[Federal Register Volume 86, Number 141 (Tuesday, July 27, 2021)]
[Proposed Rules]
[Pages 40266-40298]
[FR Doc No: 2021-15512]

Vol. 86

Tuesday,

No. 141

July 27, 2021

Part III

Department of Energy

-----------------------------------------------------------------------

Federal Energy Regulatory Commission

18 CFR Part 35

-----------------------------------------------------------------------

Building for the Future Through Electric Regional Transmission Planning
and Cost Allocation and Generator Interconnection; Proposed Rule

Federal Register / Vol. 86, No. 141 / Tuesday, July 27, 2021 /
Proposed Rules

-----------------------------------------------------------------------

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: Advance notice of proposed rulemaking.

-----------------------------------------------------------------------

SUMMARY: The Federal Energy Regulatory Commission (Commission) is
issuing an Advance Notice of Proposed Rulemaking (ANOPR) presenting
potential reforms to improve the electric regional transmission
planning and cost allocation and generator interconnection processes.
The Commission invites all interested persons to submit comments on the
potential reforms and in response to specific questions.

DATES: Comments are due October 12, 2021 and Reply Comments are due
November 9, 2021.

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 U.S. Postal Service mail or by hand (including courier)
delivery.
    [cir] Mail via U.S. Postal Service only: Addressed to: Federal
Energy Regulatory Commission, Office of the Secretary, 888 First Street
NE, Washington, DC 20426.
    [cir] For delivery via any other carrier (including courier):
Deliver to: Federal Energy Regulatory Commission, Office of the
Secretary, 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,<PHONE_NUMBER>,
<EMAIL_ADDRESS>Christopher Gore (Technical Information), Office of Energy Market
Regulation, 888 First Street NE, Washington, DC 20426,<PHONE_NUMBER>,
<EMAIL_ADDRESS>Lina Naik (Legal Information), Office of the General Counsel, 888 First
Street NE, Washington, DC 20426,<PHONE_NUMBER><EMAIL_ADDRESS>
SUPPLEMENTARY INFORMATION:

Table of Contents

                                                         Paragraph Nos.

I. Introduction.......................................                 1
II. Background........................................                 6
    A. Regional Transmission Planning and Cost                         6
     Allocation Process...............................
        1. Regional Transmission Planning Requirements                 8
        2. Nonincumbent Transmission Developer Reforms                 9
        3. Regional Transmission Cost Allocation......                11
        4. Interregional Transmission Coordination....                12
    B. Overview of Transmission Planning..............                13
        1. Reliability Needs..........................                14
        2. Economic Needs.............................                15
        3. Public Policy Requirement Needs............                16
        4. Local Transmission Facilities in the                       17
         Regional Transmission Planning Process.......
    C. Overview of Generator Interconnection..........                18
    D. Interaction Between the Regional Transmission                  23
     Planning and Cost Allocation and Generator
     Interconnection Processes........................
    E. Current Funding Paradigm.......................                24
        1. Regional Transmission Cost Allocation......                24
        2. Local Transmission Facilities..............                25
        3. Interconnection-Related Network Upgrades...                28
III. The Potential Need for Reform....................                30
    A. The Existing Regional Transmission Planning and                30
     Cost Allocation and Generator Interconnection
     Processes May Be Inadequate To Ensure Just and
     Reasonable Rates.................................
        1. Considering Anticipated Future Generation..                31
        2. Results of Existing Local and Regional                     37
         Transmission Planning Processes..............
        3. Cost Responsibility for Transmission                       38
         Facilities and Interconnection-Related
         Network Upgrades.............................
IV. Consideration of Potential Reforms and Request for                44
 Comment..............................................
    A. Regional Transmission Planning and Cost                        44
     Allocation Processes.............................
        1. Potential Reforms and Request for Comment..                44
            a. Planning for the Transmission Needs of                 44
             Anticipated Future Generation............
            i. Future Scenarios and Modeling                          46
             Anticipated Future Generation............
            ii. Identifying Geographic Zones That Have                54
             Potential for High Amounts of Renewable
             Resource Development to Meet Increased
             Demand...................................
            iii. Incentivizing Regional Transmission                  61
             Facilities...............................
            iv. Enhanced Interregional or State-to-                   62
             State Coordination.......................
            b. Coordinating Between the Regional                      65
             Transmission Planning and Cost Allocation
             and Generator Interconnection Processes..
    B. Identification of Cost and Responsibility for                  69
     Regional Transmission Facilities and
     Interconnection-Related Network Upgrades.........
        1. Relevant Cost Causation Precedent..........                74
        2. Cost Allocation for Transmission Facilities                75
         Planned through the Regional Transmission
         Planning Process.............................
            a. Background.............................                76
            b. Potential Need for Reform..............                83
            c. Potential Reforms and Request for                      90
             Comment..................................
        3. Participant Funding and Crediting Policy                  100
         for Funding Interconnection-Related Network
         Upgrades.....................................
            a. Background.............................               101
            i. Original Rationale for the Order No.                  101
             2003 Interconnection-Related Network
             Upgrade Funding Requirements.............
            (a) Crediting Policy......................               102
            (b) Participant Funding...................               105
            b. Potential Need for Reform..............               111
            i. Participant Funding....................               111
            ii. Crediting Policy......................               120
            c. Potential Reforms and Request for                     121
             Comment..................................
            i. Eliminate Participant Funding for                     123
             Interconnection-Related Network Upgrades.
            ii. Revisions to the Existing Crediting                  131
             Policy...................................

            (a) Transmission Providers Provide Upfront               132
             Funding for All Interconnection-Related
             Network Upgrades.........................
            (b) Interconnection Customers Contribute                 135
             to the Upfront Funding of Interconnection-
             Related Network Upgrades Through a Fee...
            (c) Transmission Providers Provide Upfront               139
             Funding for Only Higher Voltage
             Interconnection-Related Network Upgrades.
            (d) Allocate the Upfront Cost of                         146
             Interconnection-Related Network Upgrades
             on a Percentage Basis....................
            iii. Additional Considerations............               150
            (a) Interconnection-Related Network                      150
             Upgrade Cost Sharing.....................
            (b) Option To Build.......................               151
            (c) Interconnection Request Limit.........               153
            (d) Fast-Track for Interconnection of                    154
             Generating Facilities Committed to
             Regional Transmission Facilities.........
            (e) Fast-Track for Interconnection of                    157
             ``Ready'' Generating Facilities..........
            (f) Grid-Enhancing Technologies...........               158
        C. Enhanced Transmission Oversight............               159
        1. Potential Need for Reform..................               160
        2. Potential Reforms and Request for Comment..               163
            a. State Oversight........................               176
            b. Limitation on Recovery of Costs for                   178
             Abandoned Projects.......................
            c. Additional Oversight Approaches........               180
    D. Transition.....................................               181
V. Comment Procedures.................................               183
VI. Document Availability.............................               186

I. Introduction

    1. Pursuant to its authority under section 206 of the Federal Power
Act (FPA),\1\ the Federal Energy Regulatory Commission (Commission) is
considering the potential need for reforms or revisions to existing
regulations to improve the electric regional transmission planning and
cost allocation and generator interconnection processes.
---------------------------------------------------------------------------

    \1\ 16 U.S.C. 824e. Section 206 requires that transmission rates
be just and reasonable, and not unduly discriminatory or
preferential.
---------------------------------------------------------------------------

    2. Approximately 10 years ago, the Commission issued Order No.
1000.\2\ That order stated its purpose generally in its introduction:
---------------------------------------------------------------------------

    \2\ 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).

    The reforms herein are intended to improve transmission planning
processes and cost allocation mechanisms under the pro forma Open
Access Transmission Tariff (OATT) to ensure that the rates, terms
and conditions of service provided by public utility transmission
providers are just and reasonable and not unduly discriminatory or
preferential. This Final Rule builds on Order No. 890,\3\ in which
the Commission, among other things, reformed the pro forma OATT to
require each public utility transmission provider to have a
coordinated, open, and transparent regional transmission planning
process. After careful review of the voluminous record in this
proceeding, the Commission concludes that the additional reforms
adopted herein are necessary at this time to ensure that rates for
Commission-jurisdictional service are just and reasonable in light
of changing conditions in the industry. In addition, the Commission
believes that these reforms address opportunities for undue
discrimination by public utility transmission providers.\4\
---------------------------------------------------------------------------

    \3\ Preventing Undue Discrimination and Preference in
Transmission Service, Order No. 890, 118 FERC ] 61,119, order on
reh'g, Order No. 890-A, 121 FERC ] 61,297 (2007), order on reh'g,
Order No. 890-B, 123 FERC ] 61,299 (2008), order on reh'g, Order No.
890-C, 126 FERC ] 61,228, order on clarification, Order No. 890-D,
129 FERC ] 61,126 (2009).
    \4\ Order No. 1000, 136 FERC ] 61,051 at P 1.

    3. More than a decade after Order No. 1000, we believe it
appropriate to review the issues addressed by that order and other
transmission-related regulations and determine whether additional
reforms to the regional transmission planning and cost allocation and
generator interconnection processes or revisions to existing
regulations are needed to ensure rates for Commission-jurisdictional
service remain just and reasonable, and not unduly discriminatory or
preferential. The electricity sector is transforming as the generation
fleet shifts from resources located close to population centers toward
resources, including renewables, that may often be located far from
load centers. The growth of new resources seeking to interconnect to
the transmission system and the differing characteristics of those
resources are creating new demands on the transmission system. Ensuring
just and reasonable rates as the resource mix changes, while
maintaining grid reliability, remains the priority in the regional
transmission planning and cost allocation and generator interconnection
processes.
    4. In light of these evolving conditions, we believe it timely and
appropriate 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
transmission rates remain just and reasonable and not unduly
discriminatory or preferential and that reliability is maintained.\5\
Accordingly, we will consider herein whether and which reforms and
revisions are necessary to the Commission's regulations on these
topics. This Advanced Notice of Proposed Rulemaking (ANOPR) discusses
proposals or concepts for changes to existing processes in several
broad categories: Regional transmission planning, regional cost
allocation, generator interconnection funding, generator
interconnection queueing processes and consumer protection, and in
several instances the ANOPR also offers a potential rationale or
argument for potential proposals. We note that the Commission has not
predetermined that any specific proposal discussed herein shall or
should be made or in what final form; rather, we seek comment from the
public on these proposals and welcome commenters to offer additional or
alternative proposals for consideration.
---------------------------------------------------------------------------

    \5\ 16 U.S.C. 824e.
---------------------------------------------------------------------------

