
\91\ PJM's long-term assessment of the transmission system
ostensibly considers a 15-year horizon, for example, but does not
account for changes to the generation mix beyond a 5-year period.
See PSEG Comments at 11 (stating that ``in practice only new
resources that are near the end of the interconnection queue process
and have signed an Interconnection Service Agreement are considered
in the RTEP base case''); Union of Concerned Scientists Comments at
10 & n.11 (``Generation additions are unchanged in the 15-year study
period, as the input assumption has no additional information that
would expand the set of generators included in the forecast.'').
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49. While it is reasonable for regional transmission planning and
cost allocation processes to include near-term study of the
transmission system, the absence of any longer-term assessment of
transmission needs that may form the basis for selection and cost
allocation may prevent public utility transmission providers from
considering regional transmission facilities that may be more efficient
or cost-effective in light of changing transmission needs.\92\ The
failure to assess longer-term transmission needs is particularly
problematic given the long-lead times necessary to construct large
(e.g., high voltage or long distance) transmission facilities, the
potential for economies of scale in transmission investment, and the
long life of transmission assets, which will continue to serve
transmission needs well beyond a 5- or 10-year planning horizon--all of
which suggest that relying solely on shorter-term studies may fail to
identify transmission needs and undervalue the benefits of transmission
investments to meet those needs. Moreover, the likelihood that near-
term assessments will fail to identify more efficient or cost-effective
regional transmission facilities is higher during periods, as the
sector is now experiencing, in which the need for transmission is
expected to grow considerably.\93\
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\92\ U.S. DOE Comments at 10 (stating failure to plan
transmission far enough ahead results in ``adverse implications for
system reliability, resilience, consumers' electricity rates, and
the achievement of clean energy goals''); MISO Reply Comments at 5
(``[G]iven long-term needs of an evolving system, additional
transmission is necessary to reliably serve customers now and into
the future. These challenges require immediate action and further
delay only increases the risk that system enhancements may not be in
place in the timeframe needed.'').
\93\ U.S. DOE Comments at 10 (``Relying on successive small
transmission expansion projects to meet foreseeable long-term needs
may lead to the need for expensive retrofits (at customers' expense)
at a later date. Economies of scale and network economies suggest
that an initial larger-scale buildout will often represent a lower-
cost solution.''); see also Policy Integrity Comments at 29 (citing
[Aacute]lvaro Garc[iacute]a-Cerzo et al., Robust Transmission
Network Expansion Planning Considering Non-Convex Operational
Constraints, 98 Energy Econ. (June 2021)).
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50. The second deficiency is that existing requirements fail to
ensure that public utility transmission providers adequately account on
a forward-looking basis for known determinants of transmission needs
driven by changes in the resource mix and demand. This is closely
related to the first deficiency in the sense that both relate to the
failure of the existing requirements to result in processes that
adequately plan for the foreseeable future. Orders Nos. 890 and 1000
afforded flexibility to public utility transmission providers to
determine the inputs, assumptions, and methodologies that are used in
analyses of the transmission system to identify transmission needs and
produce a regional transmission plan. In the absence of clear
standards, public utility transmission providers have adopted widely
divergent approaches to
[[Page 26516]]
determining the factors that are relevant to regional transmission
planning and addressing uncertainty in these variables. The result is
that public utility transmission providers in some transmission
planning regions do a better job than others in accounting for changes
in the resource mix and demand when performing transmission planning
studies. We are concerned that the reality is that none do so in a
manner that ensures the consideration of more efficient or cost-
effective transmission facilities to meet transmission needs driven by
changes in the resource mix and demand.
51. While we recognize the inevitable uncertainty in forecasting, a
number of factors that increasingly shape the resource mix and demand
are known in advance and have reasonably predictable effects,
especially in the aggregate. For example, the economics of new and
existing generating facilities has predictable effects on the resource
mix, including which existing generating facilities are likely to
retire and which type of new generating facility is likely to be built
to replace them. Similarly, state laws, utility integrated resource
plans and resource procurements, and other regulatory actions
necessarily implicate the resource mix and demand for Commission-
jurisdictional services.\94\ There are other known determinants of
transmission needs as well, including factors affecting electricity
demand (e.g., electrification trends, energy efficiency improvements,
and demand response deployments), the risk of extreme weather,
information derived from the generator interconnection process about
needed transmission expansion, and the locations where transmission
needs are likely to be particularly acute or concentrated because of
desirable siting conditions for new generating facilities. Yet it
appears that existing regional transmission planning processes may
undervalue or entirely omit consideration of some or all of these
factors.\95\
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\94\ See AEE Comments at 10 (explaining that the majority of
U.S. electricity customers take service from a load-serving entity
subject to legally binding requirements that affect the resource
mix).
\95\ See SPP Market Monitor Comments at 3 & n.5 (describing that
even SPP's more forward-looking scenario analysis of an emerging
technology case in its Integrated Transmission Plan presently
underestimates the actual growth of renewables so much that ``[w]ind
capacity in service today (29.8 GW) already exceeds wind levels
projected in both 2019 ITP futures that go out to 2029''); AEE
Comments at 18 (MISO projects electrification effect on load in its
long-term regional transmission planning, but how other transmission
providers account for electrification trends is not consistent or
transparent.); Brattle-Grid Strategies Oct. 2021 Report at 36
(stating that production cost simulations that are typically used to
estimate the economic benefit of regional transmission facilities
assumes no extreme weather events); U.S. DOE Comments, app. B
(National Laboratories 's Supplemental Information to Comments of
Department of Energy to Advance Notice of Proposed Rulemaking
(ANOPR)) at 79 (stating an array of tools exist to identify and
analyze high-value zones).
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52. We believe that engaging in regional transmission planning
without adequate consideration of such factors may be leading to
transmission investment that is not more efficient or cost-effective
and, in turn, Commission-jurisdictional rates that are unjust and
unreasonable and unduly discriminatory and preferential.\96\ We believe
that this deficiency may delay planning for the transmission system's
changing operational needs until shortly before those needs manifest,
despite the fact that the continued shift in the resource mix and
changes in demand can be reasonably forecast based on known factors. As
explained above, the lack of sufficient long-term transmission planning
appears to be resulting in significant transmission investment in
recent years occurring through generator interconnection processes to
satisfy near-term transmission needs, resulting in piecemeal
development of transmission facilities that may not more efficiently or
cost-effectively meet transmission needs driven by changes in the
resource mix and demand. We expect the problems created by this
deficiency to only grow more acute as the factors that impact the
resource mix and demand are poised to continue increasing in their
impact on transmission needs.
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\96\ NERC Comments at 17-18 (``Coordination and better certainty
around anticipated future resource mix during transmission planning
and interconnection studies could improve reliability assessments
associated with the changing resource mix[.]''); ACPA and ESA
Comments at 29 (claiming the current approach ``delays overall
investment in the transmission system''); AEE Comments at 8 (arguing
existing transmission planning processes' failure to capture
``documented and predictable trends in electricity demand and
threats to the reliability, resilience, and sufficiency of the bulk
electricity system'' warrant reforms).
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53. The third potential deficiency is that public utility
transmission providers may not identify a sufficiently broad set of
benefits--and beneficiaries--associated with regional transmission
facilities planned to meet transmission needs driven by changes in the
resource mix and demand. Failing to adequately identify and consider
the benefits of such transmission facilities may lead to sub-optimal or
inefficient investment therein. In particular, the cost-benefit
analyses that are used as part of the selection process may fail to
identify more efficient or cost-effective transmission facilities for
selection in the regional transmission plan for purposes of cost
allocation because they provide an inaccurate portrayal of the
comparative benefits of different transmission facilities. In addition,
by not considering an expanded set of benefits and beneficiaries, cost
allocation methods may fail to assign the costs of such facilities to
beneficiaries in a manner that is at least roughly commensurate with
the benefits they derive from them.\97\
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\97\ Ill. Commerce Comm'n v. FERC, 576 F.3d 470, 477 (7th Cir.
2009). Order No. 1000, 136 FERC ] 61,051 at PP 622, 639 (requiring
costs of regional transmission facilities to be allocated in a
manner that is at least roughly commensurate with estimated
benefits).
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54. We recognize that, in addressing these deficiencies, the
Commission would be requiring public utility transmission providers to
plan on a longer-term and more comprehensive basis. As discussed below,
we acknowledge that such transmission planning may entail a more
complex set of considerations compared to existing regional
transmission planning requirements, which, in turn, may increase the
importance of ensuring that the cost allocations method for projects
identified and developed through these processes are perceived as
fair.\98\ As discussed below, we are proposing to address these
concerns in part through greater state involvement, particularly in the
development of cost allocation methods.
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\98\ See infra P-235- .
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55. In sum, we preliminarily find that the deficiencies in the
Commission's existing regional transmission planning and cost
allocation requirements that we identify in this NOPR are resulting in
Commission-jurisdictional rates that are unjust and unreasonable and
unduly discriminatory and preferential. To address the enumerated
deficiencies and ensure that Commission-jurisdictional rates are just
and reasonable and not unduly discriminatory or preferential, we
propose reforms to these requirements, as described in detail in the
sections that follow.
IV. Regional Transmission Planning
56. We preliminarily find that reforms to public utility
transmission providers' regional transmission planning processes are
necessary to ensure that Commission-jurisdictional rates are just and
reasonable and not unduly discriminatory or preferential. As discussed
below, the regional transmission planning reforms proposed in this NOPR
would require that public utility transmission providers conduct
regional transmission planning on a
[[Page 26517]]
sufficiently long-term, forward-looking basis to identify and plan for
transmission needs driven by changes in the resource mix and demand. As
part of this long-term regional transmission planning, public utility
transmission providers would be required, in coordination with states,
to: (1) Identify transmission needs driven by changes in the resource
mix and demand through the development of long-term scenarios that
satisfy the requirements set forth in this NOPR; (2) evaluate the
benefits of regional transmission facilities to meet identified
transmission needs driven by changes in the resource mix and demand
over a time horizon that covers, at a minimum, 20 years starting from
the estimated in-service date of the transmission facilities; and (3)
establish transparent and not unduly discriminatory criteria to select
regional transmission facilities in the regional transmission plan for
purposes of cost allocation that more efficiently or cost-effectively
address these transmission needs driven by changes in the resource mix
and demand. Additionally, we propose to require that public utility
transmission providers more fully consider dynamic line ratings and
advanced power flow control devices in regional transmission planning
processes.
A. Overview of Existing Regional Transmission Planning Processes
57. Public utility transmission providers currently plan their
transmission systems to meet reliability, economic, and Public Policy
Requirements needs identified through their regional transmission
planning process, consistent with Order Nos. 890 and 1000.\99\ The next
few paragraphs provide a brief overview of how public utility
transmission providers currently conduct regional transmission
planning.
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\99\ ANOPR, 176 FERC ] 61,024 at P 13.
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1. Reliability Needs
58. Public utility transmission providers within transmission
planning regions conduct planning studies to help ensure the ability of
the transmission system to meet minimum performance requirements under
a variety of contingencies to provide reliable service to customers.
These studies cover the near-term, which is years 1 through 5, and the
long-term, which covers years 6 through year 10 and beyond.\100\ Long-
term transmission planning varies by public utility transmission
provider; for example, studies conducted by RTOs/ISOs may range 10, 15,
to 20 years \101\ into the future depending on the transmission
planning region's regional transmission planning process and test for
violations of established North American Electric Reliability
Corporation (NERC) reliability requirements.\102\ Additional regional
and local reliability criteria may also apply in specific transmission
planning regions. In order to meet applicable reliability planning
criteria, the regional transmission planning process focuses on
studying and producing a transmission system that is robust enough to
withstand a range of probable contingencies (e.g., the sudden loss of a
generator or higher-voltage transmission facilities) while reliably
serving customer demand and preventing cascading outages.\103\
Generally, public utility transmission providers identify areas of the
transmission system that they predict will not be in compliance with
reliability criteria and develop plans to achieve compliance. Public
utility transmission providers examine potential transmission
facilities to mitigate identified reliability criteria violations for
their feasibility, impact, and comparative costs, culminating in a
recommended regional transmission plan.\104\
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\100\ NERC,Glossary of Terms Used in NERC Reliability Standards
(June 28, 2021), https://www.nerc.com/pa/Stand/Glossary%20of%20Terms/Glossary_of_Terms.pdf.
\101\ Long-term planning for reliability by RTO/ISO varies as
follows: CAISO at least 10 years (CAISO, CASIO eTariff, Sec. 24.2
(Nature of the Transmission Planning Process) (6.0.0)); ISO-NE
between 5 and 10 years (ISO-NE, Transmission, Markets and Services
Tariff, attach. K (Regional System Planning Process) (27.0.0), Sec.
3.3 (RSP Planning Horizon and Parameters))); MISO maximum of 20
years (MISO, FERC Electric Tariff, attach. FF (Transmission
Expansion Planning Protocol) (85.0.0), Sec. I.C.8.a)); NYISO years
4 through 10 (NYISO, NYISO Tariffs, NYISO OATT, Sec. 31.1, attach.
Y (New York Comprehensive System Planning Process) (26.0.0)); PJM 10
years (PJM, Intra-PJM Tariffs, OA Schedule 6, Sec. 1.4 (Contents of
the Regional Transmission Expansion Plan) (2.1.0), Sec. 1.4.b));
and, SPP 10 and 20 years (Southwest Power Pool, Inc., OATT, attach.
Y, Sec. III (The Integrated Transmission Planning Assessment)
(8.0.0), Sec. IV (Other Planning Studies) (8.0.0)).
\102\ For example, Reliability Standard TPL-001-4 requires that
Transmission Planners conduct an annual planning assessment of their
region's portion of the bulk electric system and document summarized
results of the steady state analyses, short circuit analyses, and
stability analyses. TPL-001-4 also requires that Transmission
Planners conduct these analyses using a model of their systems
operating under a wide variety of potential conditions to see under
what, if any, conditions the system will fail to meet reliability
criteria. TPL-001-4 lays out the variety of these conditions,
including system peak, off-peak, single contingency, multiple
contingencies (both sequential and simultaneous), severe
contingencies on adjacent systems, sensitivity analyses to
underlying model assumptions, and extreme events. Transmission
Planner is defined as ``the entity that develops a long-term
(generally one year and beyond) plan for the reliability (adequacy)
of the interconnected bulk electric transmission systems within its
portion of the Planning Authority area.'' NERC, Glossary of Terms
Used in NERC Reliability Standards (June 28, 2021), https://www.nerc.com/pa/Stand/Glossary%20of%20Terms/Glossary_of_Terms.pdf.
\103\ The regional transmission planning process will identify
the necessary transmission system facilities (which have varying
costs and lead times for when they can be placed into service) that
are needed to achieve reliable transmission system operations.
\104\ ANOPR, 176 FERC ] 61,024 at P 14.
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2. Economic Needs
59. Public utility transmission providers within transmission
planning regions also plan transmission facilities to meet economic
needs. In Order No. 1000, the Commission recognized that Order No. 890
placed no affirmative obligation on public utility transmission
providers to perform economic planning studies absent a request by
stakeholders.\105\ To remedy this deficiency, the Commission required
in Order No. 1000 that, in addition to economic planning studies
requested by stakeholders, public utility transmission providers
evaluate, through a regional transmission planning process and in
consultation with stakeholders, regional transmission facilities that
might meet the needs of the transmission planning region more
efficiently or cost-effectively than transmission facilities identified
by individual public utility transmission providers in their local
transmission planning process.\106\ These regional transmission
facilities could include transmission facilities needed to meet
reliability requirements, address economic considerations, and/or meet
transmission needs driven by Public Policy Requirements.\107\ As Order
No. 890 explains, the purpose of economic transmission planning is to
plan transmission to alleviate congestion through the integration of
new generation resources or an expansion of the regional transmission
system, by an amount that justifies its cost, usually by a defined
threshold.\108\ Examples of regional transmission facilities driven by
economic needs include transmission facilities that relieve historical
or projected transmission congestion and allow lower-cost power to flow
to consumers.
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\105\ Order No. 1000, 136 FERC ] 61,051 at PP 3, 81, 147.
\106\ Id. P 148.
\107\ Id. PP 147-148.
\108\ Order No. 890, 118 FERC ] 61,119 at P 549.
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3. Transmission Needs Driven by Public Policy Requirements
60. In Order No. 1000, the Commission required public utility
transmission providers to consider transmission needs driven by Public
Policy Requirements in their local and regional transmission planning
[[Page 26518]]
processes.\109\ However, the requirement in Order No. 1000 to consider
transmission needs driven by Public Policy Requirements is limited, and
the Commission provided public utility transmission providers with
flexibility in how to meet the requirement. For example, Order No. 1000
does not require that a separate class of transmission facilities be
created in the regional transmission planning process to address
transmission needs driven by Public Policy Requirements,\110\ nor does
it mandate the consideration of any particular transmission need driven
by a Public Policy Requirement.\111\ In addition, while Order No. 1000
requires that public utility transmission providers consider
transmission needs driven by Public Policy Requirements proposed by
stakeholders, it provides flexibility on how active public utility
transmission providers themselves choose to be in identifying such
needs.\112\ As a result, the process for identifying and considering
transmission needs driven by Public Policy Requirements varies from
transmission planning region to transmission planning region.
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\109\ Order No. 1000, 136 FERC ] 61,051 at PP 203, 222; Order
No. 1000-A, 139 FERC ] 61,132 at P 208.
\110\ Order No. 1000, 136 FERC ] 61,051 at P 220 (explaining
that the requirements in Order No. 1000 related to transmission
needs driven by Public Policy Requirements are intended to ``provide
flexibility for public utility transmission providers to develop
procedures appropriate for their local and regional transmission
planning processes'').
\111\ Id. P 215.
\112\ Order No. 1000-A, 139 FERC ] 61,132 at P 322.
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B. Comments
61. In response to the ANOPR, the Commission received many comments
on the need to reform regional transmission planning processes. Many
comments support long-term regional transmission planning.\113\ Some
transmission developers and incumbent public utility transmission
providers support efforts to reform aspects of existing regional
transmission planning processes, with some recommending that the
Commission impose prescriptive planning requirements.\114\ Some state
commissions and consumer advocates also support the need to reform
regional transmission planning processes, but express concern about
potential costs and ensuring that such costs are allocated commensurate
with estimated benefits.\115\
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\113\ E.g., CAISO Comments at 5; MISO Comments at 41; ISO-NE
Comments at 23; NYISO Comments at 26-28; PJM Comments at 3-4; SPP
Comments at 6; AEP Comments at 4; Ameren Comments at 5; BP Comments
at 3-4; Exelon Comments at 2; National Grid Comments at 4; NextEra
Comments at 56; PG&E Comments at 2; Indicated PJM TOs Comments at 3;
PSEG Comments at 10-11; SDG&E Comments at 2; SCE Comments at 3-4;
Shell Comments at 7; VEIR Comments at 14; Xcel Comments at 19-20;
WIRES Comments at 7; EDP Renewables Comments at 4; EDF Comments at
5; EPSA Comments at 6; ITC Comments at 4; New England for Offshore
Wind Comments at 1; Certain TDUs Comments at 7; ACORE Comments at 6;
ACPA and ESA Comments at 44; AEE Comments at 3; EEI Comments at 12-
14; Consumers Council Comments at 9; Harvard ELI Comments at 33;
Nature Conservancy Comments at 2-3; PIOs Comments at 60; Resale Iowa
Comments at 14; REBA Comments at 17; NARUC Comments at 6; California
Public Utility Commission Comments at 5; Michigan Commission
Comments at 2-3; Minnesota Department of Commerce Comments at 5; New
Jersey Commission Comments at 10-11; District of Columbia Office of
the People's Counsel Comments at 22-23; Oregon Public Utility
Commission Comments at 1; NEPOOL Comments at 6-7; SPP RSC Comment at
2; NASUCA Comments at 4; Iowa Office Of Consumer Advocate Comments
at 2; Massachusetts Attorney General Comments at 2; State of
Massachusetts Comments at 2; NESCOE Comments at 5-6; NASEO Comments
at 1-2; City of New York Comments at 4; APPA Comments at 9; American
Municipal Power Comments at 33-34; California Municipal Utilities
Association Comments at 7; Public Systems Comments at 17; U.S. DOE
Comments at 12, 16; Association of Fish and Wildlife Agencies
Comments at 3; see also ACEG Reply Comments, app. A (identifying 174
entities supporting planning for a future resource mix).
\114\ For example, AEP, SoCal Edison, and NextEra support a 20-
year planning horizon. AEP Comments at 1-2, 7-8; SoCal Edison
Comments at 4; NextEra Comments at 70, 79-80. Exelon, PSEG, and
NextEra support requirements for public utility transmission
providers to include state statutes and goals in their scenarios.
Exelon Comments at 12-20; PSEG Comments at 3-6; NextEra Comments at
80. LS Power and Resale Iowa support a requirement that all
facilities above 100 kV be regionally planned. LS Power Oct. 12
Comments at 49-60; Resale Iowa Comments at 8. NextEra supports
requiring public utility transmission providers to use an expanded
set of transmission benefits and to designate renewable energy
development zones. NextEra Comments at 92-101. Avangrid supports
requiring public utility transmission providers to plan for offshore
wind development. Avangrid Comments at 21-23.
\115\ District of Columbia's Office of the People's Counsel
Comments at 1-5; NARUC Comments at 5-7, 46-47; NASUCA Comments at 3-
5; Iowa Consumer Advocate Comments at 2.
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62. Some RTOs/ISOs assert that their current regional transmission
planning processes already incorporate many of the potential reforms
discussed in the ANOPR and ask that the Commission provide sufficient
flexibility and avoid being too prescriptive should it undertake those
reforms.\116\ ISO-NE states that forward-looking scenario planning is
underway in ISO-NE and asks that the Commission not require a one-size-
fits-all approach.\117\ NYISO urges the Commission to consider that in
NYISO, incremental, yet meaningful, reforms can implement many of the
goals of the ANOPR, and asks that the Commission recognize the need for
regional variation so that each RTO/ISO can improve its regional
transmission planning process in light of its regional needs.\118\
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\116\ CAISO Comments at 3-5; MISO Comments at 2-4.
\117\ ISO-NE Comments at 2, 13-16.
\118\ NYISO Comments at 2-4.
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63. The market monitors express mixed views on more comprehensive
or long-term transmission planning. The PJM Market Monitor expresses a
concern around the lack of certainty and quality of additional
information being included in regional transmission planning that may
impose additional uncertainty on the regional transmission planning
process.\119\ Potomac Economics expresses concern regarding mandating
long-term regional transmission planning that requires public utility
transmission providers to speculate on certain future conditions, but
notes improvements could be made to the regional transmission planning
process to account for near-term emerging trends that are less
uncertain than longer-term factors.\120\ In contrast, the SPP Market
Monitor expresses a concern that SPP's regional transmission planning
process is not planning for generation resources of the future.\121\
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\119\ PJM Market Monitor Comments at 2-3.
\120\ Potomac Economics Comments at 4.
\121\ SPP Market Monitor Comments at 4.
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C. Proposed Reforms
1. Long-Term Regional Transmission Planning
a. Need for Reform
64. We are concerned that existing regional transmission planning
processes may not be planning on a sufficiently long-term, forward-
looking basis to meet transmission needs driven by changes in the
resource mix and demand, leading to the piecemeal and inefficient
development of new transmission facilities in a manner that is not more
efficient or cost-effective. As discussed above, existing regional
transmission planning processes typically look out and plan for
transmission needs based on a relatively short time horizon.\122\ While
some existing regional transmission planning processes may incorporate
studies or assessments that have a longer forward-looking period, these
are typically for informational purposes and do not result in
identification of long-term regional transmission needs, assessment of
transmission alternatives to meet
[[Page 26519]]
those needs, or selection of transmission facilities in the regional
transmission plan for purposes of cost allocation.\123\ In lieu of such
a long-term outlook, transmission needs driven by changes in the
resource mix and demand are largely addressed through generator
interconnection processes.\124\ However, such processes are not
designed to evaluate the need for larger, regional transmission
facilities to address transmission needs driven by changes in the
resource mix and demand, resulting in a piecemeal expansion of the
electric transmission system.
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\122\ Supra Need for Reform: Unjust and Unreasonable and Unduly
Discriminatory and Preferential Commission-Jurisdictional Rates. For
example, PJM's Regional Transmission Expansion Plan (RTEP) baseline
assessment looks out over a 5-year period, the NorthernGrid Regional
Transmission Plan has a 10-year planning horizon, and SPP's
Integrated Transmission Plan (ITP) also addresses a 10-year horizon.
\123\ See infra P 94.
\124\ See supra P 36.
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65. Implementation challenges associated with long-term
transmission planning--such as determining the appropriate time
horizon, selecting a set of factors to forecast the future resource mix
and demand, and choosing the appropriate method to account for
uncertainty--make it unlikely that public utility transmission
providers will engage in such transmission planning voluntarily and
regularly. However, such challenges do not diminish the importance of
long-term transmission planning. Moreover, even if long-term regional
transmission planning is performed, failing to consider an adequate
time horizon, set of factors to forecast the future resource mix and
demand, and sufficient method to account for uncertainty--may result in
transmission planning that is inadequate in identifying more efficient
or cost-effective transmission facilities due a less comprehensive and
accurate understanding of the areas impacted by transmission needs
driven by changes in the resource mix and demand. Accordingly, we
believe that reforms may be necessary to require public utility
transmission providers to identify transmission needs driven by changes
in the resource mix and demand.
66. We are also concerned that existing regional transmission
planning requirements may be inadequate to ensure that public utility
transmission providers adequately assess the benefits of regional
transmission facilities planned to meet transmission needs driven by
changes in the resource mix and demand. In Order No. 1000, the
Commission declined to prescribe particular definitions of or a uniform
approach to identifying benefits and beneficiaries, in order to allow
flexibility for public utility transmission providers to develop cost
allocation methods for their transmission planning regions.\125\
However, transmission facilities may provide a wide variety of benefits
to transmission customers, particularly for regional transmission
facilities addressing large, systemic changes in the electric industry.
We recognize that when public utility transmission providers fail to
consider a broader set of benefits for transmission facilities meeting
transmission needs driven by changes in the resource mix and demand,
they may fail to select transmission facilities in their regional
transmission plans for purposes of cost allocation that meet the
transmission planning region's transmission needs more efficiently or
cost-effectively.
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\125\ Order No. 1000, 136 FERC ] 61,051 at PP 624-625.
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67. As described in the ANOPR, existing regional transmission
planning and cost allocation processes generally examine categories of
transmission needs separately from one another based on the driver of
the relevant transmission need, be it reliability, economic
considerations, or Public Policy Requirements.\126\ As a general
matter, public utility transmission providers only calculate the set of
benefits specific to that category of transmission need for purposes of
determining whether a regional transmission facility meets the criteria
for selection. However, the literature and experience demonstrates a
panoply of benefits beyond those currently considered by all public
utility transmission providers in existing regional transmission
planning and cost allocation processes.\127\ Failing to provide for the
allocation of costs of transmission facilities selected in a regional
transmission plan for purposes of cost allocation to address
transmission needs driven by changes in the resource mix and demand in
a way that aligns with a reasonable set of benefits through the
transmission planning process could lead to needed transmission
facilities not being built, adversely affecting ratepayers.
Accordingly, we propose a list of benefits for public utility
transmission providers to consider when assessing a broader set of
benefits during long-term regional transmission planning, and require
public utility transmission providers to provide certain information,
as described below, about the benefits they will use.
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\126\ ANOPR, 176 FERC ] 61,024 at P 85.
\127\ See generally Paul L. Joskow, Facilitating Transmission
Expansion to Support Efficient Decarbonization of the Electricity
Sector, Economics of Energy & Environmental Policy, Vol. 10, No. 2
(June 2021); Johannes Pfeifenberger et al., The Value of
Diversifying Uncertain Renewable Generation through the Transmission
System, Boston University Institute for Sustainable Energy (Sept. 1,
2020); Johannes Pfeifenberger et al., The Brattle Group, Toward More
Effective Transmission Planning: Addressing the Costs and Risks of
an Insufficiently Flexible Electricity Grid (Apr. 2015); Judy Chang
et al., The Brattle Group, The Benefits of Electric Transmission:
Identifying and Analyzing the Value of Investments (2013).
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b. Proposed Reform
68. To help to ensure just and reasonable and not unduly
discriminatory or preferential Commission-jurisdictional rates, we
propose to require that public utility transmission providers
participate in a regional transmission planning process that includes
Long-Term Regional Transmission Planning,\128\ meaning regional
transmission planning on a sufficiently long-term, forward-looking
basis to identify transmission needs driven by changes in the resource
mix and demand, evaluate transmission facilities to meet such needs,
and identify and evaluate transmission facilities for potential
selection in the regional transmission plan for purposes of cost
allocation as the more efficient or cost-effective transmission
facilities to meet such needs.
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\128\ For example, two features of Long-Term Regional
Transmission Planning included in these proposed reforms are the
development of scenarios with a 20-year planning horizon to be
reassessed and revised every three years, with each such re-
assessment providing the basis for identification and evaluation of
transmission facilities for potential selection in the regional
transmission plan for purposes of cost allocation.
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69. As discussed further below, we propose several specific
requirements on how public utility transmission providers would be
required to implement the requirement to conduct Long-Term Regional
Transmission Planning. Specifically, we propose to require that public
utility transmission providers in each transmission planning region:
(1) Identify transmission needs driven by changes in the resource mix
and demand through the development of Long-Term Scenarios \129\ that
satisfy the requirements set forth in this NOPR; (2) evaluate the
benefits of regional transmission facilities to meet these needs over a
time horizon that covers, at a minimum, 20 years starting from the
estimated in-service date of the transmission facilities; and (3)
establish transparent and not unduly discriminatory criteria to select
transmission facilities in the regional transmission plan for purposes
of cost
[[Page 26520]]
allocation that more efficiently or cost-effectively address these
transmission needs in collaboration with states and other stakeholders.
We discuss each of these requirements in greater detail below.
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\129\ We use the term Long-Term Scenarios in this NOPR to
describe a tool to identify transmission needs driven by changes in
the resource mix and demand, and enable the evaluation of
transmission facilities to meet such needs, across multiple
scenarios that incorporate different assumptions about the future
electric power system over a sufficiently long-term, forward-looking
transmission planning horizon.
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70. Taken together, these proposed requirements would establish a
more comprehensive and proactive approach to regional transmission
planning, ensuring that public utility transmission providers plan for
transmission needs driven by changes in the resource mix and demand.
The Long-Term Regional Transmission Planning proposed in this NOPR is
meant to require regional transmission planning based on a multitude of
drivers of long-term transmission needs, as detailed below, and result
in selection of more efficient or cost-effective transmission
facilities in the regional transmission plan for purposes of cost
allocation to meet those needs.
71. We recognize that benefits from transmission facilities may
change over time due to the inherent uncertainty in Long-Term Regional
Transmission Planning and actual use of transmission facilities. We
note that long-term benefits may be more stable or evenly distributed
over time if they are evaluated for a portfolio of transmission
facilities rather than for a single transmission facility. We propose
to provide public utility transmission providers with the flexibility
to propose to use a portfolio approach in the evaluation of benefits
and selection of transmission facilities in the regional transmission
plan for purposes of cost allocation through their Long-Term Regional
Transmission Planning, as discussed below in this NOPR.
72. The reforms proposed in this NOPR inevitably interact with the
existing regional transmission planning and cost allocation processes
required by Order No. 1000 to more efficiently or cost-effectively meet
transmission needs driven by the transmission planning region's
reliability, economic, and Public Policy Requirements. With respect to
transmission needs associated either with maintaining reliability or
for addressing economic considerations and their associated cost
allocation, we do not propose in this NOPR to change Order No. 1000's
requirements for public utility transmission providers to create a
regional transmission plan that will identify transmission facilities
that more efficiently or cost-effectively meet the region's reliability
and economic requirements.\130\ In other words, public utility
transmission providers may continue to rely on their existing regional
transmission planning and cost allocation processes to comply with
Order No. 1000's requirements related to transmission needs driven by
reliability concerns or economic considerations.
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\130\ See Order No. 1000, 136 FERC ] 61,051 at P 11.
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73. With respect to transmission needs driven by Public Policy
Requirements, while we do not propose to change the existing Order No.
1000 requirement to consider transmission needs driven by Public Policy
Requirements in the regional transmission planning process,\131\ we
propose to clarify that public utility transmission providers will
comply with this existing Order No. 1000 requirement through the Long-
Term Regional Transmission Planning that we propose to require in this
NOPR. Specifically, we propose that public utility transmission
providers would be deemed to comply with the existing Order No. 1000
requirement to consider transmission needs driven by Public Policy
Requirements in their regional transmission planning process through
the proposed requirement to conduct Long-Term Regional Transmission
Planning. As discussed in the Factors section below, we propose to
require that public utility transmission providers incorporate state or
federal laws or regulations, meaning enacted statutes (i.e., passed by
the legislature and signed by the executive) and regulations
promulgated by a relevant jurisdiction, whether within a state or at
the federal level,\132\ that affect the future resource mix and demand
into the development of Long-Term Scenarios. Thus, we preliminarily
find that under the reforms proposed herein, public utility
transmission providers that comply with the Long-Term Regional
Transmission Planning requirements established in any final rule in
this proceeding will comply with the requirement in Order No. 1000 that
they participate in a regional transmission planning process that
considers, and has associated cost allocation provisions related to,
transmission needs driven by Public Policy Requirements.
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\131\ See id. PP 203-224 (discussing the requirement to consider
transmission needs driven by Public Policy Requirements in regional
transmission planning processes). This proposal would also leave
unchanged the existing requirement for public utility transmission
providers to consider transmission needs driven by Public Policy
Requirements in their local transmission planning processes.
\132\ See id. P 2.
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74. That said, we understand that public utility transmission
providers in some transmission planning regions have developed
processes to consider transmission needs driven by Public Policy
Requirements through their regional transmission planning processes
that they may wish to retain. Therefore, we propose to allow public
utility transmission providers to propose to continue using some or all
aspects of the existing regional transmission planning and cost
allocation processes they use to consider transmission needs driven by
Public Policy Requirements. However, such continued use of existing
regional transmission planning and cost allocation processes would not
supplant public utility transmission providers' obligations to comply
with the Long-Term Regional Transmission Planning requirements
established in any final rule in this proceeding. Moreover, in their
filing to comply with any final rule, public utility transmission
providers seeking to retain existing regional transmission planning and
cost allocation processes to consider transmission needs driven by
Public Policy Requirements through their regional transmission planning
processes would have to demonstrate that continued use of any such
processes does not interfere or otherwise undermine the Long-Term
Regional Transmission Planning that we propose to require in this NOPR
by demonstrating that continued use of such processes is consistent
with or superior to any final rule issued in this proceeding.
75. Finally, we preliminarily find that public utility transmission
providers could propose a regional transmission planning process that
plans for reliability needs, economic needs, transmission needs driven
by Public Policy Requirements, and transmission needs driven by changes
in the resource mix and demand simultaneously through a combined
approach. Public utility transmission providers proposing to address
all such transmission needs in a single regional transmission planning
process would bear the burden of demonstrating continued compliance
with Order No. 1000 in addition to compliance with the requirements of
any final rule in this proceeding; to do so, they would be required to
demonstrate that such process is consistent with or superior to the
requirements of both Order No. 1000 and any final rule issued in this
proceeding.
76. Further, we propose to require that Long-Term Regional
Transmission Planning comply with the following existing Order Nos. 890
and 1000 transmission planning principles: (1) Coordination; (2)
openness; (3) transparency; (4) information exchange;
[[Page 26521]]
(5) comparability; and (6) dispute resolution.\133\
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\133\ See id. PP 146, 151.
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77. We seek comment on the requirements proposed in this section of
the NOPR. In particular, we seek comment on the proposed requirement
for public utility transmission providers to participate in a regional
transmission planning process that includes Long-Term Regional
Transmission Planning.
78. As part of this Long-Term Regional Transmission Planning, we
propose to require that public utility transmission providers identify
transmission needs driven by changes in the resource mix and demand
through the development of Long-Term Scenarios that satisfy the
specific requirements that we more fully enumerate below. We propose
that public utility transmission providers: (1) Use a transmission
planning horizon no less than 20 years into the future in developing
Long-Term Scenarios and reassess and revise those scenarios at least
once every three years; (2) incorporate into their Long-Term Scenarios
a set of Commission-identified categories of factors that may drive
transmission needs driven by changes in the resource mix and demand;
(3) develop a plausible and diverse set of at least four Long-Term
Scenarios; (4) use ``best available data'' in developing their Long-
Term Scenarios; and (5) consider whether to identify geographic zones
with the potential for development of large amounts of new generation.
i. Development of Long-Term Scenarios for Use in Long-Term Regional
Transmission Planning
79. In the ANOPR, the Commission expressed concern that regional
transmission planning processes may not adequately model future
scenarios to ensure that those scenarios incorporate sufficiently long-
term and comprehensive forecasts of future transmission needs.\134\ The
Commission stated that, to the extent that regional transmission
planning processes consider generation development in scenario
analyses, they tend to include in their baseline reliability model only
those generators that have completed facilities studies, and thus are
far along in the generator interconnection process and will likely come
online in the short term.\135\ The Commission stated that such a short-
term outlook may under-forecast longer-term transmission needs and that
more efficient or cost-effective transmission facilities that address
longer-term needs may never be developed.\136\ The Commission sought
comment on whether reforms are needed regarding how the regional
transmission planning processes model scenarios to ensure they
incorporate sufficiently long-term and comprehensive forecasts of
future transmission needs.\137\
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\134\ ANOPR, 176 FERC ] 61,024 at P 31.
\135\ Id.
\136\ Id. P 47.
\137\ Id. P 46.
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(a) Comments
80. Many commenters responding to the ANOPR support scenario
planning.\138\ All RTOs/ISOs express support for long-term scenario-
based planning as a current or future practice; some request that the
Commission allow for regional flexibility.\139\ SERTP states that its
``bottom-up'' regional transmission planning process already assesses a
multitude of scenarios as part of each public utility transmission
provider's integrated resource planning process and that it could
perform additional, hypothetical scenario planning to inform decision
makers.\140\
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\138\ E.g., ACEG Comments at 5; ACPA and ESA Comments at 46-47;
AEE Comments at 36; AEP Comments at 9-11; Ameren Comments at 5; APPA
Comments at 7-9; Arizona Commission Comments at 2; Avangrid Comments
at 11-12; Certain TDUs Comments at 11; Consumers Council Comments at
8-9; Union of Concerned Scientists Comments at 42; East Kentucky
Comments at 4-7; EDF Comments at 3; EEI Comments at 24-26;
Eversource Comments at 8; Exelon Comments at 11-19; Massachusetts
Attorney General Comments at 13; NARUC Comments at 10-11; National
Grid Comments at 11-17; Nature Conservancy Comments at 2-5; NESCOE
Comments at 39-40; New England for Offshore Wind Comments at 2;
NextEra Comments at 70-83; Northwest and Intermountain Comments at
6-8; Oregon Commission Comments at 1; PG&E Comments at 5-6; PIOs
Comments at 76-81; Indicated PJM TOs Comments at 24-26; Policy
Integrity Comments at 25-40; PSEG Comments at 6-18; Resale Iowa
Comments at 14; SAFE Comments at 11; SDG&E Comments at 3-4; Shell
Comments at 7; State Agencies Comments at 21; State of Massachusetts
Comments at 10-15; Tenaska Comments at 12-13; U.S. DOE Comments at
21-22; WIRES Comments at 7-8; VEIR Comments at 13-17; Xcel Comments
at 19-20.
\139\ CAISO Comments at 42-44; MISO Comments at 7, 49; SPP
Comments at 7; NYISO Comments at 27-31; PJM Comments at 41-42, 45-
46; ISO-NE Comments at 13-17, 20-22.
\140\ See SERTP Comments at 8, 14-17; SERTP Reply Comments at
11.
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81. Many public utility transmission providers support the idea of
scenario planning.\141\ Most of these public utility transmission
providers support targeted reforms that specify guardrails, or
baselines, in scenario planning. For example, some public utility
transmission providers list the minimum set of factors they think
should be included in a scenario planning requirement.\142\ Other
public utility transmission providers support scenario planning so long
as it is strictly informational, limited, or non-binding.\143\ Some
public utility transmission providers equate scenario planning to their
existing integrated resource plans.\144\
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\141\ E.g., AEP Comments at 9-11; Ameren Comments at 5;
Eversource Comments at 8; Exelon Comments at 11-19; National Grid
Comments at 11-17; NextEra Comments at 70-83; PG&E Comments at 5-6;
PSEG Comments at 6-18; SDG&E Comments at 3-4; Xcel Comments at 19-
20.
\142\ E.g., National Grid Comments at 4-9; Exelon Comments at
12-16.
\143\ E.g., Southern Comments at 36-37; Arizona Public Service
Comments at 2-4; Xcel Comments at 20.
\144\ E.g., Berkshire Comments at 12-13.
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82. NARUC supports scenario planning as a means to evaluate the
system needs to integrate state-directed resources.\145\ Other state
commissions and state representatives express their support for
scenario planning as necessary to identify system needs and
transmission facilities to address them.\146\ A few state commissions
do not support the Commission imposing specific scenario planning
requirements, or only support the Commission providing guardrails,
because they believe state regulatory officials in collaboration with
public utility transmission providers are in the best position to
evaluate the needs of each region or because they believe the current
processes work sufficiently well.\147\ The PJM Market Monitor and
Potomac Economics do not comment specifically on use of scenarios, but
acknowledge the uncertainty associated with transmission planning and
accuracy of inputs into the transmission planning process.\148\ The SPP
Market Monitor states that one of its biggest challenges related to the
transmission planning process has been persuading stakeholders to adopt
an additional scenario as part of SPP's 10-year Integrated Transmission
Planning Assessment.\149\
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\145\ NARUC Comments at 6, 10-11.
\146\ E.g., Arizona Commission Comments at 2; Oregon Commission
Comments at 8-9; Massachusetts Attorney General Comments at 5-15.
\147\ E.g., Mississippi Commission Comments at 3; Nebraska
Commission Comments at 3-4; Michigan Commission Comments at 7.
\148\ PJM Market Monitor Comments at 2-3; Potomac Economics
Comments at 3-4; see also Joint Fed.-State Task Force on Elec.
Transmission, Technical Conference, Docket No. AD21-15-000, Tr.
59:17-24 (Andrew French) (Nov. 10, 2021) (November Joint Task Force
Tr.) (commenting that in SPP, futures projections of renewables have
``probably not been based on data or reality'' but ``have been more
of a consensus of what stakeholders are willing to accept'' with the
result being that those projects have been too low).
\149\ SPP Market Monitor Comments at 3.
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83. Several consumer and trade organizations support scenario
planning to assess uncertainty about future
[[Page 26522]]
transmission needs.\150\ Some commenters call for a national uniform
framework for scenario planning.\151\
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\150\ E.g., ACEG Comments at 5; ACPA and ESA Comments at 46; AEE
Comments at 36; APPA Comments at 4; Business Council for Sustainable
Energy Comments at 4; Union of Concerned Scientists Comments at 42-
44; Consumers Council Comments at 8-9; Iowa Consumer Advocate
Comments at 32; Nature Conservancy Comments at 3; WIRES Comments at
7.
\151\ See, e.g., NARUC Comments at 17; PIOs Comments at 103;
Policy Integrity Comments 29-40; U.S. DOE Comments at 33.
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(b) Proposed Reform
84. We propose to require that public utility transmission
providers develop and use Long-Term Scenarios as part of Long-Term
Regional Transmission Planning. We propose to define Long-Term
Scenarios as a tool to identify transmission needs driven by changes in
the resource mix and demand--and enable the evaluation of transmission
facilities to meet such transmission needs--across multiple scenarios
that incorporate different assumptions about the future electric power
system over a sufficiently long-term, forward-looking transmission
planning horizon. A scenario is a hypothetical sequence of events that
includes assumptions used to forecast transmission needs. Assumptions
used to forecast transmission needs driven by changes in the resource
mix and demand include: Forecasts of the level and pattern (i.e.,
hourly and seasonal variability) of future electricity demand; the
quantity, location, and type of resource additions and retirements; and
other relevant forecasts about the electric power system that are used
as inputs to the transmission model and determine the need for new
transmission facilities over the transmission planning horizon. Other
relevant assumptions might include forecasts for natural gas prices,
increasing outage trends due to extreme weather and climatic trends,
and other future events. We also propose to require that public utility
transmission providers use Long-Term Scenarios to evaluate potential
regional transmission facilities needed to meet transmission needs
driven by changes in the resource mix and demand to identify the more
efficient or cost-effective regional transmission facilities.
85. In the next section of this NOPR, we propose specific
requirements that public utility transmission providers would need to
meet in developing Long-Term Scenarios. We propose to require each
public utility transmission provider to amend the regional transmission
planning process in its OATT to explicitly describe the open and
transparent process that it will use to develop Long-Term Scenarios
that meet these requirements.
86. We preliminarily find that requiring public utility
transmission providers to develop and utilize multiple Long-Term
Scenarios, as further specified below, as part of Long-Term Regional
Transmission Planning will allow public utility transmission providers
to identify and plan to more efficiently or cost-effectively meet
transmission needs driven by changes in the resource mix and demand.
Specifically, we believe that using Long-Term Scenarios in the regional
transmission planning process will help public utility transmission
providers to account for the inherent uncertainty involved in
identifying transmission needs driven by changes in the resource mix
and demand and evaluating more efficient or cost-effective transmission
facilities needed to meet those needs.
87. As discussed above, Long-Term Regional Transmission Planning is
critical to ensuring more efficient or cost-effective transmission
development to meet transmission needs driven by changes in the
resource mix and demand.\152\ However, such transmission planning
necessarily relies on forecasts of future system conditions, such as
the state of the resource mix and the level of demand. These conditions
may be reasonably predictable in the near term, but as the transmission
planning horizon extends further into the future, they become
increasingly imprecise. By utilizing multiple Long-Term Scenarios,
public utility transmission providers will have a better understanding
of potential future transmission needs under multiple reasonably likely
scenarios, allowing them to assess the implications of changing market
conditions and policies. They can also manage uncertainties about
future system conditions and better identify more efficient or cost-
effective regional transmission facilities by evaluating which
transmission facilities are beneficial under multiple scenarios. Doing
so will mitigate the risks of under-building or over-building
transmission facilities that are identified through Long-Term Regional
Transmission Planning.
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\152\ Supra Need for Reform: Potential Benefits of Long-Term
Regional Transmission Planning and Cost Allocation to Identify and
Plan for Transmission Needs Driven by Changes in the Resource Mix
and Demand.
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88. We preliminarily find that the development of Long-Term
Scenarios as part of the regional transmission planning process will
ensure that public utility transmission providers adequately assess the
potential benefits of regional transmission facilities that may meet
the needs of a transmission planning region more efficiently or cost-
effectively than transmission planning without Long-Term Scenarios. We
preliminarily find that a regional transmission planning process that
does not develop Long-Term Scenarios that meet the requirements
described below fails to properly identify transmission needs driven by
changes in the resource mix and demand, which may lead to piecemeal and
inefficient development of new transmission facilities. In addition, we
preliminarily find that failing to develop Long-Term Scenarios means
that transmission facilities needed to meet transmission needs driven
by changes in the resource mix and demand are more likely to be
identified in the generator interconnection process instead of the
regional transmission planning process, similarly leading to the
increased potential for piecemeal and inefficient transmission
development, as described above.\153\ For these reasons, we
preliminarily find that requiring public utility transmission providers
to develop Long-Term Scenarios that meet the requirements described
below will ensure that Commission-jurisdictional rates are just and
reasonable and not unduly discriminatory or preferential.
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\153\ Supra Need for Reform: Deficiencies in the Commission's
Existing Regional Transmission Planning and Cost Allocation
Requirements.
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89. We clarify that we do not propose to require that public
utility transmission providers use Long-Term Scenarios in their
regional transmission planning processes to address near-term
reliability and economic transmission needs. In other words, we do not
propose to require that public utility transmission providers modify
their existing regional transmission planning processes that plan for
reliability and economic transmission needs to incorporate Long-Term
Scenarios.
90. We seek comment on the requirements proposed in this section of
the NOPR. In particular, we seek comment on whether public utility
transmission providers should be required to incorporate some form of
scenario analysis into their existing reliability and economic regional
transmission planning processes to identify more efficient or cost-
effective transmission facilities than are identified through those
processes today.
(1) Long-Term Scenarios Requirements
91. We propose to require that public utility transmission
providers comply with specified minimum requirements in developing
Long-Term Scenarios,
[[Page 26523]]
which we preliminarily find will help to ensure Long-Term Regional
Transmission Planning results in Commission-jurisdictional rates that
are just and reasonable and not unduly discriminatory or preferential.
We expect these proposed minimum requirements will allow public utility
transmission providers to better identify transmission needs driven by
changes in the resource mix and demand and evaluate regional
transmission facilities to more efficiently or cost-effectively meet
those needs. Specifically, as discussed further below, we propose to
require that public utility transmission providers: (1) Use a
transmission planning horizon no less than 20 years into the future in
developing Long-Term Scenarios and reassess and revise those scenarios
at least once every three years; (2) incorporate a set of Commission-
identified categories of factors that may affect transmission needs
driven by changes in the resource mix and demand into their Long-Term
Scenarios; (3) develop a plausible and diverse set of at least four
Long-Term Scenarios; (4) use ``best available data'' (as defined in the
Specificity of Data Inputs section below) in developing their Long-Term
Scenarios; and (5) consider whether to identify geographic zones with
the potential for development of large amounts of new generation.
(i) Transmission Planning Horizon and Frequency
92. The transmission planning horizon is the number of years into
the future that public utility transmission providers look when
developing Long-Term Scenarios. For example, a transmission planning
horizon of 20 years means that the public utility transmission provider
develops Long-Term Scenarios to identify and plan to meet transmission
needs that will materialize up to 20 years in the future. We believe
that, to be just and reasonable, the transmission planning horizon used
in Long-Term Regional Transmission Planning should extend far enough
into the future that public utility transmission providers can identify
transmission needs that could be met with more efficient or cost-
effective regional transmission facilities, i.e., the transmission
planning horizon should capture the longer-term benefits of addressing
transmission needs driven by changes in the resource mix and demand.
93. In addition, we believe that the Long-Term Scenarios used in
Long-Term Regional Transmission Planning should not remain static over
time. Instead, they should be periodically re-evaluated and re-
developed to ensure that they reflect recent forecasts of future system
conditions. Frequency is how often public utility transmission
providers reassess whether the data inputs and factors included in
their previously developed Long-Term Scenarios need to be updated and
then revise their Long-Term Scenarios as needed to reflect updated data
inputs and factors. Reassessing and revising scenarios is appropriate
as technology, markets, and factors that affect the future resource mix
and demand change. Frequent scenario reassessment and revision could
help address some of the uncertainty and risks associated with under-
building or over-building transmission facilities over a long-term
transmission planning horizon. However, developing scenarios can be
costly and time-consuming for both public utility transmission
providers and their stakeholders. Frequent scenario reassessment and
revision might also be unnecessary if the data inputs and factors into
scenario development do not change much over the time period between
studies. Thus, we believe that there may be a need to balance the
benefits of updating Long-Term Scenarios with the burdens associated
with such updates when deciding how frequently to do so. In order to
prevent overlap of Long-Term Scenarios that are developed every three
years, we also propose to require that the development of Long-Term
Scenarios be completed within three years--i.e., before the next three-
year assessment commences.
94. Based on our review of public information and ANOPR comments,
our understanding is that some transmission planning regions currently
use longer-term transmission planning horizons for regional
transmission planning. For instance, CAISO selects transmission
facilities in its regional transmission plan for purposes of cost
allocation based on a 10-year transmission planning horizon and
recently initiated an effort to conduct informational high-level
technical studies with a 20-year horizon as part of its regional
transmission planning process.\154\ NYISO uses a 20-year transmission
planning horizon to evaluate scenarios in its regional transmission
planning process for transmission needs driven by Public Policy
Requirements and for its Outlook.\155\ However, NYISO uses a 10-year or
shorter transmission planning horizon for its regional transmission
planning process for reliability and economic needs. SPP conducts its
Integrated Transmission Planning Assessment with a 10-year transmission
planning horizon and conducts an informational 20-year assessment using
scenarios every five years.\156\ MISO's current Long Range Transmission
Planning effort uses a 20-year transmission planning horizon.\157\ PJM
uses a 15-year transmission planning horizon for its long-term analysis
as part of its regional transmission planning processes.\158\ All other
transmission planning regions currently use a 10-year transmission
planning horizon for their regional transmission planning
processes,\159\ consistent with NERC's definition of the Long-Term
Transmission Planning Horizon.\160\ ISO-NE has stated that it plans to
use a longer transmission planning horizon in future transmission
planning studies.\161\ We understand that transmission planning regions
that currently use scenarios with longer-term transmission planning
horizons (longer than 10 years) typically do so only for informational
purposes or in a limited application and not commonly to select
transmission facilities in regional transmission plans for purposes of
cost allocation.
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\154\ CAISO Comments at 44-46.
\155\ NYISO Comments at 10, 36-37. The Outlook is a report by
which NYISO summarizes the current assessments, evaluations, and
plans in its biennial Comprehensive System Planning Process;
produces a 20-year projection of congestion on the New York State
Transmission System; identifies, ranks, and groups congested
elements; and assesses the potential benefits of addressing the
identified congestion. See id. at 10.
\156\ SPP Comments at 3; SPP, OATT, attach. O, Sec. IV.2
(4.0.0), Sec. IV.2.a.
\157\ MISO Comments at 36.
\158\ PJM Comments at 41.
\159\ E.g., Southeastern Regional Transmission Planning, 2021
Regional Transmission Planning Analyses, at 2 (Nov. 17, 2021),
https://www.southeasternrtp.com/docs/general/2021/2021-SERTP-Regional-Transmission-Planning-Analyses-Summary-Final.pdf;
WestConnect Regional Transmission Planning, 2020-21 Planning Cycle
Final Regional Study Plan, at 7 (Mar. 18, 2020), https://doc.westconnect.com/Documents.aspx?NID=18668&dl=1; NorthernGrid,
Regional Transmission Plan for the 2020-2021 NorthernGrid Planning
Cycle, at 5 (Dec. 8, 2021), https://www.northerngrid.net/private-media/documents/2020-2021_Regional_Transmission_Plan.pdf.
\160\ See NERC, Glossary of Terms Used in NERC Reliability
Standards (June 28, 2021), https://www.nerc.com/files/glossary_of_terms.pdf (defining Long-Term Transmission Planning
Horizon as the ``[t]ransmission planning period that covers years
six through ten or beyond when required to accommodate any known
longer lead time projects that may take longer than ten years to
complete'').
\161\ ISO-NE Comments at 13-17.
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(01) Comments
95. Comments in response to the ANOPR support a range of possible
transmission planning horizons, from five years to beyond 30 years.
Some commenters claim that a transmission planning horizon of 10 years
is sufficient because that is typically
[[Page 26524]]
enough time to identify, design, and build needed transmission
facilities or because it is consistent with NERC standards and some
state integrated resource plans.\162\ Other commenters claim that a
longer transmission planning horizon, most frequently 20 years, is
needed to appropriately identify and plan for future transmission
needs.\163\ Commenters that support a longer transmission planning
horizon commonly also support shorter-term interim assessments.
Panelists at the November 2021 Technical Conference that supported a
specific transmission planning horizon contended that a 20-year
transmission planning horizon is appropriate because that transmission
planning horizon may be needed for siting, permitting, and construction
of transmission facilities or because states have longer-term policy
goals.\164\ Some panelists stated that such a transmission planning
horizon should be used in informational studies and that a shorter
transmission planning horizon (e.g., 10 years) should be used to select
transmission facilities, while other panelists stated that public
utility transmission providers should use a 20-year or greater
transmission planning horizon to select transmission facilities.\165\
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\162\ E.g., Exelon Comments at 16-17; NRECA Comments at 19-20.
Similarly, ITC supports a 5 to 10-year transmission planning
horizon. ITC Comments at 12-13.
\163\ For example, BP supports a 15-year transmission planning
horizon. BP Comments at 4. Public Systems supports a 15- to 20-year
transmission planning horizon. Public Systems Comments at 18-22.
NextEra, AEP, Northwest and Intermountain, and the Oregon Commission
support a 20-year transmission planning horizon. NextEra Comments at
70; Northwest and Intermountain Comments at 4, 16; Oregon Commission
Comments at 8-9. NYISO supports the Commission granting discretion,
up to 20 years. NYISO Comments at 34-37. ACPA and ESA, AEE, U.S.
DOE, Competitive Energy, District of Columbia's Office of the
People's Counsel, Massachusetts Attorney General, and VEIR support a
transmission planning horizon longer than 20 years. ACPA and ESA
Comments at 43-45; AEE Comments at 32; U.S. DOE Comments at 12-15,
27-28; Competitive Energy Comments at 37-40; District of Columbia's
Office of the People's Counsel Comments at 22-25; Massachusetts
Attorney General Comments at 5-15; VEIR Comments at 13-17.
\164\ November 2021 Technical Conference Transcript (Tr.) at
129-137.
\165\ Id. at 129-137.
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96. Commenters discussing frequency generally support the
Commission requiring that scenarios be reassessed and revised between
every two to five years, and up to seven years, to balance the benefits
and costs of revisiting the scenarios.\166\ AEP recommends that the
Commission require all public utility transmission providers to
reassess scenarios at the same time to promote consistent results and
comparability among regions.\167\ Panelists at the November 2021
Technical Conference, including PJM, MISO, and AEP, supported a
frequency of at least every three years.\168\
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\166\ For example, NextEra supports every two years, ITC
supports every three to five years, Exelon and Competitive Energy
support every five to seven years, AEP supports at least every three
years, and the SPP Market Monitor supports a 10-year study every
year. NextEra Comments at 79; ITC Comments at 12; Exelon Comments at
17; Competitive Energy Comments at 37-40; SPP Market Monitor
Comments at 3-4.
\167\ AEP Comments at 10-11.
\168\ November 2021 Technical Conference Tr. at 138-140.
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(02) Proposed Requirement
97. We propose to require that public utility transmission
providers develop Long-Term Scenarios as part of Long-Term Regional
Transmission Planning using no less than a 20-year transmission
planning horizon. In addition, we propose to require that public
utility transmission providers develop Long-Term Scenarios at least
every three years, by reassessing whether the data inputs and factors
incorporated in their previously developed Long-Term Scenarios need to
be updated and then revising their Long-Term Scenarios as needed to
reflect updated data inputs and factors. We also propose to require
that the development of Long-Term Scenarios be completed within three
years, before the next three-year assessment commences.
98. We preliminarily find that a 20-year transmission planning
horizon requirement strikes a reasonable balance between the current
near-term transmission planning horizons used in many transmission
planning regions and the 30-year or longer transmission planning
horizon proposed by some commenters. The 30-year or longer transmission
planning horizon is criticized by other commenters as speculative or
too uncertain. We also believe that a 20-year transmission planning
horizon requirement may be reasonable because some public utility
transmission providers use a 20-year transmission planning horizon in
existing regional transmission planning processes. In addition, we
believe that a 20-year planning horizon would allow for sufficient time
to identify, plan, and obtain siting and permitting approval and to
construct regional transmission facilities to meet long-term regional
transmission needs including those that may take longer than the
average amount of time to go from planning to in-service.\169\ Finally,
we believe that a 20-year transmission planning horizon would allow
public utility transmission providers to better leverage economies of
scale by sizing transmission facilities to meet not only nearer-term
needs but also longer-term transmission needs driven by changes in the
resource mix and demand over time. By assessing transmission needs over
a longer time horizon--for example, starting in year six \170\ through
year 20 of the transmission planning horizon--Long-Term Regional
Transmission Planning should be able to identify more efficient or
cost-effective regional transmission facilities to address these needs.
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\169\ The time needed to plan, obtain siting and permitting
approval for, and construct regional transmission facilities takes
an average of 10 years. See, e.g., MISO, 2021 MISO Transmission
Expansion Planning, at 12 (2021) (``Transmission facilities take an
average of 10 years to go from planning to in-service.''). Larger-
scale and greenfield transmission facilities may take longer to go
from planning to in-service.
\170\ As indicated above in this NOPR, NERC defines the long-
term transmission planning horizon as covering year six through year
10 and beyond.
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99. We preliminarily find that a three-year frequency requirement
balances the need of public utility transmission providers to reassess
changes in the resource mix and demand as technology, markets, and
policies have the potential to rapidly change,\171\ with the burden of
developing Long-Term Scenarios that can take a year or longer. We
believe that this three-year frequency requirement will allow public
utility transmission providers to identify new transmission needs
driven by changes in the resource mix and demand during the interim
years of the transmission planning period, and update previously
identified transmission needs, if warranted.
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\171\ For example, the annual capacity of new interconnection
requests grew 42% from 2017 to 2020, and 123% since 2015. See
Lawrence Berkeley National Lab, Generation, Storage, and Hybrid
Capacity in Interconnection Queues Interactive Visualization (May
2021), https://emp.lbl.gov/generation-storage-and-hybrid-capacity.
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100. We seek comment on whether using a 20-year transmission
planning horizon for Long-Term Scenarios is appropriate to allow public
utility transmission providers to identify transmission needs driven by
changes in the resource mix and demand and to evaluate regional
transmission facilities to more efficiently or cost-effectively meet
such transmission needs. We also seek comment on whether a frequency of
no less than three years for reassessing and revising, as necessary,
the data inputs and factors incorporated in previously developed Long-
Term Scenarios appropriately balances the benefits and burdens of such
updates. In addition, we seek comment on whether a three-year frequency
requirement for
[[Page 26525]]
reassessing and revising, as necessary, the data inputs and factors
incorporated in previously developed Long-Term Scenarios allows for
public utility transmission providers to update their assumptions in
time to assess transmission needs driven by changes in the resource mix
and demand, and whether this requirement helps to balance the risks of
under-building or over-building regional transmission facilities.
Finally, we also seek comment on the proposal to require that the
development of Long-Term Scenarios be completed within three years, and
whether this proposed requirement prevents the overlap of the three-
year assessments.
(ii) Factors
101. Factors shaping the electric power system are used as inputs
to develop scenarios for regional transmission planning. Factors
represent long-term drivers and trends that inform the expected
composition of the future resource mix and demand that may not be
captured by the inputs of a basic model of the transmission system.
Factors inform changes in the data inputs of models of the transmission
system but are not direct data inputs of such models. For example, a
state energy law driving procurement of generation is a factor, and
technology changes driving a long-term trend towards certain resource
types is also a factor, whereas the estimated impact that these factors
will have on the future resource mix and demand is a data input of a
model of the transmission system. Incorporating the appropriate set of
factors to forecast the future resource mix and demand when developing
Long-Term Scenarios is essential to ensuring that Long-Term Regional
Transmission Planning can identify more efficient or cost-effective
regional transmission facilities to meet transmission needs driven by
changes in the resource mix and demand. Importantly, incorporating more
accurate inputs into Long-Term Scenarios enables a better understanding
of transmission needs driven by changes in the resource mix and demand,
which in turn allows public utility transmission providers to better
evaluate the benefits of regional transmission facilities that would
meet those needs. Currently, public utility transmission providers
consider different sets of factors in the development of scenarios as
part of their regional transmission planning processes, to the extent
that they develop scenarios. For example, MISO's Futures study includes
federal and state climate and clean energy laws and regulations,
federal and state climate and clean energy goals that have not been
enacted into law, utility energy and climate goals, assumptions on the
potential to electrify various types of technologies/loads, data and
forecasts developed by various national labs or U.S. agencies, and
assumptions on resource retirements.\172\
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\172\ MISO Comments at 41-43.