    5. We believe it appropriate to review whether there are questions
that should be explored and possible solutions proposed regarding any
potential shortcomings in the existing regional transmission planning
and cost allocation and generator interconnection processes, which may
have become evident since the Commission issued Order No. 2003,\6\
Order No. 890, and Order No. 1000. We seek comment on several topics
across transmission planning and cost allocation and interconnection
queue processes, as well as oversight of transmission infrastructure
development. Examples

of such questions for which we will seek comment in this ANOPR include,
among others: (1) Whether the existing regional transmission planning
and cost allocation processes appropriately considers the transmission
needs of anticipated future generation to drive study assumptions, or
instead relies on less comprehensive information, such as existing
interconnection requests with completed facilities studies, and whether
such current planning criteria are appropriate or should be revised;
(2) whether the regional transmission planning and cost allocation
processes' consideration of transmission needs driven by reliability,
economic considerations, and Public Policy Requirements \7\ are
inappropriately siloed from one another, and, if so, whether this
influences the consideration of potential benefits of a regional
transmission facility (and the associated beneficiaries for purposes of
allocating the costs of such a facility); \8\ (3) whether criteria in
addition to those related to reliability, economic, and Public Policy
Requirements needs should be planned for and considered in the
evaluation of benefits, and used to determine cost allocation in the
regional transmission planning process, and these needs should be
clear, credibly quantifiable and not speculative; (4) how to
appropriately identify and allocate the costs of new transmission
infrastructure in a manner that satisfies the Commission's cost-
causation principle that costs are allocated to beneficiaries in a
manner that is at least roughly commensurate with estimated benefits;
(5) whether or not it is appropriate for the costs of state or local
public policy-driven transmission facilities to be shifted through
regional cost allocation to consumers in non-participating states, or
whether changes to current interconnection cost allocation mechanisms
may unjustly and unreasonably shift costs to customers of load serving
entities; \9\ (6) whether and which reforms are necessary to the
generator interconnection process to ensure a more purposeful
integration with the regional transmission planning and cost allocation
processes, a more efficient queueing process, and a more efficient and
cost-effective allocation of interconnection costs; (7) whether the
regional transmission planning and cost allocation processes may have
resulted in transmission facilities addressing an unduly narrow set of
transmission needs, including needs located in a single transmission
owner's footprint, and having limited region-wide benefits, but that,
collectively, may impose significant costs on customers; (8) whether
and how to better coordinate between regional and local transmission
planning processes to identify more efficient or cost-effective
solutions; and (9) whether it is necessary, and how, to more clearly
identify the lines of regulatory authority and oversight between states
and federal authorities with regard to regional and local transmission
facilities to ensure appropriate vetting of transmission
infrastructure. In addition, we seek comment regarding whether the
current approach to oversight of transmission investment adequately
protects customers, particularly given the potentially significant and
very costly investments proposed to meet the transmission needs driven
by a changing resource mix, and, if customers are not adequately
protected from excessive costs, which potential reforms may be required
and are legally permissible to ensure just and reasonable rates.
---------------------------------------------------------------------------

    \6\ Standardization of Generator Interconnection Agreements and
Procedures, Order No. 2003, 104 FERC ] 61,103 (2003), 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) (NARUC
v. FERC).
    \7\ 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). Order No. 1000, 136 FERC ] 61,051 at
P 2. The Commission clarified that Public Policy Requirements
established by state or federal laws or regulations include duly
enacted laws or regulations passed by a local governmental agency,
such as a municipal or county government. Order No. 1000-A, 139 FERC
] 61,132 at P 319. Order No. 1000 left planning and cost allocation
for Public Policy Requirements largely to the discretion of
transmission providers. See also infra P 16.
    \8\ A regional transmission facility is a transmission facility
located entirely in one transmission planning region. Order No.
1000, 136 FERC ] 61,051 at n.374.
    \9\ Under current Commission policy, the costs of
interconnection-related network upgrades are either (1) directly
assigned to the interconnection customer or (2) funded initially by
the interconnection customer and reimbursed through transmission
service credits.
---------------------------------------------------------------------------

II. Background

A. Regional Transmission Planning and Cost Allocation Process

    6. In 1996, the Commission issued Order No. 888 and the
accompanying pro forma OATT, setting forth certain minimum requirements
for transmission planning.\10\ In 2007, the Commission issued Order No.
890 to remedy flaws in the pro forma OATT, and in so doing, required
coordinated, open, and transparent transmission planning on both a
local and regional level. Specifically, the Commission required, among
other things, that each transmission provider's \11\ local transmission
planning process 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.\12\
---------------------------------------------------------------------------

    \10\ Promoting Wholesale Competition Through Open Access Non-
Discriminatory Transmission Services by Public Utilities; Recovery
of Stranded Costs by Public Utilities and Transmitting Utilities,
Order No. 888, FERC Stats. & Regs. ] 31,036 (1996) (cross-referenced
at 75 FERC ] 61,080), order on reh'g, Order No. 888-A, 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 Policy Study Group v. FERC, 225 F.3d 667
(D.C. Cir. 2000), aff'd sub nom. New York v. FERC, 535 U.S. 1
(2002).
    \11\ In this order, we use the term ``transmission provider''
when referring to a public utility that owns, controls, or operates
transmission facilities. The term transmission provider should be
read to include the transmission owner when the transmission owner
is separate from the transmission provider, as is the case in
regional transmission organizations (RTOs) and independent system
operators (ISOs).
    \12\ Order No. 890, 118 FERC ] 61,119 at PP 418-601.
---------------------------------------------------------------------------

    7. In 2011, the Commission issued Order No. 1000 to build on the
transmission planning requirements of Order No. 890. Order No. 1000
included a package of reforms to ensure that the transmission planning
and cost allocation mechanisms embodied in the pro forma OATT were
adequate to support the development of more efficient or cost-effective
transmission facilities.\13\ The reforms in Order No. 1000 fell into
the following categories: (1) Regional transmission planning; (2)
transmission needs driven by Public Policy Requirements; (3)
nonincumbent transmission developer reforms; (4) regional and
interregional cost allocation; and (5) interregional transmission
coordination. Here we provide a brief overview of the Order No. 1000
regional transmission planning requirements, nonincumbent developer
reforms, regional transmission cost allocation rules, and interregional
transmission coordination.
---------------------------------------------------------------------------

    \13\ Order No. 1000, 136 FERC ] 61,051 at PP 11-12, 42-44; Order
No. 1000-A, 139 FERC ] 61,132 at PP 3, 4-6.
---------------------------------------------------------------------------

1. Regional Transmission Planning Requirements
    8. Order No. 1000 requires that each transmission provider
participate in a regional transmission planning process that produces a
regional transmission plan.\14\ Through the regional transmission
planning process, transmission providers must evaluate, in consultation
with stakeholders,

alternative transmission solutions that might meet the region's
reliability, economic, and Public Policy Requirements needs \15\ more
efficiently or cost-effectively than solutions that transmission
providers identified in their local transmission planning
processes.\16\ Order No. 1000 also requires that the regional
transmission planning process satisfy the Order No. 890 transmission
planning principles.\17\ Therefore, these transmission planning
principles, which the Commission adopted with respect to local
transmission planning processes in Order No. 890, also apply to the
regional transmission planning processes established in Order No. 1000.
---------------------------------------------------------------------------

    \14\ Order No. 1000, 136 FERC ] 61,051 at PP 146, 148.
    \15\ Order No. 1000's requirement to consider transmission needs
driven by Public Policy Requirements is described below.
    \16\ Order No. 1000, 136 FERC ] 61,051 at PP 11, 148.
    \17\ Id. P 151. Order No. 890 explains these transmission
planning principles.
---------------------------------------------------------------------------

2. Nonincumbent Transmission Developer Reforms
    9. Order No. 1000 institutes a number of reforms that seek to
ensure that nonincumbent transmission developers have an opportunity to
participate in the regional transmission development process.\18\ In
particular, Order No. 1000 requires that each 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.\19\ Order No. 1000 defines a transmission facility selected
in a regional transmission plan for purposes of cost allocation as one
that has been selected because it is a more efficient or cost-effective
solution to a regional transmission need.\20\
---------------------------------------------------------------------------

    \18\ For purposes of Order No. 1000, ``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 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 project. Id. P 225.
    \19\ Id. P 313.
    \20\ Id. PP 5, 63.
---------------------------------------------------------------------------

    10. In addition, Order No. 1000 requires that each regional
transmission planning process include not unduly discriminatory
qualification criteria and information requirements for transmission
developers that want to propose a transmission facility for selection
in the regional transmission plan for purposes of cost allocation.\21\
The regional transmission planning process must also have a transparent
and not unduly discriminatory process for evaluating whether to select
a proposed transmission facility in the regional transmission plan for
purposes of cost allocation.\22\ Furthermore, the regional transmission
planning process must provide a nonincumbent transmission developer
with the same eligibility as an incumbent transmission developer to use
a cost allocation method(s) for any sponsored transmission facility
selected in the regional transmission plan for purposes of cost
allocation.\23\
---------------------------------------------------------------------------

    \21\ Id. PP 225, 323, 325.
    \22\ Id. P 328; Order No. 1000-A, 139 FERC ] 61,132 at P 452.
    \23\ Order No. 1000, 136 FERC ] 61,051 at P 332.
---------------------------------------------------------------------------

3. Regional Transmission Cost Allocation
    11. Order No. 1000 requires each transmission provider to have in
place a method, or set of methods, for allocating the costs of new
regional transmission facilities selected in the regional transmission
plan for purposes of cost allocation.\24\ Each regional cost allocation
method must satisfy six regional cost allocation principles,\25\
including the principle that the cost of transmission facilities must
be allocated to those in the transmission planning region that benefit
from the facilities in a manner that is roughly commensurate with
estimated benefits.\26\
---------------------------------------------------------------------------

    \24\ Id. P 558.
    \25\ Id. P 603.
    \26\ Id. PP 622, 639.
---------------------------------------------------------------------------

4. Interregional Transmission Coordination
    12. Order No. 1000 requires each transmission provider, through its
regional transmission planning process, to establish further procedures
with each of its neighboring transmission planning regions for the
purpose of coordinating and sharing the results of respective regional
transmission plans to identify possible interregional transmission
facilities that could address transmission needs more efficiently or
cost-effectively than separate regional transmission facilities. The
interregional coordination processes must provide for: (1) The sharing
of information regarding the respective needs of each region and
potential solutions to those needs; and (2) the identification and
evaluation of interregional transmission facilities that may be more
efficient or cost-effective solutions to those regional needs.\27\
---------------------------------------------------------------------------

    \27\ Id. P 396.
---------------------------------------------------------------------------