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102. The ANOPR sought comment on what factors shaping the resource
mix are appropriate to use for transmission planning purposes, such as,
for example: (1) Federal, state, and local climate and clean energy
laws and regulations; (2) federal, state, and local climate and clean
energy goals that have not been enacted or promulgated into law or
regulation; (3) utility and corporate energy and climate goals; (4)
trends in technology costs within and outside of the electricity supply
industry, including shifts toward electrification of buildings and
transportation; and (5) resource retirements.\173\
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\173\ ANOPR, 176 FERC ] 61,024 at P 46.
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(01) Comments
103. Commenters in response to the ANOPR generally support the
factors that the Commission listed in the ANOPR as shaping the resource
mix. Such commenters highlight the importance of: Public policies;
\174\ decarbonization commitments; \175\ resource retirements; \176\
the scale, location, and adoption rate of distributed energy resources
(including batteries); \177\ state-approved utility integrated resource
plans; \178\ weather trends; climate risk; and reliability or
resilience against extreme weather \179\ as factors shaping future
transmission needs that public utility transmission providers should
model in developing scenarios. Additionally, some commenters argue that
scenarios should explicitly account for additional load from
electrification of transportation and buildings and include an
estimation of clean energy demand preferences from transmission
customers in the region.\180\ Some commenters request that the
Commission allow for regional flexibility and not be overly
prescriptive on factors for scenario planning.\181\ City of New York
proposes that New York State's statutory goals should be part of the
baseline scenario, rather than an informational scenario or treated as
a mere consideration.\182\ Exelon states that a state policy ``not
enshrined into law'' by the legislature should be one of the possible
futures that should be considered, even if somewhat ``discounted'' for
being aspirational.\183\ ACPA and ESA recommend that the ``business-as-
usual'' base case include existing future resource plans of the
utilities in the planning area and any local, state, or federal policy
requirements,\184\ and Berkshire states that many of the factors listed
in the ANOPR are already under consideration in states where integrated
resource plans are required.\185\ Industrial Customers states that
transmission investment should not be based on speculative
factors.\186\ Similarly, Potomac Economics expresses concern with
mandating long-term planning studies involving speculation on a
[[Page 26526]]
variety of factors.\187\ The PJM Market Monitor acknowledges the
uncertainty associated with transmission planning and accuracy of
inputs and expresses concern with planning for anticipated new
generation.\188\
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\174\ E.g., EEI Comments at 13-14; ACPA and ESA Comments at 28-
29; Competitive Energy Comments at 38; City of New York Comments at
7-9; Union of Concerned Scientists Comments at 41-44; Minnesota
Commission Comments at 4; National Grid Comments at 4-9; New Jersey
Commission Comments at 13-15; NRECA Comments at 17-19; Indicated PJM
TOs Comments at 25-26; SDG&E Comments at 3-4; VEIR Comments at 13-
14; WIRES Comments at 8; SEIA Comments at 5.
\175\ E.g., ACPA and ESA Comments at 43-45; Amazon Comments at
3; Competitive Energy Comments at 38; City of New York Comments at
7-9; Minnesota Commission Comments at 4; PIOs Comments at 80; RMI
Comments at 2-3; SDG&E Comments at 3-4; VEIR Comments at 13-14.
\176\ E.g., ACPA and ESA Comments at 43-45; Ameren Comments at
5-8; Competitive Energy Comments at 38; Union of Concerned
Scientists Comments at 41-44; EEI Comments at 13-14; NARUC Comments
at 10; Northern Virginia Cooperative Comments at 7-8; NRECA Comments
at 17-19; NYISO Comments at 27-31; Rail Electrification Comments at
12-13; SEIA Comments at 5.
\177\ E.g., EEI Comments at 13-14; NARUC Comments at 10; PG&E
Comments at 6; U.S. DOE Comments at 12-15; SEIA Comments at 5.
\178\ E.g., ACPA and ESA Comments at 43-45; Entergy Comments at
14-15; NRECA Comments at 11, 17-19; Union of Concerned Scientists
Comments at 41-44; Minnesota Commission Comments at 4; OMS Comments
at 5-6; Rail Electrification Comments at 12-13.
\179\ E.g., AEP Comments at 7-11; AES Ohio Comments at 2-4;
Oregon Commission Comments at 9-10; District of Columbia's Office of
the People's Counsel Comments at 22-25; East Kentucky Comments at 8;
Exelon Comments at 12, 15-16; LS Power Oct. 12 Comments at 41-46;
Massachusetts Attorney General Comments at 13-21; PIOs Comments at
80; PJM Comments at 25-26; REBA Comments at 19-26, 33.
\180\ E.g., Ameren Comments at 5-8; EEI Comments at 13-14; PIOs
Comments at 80-81; PJM Comments at 25-26; Rail Electrification
Comments at 12-13; REBA Comments at 19-26, 33; SEIA Comments at 5;
Massachusetts Attorney General Comments at 5-15; U.S. DOE Comments
at 12-18; see also November Joint Task Force Tr. 112:1-10 (Andrew
French) (asserting that anything that indicates there is demand
should be considered within the transmission planning process).
\181\ Duke Comments at 5-7; PJM Comments at 9; ISO-NE Comments
at 20-21; MISO Comments at 41.
\182\ City of New York Comments at 6-7.
\183\ Exelon Comments at 12, 15-16.
\184\ ACPA and ESA Comments at 46.
\185\ Southern Comments at 3-5; Berkshire Comments at 12-13.
\186\ Industrial Customers Comments at 20-33.
\187\ Potomac Economics Comments at 4.
\188\ PJM Market Monitor Comments at 2-3; see also November
Joint Task Force Tr. at 69:18-22 (Jason Stanek) (discussing the need
to account for the fact that there will be some uncertainty if
planning on a longer term horizon).
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(02) Proposed Requirement
104. We propose to require that public utility transmission
providers incorporate specific categories of factors in the development
of Long-Term Scenarios as part of Long-Term Regional Transmission
Planning. Specifically, we propose to require that public utility
transmission providers incorporate, at a minimum, the following
categories of factors into the development of Long-Term Scenarios: (1)
Federal, state, and local laws and regulations that affect the future
resource mix and demand; \189\ (2) federal, state, and local laws and
regulations on decarbonization and electrification; \190\ (3) state-
approved utility integrated resource plans and expected supply
obligations for load serving entities; \191\ (4) trends in technology
and fuel costs within and outside of the electricity supply industry,
including shifts toward electrification of buildings and
transportation; \192\ (5) resource retirements; \193\ (6) generator
interconnection requests and withdrawals; \194\ and (7) utility and
corporate commitments and federal, state, and local goals that affect
the future resource mix and demand.\195\
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\189\ For example, consistent with the Governor's executive
order, the New Jersey Board of Public Utilities has developed a
solicitation schedule to procure 7,500 MW of offshore wind resources
by 2035. See New Jersey Commission Comments at 1. New York State
Department of Environmental Conservation has promulgated emissions
regulations that will cause many of the peaking generating
facilities in New York City to retire. See City of New York Comments
at 8. By ``state or federal laws or regulations,'' we mean enacted
statutes (i.e., passed by the legislature and signed by the
executive) and regulations promulgated by a relevant jurisdiction,
whether within a state, municipality, or at the federal level.
\190\ For example, five of the six New England states are
statutorily required to reduce economy-wide greenhouse gas emissions
by at least 80% below 1990 levels by 2050. NESCOE Comments at 8. New
York law requires all new passenger cars and trucks in the state to
be zero-emissions vehicles by 2035. City of New York Comments at 8.
\191\ For example, North Carolina's vertically-integrated
investor-owned electric utilities participate in a biennial
integrated resource plan process, in which they develop and file
with the North Carolina Commission a forecast of load, supply-side
resources, and demand-side resources over a 15-year period. North
Carolina Commission Reply Comments at 17.
\192\ For example, MISO's latest Futures Report included
assumptions on the potential to electrify various types of
technologies/loads and data on technology costs from the National
Renewable Energy Laboratory (NREL) Annual Technology Baseline
dataset, the EIA, and DOE. MISO Comments at 43 (citing MISO, MISO
Futures Report, at 30-38 (Dec. 2021)).
\193\ For example, CAISO evaluates potential generation capacity
retirements when developing the unified planning assumptions and
study plan during phase one of its regional transmission planning
process. CAISO Comments at 18.
\194\ For example, in 2019, approximately 4.75 of 5 GW of
generator interconnection requests that had been a part of the MISO
West 2017 study group withdrew from the generator interconnection
queue. ACORE Comments, Ex. 2 at 17.
\195\ For example, two-thirds of Fortune 100 companies and
roughly half of Fortune 500 companies have set renewable energy or
related sustainability targets. ACPA and ESA Comments at 28. By
``goal,'' we mean any commitment or statement expressed in writing
that is not a law or regulation.
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105. We preliminarily find that incorporating, at a minimum, these
categories of factors in the development of Long-Term Scenarios is
appropriate because these categories of factors affect the future
resource mix and demand, and their incorporation in Long-Term Scenarios
is therefore essential to identifying transmission needs driven by
changes in the resource mix and demand through Long-Term Regional
Transmission Planning. Directly below, we discuss our proposed
requirements governing how public utility transmission providers must
incorporate each category of factors into Long-Term Scenarios. We note
that we are proposing to require that public utility transmission
providers incorporate, at a minimum, these categories of factors into
the development of Long-Term Scenarios. To the extent public utility
transmission providers would like to incorporate additional categories
of factors into the development of Long-Term Scenarios, we propose to
require that they demonstrate that the incorporation of more than the
minimum is consistent with or superior to any final rule in this
proceeding.
106. First, we propose to require that each Long-Term Scenario that
public utility transmission providers use in Long-Term Regional
Transmission Planning incorporate and be consistent with federal,
state, and local laws and regulations that affect the future resource
mix and demand; federal, state, and local laws and regulations on
decarbonization and electrification; and state-approved integrated
resource plans and expected supply obligations for load serving
entities. We preliminarily find that it is reasonable to require public
utility transmission providers to assume legally binding obligations
and state utility regulator-approved plans are followed and expected
supply obligations for load serving entities are fully met. Public
utility transmission providers may not discount the factors included in
the categories of federal, state, and local laws and regulations that
affect the future resource mix; federal, state, and local laws and
regulations on decarbonization and electrification; and state-approved
integrated resource plans and expected supply obligations for load
serving entities.
107. Second, we propose to require that each Long-Term Scenario
that public utility transmission providers use in Long-Term Regional
Transmission Planning include trends in technology and fuel costs
within and outside of the electricity supply industry, including shifts
toward electrification of buildings and transportation; resource
retirements; and generator interconnection requests and withdrawals.
For these particular categories of factors, we propose to grant public
utility transmission factors flexibility in how they incorporate each
factor into Long-Term Scenarios so long as public utility transmission
providers identify and publish specific factors for each of these
categories as further described below. As discussed in the Coordination
of Regional Transmission Planning and Generator Interconnection
Processes section below, we propose to require that public utility
transmission providers consider in their Long-Term Regional
Transmission Planning regional transmission facilities that address
interconnection-related transmission needs that the public utility
transmission provider has identified multiple times in the generator
interconnection process but that have never been constructed due to the
withdrawal of the underlying interconnection request(s). We propose to
require that public utility transmission providers must incorporate the
specific interconnection-related needs identified through that reform,
in addition to one or more factors that more generally characterize
generator interconnection withdrawals, as a factor in the generator
interconnection requests and withdrawals category of factors in their
development of Long-Term Scenarios.
108. Finally, we propose to require that each Long-Term Scenario
incorporate utility and corporate goals and federal, state, and local
goals that affect the future resource mix. However, we acknowledge that
these categories of factors are less binding and more likely to change
over time, and therefore their impact on the future resource mix and
demand are less certain. For this reason, we preliminarily find that it
may be
[[Page 26527]]
appropriate for public utility transmission providers to discount such
goals to account for this uncertainty. In other words, public utility
transmission providers would not be required to assume that utility and
corporate goals and federal, state, and local goals that affect the
future resource mix will be fully met.
109. We propose to require that public utility transmission
providers identify and publish on an Open Access Same-Time Information
System (OASIS) or other public website a list of the factors that fall
into each of the required categories of factors that they will
incorporate in their development of Long-Term Scenarios. That is,
public utility transmission providers would be responsible for
identifying all the factors they know of and are considering
incorporating in the development of Long-Term Scenarios as part of
Long-Term Regional Transmission Planning. We also propose to require
that public utility transmission providers revise the regional
transmission planning processes in their OATTs to outline an open and
transparent process that provides stakeholders, including states,\196\
with a meaningful opportunity to propose potential factors that public
utility transmission providers must incorporate in their development of
Long-Term Scenarios, such as specific laws, regulations, goals, and
commitments, and to provide input on how to appropriately discount
factors that are less certain.
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\196\ See NARUC Comments at 5-6 (``NARUC . . . supports
exploring reforms that will better align regional transmission
planning with state needs and ensure meaningful opportunities for
the state to provide direction and inputs or otherwise have their
law and policies appropriately reflected through the transmission
planning process--all while benefitting electricity consumers.'').
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110. We note that, under Order No. 1000, public utility
transmission providers must already have procedures in their OATTs that
give stakeholders a meaningful opportunity to submit proposed
transmission needs driven by Public Policy Requirements and that allow
public utility transmission providers to identify, out of the larger
set of potential transmission needs driven by Public Policy
Requirements that stakeholders propose, those needs for which
transmission facilities will be evaluated.\197\ Therefore, public
utility transmission providers may be able to modify and expand these
existing procedures for identifying transmission needs driven by Public
Policy Requirements to meet these proposed requirements regarding the
identification of factors for incorporation into Long-Term Scenarios.
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\197\ Order No. 1000, 136 FERC ] 61,051 at PP 206-207; Order No.
1000-A, 139 FERC ] 61,132 at P 335.
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111. We propose this reform because we believe that incorporation
of the categories of factors set forth above in developing Long-Term
Scenarios would help facilitate the identification of transmission
needs driven by changes in the resource mix and demand, which we
preliminarily find is necessary to ensure just and reasonable and not
unduly discriminatory or preferential Commission-jurisdictional rates.
Absent a requirement to incorporate these categories of factors into
the development of Long-Term Scenarios, public utility transmission
providers may not incorporate known inputs that will likely affect the
future resource mix and demand. Additionally, public utility
transmission providers may not adequately identify transmission needs
driven by changes in the resource mix and demand and evaluate the
potential benefits of regional transmission facilities that may more
efficiently or cost-effectively meet such needs. As an additional
benefit, this requirement would provide clarity to public utility
transmission providers and stakeholders on what factors must be
considered in scenario development.
112. We seek comment on whether and how the categories of factors
listed above adequately capture factors expected to drive changes in
the resource mix and demand.
(iii) Number and Range of Long-Term Scenarios
113. In Long-Term Regional Transmission Planning, the number and
range of Long-Term Scenarios developed determines the scope of possible
future conditions for the electric power system and allows public
utility transmission providers to identify the transmission needs for
each possible future reflected in the scenarios. Developing a range of
scenarios with different assumptions allows public utility transmission
providers to consider a variety of potential scenarios and associated
transmission needs driven by changes in the resource mix and demand
and, in turn, possibly different regional transmission facilities to
more efficiently or cost-effectively meet those needs. However,
modeling multiple scenarios requires additional time and effort, and
may add to the costs of Long-Term Regional Transmission Planning. We
are cognizant of these tradeoffs in developing our proposed reforms.
114. In developing scenarios, it is possible to create a base case
scenario that is a business-as-usual scenario, or a most likely
scenario, and compare that to alternative scenarios that are considered
to be less likely to occur. These alternative scenarios typically
depart from the base case by considering different assumptions. For
example, an alternative scenario might differ from a base case in how
it considers the location and quantity of resource additions or
retirements. In addition, it is possible to develop specific scenarios
to determine potential transmission needs. For example, it is possible
to develop a scenario that assumes a greater amount of distributed
energy resource additions compared to a business-as-usual case, a
scenario that assesses conditions associated with extreme weather
events, or a scenario that explores the possibility of additional
resource development in an identified geographic zone, as well as a
scenario that combines these assumptions.
115. Currently, MISO developed three scenarios, called futures,
that it intends to use as part of its Long-Range Transmission
Planning.\198\ MISO makes a different assumption about load growth, the
extent to which state and utility goals that are not legislated are
met, and the future resource mix for each future.\199\ CAISO creates a
base case scenario reflecting the assumptions about resource locations
that are most likely to occur and one or more stress scenarios to
compare to the base case scenario.\200\ SPP currently develops a base
reliability scenario and two scenarios as part of its 10-year
Integrated Transmission Planning assessment and four scenarios as part
of its 20-year Integrated Transmission Planning assessment.\201\ NYISO
currently develops multiple scenarios (high/low load, high/low natural
gas price, 70% zero-emissions by 2030) for its regional transmission
planning process.\202\
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\198\ MISO Comments at 8, 80.
\199\ MISO, MISO Futures Report, at 4 (Dec. 2021).
\200\ CAISO Comments at 45.
\201\ SPP, 2020 Integrated Transmission Planning Assessment
Report, at 8 (Oct. 2020); SPP Market Monitor Comments at 3-4; SPP,
2022 20-Year Assessment Scope, at 2-4 (Feb. 2, 2021).
\202\ NYISO Comments at 28-29.
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116. The ANOPR sought comment on whether consideration should be
given to multiple future scenarios and whether and how public utility
transmission providers should account for an array of different future
scenarios when identifying more efficient or cost-effective
transmission facilities in regional transmission plans.\203\
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\203\ ANOPR, 176 FERC ] 61,024 at P 48.
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117. The ANOPR also sought comment on how the regional
[[Page 26528]]
transmission planning process should consider the probabilities of
scenarios.\204\ The Commission also asked ``whether greater use of
probabilistic transmission planning approaches may better assess the
benefits of regional transmission facilities'' and whether ``more
advanced approaches, such as stochastic \205\ techniques, may provide
an opportunity to consider a broader array of potential future
conditions.'' \206\
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\204\ Id.
\205\ Stochastic models are frameworks for addressing
optimization problems that involve uncertainty.
\206\ ANOPR, 176 FERC ] 61,024 at P 49.
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(01) Comments
118. Some commenters responding to the ANOPR discuss the number and
range of scenarios that should be used in regional transmission
planning. U.S. DOE recommends a national standard set of scenarios,
including business-as-usual, high/medium/low load growth, high/medium/
low reliance on distributed energy resources and demand response, and
high decarbonization.\207\ ACPA and ESA recommend a business-as-usual
base case and alternative scenarios with adjusted assumptions on
increased commitments to decarbonization, increased electrification of
transportation and other uses such as home heating, and increased fuel
prices.\208\ Oregon Commission recommends that the Commission require
study of a scenario in which there is a federal-level climate/clean
energy policy.\209\ Eversource states that regions should have
flexibility in defining scenarios, and that states should have a major
role in defining scenarios.\210\ Nebraska Commission generally opposes
the Commission specifying scenario requirements.\211\
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\207\ U.S. DOE Comments at 12-15.
\208\ ACPA and ESA Comments at 46.
\209\ Oregon Commission Comments at 8-9.
\210\ Eversource Comments at 9.
\211\ Nebraska Commission Comments at 3-4.
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119. In terms of the number of scenarios, ACPA and ESA argue that
the Commission should require public utility transmission providers to
use three to four scenarios, including a business-as-usual case.\212\
AEP recommends at least three robust and standardized scenarios.\213\
NextEra also recommends that the Commission require public utility
transmission providers to consider at least three scenarios ranging
from a business-as-usual case to a transformative scenario featuring
economy-wide national net zero emissions.\214\ And Nature Conservancy
contends that the Commission should require at least four.\215\
Avangrid proposes the number of scenarios should be sufficient to
support reasoned decision-making but not so exhaustive to complicate
and slow down planning.\216\ LS Power asserts that there is a need for
a plan that uses a broad range of plausible scenarios.\217\
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\212\ ACPA and ESA Comments at 46.
\213\ AEP Comments at 11-12.
\214\ NextEra Comments at 71-71, 75-77.
\215\ Nature Conservancy Comments at 3.
\216\ Avangrid Comments at 12-14.
\217\ LS Power Oct. 12 Comments at 33-36.
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120. In terms of probabilistic planning methods in developing
scenarios, commenters to the ANOPR identify the benefits of
probabilistic planning, which can include the ability to recognize
multiple facility outages at a single time, to prepare for and recover
from extreme weather events, and to address uncertainties about
operational outcomes (like variable generation) and over a long time
horizon.\218\ In light of these benefits, some commenters recommend
that the Commission require public utility transmission providers to
adopt probabilistic planning methods.\219\ PG&E states that the
planning toolkit must now evolve to include more probabilistic tools
that appropriately reflect the variable nature of the resource mix and
other uncertainties in the forecast.\220\ U.S. DOE states that
probabilistic planning, along with other factors, is likely to
contribute to the development of a transmission system that reliably
meets system needs at just and reasonable rates.\221\ Other commenters
support the use of probabilistic planning methods where feasible or
appropriate and do not recommend the Commission require public utility
transmission providers to adopt probabilistic planning methods at this
time.\222\ PJM, CAISO, and MISO identify the value of probabilistic
planning methods yet acknowledge that complex issues remain involving
data availability, computational intensity, and stakeholder
consensus.\223\ Minnesota Commission states that probabilistic
approaches are likely to be problematic in the stakeholder process
because of the uncertainty and wide-ranging stakeholder opinions about
the future.\224\
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\218\ E.g., California Commission Comments at 71; NARUC Comments
at 11 (stating that probabilistic approaches can provide ``more
insight into the benefits and risks of different decisions; and the
importance and relationship between various uncertainties''); MISO
Comments at 36 (stating that ``probabilistic planning has many
benefits and should be explored''); PG&E Comments at 3 (stating that
probabilistic planning ``appropriately reflect[s] the variable
nature of the resource mix and other uncertainties in the
forecast'').
\219\ AES Ohio Comments at 2-3; PIOs Comments at 79; California
Commission Comments at 66; VEIR Comments at 15-16.
\220\ PG&E Comments at 3.
\221\ U.S. DOE Comments at 20.
\222\ EEI Comments at 25; NARUC Comments at 10
(``[P]robabilistic analysis should be used, where feasible without
significantly burdening the planning process.''); WIRES Comments at
8-9; National Grid Comments at 71; see also Joint Fed.-State Task
Force on Elec. Transmission, Technical Conference, Docket No. AD21-
15-000, Tr. 71:12-72:5 (Clifford Rechtschaffen) (Feb. 16, 2022)
(February Joint Task Force Tr.) (supporting increasing use of
probabilistic and other analytical approaches where feasible to
account for uncertainty in quantification of benefits and
effectively plan for the longer term).
\223\ PJM Comments at 64-66; MISO Comments at 46-47; CAISO
Comments at 48.
\224\ Minnesota Commission Comments at 4.
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(02) Proposed Requirement
121. We propose to require that public utility transmission
providers develop at least four distinct Long-Term Scenarios as part of
Long-Term Regional Transmission Planning. We propose to require that
each of these Long-Term Scenarios incorporate, at a minimum, the
categories of factors listed in the requirement above. As discussed in
the Factors section above, we propose that each Long-Term Scenario must
be consistent with federal, state, and local laws and regulations that
affect the future resource mix; federal, state, and local laws and
regulations on decarbonization and electrification; and state-approved
integrated resource plans. However, each Long-Term Scenario may vary
according to assumptions about the remaining categories of factors
described above, as well as with respect to other characteristics of
the future electric power system. We do not propose to require the
development of a specific Long-Term Scenario or specific set of Long-
Term Scenarios, nor do we propose to require that public utility
transmission providers identify the relative likelihood of different
Long-Term Scenarios except where a public utility transmission provider
develops a base case scenario, as described more fully below.
122. We preliminarily find that using at least four distinct Long-
Term Scenarios is a reasonable lower bound for the number of Long-Term
Scenarios that public utility transmission providers must evaluate in
Long-Term Regional Transmission Planning. This minimum number of Long-
Term Scenarios will help ensure that public utility transmission
providers conduct Long-Term Regional Transmission Planning that
identifies more efficient or cost-effective regional transmission
facilities to meet transmission needs
[[Page 26529]]
driven by changes in the resource mix and demand. For example, public
utility transmission providers could develop a base case and three
alternatives or a low-, medium-, and high-level assumption for the
factors that public utility transmission providers (and their
stakeholders) believe to be important to conduct Long-Term Regional
Transmission Planning to more efficiently or cost-effectively meet
transmission needs driven by changes in the resource mix and demand,
along with a scenario that accounts for a high-impact, low-frequency
event (as discussed below).
123. Furthermore, we propose to require that public utility
transmission providers in each transmission planning region develop a
plausible and diverse set of Long-Term Scenarios.\225\ That is to say,
the set of at least four Long-Term Scenarios must be: (1) Plausible,
that is they must reasonably capture probable future outcomes, and (2)
diverse in the sense that public utility transmission providers can
distinguish distinct transmission facilities or distinct benefits of
similar transmission facilities in each scenario. If a public utility
transmission provider produces a base case scenario, that scenario
should be consistent with what the public utility transmission provider
determines to be the most likely scenario to occur. Consistent with the
Order No. 890 transparency transmission planning principle,\226\ we
propose to require that public utility transmission providers in each
transmission planning region publicly disclose (subject to any
applicable confidentiality protections) information and data inputs
they use to create each Long-Term Scenario. This transparency
requirement will allow stakeholders to understand how each scenario
differs. Similarly, consistent with the Order Nos. 890 and 1000
coordination transmission planning principle,\227\ we propose to
require that public utility transmission providers in each transmission
planning region give stakeholders the opportunity to provide timely and
meaningful input into the identification of which Long-Term Scenarios
are developed. We propose to require that public utility transmission
providers revise the regional transmission planning processes in their
OATTs to outline an open and transparent process that provides
stakeholders, including states, with a meaningful opportunity to
propose which future outcomes are probable and can be captured through
assumptions made in the development of Long-Term Scenarios. We further
propose to require that public utility transmission providers explain
on compliance how their process will identify a plausible and diverse
set of Long-Term Scenarios.
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\225\ We note that different assumptions about the factors and
data inputs used to develop Long-Term Scenarios and other
characteristics of the future electric power system determine
whether the set of Long-Term Scenarios are plausible and diverse.
\226\ The transparency transmission planning principle requires
public utility transmission providers to reduce to writing and make
available the basic methodology, criteria, and processes used to
develop transmission plans. Public utility transmission providers
must make sufficient information available to enable customers and
other stakeholders to replicate the results of transmission planning
studies. Order No. 890, 118 FERC ] 61,119 at P 471. Order No. 1000
applied this and other Order No. 890 transmission planning
principles to regional transmission planning processes. Order No.
1000, 136 FERC ] 61,051 at P 151.
\227\ The coordination transmission planning principle requires
public utility transmission providers to provide customers and other
stakeholders with the opportunity to participate fully in the
transmission planning process. The transmission planning process
must provide for the timely and meaningful input and participation
of customers and other stakeholders regarding the development of
transmission plans, allowing customers and other stakeholders to
participate in the early stages of development. Order No. 890, 118
FERC ] 61,119 at PP 451-454.
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124. We propose to require that at least one of the four distinct
Long-Term Scenarios that public utility transmission providers in each
transmission planning region use in Long-Term Regional Transmission
Planning must account for uncertain operational outcomes that determine
the benefits of or need for transmission facilities during high-impact,
low-frequency events. We propose to allow public utility transmission
providers to determine which high-impact, low-frequency event should be
modeled in this Long-Term Scenario as part of Long-Term Regional
Transmission Planning based on our understanding that each transmission
planning region may see a need to evaluate a different type of high-
impact, low-frequency event. High-impact, low-frequency events may
include extreme weather events or events associated with potential
cyber attacks. This Long-Term Scenario accounting for a high-impact,
low-frequency event can be developed, for example, by assuming greater-
than-expected electricity demand and greater-than-expected generation
or transmission outages. We propose that the use of probabilistic
transmission planning or stochastic techniques would satisfy this
requirement, but do not propose to require either approach at this
time.\228\
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\228\ For the purpose of an improved record, we clarify that we
consider probabilistic transmission planning approaches to include
any transmission planning approach that uses a probability
distribution to assign probabilities to one or more inputs to the
transmission model. These inputs can include shorter-term
operational inputs (like wind generation or generation outages).
See, e.g., Li, W., Probabilistic Planning of Transmission Systems:
Why, How and an Actual Example, at 1, 2008 IEEE Power and Energy
Society General Meeting--Conversion and Delivery of Electrical
Energy in the 21st Century (2008). Stochastic techniques include
adaptive transmission planning techniques that identify transmission
facilities that optimize transmission net-benefits over a time
horizon under market and regulatory uncertainty about the future.
See, e.g., Ho, J., et al., Planning transmission for uncertainty:
Applications and lessons for the western interconnection, at 21, The
Western Electricity Coordinating Council (2016) (answering ``What is
stochastic transmission planning?'').
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125. We note that public utility transmission providers can develop
sensitivities for every Long-Term Scenario to assess how outcomes
modeled in Long-Term Scenarios may depend on an assumption about
electric power system model inputs that does not vary across scenarios
(e.g., higher natural gas prices).\229\ Such sensitivities can provide
valuable information about the need for and benefits of potential
transmission facilities; however, they can be burdensome to develop if
applied to every scenario.
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\229\ See, e.g., SPP, 2020 Integrated Transmission Planning
Assessment Report, at 146-154 (Oct. 2020), https://www.spp.org/documents/63434/2020%20integrated%20transmission%20plan%20report%20v1.0.pdf; NYISO,
2020 Reliability Needs Assessment, at 89-92 (Nov. 2020), https://www.nyiso.com/documents/20142/2248793/2020-RNAReport-Nov2020.pdf. A
sensitivity represents a single assumption about a short-term input
or factor (some input with a value that may change throughout a day
or year). A scenario represents an assumption about a longer-term
input or factor (e.g., resource retirements and additions or public
policies). See, e.g., Brattle-Grid Strategies Oct. 2021 Report at
64.
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126. We seek comment on whether four Long-Term Scenarios will
provide public utility transmission providers with enough information
to identify transmission needs driven by changes in the resource mix
and demand and evaluate transmission facilities for potential selection
in the regional transmission plan for purposes of cost allocation that
may more efficiently or cost-effectively meet those needs or whether
additional Long-Term Scenarios should be required. In addition, we seek
comment on whether public utility transmission providers should be
required to develop sensitivities for each Long-Term Scenario to
identify more efficient or cost-effective transmission facilities for
selection in the regional transmission plan for purposes of cost
allocation as part of Long-Term Regional Transmission Planning.
(iv) Specificity of Data Inputs
127. Data inputs are numbers that characterize assumptions about
future conditions of the transmission system under each scenario over
the
[[Page 26530]]
transmission planning horizon. Using reasonable data inputs is key to
effective Long-Term Regional Transmission Planning because data inputs
can drive the results of transmission planning models, both in terms of
the transmission needs identified and the more efficient or cost-
effective transmission facilities to address those needs. For example,
the long-term load forecast can lead to more planned transmission if
the assumed growth rate is increased. Similarly, the assumed dates of
generation retirements can be a critical factor in determining when new
transmission will be needed. Given how sensitive transmission planning
models can be to changes in assumptions, using robust data inputs is
critical to identifying more efficient or cost-effective regional
transmission facilities.
128. In the ANOPR, the Commission asked what inputs should be
considered in modeling anticipated future generation.\230\ More
specifically, the Commission asked which data inputs public utility
transmission providers would need to model to represent new generation
sources, such as renewable resources, in order to reflect their actual
performance.\231\
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\230\ ANOPR, 176 FERC ] 61,024 at P 48.
\231\ Id. P 50.
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(01) Comments
129. In response to the ANOPR, several public utility transmission
providers commented on the data inputs used in their existing regional
transmission planning processes.\232\ PJM recommends that the
Commission require disclosure of data inputs and their
assumptions.\233\ ACEG, AEE, and PIOs advocate for a new rule that
specifies that public utility transmission providers use best available
data inputs and best practices for load forecasts.\234\ Rail
Electrification recommends that the Commission insist on best available
data and most plausible futures.\235\ Union of Concerned Scientists
states that the failure to use the best available data will lead to the
failure to identify more efficient and cost-effective transmission
alternatives.\236\ U.S. DOE recommends the Commission consider the need
to standardize modeling inputs to increase consistency and
comparability across planning processes and lists the potential inputs
it thinks the Commission should consider.\237\ U.S. DOE also provides
information on the array of tools and data developed by national
laboratories which can be used as inputs in transmission planning.\238\
NARUC states that better sharing of data between states and the RTOs/
ISOs would be beneficial.\239\ RMI states that state-of-the-art cost
data and forecasts are of paramount importance in planning for new
transmission.\240\ NERC says that improved transmission planning for
reliability requires better data collection especially electromagnetic
transient data.\241\ Entergy believes that the transmission models used
should incorporate realistic and objectively reasonable future
assumptions.\242\ Certain TDUs believes public utility transmission
providers should regularly update planning models with the most recent
integrated resource plan data available.\243\ The PJM Market Monitor
asserts that decisions made about the transmission grid must reflect
accurate information while remaining flexible enough to incorporate new
information as it becomes available.\244\
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\232\ As examples, CAISO and PJM mention generation retirements,
MISO mentions forced outage rates, and CAISO, NYISO, and SPP mention
load and capacity forecasts. CAISO Comments at 18; MISO Comments at
47; NYISO Comments at 6; PJM Comments at 42; SPP Comments at 3.
\233\ PJM Comments, attach. K at 4.
\234\ ACEG Comments, attach. C at 10; AEE Reply Comments at 4;
PIOs Reply Comments at 43-44.
\235\ Rail Electrification Comments at 13.
\236\ Union of Concerned Scientists Comments at 31.
\237\ U.S. DOE Comments at 12-13.
\238\ Id. at attach. B.
\239\ NARUC Comments at 42.
\240\ RMI Comments at 3.
\241\ NERC Comments at 10.
\242\ Entergy Comments at 17.
\243\ Certain TDUs Comment at 11.
\244\ PJM Market Monitor Comments at 6.
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(02) Proposed Requirement
130. We propose to require that public utility transmission
providers use ``best available data inputs'' when developing Long-Term
Scenarios. By ``best available,'' we do not imply that there is a
single ``best'' value for each data input that public utility
transmission providers must use, but rather that best practices are
used to develop that data input.
131. We propose to define ``best available data inputs'' as data
inputs that are timely \245\ and developed using diverse and expert
perspectives, adopted via a process that satisfies the transparency
planning principle described above,\246\ and that reflect the list of
factors that public utility transmission providers must incorporate
into Long-Term Scenarios. An example of data inputs that could meet
this requirement are the long-term load forecasts of demand that RTOs/
ISOs currently use for predicting long-term resource adequacy. Another
example of data inputs that could meet this requirement are the most
recent data on renewable energy potential and distributed energy
resources developed by national labs.\247\
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\245\ Timely data inputs are based on the most current
information.
\246\ See supra note 226.
\247\ See, e.g., U.S. DOE Comments, attach. B at 79, 94
(discussing NREL's Renewable Energy Potential model and Distributed
Generation Market Demand model). We note that such granular data may
be useful to public utility transmission providers to the extent
public utility transmission providers do not already have such
granular data that meet this requirement.
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132. We propose to require that public utility transmission
providers in each transmission planning region update all data inputs
each time they reassess and revise, as necessary, their Long-Term
Scenarios, which, as explained above, we propose to require they do at
least every three years. As indicated in the Long-Term Regional
Transmission Planning section above, we also propose to require that
the Order Nos. 890 and 1000 transmission planning principles apply to
the process through which public utility transmission providers
determine which data inputs to use in their Long-Term Scenarios. For
example, consistent with the coordination transmission planning
principle in Order Nos. 890 and 1000, we propose to require that public
utility transmission providers in each transmission planning region
give stakeholders the opportunity to provide timely and meaningful
input concerning which data inputs to use in Long-Term Scenarios.
133. We preliminarily find that a requirement to use the best
available data inputs is necessary to ensure that public utility
transmission providers are regularly updating data inputs and then
using timely and accurate data inputs to inform Long-Term Scenarios. As
stated above, data inputs can drive the results of Long-Term Regional
Transmission Planning, and as a result, directly affect which
transmission facilities may be selected in the regional transmission
plan for purposes of cost allocation and, in turn, Commission-
jurisdictional rates.
134. We seek comment on whether the proposed definition of best
available data inputs will allow for public utility transmission
providers to identify the more efficient or cost-effective transmission
facilities for selection in the regional transmission plan for purposes
of cost allocation using Long-Term Scenarios. We seek comment on
whether the proposed definition of best available data inputs should be
expanded to include an evaluation of the data source entities'
historical accuracy in identifying and projecting trends that impact
the resource mix and demand. We also seek comment as to
[[Page 26531]]
whether stakeholders and public utility transmission providers would
find value in or believe it is necessary for the Commission to
facilitate the development of data inputs that meet this proposed
requirement by identifying or standardizing the best available data
inputs that meet this proposed requirement.\248\
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\248\ Id. at 12-14 (arguing the Commission should standardize
modeling input assumptions and establish core scenarios); Harvard
ELI Comments at 34 (stating the Commission could work with the U.S.
DOE to develop industry-wide standards for scenario planning which
would include data inputs).
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(v) Identification of Geographic Zones
135. In the ANOPR, the Commission sought comment on whether it
should require public utility transmission providers to establish, as
part of their regional transmission planning processes, a process that
identifies geographic zones that have the potential for the development
of large amounts of new generation, particularly renewable resources.
The Commission also sought comment on whether and how such a process
might interrelate with existing regional transmission planning and cost
allocation processes, and how long-term scenario planning may be used
in this process or other relevant regional transmission planning and
cost allocation processes.\249\ The Commission also noted that the
Texas' CREZ initiative, MISO's MVPs, and a Commission-approved CAISO
proposal are examples of such identification of geographic zones in
transmission planning and development initiatives.\250\
---------------------------------------------------------------------------
\249\ ANOPR, 176 FERC ] 61,024 at P 57.
\250\ Id. PP 55-56.
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(01) Comments
136. Several commenters responded to the Commission's request for
comments related to the identification of geographic zones. Starting
with the RTOs/ISOs, CAISO states that, while it supports the idea of
finding zones of renewable energy, there are many ways to do this, and
each region should be allowed to find its own solution. CAISO states
that active involvement and buy-in of state regulators in identifying
zones of renewable energy is critical to mitigate the risk of over-
building transmission and to facilitate state siting approvals for
transmission facilities. CAISO suggests that an open season could be
used to identify interest in a new transmission line.\251\
---------------------------------------------------------------------------
\251\ CAISO Comments at 49-54.
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137. NYISO supports the identification of pockets where future
generation would be developed and where new transmission is needed.
NYISO states that it already has such an identification process.\252\
---------------------------------------------------------------------------
\252\ NYISO Comments at 31-33.
---------------------------------------------------------------------------
138. ISO-NE states that it has a process in place to identify
regions of renewable energy that it calls ISO-NE Clustering, which it
says is similar to the process CAISO used in its Tehachapi approach.
ISO-NE states that long-term planning for transmission to renewable-
rich areas should not replace the generator interconnection
process.\253\
---------------------------------------------------------------------------
\253\ ISO-NE Comments at 21-25 (citing Cal. Indep. Sys.
Operator, 118 FERC ] 61,226, order on clarification, 120 FERC ]
61,180 (2007) (granting request for waiver to conduct a ``targeted''
cluster study to identify the significant transmission
infrastructure necessary to interconnect approximately 4,500 MW of
primarily wind resources in the remote Tehachapi Wind Resource Area
of the system)).
---------------------------------------------------------------------------
139. PJM argues that if the Commission creates a geographic zone
requirement, the RTOs/ISOs should have the flexibility to establish a
process for their region.\254\ Additionally, PJM suggests that sub-
zones of renewable energy could be visualized in a heat map.\255\
---------------------------------------------------------------------------
\254\ PJM Comments at 12-13.
\255\ Id. at 41-42.
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140. MISO opposes prescriptive requirements to identify zones of
renewable energy because it argues that the regions should have the
flexibility to work with stakeholders to identify zones. MISO also
argues that there are potential problems in identifying regions of
renewable energy because (1) what counts as renewable energy is not
clear, and (2) where the zones of renewable energy resources are not
clear, in part because a state's desire to develop resources may force
generation development in other states with lower resource potential.
MISO states that the MVP process was a success, in part, due to the
Regional Generation Outlet Study, which was a successful collaboration
between MISO and the states within the MISO region that might not have
worked as well if MISO and the states had not had the flexibility to
develop it the way that they did.\256\ MISO states that the MISO MVPs,
ERCOT's CREZ, and the CAISO examples all reflect local solutions based
on unique factors in each location. MISO points out that ERCOT and
CAISO are each single-state RTOs/ISOs, which makes their experience not
directly comparable to MISO's.\257\
---------------------------------------------------------------------------
\256\ MISO Comments at 53-56.
\257\ Id. at 56-58.
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141. U.S. DOI supports the creation of geographic zones as a means
to improve the efficiency of transmission planning overall but cautions
that any requirement must consider environmental impacts and habitats
of species that are of conservation concern.\258\ Similarly, U.S. DOE
argues that while the creation of geographic zones is a step in the
right direction, additional agreement is needed on which generation
resources would actually be developed, which market areas need to be
served, and which transmission facilities are needed to connect them
reliably and efficiently.\259\ However, U.S. DOE states that Texas'
CREZ model has worked well since it establishes clear regulatory
pathways and cost allocation en masse.
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\258\ U.S. DOI Comments at 1-3.
\259\ U.S. DOE Comments at 24, 74; see also November Joint Task
Force Tr 108:23-109:8, 110:13-18 (Gladys Brown-Dutrieuille)
(suggesting identification of geographic zones as one long-term
transmission planning principle FERC could work with states to
develop to ``facilitate integration of optimal resources in
transmission'').
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142. Some commenters oppose a geographic zone requirement. Consumer
Organizations assert that a ``top down'' approach from the Commission
has the potential to saddle customers with unnecessary costs from
constructing ``roads to nowhere'' that may never be utilized.\260\ East
Kentucky argues that a Commission-required geographic zone requirement
would create an uneven playing field for generation resources that seek
to interconnect outside a designated geographic zone.\261\ APPA argues
that instead of requiring geographic zones, the Commission should
permit load-serving entities to identify geographic zones when
developing their resource plans, which is more of a ``bottom up''
approach.\262\ OMS and NESCOE both assert that each region already has
an existing process to identify zones of renewable resource potential
and that the Commission should not require anything further.\263\ WIRES
states that a requirement to identify zones of renewable energy is not
needed and regions should have the flexibility to find their own
solutions.\264\ Xcel notes that such a requirement exceeds the
Commission's authority under the FPA because states have the final say
over construction of new generation, as well as transmission facility
siting and permitting.\265\
---------------------------------------------------------------------------
\260\ Consumer Organizations Comments at 21.
\261\ East Kentucky Comments at 8-9.
\262\ APPA Comments at 17.
\263\ OMS Comments at 8-9; NESCOE Comments at 46-47.
\264\ WIRES Comments at 41-42.
\265\ Xcel Comments at 5-10.
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143. Ohio Commission states that the Commission lacks jurisdiction
to require the creation of new zones.\266\ Michigan
[[Page 26532]]
Commission cautions that if the Commission requires a geographic zone
concept, the notion that geographic zones must be ``rich in renewable
resources'' would unreasonably shift costs to consumers that do not
receive commensurate benefits.\267\ NRECA states that the decision to
establish geographic zones should be left to the regional transmission
planning processes to resolve, subject to input from state and local
governing bodies and to ultimate Commission oversight and approval on a
case-by-case basis to ensure that zone selection and cost allocations
are consistent with Order No. 1000.\268\
---------------------------------------------------------------------------
\266\ Ohio Commission Comments at 6-10.
\267\ Michigan Commission Comments at 12-14.
\268\ NRECA Comments at 21-23
---------------------------------------------------------------------------
144. LPPC argues that a geographic zone requirement should consider
guardrails that will assist in limiting undue risk and financial
exposure for those customers that may not use the planned
facilities.\269\ SoCal Edison argues that geographic zones should
entail providing federal funds to disproportionally burdened
communities.\270\ Shell argues that coastal public utility transmission
providers should be required to explain how their transmission planning
processes accommodate the unique obstacles impeding offshore wind
transmission and generation.\271\ Orsted states that the scale and
location of future offshore wind generation is well known, and RTOs/
ISOs should be required to plan cost-effective transmission to bring
offshore wind power to market.\272\ Union of Concerned Scientists argue
that if the Commission requires geographic zones, it should revise
Order No. 1000's provision for local and regional transmission planning
processes to explicitly provide for the recognition of Public Policy
Requirements established by state or federal laws or regulations,
including federal leasing for the development of generation, that will
drive transmission and interconnection in resource-rich zones.\273\
---------------------------------------------------------------------------
\269\ LPPC Comments at 14-15.
\270\ SoCal Edison Comments at 10.
\271\ Shell Comments at 8-9.
\272\ Orsted Comments at 8.
\273\ Union of Concerned Scientists Comments at 32-37.
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(02) Proposed Requirement
145. We propose to require each public utility transmission
provider, as part of its regional transmission planning process, to
consider whether to: (1) Identify, with stakeholder input, specific
geographic zones within the transmission planning region that have the
potential for development of large amounts of new generation; (2)
assess generation developers' commercial interest in developing
generation within the identified geographic zones; and (3) incorporate
designated zones, and the identified commercial interest in each zone,
into Long-Term Scenarios.
146. We preliminarily find that requiring the consideration and
potential identification of geographic zones within Long-Term Scenarios
assists public utility transmission providers, transmission developers,
and generation developers to coordinate their activities. We believe
that public utility transmission providers would be able to better
identify transmission needs driven by changes in the resource mix and
demand by considering geographic zones that have the potential for the
development of large amounts of new generation and where developers
have already shown commercial interest. Using the information gained
through the process described below to identify such geographic zones,
public utility transmission providers in each transmission planning
region could then plan transmission facilities that would serve large
concentrations of new generation in a more efficient or cost-effective
manner.
147. As step one of the geographic zone process, we propose to
require that public utility transmission providers consider whether to
establish and include in the regional transmission planning process
outlined in their OATTs the method that they will use to identify
geographic zones within the transmission planning region. We propose to
require that this method use best available data, including
atmospheric, meteorological, geophysical, and other surveys, to
identify geographic zones with potential for development of large
amounts of new generation. We also propose to require that public
utility transmission providers in each transmission planning region use
this information to create a set of draft geographic zones, and that
they post on their OASIS or other public websites maps of the draft
geographic zones, as well the information used to create the draft
geographic zones, for stakeholders' input.
148. As part of proposed step one, after the public utility
transmission providers in each transmission planning region identify
and post any draft geographic zones and related information, we propose
to require them to provide all stakeholders, including relevant federal
and state siting authorities, with a meaningful opportunity to provide
input on the draft geographic zones. We believe that input from federal
and state siting authorities is particularly important because we also
propose to require that public utility transmission providers in each
transmission planning region use this stakeholder engagement to
identify known siting, permitting, or other anticipated development
challenges or opportunities associated with the draft geographic zones.
We believe that obtaining information related to siting and permitting
early in the geographic zone development process will help public
utility transmission providers to identify draft zones where the
anticipated generation resources are most likely to materialize.
149. In addition, we propose to require that public utility
transmission providers in each transmission planning region consider
this stakeholder feedback and modify the draft geographic zones as
appropriate to produce a final list of designated geographic zones
within the transmission planning region.\274\ As the final part of
proposed step one, we propose to require that public utility
transmission providers in each transmission planning region post on
their OASIS or other public websites maps of the designated geographic
zones and information related to the designation of those zones,
including the explanation of changes from the draft to final list.
---------------------------------------------------------------------------
\274\ We note that, while we refer to multiple ``zones,''
subsequent to stakeholder feedback, the final list may contain only
one designated geographic zone.
---------------------------------------------------------------------------
150. In step two of the geographic zone process, we propose to
require that public utility transmission providers in each transmission
planning region assess generation developers' commercial interest in
developing generation within each designated geographic zone.
Specifically, we propose to require that public utility transmission
providers include in their OATTs as part of their regional transmission
planning process a method to assess generation developers' commercial
interest in developing generation within each designated geographic
zone that considers the following: (1) The generation developer's
existing energy resources within the zone; (2) the number and size of
any interconnection requests from developers with completed facilities
study agreements for generation located within the zone; (3) a
generation developer's leasing agreements with landowners within the
zone; (4) a generation developer's letters of credit associated with
generation it may develop in the zone; (5) any merchant or other entity
commitments to build
[[Page 26533]]
(including deposits or payments to secure or fund) transmission
facilities that would serve generation within the zone; (6) a
generation developer's power purchase agreements with a credit-worthy
counterparty associated with generation within the zone; and (7) any
other factors for which generation developers have provided evidence as
indications of commercial interest in developing generation within the
zone. We propose this step two requirement because we believe it will
indicate how much of the geographic zone's resource hosting potential
generation developers are interested in pursuing, which is useful for
improving the accuracy of Long-Term Scenarios as public utility
transmission providers in each transmission planning region incorporate
information about designated geographic zones into such scenarios as
part of step three.
151. In step three of the geographic zone process, we propose to
require that public utility transmission providers in each transmission
planning region incorporate the information from step one and step two
regarding the designated geographic zones into their Long-Term
Scenarios. We believe this information will be useful to public utility
transmission providers in each transmission planning region as they
identify and run different Long-Term Scenarios as part of the
requirement to conduct Long-Term Regional Transmission Planning to
address transmission needs driven by changes in the resource mix and
demand. Specifically, we propose to require that public utility
transmission providers revise the regional transmission planning
process in their OATTs to describe how the designated geographic zones,
the information they used to designate the geographic zones, and the
information about generation developers' commercial interest in
developing generation within each zone are integrated into their Long-
Term Scenarios. We believe that integrating this information into Long-
Term Scenarios will allow public utility transmission providers in each
transmission planning region to better identify transmission needs
driven by changes in the resource mix and demand, as well as more
efficient or cost-effective regional transmission facilities to meet
those needs.
152. We acknowledge that public utility transmission providers in
multi-state transmission planning regions may face unique challenges
and differing energy policy interests or preferences in complying with
this proposed requirement.
153. We seek comment on how public utility transmission providers
in multi-state transmission planning regions may reconcile or account
for differing energy policy interests or preferences in implementing
this proposed requirement, while respecting and not overriding those
state preferences.
ii. Coordination of Regional Transmission Planning and Generator
Interconnection Processes
154. As discussed above, we preliminarily find that current
regional transmission planning processes fail to plan for transmission
needs driven by changes in the resource mix and demand. Instead, public
utility transmission providers typically account for such transmission
needs through interconnection-related network upgrades identified
through the generator interconnection process. Based on the comments
received in response to the ANOPR, we believe that there may be a need
for better coordination between the regional transmission planning and
cost allocation and generator interconnection processes. To this end,
we propose to require that public utility transmission providers
consider as part of their Long-Term Regional Transmission Planning
regional transmission facilities that address interconnection-related
needs that the public utility transmission provider identified multiple
times in the generator interconnection process but that have never been
constructed due to the withdrawal of the underlying interconnection
request(s).
(a) ANOPR
155. In the ANOPR, the Commission asserted that the interaction
between a public utility transmission provider's current generator
interconnection process and its regional transmission planning and cost
allocation processes appears to be limited.\275\ The Commission also
observed that the primary interaction between a public utility
transmission provider's current generator interconnection process and
its regional transmission planning and cost allocation processes is
that the baseline regional transmission planning models generally only
incorporate interconnection projects that are near the end of the
generator interconnection process and have completed an interconnection
facilities study.\276\
---------------------------------------------------------------------------
\275\ ANOPR, 176 FERC ] 61,024 at P 23.
\276\ ANOPR, 176 FERC ] 61,024 at P 23. Id.
---------------------------------------------------------------------------
156. The ANOPR sought comment on whether reforms are necessary to
improve coordination between the regional transmission planning and
cost allocation and generator interconnection processes.\277\ In
particular, the ANOPR sought comment on whether interconnection
requests that trigger the need for interconnection-related network
upgrades that may provide regional transmission benefits could be
studied in a way that accounts for the potential broader transmission
benefits in coordination with the regional transmission planning
process.\278\ The ANOPR also sought comment on whether it may be
possible and beneficial to combine certain aspects of the regional
transmission planning and generator interconnection processes.\279\
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\277\ ANOPR, 176 FERC ] 61,024 atId. P 65.
\278\ ANOPR, 176 FERC ] 61,024 atId. P 66.
\279\ ANOPR, 176 FERC ] 61,024 at P 66. Id.
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(b) Comments
157. Each of the RTOs/ISOs filed comments in response to the ANOPR
related to the coordination of their regional transmission planning and
cost allocation and generator interconnection processes. CAISO states
that it includes interconnection-related network upgrades identified
during its interconnection study process and that meet specific voltage
and/or capital cost thresholds as an input into the regional
transmission planning process. CAISO asserts that it does so to ensure
that it identifies and approves all major transmission additions and
upgrades under a single comprehensive process and allocates the
available amount of transmission capacity to the proposed generating
facilities in each area.\280\ PJM states that it leverages
opportunities to address supplemental projects and new interconnection
service requests through its baseline transmission projects. For
instance, when increasing the capabilities of a regional transmission
facility would obviate the need for an interconnection-related network
upgrade, PJM factors the interconnection customer's incremental need
into the transmission project and the interconnection customer is only
responsible for the costs of the incremental portion of the
transmission facility.\281\ ISO-NE explains how its regional
transmission planning and generator interconnection processes are
coordinated presently but acknowledges that improvements may be
necessary to optimize transmission solutions.\282\ NYISO and SPP each
identify an ongoing or potential stakeholder process to improve the
coordination of the generator interconnection and regional
[[Page 26534]]
transmission planning processes.\283\ MISO explains how its generator
interconnection and regional transmission planning processes are
currently related to each other and contends that the regional
transmission planning process is the right avenue to determine more
holistic transmission needs but considers the generator interconnection
process more appropriate to focus on the specific needs associated with
interconnecting new generation.\284\
---------------------------------------------------------------------------
\280\ CAISO Comments at 71-72.
\281\ PJM Comments at 17-18.
\282\ ISO-NE Comments at 25-26.
\283\ NYISO Comments at 41; SPP Comments at 9-11.
\284\ MISO Comments at 75-76.
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158. Several commenters support better coordination between the
regional transmission planning and cost allocation and generator
interconnection processes, including the need for similar timelines and
assumptions.\285\ Anbaric and Public Systems ask the Commission to
require a regional transmission planning assessment if an
interconnection study identifies significant interconnection-related
network upgrades beyond the interconnection facility line needed to
reach a substation and any directly interconnected substation upgrades
to ``shift the evaluation of development of needed upgrades to the
[regional transmission] planning process.'' \286\ Anbaric and Public
Systems state that the needed upgrades could be eligible for
competitive bidding as part of the regional transmission planning
process. Similarly, Duke suggests that public utility transmission
providers can identify an ex ante measure, such as the change in the
levelized cost of a transmission network upgrade, to determine whether
an interconnection-related network upgrade should be incorporated into
its regional transmission plan for purposes of cost allocation
according to a defined cost allocation method.\287\
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\285\ See, e.g., AEP Comments at 30-31; APPA Comments at 22;
Certain TDUs Comments at 18; NARUC Comments at 6, 11, 18; NERC
Comments at 17-18; NewSun Comments at 24; Northwest and
Intermountain Comments at 33; OMS Comments at 11-13; Indicated PJM
TOs Comments at 27; REBA Comments at 2-3; SDG&E Comments at 5.
\286\ Anbaric Comments at 23; Public System Comments at 6-7, 19.
\287\ Duke Comments at 8-9.
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159. Enel outlines a detailed proposal for consolidating the
generator interconnection and regional transmission planning processes
to limit generator interconnection studies to focus on direct,
localized impacts of new generation and directly assign costs for
interconnection-related network upgrades to generators when the cost
causation relationship is ``strong and justified.'' \288\ Under Enel's
proposal, interconnection requests that meet significant readiness
criteria required by the public utility transmission provider, such as
a non-refundable cash deposit or letter of credit in the amount of 100%
of the costs of the ``local'' interconnection-related network upgrades,
would be included in the regional transmission planning process after
the public utility transmission provider conducts a basic
interconnection study (e.g., Energy Resource Interconnection
Study).\289\ AEE states that implementing Enel's proposal would help
resolve the cost allocation and market entry barrier problems
associated with the current funding paradigm for interconnection-
related network upgrades and could also help unburden constrained and
backlogged interconnection queues that are creating barriers to
entry.\290\
---------------------------------------------------------------------------
\288\ Enel Comments at 3.
\289\ Enel Comments, Id. attach. 1 (Plugging In) at 12. Enel
proposes that the Transfer Distribution Factor is a good metric for
determining electrical distance from a generation facility and what
constitutes ``local.'' See Enel Comments, attach. 1 (Plugging In)
id. at 6.
\290\ AEE Comments at 52-53.
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160. Other commenters oppose further coordination of the generator
interconnection and regional transmission planning processes.\291\ Some
consumer groups express a general concern that coordination reforms
would shift costs of generator interconnection to consumers.\292\
Finally, some commenters expect that a regional transmission planning
process that better accounts for anticipated future generation would
address generator interconnection issues that are due to a lack of
coordination, or co-optimization, of the two processes.\293\
---------------------------------------------------------------------------
\291\ Southern Comments at 38-39; US Chamber of Commerce
Comments at 4; see also ACORE Comments at 26-27; APPA Comments at
22-23; Berkshire Comments at 10-11; CAISO Comments at 70; LPPC
Comments at 18; ITC Comments at 31.
\292\ Industrial Customers Comments at 25; Consumer
Organizations Comments at 26.
\293\ EEI Comments at 37; Exelon Comments at 33-34; Policy
Integrity Comments at 27-28; Indicated PJM TOs Comments at 27.
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(c) Need for Reform
161. For the reasons set forth below, we believe that there may be
a need for better coordination between regional transmission planning
and cost allocation and generator interconnection processes to ensure
just and reasonable and not unduly discriminatory or preferential
Commission-jurisdictional rates. As the Commission explained in the
ANOPR, the interaction between regional transmission planning and cost
allocation processes on the one hand and the generator interconnection
process on the other appears limited--the baseline regional
transmission planning models generally only incorporate interconnection
projects that have completed an interconnection facilities study, and
are therefore near the end of the generator interconnection
process.\294\ But where transmission system needs are repeatedly
identified through generator interconnection processes, we believe that
more efficient or cost-effective transmission expansion could be
achieved through regional transmission planning and cost allocation
that allocates costs in a manner that is at least roughly commensurate
with estimated benefits and eliminates a potential barrier to entry for
new generation resources.
---------------------------------------------------------------------------
\294\ ANOPR, 176 FERC ] 61,024 at P 23.
---------------------------------------------------------------------------
162. We are most concerned with the prevalence of interconnection-
related network upgrades being repeatedly identified in the generator
interconnection process in multiple interconnection queue cycles in a
short period of time (e.g., five years) but not being developed because
the interconnection request(s) driving the need for the upgrade are all
withdrawn. As explained above, there has been a dramatic increase in
recent years in the level of spending on interconnection-related
network upgrades, driving the cost of interconnecting new generation to
the transmission system higher and higher.\295\ The evidence suggests
that this trend is leading to more and more interconnection customers
withdrawing their interconnection requests in the face of significant
costs associated with interconnection-related network upgrades.
According to a January 2021 report, ``the high cost of interconnection
is increasing the rate at which generators drop out of the
interconnection queue.'' \296\ For example, between January 2016 and
July 2020, 245 generation projects in advanced stages in the MISO
generator interconnection process withdrew from the queue, with the
project developers citing high interconnection-related network upgrade
costs as the primary reason for their withdrawal.\297\ While
interconnection customers may choose to withdraw from the
interconnection queue for a number of reasons, in recent
[[Page 26535]]
years, the deciding factor has become the interconnection customer's
``sticker shock'' at its cost responsibility for interconnection-
related network upgrades.\298\
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\295\ Supra section_Supra Need for Reform: Unjust and
Unreasonable and Unduly Discriminatory and Preferential Commission-
Jurisdictional Rates (detailing the sharp rise in total investment
in interconnection-related network upgrades along with the jump in
the cost per kW for newly interconnecting generators to
interconnect).
\296\ ACEG Jan. 2021 Interconnection Report at 17.
\297\ Id. (naming the high cost of interconnection-related
network upgrades as the fundamental problem that interconnection
queue reform has failed to address thus far).
\298\ See ACORE Comments at 12.
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163. When interconnection customers withdraw from the
interconnection queue, the identified interconnection-related network
upgrades associated with those interconnection customers remain unbuilt
and the underlying interconnection-related needs go unaddressed. In
many cases, when the interconnection-related need is not addressed via
development of interconnection-related network upgrades in one
interconnection queue cycle, the same interconnection-related need--and
oftentimes the same or a substantially similarly interconnection-
related network upgrade--will appear in interconnection studies for
different interconnection requests or clusters in subsequent
interconnection queue cycles. This scenario can occur even if
subsequent interconnection requests or clusters vary considerably from
previous interconnection requests or clusters in terms of size, fuel
type, technical specifications, or location. One study, which analyzed
12 specific interconnection-related network upgrades identified by MISO
and SPP, found that SPP identified three of the upgrades in two
interconnection queue cycles and one in three interconnection queue
cycles, and MISO identified three of the upgrades in two
interconnection queue cycles and two in three interconnection queue
cycles.\299\ In other words, both SPP and MISO were repeatedly
identifying the same interconnection-related network upgrades as
interconnection customers withdrew from the interconnection queue,
leaving next-in-line interconnection customers to address the same
interconnection-related needs.
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\299\ ICF Sept. 2021 Report at 25-26.
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164. Where interconnection-related needs are repeatedly identified
in interconnection studies, the implication may be that the area,
despite the potentially prohibitive interconnection costs, is otherwise
desirable for generators to locate (e.g., it is located close to fuel
sources). At the same time, the recurrent need for an interconnection-
related network upgrade is unlikely to go away without someone
investing in the transmission system in that location. As
interconnection customers that have invested time and resources in
proposing a project, entering the interconnection queue, and engaging
in the generator interconnection process choose to withdraw rather than
fund the interconnection-related network upgrades, it becomes more and
more likely that it will never be economic for an interconnection
customer (or small cluster of interconnection customers) to resolve the
interconnection-related need.
165. At the same time, interconnection-related network upgrades can
provide widespread transmission benefits that extend beyond the
interconnection customer.\300\ As a result, planning these transmission
upgrades exclusively through the generator interconnection process may
result in a mismatch between the beneficiaries of the transmission
upgrade and those to whom the costs are allocated. In other words, by
upgrading the transmission system in a piecemeal fashion through the
generator interconnection process, the current transmission planning
paradigm appears to impose costs on interconnection customers for
transmission facilities that would provide benefits beyond those
received by the interconnection customer. This paradigm can present a
potential barrier to entry for new generation resources that might
otherwise be economic if not for the cost of interconnection-related
network upgrades. We believe that reforms may be necessary to allow for
the consideration of transmission facilities to meet interconnection-
related needs repeatedly identified in the generator interconnection
process through Long-Term Regional Transmission Planning and Cost
Allocation process instead, which we believe would result in more
efficient or cost-effective transmission expansion, cost allocation for
such transmission facilities that is at least roughly commensurate with
estimated benefits, and elimination of a barrier to entry for new
generation resources. In turn, we expect that these reforms would
ensure just and reasonable and not unduly discriminatory or
preferential Commission-jurisdictional rates.
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\300\ See, e.g., CAISO Comments at 52-53 (stating that in CAISO
``transmission facilities at 200 kV and above are eligible for
regional cost allocation,'' including location-constrained resources
interconnection facilities, because ``this voltage threshold . . .
recognizes that high voltage transmission facilities support and
provide benefits to all customers to the CAISO grid''); Order No.
2003, 104 FERC ] 61,103 at P 65 (stating that ``[f]acilities beyond
the Point of Interconnection [(i.e., interconnection-related network
upgrades)] are part of the Transmission Provider's Transmission
System and benefit all users''); ACORE Comments, Ex. 5, at 4-7.
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(d) Proposed Reform
166. We propose to require that public utility transmission
providers consider in their Long-Term Regional Transmission Planning
regional transmission facilities that address certain interconnection-
related needs that the public utility transmission provider has
identified multiple times in the generator interconnection process but
that have never been constructed due to the withdrawal of the
underlying interconnection request(s). In particular, we propose to
require that public utility transmission providers evaluate for
selection in the regional transmission plan for purposes of cost
allocation regional transmission facilities to address interconnection-
related needs that have been identified in the generator
interconnection process as requiring interconnection-related network
upgrades where: (1) The public utility transmission provider has
identified interconnection-related network upgrades in interconnection
studies to address those interconnection-related needs in at least two
interconnection queue cycles during the preceding five years (beginning
at the time of the withdrawal of the first underlying interconnection
request); (2) the interconnection-related network upgrade identified to
meet those interconnection-related needs has a voltage of at least 200
kV and/or an estimated cost of at least $30 million; (3) those
interconnection-related network upgrades have not been developed and
are not currently planned to be developed because the interconnection
request(s) driving the need for the upgrade has been withdrawn; and (4)
the public utility transmission provider has not identified an
interconnection-related network upgrade to address the relevant
interconnection-related need in an executed generator interconnection
agreement or in a generator interconnection agreement that the
interconnection customer requested that the public utility transmission
provider file unexecuted with the Commission.
167. We propose to require that public utility transmission
providers in each transmission planning region consider regional
transmission facilities to address interconnection-related needs
pursuant to this reform through the proposed Long-Term Regional
Transmission Planning. We recognize that the Long-Term Regional
Transmission Planning proposal requires that public utility
transmission providers incorporate interconnection queue withdrawals
into Long-Term Scenario development. Consequently, we propose to
require that public utility transmission providers in each transmission
planning region incorporate the specific
[[Page 26536]]
interconnection-related needs identified through this reform as a
factor used to develop Long-Term Scenarios.
168. We preliminarily find that this requirement will support the
establishment of just and reasonable and not unduly discriminatory or
preferential Commission-jurisdictional rates by addressing a potential
barrier to integrating new sources of generation that may otherwise
continue to exist absent such requirements in the regional transmission
planning process. Additionally, to the extent that such transmission
facilities are selected in the regional transmission plan for purposes
of cost allocation, this proposal would provide an avenue to allocate
these regional transmission facilities' costs more broadly in
recognition of their more widespread benefits (as identified through
the regional transmission planning process), helping to ensure that
their costs are allocated in a manner that is at least roughly
commensurate with the estimated benefits that they provide. We believe
that the criteria proposed above that the public utility transmission
provider must use to identify the interconnection-related needs that
should be considered in the regional transmission planning process will
help to ensure that the associated interconnection-related network
upgrades are likely to have produced benefits beyond those provided to
the interconnection customers whose interconnection requests the
interconnection-related network upgrades are needed to accommodate. It
is important to note that we are not proposing that all
interconnection-related needs that satisfy the above criteria must
result in transmission facilities being selected in the regional
transmission plan for purposes of cost allocation; rather, those
regional transmission facilities would have to independently satisfy
the criteria for such selection in Long-Term Regional Transmission
Planning as the more efficient or cost-effective transmission facility.
169. As noted above, we propose that the first qualifying criterion
for this potential reform is that the public utility transmission
provider has identified a needed interconnection-related network
upgrade in generator interconnection studies to address the same
interconnection-related need in at least two interconnection queue
cycles during the preceding five years. The five-year look-back for
each interconnection-related need would begin on the date that an
interconnection customer with an interconnection study that identifies
an interconnection-related network upgrade that meets the voltage or
cost estimate threshold withdraws its interconnection request.\301\ We
propose to choose this starting point because, arguably, this is the
earliest point at which the transmission provider will have notice that
the costs associated with an identified interconnection-related network
upgrade may have caused a withdrawal. We also believe that this
criterion appropriately limits the scope of this requirement to those
interconnection-related needs that are likely to persist, are not
unique to a single interconnection customer's request, and have the
potential, if evaluated through the regional transmission planning
process, to provide more widespread benefits to transmission customers.
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\301\ We propose that when an interconnection-related network
upgrade is identified for the interconnection of more than one
interconnection customer in an interconnection queue cycle, the
withdrawal of all interconnection customers assigned to that
interconnection-related network upgrade qualifies as one withdrawal.
The withdrawal of a single interconnection customer when other
interconnection customers assigned to the interconnection-related
network upgrade remain in the interconnection queue cycle does not
qualify as a withdrawal of an interconnection queue interconnection
request for the purposes of this reform.
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170. We propose that the initial five-year time period begin five
calendar years prior to the initial effective date of the accepted
tariff provisions proposed to comply with this reform. Thus, upon the
acceptance of such tariff provisions in a Commission or delegated
letter order, the public utility transmission provider would consider
interconnection-related network upgrades identified to address the same
interconnection-related need in at least two interconnection queue
cycles in the five calendar years prior to the effective date
established in the order accepting those tariff revisions. Thus, if the
Commission adopts this proposal, the public utility transmission
provider should not look back to a point earlier than that date and,
going forward, this requirement would apply to any repeat
identification of an interconnection-related need identified in at
least two interconnection queue cycles in the immediately preceding
five calendar years. We believe that such a limitation would prevent
consideration of regional transmission facilities (more specifically,
interconnection-related network upgrades) identified using data that
may be stale by the time the public utility transmission providers in a
transmission planning region consider regional transmission facilities
to address the identified interconnection-related needs in their
regional transmission planning process. We believe that five years is
short enough to provide public utility transmission providers with
accurate information on interconnection-related needs and also long
enough for public utility transmission providers to identify the same
interconnection-related need, which is likely to persist, in at least
two interconnection queue cycles.
171. We do not propose to limit this reform to interconnection-
related network upgrades that are identical to those identified in
prior interconnection queue cycles. Instead, we propose to focus on the
relevant interconnection-related needs that those upgrades are intended
to address. To this point, we propose to require that public utility
transmission providers in each transmission planning region consider
whether the interconnection-related need for which the public utility
transmission provider identified the interconnection-related network
upgrade is the same in multiple interconnection queue cycles. That is,
if an interconnection-related need is driving the identification of an
interconnection-related network upgrade on the transmission system in
one interconnection queue cycle and an interconnection-related network
upgrade with, for example, a different voltage, starting point, or
ending point is identified in the next interconnection queue cycle to
address the same interconnection-related need, then the first criterion
would be satisfied. We believe that this approach will appropriately
account for differences in technology, study assumptions, system
topology, and/or interconnection requests that may occur over time that
may result in different interconnection-related network upgrades to
address the same interconnection-related need.
172. We also propose to limit the scope of this reform to those
interconnection-related network upgrades that have a voltage of at
least 200 kV and/or an estimated cost of at least $30 million. We note
that we have previously found a 200 kV voltage threshold to be just and
reasonable in the context of an analogous provision in CAISO's
tariff.\302\ With respect to the
[[Page 26537]]
$30 million estimated cost threshold, evidence suggests that requiring
interconnection customers to be responsible for this level of costs
from a single interconnection-related network upgrade can lead to
withdrawal from the interconnection queue, signaling that this level
may be an appropriate dividing line for consideration in regional
transmission planning processes.\303\
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\302\ Section 24.4.6.5 of CAISO's Comprehensive Transmission
Planning Process provides that interconnection-related network
upgrades identified in the generator interconnection process that
are not already included in a signed LGIA may be assessed in the
Comprehensive Transmission Planning Process if they ``consist of new
transmission lines 200 kV or above, and have capital costs of $100
million or greater; . . . [are] a new 500 kV substation that has
capital costs of $100 million or greater; or, . . . have a capital
cost of $200 million or more.'' CAISO, Tariff, sectionSec. 24.4.6.5
(LGIP Network Upgrades) (1.0.0).
\303\ TheAn ACEG Reportreport notes that 3.5 of 5 GW of
renewable energy projects in the MISO West 2017 study group dropped
out because each project ``faced transmission costs in the range of
tens to hundreds of millions of dollars.'' ACEG ReportSee Americans
for a Clean Energy Grid, Disconnected: The Need for New Generator
Interconnection Policy, at 17. (Jan. 2021). We also note that thean
ICF Report indicates that the Wichita-Benton 345 kV line in SPP
South, which has appeared in two different interconnection queue
cycles and has not been constructed, has an estimated cost of $32.1
million. See ICF ReportResources, LLC, Just & Reasonable?
Transmission Upgrades Charged to Interconnection Generators are
Delivering System-Wide Benefits, at 5, 26. (Sep. 2021). As a further
reference point, wind and solar industry advocates claim that ``the
`implied cost threshold' beyond which new generators are often no
longer financially viable is . . . . . . an average of about
$100,000 per megawatt of installed capacity.'' See American Wind
Energy Association, Clean Grid Alliance, and SEIA, Generator
Contributions to Transmission Expansion, at 2 (AugustAug. 2020),
https://cleangridalliance.org/_uploads/_media_uploads/_source/Generator_Contrib_Xmission-V3a-FINAL.pdf.
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173. To avoid shifting costs inappropriately from generators in the
generator interconnection process to transmission customers through the
regional transmission planning process, we further propose to limit the
scope of interconnection-related needs to be considered in the regional
transmission planning process to those interconnection-related needs
not addressed by interconnection-related network upgrades memorialized
in an executed generator interconnection agreement (or in a generator
interconnection agreement that the interconnection customer requested
to be filed unexecuted with the Commission). This proposed limitation
would ensure that public utility transmission providers only consider
in their regional transmission planning process interconnection-related
network upgrades that remain unconstructed despite the existence of a
demonstrated interconnection-related need. We reiterate that regional
transmission facilities identified through this process would have to
independently satisfy the public utility transmission provider's
criteria for selection in the regional transmission plan for purposes
of cost allocation as the more efficient or cost-effective transmission
solution.
174. We seek comment on the requirements proposed in this section
of the NOPR. In particular, we seek comment on whether this proposed
reform could delay the processing of existing interconnection queues
and what reforms, if any, would be necessary to ensure that the
generator interconnection and regional transmission planning processes
are not significantly delayed by this proposed reform. We also seek
comment on the appropriateness of the criteria that we propose a public
utility transmission provider must use to identify the interconnection-
related needs that should be considered in the regional transmission
planning process, and whether there are alternative criteria public
utility transmissions providers may use to identify significant
interconnection-related needs that warrant consideration in the
regional transmission planning process. Finally, we seek comment on how
this proposed reform should interact with existing regional
transmission planning processes and the Long-Term Regional Transmission
Planning proposed herein.
iii. Evaluation of the Benefits of Regional Transmission Facilities
175. As discussed above, we propose to require that public utility
transmission providers in each transmission planning region identify
transmission needs driven by changes in the resource mix and demand
using Long-Term Scenarios that meet the requirements proposed above. As
explained in this section, once the public utility transmission
providers in a transmission planning region have identified the
region's transmission needs driven by changes in the resource mix and
demand, we propose to require that, as part of public utility
transmission providers' identification and evaluation of more efficient
or cost-effective regional transmission facilities that may resolve
those transmission needs in the regional transmission planning process,
public utility transmission providers must: (1) Evaluate the benefits
of regional transmission facilities to meet identified transmission
needs driven by changes in the resource mix and demand, identify which
benefits they will use in Long-Term Regional Transmission Planning,
explain how they will calculate those benefits, and explain how the
benefits will reasonably reflect the benefits of regional transmission
facilities to meet identified transmission needs driven by changes in
the resource mix and demand ; and (2) evaluate the benefits of regional
transmission facilities over a time horizon that covers, at a minimum,
20 years starting from the estimated in-service date of the
transmission facilities. Further, we propose to allow (but not require)
public utility transmission providers to evaluate the benefits of a
portfolio of regional transmission facilities instead of doing so on a
facility-by-facility basis. Finally, we identify and describe a broad
set of benefits that we believe public utility transmission providers
could consider using in Long-Term Regional Transmission Planning (Long-
Term Regional Transmission Benefits) to reasonably capture the benefit
of regional transmission facilities to meet identified transmission
needs driven by changes in the resource mix and demand.
(a) Evaluations of Long-Term Regional Transmission Benefits
176. In Order No. 1000, the Commission neither prescribed a
particular definition of ``benefits'' or ``beneficiaries,'' nor
required consideration of any specific benefits. Instead, the
Commission stated that the proper context for consideration of such
matters would be on review of compliance proposals.\304\ The Commission
stated that allowing greater flexibility to accommodate a variety of
approaches better advanced the goals of Order No. 1000.\305\ The
Commission also stated that, in determining the beneficiaries of
transmission facilities, a regional transmission planning process could
consider benefits including, but not limited to, the extent to which
transmission facilities, individually or in the aggregate, provide for
maintaining reliability and sharing reserves, production cost savings
and congestion relief, and/or meeting Public Policy Requirements.\306\
The result is that there are no specific requirements for public
utility transmission providers to consider any particular benefit or
set of benefits in evaluating transmission facilities for selection in
the regional transmission plan for purposes of cost allocation as the
more efficient or cost-effective solution to a regional transmission
need.
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\304\ Order No. 1000, 136 FERC ] 61,051 at P 624.
\305\ Id. PP 624-625.
\306\ Id. P 622.
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177. In the ANOPR, the Commission sought comment on whether the
Commission should require public utility transmission providers to use
a minimum set of benefits to identify more efficient or cost-effective
regional transmission facilities, and what those benefits should
be.\307\ The Commission
[[Page 26538]]
sought comment as to whether the existing regional transmission
planning and cost allocation processes fully accounted for the full
suite of benefits, including hard-to-quantify benefits. Further, the
Commission sought comment on the types of benefits provided by
transmission facilities needed to meet the transmission needs of the
changing resource mix, as well as the manner in which those benefits
can be quantified, if at all. The Commission also sought comment on how
public utility transmission providers can document and account for
benefits if those benefits cannot be quantified, but are real.\308\
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\307\ ANOPR, 176 FERC ] 61,024 at P 53.
\308\ Id. P 70.
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(1) Comments
178. Many commenters support consideration of a wider set of
benefits than those currently used to evaluate transmission facilities
for potential selection in the regional transmission plan for purposes
of cost allocation.\309\ Further, many commenters support the
consideration of all possible benefits of regional transmission
facilities when discussing benefits in the context of the current
approach to separately consider reliability, economic, and public
policy benefits--however, even some commenters that support maintaining
the Order No. 1000 framework acknowledge that the benefits assessed
could be expanded.\310\ Commenters that support requiring consideration
of an expanded set of transmission benefits argue that existing
regional transmission planning processes are unjust and unreasonable
because they ignore the full range of transmission benefits and
therefore fail to select net beneficial transmission facilities,
leading to underinvestment in transmission and higher consumer costs in
the long run.\311\ PIOs assert that the Commission should conduct a
survey of all potential benefits that can result from multi-value,
scenario-based planning and should require that public utility
transmission providers consider those benefits for regional
transmission planning.\312\ Numerous commenters point to a list of
transmission benefits identified by The Brattle Group as providing a
useful framework for delineating a minimum set of benefits that the
Commission could require public utility transmission providers to
consider when evaluating alternative regional transmission
facilities.\313\
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\309\ ACORE Comments at ii; AEE Comments at 31-32; ACEG Comments
at 6-8; ACPA and ESA Comments at 75; AEP Comments at 14; Amazon
Comments at 4; Anbaric Comments at 29; Avangrid Comments at 9;
Business Council for Sustainable Energy Comments at 2; Citizens
Energy Comments at 6-7; City of New York Comments at 3-4; Union of
Concerned Scientists Comments at 66-75; Consumers Council Comments
at 4, 16; Duke Comments at 12; EDF Comments at 8-10; EEI Comments at
33; ITC Comments at 28-34; Massachusetts Attorney General Comments
at 24-25; New Jersey Commission at 13-14, 17-19; NextEra Comments at
83-88; Northwest and Intermountain Comments at 35-38; Orsted
Comments at 6-7; PIOs Comments at 30, 60; Policy Integrity Comments
at 43; PSEG Comments at 25-27; REBA Comments at 17; RMI Comments at
4; SEIA Comments at 9; Shell Comments at 18-20; State Agencies
Comments at 21-22; State of Massachusetts Comments at 16-17; U.S.
DOE Comments at 7-9, 23-24; WIRES Comments at 18; see also Joint
Fed.-State Task Force on Elec. Transmission, Transcript of Feb. 16,
2022 Meeting, Docket No. AD21-15-000, at 19:15-18, 22:9-12 (Comm'r
Rechtschaffen) (supporting expanded list of benefits and arguing
that a more comprehensive benefit-cost analysis would lead to better
transmission planning).
\310\ City of New York Comments at 7; PIOs Comments at 81-82;
EEI Comments at 24-25; PG&E Comments at 8-9; Anbaric Comments at 29;
Union of Concerned Scientists Comments at 38; State of Massachusetts
Comments at 16-19; Orsted Comments at 6-7; RMI Comments at 4.
\311\ See, e.g., ACEG Comments at 31-32 & app. A; ACORE Comments
at 31-32 & Ex. 6; ACPA and ESA Comments at 24-27; NextEra Comments
at 84-86; PIOs Comments at 82; PIOs Reply Comments at 55.
\312\ PIOs Comments at 30; see also Orsted Comments at 6.
\313\ See, e.g., ACEG Comments at 34 & app. A; ACORE Comments at
34 & Ex. 6; ACPA and ESA Comments at 24-26; EDF Comments at 9;
NextEra Comments at 84-86; PIOs Comments at 34 & Ex. A; RMI Comments
at 4; U.S. DOE Comments at 37; WIRES Comments at 2; ACEG Reply
Comments at 11; Enel Reply Comments at 3-4; PIOs Reply Comments at
55; see also February Joint Task Force Tr 49:8-13 (Ted Thomas)
(stating that The Brattle Group list of benefits is ``characterized
by rigor'').
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179. Many commenters generally request regional flexibility to
consider benefits. Ameren opposes requiring a specific set of benefits,
arguing that such a reform could lead to controversy and delays.\314\
Consumer Organizations and District of Columbia's Office of the
People's Counsel express that, if additional benefits are added to the
equation, additional costs to communities and landowners (for example,
additional farm production costs, local road use, and local emergency
services) should be, too.\315\ Consumer Organizations and LPPC assert
that it is not within the Commission's authority to create ``new
speculative benefits'' in an effort to broaden cost allocation.\316\
District of Columbia's Office of the People's Counsel urges that
greater specificity is needed regarding what is a benefit.\317\ APPA
does not support considering environmental benefits associated with
particular types of resources in planning transmission facilities and
allocating costs.\318\
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\314\ Ameren Comments at 9-11.
\315\ Consumer Organizations Comments at 18-19; District of
Columbia's Office of the People's Counsel Comments at 26-27.
\316\ Consumer Organizations Comments at 18; LPPC Comments at
20-23.
\317\ District of Columbia's Office of the People's Counsel
Comments at 3-4.
\318\ APPA Comments at 15-16.
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180. MISO states that it has adopted benefit metrics such as
avoided/deferred reliability projects and reduced MISO-SPP settlement
costs that go beyond adjusted production cost savings. However, MISO
states that it has not been able to adopt other metrics explored in the
stakeholder process, including: (1) Transmission outage and
transmission energy losses; and (2) reduced capacity cost due to
reduced peak load losses and future capacity expansion deferral due to
increased capacity import and export limits.\319\ MISO seeks
flexibility on benefits that are considered to reflect changing
circumstances but calls for direction or guidance from the Commission
on identification and quantification of challenging benefits like
resilience.\320\
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\319\ MISO Comments at 23-26.
\320\ Id. at 52-53; see also February Joint Task Force Tr 20:5-
8, 21:4-12 (Clifford Rechtschaffen) (suggesting that the reliability
category should be expanded to include resilience, particularly in
light of extreme events in the West and increasingly intense
hurricanes in the East), 51:10-15 (Matthew Nelson) (stating that
having commonality in terminology for benefits and where they are
considered would be valuable), 69:16-18 (Jason Stanek) (concluding
that if there is a fourth category of benefits, it may be
resilience), 73:1-4 (Riley Allen) (arguing for not ignoring
difficult to quantify benefits but rather for finding sensible ways
to quantify them).
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181. NYISO supports identifying economic benefits when studying
reliability projects. NYISO states that the current economic
calculation is based on net production cost savings and does not
consider other economic benefits such as installed capacity cost
savings to load-serving entities.\321\
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\321\ NYISO Comments at 27-31, 34-37; see also February Joint
Task Force Tr 20:9-12 (Clifford Rechtschaffen) (advocating for
expanding the economic category to include improved connectivity to
lower-cost generation).
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182. The PJM Market Monitor claims that PJM incorrectly defines the
benefits of proposed market efficiency transmission projects, resulting
in uneconomic transmission upgrades. In particular, the PJM Market
Monitor argues that PJM uses speculative transmission-related benefits
over a 15-year period while limiting the analysis to the existing
generation fleet and existing patterns of fuel costs and congestion,
which eliminates the possibility that new generation could respond to
market signals and meet the same needs.\322\ The PJM Market Monitor
cautions against considering congestion reduction or localized
locational marginal price reductions as an economic benefit to a
potential transmission project without accurately
[[Page 26539]]
accounting for how the congestion dollars are or are not returned to
load through the financial transmission rights (or their
equivalent).\323\
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\322\ PJM Market Monitor Comments at 10.
\323\ Id. at 11.
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(2) Proposed Reform
183. At this time, consistent with Order No. 1000, we decline to
propose to prescribe any particular definition of ``benefits'' or
``beneficiaries,'' nor require use of any specific benefits.\324\
Instead, we continue to acknowledge the benefits of regional
flexibility, and consistent with Order No. 1000, propose to consider
such matters on review of compliance proposals.\325\ Nevertheless, we
acknowledge the support for the adoption of a common set of minimum
benefits, and we propose a list of Long-Term Regional Transmission
Benefits described below that public utility transmission providers may
consider in Long-Term Regional Transmission Planning and cost
allocation processes. In addition, we propose to require that public
utility transmission providers identify on compliance the benefits they
will use in Long-Term Regional Transmission Planning, how they will
calculate those benefits, and how the benefits will reasonably reflect
the benefits of regional transmission facilities to meet identified
transmission needs driven by changes in the resource mix and demand. As
part of this compliance obligation, public utility transmission
providers should explain the rationale for using the benefits
identified.
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\324\ See Order No. 1000, 136 FERC ] 61,051 at PP 624-625.
\325\ See id. P 624.
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184. We believe that the Long-Term Regional Transmission Benefits
discussed below account for many of the benefits that regional
transmission facilities to address transmission needs driven by changes
in the resource mix and demand identified as part of Long-Term Regional
Transmission Planning are most likely to provide. However, we clarify
that this list of potential benefits is not mandatory or exhaustive and
public utility transmission providers would have flexibility to propose
what benefits to use as part of their Long-Term Regional Transmission
Planning. For example, public utility transmission providers may wish
to use benefits previously accepted by the Commission for existing
regional transmission planning processes that are not included in the
Long-Term Regional Transmission Benefits discussed herein.
185. We believe that the following set of Long-Term Regional
Transmission Benefits may be useful in evaluating transmission
facilities for selection in the regional transmission plan for purposes
of cost allocation as the more efficient or cost-effective solutions to
meet transmission needs driven by changes in the resource mix and
demand: (1) Avoided or deferred reliability transmission projects and
aging infrastructure replacement; (2) either reduced loss of load
probability or reduced planning reserve margin; (3) production cost
savings; (4) reduced transmission energy losses; (5) reduced congestion
due to transmission outages; (6) mitigation of extreme events and
system contingencies; (7) mitigation of weather and load uncertainty;
(8) capacity cost benefits from reduced peak energy losses; (9)
deferred generation capacity investments; (10) access to lower-cost
generation; (11) increased competition; and (12) increased market
liquidity.
Table 1--Long-Term Regional Transmission Benefits
------------------------------------------------------------------------
Benefit Description
------------------------------------------------------------------------
Avoided or deferred reliability Reduced costs of avoided or
transmission facilities and aging delayed transmission
transmission infrastructure investment otherwise required
replacement. to address reliability needs
or replace aging transmission
facilities.
Reduced loss of load probability [OR Reduced frequency of loss of
next benefit]. load events by providing
additional pathways for
connecting generation
resources with load (if
planning reserve margin is
constant), resulting in
benefit of reduced expected
unserved energy by customer
value of lost load.
Reduced planning reserve margin [OR While holding loss of load
prior benefit]. probabilities constant, system
operators can reduce their
resource adequacy requirements
(i.e., planning reserve
margins), resulting in a
benefit of reduced capital
cost of generation needed to
meet resource adequacy
requirements.
Production cost savings................ Reduction in production costs,
including savings in fuel and
other variable operating costs
of power generation, that are
realized when transmission
facilities allow for the
increased dispatch of
suppliers that have lower
incremental costs of
production, displacing higher-
cost supplies; also reduction
in market prices as lower-cost
suppliers set market clearing
prices; when adjusted to
account for purchases and
sales outside the region,
called adjusted production
cost savings.
Reduced transmission energy losses..... Reduced energy losses incurred
in transmittal of power from
generation to loads, thereby
reducing total energy
necessary to meet demand.
Reduced congestion due to transmission Reduced production costs during
outages. transmission outages that
significantly increase
transmission congestion.
Mitigation of extreme events and system Reduced production costs during
contingencies. extreme events, such as
unusual weather conditions,
fuel shortages, and multiple
or sustained generation and
transmission outages, through
more robust transmission
system reducing high-cost
generation and emergency
procurements necessary to
support the system.
Mitigation of weather and load Reduced production costs during
uncertainty. higher than normal load
conditions or significant
shifts in regional weather
patterns.
Capacity cost benefits from reduced Reduced energy losses during
peak energy losses. peak load reduces generation
capacity investment needed to
meet the peak load and
transmission losses.
Deferred generation capacity Reduced costs of needed
investments. generation capacity
investments through expanded
import capability into
resource-constrained areas.
[[Page 26540]]
Access to lower-cost generation........ Reduced total cost of
generation due to ability to
locate units in a more
economically efficient
location (e.g., low permitting
costs, low-cost sites on which
plants can be built, access to
existing infrastructure, low
labor costs, low fuel costs,
access to valuable natural
resources, locations with high-
quality renewable energy
resources).
Increased competition.................. Reduced bid prices in wholesale
electricity markets due to
increased competition among
generators and reduced overall
market concentration/market
power.
Increased market liquidity............. Reduced transaction costs
(e.g., bid-ask spreads) of
bilateral transactions,
increased price transparency,
increased efficiency of risk
management, improved
contracting, and better
clarity for long-term
transmission planning and
investment decisions through
increased number of buyers and
sellers able to transact with
each other as a result of
transmission expansion.
------------------------------------------------------------------------
186. Below, we describe each benefit along with examples of how
each benefit may be calculated. We clarify that these are just
examples, and we are not proposing to require that public utility
transmission providers use any specific benefits or calculate those
benefits in a particular manner when conducting Long-Term Regional
Transmission Planning. At this time, we are only proposing to require
public utility transmission providers to identify what benefits they
will use in Long-Term Regional Transmission Planning and explain how
they will be calculated and how the benefits will reasonably reflect
the benefits of regional transmission facilities to meet identified
transmission needs driven by changes in the resource mix and demand.
187. We seek comment on each of the Long-Term Regional Transmission
Benefits discussed in this section of the NOPR. Additionally, we seek
comment on how to ensure that each type of benefit is distinct such
that the list of benefits does not ``double count'' benefits. We also
seek comment on the application of the Long-Term Regional Transmission
Benefits in non-RTO/ISO regions.
188. Finally, we seek comment on whether public utility
transmission providers should be required to use some or all of the
Long-Term Regional Transmission Benefits as a minimum set of benefits
for their Long-Term Regional Transmission Planning process.
(3) Description of Long-Term Regional Transmission Benefits
189. The benefits of transmission facilities identified in Long-
Term Regional Transmission Planning may include a set of benefits
related to avoided or deferred reliability transmission facilities and
aging transmission infrastructure replacement, which we describe as
reduced costs on avoided or delayed transmission investment otherwise
required to address reliability needs or replace aging transmission
facilities. The Commission has recognized that regional transmission
planning could lead to the development of transmission facilities that
span the service territories of multiple public utility transmission
providers, which in turn would obviate the need for transmission
facilities that would otherwise be identified in multiple local
transmission plans.\326\
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\326\ Order No. 1000, 136 FERC ] 61,051 at P 81.
---------------------------------------------------------------------------
190. The Commission has accepted accounting for such ``avoided
costs'' as part of a method for identifying beneficiaries and
allocating costs in almost all the regional cost allocation methods in
non-RTO/ISO regions. Using this method, public utility transmission
providers in a transmission planning region determine the beneficiaries
of a regional transmission facility or portfolio of facilities by
identifying the local and regional transmission facilities that a new
proposed regional transmission facility or portfolio of facilities
would displace. The method defines the benefits of the regional
transmission facility or facilities as the costs that public utility
transmission providers in the transmission planning region ``avoid''
because they no longer need to build the displaced local and regional
transmission facilities. The method allocates costs among public
utility transmission providers whose local or regional transmission
facilities the new proposed regional transmission facility or
facilities would displace in proportion to their share of the total
benefits (i.e., the total avoided costs). If the new proposed regional
transmission facility or facilities do not displace any local or
regional transmission facilities in existing local or regional
transmission plans, the avoided cost method determines the benefits of
the applicable facilities by considering the costs of local or regional
transmission facilities that would otherwise be needed to meet the same
need that the new proposed regional transmission facility will
meet.\327\
---------------------------------------------------------------------------
\327\ See, e.g., S.C. Elec. & Gas Co., 143 FERC ] 61,058, at P
232 (2013).
---------------------------------------------------------------------------
191. In calculating this benefit, public utility transmission
providers in each transmission planning region could first identify
transmission facilities that could defer or replace an identified
reliability transmission solution. Avoided cost benefits could be
calculated by comparing the cost of transmission facilities required to
address the reliability need without the proposed regional transmission
facility to the cost of transmission facilities needed to address the
reliability need assuming the regional transmission solution were in
place.\328\
---------------------------------------------------------------------------
\328\ Brattle-Grid Strategies Oct. 2021 Report at 37.
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192. Similarly, this benefit could also include the separate
benefits stream caused by a deferral of replacement of other
transmission facilities through identification and selection for
purposes of cost allocation in the regional transmission plan of a
transmission facility or facilities. This could be measured through
calculation of the present value savings for the period of deferral of
additional replacement transmission facilities multiplied by their
estimated capital cost.
193. A number of public utility transmission providers already
evaluate the avoided or deferred costs of reliability transmission
projects. For example, SPP uses a power flow model to analyze the
ability of potential economic and Public Policy transmission facilities
to meet the same thermal reliability needs addressed by a potential
reliability transmission facility. The costs of these avoided or
delayed reliability transmission
[[Page 26541]]
facilities are used to determine the reliability benefit of the
potential economic or Public Policy Requirements transmission
facilities.\329\ Public utility transmission providers could also use
avoided costs to calculate the benefits of replacing aging transmission
facilities. NYISO, for example, estimates the benefits associated with
the replacement of aging transmission facilities by quantifying the
savings of not having to refurbish the facilities in the future.\330\
---------------------------------------------------------------------------
\329\ SPP Benefit Metrics Manual, SPP Engineering, at 15 (Nov.
6, 2020).
\330\ The Brattle Group, Benefit-Cost Analysis of Proposed New
York AC Transmission Upgrades, The Brattle Group, at 114 (Sept. 15,
2015).
---------------------------------------------------------------------------
194. Another potential benefit of regional transmission
infrastructure is reduced frequency of loss of load events by providing
additional pathways for connecting generation resources with load in
regions that can be constrained by weather events and unplanned outages
(if planning reserve margin is not changed despite lower loss of load
events), as well as improved physical reliability benefits by reducing
the likelihood of load shed events; or reduced planning reserve margin,
which we propose to define as the reduction in capital costs of
generation needed to meet resource adequacy requirements (i.e.,
planning reserve margins) while holding loss of load probability
constant. There is an overlap between reduced loss of load probability
benefits and reduced planning reserve margin benefits, such that a
single transmission facility can either reduce loss of load events if
the planning reserve margin is unchanged or allow for the reduction in
planning reserve margins if loss of load events remain constant, but
not both simultaneously.
195. As for reduction in loss of load probability benefits,
transmission investments, even those not made to satisfy a reliability
need, generally enhance the reliability of the transmission system by
increasing transfer capability, which, in turn, reduces the likelihood
that a public utility transmission provider will be unable to serve its
load due to a shortage of generation over a given period. This
enhancement in reliability can be measured as a reduction in loss of
load probability, or the likelihood of system demand exceeding
generation over a given period. One example of how a reduction of loss
of load probability benefit could be calculated can be found in a
report by SPP's Metrics Task Force. The report proposes quantifying the
incremental increase in system reliability by determining the reduction
in expected unserved energy between the base case and the change case,
obtaining the value of lost load, and multiplying these two values to
obtain the monetary benefit of enhanced reliability associated with a
transmission expansion.\331\
---------------------------------------------------------------------------
\331\ SPP, Benefits for the 2013 Regional Cost Allocation
Review, at 25 (Sept. 13, 2012).
---------------------------------------------------------------------------
196. A lower planning reserve margin requirement is another way to
demonstrate a resource adequacy benefit. Investments in transmission
capacity can reduce the system-wide planning reserve margin requirement
of the system-wide or reserve margin requirement within individual
resource adequacy zones of a transmission planning region, which can
reduce the need for generation capital expenditures. It is important to
note that, due to the overlap between the benefit obtained from a
reduction in reserve margin requirements and the benefit associated
with loss of load probability, only one of these benefits should be
calculated for a transmission investment, but not both simultaneously.
197. RTOs/ISOs have calculated the transmission benefits of reduced
planning reserve margins. MISO, for example, calculated a reduction in
planning reserves associated with its MVP portfolio, which reduced the
need for future generation buildout to meet reserve requirements, by
using loss of load expectation reliability simulations. MISO estimated
that its MVP portfolio was expected to reduce the required planning
reserve margin by up to one percentage point, which translated into a
projected savings of $1.0 to $5.1 billion in benefits over 10
years.\332\
---------------------------------------------------------------------------
\332\ MISO, Proposed Multi Value Project Portfolio: Business
Case Workshop, at 36-38 (Sept. 19 & 29, 2011).
---------------------------------------------------------------------------
198. Another potential benefit of regional transmission
infrastructure is production cost savings, which we describe as savings
in fuel and other variable operating costs of power generation that are
realized when transmission facilities allow for displacement of higher-
cost supplies through the increased dispatch of suppliers that have
lower incremental costs of production, as well as a reduction in market
prices as lower-cost suppliers set market clearing prices.\333\
---------------------------------------------------------------------------
\333\ When this calculation is adjusted to account for purchases
and sales outside the region, we propose to define this as adjusted
production cost savings.
---------------------------------------------------------------------------
199. Most regional transmission planning processes currently
estimate production cost savings. Generally, within RTOs/ISOs,
security-constrained production cost models simulate the hourly
operations of the electric system and the wholesale electricity market
by emulating how system operators would commit and dispatch generation
resources to serve load at least cost, subject to transmission and
operating constraints. The traditional method for estimating the
changes in adjusted production costs associated with proposed
transmission facilities (or portfolio of facilities) is to compare the
adjusted production costs with and without those facilities. Analysts
typically call the market simulations without the proposed transmission
facilities the ``Base Case'' and the simulations with those facilities
the ``Change Case.''
200. Approaches used to calculate production cost savings vary.
MISO uses production cost savings (adjusted for import costs and export
revenues) to allocate the costs of its Market Efficiency Projects to
cost allocation zones based on each zone's share of the total adjusted
production cost savings.\334\ NYISO and PJM, in contrast, use
reductions to load energy payments (adjusted to reflect the reduced
value of transmission congestion contracts) to allocate the costs of
economic transmission facilities.\335\
---------------------------------------------------------------------------
\334\ See MISO, FERC Electric Tariff, Attach. FF, Benefit
Metrics Sec. (I)(A)(1) (33.0.0).
\335\ See PJM Interconnection L.L.C.,142 FERC ] 61,214, at P 416
(2013) (PJM First Regional Compliance Order); New York Independent
System Operator Corp.,143 FERC ] 61,059 at PP 268, 269, n.516 (2013)
(NYISO First Regional Compliance Order); NYISO, NYISO Tariffs, OATT,
attach. Y, Sec. 31.5 (27.0.0), Sec. 31.5.4.3.2. For high voltage
economic transmission facilities, PJM allocates 50% of the costs in
accordance with its economic analysis and allocates the other 50% of
the costs on a load-ratio share basis.
---------------------------------------------------------------------------
201. Non-RTO/ISO regions, without centrally organized energy
markets, rely on other tools to perform analyses of production cost
savings. For example, WestConnect's regional cost allocation method for
regional transmission facilities driven by economic considerations
identifies the benefits and beneficiaries of a proposed regional
transmission facility or facilities by modeling the potential of the
transmission facilities to support more economic bilateral transactions
between generators and loads in the region. Specifically, WestConnect
considers the transactions between loads and lower-cost generation that
a proposed regional transmission facilities could support and,
accounting for the costs associated with transmission service,
identifies the transactions that are likely to occur. WestConnect then
estimates any resulting cost savings (in the form of reductions in
production costs and reserve sharing requirements) and
[[Page 26542]]
allocates the costs of the regional transmission facilities on that
basis.\336\
---------------------------------------------------------------------------
\336\ Pub. Serv. Co. of Colo., 142 FERC ] 61,206, at P 314
(2013).
---------------------------------------------------------------------------
202. Another set of potential benefits of regional transmission
infrastructure is benefits related to reduced transmission energy
losses, which we describe as reduced total energy necessary to meet
demand stemming from reduced energy losses incurred in transmittal of
power from generation to loads. These benefits include the reduced
energy losses incurred when transmitting power from generation to
loads.
203. Production cost savings metrics used today typically exclude
reduced transmission energy losses and the other three production cost
savings-related benefits in our proposed list described further below.
Including these additional benefits can produce a more robust set of
congestion and production cost benefits that can be quantified and
integrated into the method for calculating production cost savings,
and, therefore, help to ensure that the more efficient or cost-
effective transmission facilities are selected in the regional
transmission plan for purposes of cost allocation through Long-Term
Regional Transmission Planning.
204. To measure reduced transmission energy losses, public utility
transmission providers could: (1) Simulate losses in production cost
models; (2) estimate changes in losses with power flow models for a
range of hours; or (3) estimate how the cost of supplying losses will
likely change with marginal loss charges. For example, American
Transmission Company (ATC) measured reduced transmission energy losses
based on changes in marginal loss charges and loss refund estimates
using the marginal loss component from the PROMOD \337\ electric market
simulation software simulations for the Paddock-Rockdale 345 kV Access
Project,\338\ which produced cost reduction benefits using adjusted
production cost analysis. Also, SPP's analysis for its Regional Cost
Allocation Review (RCAR) process estimated energy loss reductions
through post-processing the marginal loss component of the locational
marginal prices in PROMOD simulation results.\339\
---------------------------------------------------------------------------
\337\ PROMOD is a generator and portfolio modeling system.
https://www.hitachienergy.com/us/en/offering/product-and-system/energy-planning-trading/market-analysis/promod.
\338\ ATC explains that the marginal loss component for
transmitting internal generation to load is the marginal loss charge
differential between load and generation, and the loss refund
returns half of that amount. ATC, Planning Analysis of the Paddock-
Rockdale Project, Docket No. 137-CE-149, app. C, Ex. 1, at 34-38
(Wisc. Pub. Serv. Comm'n Apr. 5, 2007).
\339\ SPP, Regional Cost Allocation Review (RCAR II), at 5 (July
11, 2016), https://www.spp.org/documents/46235/rcar%202%20report%20final.pdf.
---------------------------------------------------------------------------
205. Another set of potential benefits of regional transmission
infrastructure is benefits related to reduced congestion due to
transmission outages, which we describe as reduced production costs
resulting from avoided congestion during transmission outages. Such
benefits include reduced production costs during transmission outages
that significantly increase transmission congestion. Production cost
simulations typically consider planned generation outages and, in most
cases, a random distribution of unplanned generation outages. In
contrast, they do not generally reflect transmission outages, planned
or unplanned.\340\ Public utility transmission providers could measure
this benefit, for example, by either building a data set of a
normalized outage schedule (not including extreme events) that can be
introduced into simulations or by inducing system constraints more
frequently. In its RCAR process, SPP measured the benefits of reducing
congestion resulting from transmission outages. There, SPP modeled
outage events and new constraints based on these outages in PROMOD for
a 2025 case year, and then conducted PROMOD simulations to calculate
adjusted production cost savings for a base case and the change case
including the transmission line.\341\ In another example, SPP
calculated the financial value of reducing congestion caused by outages
based on a rerun of its entire day-ahead and real-time market.
---------------------------------------------------------------------------
\340\ Brattle-Grid Strategies Oct. 2021 Report at 79.
\341\ SPP, Regional Cost Allocation Review (RCAR II), at 51-52.
To estimate incremental savings associated with mitigation of
transmission outage costs, SPP analyzed outage cases in PROMOD for
the 2025 study year. SPP developed cases based on 12 months of
historical SPP transmission data. SPP said that because of the high
volume of historical transmission outage data (approximately 7,000
outage events) and based on the expectation that many outages would
not lead to significant increases in congestion, SPP only modeled a
subset of outage events. The events selected were those expected to
create significant congestion and met at least one of three
conditions. Id. at 51.
---------------------------------------------------------------------------
206. Another set of potential benefits of regional transmission
infrastructure is benefits related to mitigation of extreme events and
system contingencies, which we describe as reductions in production
costs resulting from reduced high-cost generation and emergency
procurements necessary to support the transmission system during
extreme events (such as unusual weather conditions, fuel shortages, or
multiple or sustained generation and transmission outages) and system
contingencies. These benefits include reduced production costs during
extreme events facilitated by a more robust transmission system that
reduces high-cost generation and emergency procurements necessary to
support the system.
207. Public utility transmission providers can measure benefits
from the mitigation of extreme events and system contingencies by
calculating the probability-weighted production cost savings through
production cost simulation for a set of extreme historical market
conditions. One example is CAISO's analysis of Devers-Palo Verde Line
No. 2 (PVD2), where CAISO modeled several contingencies to determine
the value of the line during high-impact, low-probability events.\342\
Another example is ATC's production cost simulation analysis of
insurance benefits for the ATC Paddock-Rockdale transmission line. ATC
found that probability-weighted savings from reducing production and
power purchase costs during a number of simulated extreme events offset
20% of total project costs.\343\ Finally, a Grid Strategies study found
development of an additional 1,000 MW of transmission capacity into
Texas would have fully paid for itself over four days during Winter
Storm Uri and the same into MISO would have saved $100 million during
the same time period.\344\
---------------------------------------------------------------------------
\342\ Opinion Granting Certificate of Public Convenience and
Necessity, In the Matter of the Application of Southern California
Edison Company (U 338-E) for a Certificate of Public Convenience and
Necessity Concerning the Devers-Palo Verde No. 2 Transmission Line
Project, Application 05-04-015 (Cal. Comm'n Jan. 27, 2007).
\343\ ATC, Planning Analysis of the Paddock-Rockdale Project,
Docket No. 137-CE-149, app. C, Ex. 1, at 4, 50-53 (Wisc. Pub. Serv.
Comm'n Apr. 5, 2007).
\344\ M. Goggin, Grid Strategies, LLC, Transmission Makes the
Power System Resilient to Extreme Weather (July 2020).
---------------------------------------------------------------------------
208. Another set of potential benefits of regional transmission
infrastructure is benefits related to mitigation of weather and load
uncertainty, which we describe as reduced production costs during
higher-than-normal load conditions or significant shifts in regional
weather patterns. This is beyond the effects of extreme weather
described above and may account for, for example, regional and sub-
regional load variances that will occur due to changing weather
patterns. This ignores the potential benefit of transmission expansions
under more normal system operating conditions, such as when the system
experiences higher-than-normal load conditions or significant shifts in
[[Page 26543]]
regional weather patterns that change the relative power consumption
levels across multiple regions or sub-regions.
209. One example of the mitigation of weather and load uncertainty
benefits is the simulations that ERCOT performed for normal loads,
higher-than-normal loads, and lower-than-normal loads for a Houston
import project, which showed increased benefits with a probability-
weighted average for all three simulated load conditions.\345\ To
measure this benefit, production cost model inputs under high and low
load conditions can be used to develop regional variations of relative
benefits under these conditions. Production cost benefits can then be
modeled based upon a probability weighted average anticipating varying
load conditions, with the increment over a base case representing
additional production cost savings.
---------------------------------------------------------------------------
\345\ ERCOT, Economic Planning Criteria: Question 1: 1/7/2011
Joint CMWG/PLWG Meeting, at 10 (Mar. 4, 2011). The $57.8 million
probability-weighted estimate is calculated based on ERCOT's
simulation results for three load scenarios and Luminant Energy
estimated probabilities for the same scenarios.
---------------------------------------------------------------------------
210. Another set of potential benefits of regional transmission
infrastructure is capacity cost benefits related to reduced peak energy
losses, which we describe as reduced generation capacity investment
needed to meet peak load.
211. Capacity cost savings from reduced peak energy losses benefits
refer to the ability of proposed transmission facilities to lessen the
amount of transmission system energy losses during peak-load conditions
which, over time, would decrease the need for new generation capacity
installations or purchases. To the extent that new transmission
facilities result in changes to generation dispatch and flows,
transmission system energy losses will also change. If transmission
system losses are reduced via the new transmission facilities, public
utility transmission providers will not have to construct or procure
additional generation to satisfy installed capacity requirements for
peak-load conditions. If there is a reduction in energy losses during
peak conditions, this would result in, presumably, lowered investments
for generation capacity resources to meet the peak load. For example,
Entergy found that potential transmission facilities in its footprint
could reduce peak-load transmission losses and associated needed
generation investment by 2% of total transmission facility costs.\346\
We note that capacity cost savings from reduced peak energy losses only
attempt to evaluate benefits for peak-load conditions.
---------------------------------------------------------------------------
\346\ ITC Holdings Co., Joint Application, Docket No. EC12-145-
000, at Ex. ITC-600, 77-78 (Test. of Pfeifenberger) (filed Sept. 24,
2012).
---------------------------------------------------------------------------
212. One potential way to calculate capacity cost savings from
reduced peak energy losses is to calculate the present value of capital
cost savings associated with the reduction in installed generation
requirements.\347\ To arrive at the value of capital cost savings
associated with these savings, the estimated net cost of new entry (Net
CONE) (i.e., the cost of new peaking generating capacity net of
operating margins earned in energy and ancillary services markets when
the region is resource constrained) would be multiplied by the
reduction in installed generation capacity requirements. The resulting
value would represent the avoided cost of procuring more generation to
cover transmission system losses during peak-load conditions that would
be passed on to consumers via lowered generation capacity costs.
---------------------------------------------------------------------------
\347\ Id.
---------------------------------------------------------------------------
213. Another set of potential benefits of regional transmission
infrastructure is benefits related to deferred generation capacity
investments, which we describe as reduced costs of needed generation
capacity investments realized through expanded import capability into
resource-constrained areas.
214. Deferred generation capacity investments benefits reflect the
value of increased transfer capability, provided by new transmission
facilities, that either defers or negates the need to invest in
generation capacity resources within a transmission planning region by
increasing import capability from neighboring regions into resource-
constrained areas. By expanding the transmission system's capacity to
deliver energy to load centers, public utility transmission providers
may avoid additional generation capacity investments closer to load
centers. We note, for example, an ITC study examining transmission
facilities between the eastern, non-ERCOT region of Texas that can
import energy from Arkansas and Louisiana. The study highlighted that,
by enabling imports of surplus energy from Arkansas and Louisiana,
additional generation capacity investments were not needed in the
eastern, non-ERCOT region of Texas.\348\
---------------------------------------------------------------------------
\348\ Id. at 58-59.
---------------------------------------------------------------------------
215. One potential manner of calculating deferred generation
capacity investments is to calculate the present value of generation
capacity cost savings resulting from deferred generation investments,
based on Net CONE. Specifically, the total value of deferred generation
investments could be determined by multiplying the change in the public
utility transmission provider's installed capacity requirement by Net
CONE. The value of deferred generation capacity investments would
ultimately benefit consumers through lower generation capacity costs.
216. Another set of potential benefits of regional transmission
infrastructure is benefits related to access to lower-cost generation,
which we describe as reduced total cost of needed generation due to the
ability to locate generating units in a more economically efficient
location (e.g., low permitting costs, low-cost sites on which plants
can be built, access to existing infrastructure, low labor costs, low
fuel costs, access to valuable natural resources). In other words, this
refers to the value of savings that may accrue to consumers who,
because of a new regional transmission facility or portfolio of
facilities, are able to access lower cost generation resources that
they would have been unable to otherwise. For example, if the new
regional transmission facilities extend to generation located farther
from load centers that may be lower-cost compared to generation located
closer to load centers that may be higher-priced, the new regional
transmission facilities will provide savings to consumers via increased
access lower-cost generation. We note, for example, that CAISO found
that its proposed PVD2 transmission project, which provided an
additional link between Arizona and California, permitted CAISO to meet
reliability requirements through imports of lower-cost, new generation
in Arizona.\349\
---------------------------------------------------------------------------
\349\ Opinion Granting Certificate of Public Convenience and
Necessity, In the Matter of the Application of Southern California
Edison Company (U 338-E) for a Certificate of Public Convenience and
Necessity Concerning the Devers-Palo Verde No. 2 Transmission Line
Project, Application 05-04-015 (Cal. Comm'n Jan. 27, 2007).
---------------------------------------------------------------------------
217. One potential way to calculate benefits from access to lower-
cost generation enabled by a regional transmission facility or
portfolio of facilities would be calculating them akin to how
production cost savings are calculated. Specifically, public utility
transmission providers could calculate the reduction in total
generation investment costs by comparing the status quo (i.e., higher-
cost local generation) to a future (i.e., lower-cost distant
generation) where the proposed new regional transmission facilities
allow for the import of those lower-cost generation. By allowing for
the import of lower-cost generation, consumers
[[Page 26544]]
would benefit via reduced total cost of generation.
218. While we acknowledge calculating benefits from access to
lower-cost generation may be similar to methodologies for calculating
production cost savings, we believe that calculating production cost
savings using traditionally used methodologies would not adequately
capture benefits associated with capacity cost savings. Such
methodologies do not account for capacity cost savings since they do
not consider load variances during hotter or colder than normal weather
conditions; do not consider transmission system outages or other
situations where less than the full transfer capability of the
transmission facility is available; do not consider extreme events like
multiple generator outages; and do not capture ``real-world''
operational issues such as forecasting errors or unexpected loop
flows.\350\ Additionally, we believe that calculating access to lower-
cost generation benefits, as Brattle Group explains, may require
additional or separate analysis by public utility transmission
providers since accurately capturing the aforementioned benefits may
require a different generation mix than specified in the production
cost simulations between the Base Case (e.g., with generation located
in lower-quality or higher-cost locations) and the Change Case (e.g.,
with more generation located in higher-quality or lower-cost
locations).\351\
---------------------------------------------------------------------------
\350\ TC Holdings, Joint Application, Docket No. EC12-145-000,
Ex. No. ITC-600, at 54-55 (filed Sept. 24, 2012) (Pfeifenberger,
Direct Testimony on behalf of ITC Holdings).
\351\ Brattle-Grid Strategies Oct. 2021 Report at 46-47.
---------------------------------------------------------------------------
219. Another set of potential benefits of regional transmission
infrastructure is benefits related to increased competition. We
describe increased competition as reduced bid prices in wholesale
electricity markets due to increased competition among generators and
reduced overall market concentration. Regional transmission facilities
can increase competition in, and the liquidity of, wholesale electric
power markets by increasing the number of wholesale electricity
suppliers that are able to compete to supply electricity at locations
in the transmission network served by the transmission facility,\352\
which helps to ensure just and reasonable Commission-jurisdictional
rates.
---------------------------------------------------------------------------
\352\ F.A. Wolak, Managing Unilateral Market Power in
Electricity, Policy Research Working Paper; No. 3691. World Bank,
Washington, DC, at 8 (2005).
---------------------------------------------------------------------------
220. More specifically, to the extent that certain portions of a
transmission planning region remain import-constrained, such that a
single resource, or even a small number of resources, can have an
outsized influence on the price of energy paid by load by increasing
the price in their offer to sell energy, additional transmission
capacity may reduce such influence, and thereby create benefits to
transmission customers in the form of reduced energy prices.
221. Some public utility transmission providers have considered
this benefit for certain transmission facilities. For example, CAISO
evaluated the PVD2 and Path 26 Upgrade projects, and ATC evaluated its
Paddock-Rockdale project, for increased competition benefits.\353\ We
highlight three possible methods to calculate increased competition
benefits, all of which ATC employed in evaluating the benefits of the
Paddock-Rockdale Project, as examples of how public utility
transmission providers could calculate this benefit. The first two
methods that ATC employed are similar in that ATC estimated the change
in a measure of market concentration (i.e., the extent to which the
largest supplier is pivotal)--called the Residual Supplier Index
\354\--which assumes a certain percentage of load is subject to market-
based pricing, and measured the subsequent effect on generators'
ability to offer above their marginal costs (measured as a price-cost
markup) and related energy prices. ATC calculated the change in the
Residual Supplier Index using an assumed change in import capability to
the area served by the new transmission facility.
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\353\ Opinion Granting Certificate of Public Convenience and
Necessity, In the Matter of the Application of Southern California
Edison Company (U 338-E) for a Certificate of Public Convenience and
Necessity Concerning the Devers-Palo Verde No. 2 Transmission Line
Project, Application 05-04-015 (Cal. Comm'n Jan. 27, 2007); CAISO,
Transmission Economic Assessment Methodology, Chapter 4 (Jun. 2004);
ATC, Planning Analysis of the Paddock-Rockdale Project, at 44-49
(Apr. 5, 2007).
\354\ The Residual Supplier Index is calculated as the ratio of
residual supply (i.e., total supply minus the capacity of the
largest supplier in the market) to the total demand. If the Residual
Supplier Index is less than 1.0, it means the largest supplier is
``pivotal,'' meaning that a load cannot be served without the
largest supplier making available at least some of its capacity.
With inelastic demand, a pivotal supplier theoretically would be
able to set the market price at any desired level above the
competitive price. See von der Fehr, Nils-Henrik & David Harbord,
Spot Market Competition in the UK Electricity Industry, Economic
Journal, at 103, 531-46 (1993); ATC, Planning Analysis of the
Paddock-Rockdale Project, Docket No. 137-CE-149, app. C, Ex. 1, at
44 & n.11 (Wisc. Pub. Serv. Comm'n Apr. 5, 2007).
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222. The first method ATC employed to calculate the increased
competition benefit, called the ``Modified MISO IMM Method,'' draws
from two key assumptions to determine price mark-ups. First, the
Modified MISO IMM Method requires an estimate of the pivotal supplier's
price-cost markup for the area served by the transmission facility for
all times when the supplier is pivotal.\355\ Second, this method
assumes that the price-cost markup increases linearly as the Residual
Supplier Index falls below 1.2,\356\ such that there is no price-cost
markup where the Residual Supplier Index for an hour is above 1.2
(i.e., no improved competition benefit) and the price markup is half
the estimated price-cost markup from the first assumption where the
Residual Supplier Index for an hour is less than 1.0. Finally, this
method assumes that the pivotal supplier is the marginal resource that
sets the energy price when the Residual Supplier Index is below 1.2.
The difference in price-cost markup for hours when the Residual
Supplier Index is below 1.2 provides the benefits from increased
competition.
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\355\ In the case of the Paddock-Rockdale Project, the MISO
independent market monitor had designated the area as a ``Narrow
Constrained Area'' and estimated that, whenever a resource became
pivotal in that area its offer would exceed its marginal costs by up
to $36/MWh. While the MISO independent market monitor provided such
an estimate for the Paddock-Rockdale Project, we do not suggest that
any specific entity conduct the necessary study deriving this
estimate (e.g., the public utility transmission providers in a
transmission planning region could also conduct such a study).
\356\ This assumption is based on a study analyzing summer 2000
peak hourly data from the California Power Exchange. Sheffrin, A.,
(2002), ``Predicting Market Power Using the Residual Supplier
Index,'' Mimeo, Department of Market Analysis, CAISO.
---------------------------------------------------------------------------
223. The second potential method to calculate increased competition
benefits that ATC employed, the ``Modified CAISO Method,'' estimates
the energy price impacts of a new transmission facility by using
regression analysis to find the relationship between historical market
structure and price-bid markups. CAISO first developed this regression
equation and its coefficients in its 2004 report evaluating the
economic viability of certain transmission upgrades, including the PVD2
and Path 26 Upgrade projects.357 CAISO's study also used two binary
indicator variables: One for the summer period in CAISO and another for
peak hours. We note that public utility transmission providers using
the Modified CAISO approach may find that coefficients developed using
data specific to the transmission planning region where the public
utility transmission provider is located are more appropriate and may
also wish to include more independent variables specific to their
respective transmission planning regions.
[[Page 26545]]
224. The third potential method to calculate increased competition
benefits, the ``Bidding Behavior Method,'' relies on a simulation model
that optimizes bidding behavior from a supplier perspective given each
supplier's supply portfolio and load obligations. This model could be
based on the theoretical incentive that suppliers have to increase
price-cost markups in proportion to the absolute value of the slope of
residual demand (i.e., total demand less the supply of all other
resources serving the same load).\358\ Public utility transmission
providers in a transmission planning region would develop a study
estimating market prices for a future period matching the planning
horizon as load, generation supply, transmission constraints, and
import capability changed. Public utility transmission providers in a
transmission planning region would also assume that a percentage of
load was exposed to congestion.
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\358\ See, e.g., F.A. Wolak, Measuring the competitiveness
benefits of a transmission investment policy: The case of the
Alberta electricity market 86 Energy Policy 426-444 (June 2015); N.
Ryan, The Competitive Effects of Transmission Infrastructure in the
Indian Electricity Market, 13 American Economic Journal:
Microeconomic 2, 202-42 (May 2021).
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225. Finally, another set of potential benefits of regional
transmission infrastructure is benefits related to increased market
liquidity. We describe increased market liquidity as enabling a larger
number of entities, both buyers and sellers, to participate in a
market. By increasing the number of market participants, both buyers
and sellers, transmission facilities may provide benefits through
reduced transaction costs (e.g., bid-ask spreads) of bilateral
transactions, increased pricing transparency, increased efficiency of
risk management, improved contracting, and better clarity for long-term
transmission planning and investment decisions.\359\ The primary
increased market liquidity benefit to transmission customers is the
decrease in energy prices. For example, bid-ask spreads for bilateral
trades at less liquid hubs have been found to be between $0.50 to
$1.50/MWh higher than the bid-ask spreads at more liquid hubs.\360\
Public utility transmission providers could quantify increased market
liquidity benefits to transmission customers by estimating (1) how
additional transmission facilities may increase liquidity and (2) how
increased liquidity may reduce bid-asks spreads or energy prices.
---------------------------------------------------------------------------
\359\ Brattle-Grid Strategies Oct. 2021 Report at 50.
\360\ Id.
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(b) Evaluation of Transmission Benefits Over Longer Time Horizon
(1) Comments
226. Several commenters responding to the ANOPR recommend that the
Commission allow or require public utility transmission providers to
evaluate the benefits of transmission facilities over a longer time
horizon.\361\ For example, ACPA and ESA argue that proper economic
analysis entails an analysis of the benefits of a proposed transmission
facility over the asset's life, which is at least 40 years for
transmission lines.\362\ Other commenters, however, raise concerns with
attempts to forecast future transmission system conditions in order to
consider potential benefits on a longer time horizon.\363\ For example,
Xcel argues that planning for the future is inherently uncertain, and
that the benefits of transmission facilities can change over time.\364\
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\361\ See, e.g., NYISO Comments at 34-37 (stating that NYISO
limits consideration of benefits to 10 years and recommending that
the Commission grant public utility transmission providers
discretion to plan for up to 20 years of needs and benefits); see
also NextEra Comments at 79-80 (recommending a similar length of
time for consideration of benefits as for scenario planning); see
also February Joint Task Force Tr 20:23-25 (Clifford Rechtschaffen)
(arguing that the Commission should extend the timeframe over which
benefits are calculated to be 15-20 years or longer), 24:4-8
(Matthew Allen) (advocating for recognizing benefits over at least a
20-year timeframe given the long life of transmission assets).
\362\ ACPA and ESA Comments at 44-45; see also PIOs Comments at
121-122.
\363\ Entergy Comments at 10-11; see also EEI Comments at 30-31
(arguing for maintaining the Commission's policies on abandoned
plant recovery because of the additional uncertainty inherent in
longer-term transmission planning); Minnesota Commerce Comments at 3
(stating that future uncertainty is compounded by the rapid pace of
technological change).
\364\ Xcel Comments at 20 n.52.
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(2) Proposed Reform
227. We propose to require that public utility transmission
providers in each transmission planning region evaluate, as part of
Long-Term Regional Transmission Planning, the benefits of regional
transmission facilities over a time horizon that covers, at a minimum,
20 years starting from the estimated in-service date of the
transmission facilities. For example, if Long-Term Regional
Transmission Planning identifies transmission facilities that are
estimated to be in-service in year 10 of the 20-year long-term
transmission planning horizon, then the estimate of benefits for those
same transmission facilities will commence at year 10 and cover an
additional 20 years. We believe that 20 years may strike an appropriate
balance that reasonably illustrates the benefits a transmission
facility is likely to provide over its useful life, which can exceed 40
years, while recognizing the inherent difficulties in attempting to
predict system conditions too far into the future. Moreover, we note
that some public utility transmission providers currently conduct long-
term transmission planning over a 20-year horizon, and thus have some
experience with modelling and making assumptions over this period,
though such modelling is typically for informational purposes and not
to select transmission facilities in the regional transmission plan for
purposes of cost allocation.\365\
---------------------------------------------------------------------------
\365\ See MISO, LRTP Business Case, Long Range Transmission
Planning Workshop, at slide 7 (Jan. 21, 2022, Revised Feb. 2, 2022),
https://cdn.misoenergy.org/20220121%20LRTP%20Workshop%20Item%2004%20Business%20Case%20Presentation619895.pdf; CAISO, 20-Year Transmission Outlook (Draft Jan. 31,
2022), https://www.caiso.com/InitiativeDocuments/Draft20-YearTransmissionOutlook.pdf; SPP Engineering, 2021 SPP Transmission
Expansion Plan Report (Jan. 11, 2021), https://spp.org/documents/56611/2021%20step%20report.pdf.
---------------------------------------------------------------------------
228. We propose to require that public utility transmission
providers evaluate benefits over this time horizon in all stages of
Long-Term Regional Transmission Planning, which includes evaluating
regional transmission facilities, selecting more efficient or cost-
effective regional transmission facilities in the regional transmission
plan for purposes of cost allocation, and allocating the costs of such
transmission facilities in a manner that is at least roughly
commensurate with estimated benefits. We also note that for consistency
and a matching comparison of benefits and costs over time, to the
extent that public utility transmission providers estimate the costs of
transmission facilities beyond the in-service date of the transmission
facilities, we propose that they should estimate those future costs
over the same time horizon as the estimated benefits.