B. Overview of Transmission Planning

    13. The next few paragraphs provide an overview of how transmission
providers plan their systems to meet their reliability, economic, and
Public Policy Requirements needs, consistent with Order Nos. 890 and
1000.
1. Reliability Needs
    14. Transmission providers within transmission planning regions
conduct reliability planning studies to help ensure the ability of the
transmission system to serve firm transmission use. These studies may
extend 10 to 15 years into the future depending on the transmission
planning region's transmission planning process and tests for
violations of established North American Electric Reliability
Corporation (NERC) reliability requirements.\28\ 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
be able to withstand a range of probable contingencies (e.g., the
sudden loss of a generator or high voltage transmission line) while
reliably serving customer demand and preventing cascading outages.\29\
Generally, transmission providers identify areas not in compliance with
planning criteria and develop plans to achieve compliance. Transmission
providers examine facilities to mitigate identified reliability
criteria violations for their feasibility, impact, and comparative
costs, culminating in a recommended regional transmission plan.
---------------------------------------------------------------------------

    \28\ 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.
    \29\ 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.
---------------------------------------------------------------------------

2. Economic Needs
    15. 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

transmission providers to perform economic planning studies absent a
request by stakeholders. To remedy this deficiency, Order No. 1000
required that, in addition to economic planning studies requested by
stakeholders, transmission providers evaluate, through a regional
transmission planning process and in consultation with stakeholders,
alternative transmission solutions that might meet the needs of the
transmission planning region more efficiently or cost-effectively than
solutions identified by individual transmission providers in their
local transmission planning process. These regional transmission
solutions could include transmission facilities needed to meet
reliability requirements, address economic considerations, and/or meet
transmission needs driven by Public Policy Requirements.\30\ 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.\31\ However, to implement the requirement in Order No. 1000
to affirmatively plan for economic needs, transmission providers
implemented thresholds that vary across the regions. 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.
---------------------------------------------------------------------------

    \30\ Order No. 1000, 136 FERC ] 61,051 at PP 147-148.
    \31\ Order No. 890, 118 FERC ] 61,119 at P 549.
---------------------------------------------------------------------------

3. Public Policy Requirement Needs
    16. Order No. 1000 requires transmission providers to consider
transmission needs driven by Public Policy Requirements in their local
and regional transmission planning processes.\32\ However, the
requirement in Order No. 1000 to consider transmission needs driven by
Public Policy Requirements is limited, and the Commission provided
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,\33\ nor does it mandate the consideration of any
particular transmission need driven by a Public Policy Requirement.\34\
As a result, the process for identifying and considering such needs
varies from transmission planning region to transmission planning
region.
---------------------------------------------------------------------------

    \32\ Order No. 1000, 136 FERC ] 61,051 at PP 203, 222; Order No.
1000-A, 139 FERC ] 61,132 at P 208.
    \33\ Order No. 1000, 136 FERC ] 61,051 at P 220 (explaining that
the Final Rule is intended to ``provide flexibility for public
utility transmission providers to develop procedures appropriate for
their local and regional transmission planning processes'').
    \34\ Id. P 215.
---------------------------------------------------------------------------

4. Local Transmission Facilities in the Regional Transmission Planning
Process
    17. Generally, the transmission facilities that 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.

C. Overview of Generator Interconnection

    18. In Order No. 2003, the Commission recognized a need for a
single set of interconnection procedures for jurisdictional
transmission providers and a single, uniformly applicable
interconnection agreement for large generators.\35\ The Commission
explained that generator interconnection is a ``critical component of
open access transmission service and thus is subject to the requirement
that utilities offer comparable service under the OATT.'' \36\ The
Commission also determined that, because of the inefficiency of
addressing generator interconnection issues on a case-by-case
basis,\37\ it was appropriate to establish a standard set of generator
interconnection procedures to ``minimize opportunities for undue
discrimination and expedite the development of new generation, while
protecting reliability and ensuring that rates are just and
reasonable.'' \38\ To this end, the Commission adopted the pro forma
Large Generator Interconnection Procedures (LGIP) and pro forma Large
Generator Interconnection Agreement (LGIA) \39\ and required that all
transmission providers' OATTs incorporate the pro forma LGIP and pro
forma LGIA.
---------------------------------------------------------------------------

    \35\ Order No. 2003, 104 FERC ] 61,103 at P 11.
    \36\ Id. P 9 (citing Tenn. Power Co., 90 FERC ] 61,238 (2000)).
    \37\ Id. P 10.
    \38\ Id. P 11.
    \39\ The pro forma LGIP and pro forma LGIA govern large
generating facilities, which are generating facilities that have a
generating facility capacity of more than 20 MW.
---------------------------------------------------------------------------

    19. In Order No. 2003, the Commission also retained a distinction
between interconnection facilities, which are located between the
interconnection customer's generating facility and the transmission
provider's transmission system, and network upgrades,\40\ which include
only facilities at or beyond the point where the interconnection
customer's generating facility interconnects to the transmission
provider's transmission system.\41\ This distinction is important
because the determination of which entity is ultimately responsible for
the cost of a facility can depend on whether that facility is an
interconnection facility or an interconnection-related network upgrade.
---------------------------------------------------------------------------

    \40\ For clarity, this ANOPR will refer to these facilities as
interconnection-related network upgrades.
    \41\ Id. P 21.
---------------------------------------------------------------------------

    20. To initiate the generator interconnection process set forth in
Order No. 2003,\42\ the interconnection customer submits an
interconnection request associated with its proposed generating
facility that includes preliminary site documentation, certain
technical information about the proposed generating facility, and the
expected in-service date along with a deposit.\43\ The transmission
provider uses this information to determine the interconnection
facilities and interconnection-related network upgrades necessary to
accommodate the interconnection request and their associated costs.\44\
---------------------------------------------------------------------------

    \42\ While we provide a broad description of the generator
interconnection process under Order No. 2003 as background here, we
recognize that many transmission providers have adopted (and the
Commission has accepted) variations to many of the terms in the pro
forma LGIP and the pro forma LGIA. Consequently, some or many of the
details of a particular transmission provider's generator
interconnection process may vary considerably from the broad
description provided here.
    \43\ Id. P 35.
    \44\ Pro forma LGIP Section 3.1.
---------------------------------------------------------------------------

    21. After the transmission provider determines that the
interconnection request is complete, the interconnection request will
enter the interconnection queue with other pending requests, and the
transmission provider will assign the request a queue position based on
the date and time of receipt. The queue position will determine the
order in which the transmission provider will perform three phases of
interconnection studies for the interconnection request. The three
phases in order are: (1) The feasibility study; (2) the system impact

study; and (3) the facilities study, all of which are necessary to
determine the interconnection facilities and interconnection-related
network upgrades needed to accommodate the interconnection request and
the interconnection customer's cost responsibility for these
facilities.\45\
---------------------------------------------------------------------------

    \45\ Order No. 2003, 104 FERC ] 61,103 at PP 35-36. The
interconnection customer is responsible for the costs of
interconnection studies and any necessary restudies.
---------------------------------------------------------------------------

    22. At the completion of the facilities study, the transmission
provider will issue a report, which includes a ``best estimate of the
costs to effect the requested interconnection,'' and provide a draft
generator interconnection agreement to the interconnection
customer.\46\ If the interconnection customer wishes to proceed, after
negotiations, the interconnection customer enters into a generator
interconnection agreement with the transmission provider or requests
that the transmission provider file the agreement with the Commission
unexecuted.\47\
---------------------------------------------------------------------------

    \46\ Id. P 38.
    \47\ Id.
---------------------------------------------------------------------------

D. Interaction Between the Regional Transmission Planning and Cost
Allocation and Generator Interconnection Processes

    23. The interaction between a transmission provider's current
generator interconnection process and its regional transmission
planning and cost allocation processes appears to be limited. The
primary interaction is that the baseline regional transmission planning
models generally only incorporate interconnection projects that are
near the end of the interconnection process and have completed a
facilities study. In addition, when creating interconnection study
models, transmission providers incorporate transmission planning
information into the interconnection base cases, but what information
is incorporated varies for each transmission provider. The base cases
for interconnection studies impact the cost assignment for
interconnection customers, often dramatically, and at present, most
transmission providers' OATTs do not contain requirements for what
information is included in base cases.\48\
---------------------------------------------------------------------------

    \48\ For example, some transmission providers have details
regarding what information is included in an interconnection study
base case in their tariffs, see e.g. Sw. Power Pool, Inc., 172 FERC
] 61,283, at P10 (2020), while others limit that information to the
business practices manuals. See, e.g., NYISO Manual 26, Reliability
Planning Process Manual at 15-16.
---------------------------------------------------------------------------

E. Current Funding Paradigm

1. Regional Transmission Cost Allocation
    24. As noted above, Order No. 1000's cost allocation reforms
require each transmission provider to participate in a regional
transmission planning process that features a regional cost allocation
method or methods for allocating the cost of new regional transmission
facilities selected in a regional transmission plan for purposes of
cost allocation. The Commission also required that such regional cost
allocation methods satisfy six regional cost allocation principles,
including the principle that the cost of transmission facilities must
be allocated to those in the transmission planning region that benefit
from the facilities in a manner that is roughly commensurate with
estimated benefits.\49\
---------------------------------------------------------------------------

    \49\ Order No. 1000, 136 FERC ] 61,051 at PP 622, 639. The six
Order No. 1000 regional cost allocation principles are discussed
further below.
---------------------------------------------------------------------------

2. Local Transmission Facilities
    25. In Order No. 1000, the Commission explained that the local
transmission planning process is the transmission planning process that
a transmission provider performs for its individual retail distribution
service territory or footprint pursuant to the requirements of Order
No. 890.\50\ The outcome of the local transmission planning processes
are local transmission facilities. In Order No. 1000, the Commission
defined a local transmission facility as a transmission facility
located solely within a transmission provider's retail distribution
service territory or footprint that is not selected in the regional
transmission plan for purposes of cost allocation.\51\
---------------------------------------------------------------------------

    \50\ Id. P 68.
    \51\ Id. P 63.
---------------------------------------------------------------------------

    26. The Commission clarified that, if the transmission provider has
a retail distribution service territory and/or footprint, then only a
transmission facility that it decides to build within that retail
distribution service territory or footprint, and that is not selected
in a regional transmission plan for purposes of cost allocation, may be
considered a local transmission facility. Further, the Commission
explained that, in the case of an RTO/ISO whose footprint covers the
entire region, local transmission facilities are defined by reference
to the retail distribution service territories or footprints of its
underlying transmission owing members.\52\ The Commission did not
require that the transmission facilities in a transmission provider's
local transmission plan be subject to approval at the regional or
interregional level, unless that transmission provider seeks to have
any of those facilities selected in the regional transmission plan for
purposes of cost allocation.\53\
---------------------------------------------------------------------------