229. Finally, while we propose to establish a minimum requirement
for the time horizon over which benefits must be evaluated, we clarify
that public utility transmission providers may propose approaches that
exceed this minimum requirement. In particular, while we believe that
20 years may strike a reasonable balance, we also believe that a time
horizon longer than 20 years for the evaluation of benefits may be
consistent with the long life of transmission facilities--
[[Page 26546]]
which generally exceeds 20 years by a substantial margin--and also
consistent with the fact that transmission facilities provide
significant benefits over their entire useful life.\366\ To the extent
public utility transmission providers would like to evaluate
transmission benefits beyond the proposed minimum time horizon, we
propose to require that they demonstrate that their proposal is
consistent with or superior to any final rule in this proceeding.
---------------------------------------------------------------------------
\366\ ACPA and ESA Comments at 44-45; see also WIRES Comments at
7-8 (recommending accounting for benefits of transmission facilities
over their useful lives).
---------------------------------------------------------------------------
230. We seek comment on the requirements proposed in this section
of the NOPR.
(c) Evaluation of the Benefits of Portfolios of Transmission Facilities
231. In the ANOPR, the Commission sought comment on whether public
utility transmission providers would identify more efficient or cost-
effective transmission facilities in their regional transmission
planning processes if they evaluated the benefits of a portfolio of
transmission facilities collectively rather than individual
transmission facilities separately.\367\
---------------------------------------------------------------------------
\367\ ANOPR, 176 FERC ] 61,024 at PP 53, 89, 91.
---------------------------------------------------------------------------
(1) Comments
232. Many commenters recommend that the Commission permit or
require public utility transmission providers to use a portfolio
approach when evaluating the benefits of transmission facilities.\368\
Under such an approach, public utility transmission providers would
evaluate multiple transmission facilities in an aggregated, integrated
fashion rather than doing so on a facility-by-facility basis. For
example, U.S. DOE argues that a portfolio approach is more likely to
result in an accurate evaluation of the benefits of transmission
facilities than would an approach requiring evaluation of each facility
individually,\369\ while PIOs claim that facility-by-facility rather
than portfolio-based evaluation underestimates the benefits of regional
transmission facilities.\370\ Other commenters explain that public
utility transmission providers could achieve administrative
efficiencies using a portfolio approach, which can help avoid the
necessity of running the same analyses on each facility.\371\
---------------------------------------------------------------------------
\368\ ITC Comments at 11; State Agencies Comments at 21; ELCON
Reply Comments at 3-4; see also Southern Comments at 13-14 (stating
that vertically-integrated utilities already use a portfolio
approach).
\369\ U.S. DOE Comments at 40-41.
\370\ PIOs Comments at 50-51.
\371\ ACEG Reply Comments at 5, 8; ITC Comments at 6, 11, 28.
---------------------------------------------------------------------------
(2) Proposed Reform
233. We propose to afford public utility transmission providers in
each transmission planning region the flexibility to propose to use a
portfolio approach in the evaluation of benefits of regional
transmission facilities through their Long-Term Regional Transmission
Planning. Evaluating the benefits of a portfolio of regional
transmission facilities appears to contain several advantages compared
to evaluating the benefits of each proposed regional transmission
facility individually. Several commenters explain that future benefits
may be more stable or evenly distributed over time if they are
evaluated for a portfolio of transmission facilities.\372\ These
comments are consistent with the fact that benefits from transmission
facilities may change over time due to the inherent uncertainty in
Long-Term Regional Transmission Planning and actual use of transmission
facilities. An example of the evaluation of expanded benefits for a
portfolio of transmission facilities is the MISO MVP Portfolio, which
is a collection of 17 distinct transmission facilities, for which MISO
evaluated a collective distribution of benefits.\373\ Given the suite
of minimum benefits proposed above, we believe that evaluating these
benefits across a portfolio of transmission facilities as opposed to
each individual transmission facility may result in significant
administrative efficiencies for public utility transmission providers.
Moreover, we believe that a more stable or even distribution of
benefits from a portfolio of transmission facilities may also
facilitate agreement on regional cost allocation that is at least
roughly commensurate with estimated benefits.
---------------------------------------------------------------------------
\372\ U.S. DOE Comments at 40-41; see also February Joint Task
Force Tr 24:15-22 (Matthew Allen) (stating his belief that
transmission planners should be looking at projects and benefits on
a portfolio basis to identify synergies).
\373\ MISO, Multi Value Project Portfolio Results and Analyses
at 1-6 (2012), https://cdn.misoenergy.org/2011%20MVP%20Portfolio%20Analysis%20Full%20Report117059.pdf.
---------------------------------------------------------------------------
234. Accordingly, we encourage this practice by public utility
transmission providers. We clarify that public utility transmission
providers that propose such an approach must include in their OATTs
provisions describing how they would analyze the benefits of regional
transmission facilities under a portfolio approach and whether the
portfolio approach would be used for Long-Term Regional Transmission
Planning universally to address transmission needs driven by changes in
the resource mix and demand or would be used only in certain specified
instances.
235. We recognize that a variety of commenters request that we
require the use of a portfolio approach. While we recognize the
advantages to a portfolio approach, we also acknowledge that the
transition to a portfolio approach may represent a significant change
for many public utility transmission providers and that the potential
benefits may not warrant such a change in all instances.\374\ We seek
comment as to whether there are certain circumstances for which the
Commission should require the use of a portfolio approach.
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\374\ See, e.g., February Joint Task Force Tr. 76:10-12
(Kimberly Duffley) (asking that the Commission recognize regional
differences that may result in portfolio projects working for one
region but not for all regions).
---------------------------------------------------------------------------
iv. Selection of Regional Transmission Facilities
236. Order No. 1000 requires public utility transmission providers
to include in their OATTs a transparent and not unduly discriminatory
process for evaluating whether to select a proposed regional
transmission facility in the regional transmission plan for purposes of
cost allocation.\375\ Order No. 1000 does not mandate that public
utility transmission providers select any transmission facility,\376\
and the Commission declined for the most part to set minimum standards
for the criteria used to select a transmission facility in a regional
transmission plan for purposes of cost allocation. However, the
Commission required that a public utility transmission provider's
selection criteria be transparent and not unduly discriminatory.\377\
---------------------------------------------------------------------------
\375\ Order No. 1000, 136 FERC ] 61,051 at PP 328-331; Order No.
1000-A, 139 FERC ] 61,132 at P 452.
\376\ Order No. 1000, 136 FERC ] 61,051 at P 331.
\377\ See Order No. 1000-A, 139 FERC ] 61,132 at P 455.
---------------------------------------------------------------------------
237. In the ANOPR, the Commission sought comment on whether and how
public utility transmission providers should use information developed
through long-term scenario planning to identify and select transmission
facilities that meet future needs. In addition, the Commission sought
comment on how public utility transmission providers should evaluate
the benefits of proposed transmission facilities in their regional
transmission planning processes, and whether the maximization of net
benefits is an appropriate criterion for selecting transmission
facilities in the regional transmission plan for purposes of cost
[[Page 26547]]
allocation.\378\ Finally, the Commission sought comment on whether
public utility transmission providers would select more efficient or
cost-effective transmission facilities in their regional transmission
planning processes if they selected a portfolio of transmission
facilities collectively.\379\
---------------------------------------------------------------------------
\378\ ANOPR, 176 FERC ] 61,024 at P 53.
\379\ See id. PP 89, 91.
---------------------------------------------------------------------------
(a) Comments
238. With respect to the selection of transmission facilities in a
regional transmission plan for purposes of cost allocation, commenters
responding to the ANOPR provided a wide range of feedback. Several
commenters emphasize that scenario planning should ensure the selection
of more efficient or cost-effective transmission facilities,\380\ while
others argue that scenario planning should be solely for informational
purposes.\381\ Certain commenters believe that Commission guidance on
selection criteria is essential,\382\ while others argue that the
Commission instead should provide flexibility for public utility
transmission providers to adopt selection criteria.\383\
---------------------------------------------------------------------------
\380\ AEP Comments at 10; Ameren Reply Comments at 3; see also
Anbaric Comments at 32 (recommending that the Commission impose
deadlines to ensure that transmission planning processes select
offshore wind transmission facilities rather than allowing results
to ``languish in protracted stakeholder processes''); AEE Reply
Comments at 7-8 (requesting the adoption of transparency and
enforcement mechanisms that would ensure the selection of
transmission facilities that meet regional needs).
\381\ See PJM Comments at 44 (stating that PJM's proposed long-
term transmission planning process will ``inform stakeholder
discussions''); see also Xcel Energy Comments at 20 (``The
Commission should not require all issues identified in the holistic
planning process to result in planned projects.'').
\382\ PJM Comments at 46; see also City of New York Comments at
11 (arguing that the Commission should adopt common project
selection criteria); Policy Integrity Comments at 17 (recommending
greater uniformity in selection criteria); Massachusetts Attorney
General Comments at 25 (arguing that consumer protection requires
that selection criteria be ``clear, real, and objective'').
\383\ MISO Comments at 32; National Grid Comments at 14-15;
American Municipal Power Comments at 15.
---------------------------------------------------------------------------
239. Many commenters also recommend that the Commission permit or
require public utility transmission providers to use a portfolio
approach when selecting transmission facilities.\384\ U.S. DOE explains
that the benefits of individual transmission facilities typically are
distributed unevenly across a region, whereas portfolios of
transmission facilities generally would be expected to confer benefits
more broadly and evenly.\385\
---------------------------------------------------------------------------
\384\ ITC Comments at 9, 11, 33; NARUC Comments at 12; PIOs
Comments at 50-51; State Agencies Comments at 21; AEP Reply Comments
at 33; ELCON Reply Comments at 3-4; see also Southern Comments at
13-14 (stating that vertically-integrated utilities already use a
portfolio approach).
\385\ U.S. DOE Comments at 40-41.
---------------------------------------------------------------------------
240. With respect to specific selection criteria or methods,
several commenters support an approach that would select transmission
facilities with the highest level of net benefits instead of facilities
with the highest benefit-cost ratio,\386\ whereas other commenters
support maintaining the maximum 1.25 benefit-cost ratio permitted by
Order No. 1000.\387\ Other commenters recommend a ``least-regrets''
approach to selecting transmission facilities, in which public utility
transmission providers would select a transmission facility identified
through scenario planning as beneficial across many or all
scenarios.\388\
---------------------------------------------------------------------------
\386\ ITC Comments at 11; ACEG Comments at 5-6; Policy Integrity
Comments at 44-46; AEP Comments at 16.
\387\ NARUC Comments at 12, 22-24 (advocating for maximizing
benefit-cost ratio and retaining the benefit-cost ratio permitted by
Order No. 1000); Entergy Comments at 18 (asking the Commission to
retain the ability to have a benefit-cost ratio up to 1.25);
Mississippi Commission Comments at 13-14 (arguing for a strict
benefit-cost ratio of no less than 1.25 for economic projects with
the possibility of a higher benefit-cost ratio for specific
projects); Entergy Reply Comments at 12-13 (asserting that a higher
benefit-cost ratio may be appropriate for a longer-term planning
horizon).
\388\ National Grid Comments at 16; American Municipal Power
Comments at 32; PIOs Comments at 79; Chamber of Commerce Comments at
4; WIRES Comments at 7-8; AEP Comments at 9-10.
---------------------------------------------------------------------------
(b) Proposed Reform
241. We propose to require that public utility transmission
providers, as part of the Long-Term Regional Transmission Planning that
we propose to require in this NOPR, include in their OATTs: (1)
Transparent and not unduly discriminatory criteria, which seek to
maximize benefits to consumers over time without over-building
transmission facilities, to identify and evaluate transmission
facilities for potential selection in the regional transmission plan
for purposes of cost allocation that address transmission needs driven
by changes in the resource mix and demand, consistent with the
discussion below; and (2) a process to coordinate with the relevant
state entities in developing such criteria.
242. Subject to certain minimum requirements, we propose to provide
public utility transmission providers the flexibility to propose the
selection criteria that they, in consultation with their stakeholders,
believe will ensure that more efficient or cost-effective regional
transmission facilities to address the region's transmission needs
driven by changes in the resource mix and demand ultimately are
selected in the regional transmission plan for purposes of cost
allocation. As stated in Order No. 1000, to comply with Order Nos. 890
and 1000 transmission planning principles, the evaluation process must
result in a determination that is sufficiently detailed for
stakeholders to understand why a particular transmission project was
selected or not selected in the regional transmission plan for purposes
of cost allocation to address transmission needs driven by changes in
the resource mix and demand.\389\ Further, we propose that the
evaluation process and, specifically, the selection criteria must seek
to maximize benefits to consumers over time without over-building
transmission facilities.
---------------------------------------------------------------------------
\389\ Order No. 1000, 136 FERC ] 61,051 at P 328.
---------------------------------------------------------------------------
243. We believe that this proposed flexibility would help
accommodate the regional differences described in comments in response
to the ANOPR, such as the different transmission needs each
transmission planning region may have, the factors driving those needs,
or market structures. We also believe that providing flexibility to
public utility transmission providers in this regard would allow public
utility transmission providers, in consultation with their
stakeholders, to determine criteria for assessing the efficiency or
cost-effectiveness of various regional transmission facilities, whether
by reference, for example, to a benefit-cost ratio or by aggregate net
benefits.\390\
---------------------------------------------------------------------------
\390\ We do not propose to change the Order No. 1000 requirement
that public utility transmission providers may not impose a benefit-
cost ratio requirement higher than 1.25. See id. P 646.
---------------------------------------------------------------------------
244. Further, we believe this proposed flexibility would allow
public utility transmission providers in each transmission planning
region to develop selection criteria that could sufficiently balance
individual state interests within each transmission planning region. We
believe that providing an opportunity for state involvement in regional
transmission planning processes is becoming more important as states
take a more active role in shaping the resource mix and demand, which,
in turn, means that those state actions are increasingly affecting the
long-term transmission needs for which we are proposing to require
public utility transmission providers to plan in this NOPR. Given the
important role states play and the wide variety of potential approaches
to selection criteria, we propose, as part of this requirement, that
public utility transmission providers must consult with and seek
support from the relevant state entities, as defined below, within
their
[[Page 26548]]
transmission planning region's footprint to develop the selection
criteria. These selection criteria would be used in Long-Term Regional
Transmission Planning to evaluate a transmission facility (or a
portfolio of regional transmission facilities) for potential selection
in the regional transmission plan for purposes of cost allocation.
245. While we propose significant flexibility in the development of
selection criteria, we believe that certain minimum requirements must
be in place for public utility transmission providers, their
stakeholders, and states. The selection criteria must be transparent
and not unduly discriminatory, and must aim to ensure that more
efficient or cost-effective transmission facilities are selected in the
regional transmission plan for purposes of cost allocation to address
transmission needs driven by changes in the resource mix and demand.
Public utility transmission providers should seek to maximize benefits
to consumers over time without over-building transmission facilities.
Public utility transmission providers should propose specific selection
criteria to achieve this balance over time. We note, as discussed
above, that regional transmission planning and cost allocation
processes generally have resulted in few regionally planned
transmission facilities being selected and ultimately built.\391\
However, the reforms proposed in this NOPR seek to better ensure that
the more efficient or cost-effective regional transmission facilities
are identified through Long-Term Regional Transmission Planning and
acknowledge commenters' concerns about over-building due to
uncertainties of future transmission system conditions.\392\ We
acknowledge the inherent uncertainty involved in predicting future
transmission needs and emphasize that we are not proposing to require
public utility transmission providers to achieve, ex post, any
particular outcome but rather to adopt an evaluation process that, ex
ante, aims to maximize consumer benefits over time without over-
building transmission facilities.
---------------------------------------------------------------------------
\391\ Supra Need For Reform: The Transmission Investment
Landscape Today (explaining in some transmission planning regions,
regional transmission investment declined after issuance of Order
No. 1000, while in other regions, regional transmission planning
processes have not resulted in the selection of a single regional
transmission facility); see also Minnesota Commerce Comments at 3
(arguing the risk of status quo is worse than the risk of over-
building).
\392\ See, e.g., NASUCA Comments at 3-5; November 2021 Technical
Conference Tr. at 29 (testimony of Dr. Patton).
---------------------------------------------------------------------------
246. Public utility transmission providers would bear the burden on
compliance of demonstrating that their proposed selection criteria
satisfy the Order Nos. 890 and 1000 transmission planning principles in
the context of Long-Term Regional Transmission Planning, even if public
utility transmission providers propose to use selection criteria that
they also use in their existing regional transmission planning
process.\393\ Likewise, public utility transmission providers would
bear the burden on compliance of demonstrating that their proposed
selection criteria seek to maximize benefits to consumers over time
without over-building transmission facilities. Moreover, we propose to
require that public utility transmission providers demonstrate on
compliance that they developed their proposed selection criteria in
consultation with the relevant state entities in their transmission
planning region's footprint.
---------------------------------------------------------------------------
\393\ For example, if public utility transmission providers in a
transmission planning region propose to use existing selection
criteria, they should explain on compliance how those criteria also
are just and reasonable with respect to the selection of regional
transmission facilities identified to address transmission needs
driven by changes in the resource mix and demand.
---------------------------------------------------------------------------
247. We propose that, consistent with Order No. 1000, the developer
of a transmission facility selected in the regional transmission plan
for purposes of cost allocation through Long-Term Regional Transmission
Planning to address transmission needs driven by changes in the
resource mix and demand would be eligible to use the applicable cost
allocation method for the Long-Term Regional Transmission
Facility.\394\ We also propose that the existing transmission developer
requirements would apply, including that the developer of the selected
regional transmission facility must submit a development schedule that
indicates the required steps, such as the granting of state approvals
necessary to develop and construct the transmission facility such that
it meets the transmission needs of the transmission planning
region.\395\ To the extent the relevant state entities in a
transmission planning region agree to a State Agreement Process, as
described in the Regional Transmission Cost Allocation section below,
the development schedule should also include relevant steps related to
that process.\396\
---------------------------------------------------------------------------
\394\ We note that the applicable cost allocation method for a
Long-Term Regional Transmission Facility may not be ex ante, as
discussed in the Regional Transmission Cost Allocation section
below.
\395\ Order No. 1000-A, 139 FERC ] 61,132 at P 442. The
Commission also stated that, as part of the ongoing monitoring of
the progress of a transmission facility once it is selected, the
public utility transmission providers in a transmission planning
region must establish a date by which state approvals to construct
must have been achieved that is tied to when construction must begin
to timely meet the need that the facility is selected to address. If
such critical steps have not been achieved by that date, then the
public utility transmission providers in a transmission planning
region may ``remove the transmission facility from the selected
category and proceed with reevaluating the regional transmission
plan to seek an alternative solution.'' Id.
\396\ Infra P 302 (describing cost allocation requirements for
Long-Term Regional Transmission Planning).
---------------------------------------------------------------------------
248. Given the longer-term nature of transmission needs driven by
changes in the resource mix and demand, we note that the required
development schedule may make it unnecessary for the developer of a
transmission facility selected in the regional transmission plan for
purposes of cost allocation to take actions or incur expenses in the
near-term if the transmission facility will not need to be in service
in the near-term. We also note that, with respect to a transmission
facility selected in the regional transmission plan for purposes of
cost allocation to meet transmission needs driven by changes in the
resource mix and demand, public utility transmission providers may make
its selection status subject to the outcomes of subsequent Long-Term
Regional Transmission Planning cycles, such that a previously selected
transmission facility is no longer needed. Public utility transmission
providers should include in their selection criteria how they will
address the selection status of a previously selected transmission
facility based on the outcomes of subsequent Long-Term Regional
Transmission Planning cycles.
249. Consistent with our approach to benefits analysis, we clarify
that public utility transmission providers would have the flexibility
to propose to use a portfolio approach in selecting regional
transmission facilities in the regional transmission plan for purposes
of cost allocation that address transmission needs driven by changes in
the resource mix and demand. Public utility transmission providers that
propose such an approach would have to include in their OATTs
provisions describing whether the selection criteria would apply to one
proposed regional transmission facility or to a portfolio of regional
transmission facilities; and whether the portfolio approach would be
used for Long-Term Regional Transmission Planning universally to
address transmission needs driven by changes in the resource mix and
[[Page 26549]]
demand or would be used only in certain specified instances.
250. We preliminarily find that the development and analysis of
Long-Term Scenarios cannot remedy the deficiencies in the Commission's
existing regional transmission planning requirements without the
inclusion of transparent and not unduly discriminatory selection
criteria that are used to evaluate transmission facilities (or
portfolios of transmission facilities) for potential selection in the
regional transmission plan for purposes of cost allocation. Absent such
criteria, public utility transmission providers' Commission-
jurisdictional rates may be unjust and unreasonable and unduly
discriminatory and preferential.
251. As noted above, we recognize the inherent uncertainty involved
in predicting future transmission needs, including those driven by
changes in the resource mix and demand, and many commenters express
concern that imperfect information may lead to selecting transmission
facilities in the regional transmission plan for purposes of cost
allocation that become stranded assets. However, we believe that there
are selection criteria that public utility transmission providers could
adopt, following consultation with stakeholders and with relevant state
entities in their transmission planning region's footprint, to minimize
these risks while allowing for investment in transmission facilities
that more efficiently or cost-effectively meet transmission needs
driven by changes in the resource mix and demand. For example, under a
least-regrets approach, public utility transmission providers in a
transmission planning region would select a transmission facility (or
portfolio of transmission facilities) in their regional transmission
plan for purposes of cost allocation that is net-beneficial in most or
all Long-Term Scenarios, even if other transmission facilities have
more net benefits or a higher benefit-cost ratio in a single Long-Term
Scenario. Another approach is a weighted-benefits approach, in
accordance with which public utility transmission providers in a
transmission planning region would select a transmission facility (or
portfolio of regional transmission facilities) in their regional
transmission plan for purposes of cost allocation based on its
probability-weighted average benefits, where probabilities have been
assigned to each Long-Term Scenario studied.\397\
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\397\ Brattle-Grid Strategies Oct. 2021 Report at 59-60.
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252. We seek comment on the requirements proposed in this section
of the NOPR. In addition, we seek comment on whether relevant state
entities should have the opportunity to voluntarily fund the cost of,
or a portion of the cost of, a Long-Term Regional Transmission Facility
\398\ to enable such facility to satisfy the public utility
transmission provider's selection criteria (e.g., any benefit-cost
threshold), and if so, whether the Commission's final rule in this
proceeding should include requirements to facilitate such an
opportunity for the relevant state entities.\399\ Commenters on this
issue should also address preferred approaches to implement such a
voluntary funding opportunity for relevant state entities for Long-Term
Regional Transmission Facilities. For example, we seek comment on what
mechanism would be appropriate to document agreement from the relevant
state entities to voluntarily fund (e.g., commit customers within the
state to fund) the cost of, or a portion of the cost of, a Long-term
Regional Transmission Facility to enable such facility to satisfy the
public utility transmission provider's selection criteria; whether a
public utility transmission provider should be required to include a
pro forma agreement for such an opportunity in its OATT for
facilitation purposes; how the Commission and the public utility
transmission providers would be assured that the commitment by the
relevant state entity is sufficiently binding; and whether another
manner for relevant state entities to make and fulfill such a
commitment would be preferable. We also seek comment on what stage in
the regional transmission planning process is the most appropriate
point for such an opportunity for the relevant state entities. We also
seek comment on whether such opportunity for the relevant state
entities to voluntarily fund the cost of, or the portion of the cost
of, a Long-Term Regional Transmission Facility should be limited to
relevant state entities or should be expanded to include
interconnection customers.\400\
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\398\ As noted infra note 507, we propose to define a Long-Term
Regional Transmission Facility as a transmission facility identified
as part of Long-Term Regional Transmission Planning and selected in
the regional transmission plan for purposes of cost allocation to
address transmission needs driven by changes in the resource mix and
demand.
\399\ For Long-Term Regional Transmission Facilities, such an
opportunity for the relevant state entities could enable them to
assign a value to achieving of their particular policy goals while
ensuring that their customers bear the corresponding costs. As the
New Jersey Commission suggests, ``some states ascribe additional
`value' to the achievement of public policy goals, backed by a
willingness to bear the costs associated with those benefits.'' NJ
Commission, Comments, Docket No. AD21-15-000, at 4 (filed Apr. 1,
2022). See also Maryland Energy Admin Comments at 8-9; Maryland
Commission Reply Comments at 2.
\400\ We note that some commenters have suggested that
interconnection customers similarly be afforded an opportunity to
voluntarily contribute funds to a Long-Term Regional Transmission
Facility so as to facilitate its selection. Enel Comments at 12-14;
ACPA and ESA Comments at 75-79.
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c. Implementation of Long-Term Regional Transmission Planning
253. We recognize that the timing of the proposed Long-Term
Regional Transmission Planning requirement has the potential to overlap
with public utility transmission providers' near-term assessment of
transmission needs captured by existing regional transmission planning
processes. We propose that public utility transmission providers must
explain on compliance how the initial timing sequence for Long-Term
Regional Transmission Planning interacts with existing regional
transmission planning efforts. We recognize the possibility that there
may be overlap in the time horizon for the proposed Long-Term Regional
Transmission Planning and existing near-term regional transmission
planning processes and that they will likely inform each other. It is
also possible that, in some cases, transmission facilities selected in
a regional transmission plan for purposes of cost allocation to address
transmission needs driven by changes in the resource mix and demand may
provide near-term reliability or economic benefits and thus potentially
displace regional transmission facilities that are under consideration
as part of existing regional transmission planning processes.
254. We seek comment on the requirement proposed in this section of
the NOPR. In particular, we seek comment on whether there is a need to
coordinate the initial timing sequences between Long-Term Regional
Transmission Planning and the existing near-term regional transmission
planning processes.
255. We also seek comment on whether the Commission should host a
periodic forum for public utility transmission providers, transmission
experts, relevant federal and state agencies, and other stakeholders to
share best practices in implementing Long-Term Regional Transmission
Planning as proposed herein. The Commission could, for example, host a
tri-annual technical conference focused on topics such as choice of
best
[[Page 26550]]
available data, principles for developing plausible scenarios, and
techniques for evaluating benefits of proposed transmission facilities.
We seek comment on the benefits such a forum might provide, and, if
implemented, how such a forum should be structured and the frequency on
which it should be held.
2. Consideration of Dynamic Line Ratings and Advanced Power Flow
Control Devices in Long-Term Regional Transmission Planning
a. ANOPR
256. In the ANOPR, the Commission sought comment on whether the
development of longer-term scenarios for planning purposes should be
pursued and, if so, whether and how Grid-Enhancing Technologies (GETs)
\401\ should be accounted for in determining what transmission is
needed under such scenarios.\402\ The Commission solicited input on how
it could require greater consideration of GETs and asked commenters to
describe any challenges that exist in establishing such a requirement
and how they might be addressed.\403\
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\401\ For purposes of a prior workshop, Commission staff stated
that GETs increase the capacity, efficiency, or reliability of
transmission facilities. Commission staff further stated that these
technologies include but are not limited to: (1) Power flow control
and transmission switching equipment; (2) storage technologies; and
(3) advanced line rating management technologies. Grid-Enhancing
Technologies, Notice of Workshop, Docket No. AD19-19-000 (issued
Sept. 9, 2019).
\402\ ANOPR, 176 FERC ] 61,024 at P 48.
\403\ Id. P 158.
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b. Comments
257. The majority of commenters on the ANOPR support the Commission
requiring public utility transmission providers to consider GETs in the
regional transmission planning process, emphasizing that advanced
technologies can optimize existing transmission corridors and provide
cost-effective solutions for consumers.\404\ NARUC states that an
effective transmission planning process should maximize the use of
existing transmission and build new transmission only where necessary
or economic, asserting that the transmission planning process needs a
clear pathway for consideration of alternative transmission solutions,
including GETs.\405\
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\404\ See, e.g., National Grid Comments at 32; PJM Comments at
59-62; State of Massachusetts Comments at 20; see also Joint Fed.-
State Task Force on Elec. Transmission, Transcript of Nov. 10, 2021
Meeting, Docket No. AD21-15-000, at 97:5-11 (Chair Scripps)
(supporting consideration of GETs in regional transmission
planning).
\405\ NARUC Comments at 9.
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258. Some commenters, such as Duke, EEI, and MISO Transmission
Owners, either oppose the use of GETs in regional transmission
planning, do not see it as a fit for regional transmission planning for
transmission needs driven by changes in the resource mix and in demand,
or urge caution, as they assert that the technologies are not always
substitutes for transmission facilities.\406\ AEP notes that GETs
should be considered as long as they are evaluated on an equal footing,
for example, evaluating technology life span on equal footing.\407\
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\406\ Duke Comments at 13; EEI Comments at 7; MISO TOs Comments
at 46-47.
\407\ AEP Comments at 15.
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259. Market monitors, such as the PJM Market Monitor, emphasize the
value that dynamic line ratings \408\ and other GETs could add in
maximizing existing transmission capacity but express caution about how
they would be implemented and compensated.\409\ Potomac Economics sees
some benefit to GETs in helping transmission owners avoid inefficient
transmission upgrade costs to mitigate congestion but expresses concern
about mandating long-term planning studies that would involve RTOs/ISOs
or transmission providers ``speculating on'' GETs.\410\
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\408\ A dynamic line rating is ``a transmission line rating that
applies to a time period of not greater than one hour and reflects
up-to-date forecasts of inputs such as (but not limited to) ambient
air temperature, wind, solar heating, transmission line tension, or
transmission line sag.'' Managing Transmission Line Ratings, Order
No. 881, 177 FERC ] 61,179, at PP 235, 238 (2021); 18 CFR
35.28(b)(14).
\409\ PJM Market Monitor Comments at 13.
\410\ Potomac Economics Comments at 4.
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260. RTOs/ISOs generally indicate that they currently consider the
use of GETs in the regional transmission planning process. CAISO
supports the use of GETs in the regional transmission planning
process.\411\ MISO indicates that its current regional transmission
planning process allows for the consideration of GETs, but also
indicates that these technologies alone will not be able to address the
changing needs of the transmission system.\412\ PJM states that, as
part of its regional transmission planning process, it evaluates GETs
proposals, to the extent submitted, in a manner not materially
different from its evaluation of other project proposals.\413\ PJM also
notes that it conducts an advanced technology pilot program as a
testing ground for new technologies that require integration into PJM
operations and markets.\414\ Additionally, SPP states that it supports
the use of certain GETs where they can be appropriately used in
regional transmission planning. It contends that it has considered
certain GETs in the regional transmission planning process, but notes
that certain technologies, such as dynamic line ratings or topological
controls, have historically not lent themselves readily to utilization
in the regional transmission planning process.\415\
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\411\ CAISO Comments at 113-114.
\412\ MISO Comments at 45-46.
\413\ PJM Comments at 59-60.
\414\ Id. at 60.
\415\ SPP Comments at 12.
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261. RTOs/ISOs, notably MISO and PJM, also discuss the importance
of ensuring that public utility transmission providers understand any
GETs that may be deployed on the system and their limitations, as well
as understanding the challenges of integrating GETs into existing
systems; for example, whether there is a need to change telemetry,
modeling, other operating tools, and protocols, all of which
necessitate careful consideration.\416\ PJM notes the value of its
ongoing Advanced Technology Pilot Program in addressing implementation
challenges and identifying system risks associated with GETs.
Expressing concerns about the deployment of GETs by nonincumbent
transmission developers, PJM recommends that the Commission request
that the industry, via NERC and/or U.S. DOE, develop a technology
application guide addressing where, when, and how to apply GETs.\417\
MISO states that it is important not to overstate the capabilities of
GETs in the regional transmission planning process, as these
technologies generally cannot substitute for long-term investment in
transmission facilities that are needed to address the evolving
resource mix, and notes the inherent uncertainty in forecasting power
flows and congestion longer into the future.\418\
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\416\ MISO Comments at 28; PJM Comments at 62-63.
\417\ PJM Comments at 60-63.
\418\ MISO Comments at 45-46.
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262. A few commenters set forth criteria that public utility
transmission providers should be required to consider in the regional
transmission planning process to promote the use of GETs. These
include: Optimizing the utilization of existing and new transmission
facilities; \419\ requiring energy efficiency as a design criterion for
every transmission capital project; \420\ and requiring public utility
transmission providers to show where they have incorporated GETs in
their
[[Page 26551]]
regional transmission planning process where they are cost-
effective.\421\
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\419\ Certain TDUs Comments at 22.
\420\ CTC Global Comments at 6.
\421\ PIOs Comments at 97.
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263. Other commenters offer specific suggestions on how GETs could
be implemented. TAPS urges the Commission to ``[m]ake more explicit the
mandate to consider GETs as part of regional planning processes,''
arguing that Order No. 1000's requirement to consider non-transmission
alternatives ``appears insufficient to ensure robust consideration of
GETs in the planning process.'' \422\ In addition, TAPS recommends that
the Commission expand the MISO/PJM Targeted Market Efficiency Process
to the regional transmission planning process to promote the use of
GETs for quick fixes identified in the regional transmission planning
process.\423\
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\422\ TAPS Comments at 2.
\423\ Id. at 22.
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264. PJM suggests that the Commission require RTOs/ISOs and non-
RTO/ISO transmission planning regions to ``develop a robust process to
account for the potential for [GETs] to be integrated into the planning
processes as part of both near-term and long-range expansion options
before requiring that new greenfield transmission be built.'' \424\
Along similar lines, WATT Coalition suggests that for proposed
transmission projects with an initial cost estimate above $10 million,
the Commission should require the transmission planning region to show
documentation of its evaluation of alternative solutions utilizing
GETs.\425\
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\424\ PJM Comments at 63.
\425\ WATT Coalition Comments at 4.
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265. EDF offers a specific application for GETs implementation,
suggesting that the Commission encourage and even require that GETs be
proposed to address outages that have a material impact on market
efficiency, reliability, and resiliency. EDF notes that transmission
system upgrades are often associated with multi-month outages, which
can have a severe impact on market efficiency and suggests that GETs be
proposed in combination with traditional upgrades or to minimize the
impact of outages that can result from the construction of transmission
upgrades.\426\ WATT Coalition builds on this notion, suggesting that
the Commission require transmission owners and planning authorities to
propose solutions, including GETs, that minimize the impacts of long
duration outages.\427\
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\426\ EDF Comments at 16-18.
\427\ WATT Coalition Comments at 5.
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266. WATT Coalition encourages the Commission to require the
periodic publication of a report on grid utilization to show
transmission usage data in order to provide system planners with a
``more holistic profile of their system capacity, establishing a new
dataset for targeted GETs deployment and associated consumer savings.''
\428\ Arizona Commission adds that an independent transmission monitor
could use information collected to provide feedback on how public
utility transmission providers consider GETs.\429\
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\428\ Id.
\429\ Arizona Commission Reply Comments at 12.
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c. Need for Reform
267. Since Order No. 1000, commercially available technologies to
make transmission systems operate more efficiently or cost-effectively
have greatly advanced. This influx of new and improved technologies has
the potential to improve the operation of new and existing transmission
facilities and defer new transmission investments. As such, the
consideration of new technological innovations in regional transmission
planning processes could help to ensure that these processes are
identifying more efficient or cost-effective regional transmission
facilities and in turn, that Commission-jurisdictional rates are just
and reasonable.
268. When the Commission issued Order No. 1000, integrating these
new technologies was not a major focus of the rule, partly because many
new technologies were either still in development or not yet widely in
use. After more than a decade, the technologies available today may
help to ensure that the transmission system operates more efficiently
or cost-effectively. However, Order No. 1000-compliant regional
transmission planning processes do not appear to have kept time with
technology advancements and potentially need to be updated to ensure
that they are appropriately considering these new technologies.
269. Recently, in Order No. 881, which required more accurate
transmission line ratings in near-term transmission service through the
use of ambient-adjusted transmission line ratings,\430\ the Commission
highlighted the benefits of dynamic line ratings, including permitting
greater power flows than would otherwise be allowed, aiding in the
detection of situations where power flows should be reduced to maintain
safe and reliable operations, and avoiding unnecessary wear on
transmission equipment.\431\ Other benefits of dynamic line ratings
that the Commission emphasized in Order No. 881 include strategic
deployments and targeted applications in which dynamic line ratings can
provide net benefits to customers by increasing the accuracy and power
carrying capabilities of a line.\432\ While the Commission declined to
mandate dynamic line ratings in Order No. 881, it required RTOs/ISOs to
establish and maintain systems and procedures necessary to allow
transmission owners to electronically update transmission line ratings
for ambient-adjusted ratings, which could facilitate the use of dynamic
line ratings.\433\ In addition, the Commission issued a Notice of
Inquiry to continue to explore the implementation of dynamic line
ratings.\434\ This Notice of Inquiry sought comment on: Whether and how
the required use of dynamic line ratings is needed to ensure just and
reasonable Commission-jurisdictional rates; potential criteria for
dynamic line ratings requirements; the benefits, costs, and challenges
of implementing dynamic line ratings; the nature of potential dynamic
line ratings requirements; and potential timeframes for implementing
dynamic line ratings requirements.\435\
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\430\ Order No. 881, 177 FERC ] 61,179 at P 34.
\431\ Id. P 253.
\432\ Id.
\433\ Id. P 255.
\434\ Implementation of Dynamic Line Ratings, 178 FERC ] 61,110
(2022).
\435\ Id. P 1.
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270. At a recent workshop held by Commission staff,\436\
participants highlighted the benefits of advanced power flow control
devices,\437\ such as their ability to modify a transmission line's
electrical characteristics to increase or decrease power flowing
through the line without increasing the capacity of the line.
Participants also highlighted that optimal transmission switching acts
to completely open or close off routes to power flow. Finally,
participants noted that advanced power
[[Page 26552]]
flow control devices, including optimal transmission switching, provide
the tools to effectively control and route power to lines that have
more capacity than those that do not, which can reduce congestion,
reduce costs to consumers, and increase reliability of the transmission
system.
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\436\ Grid-Enhancing Technologies, Notice of Workshop, Docket
No. AD19-19-000 (issued Sept. 9, 2019).
\437\ Advanced power flow control devices serve a transmission
function. These devices can help the system operator control power
flows over a given path and can include phase shifting transformers
(also known as phase angle regulators) and devices or systems
necessary for implementing optimal transmission switching. Advanced
power flow control devices allow power to be pushed and pulled to
alternate lines with spare capacity leading to maximum utilization
of existing transmission capacity. See T. Bruce Tsuchida et al., The
Brattle Group, Unlocking the Queue with Grid-Enhancing Technologies,
at 19-20 (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.
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271. To address the issues described above, we propose reforms to
require public utility transmission providers to more fully consider
two specific technologies--dynamic line ratings and advanced power flow
control devices--in regional transmission planning processes.
d. Proposed Reform
272. In order to help ensure that regional transmission planning
processes identify more efficient or cost-effective transmission
facilities for selection in the regional transmission plan for purposes
of cost allocation, we propose to require that public utility
transmission providers in each transmission planning region more fully
consider in regional transmission planning and cost allocation
processes two specific technologies: The incorporation into
transmission facilities of dynamic line ratings and advanced power flow
control devices. We believe that selecting transmission facilities that
incorporate dynamic line ratings or advanced power flow control devices
in the regional transmission plan for purposes of cost allocation may
offer a more efficient or cost-effective alternative to other regional
transmission facilities in certain instances.
273. Specifically, we believe it is possible that selecting
transmission facilities that incorporate such technologies serving a
transmission function in the regional transmission plan for purposes of
cost allocation could be more efficient or cost-effective than a
proposed regional transmission facility that does not use such
technologies. For example, selecting in the regional transmission plan
for purposes of cost allocation a transmission facility that is
designed with the equipment necessary to support dynamic line ratings
may provide greater benefits through reduced production costs than a
similar transmission facility that does not include such equipment.
Likewise, selecting in the regional transmission plan for purposes of
cost allocation a transmission facility that incorporates an advanced
power flow control device may provide greater production costs benefits
under transmission outage scenarios than another transmission facility.
274. To facilitate greater use of these technologies where
warranted, we propose to require that public utility transmission
providers in each transmission planning region consider for each
identified regional transmission need whether selecting transmission
facilities in the regional transmission plan for purposes of cost
allocation that incorporate dynamic line ratings or advanced power flow
control devices would be more efficient or cost-effective than
transmission facilities that do not incorporate these technologies.
Specifically, such consideration should include first, whether
incorporating dynamic line ratings or advanced power flow control
devices into existing transmission facilities could meet the same
regional transmission need more efficiently or cost-effectively than
other potential transmission facilities. Second, when evaluating
transmission facilities for potential selection in the regional
transmission plan for purposes of cost allocation, the public utility
transmission providers in the transmission planning region must also
consider whether incorporating dynamic line ratings and advanced power
flow control devices as part of any potential regional transmission
facility would be more efficient or cost-effective. We propose that
this requirement apply in all aspects of the regional transmission
planning processes, including the existing regional transmission
planning processes for near-term regional transmission needs and Long-
Term Regional Transmission Planning, as proposed in this NOPR. As is
the case for any other transmission facility selected in the regional
transmission plan for purposes of cost allocation, we propose that the
costs to incorporate dynamic line ratings or advanced power flow
control devices that are selected in the regional transmission plan for
purposes of cost allocation--whether as an addition to an existing
transmission facility or as part of a new regional transmission
facility--will be allocated using the applicable regional cost
allocation method.
275. As required by Order No. 1000, the evaluation process must
culminate in a determination that is sufficiently detailed for
stakeholders to understand why a particular transmission facility was
selected or not selected in the regional transmission plan for purposes
of cost allocation.\438\ This process must now include the
consideration of dynamic line ratings and advanced power flow control
devices and why they were not incorporated into selected regional
transmission facilities.
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\438\ Order No. 1000, 136 FERC ] 61,051 at P 328; Order No.
1000-A, 139 FERC ] 61,132 at P 267.
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276. As discussed above, the ANOPR requested comment on GETs as a
larger category of transmission technologies. While we recognize that
there are likely other novel technologies that public utility
transmission providers could consider as they develop their regional
transmission plans, we are not proposing to mandate their consideration
at this time. We believe that there is enough operational experience
with dynamic line ratings and power flow control devices such that
public utility transmission providers should be able to adequately
consider their operations in the regional transmission planning
process. In addition, the nature of dynamic line ratings and advanced
power flow control devices allows for consideration in regional
transmission planning and cost allocation processes in a way that may
not be possible for other technologies.\439\
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\439\ For example, while transmission topology optimization can
serve a useful function in optimizing system flows and deferring
transmission investment in the short-term, system conditions over 5
to 20 years in the future may be too uncertain to rely on system
reconfiguration to address identified transmission needs.
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277. We seek comment on the requirements proposed in this section
of the NOPR. We also seek comment on whether there are other
transmission technologies serving a transmission function that should
be considered in regional transmission planning and cost allocation
processes. Finally, we seek comment on whether non-RTO/ISO transmission
planning regions should be required to update their energy management
systems or make other similar changes if dynamic line ratings are
identified as a more efficient or cost-effective transmission facility
selected in the regional transmission plan for purposes of cost
allocation.\440\
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\440\ Cf. 18 CFR 35.25(g)(13)(i) (requiring each RTO/ISO to
maintain systems and procedures to accept and utilize dynamic line
ratings data).
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V. Regional Transmission Cost Allocation
278. We preliminarily find that reforms to public utility
transmission providers' regional cost allocation methods are necessary
to ensure that Commission-jurisdictional rates are just and reasonable
and not unduly discriminatory or preferential. As discussed below, we
propose to require that public utility transmission providers in each
transmission planning region seek the agreement of relevant state
entities within the transmission planning region regarding the cost
allocation method or methods that will
[[Page 26553]]
apply to transmission facilities selected in the regional transmission
plan for purposes of cost allocation through Long-Term Regional
Transmission Planning and revise their OATTs to include the method or
methods.\441\
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\441\ We are not proposing to require any changes to existing
interregional cost allocation methods for interregional transmission
facilities that are selected in the regional transmission plan for
purposes of cost allocation and that the Commission previously
accepted as compliant with Order No. 1000.
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279. We also propose a reform to facilitate an additional
opportunity for involvement of state regulators in decisions about how
the costs of transmission facilities selected in a regional
transmission plan for purposes of cost allocation through Long-Term
Regional Transmission Planning will be allocated. Specifically, this
reform would require public utility transmission providers in each
transmission planning region to add a time period for states to
negotiate an alternate cost allocation method for a transmission
facility selected in the regional transmission plan for purposes of
cost allocation through Long-Term Regional Transmission Planning.
A. Background
280. In Order No. 890, the Commission noted that for a transmission
planning process to comply with the final rule, it must address the
allocation of costs of new transmission facilities. The Commission
required public utility transmission providers and their stakeholders
to develop a new cost allocation method, if needed, for any new
transmission facilities that did not fall under public utility
transmission providers' existing cost allocation methods.\442\ The
Commission stated that such methods should consider: (1) Whether a
proposed cost allocation method fairly assigns costs among
participants, including those that cause them to be incurred and those
that otherwise benefit from them; (2) whether a proposed cost
allocation method provides adequate incentives to construct new
transmission; and (3) whether a proposed cost allocation method is
generally supported by the region's state authorities and
participants.\443\
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\442\ Order No. 890, 118 FERC ] 61,119 at PP 557-558.
\443\ Id. P 559.
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281. In Order No. 1000, the Commission determined that, while
existing cost allocation methods may have sufficed in the past,
changing circumstances in the industry led to the need for changes to
cost allocation requirements.\444\ The Commission observed that, as
transmission needs increased, the challenges in allocating the cost of
transmission appeared to grow more acute.\445\ The Commission further
found that, in ``the absence of clear cost allocation rules for
regional transmission facilities, there is a greater potential that
public utility transmission providers and nonincumbent transmission
developers may be unable to develop transmission facilities that are
determined by the region to meet their needs.'' \446\ As a result, the
Commission required each public utility transmission provider to have
in place a method, or set of methods, for allocating the costs of new
transmission facilities selected in the regional transmission plan for
purposes of cost allocation and established a set of six cost
allocation principles that public utility transmission providers'
regional cost allocation methods must satisfy.\447\ The Commission
determined that this principles-based approach requires the allocation
of the costs of new transmission facilities in a manner that is at
least roughly commensurate with the benefits received by those that pay
those costs while allowing for regional flexibility.\448\
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\444\ Order No. 1000, 136 FERC ] 61,051 at P 497.
\445\ Id. P 498.
\446\ Id. P 558.
\447\ Id.
\448\ Id. P 10; Order No. 1000-A, 139 FERC ] 61,132 at P 647.
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282. The six regional transmission cost allocation principles
adopted in Order No. 1000 are: (1) The costs of transmission facilities
selected in a regional transmission plan for purposes of cost
allocation must be allocated to those within the transmission planning
region that benefit from those facilities in a manner that is at least
roughly commensurate with estimated benefits; (2) those that receive no
benefit from transmission facilities, either at present or in a likely
future scenario, must not be involuntarily allocated any of the costs
of those transmission facilities; (3) a benefit to cost threshold
ratio, if adopted, cannot exceed 1.25 to 1; (4) costs must be allocated
solely within the transmission planning region unless another entity
outside the region voluntarily assumes a portion of those costs; (5)
the method for determining benefits and identifying beneficiaries must
be transparent; and (6) there may be different regional cost allocation
methods for different types of transmission facilities, such as those
needed for reliability, congestion relief, or to achieve Public Policy
Requirements.\449\ The Commission declined to require that public
utility transmission providers adopt a universal or comprehensive
definition of ``benefits'' and ``beneficiaries'' of regional
transmission facilities, instead permitting regional flexibility and
examining each transmission planning region's definitions on
compliance.\450\
---------------------------------------------------------------------------
\449\ Order No. 1000, 136 FERC ] 61,051 at PP 622, 637, 646,
657, 668, 685.
\450\ Id. P 624.
---------------------------------------------------------------------------
283. While the Commission determined that generator interconnection
was outside the scope of Order No. 1000, it also stated that public
utility transmission providers could propose a regional transmission
cost allocation method that allocates costs directly to generators as
beneficiaries, but any effort to do so must be consistent with the
Order No. 2003 generator interconnection process.\451\ No public
utility transmission providers have proposed a regional cost allocation
method that allocates costs directly to generators, instead allocating
all costs of transmission facilities selected in a regional
transmission plan for purposes of cost allocation to transmission
customers.
---------------------------------------------------------------------------
\451\ Order No. 1000-A, 139 FERC ] 61,132 at P 680.
---------------------------------------------------------------------------
284. On compliance, public utility transmission providers in each
transmission planning region adopted varying regional transmission cost
allocation methods to comply with the cost allocation principles of
Order No. 1000. The majority of these methods allocate the costs of
transmission facilities selected in a regional transmission plan for
purposes of cost allocation that address reliability needs separately
from those that address economic needs, and separately from those that
address transmission needs driven by Public Policy Requirements.
285. Some public utility transmission providers' Order No. 1000-
compliant regional transmission cost allocation methods identify
benefits across a portfolio of transmission facilities rather than on a
facility-by-facility basis. An example of a transmission planning
region accounting for broader benefits is MISO, which accounts for the
following benefits in their MVP portfolio:\452\
---------------------------------------------------------------------------
\452\ MISO, Multi-Value Project Portfolio, Detailed Business
Case, https://cdn.misoenergy.org/2011%20MVP%20Portfolio%20Detailed%20Business%20Case117056.pdf. More
general benefits requirements for MVP Projects are described at
MISO, FERC Electric Tariff, Attachment FF, Section II.C.2, .5.
---------------------------------------------------------------------------
Economic: increased market efficiency (congestion and fuel
savings and operating reserves), deferred generation investment (system
planning
[[Page 26554]]
reserve margins and transmission line losses), and other capital
benefits (wind turbine investment and future transmission investment);
\453\
---------------------------------------------------------------------------
\453\ MISO, Multi-Value Project Portfolio, Detailed Business
Case at 27.
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Reliability: transmission line overloads and system
voltage constraints mitigated, transient stability benefits, mitigation
of fault conditions that could cause system instability, voltage
stability, increased transfer capacity, increased transfer capability;
\454\
---------------------------------------------------------------------------
\454\ Id. at 17-19.
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Policy: reliably enables the delivery of energy in support
of policy mandates.\455\
---------------------------------------------------------------------------
\455\ Id. at 21.
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B. ANOPR
286. In the ANOPR, the Commission recognized that reforms to
regional transmission planning cannot be successful without ensuring
that transmission providers and customers alike are able to identify
the types of benefits these transmission facilities can provide and
also identify the beneficiaries that would receive those benefits,
along with the relative proportion of benefits that accrue to each of
those beneficiaries.\456\ Acknowledging that cost allocation methods
can be ``difficult and controversial,'' particularly for regional
transmission facilities that may be both more costly and have
potentially broad benefits, the Commission sought comment on whether
there should be reforms to cost allocation in regional transmission
planning and cost allocation processes.\457\
---------------------------------------------------------------------------
\456\ ANOPR, 176 FERC ] 61,024 at P 84.
\457\ Id. PP 83-89.
---------------------------------------------------------------------------
287. Additionally, the Commission noted that one way to add
oversight to the regional transmission planning and cost allocation
processes could be to involve state commissions in those
processes.\458\ For example, the Commission pointed to SPP's Regional
State Committee (RSC), which provides collective state regulatory
agency input in areas under the RSC's primary responsibilities and on
matters of regional importance related to the development and operation
of the bulk electric transmission system. Pursuant to the SPP Bylaws,
``with respect to transmission planning, the RSC will determine whether
transmission upgrades for remote resources will be included in the
regional transmission planning process and the role of transmission
owners in proposing transmission upgrades in the regional planning
process.'' \459\ The Commission sought comment on whether this type of
model, or other models that may be proposed, could be expanded to other
regions and other topics; for example, whether a state-led committee
could, inter alia, provide insight into regional transmission facility
costs and cost allocation methods.\460\
---------------------------------------------------------------------------
\458\ ANOPR, 176 FERC ] 61,024 atId. P 176.
\459\ ANOPR, 176 FERC ] 61,024 at P 176Id. (citing SPP,
Governing Documents Tariff, Bylaws, Section 7.2 (Regional State
Committee) (1.0.0)).
\460\ ANOPR, 176 FERC ] 61,024 atId. P 177.
---------------------------------------------------------------------------
C. Comments
288. In response to the ANOPR, the Commission received comments
from a broad range of stakeholders, generally recognizing the
importance of cost allocation to successful development of more
efficient or cost-effective regional transmission facilities and
advocating different ways to reduce the likelihood that controversy
regarding who pays for regional transmission facilities obstructs their
development and to ensure the costs of regional transmission facilities
are allocated roughly commensurate with benefits.
289. In their comments, many state regulators and groups advocate
for increased state involvement in cost allocation decisions.\461\
NARUC explains that most states think that more should be done to
encourage and incent states with similar public policy profiles to use
the State Agreement Approach, which it says has the benefit of being a
stakeholder-driven product that enjoys significant state support.\462\
NARUC further asserts that planners could provide a platform for states
with similar policy objectives to better coordinate and agree upon cost
allocation, while urging that regions should ``retain the flexibility
to develop innovative approaches to allocating the costs.'' \463\
NESCOE asserts that states need to occupy a central role in cost
allocation, consistent with applicable state requirements.\464\ NESCOE
calls for state decision making in the evaluation and selection of
projects providing public policy benefits and for a robust role in the
regional transmission planning processes.\465\ Some commenters note
that they are already pursuing cost allocation reforms with
transmission planning regions.\466\ Arizona Commission contends that,
because state commissions are already tasked with ensuring retail rates
are just and reasonable for their ratepayers, increased state
commission involvement in cost allocation processes would better allow
state commissions to establish just and reasonable retail rates.\467\
New Jersey Commission states that to enable cost allocation reforms the
Commission could mandate public utility transmission providers
institute a process for states to submit portions of their public
policies for consideration into PJM's RTEP.\468\ Mississippi Commission
notes that where one or more states have common economic development,
environmental, or other goals, and require transmission investment to
achieve those goals, the cost of such projects could be allocated to
those states in an agreed upon amount.\469\ Northwest and Intermountain
notes that a strong state role is particularly important in non-RTO/ISO
regions.\470\ ACPA and ESA state that a Commission approach to cost
allocation could include cost contributions from states and
interconnection customers.\471\
---------------------------------------------------------------------------
\461\ Members of the Task Force similarly advocated for state
regulatory involvement in cost allocation processes, emphasizing
that states are not merely stakeholders. See, e.g., Joint Fed.-State
Task Force on Elec. Transmission, Transcript of Feb. 16, 2022
Meeting, Docket No. AD21-15-000, at 107:1-6 (Chair French), 108:17-
18 (Comm'r Duffley), 109:2 (Chair Nelson), 110:4-5, 15-16 (Chair
Stanek), 112:3-5 (Comm'r Rechtschaffen).
\462\ NARUC Comments at 25; see also Ohio Commission Comments at
15 (noting the PJM State Agreement Approach and related ``hard work
and progress that has already been made in incorporating state
policy goals into transmission planning in the PJM region.'');'');
Pennsylvania Commission Comments at 6 (similarly calling for respect
of the State Agreement Approach).
\463\ NARUC Comments at 25-26.
\464\ NESCOE Comments at 21-25.
\465\ Id. at 49.
\466\ NESCOE CommentsId. at 47-48; MISO Comments at 8, 21.
\467\ Arizona Commission Comments at 7; see also SPP RSC
Comments at 10 (urging the Commission to seek approaches that
enhance state authority rather than diminishing or diluting it).
\468\ New Jersey Commission Comments at 12-15.
\469\ Mississippi Commission Comments at 14.
\470\ Northwest and Intermountain Comments at 28-30.
\471\ ACPA and ESA Comments at 75.
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290. But while there is broad agreement on the importance of
states' role in cost allocation, a number of states indicate that it is
difficult for them to participate in a timely manner in the regional
transmission planning and cost allocation processes to address concerns
regarding cost allocation.\472\ District of Columbia's Office of the
People's Counsel calls for the Commission to facilitate ``the
participation of any group that may be subject to cost allocation in
early planning stages to determine which outcome best serves the needs
of all the customers in that region.'' \473\ Other state commissions
also call for greater involvement in cost allocation
[[Page 26555]]
decisions.\474\ Maryland Energy Admin asserts that earlier state
involvement in cost allocation for the Artificial Island transmission
facility, for example, could have ``avoided significant delays and
additional costs, including some that were ultimately assigned to
ratepayers.'' \475\ Other commenters note that failure to gain state
support for selection and cost allocation for transmission facilities
can result in states subsequently blocking or delaying transmission
facilities selected in regional transmission planning and cost
allocation processes through subsequent state siting proceedings.\476\
---------------------------------------------------------------------------
\472\ District of Columbia's Office of the People's Counsel
Comments at 4-5.
\473\ Id. at 5.
\474\ Arizona Commission Comments at 7; Maryland Energy
AdministrationAdmin Comments at 2.
\475\ Maryland Energy AdministrationAdmin Comments at 3.
\476\ Exelon Comments at 31-32.
---------------------------------------------------------------------------
291. Many commenters support consideration of a wider set of
benefits than those currently used to evaluate transmission facilities
in the regional transmission plan for purposes of cost allocation.\477\
PIOs advocate that the Commission conduct a survey of all potential
benefits that can result from multi-value, scenario-based planning and
require that public utility transmission providers consider those
benefits for regional cost allocation as well as for regional
transmission planning.\478\ U.S. DOE states that the Commission should
establish a minimum set of potential benefits (and costs) to be
considered, to ensure that they are taken into account in both project
selection and in the allocation of costs for selected projects, adding
this practice would help ensure that benefits not currently fully
valued will be more appropriately incorporated in the planning process
and foster consistency among planning regions.\479\ Certain TDUs
express that cost allocation reforms must be equitable for
consumers.\480\
---------------------------------------------------------------------------
\477\ ACORE Comments at ii; AEE Comments at 31-32; ACEG Comments
at 6-8; ACPA and ESA Comments at 75; AEP Comments at 14; Amazon
Comments at 4; Anbaric Comments at 29; Avangrid Comments at 9;
Business Council for Sustainable Energy Comments at 2; Citizens
Energy Comments at 6-7; City of New York Comments at 3-4; Union of
Concerned Scientists Comments at 66-75; Consumers Council Comments
at 4, 16; Duke Comments at 12; EDF Comments at 8-10; EEI Comments at
33; ITC Comments at 28-34; Massachusetts Attorney General Comments
at 24-25; New Jersey Commission Comments at 13-14, 17-19; NextEra
Comments at 83-88; Northwest and Intermountain Comments at 35-38;
Orsted Comments at 6-7; PIOs Comments at 30, 60; Policy Integrity
Comments at 43; PSEG Comments at 25-27; REBA Comments at 17; RMI
Comments at 4; SEIA Comments at 9; Shell Comments at 18-20; State
Agencies Comments at 21-22; State of Massachusetts Comments at 16-
17; U.S. DOE Comments at 7-9, 23-24; WIRES Comments at 18.
\478\ PIOs Comments at 30; see also Orsted Comments at 6.
\479\ U.S. DOE Comments at 23.
\480\ Certain TDUs Comments at 5-6.
---------------------------------------------------------------------------
292. Some RTOs/ISOs support the Commission requiring public utility
transmission providers to consider a broader set of transmission
benefits. For example, NYISO states that requiring public utility
transmission providers to adopt a broader range of evaluation and
selection criteria in their transmission planning processes would
enable them to consider the reliability, economic, and public policy
benefits of proposed solutions to a transmission need regardless of the
underlying driver of the need, which would enhance their ability to
select the more efficient or cost-effective transmission solution.\481\
SPP states that the Commission should adopt a minimum, standardized set
of benefit metrics for all public utility transmission providers to
ensure that transmission is valued consistently between regions and to
allow for an apples-to-apples comparison of potential projects.\482\
CAISO and MISO state that the Commission could consider requiring
public utility transmission providers to consider the resilience
benefits of transmission.\483\ If the Commission expands the set of
benefits that public utility transmission providers must consider, PJM
urges the Commission to provide clear decision criteria on whether and
when it is appropriate for public utility transmission planners to
order construction of new transmission for anticipated future
generation not yet in the interconnection queue.\484\ If the Commission
requires the consideration of a broader set of transmission benefits,
several RTOs/ISOs urge the Commission to provide for regional
flexibility.\485\
---------------------------------------------------------------------------
\481\ NYISO Reply Comments at 10-11.
\482\ SPP Comments at 14.
\483\ CAISO Comments at 85-88; MISO Comments at 85.
\484\ PJM Comments at 8.
\485\ CAISO Comments at 85; MISO Comments at 85; NYISO Comments
at 35-36.
---------------------------------------------------------------------------
293. Minnesota Commerce acknowledges that cost allocation is a
central factor in determining whether to build needed regional
transmission.\486\ Many commenters state that existing regional
transmission cost allocation methods are sound and/or should
continue.\487\ At least one commenter suggests that ultimate cost
allocation reforms should not unintentionally disrupt settled
methods.\488\
---------------------------------------------------------------------------
\486\ Minnesota Commerce Comments at 6-7 (noting cost allocation
is one of the more difficult barriers to new transmission
development); see also November 2021 Technical Conference Tr. at 79.
\487\ See, e.g., NASUCA Comments at 6; North Carolina Commission
Comments at 23; Ohio Commission Comments at 12-13; SERTP Comments at
4, 21-23; SoCal Edison Comments at 6.
\488\ See NESCOE Comments at 50.
---------------------------------------------------------------------------
294. Some commenters suggest special cost allocation methods for
transmission facilities resulting from scenario-based planning. Exelon
asserts that the default cost allocation method for transmission
projects resulting from scenario-based planning should reflect a load-
ratio share method,\489\ but that the Commission should allow suitable
substitute cost allocations as agreed to by the participating states to
reflect the particular aggregation of benefits provided by the
portfolio.\490\ On the other hand, Michigan Commission notes that
postage stamp cost allocation is highly divisive.\491\
---------------------------------------------------------------------------
\489\ Under the load-ratio share regional cost allocation
method, the costs of new transmission facilities are allocated based
on some measure of system usage, whether at peak or overall.
Specifically, load-ratio share cost allocation methods include both
demand charge approaches and volumetric (energy) approaches. Under
the demand charge approach, costs are allocated in proportion to
each transmission customer's contribution to the system peak load
(which can be coincident or non-coincident peak). In contrast, under
the volumetric approach, costs are allocated based on each
transmission customer's share of total system usage. See CAISO,
Review Transmission Access Charge Structure Issue Paper, at 18, tbl.
2: Summary of ISO/RTO approaches to transmission charges (June 30,
2017).
\490\ Exelon Comments at 30-31.
\491\ Michigan Commission Comments at 20.
---------------------------------------------------------------------------
295. Some commenters state that further analysis is necessary to
determine if prescriptive action by the Commission is necessary and
whether alteration of Order No. 1000's six regional transmission cost
allocation principles is warranted.\492\ AEP urges that benefits and
methodologies to measure those benefits should be consistent throughout
regions.\493\
---------------------------------------------------------------------------
\492\ See, e.g., EEI Comments at 32-33; NARUC Comments at 22;
see also Joint Fed.-State Task Force on Elec. Transmission,
Transcript of Feb. 16, 2022 Meeting, Docket No. AD21-15-000, at
36:12-13 (Chair Brown Dutrieuille) (reiterating NARUC's comments
that the Order No. 1000 cost allocation principles should remain in
place).
\493\ AEP Comments at 15.
---------------------------------------------------------------------------
296. Some commenters propose cost allocation pursuant to benefits
related to anticipated future generation, resilience, and/or climate
and environmental benefits.\494\ APPA states that, to the extent that
regions shift their transmission planning processes to place a greater
emphasis on anticipated future generation or otherwise modify existing
planning protocols towards a more holistic analysis, it may be
appropriate to consider conforming changes to cost allocation
methods.\495\
---------------------------------------------------------------------------
\494\ See, e.g., ACEG Comments at 6-7; Consumers Council
Comments at 16-17; WIRES Comments at 18-19; PSEG Comments at 5.
\495\ APPA Comments at 15-16.
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[[Page 26556]]
D. Need for Reform
297. The Commission has previously recognized that knowing how the
costs of transmission facilities would be allocated is critical to the
development of new transmission infrastructure.\496\ Without such
clarity, the likelihood that transmission facilities selected in a
regional transmission plan for purposes of cost allocation will be
developed is diminished, undermining the entire purpose of the regional
transmission planning process, namely, the development of more
efficient or cost-effective transmission facilities.\497\ Yet,
identifying a cost allocation method that is perceived as fair,
especially within transmission planning regions that encompass several
states, remains challenging. Litigation contesting regional
transmission cost allocation methods persists.\498\ Moreover, even
where the cost allocation method is reasonably settled, regional
transmission facilities face significant uncertainty and risk of not
reaching construction if certain stakeholders--in particular, a state
regulator responsible for permitting transmission facilities--do not
perceive the regional transmission facilities' value as commensurate
with their costs.\499\
---------------------------------------------------------------------------
\496\ Order No. 1000, 136 FERC ] 61,051 at P 496 (discussing
findings in Order No. 890).
\497\ Id.
\498\ See, e.g., Long Island Power Auth. v. FERC, 27 F.4th 705,
709 (D.C. Cir. 2022) (addressing a ``long-running dispute'' over
regional transmission cost allocation in PJM); Pub. Serv. Elec. &
Gas Co. v. FERC, 989 F.3d 10 (D.C. Cir. 2021) (addressing dispute
over cost allocation for particular transmission upgrades).
\499\ See, e.g., Transource Pa., LLC v. Dutrieuille, Case No.
1:2021cv0110 (filed June 22, 2021, M.D. Pa.) (lawsuit challenging
state commission's denial of an application for siting and
construction of regional transmission facilities).
---------------------------------------------------------------------------
298. We are concerned that these challenges are likely to be
exacerbated in the context of Long-Term Regional Transmission Planning
and Cost Allocation. We recognize that, by requiring a longer-term
planning horizon, consideration of multiple scenarios, and accounting
for the longer-term factors that affect transmission needs, Long-Term
Regional Transmission Planning entails a more complex set of
considerations as compared to existing regional transmission planning
requirements. We are concerned that this increased complexity could
make cost allocation decisions more contentious, which may risk
undermining the development of more efficient or cost-effective
regional transmission facilities to address transmission needs driven
by changes in the resource mix and demand. For example, we anticipate
that stakeholders, including state regulators, may diverge in their
views of which scenarios best reflect future transmission needs, and
these conflicting perceptions may lead to disagreements regarding who
should pay for selected transmission facilities.
299. For these reasons, we preliminarily find that the cost
allocation requirements for transmission facilities identified and
selected in the regional transmission plan through Long-Term Regional
Transmission Planning proposed in this proceeding may differ in part
from those established in Order No. 1000. In particular, we believe
that providing state regulators with a formal opportunity to develop a
cost allocation method for regional transmission facilities selected
through Long-Term Regional Transmission Planning could help increase
stakeholder--and state--support for those facilities, which, in turn,
may increase the likelihood that those facilities are sited and
ultimately developed with fewer costly delays and better ensure just
and reasonable Commission-jurisdictional rates.
300. The Commission has long recognized the critical role of states
in transmission planning.\500\ The Commission recently issued a Policy
Statement addressing state efforts to develop transmission facilities
through voluntary agreements to plan and pay for those facilities.\501\
In the statement, the Commission recognized that such voluntary
agreements may allow state-prioritized transmission facilities to be
planned and built more quickly than would comparable facilities that
are planned through the regional transmission planning process, and
encouraged elimination to barriers to such agreements.\502\ The
Commission has also recently taken action to further federal-state
coordination and cooperation in this area through the establishment of
the Task Force.\503\ The Commission included in the list of topics that
the Task Force may consider: (1) ``[E]xploring potential bases for one
or more states to use FERC-jurisdictional transmission planning
processes to advance their policy goals, including multi-state goals;''
and (2) ``[e]xploring opportunities for states to voluntarily
coordinate in order to identify, plan, and develop regional
transmission solutions.'' \504\ The Task Force, comprised of FERC
Commissioners and state regulators, discussed the role of states in
regional transmission planning and cost allocation processes at two
meetings thus far, and numerous state regulators and other stakeholders
filed comments in response to the ANOPR on this topic. The general
consensus is that involving state regulators when it comes to
allocating the costs of new regional transmission facilities is
particularly important given states' role in siting those transmission
facilities, including consideration of the costs and benefits when
making state public interest determinations.\505\
---------------------------------------------------------------------------
\500\ See Order No. 1000, 136 FERC ] 61,051 at P 688 (citing
Order No. 890, 118 FERC ] 61,119 at P 574). In 2015, the Commission
accepted NYISO's proposal to facilitate the timely participation of
the New York State Public Service Commission (New York Commission)
in review of transmission facilities proposed to address
transmission needs driven by Public Policy Requirements. Under
NYISO's process, the New York Commission is provided a time period
during which it may propose a cost allocation method or negotiate a
cost allocation method with the developer of such a proposed
transmission facility before the Order No. 1000-compliant ex ante
regional cost allocation method is applied. See NY Indep. Sys.
Operator, Inc., 151 FERC ] 61,040, at PP 119-121 (2015).
\501\ State Voluntary Agreements to Plan and Pay for
Transmission Facilities, 175 FERC ] 61,225 (2021).
\502\ Id. PP 2, 6.
\503\ See Joint Fed.-State Task Force on Elec. Transmission, 175
FERC ] 61,224 at PP 1-2 (establishing the Task Force).
\504\ Id. P 6.
\505\ See NARUC Comments at 27, 46-47; NESCOE Comments at 21-25;
Arizona Commission Comments at 7; SPP RSC Comments at 10; Maryland
Energy Admin Comments at 2; Joint Fed.-State Task Force on Elec.
Transmission, Transcript of Feb. 16, 2022 Meeting, Docket No. AD21-
15-000, at 102:13-24 (Chair Thomas), 110:24-111:8 (Comm'r Allen),
111:24-112:5 (Comm'r Rechtschaffen), 134:4-9 (Chair Stanek)
(including in the list of three overarching themes from the meeting
that of state consultation--soliciting state input, at a minimum--on
cost allocation).
---------------------------------------------------------------------------
301. We believe that facilitating involvement of state regulators
in the cost allocation process, as further described below, would allow
states to voluntarily coordinate to advance their policy goals through
needed transmission development and may minimize delays and additional
costs that can be associated with siting proceedings that follow the
regional transmission planning and cost allocation processes at the
federal level.\506\ We believe that providing an opportunity for state
involvement in regional transmission planning cost allocation processes
is becoming more important as states take a more active role in shaping
the resource mix and demand, which, in turn, means that those state
actions are increasingly affecting the long-term transmission
[[Page 26557]]
needs for which we are proposing to require public utility transmission
providers to plan in this NOPR.
---------------------------------------------------------------------------
\506\ E.g., Maryland Energy Admin Comments at 3 (pointing to
significant delays and costs associated with the Artificial Island
transmission facility); Exelon Comments at 31-32 (speaking generally
to states blocking or delaying transmission development through
siting).
---------------------------------------------------------------------------
E. Proposed Reform
1. State Involvement in Cost Allocation for Long-Term Regional
Transmission Facilities \507\
---------------------------------------------------------------------------
\507\ We propose to define a Long-Term Regional Transmission
Facility as a transmission facility identified as part of Long-Term
Regional Transmission Planning and selected in the regional
transmission plan for purposes of cost allocation to address
transmission needs driven by changes in the resource mix and demand.
---------------------------------------------------------------------------
302. We propose to require that public utility transmission
providers in each transmission planning region revise their OATTs to
include either (1) a Long-Term Regional Transmission Cost Allocation
Method \508\ to allocate the costs of Long-Term Regional Transmission
Facilities, or (2) a State Agreement Process \509\ by which one or more
relevant state entities may voluntarily agree to a cost allocation
method, or (3) a combination thereof.\510\ We propose to require that
the Long-Term Regional Transmission Cost Allocation Method and any cost
allocation method resulting from the State Agreement Process for Long-
Term Regional Transmission Facilities comply with the existing six
Order No. 1000 regional cost allocation principles.\511\
---------------------------------------------------------------------------
\508\ We propose to define a Long-Term Regional Transmission
Cost Allocation Method as an ex ante regional cost allocation method
that would be included in each public utility transmission
provider's OATT as part of Long-Term Regional Transmission Planning.
The developer of a Long-Term Regional Transmission Facility would be
entitled to use the Long-Term Regional Transmission Cost Allocation
Method if it is the applicable method.
\509\ We propose to define a State Agreement Process as an ex
post cost allocation process that would be included in each public
utility transmission provider's OATT as part of Long-Term Regional
Transmission Planning, which may apply to an individual Long-Term
Regional Transmission Facility or a portfolio of such Facilities
grouped together for purposes of cost allocation. After a Long-Term
Regional Transmission Facility is selected in the regional
transmission plan for purposes of cost allocation, the State
Agreement Process would be followed to establish a cost allocation
method for that facility (if agreement can be reached). If the
Commission subsequently approves the cost allocation method that
results from the State Agreement Process, the developer of the Long-
Term Regional Transmission Facility would be entitled to use that
cost allocation method if it is the applicable method.
\510\ For example, a ``combination'' approach may entail (i)
providing a Long-Term Regional Transmission Cost Allocation Method
for certain types of Long-Term Regional Transmission Facilities and
providing a State Agreement Process for others; or (ii) providing
for cost allocation for a Long-Term Regional Transmission Facility,
portfolio, or type of such facilities partially based on a Long-Term
Regional Transmission Cost Allocation Method and partially based on
funding contributions in accordance with a State Agreement Process.
\511\ We are not proposing to require any changes to existing
interregional cost allocation methods for interregional transmission
facilities that are selected in the regional transmission plan for
purposes of cost allocation and that the Commission previously
accepted as compliant with Order No. 1000.
---------------------------------------------------------------------------
303. In order to comply with this proposed requirement, public
utility transmission providers in each transmission planning region
would be required to seek the agreement of relevant state entities
within the transmission planning region regarding the Long-Term
Regional Transmission Cost Allocation Method, State Agreement Process,
or a combination thereof. We propose to require public utility
transmission providers in each transmission planning region to explain
how the proposed Long-Term Transmission Cost Allocation Method, the
proposed State Agreement Process, or a combination thereof either: (1)
Reflect the agreement of the relevant state entities, or (2) to the
extent agreement cannot be obtained, an explanation of the good faith
efforts by the relevant public utility transmission provider to seek
agreement from such entities. We seek comment below on how to resolve
the potential inability of the relevant parties to come to agreement,
noting that it will ultimately be necessary for public utility
transmission providers to have a cost allocation method on file with
the Commission for transmission facilities selected through Long-Term
Regional Transmission Planning, and recognizing a State Agreement
Process or combination cost allocation method would not comply with
this proposed rule unless the relevant public utility transmission
providers has obtained agreement from the relevant state entities.
a. Agreement of Relevant State Entities
304. We propose to define relevant state entities for purposes of
the Long-Term Regional Transmission Planning cost allocation
requirements as any state entity responsible for utility regulation or
siting electric transmission facilities within the state or portion of
a state located in the transmission planning region, including any
state entity as may be designated for that purpose by the law of such
state. Although, as discussed below, we propose to provide public
utility transmission providers flexibility in determining what
constitutes state agreement, we preliminarily find that, for each
state, a single entity should be designated as the voting or
representative entity to avoid confusion or over-representation by a
single state in a multi-state voting process.
305. We propose to require that public utility transmission
providers in each transmission planning region seek agreement from the
relevant state entities regarding the approach to cost allocation for
Long-Term Regional Transmission Facilities. Specifically, public
utility transmission providers in each transmission planning region
must seek to determine whether, for all or a subset of Long-Term
Regional Transmission Facilities, the relevant state entities agree to
(1) a Long-Term Regional Transmission Cost Allocation Method; (2) a
State Agreement Process; (3) forgo a role in determining the cost
allocation approach for Long-Term Regional Transmission Facilities; or
(4) some combination thereof.
306. We further propose to afford public utility transmission
providers in each transmission planning region flexibility in the
process by which they seek agreement from the relevant state entities.
In addition, we propose to require public utility transmission
providers to provide the state entities with flexibility with regard to
defining what constitutes ``agreement'' among the relevant state
entities on the cost allocation approach for Long-Term Regional
Transmission Facilities. For example, states may choose to apply the
existing provisions for engaging with the relevant state entities.\512\
In other cases, the relevant state entities may elect to engage in new
or different ways to reach and communicate agreement regarding a cost
allocation approach for Long-Term Regional Transmission
Facilities.\513\
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\512\ For example, states in ISO-NE may consider NESCOE's by-
laws in defining the threshold of agreement among relevant state
entities. Likewise, states in MISO may consider OMS procedures to
define agreement and rely on existing processes by which OMS conveys
its positions to MISO.
\513\ As discussed infra in Proposed Compliance Procedures, we
propose to establish an extended compliance period to accommodate
meaningful engagement with states with respect to this Long-Term
Regional Transmission Planning cost allocation reform.
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307. We note that the relevant state entities may forgo a role in
determining the cost allocation approach for all or a subset of Long-
Term Regional Transmission Facilities. In the event that the relevant
state entities do so, we propose to require public utility transmission
providers to propose a Long-Term Regional Transmission Cost Allocation
Method consistent with the requirements of Order No. 1000, including
the prohibition on relying on voluntary agreement among states or
[[Page 26558]]
participant funding.\514\ Relevant state entities may also fail to
reach agreement on a cost allocation method for all or a portion of
Long-Term Regional Transmission Facilities, and we request comments
below on the appropriate outcome in that situation.
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\514\ Under this proposed requirement, the Long-Term Regional
Transmission Cost Allocation Method that public utility transmission
providers would be required to submit would only apply to the subset
of Long-Term Regional Transmission Facilities for which the relevant
state entities did not determine a cost allocation approach.
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308. We clarify that we are not proposing to impose any
requirements on states to participate in processes to establish
regional cost allocation methods for Long-Term Regional Transmission
Facilities. The Commission has no authority over relevant state
entities in this regard and, as such, those entities need not engage on
a cost allocation approach if they do not wish to do so. Instead, we
propose only to require that public utility transmission providers in
each transmission planning region seek the agreement of the relevant
state entities, and demonstrate in their compliance filings how either
the proposed Long-Term Regional Transmission Cost Allocation Method,
the proposed State Agreement Process, or combination thereof: (1)
Reflects the agreement of the relevant state entities, or (2) to the
extent agreement cannot be obtained, reflects good faith efforts by the
relevant public utility transmission provider to seek agreement from
such entities.
309. We seek comment on whether the proposed definition of relevant
state entities is appropriate. We also seek comment on the proposal to
afford relevant states entities the flexibility to define agreement
among relevant state entities, or whether it is preferable for the
Commission to adopt a specific definition of such agreement.
310. We further recognize that it is possible that relevant states
entities may seek to agree to a cost allocation approach but be unable
to achieve agreement, or may be unwilling to seek agreement to a cost
allocation approach but do not agree to forgo their role in developing
a cost allocation approach for Long-Term Regional Transmission
Facilities. We request comment on the appropriate outcome when the
relevant state entities fail to agree on a cost allocation method for
all or a portion of Long-Term Regional Transmission Facilities.
Specifically, we request comment on whether in such circumstances the
public utility transmission providers should be required to establish a
Long-Term Regional Transmission Cost Allocation Method, the relevant
state entities should be afforded additional time to endeavor to reach
agreement, or the Commission should instead have the responsibility to
establish the Long-Term Regional Transmission Cost Allocation
Method.\515\
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\515\ In Order No. 1000, the Commission determined that, in the
event public utility transmission providers in a region fail to
reach agreement on a cost allocation method, it would use the record
in the compliance filing to determine the cost allocation method.
Order No. 1000, 136 FERC ] 61,051 at P 607.
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b. State Agreement Process
311. We preliminarily find that a State Agreement Process by which
one or more relevant state entities voluntarily agree to a cost
allocation method for Long-Term Regional Transmission Facilities (or
portfolio of facilities) after it is selected in the regional
transmission plan for purposes of cost allocation may be a just and
reasonable approach to cost allocation for such regional transmission
facilities. The State Agreement Process may apply to all Long-Term
Regional Transmission Facilities or only a subset thereof.
312. We further propose to require that a cost allocation method
that results from the State Agreement Process and is filed by the
public utility transmission providers must comply with the existing six
Order No. 1000 regional cost allocation principles.\516\ We
preliminarily find that compliance with such principles will help to
ensure that Commission-jurisdictional rates resulting from any State
Agreement Process will be just and reasonable and not unduly
discriminatory or preferential.
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\516\ As noted, supra, those cost principles are: (1) The costs
of transmission facilities selected in a regional transmission plan
for purposes of cost allocation must be allocated to those within
the transmission planning region that benefit from those facilities
in a manner that is at least roughly commensurate with estimated
benefits; (2) those that receive no benefit from transmission
facilities, either at present or in a likely future scenario, must
not be involuntarily allocated any of the costs of those
transmission facilities; (3) a benefit to cost threshold ratio, if
adopted, cannot exceed 1.25 to 1; (4) costs must be allocated solely
within the transmission planning region unless another entity
outside the region voluntarily assumes a portion of those costs; (5)
the method for determining benefits and identifying beneficiaries
must be transparent; and (6) there may be different regional cost
allocation methods for different types of transmission facilities,
such as those needed for reliability, congestion relief, or to
achieve Public Policy Requirements.
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313. If the relevant state entities decide on a State Agreement
Process, we also propose to require that the public utility
transmission providers in each transmission planning region detail the
process by which the relevant state entities would reach voluntary
agreement regarding the cost allocation for Long-Term Regional
Transmission Facilities pursuant to the State Agreement Process,
including the timeline for such processes. For example, the public
utility transmission providers in each transmission planning region
could specify, as part of the Long-Term Regional Transmission Planning
in their OATTs the procedures by which such voluntary agreements by the
relevant state entities may be filed with the Commission for
consideration under FPA section 205. Such procedures should set forth a
process by which the relevant state entities would agree to funding
contributions and the mechanism by which such costs would be allocated
(e.g., through a pro forma contract).
314. Finally, we note that, to the extent public utility
transmission providers believe their existing cost allocation
approaches comply with the requirements adopted in any final rule in
this proceeding, including those related to the agreement of relevant
state entities, we propose that they may make such demonstration in
their compliance filings in response to any final rule. In addition, we
propose to apply the cost allocation reforms we propose in this NOPR
only to new Long-Term Regional Transmission Facilities and, therefore,
these proposed reforms would not provide grounds for re-litigation of
cost allocation decisions for transmission facilities that are selected
in the regional transmission plan for purposes of cost allocation prior
to the effective date of any final rule in this proceeding,\517\ nor
would they apply to the cost allocation methods associated with
regional transmission facilities that address shorter-term transmission
needs driven by reliability and/or economic considerations. We believe
the proposed cost allocation requirements for Long-Term Regional
Transmission Facilities will help to ensure just and reasonable
Commission-jurisdictional rates by increasing the likelihood that more
efficient or cost-effective regional transmission facilities to address
transmission needs driven by changes in the resource mix and demand are
developed, and with fewer delays. The proposed reforms would enable
relevant state entities, such as state regulators and siting
authorities, who seek greater involvement in cost allocation for Long-
Term Regional Transmission Facilities an opportunity to do so. Where
relevant state entities in a multi-state
[[Page 26559]]
transmission planning region are able to agree upon an approach to
allocate the costs of Long-Term Regional Transmission Facilities needed
to meet these longer-term transmission needs, applying that approach is
likely to decrease the controversy over development of such facilities,
by, for example, making the relevant state entities more confident that
ratepayers in the state are receiving benefits at least roughly
commensurate with their share of the cost of such facilities. In so
doing, the engagement of relevant state entities may help to reduce
instances in which a Long-Term Regional Transmission Facility is
selected, has an established ex ante cost allocation method that
applies to it, but nevertheless fails to be developed because it cannot
receive a necessary state regulatory approval. After all, states retain
siting authority over transmission facilities and will review whether
Long-Term Regional Transmission Facilities are consistent with the
public interest and state siting regulations.
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\517\ The Commission took a similar approach with respect to its
cost allocation reforms in Order No. 1000. See Order No. 1000, 136
FERC ] 61,051 at P 565.
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315. We recognize that, if states agree to a State Agreement
Process instead of a Long-Term Regional Transmission Cost Allocation
Method, certain Long-Term Regional Transmission Facilities selected in
the regional transmission plan for purposes of cost allocation would
lack a clear ex ante cost allocation method. We continue to believe
that the availability of an ex ante cost allocation method helps to
ensure the development of more efficient or cost-effective regional
transmission facilities identified in the regional transmission
planning process.\518\ However, given the increased uncertainty of
Long-Term Regional Transmission Planning and potential for divergent
views on the benefits of meeting transmission needs driven by changes
in the resource mix and demand, we believe that applying a cost
allocation approach agreed to by the relevant state entities may be
just and reasonable and support the viability of Long-Term Regional
Transmission Facilities.
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\518\ Id. P 499; Order No. 1000-A, 139 FERC ] 61,132 at P 52.
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316. We recognize that in Order No. 1000, the Commission explained
that reliance on participant funding as a regional cost allocation
method ``increases the incentive of any individual beneficiary to defer
investment in the hopes that other beneficiaries will value a
transmission project enough to fund its development'' and would
therefore not comply with the regional cost allocation principles
adopted in Order No. 1000.\519\
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\519\ Order No. 1000, 136 FERC ] 61,051 at P 723. Under a
participant funding approach to cost allocation, the costs of a
transmission facility are allocated only to those entities that
volunteer to bear those costs. Id. P 486 n.375.
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317. Nevertheless, we preliminarily find that allowing a State
Agreement Process for Long-Term Regional Transmission Facilities, where
agreed to by the relevant state entities, appropriately balances the
concerns about increased free ridership problems against the benefit of
greater state involvement in determining the cost allocation of Long-
Term Regional Transmission Facilities.\520\ As discussed above, we are
proposing to require public utility transmission providers to engage in
transmission planning over a longer time-horizon than we have
previously required. Although we preliminarily find that such reforms
are necessary to ensure just and reasonable rates, we recognize that
the precise quantification and allocation of the benefits of Long-Term
Regional Transmission Facilities may be more uncertain than
transmission facilities that are planned on a shorter-term basis and/or
based on a more limited set of benefits. As such, we recognize that
state entities charged with siting transmission facilities within their
state may, at least in certain circumstances, take a more skeptical
approach to evaluating applications to site Long-Term Regional
Transmission Facilities. We believe that providing relevant state
entities an opportunity for involvement in establishing a cost
allocation method, including through use of a State Agreement Process,
would help to address any such concerns on the part of state
regulators, increasing the likelihood that Long-Term Regional
Transmission Facilities are actually developed, and without delay.
Accordingly, we preliminarily find that this potential benefit
outweighs concerns about free-ridership with respect to the reforms
proposed herein.
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\520\ Id. P 586 (stating regional cost allocation principles,
including ``[t]hose that receive no benefit from transmission
facilities, either at present or in a likely future scenario, must
not be involuntarily allocated the costs of those facilities.'').
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318. We seek comment on the requirements proposed in this section
of the NOPR. We also seek comment on whether the Commission should
require, instead of the reforms proposed in this section of the NOPR,
public utility transmission providers to include a Long-Term Regional
Transmission Cost Allocation Method in their OATTs.
2. Time Period in Long-Term Regional Transmission Planning Cost
Allocation Processes for State-Negotiated Alternate Cost Allocation
Method
319. Additionally, we propose to require that public utility
transmission providers establish a process, detailed in their OATTs, to
provide a state or states (in multi-state transmission planning
regions) a time period to negotiate a cost allocation method for a
transmission facility (or portfolio of facilities) selected for
purposes of cost allocation through Long-Term Regional Transmission
Planning that is different than any ex ante regional cost allocation
method that would otherwise apply. During this time period for a state-
negotiated alternate cost allocation method, if a state or all states
within the transmission planning region in which the selected regional
transmission facility will be located unanimously agree on an alternate
cost allocation method, the public utility transmission provider may
elect to file it with the Commission for consideration under FPA
section 205. As discussed above, we anticipate the public utility
transmission provider may elect to file an alternate cost allocation
method because doing so increases the likelihood that relevant
stakeholders perceive the cost allocation as fair and that the needed
regional transmission facilities are actually constructed.
320. If the relevant state or states cannot agree on an alternate
cost allocation method memorialized in writing within a specified
timeframe after a transmission facility is selected in the regional
transmission plan for purposes of cost allocation through Long-Term
Regional Transmission Planning (e.g., 90 days), then the transmission
developer will be entitled to use any ex ante regional cost allocation
method that would otherwise apply for that regional transmission
facility.
321. Providing states with a time period to propose alternate cost
allocation methods could help facilitate the timely development of more
efficient or cost-effective regional transmission facilities. For
example, allowing states to negotiate an alternate cost allocation
method for selected regional transmission facilities at a time when
details of the transmission facilities are known could facilitate
agreements on the cost allocation for new regional transmission
facilities because states would have better knowledge of relevant
facts, including benefits and costs, regarding the transmission
facilities for which they are negotiating cost allocation.
[[Page 26560]]
Moreover, state siting proceedings may proceed more efficiently if
states have better information about the costs and benefits of such
regional transmission facilities.
322. We propose to require that public utility transmission
providers add to their OATTs provisions that describe a time period for
state involvement in regional cost allocation for transmission
facilities selected in Long-Term Regional Transmission Planning,
including when this time period will occur, what its duration will be,
and that any alternate cost allocation method must be submitted to the
Commission for review and approval under FPA section 205 prior to
taking effect. When filed, the Commission will evaluate the alternate
cost allocation method to ensure that it is just and reasonable and
allocates costs in a manner that is at least roughly commensurate with
estimated benefits. If the Commission rejects a state-proposed cost
allocation method, the transmission developer of the transmission
facility selected in the regional transmission plan for purposes of
cost allocation through Long-Term Regional Transmission Planning would
be entitled to use the applicable ex ante regional cost allocation
method that would have applied to it in the absence of the proposed
alternative cost allocation method, just as it would be absent this
proposed provision for an alternate cost allocation method.
323. We recognize the tension between a proposal for a time period
for state-negotiated cost allocation within an Order No. 1000-compliant
regional transmission planning process and the Commission's ex ante
cost allocation approach, which we do not propose to remove, including
the potential for delay as compared to the ex ante approach. We propose
to prescribe a 90-day time period for state-negotiated cost allocation
memorialized in writing, which is consistent with the period for state
cost allocation negotiation that the Commission accepted in NYISO's
filing described above.
324. We seek comment on the requirements proposed in this section
of the NOPR, including the timing and duration of any time period for
state-negotiated cost allocation for transmission facilities selected
in the regional transmission plan for purposes of cost allocation
through Long-Term Regional Transmission Planning. We also seek comment
on whether there should be a requirement for a time period for state
involvement in regional cost allocation for transmission facilities
selected in existing near-term reliability and economic regional
transmission planning processes.
3. Identification of Benefits Considered in Cost Allocation for Long-
Term Regional Transmission Facilities
325. We are concerned that the Commission's existing regional
transmission planning and cost allocation requirements may result in
public utility transmission providers undervaluing the benefits of
Long-Term Regional Transmission Facilities for purposes of allocating
the costs of such facilities to beneficiaries in a manner that is
roughly commensurate with estimated benefits. The current approach of
considering only a subset of categories of benefits based on the type
of transmission need that is being studied may result in inaccurate
valuation of a transmission facility's benefits in Long-Term Regional
Transmission Planning. We are also concerned that considering only a
subset of benefits in assigning the cost of Long-Term Regional
Transmission Facilities may contribute to the risk of free rider
problems that impede development of the more efficient or cost-
effective regional transmission facilities. At the same time, as
discussed above, we consider it important that cost allocation should
reflect the views of stakeholders, and the state entities with a role
in permitting transmission facilities in particular, and believe that
the involvement of states in cost allocation increases the likelihood
that Long-Term Regional Transmission Facilities are actually developed.
326. Nevertheless, we acknowledge the support for the adoption of a
common set of minimum benefits, and we propose for consideration a list
of Long-Term Regional Transmission Benefits described above for public
utility transmission providers to apply in Long-Term Regional
Transmission Planning and Cost Allocation processes. In addition, we
propose to require that public utility transmission providers identify
on compliance the benefits they will use in any ex ante cost allocation
method associated with Long-Term Regional Transmission Planning, how
they will calculate those benefits, and how the benefits will
reasonably reflect the benefits of regional transmission facilities to
meet identified transmission needs driven by changes in the resource
mix and demand. As part of this compliance obligation, public utility
transmission providers should explain the rationale for using the
benefits identified.
327. We request comment on this proposed requirement. We also
request comment on whether the Commission should require that public
utility transmission providers account for the full list of benefits
described in the Evaluation of the Benefits of Regional Transmission
Facilities section above in Long-Term Regional Transmission Planning,
or whether no change to the benefits currently used in existing
regional transmission planning processes is needed.
VI. Construction Work in Progress Incentive
A. Background
328. In the Energy Policy Act of 2005,\521\ Congress added section
219 to the FPA, directing the Commission to establish, by rule,
incentive-based rate treatments to promote capital investment in
certain transmission infrastructure. The Commission subsequently issued
Order No. 679 in 2006, which sets forth processes by which a public
utility may seek transmission rate incentives pursuant to FPA section
219.\522\
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\521\ Public Law 109-58, 1241, 119 Stat. 594 (2005).
\522\ Promoting Transmission Inv. through Pricing Reform, Order
No. 679, 116 FERC ] 61,057, order on reh'g, Order No. 679-A, 117
FERC ] 61,345 (2006), order on reh'g, 119 FERC ] 61,062 (2007).
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329. In Order No. 679, the Commission adopted several incentive-
based rate treatments to promote capital investment in certain
transmission infrastructure and to address impediments faced by those
investing in transmission. The Commission found that the long-lead time
to construct new transmission and associated cash flow difficulties
presented an impediment to new transmission investment.\523\ To remove
this impediment, the Commission adopted its proposal to allow for the
recovery of 100% of CWIP costs in rate base in certain circumstances
(CWIP Incentive).\524\ Allowing transmission developers to include
construction costs in rate base prior to commercial operation provides
utilities with additional cash flow in the form of an immediate earned
return, rather than delaying recovery of those costs until the plant is
placed into service.\525\ In Order No. 679, the Commission acknowledged
that the CWIP Incentive was a departure from the existing ratemaking
doctrine that rates should be based on plant costs that
[[Page 26561]]
are ``used and useful.'' \526\ However, the Commission clarified that
``the Commission can depart from the norm as long as it reasonably
balances consumers' interest in fair rates against investors' interest
in maintaining financial integrity and access to capital markets.''
\527\
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\523\ Id. P 9.
\524\ The Commission has also provided that any public utility
engaged in the sale of electric power for resale can file to include
in rate base up to 50% of CWIP, subject to limitations. Construction
Work in Progress for Public Utilities; Inclusion of Costs in Rate
Base, Order No. 298, FERC Stats. & Regs. ] 30,455 (1983), order on
reh'g, 25 FERC ] 61,023 (1983).
\525\ Order No. 679, 116 FERC ] 61,057 at n.70.
\526\ Id. PP 116-117.
\527\ Id. P 117 (quoting Jersey Cent. Power & Light Co. v. FERC,
810 F.2d 1168, 1178 (D.C. Cir. 1987)).
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B. Need for Reform
330. As indicated above in this NOPR, under the proposed Long-Term
Regional Transmission Planning reforms, we seek to strike a balance
between the risk of over- and under-investment regarding the selection
of transmission facilities in the regional transmission plan for
purposes of cost allocation that address transmission needs driven by
changes in the resource mix and demand. We acknowledge that there is
likely to be more uncertainty in Long-Term Regional Transmission
Planning, e.g., requiring public utility transmission providers to
conduct Long-Term Regional Transmission Planning over a minimum of 20
years (compared to the current practice of 6-15 years), than in the
existing regional transmission planning processes.
331. In light of the incremental uncertainty associated with the
proposed Long-Term Regional Transmission Planning, we preliminarily
find that additional protection for ratepayers may be necessary to
reasonably balance consumers' interest in just and reasonable rates
against investors' interest in earning a return on their investments
and reduce the risk to ratepayers of potentially financing over-
investment in regional transmission facilities.\528\ The Commission
previously found that the CWIP Incentive is beneficial to ease the
financial pressures associated with transmission development by
providing up-front regulatory certainty, rate stability, and improved
cash flow, which in turn can result in higher credit ratings and lower
capital costs.\529\ These benefits mainly accrue to the public utility
transmission providers and their shareholders during construction,
while ratepayers mainly receive the benefits from completed
transmission facilities under a more stable rate environment.
Specifically, during the construction of the regional transmission
facilities, ratepayers do not receive benefits from the regional
transmission facilities, while simultaneously ratepayers directly
finance the construction under the CWIP Incentive. Should the regional
transmission facilities not be placed in service, then ratepayers will
have financed the construction of such facilities that were not used
and useful, while ultimately receiving no benefits from such
facilities.
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\528\ See, e.g., NextEra Energy Transmission Sw., LLC, 178 FERC
] 61,082 (2022) (Christie, Comm'r, concurring).
\529\ Order No. 679, 116 FERC ] 61,057 at P 115.
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332. Given the Long-Term Regional Transmission Planning reforms
proposed in this NOPR and the incremental uncertainty and risk that
Long-Term Regional Transmission Facilities may not become ``used and
useful,'' we are concerned that the CWIP Incentive, if made available
for Long-Term Regional Transmission Facilities, may shift too much risk
to consumers to the benefit of public utility transmission providers in
a manner that renders Commission-jurisdictional rates unjust and
unreasonable.
C. Proposed Reform
333. To address the concerns identified above, we propose to not
permit public utility transmission providers to take advantage of the
CWIP Incentive for Long-Term Regional Transmission Facilities. We note
that public utility transmission providers may still book costs
incurred during the pre-construction or construction phase as Allowance
for Funds Used During Construction (AFUDC) and only recover those costs
after the project is in service to customers, in accordance with
generally accepted utility accounting principles for AFUDC.\530\
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\530\ We further note that our proposal regarding the CWIP
Incentive for Long-Term Regional Transmission Facilities does not
affect Commission policy and regulations established before Order
No. 679. That is, public utility transmission providers would still
be allowed to request 50% CWIP in rate base, as is permitted
pursuant to 18 CFR 35.25(c)(3), subject to an FPA section 205 filing
detailing how the request meets the requirements of Order No. 298.
We believe that the ability to include 50% CWIP in rate base, if
requested and granted, reflects a more reasonable sharing of risks
and benefits than the CWIP Incentive for Long-Term Regional
Transmission Facilities given the greater uncertainty inherent in
Long-Term Regional Transmission Planning, as proposed in this NOPR.
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334. We seek comment on the requirements proposed in this section
of the NOPR. In particular, we seek comment on whether this proposed
reform would reasonably balance consumer and investor interests.
VII. Exercise of a Federal Right of First Refusal in Commission-
Jurisdictional Tariffs and Agreements
335. Order No. 1000 instituted a number of reforms regarding the
participation of nonincumbent transmission developers in the regional
transmission planning process, which, as a whole, facilitate
competition for transmission development.\531\ As explained in more
detail below, we continue to require compliance with Order No. 1000's
nonincumbent transmission developer reforms, and we maintain our
commitment to transmission development rules and policies that align
with or advance the goals of those reforms, or otherwise ensure just
and reasonable Commission-jurisdictional rates and limit opportunities
for undue discrimination by public utility transmission providers.
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\531\ See ISO New Eng. Inc., 169 FERC ] 61,054, at PP 1-2 (2019)
(citations omitted); see also Order No. 1000, 136 FERC ] 61,051 at
PP 225-344.
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336. However, in light of the experience gained since the issuance
of Order No. 1000 and the comments received in response to the ANOPR,
we propose to amend Order No. 1000's nonincumbent transmission
developer requirements, in part. As described in more detail below, we
propose to permit the exercise of federal rights of first refusal for
transmission facilities selected in a regional transmission plan for
purposes of cost allocation, conditioned on the incumbent transmission
provider with the federal right of first refusal for such regional
transmission facilities establishing joint ownership of the
transmission facilities consistent with the proposal below.
A. Background
1. Order No. 1000's Nonincumbent Transmission Developer Reforms and
Federal Right of First Refusal Elimination Mandate
337. In instituting nonincumbent transmission developer reforms,
the Commission in Order No. 1000 distinguished between incumbent
transmission developers (also called incumbent transmission providers)
and nonincumbent transmission developers. An incumbent transmission
developer/provider is an entity that develops a transmission facility
within its own retail distribution service territory or footprint. A
nonincumbent transmission developer refers to two categories of
transmission developer: (1) A transmission developer that does not have
a retail distribution service territory or footprint; and (2) a public
utility transmission provider that proposes a transmission facility
outside of its existing retail distribution service territory or
footprint, where it is not the incumbent for purposes of that
facility.\532\
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\532\ Order No. 1000, 136 FERC ] 61,051 at P 225.
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338. Among its nonincumbent transmission developer reforms, Order
No. 1000 requires that each public
[[Page 26562]]
utility transmission provider eliminate provisions in Commission-
jurisdictional tariffs and agreements that establish a federal right of
first refusal for an incumbent transmission provider with respect to
entirely new transmission facilities selected in a regional
transmission plan for purposes of cost allocation.\533\
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\533\ Id. P 313; Order No. 1000-A, 139 FERC ] 61,132 at P 426
(``The concept is that there should not be a federally established
monopoly over the development of an entirely new transmission
facility that is selected in a regional transmission plan for
purposes of cost allocation to others.''). The phrase ``a federal
right of first refusal'' refers only to rights of first refusal that
are created by provisions in Commission-jurisdictional tariffs or
agreements. Order No. 1000-A, 139 FERC ] 61,132 at P 415. Before
Order No. 1000, some RTO/ISO governing documents and other utility
tariffs and agreements included federal rights of first refusal,
which ``gave incumbent utilities the option to construct any new
transmission facilities in their particular service areas, even if
the proposal for new construction came from a third party.'' S.C.
Pub. Serv. Auth., 762 F.3d at 72.
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339. This requirement from Order No. 1000 does not apply to local
transmission facilities, which are defined as transmission facilities
located solely within an incumbent transmission provider's retail
distribution service territory or footprint that are not selected in
the regional transmission plan for purposes of cost allocation.\534\
The requirement also does not apply to the right of an incumbent
transmission provider to build, own, and recover costs for upgrades to
its own existing transmission facilities, regardless of whether an
upgrade has been selected in the regional transmission plan for
purposes of cost allocation.\535\ In addition, the Commission noted
that the requirement does not remove, alter, or limit an incumbent
transmission provider's use and control of its existing rights-of-way
under state law.\536\ The Commission has also permitted exemptions from
the federal right of first refusal elimination mandate for immediate
need reliability projects.\537\
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\534\ Order No. 1000, 136 FERC ] 61,051 at PP 63, 226, 258, 318.
In addition, the Commission clarified in Order No. 1000-A that a
transmission facility whose costs are 100% allocated to the public
utility transmission provider in whose retail distribution service
territory or footprint the facility is located is not considered to
be selected in the regional transmission plan for purposes of cost
allocation and could remain subject to a federal right of first
refusal. Order No. 1000-A, 139 FERC ] 61,132 at PP 423-424; see also
id. P 427.
\535\ Order No. 1000, 136 FERC ] 61,051 at PP 226, 319; Order
No. 1000-A, 139 FERC ] 61,132 at P 426. Upgrades to existing
transmission facilities include, for example, tower change outs or
reconductoring, regardless of whether or not an upgrade has been
selected in the regional transmission plan for purposes of cost
allocation. Order No. 1000, 136 FERC ] 61,051 at P 319. The
Commission clarified in Order No. 1000-A that the term ``upgrade''
means an improvement to, addition to, or replacement of a part of,
an existing transmission facility. The term does not refer to an
entirely new transmission facility. Order No. 1000-A, 139 FERC ]
61,132 at P 426.
\536\ Order No. 1000, 136 FERC ] 61,051 at PP 226, 319.
\537\ See, e.g., PJM Interconnection, L.L.C., 174 FERC ] 61,117,
at P 3 (2021); Sw. Power Pool, Inc., 171 FERC ] 61,213, at P 3
(2020); Midcontinent Indep. Sys. Operator, Inc., 173 FERC ] 61,203,
at P 1 (2020); ISO New Eng. Inc., 171 FERC ] 61,211, at P 1, 3
(2020); N.Y. Indep. Sys. Operator, Inc., 171 FERC ] 61,082, at PP
30-34 (2020).
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340. In adopting Order No. 1000's nonincumbent transmission
developer reforms, the Commission identified several reasons why it
believed that eliminating federal rights of first refusal from
Commission-jurisdictional tariffs and agreements was necessary and
appropriate to ensure that Commission-jurisdictional rates are just and
reasonable. The Commission found that federal rights of first refusal
``creat[e] a barrier to entry,'' and that their existence could lead to
the loss of nonincumbent transmission developer investment
opportunities to incumbent transmission providers, which ``discourages
nonincumbent transmission developers from proposing alternative
solutions for consideration at the regional level'' in regional
transmission planning processes.\538\ The Commission found that
administering transmission planning processes with federal rights of
first refusal ``may result in the failure to consider more efficient or
cost-effective solutions to regional needs'' and thus their elimination
may give ``customers . . . the benefits of competition in transmission
development, and associated potential savings.'' \539\ The Commission
also expressed concern that federal rights of first refusal could allow
an incumbent transmission provider ``to act in its own economic self-
interest,'' which in general would not support permitting ``new
entrants to develop transmission facilities, even if proposals
submitted by new entrants would result in a more efficient or cost-
effective solution to the region's needs.'' \540\
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\538\ Order No. 1000, 136 FERC ] 61,051 at PP 229, 256-257, 284,
320.
\539\ Id. PP 284-286, 291; see also id. PP 229, 315. The
Commission reasoned, in part, that ``[g]reater participation by
transmission developers in the transmission planning process may
lower the cost of new transmission facilities, enabling more
efficient or cost-effective deliveries by load serving entities and
increased access to resources.'' Id. P 291.
\540\ Id. P 256.
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341. The Commission also found that elimination of federal rights
of first refusal was ``necessary to address opportunities for undue
discrimination and preferential treatment against nonincumbent
transmission developers within regional transmission planning
processes.'' \541\ While the Commission did not dispute the claim that
incumbent transmission providers may have some inherent advantages over
nonincumbent transmission developers in the transmission development
context,\542\ the Commission found that these claimed incumbent
advantages were ``strengths'' that could be deployed by incumbent
transmission providers to their benefit in competitive transmission
development processes, and not a reason to forgo holding those
processes.\543\
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\541\ Order No. 1000-A, 139 FERC ] 61,132 at P 361; see also
Order No. 1000, 136 FERC ] 61,051 at PP 269, 286. The Commission
also reiterated that ``if a regional transmission planning process
does not consider and evaluate transmission projects proposed by
nonincumbents that regional transmission planning process cannot
meet the Order No. 890 transmission planning principle of being
`open.' '' Order No. 1000, 136 FERC ] 61,051 at P 229.
\542\ See Order No. 1000, 136 FERC ] 61,051 at P 260
(acknowledging that incumbent transmission providers ``may have
unique knowledge of their own transmission systems, familiarity with
the communities they serve,'' and other potential transmission
development advantages); see also id. PP 241, 250 (summarizing other
contentions ``that incumbent transmission owners are better situated
to build new transmission facilities'').
\543\ Id. P 260.
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342. Importantly, while the Commission declined to eliminate
federal rights of first refusal for upgrades to existing transmission
facilities and local transmission facilities, among other specific
types of transmission facilities,\544\ and has permitted exemptions for
immediate need reliability projects,\545\ the Commission did not
otherwise qualify or limit the federal right of first refusal
elimination mandate within its defined scope (i.e., as applied to
entirely new transmission facilities selected in a regional
transmission plan for purposes of cost allocation).\546\ Instead, the
[[Page 26563]]
Commission ordered, with limited exceptions, the elimination of federal
rights of first refusal for entirely new transmission facilities
selected in a regional transmission plan for purposes of cost
allocation, regardless of the specifics of or the circumstances under
which such federal rights of first refusal had been or could be used.
---------------------------------------------------------------------------
\544\ See supra notes 534-536 and associated text. The
Commission explained, in part, that its decision in this regard
would ``continue[ ] to permit an incumbent . . . to meet its
reliability needs or service obligations'' through local
transmission facilities, and the Commission hoped that this
exemption would also, in part, address concerns that Order No.
1000's reforms would ``adversely impact the collaborative nature of
current regional transmission planning processes.'' See Order No.
1000, 136 FERC ] 61,051 at PP 258, 262.
\545\ See supra note 537 and associated text.
\546\ See, e.g., Order No. 1000-A, 139 FERC ] 61,132 at P 426
(``The concept is that there should not be a federally established
monopoly over the development of an entirely new transmission
facility that is selected in a regional transmission plan for
purposes of cost allocation to others.''); id. P 360 (finding on
rehearing that ``the Commission's decision to require public utility
transmission providers to adopt the nonincumbent transmission
developer reforms was an appropriate, and adequately tailored,
remedy'' and noting that the Commission did not accept the position
of some commenters that ``supported eliminating all federal rights
of first refusal'' but rather it ``determined that incumbent
transmission providers should be able to maintain an existing
federal right of first refusal for certain types of new transmission
projects'').
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2. Experience Since Order No. 1000
343. Since the Commission issued Order No. 1000, all public utility
transmission providers across the country have adopted and many have
administered competitive transmission development processes for the
selection of transmission facilities in a regional transmission plan
for purposes of cost allocation.\547\ Though public utility
transmission providers in all transmission planning regions must
participate in their respective regional transmission planning
processes, the degree to which competitive transmission development
processes have led to specific transmission facility selection,
investment, and development activities since Order No. 1000--and the
proportion of such processes that resulted in the selection of a
nonincumbent transmission developer's proposal--varies significantly by
region.\548\
---------------------------------------------------------------------------
\547\ See FERC, Staff Report, 2017 Transmission Metrics, at 8
(Oct. 6, 2017), https://www.ferc.gov/sites/default/files/2020-05/transmission-investment-metrics.pdf (describing the two general
types of competitive transmission development processes, the
``competitive bidding model'' and the ``sponsorship model''); see
also Competition Coalition Comments at 14-15 (same).
\548\ See FERC, Staff Report, 2017 Transmission Metrics, at 23-
26 (Oct. 6, 2017), https://www.ferc.gov/sites/default/files/2020-05/transmission-investment-metrics.pdf; see also Brattle Apr. 2019
Competition Report at 5, 8 fig. 2, 28 fig. 10 (included as Ex. 2 to
LS Power Oct. 12 Comments).
---------------------------------------------------------------------------
344. Importantly, recent transmission investment trends suggest
that despite increased investment in transmission facilities overall,
in many transmission planning regions there has been comparatively
limited investment in transmission facilities selected in a regional
transmission plan for purposes of cost allocation as a result of a
competitive process; transmission investment has instead largely been
concentrated in transmission facilities generally not subject to
competitive transmission development processes.\549\ In particular,
recent transmission investment appears to be concentrated in local
transmission facility development or regional transmission facilities
subject to an exception from competitive transmission development
processes, such as immediate need reliability projects or upgrades to
existing transmission facilities, as opposed to investment in regional
transmission facilities selected in a regional transmission plan for
purposes of cost allocation that serve a wider set of transmission
needs and are subject to competitive transmission development
processes.\550\
---------------------------------------------------------------------------
\549\ See Competition Coalition Comments at 9-10 (describing
growth trend in overall transmission investment); NextEra Comments
at 99-101 (estimating that only a small fraction of overall
transmission investment in RTO/ISO regions between 2013-2020 was
awarded as the result of a competitive process); Brattle Apr. 2019
Competition Report at 1, 3, 5-8, 25 (same).
\550\ See APPA Comments at 20; AEE Comments at 22-23; LS Power
Reply Comments at 41-44; see also California Commission Comments at
14-16 (discussing investment in ``self-approved projects''); EEI
Comments at 6 (referring in part to ``a near standstill in
transmission development for regional projects''); Brattle-Grid
Strategies Oct. 2021 Report at 19-20 (explaining that concentration
on local transmission facilities and the incentives given to
transmission owners may create ``a bias against larger regional
solutions even if they are more innovative and cost-effective'').
---------------------------------------------------------------------------
3. ANOPR
345. In the ANOPR, the Commission recognized the possibility that
``the current transmission planning processes may be resulting
increasingly in transmission facilities addressing a narrow set of
transmission needs, often located in a single transmission owner's
footprint.'' \551\ The Commission also recognized that to ``the extent
that the requirements of the regional transmission planning process
result in transmission providers expanding predominately local
transmission facilities, that process may fail to identify more
efficient or cost-effective transmission facilities needed to
accommodate anticipated future generation.'' \552\ The Commission
sought ``to better understand how the reforms of the federal right of
first refusal in Order No. 1000 have shaped the type and
characteristics of transmission facilities developed through regional
and local transmission planning processes, such as a relative increase
in investment in local transmission facilities or the diversity of
projects resulting from competitive bidding processes.'' \553\
---------------------------------------------------------------------------
\551\ ANOPR, 176 FERC ] 61,024 at P 37.
\552\ Id.
\553\ Id.
---------------------------------------------------------------------------
4. Comments
346. In response, many commenters address issues related to
competitive transmission development processes, federal rights of first
refusal, and how Order No. 1000's reforms may have shaped transmission
development decisions and investments in recent years. Included among
these comments are critiques of the Commission's Order No. 1000
nonincumbent transmission developer reforms, which contend that those
reforms have not achieved their predicted benefits; these critiques
tend to associate that track record at least in part with Order No.
1000's federal right of first refusal elimination policy.\554\
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\554\ E.g., MISO Comments at 26-27, 29-30 (asserting that
``Order No. 1000 requirements for competitive development of
projects selected in a regional plan for purposes of cost allocation
[have] . . . seen only limited success'' and describing the
challenges MISO has faced in implementing those mandates); WIRES
Comments at 11-12, 16 (asserting that the ``introduction of
competition . . . has not lived up to expectations'' and addressing
the Commission's articulated concerns about the possibility that
``current policies and processes are not appropriately incentivizing
the development and construction of larger regional facilities'');
Harvard ELI Comments at 17-18, 20-21 (contending that ``Order No.
1000-compliant regional processes . . . have not fulfilled their
promise'' and did not ``lead to an increase in regional projects'').
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347. However, commenters are divided regarding the steps that they
believe the Commission should take in response to the concerns and
trends described above. Several commenters support increasing the scope
and number of competitive transmission development processes by
expanding Order No. 1000's federal right of refusal elimination mandate
to other types of transmission facilities. For example, the Competition
Coalition and the California Commission call for more competition in
regional transmission planning, design, and construction, which they
predict will lower costs to customers as transmission investment
increases.\555\ Similarly, LS Power contends that the implementation of
current regional transmission planning processes has resulted in
increasingly local transmission planning to the detriment of regional
transmission planning, that a focus on local transmission needs leads
to piecemeal solutions, and that the proper response is to expand
competitive transmission development processes to address a greater
number of transmission facilities.\556\ NARUC similarly recommends that
the Commission encourage the use of current competitive processes and
discourage over-investment in local transmission facilities to help
maximize regional and
[[Page 26564]]
interregional benefits.\557\ PIOs assert that the Commission must
require public utility transmission providers to plan for local
transmission needs as part of the regional transmission planning
process.\558\ The PJM Market Monitor indicates that there is not yet a
transparent, robust, and clearly defined mechanism to permit
competition to build transmission projects, to ensure that competitors
provide a total project cost cap, or to obtain least cost financing
through the capital markets. The PJM Market Monitor claims that the
Commission should build upon Order No. 1000 to remove barriers to
nonincumbent transmission development and create more opportunities for
competition between incumbent transmission providers and nonincumbent
transmission providers.\559\ The Chairman of the Kentucky Commission
states that more transmission facilities and needs should be subject to
competition.\560\
---------------------------------------------------------------------------
\555\ Competition Coalition Comments at 4, 11; see also id. at 4
nn.4-5 (citing Brattle Apr. 2019 Competition Report at 13, 19);
California Commission Comments at 24-25, 34-35, 42-43.
\556\ LS Power Oct. 12 Comments at 28, 31-33, 35, 85-111
(citations omitted); see also LS Power Reply Comments at 2-39
(collecting statements from similar comments (citations omitted)).
\557\ NARUC Comments at 55-56; see also Environmental Advocates
Comments at 15-18 (arguing, in part, that reliance on projects not
subject to competition ``can forestall regional projects by making
transmission planning and construction into a piecemeal process'').
\558\ PIOs Reply Comments at 13.
\559\ PJM Market Monitor Comments at 8. For example, the PJM
Market Monitor criticizes the lack of oversight of supplemental
projects in PJM, noting that the need for supplemental projects
should be clearly defined within PJM's transmission planning process
and there should be a transparent, robust, and clearly defined
mechanism to permit competition to build supplemental projects. Id.
at 8-9.
\560\ Chairman of the Kentucky Commission Kent A. Chandler Reply
Comments at 3-4.
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348. In contrast, other commenters urge the Commission to move in
the opposite direction, arguing that the existence of competitive
transmission development processes leads to delays and added costs
while the elimination of federal rights of first refusal for
transmission facilities selected in a regional transmission plan for
purposes of cost allocation has failed to produce the benefits that the
Commission expected.\561\ For example, EEI urges the Commission to
recognize that ``transmission is not being built'' and to act to
``remove the complex and costly competitive processes'' that, in EEI's
view, delay transmission development.\562\ ITC asserts that significant
time and resources are required to conduct competitive transmission
development processes, yet those processes ``deliver few if any savings
to customers, let alone savings which justify their costs.'' \563\
Accordingly, ITC advocates for allowing public utility transmission
providers to adopt or reinstate a federal right of first refusal in
light of ``the urgency of the need for new transmission investment.''
\564\
---------------------------------------------------------------------------
\561\ See EEI Comments at 21-23; see also id. at 23-24 (urging
the Commission to recognize that ``transmission is not being built''
and to act to ``remove the complex and costly competitive
processes'' that, in EEI's view, delay transmission development);
See EEI Comments at 21-23; see also Eversource Comments at 13-14
(arguing that, in its experience, competitive transmission
development processes have created delays, and that it is unclear
what benefits can be shown from such processes); Indicated PJM TOs
Comments at 4 (arguing in part that Order No. 1000's nonincumbent
transmission developer reforms have ``fostered conflict and
litigation, with the associated expense and delays'').
\562\ EEI Comments at 23-24.
\563\ ITC Comments at 13-15 & nn.8-9 (citing Concentric Energy
Advisors, Building New Transmission, Experience to Date Does Not
Support Expanding Solicitations (June 2019) (included as attach. B
to EEI Reply Comments)).
\564\ Id. at 13.
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B. Need for Reform
349. As noted above, recent investment appears to be concentrated
in transmission facilities not subject to Order No. 1000 competitive
transmission development processes, which are often developed within
individual incumbent transmission provider retail distribution service
territories or footprints or address narrow regional transmission
needs, as opposed to investment in regional transmission facilities
selected in a regional transmission plan for purposes of cost
allocation that serve a wider set of transmission needs and are subject
to competitive transmission development processes.\565\ Indeed, despite
the fact that multiple industry studies estimate that regionally
planned transmission expansion would yield numerous consumer
benefits,\566\ transmission investment through the regional
transmission planning and cost allocation processes has not necessarily
increased since implementation of Order No. 1000; in fact, in some
transmission planning regions, investment in regionally planned
transmission has declined.\567\ The record here further indicates that
regional transmission facilities subject to a competitive transmission
development process represent only a small portion of total
transmission investment in recent years across several transmission
planning regions.\568\
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\565\ See supra note 550 and associated text.
\566\ See, e.g., Rob Gramlich & Jay Caspary, Americans for a
Clean Energy Grid, Planning for the Future, at app. A (Jan. 2021)
(included as Ex. 1 to ACORE Comments) (ACEG Jan. 2021 Planning
Report); at app. A; Brattle, Offshore Transmission in New England:
The Benefits of a Better Planned Grid (May 2020), https://www.brattle.com/wp-content/uploads/2021/05/18939_offshore_transmission_in_new_england_-the_benefits_of_a_better-planned_grid_brattle.pdf (Brattle Offshore
Transmission Study).
\567\ See, e.g., ACEG Jan. 2021 Planning Report at 25 & fig. 8
(charting the annual regionally planned transmission investment in
RTOs/ISOs from 2010 to 2018); ACORE Comments at 4 (citing Ex. 1,
ACEG Jan. 2021 Planning Report at 25). For example, investment in
regional transmission facilities in PJM averaged $2.76 billion from
2005 to 2013 and dropped to $1.65 billion from 2014 to 2020. Harvard
ELI Comments at 21 & n.92 (citations omitted); see also PJM,
Transmission Expansion Advisory Committee, 2019 Project Statistics,
at 3 (May 12, 2020), https://www.pjm.com/-/media/committees-groups/committees/teac/2020/20200512/20200512-item-10-2019-project-statistics.ashx.
\568\ See, e.g., Brattle Apr. 2019 Competition Report at 19 fig.
6.
---------------------------------------------------------------------------
350. This trend may be related to Order No. 1000's nonincumbent
transmission developer reforms. While Order No. 1000 anticipated and
generally sought to facilitate greater and more efficient or cost-
effective investment in regional transmission facilities,\569\ some
observers at the time expressed concern that Order No. 1000's reforms
``could ultimately discourage'' existing ``transmission owners from
seeking regional cost allocation for their local projects,'' and
thereby unintentionally encourage ``more local transmission projects''
serving more local needs, even where broader regional transmission
facilities may be more efficient or cost-effective.\570\ Thus, given
the investment trends observed since Order No. 1000's implementation,
it is possible that the Commission's Order No. 1000 nonincumbent
transmission developer reforms may in fact be inadvertently
discouraging investment in and development of regional transmission
facilities to some extent. Incumbent transmission providers, as a
result of those reforms, may be presented with perverse investment
incentives that do not adequately encourage those incumbent
transmission providers to develop and advocate for transmission
facilities that benefit more than just their own local retail
distribution service territory or footprint. Due to these concerns, we
propose to revisit and reform the Commission's rules and policies
regarding the elimination of federal rights of first refusal, as
described in this section.
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\569\ See Order No. 1000, 136 FERC ] 61,051 at PP 2-3, 46.
\570\ See, e.g., id. (Moeller, Comm'r, dissenting in part).
---------------------------------------------------------------------------
C. Proposed Reform
1. Approach To Reform
351. In light of the experience gained since the issuance of Order
No. 1000 and the comments received in response to the ANOPR, we propose
to amend Order No. 1000's nonincumbent transmission developer reforms
in part,
[[Page 26565]]
so as to permit the exercise of federal rights of first refusal for
transmission facilities selected in a regional transmission plan for
purposes of cost allocation, conditioned on the incumbent transmission
provider with the federal right of first refusal for such regional
transmission facilities establishing joint ownership of the
transmission facilities consistent with the proposal below. We propose
to use the discretion afforded by FPA section 309 to ``amend, and
rescind such orders, rules, and regulations as [the Commission] may
find necessary or appropriate'' in implementing the FPA, including FPA
section 205,\571\ to amend Order No. 1000's findings and mandates in
part. Specifically, we preliminarily find that Order No. 1000 remains
correct regarding the unconditional exercise of federal rights of first
refusal for entirely new transmission facilities selected in a regional
transmission plan for purposes of cost allocation--the unconditional
use of federal rights of first refusal for such facilities remains
unjust and unreasonable given the likelihood that the presence and
exercise of those rights may prevent the realization of more efficient
or cost-effective transmission solutions to regional transmission
needs.\572\
---------------------------------------------------------------------------
\571\ 16 U.S.C. 825h (``The Commission shall have power to
perform any and all acts, and to prescribe, issue, make, amend, and
rescind such orders, rules, and regulations as it may find necessary
or appropriate to carry out the provisions of this chapter.''); see
also id. section 824d(a)-(b) (requiring that ``all rules and
regulations affecting or pertaining to'' jurisdictional rates ``be
just and reasonable'' and free from ``undue preference or
advantage''); Am. Pub. Power Ass'n v. FPC, 522 F.2d 142, 144, 145-47
(D.C. Cir. 1975) (affirming Commission action taken under FPA
section 309 to change rules regarding cost basis for wholesale
electric power rates, observing in part that ``ratemaking
methodologies perceived to produce just and reasonable results in
the past may be scrapped in favor of other methodologies now
perceived to be preferable'' (citation omitted)); La.Regional
Transmission Organizations, Order No. 2000, FERC Stats. & Regs. ]
31,089, at 30,993 (1999) (cross-referenced at 89 FERC ] 61,285)
(relying in part on section 205 in a rulemaking order that enabled
voluntary reforms), order on reh'g, Order No. 2000-A, FERC Stats. &
Regs. ] 31,092 (2000) (cross-referenced at 90 FERC ] 61,201), aff'd
sub nom. Pub. Util. Dist. No. 1 of Snohomish Cty. v. FERC, 272 F.3d
607 (DC Cir. 2001); La. Pub. Serv. Comm'n v. Entergy Corp., Opinion
No. 519-A, 153 FERC ] 61,188, at P 15 (2015) (``The Commission,
which is responsible for determining what is `just and reasonable'
under the FPA, necessarily has broad discretion to take into account
all factors that affect that determination.'').
\572\ See Order No. 1000, 136 FERC ] 61,051 at PP 5, 7, 226.
---------------------------------------------------------------------------
352. However, in light of the years of experience since the
issuance of Order No. 1000 and the comments received in response to the
ANOPR, we preliminarily find that Order No. 1000's remedy--requiring
the elimination of all federal rights of first refusal for entirely new
transmission facilities selected in a regional transmission plan for
purposes of cost allocation--was overly broad. Order No. 1000 may have
overlooked the possibility that, as an alternative to elimination of
federal rights of first refusal for transmission facilities selected in
a regional transmission plan for purposes of cost allocation,
conditions could be applied to the use of federal rights of first
refusal for such facilities that would make their exercise just and
reasonable and not unduly discriminatory or preferential.
353. Accordingly, we preliminarily find that, while Order No.
1000's nonincumbent transmission developer reforms have a sound
theoretical basis,\573\ in requiring the elimination of all federal
rights of first refusal for entirely new transmission facilities
selected in a regional transmission plan for purposes of cost
allocation, the remedy prescribed by Order No. 1000 failed to recognize
that at least some of the most notable expected benefits from
competitive transmission development processes (e.g., new transmission
developer market entry, greater innovation in and potentially lower
costs of transmission development) could be achieved or at least
reasonably approximated through other means. We believe that it may be
possible that allowing public utility transmission providers to propose
conditional federal rights of first refusal consistent with the
proposal below may help public utility transmission providers address
potentially flawed investment incentives that may be restraining
otherwise more efficient or cost-effective regional transmission
facility development. Therefore, under FPA sections 309 and 205, we
preliminarily find it necessary or appropriate to carry out the
provisions of the FPA to amend Order No. 1000 in part as described in
this section.