    \52\ Order No. 1000-A, 139 FERC ] 61,132 at P 429.
    \53\ Id. P 190.
---------------------------------------------------------------------------

    27. Moreover, local transmission facilities planned through a local
transmission planning process are not eligible to use the Order No.
1000 regional cost allocation method and instead their costs are
allocated to the transmission provider in whose retail distribution
service territory or footprint the local transmission facility is
located. In support of this, the Commission explained that it continues
to permit 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 as long as the transmission provider
does not receive regional cost allocation for the facilities.\54\
Further, the Commission clarified that nothing in Order No. 1000
restricts an incumbent transmission provider from developing a local
transmission solution that is not eligible for regional cost allocation
to meet its reliability needs or service obligations in its own retail
distribution service territory or footprint.\55\
---------------------------------------------------------------------------

    \54\ Id. PP 366, 379, 425, 428.
    \55\ Order No. 1000, 136 FERC ] 61,051 at P 329.
---------------------------------------------------------------------------

3. Interconnection-Related Network Upgrades
    28. The Commission's interconnection pricing policy \56\ allows for
two general approaches on how to assign the cost of interconnection-
related network upgrades, one of which we refer to as the crediting
policy and the other as participant funding. We will discuss the
rationale that the Commission provided when accepting each of the two
approaches in later sections.
---------------------------------------------------------------------------

    \56\ We use the term interconnection pricing policy to refer
collectively to both Order No. 2003's establishment of the crediting
policy for financing interconnection-related network upgrades and
Order No. 2003's allowance of participant funding for
interconnection-related network upgrades in RTOs/ISOs.
---------------------------------------------------------------------------

    29. In Order No. 2003, the Commission established the crediting
policy as a requirement of the Commission's interconnection pricing
policy. Pursuant to the crediting policy, the interconnection customer
is solely responsible for the costs of interconnection facilities, and
interconnection-related network upgrades are funded initially by the

interconnection customer (unless the transmission provider elects to
fund them) and the transmission provider reimburses the interconnection
customer through transmission service credits.\57\ The Commission
reasoned that ``it is appropriate for the Interconnection Customer to
pay initially the full cost of Interconnection Facilities and
[interconnection-related] Network Upgrades that would not be needed but
for the interconnection.'' \58\ While the interconnection customer pays
for the costs of the interconnection-related network upgrades upfront,
the transmission provider must reimburse the total amount that the
interconnection customer paid for interconnection-related network
upgrades, plus interest, as credits against the charges for
transmission service taken with respect to the interconnection
customer's generating facility as such charges are incurred. The
transmission provider recovers the cost of interconnection-related
network upgrades funded under the crediting policy through its embedded
cost transmission rates.\59\ The second pricing approach for
interconnection-related network upgrades is called participant funding.
Participant funding for interconnection-related network upgrades refers
to the direct assignment to a particular interconnection customer of
the costs of interconnection-related network upgrades that would not be
needed but for the interconnection.\60\ The Commission has accepted as
just and reasonable various participant funding approaches proposed by
RTOs/ISOs as independent entity variations from the pro forma
requirements of Order No. 2003.
---------------------------------------------------------------------------

    \57\ Order No. 2003, 104 FERC ] 61,103 at P 22.
    \58\ Id. P 694. ``But for'' interconnection-related network
upgrades are those interconnection-related network upgrades that
would not have been constructed ``but for'' the interconnection
request. See N.Y. Indep. Sys. Operator, Inc., 122 FERC ] 61,267, at
n.3 (2008).
    \59\ The embedded cost pricing ``attempts to allocate costs
among customers based upon usage.'' Fla. Power & Light Co., 70 FERC
] 61,158 (1995). Embedded cost rates reflect ``system average costs
including the cost of the [interconnection-related] network
upgrades, and incremental cost rates ``reflect [ ] just the cost of
the [interconnection-related] network upgrades.'' See Interstate
Power & Light Co. v. ITC Midwest, LLC, 144 FERC ] 61,052, at P 36
(2013) (emphasis added).
    \60\ Order No. 845-B, 166 FERC ] 61,092 at P 5; see also Order
No. 2003, 104 FERC ] 61,103 at P 679 (pursuant to a ``policy of
participant funding . . . those [that] benefit from a particular
project pay for it'').
---------------------------------------------------------------------------

III. The Potential Need for Reform

A. The Existing Regional Transmission Planning and Cost Allocation and
Generator Interconnection Processes May Be Inadequate To Ensure Just
and Reasonable Rates

    30. As a result of changing circumstances since the Commission
issued Order Nos. 890, 1000, and 2003, we believe it is now appropriate
to examine whether the existing regional transmission planning and cost
allocation and generator interconnection processes adequately account
for the transmission needs of the changing resource mix, or whether
reforms may be necessary to ensure that transmission rates remain just
and reasonable and not unduly discriminatory or preferential.
1. Considering Anticipated Future Generation
    31. Expansion of the transmission system generally occurs by design
through a transmission provider's transmission planning processes, or
ad hoc through its generator interconnection process. At present, it
appears 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, including considering the needs of
anticipated future generation in identifying needed transmission
facilities. Although regional transmission planning processes may
include some level of generation development in different future
scenarios analyses, it appears that they tend to include in their
baseline reliability models only those generators that have completed
facilities studies, and thus are far along in the generator
interconnection process. These baseline reliability models, by relying
only on generators that have completed facilities studies, may only
account for generation that will come online in the short term.
    32. As a result, the generator interconnection process appears to
be the principal means by which infrastructure is built to accommodate
new generators. That process, however, focuses on a single
interconnection request (or cluster of requests). In other words, the
generator interconnection process is not designed to consider how to
address anything beyond the reliability interconnection-related network
upgrades required for a specific interconnection request or group of
interconnection requests.
    33. New transmission facilities often have a development lead time
that exceeds the interconnection timing needs of those interconnection
customers already in the queue. It appears that these types of
transmission facilities may not currently be planned and built in
advance to meet the needs of anticipated future generation and as a
result, interconnection customers are assigned the costs to construct
large, high-voltage transmission facilities.
    34. In addition, because transmission planning processes generally
do not plan for the needs of anticipated future generation,
transmission infrastructure that is being developed in order to
facilitate new generation is constructed largely through the generator
interconnection process, which is unlikely to result in the economies
of scale that could more efficiently or cost-effectively meet the needs
of the changing resource mix.
    35. Likewise, the existing generator interconnection process
appears to focus on the limited set of facilities needed to reliably
interconnect a single interconnection customer (or cluster of requests)
at the interconnection service level that the interconnection customer
requests. The generator interconnection process may not adequately
consider whether it may be more efficient or cost-effective to consider
the interconnection-related network upgrades needed for multiple
anticipated future generators that are not in the same cluster or are
not yet in the interconnection queue in areas that have abundant wind
or solar attributes that could support multiple future generators.\61\
---------------------------------------------------------------------------

    \61\ We note that certain regions do have the ability to share
costs of network upgrades with future generation, but this is
generally limited to the short term. For example, Midcontinent
Independent System Operator, Inc.'s (MISO's) Shared Network Upgrade
construct allows interconnection customers to be repaid for portions
of an interconnection-related network upgrade's cost if another
interconnection customer uses that network upgrade within five
years.
---------------------------------------------------------------------------

    36. In addition, there may be a need for coordination between the
regional transmission planning process and the generator
interconnection process, the absence of which may result in inefficient
investment in transmission infrastructure and ultimately unjust and
unreasonable or unduly discriminatory or preferential rates. By
considering the transmission needs of anticipated future generation in
its regional transmission planning and cost allocation processes, a
transmission provider may identify transmission facilities that could
facilitate both the interconnection of new generation as well as
address other identified transmission system needs--such as mitigating
a reliability violation or reducing congestion--at a lower total cost
than pursuing two separate transmission projects through the

generator interconnection and regional transmission planning and cost
allocation processes. Without co-optimization of the two processes,
however, there appears to be no system in place to jointly assess the
benefits and allocate the costs of transmission facilities that yield
benefits to both system loads and new generation.
2. Results of Existing Local and Regional Transmission Planning
Processes
    37. We seek to better understand whether 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. 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. We seek 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.
3. Cost Responsibility for Transmission Facilities and Interconnection-
Related Network Upgrades
    38. The Commission cannot ensure just and reasonable rates without
considering how to allocate the costs of transmission facilities and
interconnection-related network upgrades that result from the regional
transmission planning and cost allocation and generator interconnection
processes to the entities that benefit from those facilities. As the
Commission explained in Order No. 1000, the costs of transmission
infrastructure must be allocated to its beneficiaries in a manner that
is at least roughly commensurate with the benefits that they draw from
those facilities.\62\ We seek to better understand whether the current
approach to allocating the costs of transmission infrastructure,
including transmission facilities developed through the regional
transmission planning and cost allocation processes and
interconnection-related network upgrades planned through the generator
interconnection process, continues to appropriately allocate the costs
of those transmission facilities to the entities that ultimately
benefit from them.
---------------------------------------------------------------------------

    \62\ Order No. 1000, 136 FERC ] 61,051 at P 10.
---------------------------------------------------------------------------

    39. The current regional transmission planning process considers
transmission needs driven by reliability, economics, and Public Policy
Requirements. We seek comment whether, by separating transmission
facilities into types, transmission planning processes may fail to take
into account the benefits of multi-faceted projects for the purposes of
cost allocation.
    40. The current approach to allocating the costs of
interconnection-related network upgrades may fail to allocate costs in
a manner that is roughly commensurate with benefits. As discussed
above, the generator interconnection process identifies the
interconnection facilities and interconnection-related network upgrades
needed to interconnect a single interconnection request (or cluster of
requests). Under the participant funding approach to financing the cost
of interconnection-related network upgrades, the interconnection
customer pays for the costs of such upgrades, even where they would
provide benefits to other customers such as resolving congestion on the
transmission system. At the time that the Commission issued Order No.
2003, it was less likely that interconnection customers would be
assigned significant interconnection-related network upgrades through
the interconnection study process. Now, however, there is little
remaining existing interconnection capacity on the transmission system,
particularly in areas with high degrees of renewable resources that may
require new resources to fund interconnection-related network upgrades
that are more extensive and, as a result, more expensive. The more
significant the interconnection-related network upgrades needed to
accommodate a new resource, the greater the potential that such
upgrades may benefit more than just the interconnection customer. Where
an interconnection customer elects not to pursue a generating facility
with system-wide benefits that exceeds such facility's cost, net
beneficial infrastructure would not be developed, potentially leaving a
wide range of customers worse off as a result.
    41. We also note that the cost of interconnection-related network
upgrades can depend entirely on both the timing of when and the
specific site where the interconnection customer enters the
interconnection queue that may result in interconnection customers
submitting multiple speculative interconnection requests in an effort
to receive a favorable queue position and reduce their interconnection-
related network upgrade costs.\63\ When interconnection customers
``test the waters'' in this manner, it may lead to late-stage
withdrawals of the excess interconnection requests that can then impede
the transmission provider's ability to process its interconnection
queue in an efficient manner. Because of the changing interconnection
landscape since Order No. 2003, the Commission's interconnection
pricing policy, and in particular participant funding, now may result
in a situation where interconnection customers have a financial
incentive to submit multiple speculative projects. As a result, we
believe it may be time to reexamine the rationale behind the
Commission's pricing policy established for interconnection-related
network upgrades and to consider reforms to generator interconnection
processes that would make such processes more efficient, less costly,
and ensure that generation projects that are more ``ready'' than others
are not unduly delayed in the queue. In consideration of generator
interconnection process reforms, we remain mindful of the need to
ensure that interconnection costs are not unjustly and unreasonably
shifted to customers of load-serving entities.
---------------------------------------------------------------------------

    \63\ See, e.g., Review of Generator Interconnection Agreements
and Procedures, Technical Conference Transcript, Docket No. RM16-12-
000, at Tr. 211:10-21 (May 13, 2016) (Steve Naumann, Exelon
Corporation) (filed Aug. 23, 2016) (``We would look at putting let's
say new gas fired generation in PJM, it may have four queue
positions. And we only intend to go through with one, that's not
speculation, that's trying to get information on which is the most
viable.'').
---------------------------------------------------------------------------

    42. While a reassessment of Order No. 2003's assumptions pertaining
to the Commission's interconnection pricing policy may be necessary,
our focus is in line with Order No. 2003's finding that ``relatively
unencumbered entry into the market is necessary for competitive
markets.'' \64\ Furthermore, the purpose of this examination is also
consistent with the original objectives of Order No. 2003, namely to
``limit opportunities for Transmission Providers to favor their owner
generation'' and to ``facilitate market entry for generation
competitors by reducing interconnection costs and time.'' \65\ At the
same time, there is reason to question the contention in Order No. 2003
that participant funding provides more ``efficient price signals and a
more equitable allocation of costs than the crediting approach.'' \66\
Also, while the crediting policy ``recognizes the reliability benefits
of a stronger

transmission infrastructure and more competitive power markets that
result from a policy that facilitates the interconnection of new
generating facilities,'' \67\ we raise questions on whether there are
improvements that can be made to the crediting policy or whether a
different pricing policy may be more efficient.
---------------------------------------------------------------------------

    \64\ Order No. 2003, 104 FERC ] 61,103 at P 11.
    \65\ Id. P 12.
    \66\ Id. P 695.
    \67\ Order No. 2003-A, 106 FERC ] 61,220 at P 584.
---------------------------------------------------------------------------

    43. We note that ensuring just and reasonable rates, while
maintaining grid reliability, remain the priorities for regional
transmission planning, and cost allocation processes, and generator
interconnection processes, and any comments proposing revisions to
existing regulations should address their impact on reliability and
costs to customers. All proposed reforms or revisions to regulations
proposed in this proceeding must be consistent with the Commission's
authority under section 206 of the FPA.

IV. Consideration of Potential Reforms and Request for Comment

A. Regional Transmission Planning and Cost Allocation Processes

1. Potential Reforms and Request for Comment
a. Planning for the Transmission Needs of Anticipated Future Generation
    44. We seek comment regarding whether transmission providers in
each transmission planning region should amend the regional
transmission planning and cost allocation processes to plan for the
transmission needs of anticipated future generation to meet a changing
resource mix, including generation that is not yet in the
interconnection queue. We seek comment on whether the existing regional
transmission planning and cost allocation processes fail to adequately
account for anticipated future generation. We also seek comment on
whether the possible failure to account for anticipated future
generation results in inefficient investment in transmission
infrastructure and causes customers to pay unjust and unreasonable
rates for transmission service. We also seek comment on whether, and,
if so, how the Commission could structure and implement a framework for
considering the transmission needs of anticipated future generation in
the regional transmission planning and cost allocation processes.
Commenters should address how each suggested reform or revision to
existing rules is consistent with the Commission's authority under the
FPA.
    45. Below, we describe potential changes to the regional
transmission planning and cost allocation processes that may be
components of a process that plans for transmission needs associated
with anticipated future generation. We seek comment on each of these
potential changes, including whether and, if so, how the potential
changes may lead to identification of more efficient or cost-effective
transmission solutions to meet the needs of anticipated future
generation. We also seek comment on whether there exist other potential
revisions that could improve regional transmission planning and cost
allocation for anticipated future generation, either as alternatives to
potential reforms discussed herein or as supplementary reforms.
i. Future Scenarios and Modeling Anticipated Future Generation
    46. We seek comment on whether reforms are needed regarding how the
regional transmission planning and cost allocation processes model
future scenarios to ensure that those scenarios incorporate
sufficiently long-term and comprehensive forecasts of future
transmission needs. We seek comment on what factors shaping the
generation 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 enshrined into law;
(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. With regard to each
factor that may be considered for inclusion in scenario modeling, we
seek comment on the source of the Commission's authority to incorporate
that factor in the regional transmission planning and cost allocation
processes. In addition, we seek comment on whether the Commission
should establish minimum requirements regarding future scenarios for
transmission providers to use in their regional transmission planning,
including modeling anticipated future generation in those scenarios.
Commenters should also address whether and how any reforms or revisions
to existing rules could unjustly and unreasonably shift additional
costs to customers of load serving entities. Commenters should also
address whether the status quo does or does not allocate costs in a
manner roughly commensurate with benefits, and whether the status quo
leads to rates that are unjust or unreasonable.
    47. The current regional transmission planning and cost allocation
processes vary regarding how far into the future transmission providers
look when evaluating transmission needs driven by reliability, economic
considerations, or Public Policy Requirements. In general, however, the
extent to which regional transmission planning processes plan for
anticipated future generation is often limited to generation in the
generator interconnection queue with a completed facilities study,
which represents a relatively short-term outlook, and therefore may
under-forecast anticipated future generation on a longer-term basis
(and the associated transmission needs of that anticipated future
generation). As noted, planning and developing the transmission
facilities needed to address more efficiently or cost-effectively the
transmission needs of a changing resource mix will often take
considerably longer than the typical development timeline of a
generating facility that has completed a facilities study and by
considering such a limited subset of generation resources, more cost-
effective transmission facilities that address longer-term needs may
never be developed.
    48. In light of the above, we seek comment on whether, and if so,
how the regional transmission planning process should be restructured
to consider a longer-term outlook. We seek comment on whether
developing plausible long-term scenarios would lead to the
identification of more efficient or cost-effective transmission
solutions in regional transmission plans, whether building transmission
facilities to accommodate anticipated future generation is required to
render rates just and reasonable, and whether there are deficiencies in
existing regional transmission planning and cost allocation processes
that would be cured by conducting such future scenarios planning.
Specifically, we seek comment on whether the development of longer-term
scenarios for planning purposes should be pursued and, if so: (1) The
number of years into the future the scenarios should consider
(including an explanation of how far ahead it is reasonable to forecast
anticipated future generation and system requirements); (2) the inputs
that should be considered in modeling anticipated future generation;
(3) different transmission planning methods, including whether
consideration should be given to multiple future scenarios, as well as
how the planning process should consider the probabilities of future

scenarios; (4) whether and how transmission providers should account
for an array of different future scenarios when identifying more
efficient or cost-effective transmission solutions in regional
transmission plans; (5) whether and how transmission providers should
account for federal, state, local, and individual utility energy and
climate goals (including federal, state and local laws and regulations,
as well as other policies or goals), and the source of the Commission's
authority to account for such laws, regulations, policies and goals;
(6) whether and how transmission providers should plan for expected
future generator retirements; (7) whether and how Grid-Enhancing
Technologies \68\ should be accounted for in determining what
transmission is needed under such scenarios; (8) how benefits and costs
of transmission infrastructure should be accounted for in such models,
including how adjusted production costs should be calculated; (9) any
other aspects of future scenarios modeling, including planning for
anticipated future generation and associated transmission needs that
would be useful for the Commission to consider.
---------------------------------------------------------------------------

    \68\ Grid Enhancing Technologies increase the capacity,
efficiency, or reliability of transmission facilities. 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. FERC, Grid
Enhancing Technologies, Notice of Workshop, Docket No. AD19-9-000
(Sept. 9, 2019).
---------------------------------------------------------------------------

    49. In addition, we seek comment on whether greater use of
probabilistic transmission planning approaches may better assess the
benefits of regional transmission facilities. While some transmission
providers consider a small number of future scenarios as part of their
transmission planning process, more advanced approaches, such as
stochastic \69\ techniques, may provide an opportunity to consider a
broader array of potential future conditions. Accordingly, we seek
comment on potential benefits and drawbacks of such techniques in
regional transmission planning assessments, including whether these or
other new approaches may facilitate the co-optimization of generation
siting and transmission development, whether such methods capture
savings in generation capital costs as well as production expenses that
can be realized from transmission additions, and whether implementing
such methods is required to render rates just and reasonable.
---------------------------------------------------------------------------

    \69\ Stochastic models are frameworks for addressing
optimization problems that involve uncertainty.
---------------------------------------------------------------------------