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\573\ See supra notes 538 to 541 and associated text.
---------------------------------------------------------------------------
354. Should the Commission proceed to amend Order No. 1000's
findings and mandates as described above, following the issuance of any
final rule in this docket, we propose to allow public utility
transmission providers to propose, pursuant to FPA section 205, new
federal rights of first refusal for incumbent transmission providers,
provided that such rights are conditioned on the incumbent transmission
provider with the federal right of first refusal for such regional
transmission facilities establishing joint ownership of the
transmission facilities consistent with the proposal below. We believe
that this reform will help to ensure just and reasonable Commission-
jurisdictional rates and limit opportunities for undue discrimination
by public utility transmission providers. We preliminarily continue to
find that unconditional federal rights of first refusal for incumbent
transmission providers are unjust and unreasonable, and unduly
discriminatory and preferential.
355. In making this proposal, however, we do not intend to require
the establishment of any particular federal rights of first refusal.
Given the nature of our proposed action, public utility transmission
providers would not be obligated to adopt the conditional federal
rights of first refusal described in this section. Instead, Order No.
1000's findings and mandates would be amended such that joint ownership
conditions may presumptively be found to ensure just and reasonable
Commission-jurisdictional rates and limit opportunities for undue
discrimination by public utility transmission providers, if imposed
upon the exercise of an incumbent transmission provider's federal right
of first refusal for transmission facilities selected in a regional
transmission plan for purposes of cost allocation. We believe that this
approach would permit justified variations from an otherwise one-size-
fits-all federal rights of first refusal policy, and thereby would
allow for regional flexibility, without imposing new federal rights of
first refusal requirements on all public utility transmission
providers. Public utility transmission providers would have the
opportunity in their regular course of business to consider whether
this type of a conditional federal right of first refusal would, if
adopted, help improve their particular regional transmission planning
process or help address potentially misaligned incentives regarding
regional and local transmission facility investment.
356. We also propose to allow public utility transmission providers
that establish conditional federal rights of first refusal as
recognized in any final rule adopted in this proceeding to make other
corresponding adjustments to the timing and procedural requirements of
their competitive transmission development processes that are just and
reasonable and not unduly discriminatory or preferential. More
specifically, to accommodate changes in federal rights of first refusal
provisions regarding certain transmission facilities selected in a
regional transmission plan for purposes of cost allocation, we propose
to permit changes to existing tariff provisions that were adopted to
comply with the following requirements
[[Page 26566]]
of Order No. 1000: The federal rights of first refusal elimination
requirement; \574\ the qualification requirement; \575\ the information
requirement; \576\ and the access to use the regional cost allocation
method(s) requirement.\577\ The degree to which changes to such tariff
provisions will be necessary will depend on the specifics of the future
proposal made by a particular public utility transmission provider. In
allowing these corresponding adjustments, we intend for public utility
transmission providers to provide robust openness and transparency
safeguards regarding the exercise of conditional federal rights of
first refusal, to help ensure just and reasonable Commission-
jurisdictional rates and to limit and detect instances of potential
undue discrimination.\578\
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\574\ The federal right of first refusal elimination requirement
means the requirement that each public utility transmission provider
eliminate provisions in Commission-jurisdictional tariffs and
agreements that establish a federal right of first refusal for an
incumbent transmission provider with respect to transmission
facilities selected in a regional transmission plan for purposes of
cost allocation. See Order No. 1000, 136 FERC ] 61,051 at P 313.
\575\ The qualification requirement means the requirement that
each public utility transmission provider revise its OATT to
demonstrate that the regional transmission planning process in which
it participates has established appropriate qualification criteria
for determining an entity's eligibility to propose a transmission
facility for selection in the regional transmission plan for
purposes of cost allocation, whether that entity is an incumbent
transmission provider or a nonincumbent transmission developer. See
id. P 323.
\576\ The information requirement means the requirement that
each public utility transmission provider identify in its OATT the
information that a prospective transmission developer must submit in
support of a transmission project the developer proposes in the
regional transmission planning process. See id. P 325.
\577\ The access to use the regional cost allocation method(s)
requirement means the requirement that each public utility
transmission provider participate in a regional transmission
planning process that provides that a nonincumbent transmission
developer has an opportunity comparable to that of an incumbent
transmission provider to allocate the cost of a transmission
facility selected in the regional transmission plan for purposes of
cost allocation through a regional cost allocation method or
methods. See id. PP 332, 335.
\578\ See, e.g., PJM Interconnection, L.L.C., 174 FERC ] 61,117
at PP 3-4 (describing the criteria for and process regarding
immediate need reliability projects).
---------------------------------------------------------------------------
357. Also, we envision that conditional federal right of first
refusal proposals would seek to establish federal rights of first
refusal true to their name--a process whereby an incumbent transmission
provider may, at its own election, choose to exercise a right to be
designated to use the regional cost allocation method for a particular
transmission facility or set of transmission facilities within its
retail distribution service territory or footprint that is selected in
a regional transmission plan for purposes of cost allocation,\579\
subject to applicable conditions. Should the incumbent transmission
provider choose not to exercise its right, we envision that a public
utility transmission provider would then proceed to follow its
competitive transmission development process to select a qualified
transmission developer to use the regional transmission cost allocation
method for the selected regional transmission facilities.\580\
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\579\ See S.C. Pub. Serv. Auth., 762 F.3d at 72 & n.6.
\580\ If the competitive transmission development process does
not yield a qualified transmission developer to use the regional
transmission cost allocation method for the selected regional
transmission facilities, and if necessary, the incumbent
transmission provider may be obligated to build those selected
regional transmission facilities. See PJM Interconnection, L.L.C.,
142 FERC ] 61,214, at P 224 (2013) (explaining that Order No. 1000
did not limit ``mechanisms to impose an obligation to build
transmission facilities in a regional transmission plan''); e.g.,
CAISO, CASIO eTariff, Sec. 24.6.4, (Inability to Complete the
Transmission Solution) (2.0.0) (granting CAISO the discretion,
regarding reliability driven transmission solutions an Approved
Project Sponsor is unable to construct, to either ``direct the
Participating TO in whose PTO Service Territory or footprint either
terminus of the transmission solution is located . . . to build the
transmission solution, or the CAISO may open a new solicitation for
Project Sponsors to finance, own, and construct the transmission
solution'').
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2. Conditional Federal Rights of First Refusal for Certain Jointly-
Owned Transmission Facilities
358. We propose to preliminarily find presumptively just and
reasonable and not unduly discriminatory or preferential the
establishment of a federal right of first refusal for transmission
facilities selected in a regional transmission plan for purposes of
cost allocation, conditioned on joint-ownership requirements, as more
fully described in this section. We propose that an incumbent
transmission provider may establish qualifying joint ownership
structures with unaffiliated nonincumbent transmission developers as
defined in Order No. 1000,\581\ or with another unaffiliated entity,
including another incumbent transmission provider, if the joint
ownership structure meets the requirements outlined in this section,
including the requirement that the joint ownership structure offer a
meaningful level of participation and investment in proposed
transmission facilities to the incumbent transmission provider's
unaffiliated partners.\582\ We believe this proposed reform could
address the potentially misaligned incentives for regional transmission
facility development faced by incumbent transmission providers while
still largely ensuring at least some of the potential cost-related
benefits of competitive transmission development processes.
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\581\ See supra P 337.
\582\ See infra PP 365, 371.
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a. Background
359. In Order No. 1000, in response to comments requesting that the
Commission consider joint transmission ownership as a financing and
cost allocation tool, the Commission stated that specific financing
techniques such as joint ownership were beyond the scope of that
proceeding. While the Commission declined to ``specifically address
joint ownership as a cost allocation tool,'' it did note that
transmission developers were ``free to consider joint ownership when
proposing and developing a transmission project.'' \583\ The Commission
also reiterated its belief that ``there are benefits to joint ownership
of transmission facilities, particularly large backbone facilities,
both in terms of increasing opportunities for investment in the
transmission grid, as well as ensuring nondiscriminatory access to the
transmission grid by transmission customers.'' \584\ Since Order No.
1000, joint proposals or joint ownership arrangements between incumbent
transmission providers and nonincumbent transmission developers have
been an option generally available to qualified transmission developers
participating, pursuant to public utility transmission provider
tariffs, in competitive transmission development processes.\585\
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\583\ Order No. 1000, 136 FERC ] 61,051 at P 776.
\584\ Id. (citing Order No. 890, 118 FERC ] 61,119 at P 593).
\585\ See, e.g., CAISO, CASIO eTariff, Sec. 24.5.2 (Project
Sponsor Application and Information Requirements) (6.0.0), Sec.
24.5.2.1 (Opportunity for Collaboration); id. 24.15.1 Transmission
Additions and Upgrades under TCA (0.0.0), section 24.15.1
(referencing ``transmission additions and upgrades [that] are
jointly developed by Participating TOs and non-Participating TOs'');
MISO, FERC Electric Tariff, attach. FF (Transmission Expansion
Planning Protocol) (85.0.0), Sec. VIII.D.4.2. (Joint-Developer
Proposal); PJM, Intra-PJM Tariffs, OA Schedule 6, Sec. 1.5
(Procedure for the Development of the Regional Transmission
Expansion Plan) (28.0.0), Sec. 1.5.6(l) (``Nothing herein shall
prevent any Transmission Owner or other entity designated to
construct, own and/or finance a recommended transmission enhancement
or expansion from agreeing to undertake its responsibilities under
such designation jointly with other Transmission Owners or other
entities.'').
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b. Comments
360. Although the Commission did not specifically ask about
jointly-owned
[[Page 26567]]
transmission facilities in the ANOPR,\586\ some commenters address the
topic of jointly-owned transmission facilities. For example, SDG&E
discusses its partnership with nonincumbent transmission developers to
develop and construct two new transmission lines, known as the Sunrise
Powerlink and Sycamore-Pe[ntilde]asquitos projects.\587\
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\586\ See ANOPR, 176 FERC ] 61,024 at P 37.
\587\ SDG&E Comments at 4-5.
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361. In its comments, TAPS supports joint transmission ownership
arrangements, which TAPS argues have been effective for getting
transmission facilities constructed.\588\ Among other potential
benefits of joint transmission ownership arrangements, TAPS argues that
these arrangements improve coordination by leveraging relationships and
knowledge among the joint-owning parties for transmission siting,
obtaining approval from state-level retail regulators, easing cost
allocation issues by spreading or socializing costs among the joint-
owning parties, spreading risk more evenly, and likely lessening
disputes related to transmission planning and cost allocation that the
Commission may otherwise have to adjudicate.\589\ Joint ownership
arrangements, TAPS explains, can be structured in various ways,
including as an inclusive transmission-only company, or shared-system
arrangement, or other type of joint venture, including structures where
ownership among two or more utilities is held in proportion to each
participant's load ratio share of connected customer load.\590\
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\588\ TAPS Comments at 8 (citing TAPS 2021 White Paper (June 25,
2021), https://www.tapsgroup.org/wp-content/uploads/2021/09/TAPS-Inclusive-Joint-Ownership-White-Paper.pdf (TAPS 2021 White Paper)).
\589\ Id. at 9-11.
\590\ Id. at 8-9 & nn.9-11.
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362. TAPS asserts that while the Commission has previously found
that joint transmission ownership arrangements are beneficial and
encouraged more entities to consider these types of arrangements,\591\
there are few joint transmission ownership arrangements today. TAPS
warns that the Commission's objective of modifying transmission
planning and expansion requirements to accommodate the changing
resource mix, while minimizing costs to consumers, would be thwarted if
costs are unnecessarily increased; that objective may also be thwarted
if needed transmission projects are not timely built because those
projects face greater financial or siting risk without joint ownership,
which may relate to federal rights of first refusal requirements.\592\
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\591\ Id. at 12; TAPS 2021 White Paper at 7-8 (citing in part
Order No. 1000, 136 FERC ] 61,051 at P 776; Promoting Transmission
Inv. Through Pricing Reform, Policy Statement, 77 FR 69754 (Nov. 21,
2012), 141 FERC ] 61,129 (2012)).
\592\ TAPS Comments at 13-15, 52-53.
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363. In order to foster joint transmission ownership arrangements,
TAPS recommends that the Commission make changes to transmission
planning processes, including by permitting public utility transmission
providers to bid out the cost of construction and associated capital
requirements regarding regional and interregional transmission
facilities selected in regional transmission plans, which would be
designed to identify ownership partners among the existing load-serving
entities in the transmission planning region. TAPS recommends that, to
the extent the Commission makes a finding on joint transmission
ownership arrangements, the Commission should structure competitive
bidding processes such that they provide transmission-dependent
utilities in the project's footprint with opportunities to participate
in supplying their fair share of capital for certain projects.\593\
---------------------------------------------------------------------------
\593\ Id. at 13-15.
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364. While TAPS does not explicitly request that the Commission
permit the establishment of a conditional federal right of first
refusal for constructing transmission facilities under certain joint
transmission ownership arrangements, TAPS contends that in general
there is significant interest from willing partners that could work
together with incumbent transmission providers to construct a
transmission facility, and that the structure of competitive
transmission development processes should ``advance[ ] the role of
inclusive joint ownership.'' \594\
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\594\ Id. at 12, 14-15, 52-53.
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c. Proposed Reform
365. We preliminarily find presumptively just and reasonable and
not unduly discriminatory or preferential the establishment of a
federal right of first refusal for transmission facilities selected in
a regional transmission plan for purposes of cost allocation,
conditioned on the incumbent transmission provider with the federal
right of first refusal for such regional transmission facilities
establishing joint ownership of the transmission facilities consistent
with this subsection. We propose that an incumbent transmission
provider may establish qualifying joint ownership with unaffiliated
nonincumbent transmission developers as defined in Order No. 1000,\595\
or another unaffiliated entity, including another incumbent
transmission provider, if otherwise consistent with this subsection.
These potential joint ownership partners could include unaffiliated
public power entities, unaffiliated load-serving entities such as
transmission-dependent municipally-owned utilities or electric
cooperatives, other unaffiliated third parties that do not have (or are
operating outside of) their retail distribution service territory or
footprint, or another unaffiliated entity, including another incumbent
transmission provider.
---------------------------------------------------------------------------
\595\ See supra P 337.
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366. We expect that public utility transmission providers seeking
to adopt this reform will need to include in their tariffs a detailed
process for the exercise of a conditional right of first refusal for
regional transmission facilities that will be jointly owned. Relatedly,
we believe that an incumbent transmission provider's conditional
federal right of first refusal--whether exercised or not regarding any
particular transmission facility--should not significantly delay the
regional transmission planning process, nor should it result in
prolonged uncertainty regarding which transmission facilities will (or,
alternatively, will not) be subject to competitive transmission
development processes.
367. We envision, as an example, the following process for the
exercise of a conditional federal right of first refusal for regional
transmission facilities that will be jointly owned. First, the public
utility transmission providers in a transmission planning region will
identify a regional transmission need (under the sponsorship model) or
identify a regional transmission need and select a transmission
facility in the regional transmission plan for purposes of cost
allocation to meet that need (under the competitive bidding
model).\596\
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\596\ See FERC, Staff Report, 2017 Transmission Metrics, at 8
(Oct. 6, 2017), https://www.ferc.gov/sites/default/files/2020-05/transmission-investment-metrics.pdf (describing the two general
types of competitive transmission development processes).
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368. Second, before public utility transmission providers in each
transmission planning region initiate competitive transmission
development processes, public utility transmission providers in each
transmission planning region will give an opportunity for an incumbent
transmission provider possessing a relevant conditional federal right
of first refusal to indicate its intent to invoke that right and submit
a jointly-owned regional transmission facility
[[Page 26568]]
proposal in partnership with one or more unaffiliated entities.
369. Third, given that the potentially relevant conditional federal
right of first refusal and process for exercising it has been
established in Commission-jurisdictional tariffs and agreements, upon
receipt of a jointly-owned regional transmission facility proposal, the
public utility transmission providers in the transmission planning
region would confirm the parties' rights and responsibilities
associated with the jointly-owned transmission facility proposal and
its conformance with tariff provisions implementing the option proposed
in this subsection. Here, we envision that the parties participating in
the jointly-owned regional transmission facility proposal would have to
demonstrate that their proposal commits the parties to a joint-
ownership arrangement consistent with this subsection and that it meets
the requirements of the applicable regional transmission planning
process as outlined in the public utility transmission providers'
tariffs on file with the Commission. For instance, the parties to a
jointly-owned regional transmission facility proposal would have to
provide sufficient detail to adequately delineate their respective
financial interests and relationship as partners, and to demonstrate
that the parties either individually or jointly meet all other
applicable requirements. Public utility transmission providers in the
transmission planning region should, at the conclusion of this step in
the process, notify stakeholders and the public (e.g., through posting
on a public website) that either the jointly-owned regional
transmission facility proposal conforms with tariff provisions
implementing the conditional right of first refusal and, thus, a
relevant conditional right of first refusal has been exercised, or,
alternatively, that the public utility transmission providers in the
transmission planning region will proceed to initiate a competitive
transmission development process given that the jointly-owned regional
transmission facility proposal does not conform with such tariff
provisions. If a jointly-owned regional transmission facility proposal
is not or cannot be confirmed as conforming with the public utility
transmission provider's Commission-jurisdictional tariffs and
agreements that relate to the incumbent transmission provider's
conditional federal right of first refusal, or otherwise does not
qualify for selection in the regional transmission plan for purposes of
cost allocation, public utility transmission providers in the
transmission planning region shall proceed to follow their otherwise
applicable competitive transmission development process.
370. Finally, public utility transmission providers in the
transmission planning region would proceed to evaluate the jointly-
owned regional transmission facility proposal without going through the
competitive transmission development process. In a transmission
planning region with a sponsorship model, this means that public
utility transmission providers would evaluate in their regional
transmission planning process the jointly-owned regional transmission
facility proposal for potential selection in the regional transmission
plan for purposes of cost allocation without soliciting any sponsored
transmission facility proposals. In a transmission planning region with
a competitive bidding model, where the transmission facility has
already been selected in the regional transmission plan for purposes of
cost allocation, this means that public utility transmission providers
would evaluate the jointly-owned regional transmission facility
proposal through the regional transmission planning process without
soliciting other proposals to develop the already-selected regional
transmission facility.
371. As part of this proposal and in general, we believe that the
benefits of joint ownership would not be achieved if an incumbent
transmission provider partnered with an affiliated entity to submit a
proposal, or if that incumbent transmission provider limited the input
or ownership share of its intended partners to less than a meaningful
level. Instead, we intend for incumbent transmission providers pursuing
joint-ownership proposals to offer unaffiliated entities a reasonable
chance at meaningful participation and investment in the proposed
regional transmission facility. Therefore, we propose that to qualify
for the presumption advanced in this proposal, incumbent transmission
providers with a conditional federal right of first refusal would not
be allowed to partner with affiliated entities, and would not be
allowed to structure joint-ownership arrangements such that
unaffiliated entities were offered less than a meaningful level of
participation and investment in the proposed regional transmission
facility. While we do not propose to limit potentially qualifying joint
ownership structures to those already employed in the industry, we note
that a meaningful level of participation and investment in proposed
facilities has been or could be offered to unaffiliated entities under
various types of joint ownership structures that have been established
or proposed.\597\
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\597\ See, e.g., supra PP 360-364 (discussing examples of joint
ownership structures employed or identified by ANOPR commenters,
including those based on load-ratio share); see also infra note 604
and associated text (describing the inclusive transmission-only
company or shared-system agreement concepts).
---------------------------------------------------------------------------
372. We believe that a conditional federal right of first refusal
for jointly-owned transmission facilities as described in this
subsection may help facilitate openness in the regional transmission
planning process, decrease potential financial and siting risks, and
increase the likelihood that transmission facilities selected in a
regional transmission plan for purposes of cost allocation are
successfully and cost-effectively developed. First, if a conditional
federal right of first refusal was available for jointly-owned regional
transmission facilities, the greater development certainty that a
federal right of first refusal could provide for the development of a
transmission facility could help incentivize interested parties
(including incumbent transmission providers and potential unaffiliated
partners) to consider a jointly-owned transmission facility and
leverage the combined transmission development strengths of the
parties, potentially including the parties' knowledge of siting and
permitting processes or other strengths. Joint ownership arrangements
could, consistent with Commission precedent, help increase
opportunities for investment in the transmission system, as well as
ensure not unduly discriminatory access to the transmission system by
transmission customers.\598\ Indeed, we believe that jointly-owned
regional transmission facilities, which may involve the participation
of multiple nearby load-serving entities and potentially those that are
public power entities, may increase collaboration within the regional
transmission planning process consistent with Order No. 679.\599\
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\598\ See Order No. 1000, 136 FERC ] 61,051 at P 776; see also
Order No. 890, 118 FERC ] 61,119 at PP 593-594.
\599\ See Promoting Transmission Inv. through Pricing Reform,
Order No. 679, 71 FR 43294 (July 31, 2006), 116 FERC ] 61,057, at PP
354, 355 (2006).
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373. Second, given the nature of a joint-ownership arrangement,
individual parties working together may achieve efficiencies in
addressing their collective transmission needs and, therefore, achieve
lower overall costs compared to developing transmission facilities to
resolve more individualized needs in a more piecemeal manner as is the
case today. Relatedly, the entities in
[[Page 26569]]
a joint ownership arrangement might bring different strengths to the
process of developing a regional transmission facility, potentially
reducing the costs for development or leveraging their expertise to
design a more efficient or cost-effective transmission facility than
the partners would have designed separately, thus benefiting customers.
We note, for example, that while SDG&E's Sunrise Powerlink and
Sycamore-Pe[ntilde]asquitos projects addressed multiple reliability
needs for CAISO's transmission system, these transmission facilities
also enabled the transmission facility's other joint owner the option
to lease a portion transfer capability of the transmission
facility.\600\ In short, we believe that this joint ownership proposal
may help promote innovative transmission ownership structures for
transmission development, as well as innovative regional transmission
facilities that more efficiently or cost-effectively address regional
transmission needs, which in turn would help ensure just and reasonable
Commission-jurisdictional rates.
---------------------------------------------------------------------------
\600\ See SDG&E Comments at 4-5; see also California State Water
Project Reply Comments at 12 n.44 (discussing the Sycamore-
Pe[ntilde]asquitos Project (citations omitted)); Citizens Sycamore-
Penasquitos Transmission LLC, 164 FERC ] 61,149, at PP 5-6 (2018)
(same); Citizens Sunrise Transmission LLC, 138 FERC ] 61,129, at PP
3-10 (2012) (discussing the Sunrise Powerlink Project); Citizens
Energy Corp., 129 FERC ] 61,242, at P 5 (2009) (same).
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374. Third, jointly-owned regional transmission facilities, by
spreading the risks and responsibilities of developing transmission
facilities among multiple parties, may act as a useful hedging tool
against expected longer-term, future transmission system development
costs by allowing the parties to offset near-term expenditures on
constructing transmission facilities necessary to maintain reliability.
375. Thus, we preliminarily find that a conditional federal right
of first refusal for regional transmission facilities that will be
jointly owned, as described in this subsection, could address the
potentially misaligned incentives for transmission facility development
faced by incumbent transmission providers while still largely ensuring
the potential cost-related benefits of competitive transmission
development processes. Given that jointly-owned transmission facilities
appear to offer many benefits, we preliminarily find that customers may
benefit from such a conditional federal right of first refusal through
the selection of more efficient or cost-effective transmission
facilities in the regional transmission plan for purposes of cost
allocation. Indeed, we believe that joint ownership arrangements may
help achieve several of the goals that competitive transmission
development processes are intended to serve today.\601\
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\601\ See supra notes 538 to 541 and associated text.
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376. In particular, we believe that this proposal would offer
nonincumbent transmission developers and other potential unaffiliated
entities the opportunity to partner with an incumbent transmission
provider and thereby achieve market entry and greater diversity of
participation and perspectives in transmission ownership. Moreover, to
exercise their conditional federal right of first refusal under this
proposed reform, incumbent transmission providers would be required to
share ownership and investment opportunities with other partners,
potentially including other transmission developers, limiting an
incumbent transmission provider's ability to use federal rights of
first refusal to serve only its own economic interests.
377. As described above, we are concerned that today's processes
place unintended emphasis on the development of local transmission
facilities or other transmission facilities not subject to competitive
transmission development processes, potentially at the expense of
regional transmission facility development, given trends observed since
the issuance of Order No. 1000.\602\ We believe that this joint
ownership-focused conditional federal right of first refusal proposal
may help address that issue while advancing the goals of Order No.
1000.
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\602\ See supra note 550; see also WIRES Comments at 11-12, 16
(asserting that the ``introduction of competition . . . has not
lived up to expectations'' and addressing the Commission's
articulated concerns about the possibility that ``current policies
and processes are not appropriately incentivizing the development
and construction of larger regional facilities'').
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378. We seek comment on the requirements proposed in this section
of the NOPR. In particular, we request that commenters address how this
proposed conditional right of first refusal aligns with or advances the
goals of Order No. 1000's reforms,\603\ or otherwise ensures just and
reasonable Commission-jurisdictional rates and limits opportunities for
undue discrimination by public utility transmission providers.
---------------------------------------------------------------------------
\603\ See supra notes 538 to 543 and associated text.
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379. We also seek comment regarding the administrability of and
implementation challenges associated with the establishment and
exercise of joint ownership-focused conditional federal rights of first
refusal, including what specific requirements the Commission should
impose on joint-ownership agreements or on the process of formulating
them. We also seek comment on whether limiting this option to proposals
that form or expand an inclusive transmission-only company or shared-
system arrangement is necessary to ensure just and reasonable
Commission-jurisdictional rates and limited opportunities for undue
discrimination by public utility transmission providers.\604\ We seek
comment as well regarding whether all transmission-dependent utilities
or load-serving entities in a particular public utility transmission
provider's service territory where a proposed regional transmission
facility would be located should be given the opportunity to
participate in a joint ownership arrangement that allows those
transmission-dependent utilities or load-serving entities to supply up
to their fair share (e.g., load-ratio share) of capital for certain
regional transmission facilities.\605\
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\604\ In its comments and related white paper, TAPS cites
Vermont Transco LLC and American Transmission Company LLC as
inclusive transmission-only companies where instead of retaining
direct ownership of separate transmission facilities, investor-owned
and public power or cooperative utilities alike own membership units
or equity stakes in one jointly-owned transmission company. See TAPS
Comments at 8 nn.8-9; see also TAPS 2021 White Paper at 2. As TAPS
further explains, under ``shared-system arrangements, . . .
transmission facilities of two or more utilities are planned and
operated jointly, as a single system, pursuant to a long-term
agreement. Ownership is generally in proportion to each
participant's load ratio share of connected customer load, which can
be achieved in a variety of ways, e.g., owning an undivided share of
the entire joint system; owning discrete facilities; owning new
facilities.'' See TAPS Comments at 8 n.10.
\605\ See TAPS Comments at 14-15.
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380. We also seek comment on the standards, such as ownership share
percentages or load-ratio share offer requirements, that should govern
whether particular joint ownership arrangements qualify for the
presumption identified here because such standards would help achieve
the benefits described above. Accordingly, we seek comment on whether
any additional requirements beyond those mentioned above would be
necessary to prevent the exertion of undue influence over the
transmission development process or joint ownership arrangement by any
project entity (including an incumbent transmission provider), avoid
greater risks of project cancellation or abandonment, or otherwise
protect customer interests.
381. Relatedly, we seek comment on eligibility and participation
criteria related to jointly-owned transmission facilities and partners
that should be permitted to qualify for the presumption proposed in
this section, and any
[[Page 26570]]
transparency, informational, or screening processes that may be
required.\606\ While transmission developers already must satisfy
qualification criteria to be eligible to use the regional transmission
cost allocation method for regional transmission facilities selected in
a regional transmission plan for purposes of cost allocation, we seek
comment on whether this proposal necessitates specialized eligibility
criteria or particular joint ownership partner selection processes to
ensure just and reasonable Commission-jurisdictional rates and limit
opportunities for undue discrimination by public utility transmission
providers.\607\
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\606\ For example, MISO's tariff requires information regarding
the responsibilities and liabilities of each party to a joint-
developer transmission project proposal. See MISO, FERC Electric
Tariff, attach. FF (Transmission Expansion Planning Protocol)
(85.0.0), Sec. VIII.D.4.2. (Joint-Developer Proposal); id. Sec.
VIII.D.5.1.1. (Identification of RFP Respondents).
\607\ For example, we note that SDG&E's Sycamore-
Pe[ntilde]asquitos Project was developed in partnership with
Citizens Energy and required both SDG&E and Citizens Energy to enter
into a Development, Coordination, and Option Agreement to provide
for their rights, responsibilities, and future options related to
the Sycamore-Pe[ntilde]asquitos Project. See Citizens Sycamore-
Penasquitos Transmission LLC, 164 FERC ] 61,149 at P 7.
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382. Finally, we seek comment regarding whether the Commission
should pursue broader reform to its rules and regulations governing
federal rights of first refusal. In particular, we seek comment on
whether the Commission should consider fully restoring the federal
rights of first refusal eliminated in Order No. 1000 and, if so, how
the Commission should go about doing so. We recognize that pursuing
reforms focused on joint ownership alone may not fully address the
potential issues that commenters have raised regarding competitive
transmission development processes. Therefore, we seek comment both on
the joint ownership-focused conditional federal rights of first refusal
reform proposed above and on whether more significant changes to Order
No. 1000's federal right of first refusal elimination mandate would
help ensure just and reasonable Commission-jurisdictional rates while
limiting opportunities for undue discrimination by public utility
transmission providers.
VIII. Enhanced Transparency of Local Transmission Planning Inputs in
the Regional Transmission Planning Process and Identifying Potential
Opportunities to Right-Size Replacement Transmission Facilities
A. Background
383. Generally, the transmission facilities that public utility
transmission providers include in their individual local transmission
plans are incorporated into regional transmission plans as inputs, with
minimal opportunity for stakeholder review in the regional transmission
planning process. That is because the analysis of local transmission
plans in the regional transmission planning process is limited mainly
to a reliability analysis to ensure that local transmission plans do
not negatively affect the reliability of the regional transmission
system.
384. As noted earlier, the Commission in Order No. 1000 defined a
local transmission facility as a transmission facility located solely
within a public utility transmission provider's retail distribution
service territory or footprint that is not selected in the regional
transmission plan for purposes of cost allocation.\608\ The Commission
did not require that the transmission facilities in a public utility
transmission provider's local transmission plan be subject to approval
at the regional or interregional level, unless that public utility
transmission provider seeks to have any of those facilities selected as
regional transmission facilities in the regional transmission plan for
purposes of cost allocation.\609\
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\608\ Supra P 17.
\609\ Order No. 1000-A, 139 FERC ] 61,132 at P 190.
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385. As existing transmission infrastructure ages, transmission
owners must assess the state of their transmission systems and the
condition of their transmission assets to determine whether and, if so,
how to replace existing transmission facilities that have reached the
end of their useful lives. The Commission has found that a replacement
of an existing transmission facility that does not incrementally
increase that facility's capacity is not subject to the transmission
planning requirements of Order No. 890 or Order No. 1000 because an in-
kind replacement \610\ of an existing transmission facility does not
represent an expansion or enhancement of the transmission system.\611\
Therefore, under this precedent there is no requirement that public
utility transmission providers provide information about potential in-
kind replacements of existing transmission facilities in either their
local or regional transmission planning processes. Some RTO/ISO
transmission planning regions may assess a planned in-kind replacement
of an existing transmission facility to ensure that it does not cause
adverse reliability impacts,\612\ but regional transmission planning
processes generally do not evaluate whether the planned in-kind
replacement transmission facility could be modified to more efficiently
or cost-effectively address regional transmission needs. However, we
note that some public utility transmission providers do provide
stakeholders with reports detailing the justification and quantity of
replacement transmission
[[Page 26571]]
facilities.\613\ Further, as discussed above, some public utility
transmission providers do assess the benefits of deferred or avoided
infrastructure, including asset replacements that would otherwise be
needed.\614\
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\610\ For the purposes of this NOPR, we define an ``in-kind
replacement'' as a new transmission facility that does not expand
the capacity of the existing transmission facility that is being
replaced unless the incidental increase in transmission capacity
occurs as a function of advancements in technology of the replaced
equipment and is thus not reasonably severable from that
replacement. (e.g., a 345 kV transmission facility that is replaced
with a 345 kV transmission facility).
\611\ See S. Cal. Edison Co., 164 FERC ] 61,160, at P 31 (2018)
(``While Order No. 890 does not explicitly define the scope of
`transmission planning,' the Commission adopted the transmission
planning requirements in Order No. 890 to remedy opportunities for
undue discrimination in expansion of the transmission grid.''
(citing Order No. 890, 118 FERC ] 61,119 at PP 57-58, 421-422));
Cal. Pub. Utils. Comm'n v. Pac. Gas & Elec. Co., 164 FERC ] 61,161,
at P 68 (2018); PJM Interconnection, L.L.C., 172 FERC ] 61,136, at
PP 12, 89, order on reh'g, 173 FERC ] 61,225 (2020); PJM
Interconnection, L.L.C., 173 FERC ] 61,242, at P 54 (2020), order on
reh'g, 176 FERC ] 61,053 (2021). The Commission has further
clarified that there may be instances in which a transmission
owner's replacement of an existing transmission facility may result
in an incidental increase in transmission capacity that is not
reasonably severable from that replacement, e.g., that occurs as a
function of advancements in technology of the replaced equipment. In
such cases, the Commission stated, the incidental increase in
transmission capacity would not render the in-kind replacement of an
existing transmission facility a transmission expansion that is
subject to the transmission planning requirements of Order No. 890.
Cal. Pub. Utils. Comm'n v. Pac. Gas & Elec. Co., 164 FERC ] 61,161
at P 68.
\612\ See, e.g., PJM Manual 14B: PJM Regional Transmission
Planning Process at 19-20 (``It should also be noted that prior to
integrating a Supplemental Project into the RTEP base case PJM
performs a `do no harm study' to evaluate whether a proposed
Supplemental Project will adversely impact the reliability of the
Transmission System as represented in the planning models used in
all other PJM reliability planning studies. If as a result of the do
no harm study, system upgrades are required, such upgrades will be
considered part of the Supplemental Project and are the
responsibility of the Transmission Owner sponsoring the Supplemental
Project.''); see also MISO Business Practice Manual, Transmission
Planning, Manual No. 020 at 22-23 (``In its role as the Planning
Coordinator (PC), MISO will evaluate all bottom-up projects
submitted by Transmission Owner(s) and validate that the projects
represent prudent solutions to one or more identified Transmission
Issues.'').
\613\ See PJM Interconnection, L.L.C., 172 FERC ] 61,136 at 21.
\614\ Supra Table 1--Long-Term Regional Transmission Benefits.
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386. The Commission in Order 1000-A clarified that it was not
eliminating the right of an owner of a transmission facility to improve
its own existing transmission facility.\615\ Order No. 1000 also allows
an incumbent transmission provider to meet its reliability needs or
service obligations by choosing to build new transmission facilities
that are located solely within its retail distribution service
territory or footprint and that are not selected in a regional
transmission plan for purposes of cost allocation.\616\ Such
transmission facilities' costs are allocated to the retail distribution
service territory or footprint in which the facility is located through
the incumbent transmission provider's individual transmission service
rates in its OATT or though the zonal rates in an RTO/ISO OATT.
---------------------------------------------------------------------------
\615\ Order No. 1000-A, 139 FERC ] 61,132 at P 426.
\616\ Id. PP 366, 379, 425, 428; Order No. 1000, 136 FERC ]
61,051 at P 262; Order No. 1000-A, 139 FERC ] 61,132 at PP 366, 379,
425, 428.
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B. ANOPR
387. In the ANOPR, the Commission sought comment on whether
individual incumbent transmission provider practices regarding
replacement of existing transmission facilities sufficiently align with
the directive to ensure evaluation of alternative transmission
solutions and whether these practices sufficiently consider the more
efficient or cost-effective ways to serve future needs.\617\
Additionally, the Commission sought comment on whether sufficient
transparency exists around replacement decisions made by transmission
providers to allow an assessment of these decisions in the regional
transmission planning process.
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\617\ ANOPR, 176 FERC ] 61,024 at P 171.
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388. In the ANOPR, the Commission also sought comment on local
transmission planning to better understand how the reforms of the
federal right of first refusal in Order No. 1000 have shaped the type
and characteristics of transmission facilities developed through
regional and local transmission planning processes, such as a relative
increase in investment in local transmission facilities or the
diversity of projects resulting from competitive regional transmission
planning processes.\618\
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\618\ ANOPR, 176 FERC ] 61,024 at P 37.
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389. The Commission requested comment on whether the current
regional and local transmission planning processes provide sufficient
transparency for stakeholders to understand how best to obtain
information and fully participate in the various processes.\619\ The
Commission, for example, theorized that in non-RTO/ISO regions,
individual transmission owning members' local transmission planning
processes may not be as well-publicized or follow as well-understood
processes to provide information as in RTO/ISO regions. Based on this
example, the Commission inquired whether customers and other
stakeholders may benefit from enhanced oversight of local transmission
planning.
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\619\ Id. P 162.
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C. Comments
390. Numerous commenters state that the vast majority of investment
for transmission facilities in recent years has increasingly been
focused on local level transmission facilities (typically less than
100-250 kV), and in replacing existing transmission facilities.\620\
---------------------------------------------------------------------------
\620\ ACORE Comments at 19-23; AEE Comments at 41-43; ACPA and
ESA Comments at 30; American Municipal Power Comments at 22-24; APPA
Comments at 20; California Commission Comments at 31-37; Union of
Concerned Scientists Comments at 24-31; Harvard ELI Comments at 20-
21; LS Power Oct. 12 Comments at 36-37; Michigan Commission Comments
at 8-9; NARUC Comments at 55-56; New Jersey Commission Comments at
3-7; Pennsylvania Commission Comments at 16-17; Policy Integrity
Comments at 16.
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391. Several commenters generally agree that the process for
replacing aging transmission facilities needs additional improvements
related to transparency and to increase the potential that multiple
transmission system needs are addressed.\621\ The California Commission
argues that because the decision to order replacement transmission
facilities is delegated to incumbent transmission owners, there is no
process to evaluate whether replacement transmission facilities could
be a ``like-for-like'' replacement or whether the replacement
transmission facility may be upgraded via a new design or
capacity.\622\ NARUC argues that the Commission should require public
utility transmission providers to apply Order No. 890 transparency
principles to replacement transmission facilities to guard against
incumbent public utility transmission providers' incentive to
overinvest in replacement transmission facilities.\623\ The New Jersey
Commission asserts that by evaluating replacement transmission
facilities through the regional transmission planning process, a
potentially broader transmission solution may be identified thus
obviating the need for a smaller-scope replacement transmission
facility.\624\
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\621\ E.g., District of Columbia's Office of the People's
Counsel Comments at 11-12; EDF Comments at 12.
\622\ California Commission Comments at 17-18.
\623\ NARUC Comments at 15, 48-29.
\624\ New Jersey Commission Comments at 12-13.
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392. ACEG notes that much of the nation's transmission facilities
are over 50 years old and that the lack of a broader view of
transmission planning in terms of replacement of existing, aging
transmission facilities, coupled with a changing generation mix, will
lead to a suboptimal transmission infrastructure network.\625\
Eversource argues that, going forward, the Commission should encourage
flexibility by breaking down transmission planning silos so that an
existing or planned transmission facility can be ``upsized'' to address
multiple system needs like transmission facility conditions while also
anticipating clean energy goals.\626\ LS Power argues that the
Commission should require NERC to develop a new requirement that
transmission providers must give notice when an existing transmission
facility has reached the end of its useful life.\627\ PIOs explain that
the routine of in-kind replacement of aging transmission facilities
misses opportunities for better utilizing existing rights-of-way so as
to meet multiple transmission system needs, which increases costs and
inefficiencies.\628\
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\625\ ACEG Jan. 2021 Planning Report at 18-24.
\626\ Eversource Comments at 10.
\627\ LS Power Oct. 12 Comments at 43-44.
\628\ PIOs Comments at 50 (citing Brattle-Grid Strategies Oct.
2021 Report at 3).
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393. Likewise, many commenters argue that the current relationship
between local and regional transmission planning processes must be
reformed. Some consumer groups, state commissions, market monitors, and
renewable energy developers and organizations argue that the local
transmission planning process is broken.\629\ These entities argue that
the local transmission planning process lacks transparency and
oversight and is inappropriately influenced by incumbent transmission
owners. To correct these flaws, these commenters
[[Page 26572]]
are in favor of lowering voltage thresholds for regional transmission
planning processes, such that more transmission facilities would be
planned through that process rather than local transmission planning
processes.\630\ Some of those commenters further urge the Commission to
require transmission owners and providers to provide information and
metrics about their local systems to the transmission planning process,
and to do so within a timeframe that allows opportunity for real
engagement with stakeholders, because without such a requirement,
transmission owners and providers may be inhibiting the sharing of
information relevant to the regional transmission planning
processes.\631\
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\629\ ACEG Comments at 4-6 (citing Brattle Report at 25); AEE
Comments at 41-49; Union of Concerned Scientists Comments at 24-31;
Eversource Comments at 15-18; New Jersey Commission Comments at 4-6;
LS Power Oct. 12 Comments at 49-62; PJM Market Monitor Comments at
9., Harvard ELI Reply Comments at 12-16.
\630\ California Commission Comments at 39-43; Competition
Coalition Comments at 16; LS Power Oct. 12 Comments at 49-53.
\631\ See e.g., Union of Concerned Scientists Comments at 24-31;
see also Environmental Advocates Comments at 22; Northwest and
Intermountain Comments at 49.
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394. The PJM Market Monitor recommends that PJM should clearly
define the need for local transmission projects within the regional
transmission planning process and that there should be a transparent,
robust, and clearly defined mechanism to permit competition to build
the project.\632\ Some commenters go so far as to argue that there
should be no separation between local and regional transmission
planning processes at all.\633\
---------------------------------------------------------------------------
\632\ PJM Market Monitor Comments at 9.
\633\ American Municipal Power Comments at 32; City of New York
Comments at 20-21; LS Power Oct. 12 Comments at 61-62; New Jersey
Commission Comments at 11-13.
---------------------------------------------------------------------------
395. Other commenters identify the potential for less significant
changes. AEP recommends that, to the extent the Commission reforms
local transmission planning processes by increasing transparency and
oversight, the Commission apply the practices and principles of PJM's
Attachment M-3 process for Supplemental Projects across all other
regions, including non-RTO/ISO regions.\634\
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\634\ AEP Comments at 43-44 (citing PJM Interconnection, L.L.C.,
172 FERC ] 61,136 (2020)). Briefly, PJM's Attachment M-3 process for
Supplemental Projects refers to the additional transparency and
stakeholder input rules around transmission facilities that are not
eligible for selection in the regional transmission plan for
purposes of cost allocation but, though classified as local
transmission facilities, nonetheless impact the identification and
selection of regional transmission facilities.
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396. Alternatively, some commenters contend that existing processes
are adequate. Some commenters argue that existing processes adequately
address replacements of aging transmission facilities. CAISO notes
that, while only participating transmission owners oversee replacement
transmission facilities that do not expand the capacity of transmission
facilities, CAISO continues to evaluate and approve transmission
facilities that do expand the transmission system.\635\ MISO TOs assert
that replacement transmission facilities are evaluated through the MISO
regional transmission planning process already and that MISO is
obligated to seek combining replacement transmission facilities with
other transmission facility projects where it is efficient and cost-
effective to do so.\636\ PJM TOs note that they provide PJM with a list
of candidates for replacement transmission facilities so that PJM can
determine if the replacement transmission project may also address a
larger, regional need.\637\
---------------------------------------------------------------------------
\635\ CAISO Comments at 55-56.
\636\ MISO TOs Comments at 21-22.
\637\ PJM TOs Comments at 13-14.
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397. Additionally, some commenters argue that existing processes
provide for an appropriate level of coordination between regional and
local planning. The Alabama Commission, Duke, Southern, the Louisiana
Commission, and the Ohio Commission,\638\ assert jurisdictional
arguments in opposition to enhanced or expanded local transmission
planning processes. These commenters argue that the Commission should
not intervene in retail activities that are subject to state-level
regulatory bodies.
---------------------------------------------------------------------------
\638\ Alabama Commission Comments at 2; Duke Comments at 2-4;
Southern Comments at 22-33; Louisiana Commission Comments at 4-9;
Ohio Commission Comments at 1-6.
---------------------------------------------------------------------------
D. Need for Reform
398. We are concerned that local transmission planning processes
may lack adequate provisions for transparency and meaningful input from
stakeholders, and that regional transmission planning processes may not
adequately coordinate with local transmission planning processes.\639\
In Order No. 890, the Commission required that public utility
transmission providers' local transmission planning processes comply
with nine transmission planning principles, including coordination,
openness, transparency, and information exchange.\640\ The Commission
further explained that to satisfy the coordination principle, public
utility transmission providers must facilitate the timely and
meaningful input and participation of customers in the development of
transmission plans and, more specifically, that ``customers must be
included at the early stages of the development of the transmission
plan and not merely given an opportunity to comment on transmission
plans that were developed in the first instance without their input.''
\641\ At times, the Commission has found it necessary to review local
transmission planning processes to ensure stakeholders' opportunity to
engage in them is meaningful.\642\ However, implementation of these
principles in local transmission planning processes appears to remain
uneven, as commenters from regions across the country raise concerns
about the transparency of and the opportunity for real engagement in
various aspects of local transmission planning processes and their
interaction with regional transmission planning processes.\643\ We are
concerned that the lack of minimal standards or specified procedures to
implement these principles may contribute to inadequate transparency
and opportunities for stakeholders to engage in local transmission
planning processes. In addition, we believe that reforms to better
ensure more consistent implementation of these principles may be timely
and important in light of the significant investments in transmission
that now occur through local transmission planning processes.\644\
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\639\ See Order No. 1000, 136 FERC ] 61,051 at P 148 (providing
that regional planning processes should identify ``alternative
transmission solutions that might meet the needs of the transmission
planning region more efficiently or cost-effectively than solutions
identified by individual utility transmission providers in their
local transmission planning process'').
\640\ Order No. 890, 118 FERC ] 61,119 at PP 418-601.
\641\ Id. P 454.
\642\ See, e.g., Monongahela Power Co., 156 FERC ] 61,134
(2016).
\643\ NARUC Comments at 14 (stating current planning processes
may not be sufficiently transparent ``in every region'');
Massachusetts Attorney General Comments at 11 (stating it requires
``herculean'' efforts to review transmission project proposals);
Resale Iowa Comments at 7 (claiming ``[c]ustomers and other third
parties have little or no input into alternative evaluation and
project selection of these local projects''); Northwest and
Intermountain Comments at 6 (stating ``local utilities' transmission
plans are incorporated into regional transmission planning processes
as inputs with little opportunity for stakeholder comment'').
\644\ See supra P 40; note 63.
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399. In addition, we are concerned that, given the age of the
nation's transmission infrastructure, many incumbent transmission
providers are replacing aging transmission infrastructure as it reaches
the end of its useful life without evaluating whether those replacement
transmission facilities could be modified (i.e., right sized) to more
efficiently or cost-effectively address regional transmission needs,
and, more generally, that public utility transmission providers
developing
[[Page 26573]]
regional transmission plans may lack the information necessary to
identify the benefits regional transmission facilities may provide in
deferring or eliminating the need for in-kind replacements.\645\
Specifically, as described in the background section, in-kind
replacements of existing transmission facilities are managed by
individual incumbent transmission providers according to their company
practices; there is no requirement that public utility transmission
providers plan these in-kind replacement transmission facilities
through an Order No. 890-compliant transmission planning process.\646\
While a transmission provider may be able to meet its needs associated
with an aging asset through an in-kind replacement, there may be
circumstances under which ``right-sizing'' the planned transmission
replacement would result in a more efficient or cost-effective
transmission facility to meet both the need for the transmission
provider to replace the existing transmission facility and transmission
needs identified through Long-Term Regional Transmission Planning.
Because in-kind replacement of existing transmission facilities is not
subject to any transmission planning process, we are concerned that,
absent reform, there may be a lack of coordination between regional
transmission planning processes and in-kind replacement of existing
transmission facilities to identify whether these replacement
transmission facilities could be modified to more efficiently or cost-
effectively address transmission needs identified through Long-Term
Regional Transmission Planning. This lack of coordination may result in
a regional transmission planning process that fails to identify
opportunities to right size planned in-kind replacement transmission
facilities and may result in the development of duplicative or
unnecessary transmission facilities that increase costs to consumers
and render Commission-jurisdictional rates unjust and unreasonable.
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\645\ For example, we note a recent PJM analysis estimates that
roughly two-thirds of all PJM transmission system assets are more
than 40 years old, with some transmission facilities approaching 90
years old. See PJM Interconnection, L.L.C., The Benefits of the PJM
Transmission System at 5 (April 16, 2019), https://www.pjm.com/-/media/library/reports-notices/special-reports/2019/the-benefits-of-the-pjm-transmission-system.pdf.https://www.pjm.com/-/media/library/reports-notices/special-reports/2019/the-benefits-of-the-pjm-transmission-system.pdf. Moreover, AEP estimates that approximately
30 percent of all its transmission assets will need to be replaced
over the next ten10 years. See AEP, Wolfe Utilities, Midstream, &
Clean Energy Conference, at 40 (Sept. 30, 2021), https://www.aep.com/Assets/docs/investors/eventspresentationsandwebcasts/WolfeConferencePresentation093021.pdf.https://www.aep.com/Assets/docs/investors/eventspresentationsandwebcasts/WolfeConferencePresentation093021.pdf.
\646\ S. Cal. Edison Co., 164 FERC ] 61,160 at P 33; Cal. Pub.
Utils. Comm'n v. Pac. Gas & Elec. Co., 164 FERC ] 61,161 at P 68;
PJM Interconnection, L.L.C., 172 FERC ] 61,136 at PP 12, 89; PJM
Interconnection, L.L.C., 173 FERC ] 61,242 at P 54.
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E. Proposed Reform
400. We propose to require that public utility transmission
providers in each transmission planning region revise the regional
transmission planning process in their OATTs with additional provisions
to enhance transparency of: (1) The criteria, models, and assumptions
that they use in their local transmission planning process, (2) the
local transmission needs that they identify through that process, and
(3) the potential local or regional transmission facilities that they
will evaluate to address those local transmission needs. Under this
proposed reform, public utility transmission providers would be
required to establish an iterative process that would ensure that
stakeholders have meaningful opportunities to participate and provide
feedback on local transmission planning throughout the regional
transmission planning process. Leveraging the existing stakeholder
processes for regional transmission planning, we propose to require
that the regional transmission planning process include at least three
stakeholder meetings concerning the local transmission planning process
of each public utility transmission provider that is a member of the
transmission planning region before each public utility transmission
provider's local transmission plan can be incorporated into the
transmission planning region's planning models, as described further
below.
401. Specifically, prior to the submission of local transmission
planning information to the transmission planning region for inclusion
in the regional transmission planning process, public utility
transmission providers in each transmission planning region would be
required to convene, collectively, as part of the regional transmission
planning process, a stakeholder meeting to review the criteria,
assumptions, and models related to each public utility transmission
provider's local transmission planning (Assumptions Meeting). Next, no
fewer than 25 calendar days after the Assumptions Meeting, public
utility transmission providers that are members of the transmission
planning region would be required to convene, collectively, as part of
the regional transmission planning process, a stakeholder meeting to
review identified reliability criteria violations and other
transmission needs that drive the need for local transmission
facilities (Needs Meeting). Finally, no fewer than 25 calendar days
after the Needs Meeting, public utility transmission providers that are
members of the transmission planning region would be required to
convene, collectively, as part of the regional transmission planning
process, a stakeholder meeting to review potential solutions to those
reliability criteria violations and other transmission needs (Solutions
Meeting). Additionally, we propose to require that all materials for
stakeholder review during these three meetings be publicly posted and
that stakeholders have opportunities before and after each meeting to
submit comments.
402. We preliminarily find that these proposed requirements will
result in needed additional transparency into local transmission
planning processes, which inform the regional transmission planning
process in a transmission planning region. We believe that these
proposed requirements are needed to ensure just and reasonable
Commission-jurisdictional rates because the information provided will
better facilitate the identification of regional transmission
facilities that may be more efficient or cost-effective than proposed
local transmission facilities through the regional transmission
planning process. We also believe that these proposed requirements are
needed to ensure just and reasonable and not unduly discriminatory or
preferential Commission-jurisdictional rates because the information
provided will enable customers and other stakeholders alike to evaluate
or replicate the findings of public utility transmission providers so
as to reduce after-the-fact disputes regarding whether local
transmission planning has been conducted in an unjust and unreasonable
or unduly discriminatory or preferential fashion.\647\
---------------------------------------------------------------------------
\647\ Order No. 890, 118 FERC ] 61,119 at P 471.
---------------------------------------------------------------------------
403. We also propose to require that, as part of each Long-Term
Regional Transmission Planning cycle, public utility transmission
providers in each transmission planning region evaluate whether
transmission facilities operating at or above 230 kV that an individual
public utility transmission provider that owns the transmission
facility anticipates replacing in-kind with a new transmission facility
during the next 10 years can be ``right-sized'' to more efficiently or
cost-effectively address regional transmission needs
[[Page 26574]]
identified in Long-Term Regional Transmission Planning. By ``right-
sizing'' we mean the process of modifying a public utility transmission
provider's in-kind replacement of an existing transmission facility to
increase that facility's transfer capability. Right-sizing could
include, for example, increasing the transmission facility's voltage
level, adding circuits to the towers (e.g., redesigning a single-
circuit line as a double-circuit line), or incorporating advanced
technologies (such as advanced conductor technologies).\648\
---------------------------------------------------------------------------
\648\ Grid Strategies LLC, Advanced Conductors on Existing
Transmission Corridors to Accelerate Low Cost Decarbonization, at 2
(Mar. 2022), https://gridprogress.files.wordpress.com/2022/03/advanced-conductors-on-existing-transmission-corridors-to-accelerate-low-cost-decarbonization.pdf.
---------------------------------------------------------------------------
404. As part of this proposed reform, first, we propose to require
that, at a specified point early in each Long-Term Regional
Transmission Planning cycle, each public utility transmission provider
submit, as part of the regional transmission planning process, a list
of each existing transmission facility operating at or above 230 kV
that the public utility transmission provider owns and that it
estimates may need to be replaced with a new in-kind transmission
facility over the next 10 years, starting from the point in the
transmission planning cycle when the list is compiled (which we refer
to as ``in-kind replacement estimates'').\649\
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\649\ We note that in RTOs/ISOs, the RTO/ISO is the public
utility transmission provider. Each individual transmission-owning
member of the RTO/ISO generally has the responsibility to maintain
its own existing transmission facilities and thus would have the
obligation to provide replacement estimates to the RTO/ISO.
---------------------------------------------------------------------------
405. Second, we propose to require that public utility transmission
providers in each transmission planning region, as part of Long-Term
Regional Transmission Planning, review and evaluate whether the
existing transmission facilities included in each public utility
transmission owner's in-kind replacement estimates can be right-sized
to address a transmission need identified in Long-Term Regional
Transmission Planning.
406. We preliminarily find that an existing transmission facility
operating at or above 230 kV that a public utility transmission
provider indicates may need to be replaced over the next 10 years is
the type of facility that is best suited to be considered for right-
sizing as part of Long-Term Regional Transmission Planning. We believe
that in-kind replacement transmission facilities that will operate at
or above 230 kV are the most likely candidates for right-sizing, i.e.,
are most susceptible to modification that could more efficiently or
cost-effectively meet transmission needs identified through Long-Term
Regional Transmission Planning. We also believe that 10 years is an
appropriate timeframe to evaluate potential in-kind replacements for
right-sizing to balance the long lead times necessary to construct
large transmission facilities with the uncertainty associated with the
exact timing when aging transmission assets may need to be replaced. A
right-sized replacement transmission facility has the potential to both
meet the individual public utility transmission provider's
responsibility to maintain the reliability of its existing transmission
system and address a regional transmission need(s) identified in Long-
Term Regional Transmission Planning more efficiently or cost-
effectively. In addition, a right-sized replacement transmission
facility may defer or displace the need for other transmission
facilities, including both new transmission facilities and in-kind
replacement of existing transmission facilities, thus representing a
benefit to the public utility transmission provider and its customers.
We believe that if opportunities for right-sized replacement
transmission facilities are not considered, regional transmission
planning processes may not select the more efficient or cost-effective
transmission facilities in the regional transmission plan for purposes
of cost allocation to meet transmission needs identified through Long-
Term Regional Transmission Planning.\650\
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\650\ We note that benefits associated with right-sizing
potential replacement transmission facilities to address
transmission needs identified through Long-Term Regional
Transmission Planning should be evaluated the same as any potential
transmission facility that could address that transmission need. See
supra Regional Transmission Planning: Proposed Reforms, Evaluation
of the Benefits of Regional Transmission Facilities.
---------------------------------------------------------------------------
407. The process under this proposed reform would entail the
following steps. First, sufficiently early in each Long-Term Regional
Transmission Planning cycle, each public utility transmission provider
would submit its in-kind replacement estimates for use in Long-Term
Regional Transmission Planning. Then, if a right-sized replacement
transmission facility is identified as a potential solution to a Long-
Term Regional Transmission Planning need, that right-sized replacement
transmission facility would be evaluated in the same manner as any
other proposed transmission facility to determine whether it is the
more efficient or cost-effective transmission facility to address the
transmission need. If a right-sized replacement transmission facility
addresses the public utility transmission provider's need to replace an
existing transmission facility, meets all the applicable selection
criteria included in Long-Term Regional Transmission Planning, and is
found to be the more efficient or cost-effective solution to a
transmission need identified through Long-Term Regional Transmission
Planning, then the right-sized replacement transmission facility may be
selected in the regional transmission plan for purposes of cost
allocation.\651\
---------------------------------------------------------------------------
\651\ See supra Regional Transmission Planning: Proposed
Reforms, Selection of Regional Transmission Facilities.
---------------------------------------------------------------------------
408. Although the right-sized replacement transmission facility may
be selected in the regional transmission plan for purposes of cost
allocation, it is necessary that a selected right-sized replacement
transmission facility be subject to different rules with respect to the
elimination of a federal right of first refusal than other regional
transmission facilities. Absent reform, if a public utility
transmission provider's estimated in-kind replacement were right-sized
and then selected in the regional transmission plan for purposes of
cost allocation to meet transmission needs identified through Long-Term
Regional Transmission Planning, the right-sized replacement
transmission facility might then be subject to the transmission
planning region's competitive transmission development process.
However, the public utility transmission provider would not necessarily
be bound by that right-sizing decision made by the region, unless the
public utility transmission provider was selected to develop the right-
sized replacement transmission facility. This is because nothing in
this proposed rule would alter existing law concerning the public
utility transmission provider's ability to proceed with developing its
planned in-kind replacement transmission facility without the right-
sizing, in spite of the potential efficiencies of right-sizing
identified in the regional transmission planning process.\652\ This may
reduce the opportunities for the regional transmission planning process
to identify more efficient or cost-effective solutions to transmission
needs identified through Long-Term Regional Transmission Planning and
potentially lead to duplicative or inefficient transmission
development.
---------------------------------------------------------------------------
\652\ Similarly, nothing in this proposed rule would alter
existing law concerning subsequent proceedings involving an in-kind
asset replacement, e.g., state-law siting proceedings.
---------------------------------------------------------------------------
[[Page 26575]]
409. In addition, requiring in-kind replacement estimates to cover
the next 10 years, starting from the point in the transmission planning
cycle when the list is compiled, may lengthen the time horizon over
which in-kind replacement needs are assessed, compared to current
practices where in-kind replacement needs may be assessed on a shorter-
term or nearer-term basis.\653\ Accordingly, areas of uncertainty that
could lessen the accuracy of a public utility transmission provider's
in-kind replacement estimates should be minimized where possible. In
particular, such an approach that looks out over 10 years, would allow
the public utility transmission provider to formulate in-kind
replacement estimates with greater certainty as to its own future role
in meeting that transmission need. Therefore, for any right-sized
replacement transmission facility that is selected in the regional
transmission plan for purposes of cost allocation to meet transmission
needs identified through Long-Term Regional Transmission Planning, we
propose to require the establishment of a federal right of first
refusal for the public utility transmission provider that included the
in-kind replacement transmission facility in its in-kind replacement
estimates, which would extend to any portion of such a transmission
facility located within the applicable public utility transmission
provider's retail distribution service territory or footprint.
---------------------------------------------------------------------------
\653\ See, e.g., PJM, Intra-PJM Tariffs, OATT, attach. M-3, OATT
Attachment M-3 (1.0.0), Sec. (d)(1)(iii) (providing that every year
``each Transmission Owner will provide to PJM a Candidate [End-of-
Life (EOL)] Needs List comprising its non-public confidential, non-
binding projection of up to 5 years of EOL Needs that it has
identified under the Transmission Owner's processes for
identification of EOL Needs'' and that each ``Transmission Owner may
change its projection as it deems necessary and will update it
annually'').
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410. With respect to cost allocation, we propose that if a right-
sized replacement transmission facility is selected in the regional
transmission plan for purposes of cost allocation, only the incremental
costs of right-sizing the transmission facility will be eligible to use
the applicable Long-Term Regional Transmission Cost Allocation Method.
We propose that the costs the incumbent transmission provider would
have otherwise incurred to construct the in-kind replacement
transmission facility be allocated in a manner consistent with the
allocation that would have otherwise occurred for the in-kind
replacement. We preliminarily find that it is just and reasonable and
not unduly discriminatory or preferential for only the portion of the
costs associated with right-sizing a right-sized replacement
transmission facility that is selected in the regional transmission
plan for purposes of cost allocation to be eligible to use the Long-
Term Regional Transmission Cost Allocation Method because it is the
right-sizing of the in-kind replacement transmission facility that
allows the transmission facility to meet the transmission need(s)
identified in Long-Term Regional Transmission Planning. In addition,
the customers of the public utility transmission provider that would be
allocated the costs associated with the original in-kind replacement
transmission facility would have otherwise been responsible for paying
those costs had the replacement transmission facility not been right-
sized.
411. We note that Order No. 1000 allows a public utility
transmission provider to meet its reliability needs or service
obligations by choosing to build new transmission facilities that are
located solely within its retail distribution service territory or
footprint and that are not selected in the regional transmission plan
for purposes of cost allocation.\654\ Similarly, nothing in the reforms
that we propose here alters existing law concerning a public utility
transmission provider's existing rights and responsibilities with
respect to maintaining, and when necessary replacing, existing
transmission facilities. Thus, the proposed requirements for public
utility transmission providers to provide greater transparency and
stakeholder process surrounding local transmission planning and in-kind
replacement estimates would not create an obligation for an incumbent
transmission provider to actually replace any existing transmission
facilities. We believe that this clarification is important given that
decisions related to replacement of existing transmission facilities
may change as a public utility transmission provider gets better
information about the condition of its transmission facilities.
---------------------------------------------------------------------------
\654\ Order No. 1000, 136 FERC ] 61,051 at P 262; Order No.
1000-A, 139 FERC ] 61,132 at PP 366, 379, 425, 428.
---------------------------------------------------------------------------
412. Even if a right-sized replacement transmission facility is
selected in the regional transmission plan for purposes of cost
allocation to meet transmission needs identified in Long-Term Regional
Transmission Planning, that selection does not alter existing law
concerning any existing rights and responsibilities a public utility
transmission provider may have to replace as needed its existing
transmission facilities with in-kind replacement transmission
facilities. For example, a public utility transmission provider could
inform the transmission planning region that, notwithstanding the
selection of a right-sized replacement transmission facility in the
regional transmission plan for purposes of cost allocation, the public
utility transmission provider has chosen to build the original in-kind
replacement transmission facility instead. In such cases, as we explain
earlier,\655\ we understand that, depending on the rules of the
particular regional transmission planning process, the in-kind
replacement transmission facility may be included in the regional
transmission plan for informational purposes, but not selected in the
regional transmission plan for purposes of cost allocation.