    50. We also seek comment on which inputs and assumptions
transmission providers would need to model to represent new generation
sources, such as renewable resources, in order to reflect their actual
performance, such as active power-frequency control, reactive power-
voltage control, and fault ride-through capabilities, in the planning
study cases and any additional studies in order to ensure that
transmission planning solutions result in operating reliability for the
future.
    51. We seek comment on the extent to which anticipated generation
and transmission facility retirements are reflected in future scenarios
modeled by transmission providers, and whether modifications to
regional market rules and coordination processes between local and
regional plans could facilitate more accurate regional transmission
plans that reflect such anticipated retirements.
    52. In addition, should the use of certain long-term scenarios be
shown appropriate as part of ensuring just and reasonable rates, we
seek comment on whether and how the Commission should ensure that the
regional transmission planning and cost allocation processes develop a
sufficiently wide range of future scenarios. We seek comment on whether
the Commission should consider principles or minimum requirements as a
basis for establishing such scenarios. Given that states or other local
governing bodies may be uniquely situated in determining how much
anticipated future generation is needed, or in providing information
related to infrastructure siting or resource mix as influenced by state
and local policies, we seek comment on how their input should be
reflected by transmission providers in developing a sufficiently wide
range of future scenarios, including those for anticipated future
generation, and the more efficient or cost-effective transmission
facilities that may be necessary to facilitate those future scenarios.
We seek comment on whether it is necessary to require transmission
providers to modify the regional transmission planning and cost
allocation processes, such as requiring additional stakeholder input,
to develop future scenarios, including those for anticipated future
generation, such that there are sufficient opportunities for
stakeholders to assess the reasonableness of the results, as well as
for future modifications to the planning process.
    53. Finally, we seek comment on whether and how such long-term
scenarios should be used in identifying and selecting solutions to meet
future transmission needs. For example, as discussed below, should
transmission providers focus on a broader set of benefits for
transmission facilities and a portfolio of transmission facilities in
identifying the more efficient or cost-effective transmission
solutions? If so, how should regional planning processes determine the
right set of benefits to factor into such an evaluation? Is maximizing
net benefits an appropriate criterion to use to identify efficient and
cost-effective transmission solutions? Should the willingness of some
beneficiaries to pay for certain transmission infrastructure, for
example utilities or corporations with renewable resource or zero
carbon goals, be considered in determining whether to include the
benefits within a broader set of benefits from transmission facilities,
and if so then how? Is there a need to establish a minimum set of
transmission facility benefits that transmission providers must
incorporate into regional transmission planning decisions, and if so,
is there also a need to regularly update the minimum set of
transmission facility benefits?
ii. Identifying Geographic Zones That Have Potential for High Amounts
of Renewable Resource Development To Meet Increased Demand
    54. We seek comment on whether the Commission should require
transmission providers in each transmission planning region to
establish, as part of their regional transmission planning and cost
allocation processes, a process to identify geographic zones that have
the potential for the development of large amounts of renewable
generation and plan transmission to facilitate the integration of
renewable resources in those zones.
    55. Examples of transmission planning and development initiatives
that have identified geographic zones with the potential for the
development of significant amounts of renewable resources and
transmission to facilitate the integration of renewable resources in
those zones include the Public Utility Commission of Texas's (Texas
Commission) Competitive Renewable Energy Zones (CREZ) initiative \70\
and MISO's Multi-Value Projects (MVP).\71\
---------------------------------------------------------------------------

    \70\ http://www.ercot.com/committee/crez.
    \71\ https://www.misoenergy.org/planning/planning/multi-value-projects-mvps/.
---------------------------------------------------------------------------

    56. California Independent System Operator Corporation (CAISO)
offers another example of a regional transmission planning process
identifying transmission facilities to accommodate renewable resources
in

geographic zones that have the potential for high amounts of renewable
resources. In a petition for declaratory order, the Commission approved
a mechanism to facilitate the financing and development of transmission
facilities to interconnect multiple resources that met CAISO's
eligibility requirements, including a high voltage level and providing
access to areas rich in renewable energy.\72\
---------------------------------------------------------------------------

    \72\ Cal. Indep. Sys. Operator Corp., 119 FERC ] 61,061 (2007).
---------------------------------------------------------------------------

    57. We seek comment on whether the Commission should require
transmission providers in each transmission planning region to
establish, as part of their regional transmission planning and cost
allocation processes, a process that identifies geographic zones that
have the potential for the development of large amounts of new
generation, particularly renewable resources. We seek comment on
whether and how such a process might interrelate with existing regional
transmission planning and cost allocation processes within each region,
and how long-term scenario planning discussed above may be used in this
process or other relevant regional transmission planning and cost
allocation processes. In addition, we seek comment on whether reforms
to the current interregional transmission coordination process are
needed or appropriate for making an approach along these lines
effective. We also seek comment on: (1) How the Commission should
structure this potential requirement; and (2) any potential best
practices, analyses, models, and metrics that could be used to identify
such zones, including the amount and type of potential generation that
could be located there. As with the future scenarios transmission
planning discussed above, we seek comment on whether and how states and
local entities may provide input into the identification of such zones.
We seek comment on whether, and, if so, how transmission providers can
assess whether there is sufficient commercial interest in developing
generation in any potential zones and transmission to interconnect the
potential generation (for example, through studies or formal
declarations of interest). We also seek comment on whether and, if so,
what safeguards or incentives might be necessary to ensure that
transmission infrastructure is built only to satisfy expected
transmission needs and not overly speculative commercial interests. We
also seek comment on whether any such requirement is consistent with
the FPA's prohibition of unduly discriminatory or preferential rates.
    58. We seek comment on whether the Commission should require
transmission providers to account for trends in the resource mix in
developing energy zones for anticipated future generation as part of
planning for transmission needs related to such resources and if so,
what would be the best way to do so? We seek comment whether it would
be appropriate, as the resource mix further develops, to develop
similar zones for the transmission needs driven by the development and
interconnection of energy storage resources and how to do so.
    59. In order to ensure that the more efficient or cost-effective
transmission facilities are selected and that rates are just and
reasonable, we also seek comment on whether: (1) Eligibility thresholds
or criteria (e.g., voltage levels, amount of new generation located
within a given geographic area or load zone, etc.) may be appropriate
to determine whether a proposed regional transmission facility should
be considered as part of the regional transmission planning and cost
allocation process for transmission facilities built for anticipated
future generation; (2) whether the CREZ, MISO MVP, CAISO approaches, or
other processes for identifying and planning for the needs of
anticipated future generation are models for any potential requirements
and, if so, which aspects of those initiatives the Commission should
consider requiring transmission providers to implement, for example,
the CREZ model of requiring future generation to financially commit in
advance of construction; (3) whether there is a need for mechanisms to
limit the risk to customers from planning for anticipated future
generation, for example, we note CAISO's use of an ex ante cap on the
total cost exposure to transmission customers in addressing generation
resource interconnection, as one potential approach; \73\ and (4)
whether specific proposals are consistent with the Commission's FPA
section 206 authority.
---------------------------------------------------------------------------

    \73\ Id. P 6.
---------------------------------------------------------------------------

    60. We also seek comment on whether the regional transmission
planning process could be structured in such a way that is more
collaborative, relying on the knowledge and experience that
transmission providers, project developers, state commissions, and
other stakeholders have regarding optimal locations, the topography of
the transmission network, and Public Policy Requirements, among other
factors that will influence the location and amount of future renewable
resources. We note that the CREZ process was highly collaborative, with
the Electric Reliability Council of Texas (ERCOT) conducting workshops
with stakeholders over a six-month period to consider and evaluate
multiple transmission scenarios.\74\ In addition to seeking comment on
technical and collaborative approaches to identify geographic zones for
future renewable resources, we seek comment on potential alternative
proposals from stakeholders on how to identify where transmission
facilities may be needed to accommodate anticipated future generation.
Commenters should address whether, if implemented, such a scenario
planning process should be the same or different in non-RTO/ISO versus
RTO/ISO regions, and if different, what those differences should be.
Commenters should address how any proposed changes to the regional
planning and cost allocation processes increase the efficiency, or
lower the costs, of such processes and whether such changes will help
ensure a reliable power supply and/or will reduce or control the costs
of transmission and generation services that are ultimately passed on
to customers of load serving entities. Commenters should also address
proposed cost allocation.
---------------------------------------------------------------------------

    \74\ See Texas Commission, Order on Rehearing, Docket No. 33672,
at 3 (Oct. 7, 2008).
---------------------------------------------------------------------------

iii. Incentivizing Regional Transmission Facilities
    61. To prioritize regional transmission facilities that may have
greater benefit-to-cost ratios than local alternatives, we seek comment
on whether and, if so, how to expand or improve any incentives to
incent the development of regional transmission facilities that
demonstrably may offer a more efficient or cost-effective solution to
an identified need than local alternatives. As an example of a possible
regional transmission incentive, we seek comment on whether or not any
available return on equity adder incentive that may be available for
RTO/ISO participation should be limited in applicability only to
regional, and not local, transmission facilities, when those regional
transmission facilities are selected as the more efficient or cost-
effective solution to an identified transmission need.
iv. Enhanced Interregional or State-to-State Coordination
    62. We recognize that potential reforms discussed for comment above
may require greater interregional or

state-regional coordination to be fully realized in a just, reasonable
and not unduly discriminatory or preferential manner. As a result, we
seek comment on whether reforms to the current interregional
transmission coordination process, including potentially requiring
interregional transmission planning, are needed or appropriate for
making the potential approaches discussed above effective, and whether
such reforms are consistent with the Commission's authority under
section 206 of the FPA.
    63. We seek comment on whether, because an interregional project
must first be selected in each of the neighboring regions' regional
planning processes before being selected in the interregional process,
this challenge to the current interregional coordination process is
impeding the selection and development of efficient, cost-effective
interregional projects and, if so, what revisions are necessary to
address that barrier. Should the Commission require joint planning
processes, rather than simply joint coordination, for neighboring
regions? In light of the potential reforms to regional planning and
cost allocation and generator interconnection processes being
considered in this ANOPR, are there core principles or approaches that
the Commission should also consider when reviewing the existing
approach to interregional planning? For example, should the Commission
establish interregional reliability planning criteria or consider
renewable resource geographic zones during interregional planning?
Beyond interregional planning, can and should the Commission provide
alternate pathways for transmission facilities that benefit multiple
regions to be assigned cost allocation to customers across multiple
regions? For example, should the Commission allow for identification of
benefits, and allocation of commensurate costs, to one region of a
project selected in a neighboring region's regional transmission
planning process? Finally, comments should address whether taking any
proposed action is consistent with the Commission's authority under
section 206 of the FPA.
    64. In addition, we seek comment on whether and, if so, 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 regional transmission planning and cost allocation
and interregional coordination and cost allocation for transmission
needs related to future scenarios, including for anticipated future
generation or geographic generation zones.
b. Coordinating Between the Regional Transmission Planning and Cost
Allocation and Generator Interconnection Processes
    65. We seek comment on whether reforms are needed to improve the
coordination between the regional transmission planning and cost
allocation and generator interconnection processes. We seek comment on
whether the Commission should require transmission providers to operate
their regional transmission planning and cost allocation and generator
interconnection processes on concurrent, coordinated timeframes, with
the same or similar assumptions and methods, and whether such a
potential requirement may identify more efficient or cost-effective
transmission solutions that could address needs shared between the two
processes.
    66. We seek comment on how the regional transmission planning and
cost allocation and generator interconnection processes could be better
coordinated or integrated. For example, would use of similar timeframes
and assumptions facilitate more efficient or cost-effective
transmission solutions? How could these processes most effectively be
co-optimized? We seek comment on whether and, if so, how
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 associated with, for example, resource
adequacy, operating reliability, and similar needs, and in coordination
with the regional transmission planning process? We seek comment on
whether and how relevant information from the generator interconnection
process could be integrated into regional transmission planning in a
timely manner, and whether and how transmission providers could move
beyond using the outputs of each process as a deterministic input into
the other rather than optimizing together across approaches. We also
seek comment on whether it may be possible and beneficial to combine
certain aspects of the transmission planning and generator
interconnection processes, and if so, how?
    67. We also seek comment on whether and how the Commission could
revise transmission planning criteria that transmission providers use
in the generator interconnection process so that they could better
identify more efficient or cost-effective interconnection-related
network upgrades. As indicated earlier, we also seek comment on whether
and how transmission providers could incorporate anticipated future
generation, including resources in the interconnection queue, in the
regional transmission planning and cost allocation processes. In
particular, we encourage commenters to discuss how to address concerns
regarding uncertainty, including speculative projects, in planning for
anticipated future generation.
    68. Further, we seek comment on whether and how more effectively
accounting for anticipated future generation in transmission planning
may reduce the costs of interconnection-related network upgrades. To
the extent this is the case, how should such benefits be identified,
and should they factor into the regional transmission planning and cost
allocation process?

B. Identification of Cost and Responsibility for Regional Transmission
Facilities and Interconnection-Related Network Upgrades

    69. The Commission has repeatedly recognized that, where cost
allocation methods do not appropriately account for benefits associated
with new transmission facilities, they may result in rates that are not
just and reasonable or are unduly discriminatory or preferential.\75\
---------------------------------------------------------------------------

    \75\ See Order No. 890, 118 FERC ] 61,119 at P 557 (finding that
how ``the costs of new transmission facilities are allocated is
critical to the development of new infrastructure'' because
``[t]ransmission providers and customers cannot be expected to
support the construction of new transmission unless they understand
who will pay the associated cost''); Order No. 1000, 136 FERC ]
61,051 at PP 484-487; see also Ill. Commerce Comm'n v. FERC, 576
F.3d 470, 476 (7th Cir. 2009) (ICC v. FERC).
---------------------------------------------------------------------------

    70. We seek comment on whether the existing approach to cost
allocation in regional transmission planning processes fails to
consider the full suite of benefits--and the associated beneficiaries--
produced by transmission facilities developed to meet the transmission
needs of the changing resource mix. We seek comment on whether the
current approach omits relevant benefits of new transmission
infrastructure and, if so, thereby fails to consider the entities that
receive those benefits in the cost allocation process. What,
specifically, are those other benefits that should be considered? In
addition, while the regional transmission planning process considers
transmission needs driven by reliability, economic considerations, and
Public Policy Requirements, these types of transmission needs are, in

many cases, considered in isolation from one another and the cost
allocation methods for transmission facilities developed in response to
these needs are generally separated by type. We seek comment as to
whether the existing regional transmission planning and cost allocation
processes may not fully account for the full suite of benefits,
including hard-to-quantify benefits, and may impede the allocation of
the costs of transmission facilities needed to meet the transmission
needs of the changing resource mix in a manner that is at least roughly
commensurate with the actual benefits of those facilities. Getting that
balance right is important not only to comply with the cost causation
principle, but also because efforts to plan the transmission system to
meet the needs of the changing resource mix will succeed only if the
associated cost allocation methods are transparent, equitable, and
practicable.\76\
---------------------------------------------------------------------------

    \76\ Cf. BNP Paribas Energy Trading GP v. FERC, 743 F.3d 264,
268-269 (D.C. Cir. 2014) (BNP Paribas Energy) (``[T]he cost
causation principle itself manifests a kind of equity. This is most
obvious when we frame the principle (as we and the Commission often
do) as a matter of making sure that burden is matched with
benefit.'' (citing Midwest ISO Transmission Owners v. FERC, 373 F.3d
1361, 1368 (D.C. Cir. 2004) and Se. Mich. Gas Co. v. FERC, 133 F.3d
34, 41 (D.C. Cir. 1998))); Order No. 1000, 136 FERC ] 61,051 at P
669 (explaining that requiring cost allocation methods be open and
transparent ensures that such methods are just and reasonable and
not unduly discriminatory or preferential, aids in development and
construction of new transmission, and may avoid contentious
litigation or prolonged stakeholder debate); KN Energy, Inc. v.
FERC, 968 F.2d 1295, 1300-01 (D.C. Cir. 1992) (describing properly
designed rates as producing revenues `` `which match, as closely as
practicable, the costs to serve each class or individual customer'
'' (emphasis in original)) (quoting Ala. Elec. Coop., Inc. v. FERC,
684 F.2d 20, 27 (D.C. Cir. 1982)); Pub. Serv. Co. of Colo., 163 FERC
] 61,204, at P 14 (2018) (recognizing that ``feasibility'' is part
of ratemaking, such that the Commission may appropriately ``balance
maximally reflecting cost causation with other competing policy
goals,'' such as promoting more efficient or cost-effective regional
transmission planning).
---------------------------------------------------------------------------

    71. With respect to cost allocation in the generator
interconnection process, we seek comment as to whether the participant
funding approach for interconnection-related network upgrades required
for an interconnection request in RTOs/ISOs may no longer be just and
reasonable. Participant funding may result in costly interconnection-
related network upgrades being allocated entirely to interconnection
customers while failing to account for the significant benefits that
these interconnection-related network upgrades may provide to other
anticipated future generators seeking to interconnect and/or existing
or future transmission customers. We further seek comment on whether
the narrow focus of the generator interconnection process results in
only a subset of beneficiaries paying for transmission infrastructure
that, in practice, may benefit many.
    72. We seek comment on whether separating the regional transmission
planning and cost allocation and generator interconnection processes
may increasingly result in an only partial-accounting of the benefits
of new transmission infrastructure, leaving some transmission and
interconnection customers potentially bearing a disproportionate cost
burden. We seek comment on whether any changes to the criteria used for
considering which transmission facilities are selected in the regional
transmission plan for purposes of regional cost allocation, as well as
the formula for the regional allocation of costs of regional
transmission facilities and for the cost of interconnection-related
network upgrades, including changes to the definition of beneficiary,
hold the potential to unjustly and unreasonably shift costs to
customers of load serving entities. We seek comment on how any
contemplated reforms or revisions to existing regulations are
consistent with the FPA and its requirement for just and reasonable and
not unduly discriminatory or preferential rates.
    73. In the following sections, we address the relevant court and
Commission precedent governing cost allocation and seek comment on a
number of potential reforms to address these concerns and ensure that
transmission rates remain just and reasonable and not unduly
discriminatory or preferential.
1. Relevant Cost Causation Precedent
    74. Pursuant to FPA sections 205 and 206, the Commission is
responsible for ensuring that the rates, terms, and conditions for
transmission of electricity in interstate commerce are just,
reasonable, and not unduly discriminatory or preferential.\77\ For a
cost allocation approach to satisfy this standard, it must satisfy the
cost causation principle. The cost causation principle requires that
``all approved rates reflect to some degree the costs actually caused
by the customer who must pay them'' \78\ and that costs ``be allocated
to those who cause the costs to be incurred and reap the resulting
benefits.'' \79\ As the U.S. Court of Appeals for the Seventh Circuit
(Seventh Circuit) further explained, to ``the extent that a utility
benefits from the costs of new facilities, it may be said to have
`caused' a part of those costs to be incurred, as without the
expectation of its contributions the facilities might not have been
built, or might have been delayed.'' \80\ Courts ``evaluate compliance
with this . . . principle by comparing the costs assessed against a
party to the burdens imposed or benefits drawn by that party.'' \81\ In
ICC v. FERC, the Seventh Circuit also stated that a cost allocation
method can satisfy the cost causation principle if the Commission ``has
an articulable and plausible reason to believe that the benefits are at
least roughly commensurate with'' the allocation of the costs.\82\ The
Seventh Circuit stated, however, that satisfying this requirement does
not require exacting precision, and the Commission need not ``calculate
benefits to the last penny, or for that matter to the last million or
ten million or perhaps hundred million dollars.'' \83\
---------------------------------------------------------------------------

    \77\ 16 U.S.C. 824d, 824e.
    \78\ KN Energy, Inc. v. FERC, 968 F.2d at 1300.
    \79\ S.C. Pub. Serv. Auth., 762 F.3d at 87 (quoting NARUC v.
FERC, 475 F.3d at 1285).
    \80\ ICC v. FERC, 576 F.3d at 476.
    \81\ Midwest ISO Transmission Owners v. FERC, 373 F.3d at 1368.
    \82\ 576 F.3d at 477.
    \83\ Id. (citing Midwest ISO Transmission Owners v. FERC, 373
F.3d at 1369).
---------------------------------------------------------------------------

2. Cost Allocation for Transmission Facilities Planned Through the
Regional Transmission Planning Process
    75. Potential reforms for which we seek comment in this ANOPR
contemplate a more forward-looking approach to the regional
transmission planning process that plans for anticipated future
generation, potentially producing a different and broader set of
benefits and beneficiaries. The following sections seek comment on
potential reforms that may be necessary to ensure that the costs of
transmission facilities developed to meet the transmission needs of the
changing resource mix are allocated in a manner that is roughly
commensurate with those benefits, while ensuring that any potential
reforms or revisions to existing cost-allocation rules do not unjustly
or unreasonably shift costs to any type of market participant or
customers of load serving entities. We seek comment on whether certain
benefits are not appropriate to account for under the FPA, and whether
allocation of costs based on such benefits may be inconsistent with the
Commission's statutory mandate.
a. Background
    76. In Order No. 1000, the Commission determined that the lack of
clear ex ante cost allocation methods that identify beneficiaries of
proposed regional transmission facilities was

impairing the ability of transmission providers to implement more
efficient or cost-effective transmission solutions identified in the
regional transmission planning process. According to the Commission,
the failure to address cost allocation in a way that aligns with the
benefits of new transmission facilities could lead to needed
transmission facilities not being built, adversely impacting
ratepayers.\84\ The Commission therefore required transmission
providers to have in place a method, or set of methods, for allocating
the costs of new transmission facilities selected in a regional
transmission plan for purposes of cost allocation. To guide
transmission providers, the Commission established a set of cost
allocation principles that transmission providers' cost allocation
methods must satisfy, with the goal of ensuring that the costs of
transmission solutions chosen to meet regional transmission needs would
be allocated to those that received benefits from them.\85\ The
Commission determined that this principles-based approach would result
in 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.\86\
---------------------------------------------------------------------------