---------------------------------------------------------------------------
\655\ See supra P 412.
---------------------------------------------------------------------------
413. Our proposal to only allow the incremental costs of right-
sizing replacement transmission facilities to be eligible to use the
applicable Long-Term Regional Transmission Cost Allocation Method
emphasizes the need for transparency in regional transmission planning
processes so as to clearly determine which right-sized replacement
transmission facilities have been selected in the regional transmission
plan for purposes of cost allocation.\656\ Therefore, we propose to
require public utility transmission providers in each transmission
planning region to amend their regional transmission planning processes
to provide transparency with respect to which right-sized replacement
transmission facilities have been selected in the regional transmission
plan for purposes of cost allocation (and thus found to be a more
efficient or cost-effective transmission facility to meet regional
transmission needs) and which transmission facilities are simply
included in the regional transmission plan for informational (and not
cost allocation) purposes. We believe that this additional transparency
would inform interested parties, including state regulators, regarding
the degree to which a right-sized replacement transmission facility was
evaluated through Long-Term Regional Transmission Planning. As such, we
believe that this additional transparency ensures just and reasonable
Commission-jurisdictional rates because the information provided will
enable customers and other stakeholders alike to evaluate or replicate
the findings related to right-sized replacement transmission facilities
or in-kind
[[Page 26576]]
replacement transmission facilities so as to reduce after-the-fact
disputes regarding transmission system needs or cost allocation.
---------------------------------------------------------------------------
\656\ See supra Regional Transmission Planning: Proposed
Reforms, Selection of Regional Transmission Facilities.
---------------------------------------------------------------------------
414. We seek comment on the requirements proposed in this section
of the NOPR. In particular, we seek comment on whether the Commission
should impose any requirements regarding how the relevant public
utility transmission providers would determine incremental costs of
right-sizing the transmission facility.
415. We also seek comment on whether there is additional
information from transmission owners that would help public utility
transmission providers to identify whether there are estimated in-kind
replacements of an existing transmission facility that could be right-
sized to address a transmission need identified in Long-Term Regional
Transmission Planning. If so, we seek comment what level of burden such
a requirement would impose on the transmission owners required to
provide that information, and what level of burden is justified given
the potential benefits of such information. Moreover, we seek comment
on whether there is additional information beyond a list of in-kind
replacement estimates that public utility transmission providers need
to calculate such benefits and, if so, how that information could be
obtained.
IX. Interregional Transmission Coordination and Cost Allocation
416. In the ANOPR, the Commission asked several questions about the
value and logistics of reforms to interregional transmission
coordination, planning, and cost allocation. The Commission continues
to examine those issues, including review of comments to the ANOPR, and
to consider possible reforms. As such, we do not, at this time, propose
changes to the existing interregional transmission coordination and
cost allocation requirements of Order No. 1000. However, we propose to
require that public utility transmission providers revise their
existing interregional transmission coordination procedures adopted in
compliance with Order No. 1000 to apply them to the proposed Long-Term
Regional Transmission Planning reforms in this NOPR, as discussed
below.
A. Background
417. In Order No. 1000, the Commission set out a number of
requirements for interregional transmission coordination and
interregional cost allocation.\657\ Order No. 1000 requires public
utility transmission providers in neighboring transmission planning
regions to develop and implement procedures to provide for: (1) The
sharing of information regarding the respective transmission needs of
each region and potential solutions to those needs; and (2) the
identification and joint evaluation of interregional transmission
facilities that may be more efficient or cost-effective transmission
facilities needed to meet those regional needs.\658\
---------------------------------------------------------------------------
\657\ In Order No. 1000, the Commission defined an interregional
transmission facility as a transmission facility that is located in
two or more transmission planning regions. Order No. 1000, 136 FERC
] 61,051 at P 482 n.374.
\658\ Id. PP 393-399.
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418. With regard to the evaluation of interregional transmission
facilities, Order No. 1000 requires public utility transmission
providers in neighboring transmission planning regions to develop and
implement formal procedures to identify and jointly evaluate
transmission facilities that are proposed to be located in neighboring
transmission planning regions.\659\ The Commission clarified that the
developer of an interregional transmission facility must first propose
its transmission facility in the regional transmission planning
processes of each of the neighboring transmission planning regions in
which the transmission facility is proposed to be located. The
submission of the interregional transmission facility in each regional
transmission planning process triggers the procedure under which the
public utility transmission providers, acting through their regional
transmission planning process, jointly evaluate the proposed
transmission project.\660\
---------------------------------------------------------------------------
\659\ Id. P 436.
\660\ Id.
---------------------------------------------------------------------------
419. The Commission further required, inter alia, that
interregional transmission coordination procedures must have a process
by which differences in the data, models, assumptions, planning
horizons, and criteria used to study a proposed transmission project
can be identified and resolved for purposes of jointly evaluating the
proposed interregional transmission facility.\661\
---------------------------------------------------------------------------
\661\ Id. P 437; Order No. 1000-A, 139 FERC ] 61,132 at PP 506,
510.
---------------------------------------------------------------------------
420. With regard to transmission facility selection, Order No. 1000
requires that an interregional transmission facility must be selected
in both of the relevant regional transmission plans for purposes of
cost allocation in order to be eligible for interregional cost
allocation.\662\ The Commission further clarified that based on the
information gained during the joint evaluation of an interregional
transmission project, each transmission planning region will determine,
for itself, whether to select those interregional transmission
facilities within its footprint in the regional transmission plan for
purposes of cost allocation.\663\
---------------------------------------------------------------------------
\662\ Order No. 1000, 136 FERC ] 61,051 at P 400; Order No.
1000-A, 139 FERC ] 61,132 at P 509.
\663\ Order No. 1000, 136 FERC ] 61,051 at PP 443, 635.
---------------------------------------------------------------------------
421. With respect to interregional cost allocation, the Commission
required that each public utility transmission provider in a
transmission planning region must have, together with the public
utility transmission providers in its own transmission planning region
and a neighboring transmission planning region, a common method or
methods for allocating the costs of a new interregional transmission
facility among the beneficiaries of that transmission facility in the
two neighboring transmission planning regions in which the transmission
facility is located.\664\ The Commission also defined six interregional
cost allocation principles that apply to, and only to, a cost
allocation method or methods for a new interregional transmission
facility.\665\
---------------------------------------------------------------------------
\664\ Id. P 578.
\665\ Id. P 603.
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B. ANOPR
422. In the ANOPR, the Commission asked several questions about the
value and logistics of reforms to interregional transmission
coordination, planning, and cost allocation. Specifically, the
Commission sought comment on whether greater interregional or state-
regional coordination is required to address other topics in the ANOPR,
including long-term regional transmission planning, identifying
geographic zones that have the potential for the development of large
amounts of new generation, and incentives for transmission
development.\666\ The Commission also sought comment on how a regional
states committee or other organized body of state officials should
participate in the development and evaluation of assumptions or
criteria used for interregional transmission coordination.\667\
Further, the Commission sought comment on whether to require joint
transmission planning processes for neighboring transmission planning
regions, rather than simply joint coordination, and
[[Page 26577]]
whether the Commission should establish interregional reliability
planning criteria.\668\
---------------------------------------------------------------------------
\666\ ANOPR, 176 FERC ] 61,024 at PP 57, 62-64.
\667\ Id. P 64.
\668\ Id. PP 62-63.
---------------------------------------------------------------------------
C. Comments
423. Some commenters urge the Commission to require substantial
changes to the existing interregional transmission coordination
requirements established in Order No. 1000.\669\ Other commenters
instead urge the Commission to maintain the existing interregional
transmission coordination requirements.\670\
---------------------------------------------------------------------------
\669\ See, e.g., ACEG Comments at 4-5; ACORE Comments at 27;
ACPA and ESA Comments at 51-52; Advanced Power Comments at 2; AEE
Comments at 31; AEP Comments at 18-24; Amazon Comments at 2;
American Municipal Power Comments at 33; Anbaric Comments at 30-32;
Avangrid Comments at 20-21; Arizona Commission Comments at 4;
Competition Coalition Comments at 20; Consumers Council Comments at
10-11; EDF Comments at 8; Eversource Comments at 18-19; Kansas
Commission Comments at 2; LS Power Oct. 12 Comments at 63; NARUC
Comments at 16-19; Nature Conservancy Comments at 9-10; New Jersey
Commission Comments at 2; NY TOs Comments at 25-26; Northwest and
Intermountain Comments at 30; PG&E Comments at 7; PIOs Comments at
70-72; Policy Integrity Comments at 16-18; REBA Comments at 17;
Resale Iowa Comments at 15; RMI Comments at 3-4; State Agencies
Comments at 28-30; State of Massachusetts Comments at 21; U.S. DOE
Comments at 25-26; Xcel Comments at 22.
\670\ See, e.g., APPA Comments at 5; CAISO Comments at 6-8, 59-
63; LPPC Comments at 24-26; MISO Comments at 2-3, 15-16; MISO TOs
Comments at 16-18; NYISO Comments at 56-57; PJM Comments at 68.
---------------------------------------------------------------------------
D. Need for Reform
424. In establishing the Order No. 1000 interregional transmission
coordination and cost allocation requirements, the Commission
considered the requirements of Order No. 890, determining that the
transmission planning requirements of Order No. 890 were too narrowly
focused geographically and failed to provide for adequate analysis of
the benefits associated with interregional transmission facilities in
neighboring transmission planning regions.\671\ The Commission stated
that ``in the absence of coordination between transmission planning
regions, public utility transmission providers may be unable to
identify more efficient or cost-effective solutions to the individual
needs identified in their respective local and regional transmission
planning processes, potentially including interregional transmission
facilities.'' \672\ Therefore, the Commission concluded that
interregional transmission coordination reforms were necessary. The
Commission stated that ``[c]lear and transparent procedures that result
in the sharing of information regarding common needs and potential
solutions across the seams of neighboring transmission planning regions
will facilitate the identification of interregional transmission
facilities that more efficiently or cost-effectively could meet the
needs identified in individual regional transmission plans.'' \673\
---------------------------------------------------------------------------
\671\ Order No. 1000, 136 FERC ] 61,051 at P 369.
\672\ Id. P 368.
\673\ Id.
---------------------------------------------------------------------------
425. Based upon our experience since Order No. 1000 and the record
in this proceeding, we continue to believe that there is a significant
need for interregional transmission coordination. We therefore
preliminarily find that it is necessary to revise the existing Order
No. 1000 interregional transmission coordination requirements to apply
them to the proposed Long-Term Regional Transmission Planning reforms
in this NOPR to ensure that interregional transmission coordination is
just and reasonable. We believe that the reforms we propose here will
ensure that the information sharing and evaluation of interregional
transmission facilities required as part of the existing interregional
transmission coordination procedures will continue to occur with
respect to all aspects of the regional transmission planning process,
including the proposed Long-Term Regional Transmission Planning.
E. Proposed Reform
426. We propose to require that public utility transmission
providers revise their existing interregional transmission coordination
procedures to reflect the Long-Term Regional Transmission Planning
reforms proposed in this NOPR.\674\
---------------------------------------------------------------------------
\674\ As noted earlier, we are not proposing to require any
changes to existing interregional cost allocation methods for
interregional transmission facilities that are selected in the
regional transmission plan for purposes of cost allocation and that
the Commission previously accepted as compliant with Order No. 1000.
---------------------------------------------------------------------------
427. Specifically, we propose to require that public utility
transmission providers in neighboring transmission planning regions
revise their existing interregional coordination procedures (and
regional transmission planning processes as needed) to provide for: (1)
The sharing of information regarding the respective transmission needs
identified in the Long-Term Regional Transmission Planning that we
propose to require in that section above, as well as potential
transmission facilities to meet those needs; and (2) the identification
and joint evaluation of interregional transmission facilities that may
be more efficient or cost-effective transmission facilities to address
transmission needs identified through Long-Term Regional Transmission
Planning.
428. We also propose to require that public utility transmission
providers in neighboring transmission planning regions revise their
interregional transmission coordination procedures (and regional
transmission planning processes as needed) to allow an entity to
propose an interregional transmission facility in the regional
transmission planning process as a potential solution to transmission
needs identified through Long-Term Regional Transmission Planning. We
believe that this will align the existing requirement for an entity to
propose an interregional transmission facility in the regional
transmission planning processes of each of the neighboring transmission
planning regions in which the transmission facility is proposed to be
located with the proposed requirement for public utility transmission
providers to conduct Long-Term Regional Transmission Planning as part
of their regional transmission planning processes.
429. This proposed reform aims to ensure that transmission needs
driven by changes in the resource mix and demand identified through
Long-Term Regional Transmission Planning can be considered in existing
interregional transmission coordination and cost allocation
processes.\675\ Doing so will ensure that there is an opportunity for
the public utility transmission providers in neighboring transmission
planning regions to consider whether there are interregional
transmission facilities that could more efficiently or cost-effectively
meet the transmission needs identified through Long-Term Regional
Transmission Planning, in turn helping to ensure just and reasonable
Commission-jurisdictional rates.
---------------------------------------------------------------------------
\675\ See Order No. 1000, 136 FERC ] 61,051 at PP 99-117
(explaining the Commission's legal basis for requiring interregional
transmission coordination and interregional cost allocation).
---------------------------------------------------------------------------
X. Proposed Compliance Procedures
430. Given the necessity to coordinate with the relevant state
entities and other stakeholders on the proposed reforms, we propose an
extended compliance period. We propose to require that each public
utility transmission provider submit a compliance filing within eight
months of the effective date of any final rule in this proceeding
revising its OATT and other document(s) subject to the Commission's
jurisdiction as necessary to demonstrate that it meets the proposed
requirements set forth in
[[Page 26578]]
this NOPR and are included in any final rule in this proceeding.\676\
---------------------------------------------------------------------------
\676\ See Appendix B for the proposed pro forma Attachment K
consistent with this NOPR.
---------------------------------------------------------------------------
431. The Commission would assess whether each compliance filing
satisfies the proposed requirements outlined above and issue additional
orders as necessary to ensure that each public utility transmission
provider meets the requirements of any final rule in this proceeding.
432. We propose that transmission providers that are not public
utilities would have to adopt the requirements of this NOPR as a
condition of maintaining the status of their safe harbor tariff or
otherwise satisfying the reciprocity requirement of Order No. 888.\677\
---------------------------------------------------------------------------
\677\ Order No. 888, FERC Stats. & Regs. ] 31,036 at 31,760-63.
---------------------------------------------------------------------------
433. The Commission will ensure that jurisdictional entities comply
with these NOPR requirements upon final action of the Commission and
has the authority to conduct audits to evaluate such compliance.
Section 302(C) of the Federal Power Act allows the Commission staff to
examine the books, accounts, memoranda, and records of any person who
controls directly or indirectly, a licensee or public utility subject
to the jurisdiction of the Commission insofar as they relate to
transactions with or the business of such licensee or public utility.
XI. Information Collection Statement
434. The information collection requirements contained in this NOPR
are subject to review by the Office of Management and Budget (OMB)
under section 3507(d) of the Paperwork Reduction Act of 1995.\678\
OMB's regulations require approval of certain information collection
requirements imposed by agency rules.\679\ Upon approval of a
collection of information, OMB will assign an OMB control number and
expiration date. Respondents subject to the filing requirements of this
rule will not be penalized for failing to respond to these collections
of information unless the collections of information display a valid
OMB control number.
---------------------------------------------------------------------------
\678\ 44 U.S.C. 3507(d).
\679\ 5 CFR 1320.11.
---------------------------------------------------------------------------
435. This NOPR would, pursuant to section 206 of the FPA, reform
the Commission's pro forma OATT and the Commission's pro forma LGIP to
correct deficiencies in the Commission's existing regional transmission
planning and cost allocation requirements so that the transmission
system can better support wholesale power markets and thereby ensure
that Commission-jurisdictional rates remain just and reasonable and not
unduly discriminatory or preferential.
436. 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).
437. The Commission solicits 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, including
the use of automated information techniques.
438. Please send comments concerning the collections of information
and the associated burden estimates to the Office of Information and
Regulatory Affairs, Office of Management and Budget, through
www.reginfo.gov/public/do/PRAMain. Attention: Federal Energy Regulatory
Commission Desk Officer. Please identify the OMB Control Numbers 1902-
0233 and 1902-0096 in the subject line of your comments. Comments
should be sent within 60 days of publication of this notice in the
Federal Register.
439. Please submit a copy of your comments on the information
collections to the Commission via the eFiling link on the Commission's
website at https://www.ferc.gov. Comments on the information collection
that are sent to FERC should refer to Docket No. RM21-17-000.
440. Title: Electric Transmission Facilities (FERC-917) and
Electric Rate Schedules and Tariff Filings (FERC-516).
441. Action: Proposed revision of collections of information in
accordance with Docket No. RM21-17-000 and request for comments.
442. OMB Control Nos.: 1902-0233 (FERC-917) and 1902-0096 (FERC-
516).
443. Respondents: Public utility transmission providers, including
RTOs/ISOs, and public utility transmission owners.
444. Frequency of Information Collection: One time during Year 1.
Occasional times during subsequent years, at least once every three
years.
445. Necessity of Information: The reforms in this Proposed Rule
will correct deficiencies in the Commission's existing regional
transmission planning and cost allocation requirements so that the
transmission system can better support wholesale power markets and
thereby ensure that Commission-jurisdictional rates remain just and
reasonable and not unduly discriminatory or preferential.
446. Internal Review: The Commission has reviewed the changes and
has determined that such changes are necessary. These requirements
conform to the Commission's need for efficient information collection,
communication, and management within the energy industry. The
Commission has specific, objective support for the burden estimates
associated with the information collection requirements.
447. Our estimates are based on the NERC Compliance Registry as of
March 3, 2022, which indicates that there are 48 transmission service
providers \680\ and 118 transmission owners that are registered within
the United States and are subject to this proposed rulemaking.\681\
---------------------------------------------------------------------------
\680\ The transmission service provider (TSP) function is a NERC
registration function which is similar to the transmission provider
that is referenced in the pro forma OATT. The TSP function is being
used as a proxy to estimate the number of transmission providers
that are impacted by this proposed rulemaking.
\681\ The number of entities listed from the NERC Compliance
Registry reflects the omission of the Texas RE registered entities.
Note that 41 transmission owners in non-RTO/ISO regions are also
transmission service providers, so in total there are 125 entities
subject to this proposed rulemaking.
---------------------------------------------------------------------------
448. Public Reporting Burden: The burden and cost estimates below
are based on the need for applicable entities to revise documentation,
already required by the Commission's pro forma OATT and the
Commission's pro forma LGIP.
449. The Commission estimates that the NOPR would affect the burden
\682\ and cost of FERC-917 and FERC-516 as follows:
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\682\ ``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.
[[Page 26579]]
Proposed Changes in NOPR in Docket No. RM21-17-000 \683\
----------------------------------------------------------------------------------------------------------------
Total estimated
Total annual Average burden burden hours &
Area of modification Annual number of estimated hours & cost \684\ total estimated
respondents number of per response cost (column C x
responses column D)
A B.................. C D.................. E
----------------------------------------------------------------------------------------------------------------
FERC-917, Electric Transmission Facilities
(OMB Control No. 1902-0233)
----------------------------------------------------------------------------------------------------------------
Participate in Long-Term Regional 125 (TSPs and TOs). 125 Year 1: 150 hours; Year 1: 18,750
Transmission Planning, which $11,275. hours; $1,409,363.
includes developing Long-Term Subsequent Years: Subsequent Years:
Scenarios, evaluating the 50 hours per year; 6,250 hours per
benefits of regional $3,758 per year. year; $469,788 per
transmission facilities, and year.
establishing criteria in
consultation with states to
select transmission facilities
in the regional transmission
plan for purposes of cost
allocation.
Revise the regional transmission 125 (TSPs and TOs). 125 Year 1: 20 hours; Year 1: 2,500
planning process to enhance $1,208. hours; $151,038.
transparency of local Subsequent Years: Subsequent Years:
transmission planning and 50 hours per year; 6,250 hours per
identifying potential $3,758 per year. year; $469,788 per
opportunities to right-size year.
replacement transmission
facilities.
Seek agreement from the states to 125 (TSPs and TOs). 125 Year 1: 150 hours; Year 1: 18,750
establish a Long-Term Regional $11,275. hours; $1,409,363.
Transmission Cost Allocation Subsequent Years: Subsequent Years:
Method and/or a State Agreement 50 hours per year; 6,250 hours per
Process. $3,758 per year. year; $469,788 per
year.
Consider in the regional 125 (TSPs and TOs). 125 Year 1: 50 hours; Year 1: 6,250
transmission planning processes $3,758. hours; $469,750.
regional transmission facilities Subsequent Years: 0 Subsequent Years: 0
that address certain hours per year; $0 hours per year; $0
interconnection-related needs. per year. per year.
Revise interregional transmission 125 (TSPs and TOs). 125 Year 1: 50 hours; Year 1: 6,250
coordination procedures to $3,758. hours; $469,750.
reflect Long-Term Regional Subsequent Years: Subsequent Years:
Transmission Planning. 25 hours per year; 3,125 hours per
$1,715 per year. year; $214,375 per
year.
----------------------------------------------------------------------------------------------------------------
FERC-516, Electric Rate Schedules and Tariff Filings
(OMB Control No. 1902-0096)
----------------------------------------------------------------------------------------------------------------
Revise LGIP to indicate the 125 (TSPs and TOs). 125 Year 1: 30 hours; Year 1: 3,750
consideration in the regional $2,058. hours; $257,288.
transmission planning processes Subsequent Years: 0 Subsequent Years: 0
of regional transmission hours per year; $0 hours per year; $0
facilities that address certain per year. per year.
interconnection-related needs.
----------------------------------------------------------------------------------------------------------------
450. Our estimates conservatively assume the maximum number of
respondents and burdens. We acknowledge that the actual burdens for
some respondents may be lower than estimated, and that other
respondents may incur the maximum burdens. We seek comment on the
estimates in the burden table and on the assumptions described here.
---------------------------------------------------------------------------
\683\ In the table, Year 1 figures are one-time implementation
hours and cost. ``Subsequent years'' show ongoing burdens and costs
starting in Year 2.
\684\ The hourly cost (for salary plus benefits) uses the
figures from the Bureau of Labor Statistics (BLS) for three
positions involved in the reporting and recordkeeping requirements.
These figures include salary (based on BLS data for May 2020,
https://bls.gov/oes/current/naics2_22.htm) and benefits (based on
BLS data for December 2020; issued March 18, 2021, https://www.bls.gov/news.release/ecec.nr0.htm) and are Manager (Occupation
Code 11-0000, $97.89/hour), Electrical Engineer (Occupation Code 17-
2071, $72.15/hour), and File Clerk (Occupation Code 43-4071, $35.83/
hour). The hourly cost for the reporting requirements ($85.00) is an
average of the hourly cost (wages plus benefits) of a manager and
engineer. The hourly cost for recordkeeping requirements uses the
cost of a file clerk.
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XII. Environmental Analysis
451. 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.\685\ We
conclude that neither an Environmental Assessment nor an Environmental
Impact Statement is required for this Proposed Rule under section
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, classifications,
and services.\686\
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\685\ Reguls. Implementing the Nat'l Envt'l Pol'y Act, Ord. No.
486, 52 FR 47897 (Dec. 17, 1987), FERC Stats. & Regs. 30,783 (1987)
(cross-referenced at 41 FERC ] 61,284).
\686\ 18 CFR 380.4(a)(15).
---------------------------------------------------------------------------
XIII. Regulatory Flexibility Act [Analysis or Certification]
452. The Regulatory Flexibility Act of 1980 (RFA) \687\ generally
requires a description and analysis of proposed 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,\688\ RTOs/
ISOs, planning regions, and transmission owners all fall under the
category of Electric Bulk Power Transmission and Control (NAICS code
221121), with a size threshold of 500 employees (including the entity
and its associates).\689\
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\687\ 5 U.S.C. 601-612.
\688\ 13 CFR 121.201.
\689\ 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 Administrations' regulations at 13 CFR 121.201 define
the threshold for a small Electric Bulk Power Transmission and
Control entity (NAICS code 221121) to be 500 employees. See 5 U.S.C.
601(3), citing to section 3 of the Small Business Act, 15 U.S.C.
632.
---------------------------------------------------------------------------
453. The six RTOs/ISOs (SPP, MISO, PJM, ISO-NE, NYISO, and CAISO)
each employ more than 500 employees and are not considered small.
454. We estimate that 119 additional transmission providers and
transmission owners are affected by the NOPR. Using the list of
transmission service providers and transmission owners from the NERC
Registry (dated March 3, 2022), we estimate that approximately 68% of
those entities are small entities.
[[Page 26580]]
455. We estimate additional one-time costs associated with the NOPR
(as shown in the table above) of:
--$31,274 for each transmission provider and transmission owner (FERC-
917)
--$2,058 for each transmission provider and transmission owner (FERC-
516)
456. Therefore, the estimated additional one-time implementation
cost in Year 1 per entity is $33,332.
457. We estimate additional recurring costs in subsequent years
(starting in Year 2) associated with the NOPR (as shown in the table
above) of:
--$12,989 for each transmission provider and transmission owner (FERC-
917)
--$0 for each transmission provider and transmission owner (FERC-516)
458. Therefore, the estimated recurring costs per entity in
subsequent years are $12,989 per year.
459. 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.'' \690\ We do not consider the estimated cost to be
a significant economic impact. As a result, we certify that the
proposals in this NOPR will not have a significant economic impact on a
substantial number of small entities.
---------------------------------------------------------------------------
\690\ U.S. Small Business Administration, A Guide for Government
Agencies How to Comply with the Regulatory Flexibility Act, at 18
(May 2012), https://www.sba.gov/sites/default/files/advocacy/rfaguide_0512_0.pdf.
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XIV. Comment Procedures
460. The Commission invites interested persons to submit comments
on the matters and issues proposed in this notice to be adopted,
including any related matters or alternative proposals that commenters
may wish to discuss. Comments are due July 18, 2022 and Reply Comments
are due August 17, 2022. Comments must refer to Docket No. RM21-17-000,
and must include the commenter's name, the organization they represent,
if applicable, and their address in their comments. All comments will
be placed in the Commission's public files and may be viewed, printed,
or downloaded remotely as described in the Document Availability
section below. Commenters on this proposal are not required to serve
copies of their comments on other commenters.
461. The Commission encourages comments to be filed electronically
via the eFiling link on the Commission's website at https://www.ferc.gov. The Commission accepts most standard word processing
formats. Documents created electronically using word processing
software must be filed in native applications or print-to-PDF format
and not in a scanned format. Commenters filing electronically do not
need to make a paper filing.
462. Commenters that are not able to file comments electronically
may file an original of their comment by USPS mail or by courier-or
other delivery services. For submission sent via USPS only, filings
should be mailed to: Federal Energy Regulatory Commission, Office of
the Secretary, 888 First Street NE, Washington, DC 20426. Submission of
filings other than by USPS should be delivered to: Federal Energy
Regulatory Commission, 12225 Wilkins Avenue, Rockville, MD 20852.
XV. Document Availability
463. 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 Commission's Home Page (https://www.ferc.gov). At
this time, the Commission has suspended access to the Commission's
Public Reference Room due to the President's March 13, 2020
proclamation declaring a National Emergency concerning the Novel
Coronavirus Disease (COVID-19).
464. 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 excluding the last three digits of this document in
the docket number field.
465. 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].
By direction of the Commission.
Commissioner Danly is dissenting with a separate statement
attached.
Commissioner Christie is concurring with a separate statement
attached.
Commission Phillips is concurring with a separate statement
attached.
Issued: April 21, 2022.
Debbie-Anne A. Reese,
Deputy Secretary.
Note: The following appendices will not be published in the Code
of Federal Regulations.
Appendix A: Abbreviated Names of Commenters
------------------------------------------------------------------------
Abbreviation Commenter
------------------------------------------------------------------------
Aaron Litz................... Aaron Litz.
ACEG......................... Americans for a Clean Energy Grid.
ACORE........................ American Council on Renewable Energy.
ACPA and ESA................. American Clean Power Association and the
U.S. Energy Storage Association.
AEE.......................... Advanced Energy Economy.
Advanced Power............... Advanced Power Alliance.
AEP.......................... American Electric Power Service
Corporation.
AES Ohio..................... Dayton Power and Light.
Alabama Commission........... Alabama Public Service Commission.
Amazon....................... Amazon Energy LLC.
Ameren....................... Ameren Services Company.
American Farmland Trust...... American Farmland Trust.
American Municipal Power..... American Municipal Power, Inc.
Ample........................ Ample, Inc.
Anbaric...................... Anbaric Development Partners, LLC.
APPA......................... American Public Power Association.
Arizona Commission........... Arizona Corporation Commission.
Arizona Public Service....... Arizona Public Service Company.
Avangrid..................... Avangrid.
Berkshire.................... Berkshire Hathaway Energy Company.
[[Page 26581]]
BP........................... BP America Inc.
Bridgelink................... Bridgelink Investments, LLC.
Business Council for Business Council for Sustainable Energy.
Sustainable Energy.
CAISO........................ California Independent System Operator
Corporation.
California Commission........ California Public Utilities Commission.
California Municipal California Municipal Utilities
Utilities. Association.
California Water............. California Department of Water Resources
State Water Project.
CBD.......................... The Center for Biological Diversity.
Center for Sustainable Energy Center for Sustainable Energy.
Certain TDUs................. Alliant Energy Corporate Services, Inc.
Consumers Energy Company, DTE Electric
Company.
Competitive Energy........... Competitive Energy Services, LLC.
Citizens Energy.............. Citizens Energy Corporation.
City of New York............. City of New York.
Competition Coalition........ Electricity Transmission Competition
Coalition.
Competitive Power............ Competitive Power Ventures, Inc.
Consumers.................... Consumer Organizations.
Electricity Consumers Electricity Consumers Resource Council.
Resource Council.
CTC Global................... CTC Global Corporation.
District of Columbia's Office Office of the People's Counsel for the
of the People's Counsel. District of Columbia.
Dominion..................... Dominion Energy Services, Inc.
Duke......................... Duke Energy Corporation.
Duquesne Light............... Duquesne Light Company.
East Kentucky................ East Kentucky Power Cooperative, Inc.
EDF.......................... EDF Renewables, Inc.
EDP Renewables............... EDP Renewables North America LLC.
EEI.......................... Edison Electric Institute.
El Paso Electric............. El Paso Electric Company.
Enel......................... Enel North America, Inc.
Entergy...................... Entergy Services, LLC.
Environmental Advocates...... Center for Renewables Integration,
Defenders of Wildlife, Environmental Law
& Policy Center, National Audubon
Society, National Wildlife Federation,
and Vote Solar.
EPSA......................... Electric Power Supply Association.
Eversource................... Eversource Energy Service Company.
Exelon....................... Exelon Corporation.
Grid United.................. Grid United LLC.
Handy Law.................... Set Handy, Handy Law.
Harvard ELI.................. Harvard Electricity Law Initiative.
Idaho Power.................. Idaho Power Company.
Indiana Commission........... Indiana Utility Regulatory Commission.
Indicated PJM TOs............ PJM Transmission Owners.
Industrial Customers......... Industrial Customer Organizations.
Iowa Consumer Advocate....... Iowa Office of Consumer Advocate.
ISO-NE....................... ISO New England Inc.
ITC.......................... International Transmission Company.
Kansas Commission............ Kansas Corporation Commission.
Land Trust................... Land Trust Alliance.
LPPC......................... Large Public Power Council.
Law Students................. Students of Law at the University of
Minnesota Law School.
LG&E/KU...................... Louisville Gas and Electric Company and
Kentucky Utilities Company.
Louisiana Commission......... Louisiana Public Service Commission.
LS Power..................... LS Power Grid, LLC.
Macro Grid................... Macro Grid Initiative.
Massachusetts Attorney Massachusetts Attorney General Maura
General. Healey.
Massachusetts DOER........... Massachusetts Department of Energy
Resources.
Maryland Commission.......... Maryland Public Service Commission.
Maryland Energy Admin........ Maryland Energy Administration.
Michigan Commission.......... Michigan Public Service Commission.
Minnesota Commerce........... Minnesota Department of Commerce.
MISO......................... Midcontinent Independent System Operator,
Inc.
MISO TOs..................... MISO Transmission Owners.
Mississippi Commission....... Mississippi Public Service Commission and
the Mississippi Public Utilities Staff.
Missouri Farm Bureau......... Missouri Farm Bureau Federation.
Montana QF Developers........ Clenera, LLC and Greenfields Irrigation
District.
NARUC........................ National Association of Regulatory
Utility Commissioners.
NASEO........................ National Association of State Energy
Officials.
NASUCA....................... National Association of State Utility
Consumer Advocates.
National Grid................ National Grid Plc.
Nature Conservancy........... The Nature Conservancy.
New England for Offshore Wind New England for Offshore Wind.
Nebraska Commission.......... Nebraska Power Review Board.
NEPOOL....................... New England Power Pool Participants
Committee.
NERC......................... North American Electric Reliability
Corporation.
NESCOE....................... New England States Committee on
Electricity.
[[Page 26582]]
New England Systems.......... New England Consumer-Owned Systems.
New Jersey Commission........ New Jersey Board of Public Utilities.
NewSun....................... NewSun Energy LLC.
NextEra...................... NextEra Energy, Inc.
Niskanen..................... Niskanen Center.
North Carolina Commission.... North Carolina Utilities Commission.
North Carolina Commission North Carolina Utilities Commission
Staff. Public Staff.
North Dakota Commission...... North Dakota Public Service Commission.
Northern VA Coop............. Northern Virginia Electric Cooperative.
Northwest and Intermountain.. Northwest & Intermountain Power Producers
Coalition.
NRECA........................ National Rural Electric Cooperative
Association.
NY Commission and NYSERDA.... New York Public Service Commission and
New York State Energy Research and
Development Authority.
NY TOs....................... New York Transmission Owners.
NYISO........................ New York Independent System Operator,
Inc.
Ohio Commission.............. Public Utilities Commission of Ohio's
Office of the Federal Energy Advocate.
Ohio Consumers............... Ohio Consumers' Counsel.
Oklahoma Commission.......... Oklahoma Corporation Commission.
Oklahoma Gas and Electric.... Oklahoma Gas and Electric Company.
Omaha Public Power........... Omaha Public Power District.
OMS.......................... Organization of MISO States.
Oregon Commission............ Public Utility Commission of Oregon.
Orsted....................... Orsted North America.
Pennsylvania Commission...... Pennsylvania Public Utility Commission.
PG&E......................... Pacific Gas and Electric.
Pine Gate.................... Pine Gate Renewables, LLC.
PIOs......................... Public Interest Organizations.
PJM.......................... PJM Interconnection, L.L.C.
PJM Market Monitor........... Monitoring Analytics, LLC, acting in its
capacity as the Independent Market
Monitor of PJM Interconnection, L.L.C.
Indicated PJM TOs............ PJM Transmission Owners.
Policy Integrity............. Institute for Policy Integrity.
Potomac Economics............ Potomac Economics, Ltd.
PPL.......................... PPL Electric Utilities Corporation.
PSEG......................... PSEG Companies.
Public Citizen............... Public Citizen, Inc.
Public Systems............... Massachusetts Municipal Wholesale
Electric Company, New Hampshire Electric
Cooperative, Inc., Connecticut Municipal
Electric Energy Cooperative, and Vermont
Public Power Supply Authority.
QCo.......................... Q Coefficient, Inc.
R Street..................... R Street Institute.
Rail Electrification......... Rail Electrification Council.
REBA......................... Renewable Energy Buyers Alliance.
Resale Iowa.................. Resale Power Group of Iowa.
Resilient Societies.......... Foundation for Resilient Societies.
RMI.......................... RMI.
Ron Belval................... Ron Belval.
SAFE......................... SAFE.
SoCal Edison................. Southern California Edison Company.
SDG&E........................ San Diego Gas & Electric Company.
SEIA......................... Solar Energy Industries Association.
SERTP........................ Sponsors of the Southeastern Regional
Transmission Planning Process.
Shell........................ Shell Energy North America.
Six Cities................... Cities of Anaheim, Azusa, Banning,
Colton, Pasadena, and Riverside,
California.
Sorgo........................ Sorgo Fuels & Chemicals, Inc.
Southern..................... Southern Company Services, Inc.
SPP.......................... Southwest Power Pool, Inc.
SPP Market Monitor........... Southwest Power Pool Market Monitoring
Unit.
SPP RSC...................... Southwest Power Pool Regional State
Committee.
State Agencies............... State Agencies (CT, DE, MD, DC, IL, MN,
MI, MA, NJ, OR, PA, RI, VT).
State Legislatures........... National Conference of State
Legislatures.
State of Idaho............... Idaho Governor's Office of Energy &
Mineral Resources.
State of Massachusetts....... Commonwealth of Massachusetts Department
of Energy Resources.
State of New York............ New York State Department of State
Utility Intervention Unit.
State of Tennessee........... State of Tennessee.
State of Washington.......... Jay Inslee, Governor, State of
Washington.
State Wildlife Agencies...... Association of Fish & Wildlife Agencies.
TANC......................... Transmission Agency of Northern
California.
TAPS......................... Transmission Access Policy Study Group.
Tenaska...................... Tenaska, Inc.
Tom Pike..................... Tom R Pike.
Transmission Dependent Transmission Dependent Utility Systems.
Utilities.
Union of Concerned Scientists Union of Concerned Scientists.
US Chamber of Commerce....... US Chamber of Commerce.
U.S. DOE..................... United States Department of Energy.
[[Page 26583]]
US DOI....................... US Department of Interior.
Utah Commission.............. Utah Public Service Commission.
VEIR......................... VEIR Inc.
Vermont Electric............. Vermont Electric Power Company.
Vistra....................... Vistra Corp.
WATT Coalition............... WATT Coalition.
WIRES........................ WIRES.
Xcel......................... Xcel Energy Services Inc.
------------------------------------------------------------------------
Appendix B: Pro Forma Open Access Transmission Tariff Attachment K
Note: Proposed deletions are in brackets and proposed additions
are in italics.
Attachment K
Transmission Planning Process
Local Transmission Planning
The Transmission Provider shall establish a coordinated, open,
and transparent local transmission planning process with its Network
and Firm Point-to-Point Transmission Customers and other interested
parties to ensure that the Transmission System is planned to meet
the needs of both the Transmission Provider and its Network and Firm
Point-to-Point Transmission Customers on a comparable and not unduly
discriminatory basis. The Transmission Provider's coordinated, open,
and transparent local transmission planning process shall be
provided as an attachment to the Transmission Provider's Tariff. The
Transmission Provider's local transmission planning process shall
satisfy the following nine principles, as defined in Order No. 890:
Coordination, openness, transparency, information exchange,
comparability, dispute resolution, regional participation, economic
planning studies, and cost allocation for new transmission projects.
The local transmission planning process also shall include the
procedures and mechanisms for considering transmission needs driven
by Public Policy Requirements consistent with Order No. 1000. The
local transmission planning process also shall provide a mechanism
for the recovery and allocation of transmission planning costs
consistent with Order No. 890. The description of the Transmission
Provider's local transmission planning process must include
sufficient detail to enable Transmission Customers to understand:
(i) The process for consulting with customers;
(ii) The notice procedures and anticipated frequency of
meetings;
(iii) The methodology, criteria, and processes used to develop a
transmission plan;
(iv) The method of disclosure of criteria, assumptions, and data
underlying a transmission plan;
(v) The obligations of and methods for Transmission Customers to
submit data to the Transmission Provider;
(vi) The dispute resolution process;
(vii) The Transmission Provider's study procedures for economic
upgrades to address congestion or the integration of new resources;
(viii) The Transmission Provider's procedures and mechanisms for
considering transmission needs driven by Public Policy Requirements,
consistent with Order No. 1000; and
(ix) The relevant cost allocation method or methods.
Regional Transmission Planning
The Transmission Provider shall participate in a regional
transmission planning process through which transmission facilities
and non-transmission alternatives may be proposed and evaluated. The
regional transmission planning process also shall develop a regional
transmission plan that identifies the transmission facilities
necessary to meet the needs of transmission providers and
transmission customers in the transmission planning region. The
regional transmission planning process must be consistent with the
provision of Commission-jurisdictional services at rates, terms, and
conditions that are just and reasonable and not unduly
discriminatory or preferential, as described in Order No. 1000 and
Order No. [final rule]. The regional transmission planning process
shall be described in an attachment to the Transmission Provider's
Tariff.
The Transmission Provider's regional transmission planning
process shall satisfy the following seven principles, as set out and
explained in Order Nos. 890 and 1000: Coordination, openness,
transparency, information exchange, comparability, dispute
resolution, and economic planning studies. The regional transmission
planning process also shall include the procedures and mechanisms
for considering transmission needs driven by Public Policy
Requirements, consistent with Order No. 1000. The regional
transmission planning process shall provide a mechanism for the
recovery and allocation of ``transmission planning costs''
consistent with Order No. 890 and Order No. 1000.
The regional transmission planning process shall include a clear
enrollment process for public and non-public utility transmission
providers that make the choice to become part of a transmission
planning region. The regional transmission planning process shall be
clear that enrollment will subject enrollees to cost allocation if
they are found to be beneficiaries of new transmission facilities
selected in the regional transmission plan for purposes of cost
allocation. Each Transmission Provider shall maintain a list of
enrolled entities in the Transmission Provider's Tariff.
As part of the regional transmission planning process, the
Transmission Providers in each transmission planning region will
conduct Long-Term Regional Transmission Planning, meaning regional
transmission planning on a sufficiently long-term, forward-looking
basis to identify transmission needs driven by changes in the
resource mix and demand, evaluate transmission facilities to meet
such needs, and identify and evaluate transmission facilities for
potential selection in the regional transmission plan for purposes
of cost allocation as the more efficient or cost-effective
transmission facilities to meet such needs. As part of this Long-
Term Regional Transmission Planning, the Transmission Providers in
each transmission planning region will: (1) Identify transmission
needs driven by changes in the resource mix and demand through the
development of Long-Term Scenarios that satisfy the requirements set
forth in Order No. [final rule]; (2) evaluate the benefits of
regional transmission facilities to meet transmission needs driven
by changes in the resource mix and demand over a time horizon that
covers, at a minimum, 20 years starting from the estimated in-
service date of the transmission facilities; and (3) establish
transparent and not unduly discriminatory criteria to select
transmission facilities in the regional transmission plan for
purposes of cost allocation that more efficiently or cost-
effectively address transmission needs driven by changes in the
resource mix and demand in collaboration with states and other
stakeholders.
When developing Long-Term Scenarios, the Transmission Providers
in each transmission planning region must: (1) Use a transmission
planning horizon no less than 20 years into the future; (2) reassess
and revise Long-Term Scenarios including to reassess whether the
data inputs and factors incorporated in their previously developed
Long-Term Scenarios need to be updated and then revise their Long-
Term Scenarios as needed to reflect updated data inputs and factors
at least every three years, and complete the development of Long-
Term Scenarios within three years, before the next three-year
assessment commences; (3) incorporate, at a minimum, the seven
categories of factors identified in Order No. [final rule] that may
drive transmission needs driven by changes in the resource mix and
demand; (4) develop a plausible and diverse set of at least four
Long-Term Scenarios; (5) use ``best available data'' (as defined in
Order No. [final rule]) in developing Long-Term Scenarios; and (6)
consider whether to identify geographic zones with the potential for
development of large amounts of new generation. The process through
which the Transmission Providers develop Long-Term Scenarios also
must comply with the
[[Page 26584]]
following six transmission planning principles established in Order
No. 890: Coordination; openness; transparency; information exchange;
comparability; and dispute resolution.
The Transmission Providers in each transmission planning region
must identify the benefits they will use in Long-Term Regional
Transmission Planning, how they will calculate those benefits, and
how the benefits will reasonably reflect the benefits of regional
transmission facilities to meet identified transmission needs driven
by changes in the resource mix and demand. The following set of
Long-Term Regional Transmission Benefits may be useful for
Transmission Providers in each transmission planning region in
evaluating transmission facilities for selection in the regional
transmission plan for purposes of cost allocation as the more
efficient or cost-effective solutions to meet transmission needs
driven by changes in the resource mix and demand: (1) Avoided or
deferred reliability transmission projects and aging infrastructure
replacement; (2) either reduced loss of load probability or reduced
planning reserve margin; (3) production cost savings; (4) reduced
transmission energy losses; (5) reduced congestion due to
transmission outages; (6) mitigation of extreme events and system
contingencies; (7) mitigation of weather and load uncertainty; (8)
capacity cost benefits from reduced peak energy losses; (9) deferred
generation capacity investments; (10) access to lower-cost
generation; (11) increased competition; and (12) increased market
liquidity.
Table 1--Long-Term Regional Transmission Benefits
------------------------------------------------------------------------
Benefit Description
------------------------------------------------------------------------
Avoided or deferred reliability Reduced costs of avoided or
transmission facilities and aging delayed transmission
transmission infrastructure investment otherwise required
replacement. to address reliability needs
or replace aging transmission
facilities.
Reduced loss of load probability [OR Reduced frequency of loss of
next benefit]. load events by providing
additional pathways for
connecting generation
resources with load (if
planning reserve margin is
constant), resulting in
benefit of reduced expected
unserved energy by customer
value of lost load.
Reduced planning reserve margin [OR While holding loss of load
prior benefit]. probabilities constant, system
operators can reduce their
resource adequacy requirements
(i.e., planning reserve
margins), resulting in a
benefit of reduced capital
cost of generation needed to
meet resource adequacy
requirements.
Production cost savings................ Reduction in production costs,
including savings in fuel and
other variable operating costs
of power generation, that are
realized when transmission
facilities allow for the
increased dispatch of
suppliers that have lower
incremental costs of
production, displacing higher-
cost supplies; also reduction
in market prices as lower-cost
suppliers set market clearing
prices; when adjusted to
account for purchases and
sales outside the region,
called adjusted production
cost savings.
Reduced transmission energy losses..... Reduced energy losses incurred
in transmittal of power from
generation to loads, thereby
reducing total energy
necessary to meet demand.
Reduced congestion due to transmission Reduced production costs during
outages. transmission outages that
significantly increase
transmission congestion.
Mitigation of extreme events and system Reduced production costs during
contingencies. extreme events, such as
unusual weather conditions,
fuel shortages, and multiple
or sustained generation and
transmission outages, through
more robust transmission
system reducing high-cost
generation and emergency
procurements necessary to
support the system.
Mitigation of weather and load Reduced production costs during
uncertainty. higher than normal load
conditions or significant
shifts in regional weather
patterns.
Capacity cost benefits from reduced Reduced energy losses during
peak energy losses. peak load reduces generation
capacity investment needed to
meet the peak load and
transmission losses.
Deferred generation capacity Reduced costs of needed
investments. generation capacity
investments through expanded
import capability into
resource-constrained areas.
Access to lower-cost generation........ Reduced total cost of
generation due to ability to
locate units in a more
economically efficient
location (e.g., low permitting
costs, low-cost sites on which
plants can be built, access to
existing infrastructure, low
labor costs, low fuel costs,
access to valuable natural
resources, locations with high-
quality renewable energy
resources).
Increased competition.................. Reduced bid prices in wholesale
electricity markets due to
increased competition among
generators and reduced overall
market concentration/market
power.
Increased market liquidity............. Reduced transaction costs
(e.g., bid-ask spreads) of
bilateral transactions,
increased price transparency,
increased efficiency of risk
management, improved
contracting, and better
clarity for long-term
transmission planning and
investment decisions through
increased number of buyers and
sellers able to transact with
each other as a result of
transmission expansion.
------------------------------------------------------------------------
As part of Long-Term Regional Transmission Planning, the
Transmission Providers in each transmission planning region must
include (1) transparent and not unduly discriminatory criteria,
which seek to maximize benefits to consumers over time without over-
building transmission facilities, to identify and evaluate
transmission facilities for potential selection in the regional
transmission plan for purposes of cost allocation that address
transmission needs driven by changes in the resource mix and demand;
and (2) a process to coordinate with relevant state entities in
developing such criteria.
If the Transmission Providers include a portfolio approach in
selecting transmission facilities in the regional transmission plan
for
[[Page 26585]]
purposes of cost allocation that address transmission needs driven
by changes in the resource mix and demand, then the Transmission
Providers must include provisions describing whether the selection
criteria would be used for Long-Term Regional Transmission Planning
universally to address transmission needs driven by changes in the
resource mix and demand or would be used only in certain specified
instances.
The Transmission Providers in each transmission planning region
shall include in their tariffs either (1) a Long-Term Regional
Transmission Cost Allocation Method to allocate the costs of Long-
Term Regional Transmission Facilities, or (2) a State Agreement
Process by which one or more relevant state entities may voluntarily
agree to a cost allocation method, or (3) a combination thereof. A
Long-Term Regional Transmission Cost Allocation Method is an ex ante
regional cost allocation method that applies to a transmission
facility identified as part of Long-Term Regional Transmission
Planning and selected in the regional transmission plan for purposes
of cost allocation to address transmission needs driven by changes
in the resource mix and demand (Long-Term Regional Transmission
Facility). The developer of a Long-Term Regional Transmission
Facility would be entitled to use the Long-Term Regional
Transmission Cost Allocation Method if it is the applicable cost
allocation method. A State Agreement Process is an ex post cost
allocation process, which may apply to an individual Long-Term
Regional Transmission Facility or a portfolio of such Facilities
grouped together for purposes of cost allocation. After a Long-Term
Regional Transmission Facility is selected in the regional
transmission plan for purposes of cost allocation, the State
Agreement Process would be followed to establish a cost allocation
method for that facility (if agreement can be reached). If the
Commission subsequently approves the cost allocation method that
results from the State Agreement Process, the developer of the Long-
Term Regional Transmission Facility would be entitled to use that
cost allocation method if it is the applicable method. The Long-Term
Regional Transmission Cost Allocation Method and any cost allocation
method resulting from the State Agreement Process for Long-Term
Regional Transmission Facilities must comply with the existing six
Order No. 1000 regional cost allocation principles.
Transmission Providers in each transmission planning region must
seek the agreement of relevant state entities within the
transmission planning region regarding the Long-Term Regional
Transmission Cost Allocation Method, State Agreement Process.
The regional transmission planning processes must give a state
or states a period of time to negotiate a cost allocation method for
a transmission facility that is selected in the Long Term Regional
Transmission Plan for purposes of cost allocation to address
transmission needs driven by changes in the resource mix and demand
that is different than the regional cost allocation method
(alternate cost allocation method related to transmission needs
driven by changes in the resource mix and demand).
The Transmission Providers in each transmission planning region
shall consider in regional transmission planning and cost allocation
processes whether selecting transmission facilities in the regional
transmission plan for purposes of cost allocation that incorporate
dynamic line ratings, as defined in 18 CFR 35.28(b)(14), or advanced
power flow control devices would be more efficient or cost-effective
than regional transmission facilities that do not incorporate these
technologies. Specifically, such consideration must include both:
(1) First, whether incorporating dynamic line ratings or advanced
power flow control devices into existing transmission facilities
could meet the same regional transmission need more efficiently or
cost-effectively than other potential transmission facilities; and
(2) second, when evaluating transmission facilities for potential
selection in the regional transmission plan for purposes of cost
allocation, the Transmission Providers in each transmission planning
region must also consider whether incorporating dynamic line ratings
and advanced power flow control devices as part of any potential
regional transmission facility would be more efficient of cost-
effective.
This requirement applies in all of the Transmission Provider's
regional transmission planning processes, including the regional
transmission planning processes for near-term regional transmission
needs and Long-Term Regional Transmission Planning required in Order
No. [final rule]. The costs of transmission facilities that
incorporate dynamic line ratings or advanced power flow control
devices that are selected in the regional transmission plan for
purposes of cost allocation will be allocated using the applicable
regional cost allocation method. The Transmission Provider's
evaluation process must culminate in a determination that is
sufficiently detailed for stakeholders to understand why a
particular transmission facility was selected or not selected in the
regional transmission plan for purposes of cost allocation. This
process must include the consideration of dynamic line ratings and
advanced power flow control devices and why they were not
incorporated into selected regional transmission facilities.
The description of the regional transmission planning process
must include sufficient detail to enable Transmission Customers to
understand:
(i) The process for enrollment in the regional transmission
planning process;
(ii) The process for consulting with customers;
(iii) The notice procedures and anticipated frequency of
meetings;
(iv) The methodology, criteria, and processes used to develop a
transmission plan;
(v) The method of disclosure of criteria, assumptions, and data
underlying a transmission plan;
(vi) The obligations of and methods for transmission customers
to submit data;
(vii) The process for submission of data by nonincumbent
developers of transmission projects that wish to participate in the
regional transmission planning process and seek regional cost
allocation;
(viii) The process for submission of data by merchant
transmission developers that wish to participate in the regional
transmission planning process;
(ix) The dispute resolution process;
(x) The study procedures for economic upgrades to address
congestion or the integration of new resources; and
[The procedures and mechanisms for considering transmission
needs driven by Public Policy Requirements, consistent with Order
No. 1000; and]
(xi) The relevant cost allocation method or methods.
The regional transmission planning process must include a cost
allocation method or methods that satisfy the six regional cost
allocation principles set forth in Order No. 1000.
Enhanced Transparency of Local Transmission Planning Inputs in the
Regional Transmission Planning Process
The regional transmission planning process must include at least
three stakeholder meetings concerning the local transmission
planning process of each Transmission Provider that is a member of
the transmission planning region before each Transmission Provider's
local transmission planning information can be incorporated into the
transmission planning region's planning models:
(1) A stakeholder meeting to review the criteria, assumptions,
and models related to each Transmission Provider's local
transmission planning (Assumptions Meeting);
(2) No fewer than 25 calendar days after the Assumptions
Meeting, a stakeholder meeting to review identified reliability
criteria violations and other transmission needs that drive the need
for local transmission facilities (Needs Meeting); and
(3) No fewer than 25 calendar days after the Needs Meeting, a
stakeholder meeting to review potential solutions to those
reliability criteria violations and other transmission needs
(Solutions Meeting).
Identifying Potential Opportunities to Right-Size Replacement
Transmission Facilities
As part of each Long-Term Regional Transmission Planning cycle,
Transmission Providers in each transmission planning region shall
evaluate whether transmission facilities operating at or above 230
kV that an individual Transmission Provider that owns the
transmission facility anticipates replacing in-kind with a new
transmission facility during the next 10 years can be ``right-
sized'' to more efficiently or cost-effectively address regional
transmission needs identified in Long-Term Regional Transmission
Planning. ``Right-sizing'' means the process of modifying a
Transmission Provider's in-kind replacement of an existing
transmission facility to increase that facility's transfer
capability. The process to identify potential opportunities to
right-size replacement transmission facilities must follow the
process outlined in Order No. [final rule].
[[Page 26586]]
Interregional Transmission Coordination
The Transmission Provider, through its regional transmission
planning process, must coordinate with the public utility
transmission providers in each neighboring transmission planning
region within its interconnection to address transmission planning
coordination issues related to interregional transmission
facilities. The interregional transmission coordination procedures
must include a detailed description of the process for coordination
between public utility transmission providers in neighboring
transmission planning regions (i) with respect to each interregional
transmission facility that is proposed to be located in both
transmission planning regions and (ii) to identify possible
interregional transmission facilities that could address
transmission needs more efficiently or cost-effectively than
separate regional transmission facilities. The interregional
transmission coordination procedures shall be described in an
attachment to the Transmission Provider's Tariff.
The Transmission Provider must ensure that the following
requirements are included in any applicable interregional
transmission coordination procedures:
(1) A commitment to coordinate and share the results of each
transmission planning region's regional transmission plans
(including information regarding the respective transmission needs
identified in Long-Term Regional Transmission Planning and potential
transmission facilities to meet those needs) to identify possible
interregional transmission facilities that could address
transmission needs more efficiently or cost-effectively than
separate regional transmission facilities, as well as a procedure
for doing so;
(2) A formal procedure to identify and jointly evaluate
transmission facilities that are proposed to be located in both
transmission planning regions, including those that may be more
efficient or cost-effective transmission solutions to transmission
needs identified through Long-Term Regional Transmission Planning;
(3) An agreement to exchange, at least annually, planning data
and information; and
(4) A commitment to maintain a website or email list for the
communication of information related to the coordinated planning
process.
The Transmission Provider must work with transmission providers
located in neighboring transmission planning regions to develop a
mutually agreeable method or methods for allocating between the two
transmission planning regions the costs of a new interregional
transmission facility that is located within both transmission
planning regions. Such cost allocation method or methods must
satisfy the six interregional cost allocation principles set forth
in Order No. 1000 and must be included in the Transmission
Provider's Tariff.
Appendix C: Pro Forma LGIP
Note: Proposed deletions are in brackets and proposed additions
are in italics.
Standard Large Generator Interconnection Procedures (LGIP) Including
Standard Large Generator Interconnection Agreement (LGIA); Standard
Large Generator Interconnection Procedures (LGIP) (Applicable to
Generating Facilities That Exceed 20 MW)
Table of Contents
Section 1. Definitions
Section 2. Scope and Application
2.1 Application of Standard Large Generator Interconnection
Procedures
2.2 Comparability
2.3 Base Case Data
2.4 No Applicability to Transmission Service
Section 3. Interconnection Requests
3.1 General
3.2 Identification of Types of Interconnection Services
3.2.1 Energy Resource Interconnection Service
3.2.1.1 The Product
3.2.1.2 The Study
3.2.2 Network Resource Interconnection Service
3.2.2.1 The Product
3.2.2.2 The Study
3.3 Utilization of Surplus Interconnection Service
3.3.1 Surplus Interconnection Service Request
3.4 Valid Interconnection Request
3.4.1 Initiating an Interconnection Request
3.4.2 Acknowledgment of Interconnection Request
3.4.3 Deficiencies in Interconnection Request
3.4.4 Scoping Meeting
3.5 OASIS Posting
3.5.1
3.5.2 Requirement to Post Interconnection Study Metrics
3.5.2.1 Interconnection Feasibility Studies Processing Time
3.5.2.2 Interconnection System Impact Studies Time
3.5.2.3 Interconnection Facilities Studies Processing Time
3.5.2.4 Interconnection Service Requests Withdrawn From
Interconnection Queue
3.6 Coordination With Affected Systems
3.7 Withdrawal
3.8 Identification of Contingent Facilities
3.10 Repeat Network Upgrades for Consideration in the Regional
Transmission Planning Process
Section 4. Queue Position
4.1 General
4.2 Clustering
4.3 Transferability of Queue Position
4.4 Modifications
Section 5. Procedures for Interconnection Requests Submitted Prior
to Effective Date of Standard Large Generator Interconnection
Procedures
5.1 Queue Position for Pending Requests
5.2 New Transmission Provider
Section 6. Interconnection Feasibility Study
6.1 Interconnection Feasibility Study Agreement
6.2 Scope of Interconnection Feasibility Study
6.3 Interconnection Feasibility Study Procedures
6.4 Re-Study
Section 7. Interconnection System Impact Study
7.1 Interconnection System Impact Study Agreement
7.2 Execution of Interconnection System Impact Study Agreement
7.3 Scope of Interconnection System Impact Study
7.4 Interconnection System Impact Study Procedures
7.5 Meeting With Transmission Provider
7.6 Re-Study
Section 8. Interconnection Facilities Study
8.1 Interconnection Facilities Study Agreement
8.2 Scope of Interconnection Facilities Study
8.3 Interconnection Facilities Study Procedures
8.4 Meeting With Transmission Provider
8.5 Re-Study
Section 9. Engineering & Procurement (`E&P') Agreement
Section 10. Optional Interconnection Study
10.1 Optional Interconnection Study Agreement
10.2 Scope of Optional Interconnection Study
10.3 Optional Interconnection Study Procedures
Section 11. Standard Large Generator Interconnection Agreement
(LGIA)
11.1 Tender
11.2 Negotiation
11.3 Execution and Filing
11.4 Commencement of Interconnection Activities
Section 12. Construction of Transmission Provider's Interconnection
Facilities and Network Upgrades
12.1 Schedule
12.2 Construction Sequencing
12.2.1 General
12.2.2 Advance Construction of Network Upgrades That Are an
Obligation of an Entity Other Than Interconnection Customer
12.2.3 Advancing Construction of Network Upgrades That Are Part
of an Expansion Plan of the Transmission Provider
12.2.4 Amended Interconnection System Impact Study
Section 13. Miscellaneous
13.1 Confidentiality
13.1.1 Scope
13.1.2 Release of Confidential Information
13.1.3 Rights
13.1.4 No Warranties
13.1.5 Standard of Care
13.1.6 Order of Disclosure
13.1.7 Remedies
13.1.8 Disclosure to FERC or Its Staff
13.2 Delegation of Responsibility
13.3 Obligation for Study Costs
13.4 Third Parties Conducting Studies
13.5 Disputes
13.5.1 Submission
13.5.2 External Arbitration Procedures
13.5.3 Arbitration Decisions
13.5.4 Costs
13.5.5 Non-Binding Dispute Resolution Procedures
13.6 Local Furnishing Bonds
[[Page 26587]]
13.6.1 Transmission Providers That Own Facilities Financed by
Local Furnishing Bonds
13.6.2 Alternative Procedures for Requesting Interconnection
Service
Appendix 1--Interconnection Request for a Large Generating Facility
Appendix 2--Interconnection Feasibility Study Agreement
Appendix 3--Interconnection System Impact Study Agreement
Appendix 4--Interconnection Facilities Study Agreement
Appendix 5--Optional Interconnection Study Agreement
Appendix 6--Standard Large Generator Interconnection Agreement
Appendix 7--Interconnection Procedures for a Wind Generating Plant
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 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, and the
Control Area of the Transmission System to which the Generating
Facility is directly interconnected.
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.
Clustering shall mean the process whereby a group of
Interconnection Requests is studied together, instead of serially,
for the purpose of conducting the Interconnection System Impact
Study.
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 Re-Studies 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.
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 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
[[Page 26588]]
not include acts of negligence or intentional wrongdoing by the
Party claiming Force Majeure.
Generating Facility shall mean 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.
Generating Facility Capacity shall mean the net capacity of the
Generating Facility and the aggregate net capacity of the Generating
Facility where it includes multiple energy production devices.
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
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 Standard Large Generator Interconnection
Procedures.
Interconnection Facilities Study Agreement shall mean the form
of agreement contained in Appendix 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 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, and the Interconnection Facilities Study described in
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.
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 a later 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
[[Page 26589]]
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 5 of 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].
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.
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 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 and Transmission Provider conducted
for the purpose of discussing alternative interconnection options,
to exchange information including any transmission data and earlier
study evaluations that would be reasonably expected to impact such
interconnection options, to analyze such information, and to
determine the potential feasible Points of Interconnection.
Site Control shall mean documentation reasonably demonstrating:
(1) Ownership of, a leasehold interest in, or a right to develop a
site for the purpose of constructing the Generating Facility; (2) an
option to purchase or acquire a leasehold site for such purpose; or
(3) 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.
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. 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.
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 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
[[Page 26590]]
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.
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 in
processing and analyzing Interconnection Requests from all
Interconnection Customers, 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 (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
An Interconnection Customer shall submit to Transmission
Provider an Interconnection Request in the form of Appendix 1 to
this LGIP and a refundable deposit of $10,000. Transmission Provider
shall apply the deposit toward the cost of an Interconnection
Feasibility Study. 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. 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 Scoping Meeting 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.
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.
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 Facility 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 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 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
[[Page 26591]]
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, 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 Requests
Surplus Interconnection Service requests may be made by the
existing Interconnection Customer whose Generating Facility is
already interconnected or one of its affiliates. 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 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.
3.4 Valid Interconnection Request
3.4.1 Initiating an Interconnection Request
To initiate an Interconnection Request, Interconnection Customer
must submit all of the following: (i) A $10,000 deposit, (ii) a
completed application in the form of Appendix 1, and (iii)
demonstration of 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.
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 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 Deficiencies in Interconnection Request
An Interconnection Request will not be considered to be a valid
request until all items in Section 3.4.1 have been received by
Transmission Provider. If an Interconnection Request fails to meet
the requirements set forth in Section 3.4.1, 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. Failure by Interconnection Customer to
comply with this Section 3.4.3 shall be treated in accordance with
Section 3.7.
3.4.4 Scoping Meeting
Within ten (10) Business Days after receipt of a valid
Interconnection Request, Transmission Provider shall establish a
date agreeable to Interconnection Customer for the Scoping Meeting,
and such date shall be no later than thirty (30) Calendar Days from
receipt of the valid Interconnection Request, unless otherwise
mutually agreed upon by the Parties.
The purpose of the Scoping Meeting shall be to discuss
alternative interconnection options, to exchange information
including any transmission data that would reasonably be expected to
impact such interconnection options, to analyze such information and
to determine the potential feasible Points of Interconnection.
Transmission Provider and Interconnection Customer 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 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 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.
3.5. OASIS Posting
3.5.1
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 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.
[[Page 26592]]
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 3.5.2.1
through 3.5.2.4.
3.5.2.1 Interconnection Feasibility Studies Processing Time
(A) Number of Interconnection Requests that had Interconnection
Feasibility Studies completed within Transmission Provider's
coordinated region during the reporting quarter,
(B) Number of Interconnection Requests that had Interconnection
Feasibility 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] after
receipt by Transmission Provider of the Interconnection Customer's
executed Interconnection Feasibility Study Agreement,
(C) At the end of the reporting quarter, the number of active
valid Interconnection Requests with ongoing incomplete
Interconnection Feasibility Studies where such Interconnection
Requests had executed Interconnection Feasibility Study Agreements
received by Transmission Provider more than [timeline as listed in
Transmission Provider's LGIP] before the reporting quarter end,
(D) Mean time (in days), Interconnection Feasibility 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 to
the date when Transmission Provider provided the completed
Interconnection Feasibility Study to the Interconnection Customer,
(E) Percentage of Interconnection Feasibility Studies exceeding
[timeline as listed in Transmission Provider's LGIP] 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 Processing Time
(A) Number of Interconnection Requests that had Interconnection
System Impact Studies completed within Transmission Provider's
coordinated region during the reporting quarter,
(B) Number of Interconnection Requests that had Interconnection
System Impact 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] after
receipt by Transmission Provider 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 where such Interconnection Requests had executed
Interconnection System Impact Study Agreements received by
Transmission Provider more than [timeline as listed in Transmission
Provider's LGIP] before the reporting quarter end,
(D) Mean time (in days), Interconnection System Impact Studies
completed within Transmission Provider's coordinated region during
the reporting quarter, from the date when Transmission Provider
received the executed Interconnection System Impact Study Agreement
to the date when Transmission Provider provided the completed
Interconnection System Impact Study to the Interconnection Customer,
(E) Percentage of Interconnection System Impact Studies
exceeding [timeline as listed in Transmission Provider's LGIP] 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] 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] 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) 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,
(C) Number of Interconnection Requests withdrawn from
Transmission Provider's interconnection queue during the reporting
quarter before completion of an Interconnection System Impact 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 study or group of clustered studies
pursuant to an Interconnection Request that exceeded its deadline
(i.e., 45, 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.
[[Page 26593]]
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 (if available) 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 in all matters related to the conduct of studies and the
determination of modifications to Affected Systems. A Transmission
Provider which may be an Affected System shall cooperate with
Transmission Provider with whom interconnection has been requested
in all matters related to the conduct of studies and the
determination of modifications to Affected Systems.
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.
Transmission Provider shall (i) update the OASIS Queue Position
posting and (ii) refund to Interconnection Customer any portion of
Interconnection Customer's 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. In the event of such withdrawal, Transmission
Provider, subject to the confidentiality provisions of Section 13.1,
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.
3.8 Identification of Contingent Facilities
Transmission Provider shall post in this section a method for
identifying the Contingent Facilities to be provided to
Interconnection Customer at the conclusion of the System Impact
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.
3.10 Repeat Network Upgrades for Consideration in the Regional
Transmission Planning Process
If Transmission Provider: (1) Identifies a Network Upgrade with
an interconnection study estimated cost of at least $30 million or
with a voltage of at least 200 kV as necessary to accomplish an
interconnection and the underlying interconnection request related
to such Network Upgrade is withdrawn; (2) if, within five years of
that withdrawal, Transmission Provider identifies a Network Upgrade
with an interconnection study estimated cost of at least $30 million
or with a voltage of at least 200 kV to address a similar
interconnection-related need as specified in (1) and the underlying
interconnection request with cost responsibility for the second
identified Network Upgrade is withdrawn; and (3) a similar
interconnection-related need is not addressed by any Network Upgrade
described in Appendix A of any executed Large Generator
Interconnection Agreement or any Large Generator Interconnection
Agreement that an Interconnection Customer has requested that
Transmission Provider file with the Commission unexecuted, then
Transmission Provider shall consider the interconnection-related
need addressed by the Network Upgrade(s) that Transmission Provider
identified in the interconnection queue cycles specified in (1) and
(2) in Long-Term Regional Transmission Planning.
Section 4. Queue Position
4.1 General
Transmission Provider shall assign a Queue Position 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
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.
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 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.
Clustering Interconnection System Impact Studies 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.
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.
4.3 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.
[[Page 26594]]
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, or are determined not to be Material
Modifications pursuant to Section 4.4.3.
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 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 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) 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 the end of the queue for the
purposes of cost allocation and study analysis.
4.4.2
Prior to the return of the executed Interconnection Facility
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, 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
4.4.1, 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.
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.
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.
4.4.6 Technological Change Procedures
[Insert technological change procedure here]
Section 5. Procedures for Interconnection Requests Submitted Prior to
Effective Date of Standard Large Generator Interconnection Procedures
5.1 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.
5.1.1.1
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.
5.1.1.2
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.
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
[[Page 26595]]
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 Feasibility Study
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 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 Interconnection
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 Study
7.1 Interconnection System Impact 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,
Transmission Provider shall provide to Interconnection Customer an
Interconnection System Impact Study Agreement in the form of
Appendix 3 to this LGIP. The Interconnection System Impact Study
Agreement shall provide that Interconnection Customer shall
compensate Transmission Provider for the actual cost of the
Interconnection System Impact Study. 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 Study Agreement
Interconnection Customer shall execute the Interconnection
System Impact Study Agreement and deliver the executed
Interconnection System Impact 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.
If Interconnection Customer does not provide all such technical
data when it delivers the Interconnection System Impact 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 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 Study Agreement or 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
[[Page 26596]]
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, as
specified pursuant to Section 3.4.4, shall be the substitute.
7.3 Scope of Interconnection System Impact Study
The Interconnection System Impact Study shall evaluate the
impact of the proposed interconnection on the reliability of the
Transmission System. The Interconnection System Impact 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 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 System Impact Study will consist of a short
circuit analysis, a stability analysis, and a power flow analysis.
The Interconnection System Impact Study 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
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. The Interconnection System Impact Study will provide a
list of facilities that are required as a result of the
Interconnection Request and a non-binding good faith estimate of
cost responsibility and a non-binding good faith estimated time to
construct.
7.4 Interconnection System Impact Study Procedures
Impact Study with any Affected System that is affected by the
Interconnection Request pursuant to Section 3.6 above. 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 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.
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 Study,
Transmission Provider shall notify Interconnection Customer as to
the schedule status of the Interconnection System Impact Study. If
Transmission Provider is unable to complete the Interconnection
System Impact Study within the 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 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 Study, subject to confidentiality arrangements consistent
with Section 13.1.
7.5 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, Transmission Provider
shall provide to Interconnection Customer an Interconnection
Facilities Study Agreement in the form of Appendix 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
three (3) Business Days following the 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 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.
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 specify and estimate
the cost of the equipment, engineering, procurement and construction
work needed to implement the conclusions of the Interconnection
System Impact Study in accordance with Good Utility Practice to
physically and electrically connect the Interconnection Facility 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 Facilities Study will also identify any potential control
equipment for requests for Interconnection Service that are lower
than the Generating Facility Capacity.
8.3 Interconnection Facilities Study Procedures
Transmission Provider shall coordinate the Interconnection
Facilities Study with any Affected System pursuant to Section 3.6
above. 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 report to Interconnection Customer within the following number
of days after receipt of an executed 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, 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
report within the time required, it
[[Page 26597]]
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 report, provide written comments to
Transmission Provider, which Transmission Provider shall include in
the final report. Transmission Provider shall issue the final
Interconnection Facilities Study 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 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
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.
8.4 Meeting With Transmission Provider
Within ten (10) Business Days of providing a draft
Interconnection Facilities Study report to Interconnection Customer,
Transmission Provider and Interconnection Customer shall meet to
discuss the results of the Interconnection Facilities Study.
8.5 Re-Study
If Re-Study of the Interconnection Facilities Study is required
due to a higher queued project dropping out of the queue or a
modification of a higher queued project pursuant to Section 4.4,
Transmission Provider shall so 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 9. 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 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
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 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 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, Transmission Provider shall tender
a draft LGIA, together with draft appendices. The draft LGIA shall
be in the
[[Page 26598]]
form of Transmission Provider's FERC-approved standard form LGIA,
which is in Appendix 6. Interconnection Customer shall execute and
return the completed draft appendices within thirty (30) Calendar
Days.
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.
11.3 Execution and Filing
Within fifteen (15) Business Days after receipt of the final
LGIA, Interconnection Customer shall provide Transmission Provider
(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. 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: (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 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 Study
An Interconnection System Impact Study will be amended to
determine the facilities necessary to support the requested In-
Service Date. This amended study will include those transmission and
Large Generating Facilities that are expected to be in service 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
[[Page 26599]]
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 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 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, consistent with applicable state rules
and regulations.
13.1.9
Subject to the exception in Section 13.1.8, 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
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,
[[Page 26600]]
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 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
Transmission Provider shall charge and Interconnection Customer
shall pay the actual costs of the Interconnection Studies. 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 or
offset against the cost of any future Interconnection Studies
associated with the applicable Interconnection Request 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 shall pay any such undisputed costs within
thirty (30) Calendar Days of receipt of an invoice therefor.
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.
13.5.5 Non-Binding Dispute Resolution Procedures
If a Party has submitted a Notice of Dispute pursuant to section
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 section 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
[[Page 26601]]
agreement to pursue the section 13.5 arbitration process. The
process in section 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 section 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.
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. This Interconnection Request is for (check one):
__ A proposed new Large Generating Facility.
__ An increase in the generating capacity or a Material Modification
of an existing Generating Facility.
3. The type of interconnection service requested (check one):
__ Energy Resource Interconnection Service
__ 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
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) and
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).
6. Applicable deposit amount as specified in the LGIP.
7. Evidence of Site Control as specified in the LGIP (check one)
__ Is attached to this Interconnection Request
__ Will be provided at a later date in accordance with this LGIP
8. This Interconnection Request shall be submitted to the
representative indicated below: [To be completed by Transmission
Provider]
9. Representative of Interconnection Customer to contact: [To be
completed by Interconnection Customer]
10. This Interconnection Request is submitted by:
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 ___
------------------------------------------------------------------------
[[Page 26602]]
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:--------------------------------------------------
(*) 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.
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 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 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 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:
[[Page 26603]]
--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 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 2--Interconnection Feasibility Study Agreement
Assumptions Used in Conducting the Interconnection Feasibility Study
The 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]
Appendix 3 to LGIP--Interconnection System Impact 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
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 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
Transmission Provider's FERC-approved LGIP.
2.0 Interconnection Customer elects and Transmission Provider
shall cause to be performed an Interconnection System Impact Study
consistent with Section 7.0 of this LGIP in accordance with the
Tariff.
3.0 The scope of the Interconnection System Impact Study shall
be subject to the assumptions set forth in Attachment A to this
Agreement.
4.0 The Interconnection System Impact 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 the 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 Study. If Interconnection
Customer modifies its designated Point of Interconnection,
Interconnection Request, or the technical information provided
therein is modified, the time to complete the Interconnection System
Impact Study may be extended.
5.0 The Interconnection System Impact 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
--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 Study is [insert
date].
Upon receipt of the Interconnection System Impact Study,
Transmission Provider shall charge and Interconnection Customer
shall pay the actual costs of the Interconnection System Impact
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 System Impact 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 the LGIP and the 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]
By:--------------------------------------------------------------------
Title:-----------------------------------------------------------------
Date:------------------------------------------------------------------
By:--------------------------------------------------------------------
Title:-----------------------------------------------------------------
Date:------------------------------------------------------------------
[Insert name of Interconnection Customer]
By:--------------------------------------------------------------------
Title:-----------------------------------------------------------------
Date:------------------------------------------------------------------
Attachment A To Appendix 3--Interconnection System Impact Study
Agreement
Assumptions Used in Conducting the Interconnection System Impact Study
The Interconnection System Impact Study will be based upon the
results of the Interconnection Feasibility Study, subject to any
modifications in accordance with
[[Page 26604]]
Section 4.4 of the 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]
Appendix 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 Study (the ``System Impact 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 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 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 Study.
5.0 Interconnection Customer shall provide a 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 Facility 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 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 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 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 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
Generation Testing-----------------------------------------------------
Date:------------------------------------------------------------------
Commercial Operation
Date:------------------------------------------------------------------
[[Page 26605]]
Appendix 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 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 6 to LGIP--Large Generator Interconnection Agreement (See
LGIA)
Appendix 7--Interconnection Procedures for a Wind Generating Plant
Appendix 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 section 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 Study.
United States of America--Federal Energy Regulatory Commission
Building for the Future Through Electric Regional Transmission
Planning and Cost Allocation and Generator Interconnection
Docket No. RM21-17-000
(Issued April 21, 2022)
DANLY, Commissioner, dissenting:
1. I welcome long term transmission planning reform. I would
prefer that Regional Transmission Organizations (RTOs) and other
interested public utilities simply file their own proposals under
section 205 of the Federal Power Act (FPA). They are fully capable
of proposing rate changes and reforms on their own.\1\
---------------------------------------------------------------------------
\1\ See, e.g., New England Power Pool Participants Committee
October 12, 2021 Comments at 4-8 (detailing past and current
transmission planning activities).
---------------------------------------------------------------------------
2. This Notice of Proposed Rulemaking (NOPR) goes far beyond
that. It contemplates a Federal Power Act section 206 finding that
existing transmission planning across the nation--in every region,
for every utility and market--is so unjust and unreasonable that it
must be replaced with mandatory, pervasive, and invasive
``reforms.'' \2\ But let us be clear. The NOPR's primary purpose is
to achieve narrow environmental policy objectives, not to address
legitimate requirements under the Federal Power Act like ensuring
just and reasonable rates or reliability. After all, as the NOPR
itself repeatedly admits, it is ``driven by changes in resource mix
and demand,'' \3\ notwithstanding its references to genuine problems
with existing transmission planning.\4\
---------------------------------------------------------------------------
\2\ Building for the Future Through Elec. Reg'l Transmission
Planning & Cost Allocation & Generator Interconnection, 179 FERC ]
61,028 (2022) (``NOPR''); see also Building for the Future Through
Elec. Reg'l Transmission Planning & Cost Allocation & Generator
Interconnection, 176 FERC ] 61,024 (2021) (``ANOPR'').
\3\ The NOPR uses the phrase ``driven by changes in the resource
mix and demand'' 116 times. These are code words for ``renewables.''
See NOPR, 179 FERC ] 61,028 at P 45 (detailing ``[t]hese changes in
the resource mix and demand,'' almost all of which involve the
transition to renewable resources).
\4\ See id. PP 37-41, 48-49. Nearly every other preliminary
finding related to current transmission planning is tied to
``changes in the resource mix and demand.''
---------------------------------------------------------------------------
3. The majority seeks to establish policies designed to
encourage the massive transmission build-out that will doubtless be
required to transition to an aspirational renewable future. To do
so, they need to socialize the costs of this transmission across as
broad a population of ratepayers as possible. Thus, they seek to use
the FPA, a statute that sounds in rate regulation and reliability,
as a tool to achieve a particular (and inapposite) policy goal. In
this regard, it is much like the majority's recent foray into
transforming our pipeline certification process into a comprehensive
environmental review.\5\ Accordingly, I must dissent.
---------------------------------------------------------------------------
\5\ See Certification of New Interstate Nat. Gas Facilities, 178
FERC ] 61,107, order dismissing reh'g requests, Certification of New
Interstate Nat. Gas Facilities, 179 FERC ] 61,012 (2022); see also
Certification of New Interstate Nat. Gas Facilities, 178 FERC ]
61,197 (2022).
---------------------------------------------------------------------------
[[Page 26606]]
4. I normally would not oppose a NOPR. What is wrong with asking
questions and seeking a record to consider reforms? But this NOPR is
a boondoggle. It seeks to change virtually all aspects of
transmission planning, including in non-RTO regions and it does so
for the specific, though unstated, purpose of suborning the
transmission planning process so it can be wielded as a tool to
support the development of a specific set of favored generation
resources. How does it do this? The NOPR proposes to require regions
to factor in any state or even ``local'' (!) public policy (read,
renewable) goals, no matter how far-fetched.\6\ If San Francisco,
for example, passes an ordinance that all its energy must be solar
no matter the cost, CAISO and perhaps all western regional planning
now must take that into account in their transmission plans. And
what if the local policy is unreasonable? Or what if a state has far
more aggressive goals than another state? No matter: All must plan
for the dreams of others.
---------------------------------------------------------------------------
\6\ NOPR, 179 FERC ] 61,028 at PP 104, 106.
---------------------------------------------------------------------------
5. The Federal Power Act requires just and reasonable rates.
That prohibits the Commission from charging ratepayers for unneeded
transmission projects to accommodate someone else's view of what
types of generation might be preferable. And we are not talking
about economic or reliability projects. The transmission at issue
here is that required to accommodate state and local laws
establishing the composition of their generation fleets. Choosing
their own generation mix is undoubtedly their right, since such
choices are unambiguously reserved to the states under the FPA, but
the FPA does not require the Commission to accommodate these
policies under either of its core statutory obligations: To ensure
just and reasonable rates and to ensure reliability. In fact, it is
quite the opposite, the NOPR risks further undue discrimination.
Nevertheless, the NOPR starts from the premise that such projects
must be considered in regional planning.
6. Even if no transmission projects are ever selected under the
new regional planning regime, the process imposed by the NOPR itself
will substantially increase customer costs. As Arizona's largest
utility commented in the record, ``[w]hile [Arizona Public Service
Company] acknowledges the Commission's desire to construct
transmission for a quicker transition to a clean energy mix,
unbound[ed] study work would lengthen timelines, thereby increasing
the associated costs, for both the transmission planning process and
the generator interconnection process.'' \7\
---------------------------------------------------------------------------
\7\ Arizona Public Service Company October 12, 2021 Comments at
4.
---------------------------------------------------------------------------
7. The NOPR not only is too expansive, it also is too specific.
It proposes scores of detailed mandates. One such mandate, for
example, is that four is the minimum number of planning scenarios a
public utility must study, and that if one of the scenarios is a
``base case,'' that one must be ``most likely.'' \8\ ``[A]t least
one of the four distinct'' scenarios ``must account for uncertain
operational outcomes . . . during high-impact, low-frequency
events'' but we do ``allow'' utilities ``to determine which . . .
high-impact, low-frequency event should be modeled.'' \9\ Woe unto
the utility that conducts long term planning by considering a fewer
number of scenarios, but you do get to pick your favorite high-
impact, low-frequency event.
---------------------------------------------------------------------------
\8\ NOPR, 179 FERC ] 61,028 at P 123.
\9\ Id. P 124 (emphasis added).
---------------------------------------------------------------------------
8. Entire sections of the NOPR read like a think tank's wish
list rather than a rigorous analysis of whether such Nice-to-Have
ideas are required for just and reasonable, non-discriminatory
ratemaking. For some reason, the NOPR proposes that dynamic line
ratings and advanced power flow control devices must be the default
when studying any new transmission or generation solution ``in all
aspects of the regional transmission planning processes, including
the existing regional transmission planning processes for near-term
regional transmission needs.'' \10\ Never mind that we already have
a Notice of Inquiry on dynamic line ratings.\11\ And I thought this
proceeding was about long-term planning? For some other reason, the
NOPR has a section on ``Specificity of Data Inputs'' \12\ which
defines the ``best available data'' everyone in the industry must
use in their planning, particularly endorsing ``the most recent data
on renewable energy potential and distributed energy resources
developed by national labs.'' \13\ The NOPR also considers a mandate
to establish a ``periodic forum'' to study best practices and
additional reforms.\14\ Why would this need to be mandated? Must the
Commission control everything? Is no one in the industry capable of
such foresight absent our intervention? And, by the way, the NOPR
also proposes (in the name of ``transparency'') to require new
levels of ``enhancements'' and oversight for local transmission
planning, by requiring utilities to incorporate detailed tariff
amendments to describe their local planning processes.\15\ It also
obligates them to consider, among other things, requirements for how
utilities should be ``right-sizing'' transmission facilities, and
whether we should mandate information requirements on ``estimated
in-kind replacements of . . . existing transmission.'' \16\ Does
this not seem like overly prescriptive regulatory meddling?
---------------------------------------------------------------------------
\10\ Id. P 274.
\11\ Implementation of Dynamic Line Ratings, 178 FERC ] 61,110
(2022).
\12\ NOPR, 179 FERC ] 61,028 at PP 91, 127-134.
\13\ Id. P 131 & n.247 (citing National Renewable Energy
Laboratory's Renewable Energy Potential model and Distributed
Generation Market Demand model).
\14\ Id. P 255.
\15\ Id. PP 7, 400-415.
\16\ Id. PP 414-415.
---------------------------------------------------------------------------
9. And yet--notwithstanding its bulk and granularity--the NOPR
fails to clarify the single most critical question confronting
individual states and consumers: Will unwilling states' ratepayers
be required to pay for their neighboring state's new transmission
project which is being built solely for the purpose of achieving
that neighboring state's (or locality's) public policy goals? The
NOPR leaves open what happens if states cannot voluntarily agree on
such issues,\17\ but many will seek to have the RTO allocate costs
as it sees fit, including to unwilling states. I oppose forcing the
ratepayers in states with different public policy goals to pay for
another state's plans.
---------------------------------------------------------------------------
\17\ Id. P 310.
---------------------------------------------------------------------------
10. According to a 2018 summary by the National Conference of
State Legislatures, 24 states either did not have any renewable
portfolio standard or it had expired or was set to expire: Alabama,
Alaska, Arkansas, Florida, Georgia, Idaho, Iowa (expired), Kansas
(expired), Kentucky, Louisiana, Michigan (expired in 2021),
Mississippi, Missouri (expired in 2021), Montana (expired),
Nebraska, North Carolina (expired in 2021), North Dakota (expired),
Oklahoma (expired), Pennsylvania (expired in 2021), South Dakota
(expired), Tennessee, West Virginia, Wisconsin (expired), and
Wyoming.\18\ Renewable standards in an additional 3 states were
voluntary: Indiana, South Carolina, and Utah.\19\ That 27 states
lack mandatory renewable portfolio standards rather suggests that
the country is divided on this issue.
---------------------------------------------------------------------------
\18\ See State Renewable Portfolio Standards & Goals, National
Conference of State Legislatures (Aug. 13, 2021), https://www.ncsl.org/research/energy/renewable-portfolio-standards.aspx.
\19\ See id.
---------------------------------------------------------------------------
11. Not surprisingly, states are among the primary opponents of
the reforms contemplated in the ANOPR, many of which have survived
through to the issuance of today's NOPR. The Utah Public Service
Commission correctly commented ``that FERC seeks to reshape
transmission planning and cost allocation for the purpose of
expanding the transmission system `in areas with high degrees of
renewable resources' that require `extensive' and `more expensive'
new transmission facilities.'' \20\ The Utah Public Service
Commission explained that:
---------------------------------------------------------------------------
\20\ Utah Public Service Commission October 8, 2021 Comments at
2 (citing ANOPR, 176 FERC ] 61,024 at P 40).
[I]ncreased development and integration of renewable generation is a
highly charged political question and a matter of significant
political interest. Different states' legislatures have made
different policy choices. Some states, like California, have enacted
very ambitious laws that require revolutionary changes to their
generation mixes. As the [ANOPR] makes clear, these changes require
significant investment in, among other things, new transmission
infrastructure to wheel renewable generation.
* * * * *
The [Utah Public Service Commission] is deeply concerned the
[ANOPR] advertises an interest in rewriting the rules governing
transmission planning and cost allocation to better facilitate
policy choices, not of Congress, but of particular state
legislatures. More specifically, the [Utah Public Service
Commission] is opposed to any rule change that would allow such
preferences to impose costs on ratepayers in other states.\21\
---------------------------------------------------------------------------
\21\ Id. at 2-3.
12. Different policy goals are a critical reason for state
opposition to a federal transmission planning regime, but certainly
---------------------------------------------------------------------------
not the only one. The Louisiana Public Service Commission explained:
[[Page 26607]]
the Commission proposes to change transmission planning and cost
allocation to support a new fleet of renewable generating resources
in preference to other types of generation. But it is not within the
Commission's FPA authority, or within the ambit of sound
transmission planning, to dictate the choice of generating resources
and then determine what planning and cost allocation metrics will
lead to the appearance of an economic transmission build-out to
support those resources. This approach interferes with the
jurisdiction and authority of the states, fails to recognize
regional differences, and could stifle innovation and the
development of the most reliable and beneficial solutions at the
least delivered energy and capacity cost.
Many of the ANOPR's proposals would not achieve just and
reasonable rates, and, in fact, could lead in the opposite
direction. They would dramatically increase costs imposed on
consumers while potentially jeopardizing the reliability of the
grid. Renewable resources are inherently intermittent and not
dispatchable. They do not and will not have the same reliability
benefits as thermal generation without significant technological
investment and/or duplicative back-up power costs. Consumer costs
should not increase without a corresponding benefit, and certainly
not in the face of diminished reliability, one of the bedrock
principles of electric rate regulation.\22\
---------------------------------------------------------------------------
\22\ Louisiana Public Service Commission October 12, 2021
Comments at 2-3.
13. I also attended the meetings of the joint federal-state task
force on electric transmission in which numerous state commissioners
voiced their concern that federal transmission planning regimes
would be imposed upon the states, that the Commission would insist
on uniformity throughout the country, and most importantly, that the
Commission might require their state's ratepayers to shoulder the
costs of another state's transmission projects.\23\ It should go
without saying that the Commission would be wise to proceed with
caution before acting in the face of state opposition.
---------------------------------------------------------------------------
\23\ See, e.g., Joint Fed.-State Task Force on Elec.
Transmission, 175 FERC ] 61,224 (2021) (establishing task force);
see Joint Fed.-State Task Force on Elec. Transmission, FERC (last
updated Apr. 4, 2022), https://www.ferc.gov/TFSOET.
---------------------------------------------------------------------------
14. The NOPR raises another serious issue: I do not know how
most of these proposals are supposed to work in non-RTO regions.
Nor, apparently, does anyone else. This may explain the repeated
entreaties for the Commission to allow regional variation in
transmission planning. For example:
the [Sponsors of the Southeastern Regional Transmission Planning
Process (SERTP Sponsors)] are concerned that a one-size-fits-all
adoption of some of the items contemplated in the ANOPR could prove
counter-productive or unworkable in the SERTP's expansive, twelve-
state, non-RTO footprint. The SERTP Sponsors respectfully submit
that the Commission's rules concerning regional transmission
planning should continue to accommodate varying approaches to
transmission and system planning in recognition of the inherent
variability of existing market structures, state policies and
requirements, locally available resources, and customer needs that
prevail throughout the country.\24\
---------------------------------------------------------------------------
\24\ Sponsors of the Southeastern Regional Transmission Planning
Process October 12, 2021 Comments at 2.
15. It likewise is doubtful that many of the problems
highlighted in the NOPR apply to the entire country or even extend
beyond certain RTOs. In the southeast, at least, where there is no
RTO, public utilities added 3,158 miles of new transmission and
6,989 miles of uprates between 2015-2020, representing 12% of all
transmission in the region.\25\ This non-RTO region provided
detailed record evidence that strongly suggests it is managing
transmission expansion and renewable integration as well as or
better than any RTO.\26\ Somehow this evidence evaded discussion in
the NOPR and the Commission, regardless of the record evidence,
seems intent on subjecting all public utilities, even those outside
of the RTOs, to the same planning requirements.\27\
---------------------------------------------------------------------------
\25\ See id. at 11.
\26\ See id. at 12-14 (detailing renewable integration in the
southeast on a state-by-state basis).
\27\ See, e.g., NOPR, 179 FERC ] 61,028 at P 3 (``the reforms
proposed in this NOPR would require public utility transmission
providers'' to amend their tariffs) (emphasis added).
---------------------------------------------------------------------------
16. Even RTOs are calling for the Commission to recognize
regional differences and not to impose uniform federal mandates. The
New England Power Pool, for example, tells us in its ANOPR comments
that ``[t]he Commission should allow ISO-NE, NEPOOL, the
[transmission owners in New England] and the New England States to
continue to have the flexibility to develop solutions in planning,
cost allocation and generator interconnection that work best for New
England . . . .'' \28\
---------------------------------------------------------------------------
\28\ New England Power Pool Participants Committee October 12,
2021 Comments at 8.
---------------------------------------------------------------------------
17. I recognize that there are at least some stakeholders,
particularly in RTOs, that want guidance or direction from the
Commission to address the current or potential lack of stakeholder
consensus for transmission planning reforms. But replacing the
stakeholder process with FERC-driven mandates only pleases the
subset of stakeholders who agree with the mandates. It is another
way to overrule voices in opposition.
18. The numerous comments in response to the ANOPR requesting
the continued recognition of regional differences underscore one of
my primary concerns. I simply disagree that the record before us
supports the scope and profundity of change the Commission seeks to
impose. Other broad Commission rulemakings have had sufficient
record support to satisfy our statutory obligations. Here, I am
doubtful. I agree with the comments of the U.S. Chamber of Commerce
which stated that:
the Commission should seriously consider the gravity of this
undertaking and its potential significant impacts on both the
reliability and the cost of electricity for businesses and consumers
across the country. Many of the policies and procedures subject to
revaluation in this docket have served their intended purposes. They
should not be abruptly jettisoned without a thorough evaluation of
the costs and benefits resulting from any significant transmission
planning and interconnection policy changes.\29\
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\29\ Chamber of Commerce of the United States of America October
12, 2021 Comments at 1.
19. In the same vein, the Large Public Power Council ``asks the
Commission to be careful not to disrupt planning and cost allocation
principles within and outside ISOs/RTO structures that are currently
working, and pursuant to which transmission is being planned and
developed.'' \30\ Again, there is no mention of this argument or the
supporting evidence in the NOPR.
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\30\ Large Public Power Council October 12, 2021 Comments at 5
(emphasis added).
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20. The NOPR solicits further comment, but it also plainly
anticipates rule changes for which my own review of the record
indicates only partial, or lukewarm, or minimal support. The most
common comment I have seen in the record, and at the task force
meetings, as I have already highlighted above, is some variation of
``regional planning is a good idea, and reform is needed, but please
do not tell us what to do.'' Well, here are 450 pages of the
Commission proposing to tell you what to do.
21. I freely acknowledge that the NOPR includes several
potentially reasonable ideas for reform. But that is not the test
under section 206 of the FPA. We are not the Good Ideas Commission.
We must have substantial record evidence that the existing rate is
unjust and unreasonable. We must find that the current planning
processes are so unacceptable that the existing system essentially
must be scrapped. We must also have record evidence that the
replacement rate--the final rule to follow the NOPR--is just and
reasonable. We owe it to the jurisdictional entities and the
ratepayers to assure ourselves that each of the prescriptive
requirements we seek to impose are actually necessary to ensure a
just and reasonable, non-discriminatory replacement rate. I
certainly do not see the required evidentiary support in the record
we have compiled to date and I am skeptical that I will ever see it.
22. Every single party with an interest should file in this
docket. And many parties will. The sheer scope of the NOPR means
that there is likely to be at least some support in the record for
just about anything. I must therefore underscore that it is critical
for parties filing comments in response to the NOPR to be direct and
clear. This can be as simple as styling comments as ``Comments in
Opposition'' when the filing party opposes any significant part of
the NOPR. For example, if you are one of the numerous parties that
filed comments in the ANOPR proceeding requesting that ``[i]n any
final rule that comes out of this rulemaking proceeding the
Commission should allow for regional variations and flexibility in
compliance for RTO/ISO regions,'' \31\ or for
[[Page 26608]]
non-RTO regions, then I strongly suggest that you file ``Comments in
Opposition'' to the NOPR. The NOPR appears to anticipate only
limited regional flexibility.\32\
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\31\ New England Power Pool Participants Committee October 12,
2021 Comments at 7.
\32\ See NOPR, 179 FERC ] 61,028 at PP 183, 355.
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23. I further specifically request itemized lists from each
commenting party indicating whether it supports, opposes, or
abstains as to each of the NOPR's preliminary findings and proposed
reforms. The Commission's ultimate findings cannot rest merely on a
tally of votes, but the scope of this proceeding would make such
basic summaries of the comments immensely helpful and will aid the
Commission in its review of the (already) voluminous record.
24. To the extent possible, every part of a comment should
directly respond to a particular preliminary finding or proposal in
the NOPR. The ANOPR comments have been filed and reviewed. The time
for generic comments, ``principles'' of planning, the voicing of
general support and the like is over and such comments will be
nearly without value in the face of page after page of detailed,
specific preliminary findings and proposed requirements. Do you
support the finding or not? Do you support the proposal or not?
25. And in voicing your support or opposition, I also remind
commenting parties to submit hard data whenever possible, including
in affidavits, to help the Commission meet--or not--both of the
required legal showings for this section 206 proposal (that existing
rates are unjust and unreasonable, and that the proposed replacement
rate is just and reasonable). I am fully aware that parties have
limited resources to comment on the Commission's generic
proceedings. And while the scope of this NOPR will inevitably make
this an expensive and burdensome endeavor for commenters, I urge you
not to rest solely on your ANOPR comments. Support or opposition to
the specific proposals in the NOPR is necessary. It will be worth
the effort. After all, the only thing at stake in this proceeding is
nearly everything connected with transmission planning.
26. Parties should remember that this is not the final rule. The
Commission can issue a final rule that contains any provision based
on substantial evidence and that is a ``logical outgrowth'' \33\ of
the provisions in today's proposed rule. That gives wide berth for
any number of ultimate outcomes. In other words, this rule, when
finalized, could be substantially different. Given what is at stake,
be certain to inform the Commission of your positions on every
element of the NOPR that could possibly be of concern to you.
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\33\ See, e.g., Sierra Club v. Costle, 657 F.2d 298, 352 (D.C.
Cir. 1981).
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27. In this regard, I strongly object to our 75- and 30-day
comment and reply periods. Commenting parties presumably do not have
hundreds of hours to wade through 450 pages of detailed proposals
and to marshal evidence and legal argument for or against every
potential change. I am not sure how the same Commission that just
set up an Office of Public Participation thinks anyone can
reasonably comment on every detail in this tome in 6 months, let
alone 75 days. In another proceeding today, we provide RTOs with 6
months to file reports on potential ``modernizing'' reforms to
electricity markets, yet here, where no less than the entirety of
transmission planning is at stake, we suddenly are in a rush.\34\
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\34\ See Modernizing Wholesale Elec. Mkt. Design, 179 FERC ]
61,029 at P 1 (2022).
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28. Do not forget that we are also actively considering
interconnection queue reforms, albeit separately, which might be an
even greater priority. If we are going to propose comprehensive
transmission planning changes in a rulemaking, regional planning and
transmission interconnection queue reform should not be considered
in silos.
29. While I think this NOPR is a mistake, I am happy to be
convinced that particular reforms are justified by sound legal
argument and solid record evidence. Where reform is needed to ensure
just and reasonable rates and reliable service, and the reform
itself is just and reasonable, I can be persuaded that it is worthy
of support. I nevertheless reiterate my strong preference that we
allow public utilities to file their own transmission planning
solutions under FPA section 205. The Commission does not need to
issue rules to change everything. Sometimes it is better to build
incrementally to improve the current system, rather than to scrap
everything and start from scratch. In my view, if an RTO or public
utility wants to ``enhance'' its regional planning, it can figure
out how to do so. And if the Commission really believes that we
cannot rely on public utilities to seek more efficient transmission
planning of their own volition, my second option would be to issue
section 206 orders requiring the RTOs to show cause why their
existing transmission planning processes are just and reasonable.
Whether you agree or disagree with these alternative procedural
vehicles for change, please say so in your comments.
30. I conclude with a note of caution. A transmission planning
revolution opposed by half of the country risks becoming a
transmission planning civil war. The Commission should not cram
``reforms'' down the throats of opponents on issues of such deep
division, such as whether we can force utilities in unwilling states
to consider the transmission needs of other states' policy
aspirations. The result will be protracted proceedings, litigation,
and risk. Who is going to fund a transmission project in such an
environment, in the face of the perpetual risk that it might have
its costs ``reallocated''?
For these reasons, I respectfully dissent.
-----------------------------------------------------------------------
James P. Danly,
-----------------------------------------------------------------------
Commissioner.
United States of America Federal Energy Regulatory Commission
Building for the Future Through Electric Regional Transmission
Planning and Cost Allocation and Generator Interconnection
Docket No. RM21-17-000
(Issued April 21, 2022)
CHRISTIE, Commissioner, concurring:
1. The broad purpose of this Commission's oversight of
transmission planning under the Federal Power Act (FPA) is to
provide consumers with reliable power at just and reasonable rates.
I am voting for this Notice of Proposed Rulemaking (NOPR) because I
believe it contains some very good proposals that could protect
consumers from paying unjust and unreasonable rates for transmission
service while also supporting the delivery of reliable power to
those consumers. I also believe it comports with our legal authority
under the FPA.
2. First, the legal framework: While the FPA gives this
Commission authority over ``the transmission of electric energy in
interstate commerce,'' \1\ the Commission has no authority to
encroach on matters regulated by the states.\2\ The planning,
approval and siting of the generation resources necessary to meet
the needs of customers in a state are under the regulatory authority
of the states, not the Commission.\3\ States can prefer, mandate or
subsidize specific types of generation resources, but the Commission
cannot use its authority over transmission to pressure, steer or
require regional planning entities to act as the Commission's agents
and do indirectly what the Commission cannot do directly. The
Commission is not a national integrated resource planner. Order No.
1000, to its credit, recognized this clear delineation between
federal and state authority.\4\
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\1\ 16 U.S.C. 824(b)(1).
\2\ Id. Sec. 824(a).
\3\ Id. Sec. 824(b)(1).
\4\ Transmission Planning and Cost Allocation by Transmission
Owning and Operating Public Utilities, Order No. 1000, 136 FERC ]
61,051, at P 154 (2011), order on reh'g, Order No. 1000-A, 139 FERC
] 61,132, order on reh'g and clarification, Order No. 1000 -B, 141
FERC ] 61,044 (2012), aff'd sub nom. S.C. Pub. Serv. Auth. v. FERC,
762 F.3d 41 (DC Cir. 2014) (``[T]he regional transmission planning
process is not the vehicle by which integrated resource planning is
conducted; that may be a separate obligation imposed on many public
utility transmission providers and under the purview of the
states.'') (emphases added); see also id. PP 107, 156.
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3. Further, under the FPA our authority over transmission
planning and cost allocation must ensure that wholesale transmission
rates are not unjust and unreasonable.\5\ We also have the authority
to promote the reliability of the bulk power grid.\6\ Those are
consumer protection functions, not a license to promote the policy
goals of any presidential administration or of any corporate or
special-interest group that have not been enacted into law in the
FPA or any other federal statute.
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\5\ 16 U.S.C. 824e(a).
\6\ Id. Sec. 824o.
---------------------------------------------------------------------------
4. With that legal framework in mind, I am voting in favor of
issuing this NOPR at this time and in this form because, on the
whole, I find the current draft is consistent with our authority
under the FPA and contains some important and constructive proposals
that will serve the consumer protection goals of just and reasonable
rates and reliability.
5. For example, and as described more fully below, this NOPR
will formally put the states--for the first time--at the center of
regional transmission planning and cost allocation decision-making
for policy-driven projects in all regional transmission entities,
[[Page 26609]]
if the states choose.\7\ As another valuable example, also described
below, the NOPR will shift the risk of financing policy-driven
projects from consumers back to developers, where it should be.
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\7\ States have long played an informal advisory and advocacy
role through organizations such as the Organization of PJM States,
Inc. (my alma mater) and the Organization of MISO States. In
Southwest Power Pool, Inc. (SPP) and ISO New England Inc. states
have played what could be perhaps described as a more formal role in
the decision-making processes of the regional entity, through the
SPP Regional State Committee and the New England States Committee on
Electricity, respectively. In single-state RTOs/ISOs such as New
York Independent System Operator, Inc. (NYISO) and California
Independent System Operator Corporation, state policies and policy-
makers already heavily influence transmission planning and cost
allocation. See, e.g., N.Y. Indep. Sys. Operator, Inc., 178 FERC ]
61,179 (2022) (Christie, Comm'r, concurring) (``The specific
[transmission] projects at issue in this proceeding are designed to
implement the public policies of the State of New York, which are
ultimately the responsibility of New York's elected legislators. . .
. NYISO is a single-state ISO that is attempting to act in
accordance with the public policies of the state.''). The states, as
sovereign entities, must choose to embrace the heightened role
offered by this NOPR; no state can be compelled to do so, as the
NOPR makes clear. Building for the Future Through Electric Regional
Transmission Planning and Cost Allocation and Generator
Interconnection, 179 FERC ] 61,028, at P 308 (2022) (NOPR).
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6. Let me also emphasize that this is a NOPR--the ``P'' stands
for ``Proposed''--it is not a final rule. This is only another step
in a long process. I look forward to reviewing the comments reacting
to it, which I suspect will come in significant quantities. My vote
on any final rule will, of course, be based on the text of that
final rule. I will not support any final rule that exceeds our FPA
authority and/or threatens to cause unjust and unreasonable rates to
consumers.
7. When we issued the ANOPR last summer,\8\ I said:
---------------------------------------------------------------------------
\8\ Building for the Future Through Electric Regional
Transmission Planning and Cost Allocation and Generator
Interconnection, 176 FERC ] 61,024 (2021) (Christie, Comm'r,
concurring, at P 5).
This ANOPR contains a number of good proposals, some potentially
good proposals (depending on how they are fleshed out), and frankly,
some proposals that are not--and may never be--ready for prime time,
or could potentially cause massive increases in consumers' bills for
little to no commensurate benefit or inappropriately expand the role
---------------------------------------------------------------------------
of federal regulation over local utility regulation.
Fortunately, this NOPR contains some very good proposals and
leaves out the worst of the ``not ready for prime time'' ideas of
the ANOPR. While it still contains some features I would not
choose,\9\ on balance I am comfortable in voting for it in this form
and putting it out for additional comment. Here are some of the best
features of this NOPR:
---------------------------------------------------------------------------
\9\ For example, I agree with Commissioner Danly's dissent that
many of the specific long-term planning directives proposed in the
NOPR may be far too prescriptive and may need to be revised in any
final rule to permit more regional variation and flexibility.
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8. First, it leaves unchanged the planning criteria and cost
allocation frameworks for Reliability and Economic projects.\10\
Reliability and Economic projects are the meat and potatoes of
regional transmission planning. These categories of projects are, by
definition, integral to the primary duty of utilities to serve
retail customers (load). Reliability projects are essential to keep
the lights on. Economic projects are constructed to reduce
quantifiable and definable congestion costs. When these projects are
needed, they should be expeditiously built.\11\ The NOPR wisely does
not disturb existing criteria for timely planning, constructing and
paying for these two categories of projects.
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\10\ NOPR, 179 FERC ] 61,028 at PP 3, 89, 314.
\11\ I recognize that, with regard to projects to relieve
congestion costs, in some circumstances there may be cheaper
solutions available through new builds of generation.
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9. Second, the NOPR proposes to create a separate category of
projects, which we can label ``Long-Term Regional Transmission
Facilities,'' \12\ or ``LTRT projects.'' This new category replaces
Order No. 1000's ``public policy projects.'' \13\ As with these
public policy projects, the new category of LTRT projects are mostly
driven, in whole or in part, directly or indirectly, by public
policies, such as projects that would accommodate a state's
legislated preferences for certain resources, or projects that could
accommodate generation growth and retirements resulting from states'
implementation of their own integrated resource plans (IRP), or
corporate goals recognized in state utility regulation.
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\12\ NOPR, 179 FERC ] 61,028 at P 4 & n.6; see also id. n.507.
\13\ Order No. 1000 described these types of projects as those
that address ``transmission needs driven by Public Policy
Requirements.''
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10. For this new category of LTRT projects, the NOPR proposes to
require a planning process extending out 20 years, based on the
premise that a 20-year projection of the expected generation mix,
costs of generation, and/or load has validity. Based on my
experience as a state regulator with IRPs and computer models
purporting to predict the future two or more decades down the road,
I regard 20-year projections of this sort as, at best, occasionally
interesting, but they certainly provide no basis whatsoever for
saddling consumers with the costs of a billion-dollar transmission
line. However, while this NOPR does propose to require a 20-year
planning process for LTRT projects, it does not propose to require
that any individual LTRT project or group of projects must be
approved for inclusion in any regional transmission expansion plan.
Indeed, there are no mandated LTRT projects in this NOPR, nor any
planning-cycle quotas that regional entities must meet for including
these types of projects in regional plans.
11. Even more importantly though, for these LTRT projects, the
NOPR proposes to require the regional planning entities to consult
with and seek the agreement of the relevant states to both the
selection criteria for these projects and to the regional cost
allocation arrangements. State approval is especially important in a
multi-state region, where different states have different policies.
The NOPR proposes to provide the maximum opportunity for creativity
and flexibility to the states and regional entities in developing
the process for designing and approving regional selection criteria
and cost allocation arrangements. States can agree to an ex ante
formula for regional cost allocation of these types of projects--
such as, for example, the ``highway-byway'' formula approved by the
SPP Regional State Committee--or states can agree to a process for a
project-by-project agreement on cost allocation among one or several
states--such as, for example, the State Agreement Approach in PJM--
or states may choose some combination of both.\14\ States in a
multi-state RTO or ISO can even agree to defer the decision on cost
allocation to the governing board of the RTO/ISO.\15\ The result is,
while we are proposing to require regional planning entities to
study and evaluate a broad, forward-looking array of information--
including information addressing states' individual energy policies
and goals--any projects identified through this new process will not
be built, or more importantly, paid for by consumers, until the
states representing such consumers have agreed that such projects
are indeed needed and wanted by those same consumers.
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\14\ NOPR, 179 FERC ] 61,028 at PP 302-303, 305.
\15\ Id. PP 305, 307.
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12. And let me emphasize two points: First, as stated above, the
Commission cannot impose a preference for certain types of
generation nor require regional entities to plan transmission
designed to prefer or facilitate one type of generation over
another. Second, regardless of any ultimate cost allocation
arrangement agreed to in a regional entity, no individual state's
consumers can be forced to bear the costs of another state's policy-
driven project or element of a project against its consent.\16\ That
would be inconsistent with the cost-allocation principles of Order
No. 1000, which this NOPR explicitly proposes to preserve.\17\
---------------------------------------------------------------------------
\16\ See, e.g., id. PP 302, 312.
\17\ Id.
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13. States did not join RTOs \18\ to pay for other states'
public policies or to pay for the public policy goals of huge
multinational corporations or asset managers.\19\ States joined to
provide their retail consumers with the promised benefits of lower
transmission costs and strengthened reliability through regional
planning of core Reliability projects. Some may say that state
regulators should have no more special right to consent to planning
criteria and cost allocation for these projects than other
stakeholders in the RTO/ISO. But states are not just
``stakeholders.'' State regulators have the duty to act in the
public interest and states alone are sovereign authorities with
inherent police powers to regulate utilities through their
designated state officers. The FPA itself explicitly recognizes
state authority. So it is perfectly fitting for state regulators to
have the
[[Page 26610]]
important roles proposed in this NOPR, without preempting the
regional planning entities from seeking additional input through
their existing stakeholder processes.
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\18\ I am aware that states qua states do not join RTOs/ISOs.
Rather, they use their regulatory power to allow or require their
regulated transmission-owning utilities to join.
\19\ See, e.g., Google, A Policy Roadmap for 24/7 Carbon-Free
Energy (Apr. 14, 2022), https://cloud.google.com/blog/topics/sustainability/a-policy-roadmap-for-achieving-247-carbon-free-energy; see also BlackRock, Inc., 179 FERC ] 61,049 (2022)
(Christie, Comm'r, concurring).
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14. The bottom line for me is this: I believe that elevating the
role in planning and cost allocation of state regulators--who are,
as a group, deeply concerned about the monthly bills paid by
consumers, of which transmission is a rapidly growing component--
will make it more likely, not less, that necessary transmission can
get built while ensuring that rates resulting from these types of
policy-driven projects will not be unjust and unreasonable, which
they clearly have the potential to be.
15. There is a third feature of this NOPR I also find very
important. For LTRT projects the NOPR proposes to end the
Commission's long practice of awarding, as an incentive, cost
recovery for Construction Work in Process (CWIP); instead it will
propose to require the booking of these pre-service costs as
Allowance for Funds Used During Construction (AFUDC).\20\ CWIP is
the award of cost recovery of construction costs during the pre-
construction and construction phases to the developer. CWIP is, of
course, passed through as a cost to consumers, making consumers
effectively an involuntary lender to the developer. By contrast,
AFUDC is booked during the pre-service phases, but cannot be
recovered from customers until the project is completed and actually
serving customers, i.e., ``used and useful.'' The NOPR proposal is
simply in keeping with traditional good utility ratemaking
principles. Booking these costs as AFUDC also recognizes the reality
that just because an LTRT project is selected for a regional plan,
it still has to obtain all state siting, certificate of public
convenience and necessity and other, including environmental,
approvals, and survive what may be the subsequent litigation, before
it is actually built.\21\ Consumers should be protected from paying
CWIP costs during this potentially long period before a project
actually enters service, if it ever does. This NOPR proposal
represents a major step forward in consumer protection and is a big
reason I am voting for it.
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\20\ NOPR, 179 FERC ] 61,028 at P 333 & n.530.
\21\ See e.g., Nat'l Wildlife Refuge Ass'n v. Rural Utils.
Serv., Nos. 21-cv-096-wmc & 21-cv-306, 2021 WL 5050073 (W.D. Wis.
Nov. 1, 2021) (enjoining on environmental grounds construction of a
segment of a transmission project intended to bring wind-generated
power from generators in Iowa to Wisconsin); see also Clark Mindock,
Wis. Judge Blocks $500M Power Line From Wildlife Refuge, LAW360
(Mar. 2, 2022), https://www.law360.com/articles/1469697 (``The CHC
Project is a proposed 102-mile high-voltage transmission line in the
Midwest that was proposed as a way of connecting parts of Milwaukee
and Chicago to cheap wind power by connecting Dubuque, Iowa, to
southwestern Wisconsin.'').
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16. Finally, let me note again that this is a NOPR--a continuing
work in progress with more work ahead. For example, the section on
planning of local projects \22\ seeks to address a concern expressed
by many commenters, that local projects may not be getting
sufficiently vetted by regional planning entities. In response, the
NOPR essentially proposes PJM's procedures for vetting and
transparency of local projects, but I welcome additional comment
from other regional entities as to whether there are more conducive
measures for such vetting that may fit their own regions better.
Most importantly, on the broader issue of whether local projects are
being properly scrutinized, as a former state regulator who sat on
scores of local-project cases, I would point out that no local
project is going to be built unless a state agency approves a
certificate or its equivalent. While the commenters note that
procedures differ greatly from state to state, and some state
utility commissions have more authority than others,\23\ there is no
question that states have within their inherent police powers the
authority to regulate utilities and that includes the power to vet
local projects both as to need and cost before approving them, just
as states have the siting authority. If states are not using these
powers to vet fully such local projects, they should review their
own state laws and procedures. And if states believe they need more
information from the RTOs/ISOs to make more informed decisions in
their vetting processes, please comment on what additional
information would be helpful for the RTOs and ISOs to provide.
States should be a full partner in the process for vetting and
approving local projects and I invite comment on how to strengthen
state oversight of these projects to get the best deal for the
consumer.
---------------------------------------------------------------------------
\22\ NOPR, 179 FERC ] 61,028 at PP 383-415.
\23\ See, e.g., Ohio Consumers' Counsel Comments at 13
(explaining that the Ohio Power Siting Board (OPSB) does not review
local projects ``for need, prudence, or cost efficiency''); Ohio
Consumers' Counsel Reply Comments at 8 (``the OPSB rejected [Ohio
Consumers' Counsel's] recommendation that the OPSB report to the
General Assembly that the state legislature should pass new
statutory authority for OPSB that would require the agency to
regulate the siting of, need for and cost-effectiveness of any
proposed new transmission facilities in Ohio rated at 69 kV and
above.'').
---------------------------------------------------------------------------
For these reasons cited above, I concur in the issuance of the
NOPR.
-----------------------------------------------------------------------
Mark C. Christie,
Commissioner.
United States of America Federal Energy Regulatory Commission
Building for the Future Through Electric Regional Transmission
Planning and Cost Allocation and Generator Interconnection
Docket No. RM21-17-000
(Issued April 21, 2022)
PHILLIPS, Commissioner, concurring:
1. I concur in today's Notice of Proposed Rulemaking (NOPR) to
emphasize the importance of our action today and to call attention
to the work that remains. I believe today's NOPR represents a
critical first step toward ensuring a 21st century electric grid
that is capable of reliably and affordably accommodating new
generation.
2. Most commenters urge the Commission to reexamine the
transmission planning and cost allocation policies adopted in Order
No. 1000 over a decade ago.\1\ While Order No. 1000 was well
intentioned, commentors argue that it fell short of its goal to spur
competitive transmission buildout. Under section 206 of the Federal
Power Act,\2\ the Commission must ensure that transmission rates are
just and reasonable. If there are deficiencies in the Commission's
existing regional transmission planning and cost allocation
requirements, we must endeavor to remedy those deficiencies. For
this reason, I support the NOPR's proposal to revisit our existing
policies.
---------------------------------------------------------------------------
\1\ Transmission Planning and Cost Allocation by Transmission
Owning and Operating Public Utilities, Order No. 1000, 136 FERC ]
61,051 (2011), order on reh'g, Order No. 1000-A, 139 FERC ] 61,132,
order on reh'g and clarification, Order No. 1000-B, 141 FERC ]
61,044 (2012), aff'd sub nom. S.C. Pub. Serv. Auth. v. FERC, 762
F.3d 41 (D.C. Cir. 2014).
\2\ 16 U.S.C. 824e.
---------------------------------------------------------------------------
3. This NOPR acknowledges the facts on the ground. It is an
inescapable fact that our resource mix is changing, which is a key
factor leading to a greater need for transmission. Due in large part
to economies of scale, the cost of renewable energy has fallen
rapidly over the last decade while the demand for those resources
has increased.\3\ As of the end of 2020, there were over 800 GW of
wind, solar, and energy storage capacity seeking interconnection in
the United States.\4\ That figure has now risen to 1,300 gigawatts
of wind, solar and storage capacity proposed for interconnection as
of the end of 2021.\5\ At the same time as the resource mix is
changing, severe weather events and wildfires are becoming more
frequent and extreme.\6\ These are just a few of the factors
contributing to a greater need for expansion of our nation's
grid.\7\
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\3\ For instance, after an 85% cost decline over the past
decade, solar photovoltaic systems are among the most cost-
competitive energy resources in the market. See Deloitte, 2022
Renewable Energy Outlook, https://www2.deloitte.com/us/en/pages/energy-and-resources/articles/renewable-energy-outlook.html.
\4\ Queued Up: Characteristics of Power Plants Seeking
Transmission Interconnection As of the End of 2020, Lawrence
Berkeley National Laboratory, at 22 (May 2021).
\5\ Queued Up: Characteristics of Power Plants Seeking
Transmission Interconnection As of the End of 2021, Lawrence
Berkeley National Laboratory, at 3 (April 2022).
\6\ As outlined in the November 2021 FERC-NERC-Regional Entity
Staff Report on Winter Storm Uri, interregional transfers played a
critical role in helping MISO and SPP compensate for generation
outages during the event. The February 2021 Cold Weather Outages in
Texas and the South Central United States, FERC, NERC and Regional
Entity Staff Report, at 98 (November 2021).
\7\ See National Association of Regulatory Utility Commissioners
(NARUC) Comments at 17 (``Because certain clean energy resources are
diffuse by nature, meaning the resources exist at disparate
locations and cannot simply be placed near existing load centers,
new transmission facilities may need to be developed to gather and
transport energy from generation rich areas to load.''); Harvard
Electricity Law Initiative Comments at 17 (``Transmission is needed
to connect these location-constrained resources and to ensure that
the system remains reliable with a larger share of intermittent
generation.'').
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4. The record here appears to show that transmission expansion
is increasingly occurring in a piecemeal and inefficient fashion
outside of the regional transmission
[[Page 26611]]
planning process, which may not be cost-effective for consumers in
the long run.\8\ While commenters' views vary on how best to address
this problem, nearly all commenters endorse some form of proactive
planning for the future resource mix and demand.\9\ I believe the
NOPR proposal to require long-term scenario planning, including
accounting for extreme weather events, is necessary to maintain the
reliability of the grid and to ensure that transmission costs are
just and reasonable. I also note that while this NOPR proposes to
require the evaluation of benefits of long-term regional
transmission facilities over a 20-year time horizon, it does not
propose to prescribe any particular definition of ``benefits'' or
``beneficiaries,'' nor require use of any specific benefits.\10\
Instead, we continue to acknowledge the benefits of regional
flexibility. Nor does it propose to require that transmission
providers select any particular transmission projects, instead
proposing to provide transmission providers the flexibility to
propose the selection criteria that they, in consultation with their
stakeholders and states, believe will ensure that more efficient or
cost-effective long-term regional transmission facilities ultimately
are selected.\11\ And I support the proposal to require transmission
providers to consult with and incorporate states' views in project
selection and cost allocation. I invite comment on the value of such
state involvement for increasing the likelihood that those
facilities are sited and ultimately developed with fewer costly
delays.
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\8\ See Building for the Future Through Electric Regional
Transmission Planning and Cost Allocation and Generator
Interconnection, 179 FERC ] 61,028, at P 38 (2022) (NOPR)
(discussing the dramatic increase in cost, size, and scope of
interconnection-related network upgrades).
\9\ See Americans for a Clean Energy Grid Reply Comments,
Appendix A (listing 174 commenters).
\10\ See NOPR, 179 FERC ] 61,028 at P 183.
\11\ Id. P 242.
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5. I also strongly support the NOPR proposal for greater
consideration of dynamic line ratings and advanced power flow
control devices in regional transmission planning processes. Grid-
enhancing technologies (GETs) can optimize our existing transmission
infrastructure and provide cost-effective solutions for consumers.
For example, by allowing the measurement of transmission capacity in
real-time, dynamic line ratings can provide net benefits to
customers by allowing increased power flow and reducing congestion
costs, as well as by detecting when power flows should be reduced to
avoid unnecessary wear on transmission equipment. The role that
these and other GETs could play in delaying or eliminating the need
for new transmission facilities cannot be ignored. I urge the
Commission to consider further reforms to incentivize the adoption
and deployment of GETs.
6. Many commenters raise concerns about delays and significant
backlogs in interconnection queues across the country.\12\
Currently, less than a quarter of generator interconnection
applications actually result in an interconnection.\13\
Interconnection applicants submitting speculative interconnection
requests can linger in the queue, only to withdraw at late stages,
often necessitating the study of non-viable projects as well as
restudies due to withdrawals. These often result in delays and cost
risks for commercially viable projects that are otherwise ready to
interconnect. Although the reforms we propose in this NOPR may help
mitigate these issues in the long term, they are not enough to
alleviate existing backlogs in the near term. While I recognize and
commend the ongoing efforts in some regions to address the large
volume of interconnection requests,\14\ I encourage my colleagues to
consider whether it is necessary to require certain best practices,
such as first-ready, first-served cluster study approaches, to
process interconnection requests more efficiently.
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\12\ See, e.g., Advanced Energy Economy Reply Comments at 17-23;
American Electric Power Service Corporation Comments at 36-38;
American Public Power Association Comments at 27; Edison Electric
Institute Reply Comments at 27-30; NextEra Energy, Inc. Comments at
12.
\13\ See Queued Up . . . But in Need of Transmission Unleashing
the Benefits of Clean Power with Grid Infrastructure, U.S.
Department of Energy, at 2 (April 2022).
\14\ See, e.g., California Public Utilities Commission Comments
at 70 (noting that California Independent System Operator
Corporation is undertaking a stakeholder process focused on
increasing efficiency of the interconnection study process); PJM
Interconnection, L.L.C. Comments at 47-49.
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7. Similarly, many commenters have highlighted the importance of
adopting interregional coordination and planning reforms,
particularly for reliability.\15\ Today's NOPR does not, at this
time, propose changes to the existing interregional transmission
coordination and cost allocation requirements of Order No. 1000. As
we continue to examine those issues, I urge the Commission to act
expeditiously to propose interregional reliability planning reforms.
Looking beyond regional boundaries is important so that cost-
efficient regional and interregional projects can be considered and
studied together. We should consider whether neighboring regions
should adopt common planning assumptions and methods that allow for
region-specific inputs. Additionally, I believe we must consider
whether to adopt a requirement for a minimum amount of interregional
transfer capacity to protect against generation shortfalls,
especially during extreme weather events.
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\15\ See, e.g., NARUC Comments at 8 (``The planning process
should share system planning information on an interregional level
whenever appropriate.''); id. at 19 (describing how during Winter
Storm Uri, ``usually a net exporter of energy, SPP relied
significantly on imported energy to serve load during the winter
event'' and that ``effective planning should strive to quantify
benefits associated with enhancing interregional import and export
capabilities, given the likelihood of future extreme weather events
and related energy shortages. Further analysis and process
improvements in interregional transmission development and imports
and exports capability will be necessary, not only to accommodate
demand for a clean energy transition, but also for reliability and
defined resiliency benefits.''); PJM Interconnection, L.L.C.
Comments at 72-73 (stating that greater interregional transfer
capability has a significant reliability benefit as demonstrated by
the February 2021 Cold Snap and the 2014 Polar Vortex, and the
Commission should approach the issue of strengthening interregional
ties as a broad reliability-based benefit); New York Independent
System Operator, Inc. Comments at 55 (``Interconnections with
neighboring systems are important tools to support grid reliability,
resiliency, and market efficiency by providing opportunities for the
exchange of capacity and energy.'').
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8. Finally, I note that this NOPR is merely a proposal and I am
looking forward to reviewing the comments in response. In addition,
I emphasize that the reforms in this NOPR are not intended to be
one-size-fits-all, nor would I support such an approach. Recognizing
the unique needs and characteristics of individual markets and
regions, I am particularly interested in comments on whether the
reforms proposed in this NOPR allow for a sufficient level of
regional flexibility.
For these reasons, I respectfully concur.
Willie L. Phillips,
Commissioner.
[FR Doc. 2022-08973 Filed 5-3-22; 8:45 am]
BILLING CODE 6717-01-P