    \84\ Order No. 1000, 136 FERC ] 61,051 at P 499.
    \85\ Id. PP 9, 482-83.
    \86\ Id. P 10; Order No. 1000-A, 139 FERC ] 61,132 at P 647.
---------------------------------------------------------------------------

    77. The six regional cost allocation principles that the Commission
adopted in Order No. 1000 are: (1) Costs of transmission facilities
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; \87\ (3) a benefit to cost threshold ratio, if
adopted, cannot exceed 1.25 to 1; \88\ (4) costs must be allocated
solely within the transmission planning region unless another entity
outside the region voluntarily assumes a portion of those costs; \89\
(5) the method for determining benefits and identifying beneficiaries
must be transparent; \90\ and (6) there may be different methods for
different types of transmission facilities, such as those needed for
reliability, congestion relief, or to achieve Public Policy
Requirements.\91\ Although the Commission required the regional cost
allocation methods to determine benefits and identify beneficiaries in
a transparent manner, the Commission also recognized that ``identifying
which types of benefits are relevant for cost allocation purposes,
which beneficiaries are receiving those benefits, and the relative
benefits that accrue to various beneficiaries can be difficult and
controversial.'' \92\ Consistent with this notion, the Commission
declined to require transmission providers to adopt a universal or
comprehensive definition of ``benefits'' and ``beneficiaries'' \93\ of
regional transmission facilities, instead allowing for regional
flexibility and examining each region's definitions on compliance.
---------------------------------------------------------------------------

    \87\ Order No. 1000, 136 FERC ] 61,051 at P 637.
    \88\ Id. P 646.
    \89\ Id. P 657.
    \90\ Id. P 668.
    \91\ Id. P 685.
    \92\ Id. P 501.
    \93\ Order No. 1000-A, 139 FERC ] 61,132 at P 679 (explaining
that Order No. 1000 does not define benefits and beneficiaries but
rather requires transmission providers to be definite about benefits
and beneficiaries for purposes of their cost allocation methods).
---------------------------------------------------------------------------

    78. The result is that transmission providers in each transmission
planning region have implemented varying regional transmission cost
allocation methods to comply with the cost allocation principles of
Order No. 1000, the majority of which allocate the costs of regional
transmission facilities that address reliability needs separately from
those that address economic needs and separately from those that
address Public Policy Requirements. In other words, most regional
transmission cost allocation methods do not consider whether a regional
transmission facility addresses more than one category of needs, and
therefore provides more than one category of transmission benefits.
    79. That said, some transmission providers' Order No. 1000-
compliant regional transmission cost allocation methods may recognize a
broader number of benefits than others and identify the broader
benefits across a portfolio of transmission facilities rather than on a
facility-by-facility basis, whereas others may be more constrained. For
example, MISO's MVP process is designed to identify a portfolio of
regional transmission facilities that: (1) Reliably and economically
enable regional public policy needs; (2) provide multiple types of
regional economic value; and/or (3) provide a combination of regional
reliability and economic value. Specifically, MISO MVPs must be above
100 kV, have a project cost of $20 million or more, and have a combined
benefit-to-cost ratio greater than 1.0 and must be evaluated as part of
a portfolio of transmission projects.\94\ The costs of this MVP
portfolio are allocated on a postage stamp basis across the MISO
region.\95\
---------------------------------------------------------------------------

    \94\ MISO, FERC Electric Tariff, Attachment FF, Section II.C
(85.0.0).
    \95\ Id. Section III.A.2.g.
---------------------------------------------------------------------------

    80. Southwest Power Pool's (SPP) Balanced Portfolio process
similarly considers broader transmission benefits.\96\ SPP evaluates
economic benefits of a portfolio of transmission facilities to achieve
a balance where the benefits of the portfolio to each zone (as measured
by adjusted production cost savings) equal or exceed the costs
allocated to each zone over a 10-year period. By allocating costs such
that the benefits to each zone will equal or exceed those costs, the
Balanced Portfolio process ensures that SPP allocates costs in a manner
that is least roughly commensurate with benefits by design. In
addition, SPP may reallocate costs to ensure that the portfolio is
balanced and, under certain conditions, including cancellation of a
transmission facility or unanticipated decreases in benefits or
increases in costs, may review a previously approved Balanced Portfolio
and recommend reconfiguring the portfolio.\97\
---------------------------------------------------------------------------

    \96\ SPP's Balanced Portfolio was an initiative to develop a
group of economic transmission projects that benefit the entire SPP
region and to allocate those transmission project costs regionally.
The SPP Board of Directors approved the Balanced Portfolio
transmission projects in April 2009.
    \97\ SPP OATT, attach. J (Recovery of Costs Associated With New
Facilities), Section III.D.
---------------------------------------------------------------------------

    81. As for allocating the costs of regional transmission facilities
to generators, in Order No. 1000, while commenters requested that the
Commission allow such costs to be allocated to generators as
beneficiaries, the Commission determined that generator interconnection
was outside the scope of the rulemaking.\98\ However, the Commission
also stated that 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 not be
inconsistent with the Order No. 2003 generator interconnection process.
The Commission noted that in not addressing these issues, it was
neither minimizing the importance of evaluating the impact of generator
interconnection requests during transmission planning, nor limiting the
ability of transmission providers to use requests for generator
interconnections in developing assumptions to be used in

the regional transmission planning process.\99\
---------------------------------------------------------------------------

    \98\ Order No. 1000, 136 FERC ] 61,051 at P 760.
    \99\ Id. P 760.
---------------------------------------------------------------------------

    82. Nevertheless, at least one transmission provider considers
interconnection customers as beneficiaries of new transmission
facilities. The Commission approved CAISO's proposal whereby
transmission customers initially fund the transmission expansion needed
to facilitate interconnection through the transmission revenue
requirement of the constructing transmission provider, and
interconnection customers are assigned their pro rata share of the
going-forward costs of using the transmission facility as their
generators interconnect to the transmission system. Under CAISO's
proposal, all transmission system users pay the costs of the
unsubscribed portion of a new transmission facility until the line is
fully subscribed.\100\ The CAISO approach also includes an ex ante cap
on the total cost exposure to transmission customers, which was set at
15% of the sum total of the net high-voltage transmission plant of all
transmission providers, as reflected in their transmission revenue
requirements and in the CAISO transmission access charge.\101\
---------------------------------------------------------------------------

    \100\ Cal. Indep. Sys. Operator Corp., 119 FERC ] 61,061.
    \101\ Cal. Indep. Sys. Operator Corp., 119 FERC ] 61,061, at P
6.
---------------------------------------------------------------------------

b. Potential Need for Reform
    83. This statement in Order No. 1000 rings as true today as it did
then--``identifying which types of benefits are relevant for cost
allocation purposes, which beneficiaries are receiving those benefits,
and the relative benefits that accrue to various beneficiaries can be
difficult and controversial.'' \102\ This is especially true for
larger, regional transmission facilities that are both costly and could
have potentially broad benefits. As the Commission recognized in Order
No. 890, the manner in which the costs of new transmission facilities
are allocated is ``critical'' to developing those facilities as is
identifying the types of benefits and the associated beneficiaries of
those facilities.\103\
---------------------------------------------------------------------------

    \102\ Order No. 1000, 136 FERC ] 61,051 at P 501.
    \103\ Order No. 890, 118 FERC ] 61,119 at P 557.
---------------------------------------------------------------------------

    84. The possible reforms for which we seek comment in this ANOPR
seek to ensure the development of regional transmission facilities
needed to meet the transmission needs of the changing resource mix
occurs in a more efficient or cost-effective manner, at just and
reasonable rates. Commenters should also address whether and how any
reforms or revisions to existing rules could unjustly and unreasonably
shift additional costs to customers of load serving entities. These
reforms cannot be successful without ensuring that transmission
providers and customers alike are able to identify the types of
benefits of 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. The failure to account for all the benefits of a
transmission facility while taking into account all the costs of the
transmission facility does not allow for a fair examination of whether
the costs are allocated roughly commensurate with the benefits. We seek
comment on whether ignoring benefits of these transmission facilities
may impair more efficient or cost-effective transmission development by
limiting the number of facilities that overcome the cost-benefit
threshold needed to justify the cost of new transmission, and if so,
what the appropriate standard should be for identifying such benefits.
This potential concern goes to the need to not only identify the types
of benefits of these new transmission facilities, and to quantify those
benefits where possible, but likewise to the need for transparent
methods to calculate benefits and ascertain beneficiaries without being
so burdensome that the methods hinder transmission development. We seek
comment on whether customers of load serving entities should be
required to pay the costs of regional transmission facilities that
provide them only with unquantifiable or purported benefits, or be
required to pay for costs driven by the public policies of state and
local governments in states other than their own.\104\
---------------------------------------------------------------------------

    \104\ See, e.g., PJM's State Agreement Approach. PJM
Interconnection, L.L.C., 142 FERC ] 61,214, at PP 142-143 (2013),
order on reh'g and compliance, 147 FERC ] 61,128, at P 92 (2014);
---------------------------------------------------------------------------

    85. Currently, most regional cost allocation methods do not
consider whether a regional transmission facility addresses more than
one category of needs, thereby providing more than one category of
transmission benefits. Specifically, although the regional transmission
planning process considers transmission needs driven by reliability,
economic considerations, and Public Policy Requirements,\105\ these
types of transmission needs are generally considered in a silo from one
another; the cost allocation methods for regional transmission
facilities developed in response to these needs are similarly for the
most part separated by type. We seek comment on whether the result is a
paradigm that may potentially fail to consider the suite of benefits
that transmission facilities provide and therefore fails to allocate
the costs of such facilities roughly commensurate with the benefits.
---------------------------------------------------------------------------

    \105\ Order No. 1000 left planning and cost allocation for
Public Policy Requirements largely to the discretion of transmission
providers. See supra P 16. Moreover, under PJM's State Agreement
Approach (see supra n.104), the costs of transmission facilities
required to meet the public policy requirements of an individual
state or group of states may not be shifted to customers in other,
non-participating states.
---------------------------------------------------------------------------

    86. We seek comment as to whether a shift to a more integrated and
holistic process for regional transmission planning and cost allocation
is appropriate. Such a shift may raise novel questions around which
customers should pay for new transmission facilities and concerns about
free riders benefitting from the transmission expansion without paying
for their fair share. Under the potential reforms for which we seek
comment in this ANOPR, the regional transmission planning process would
identify transmission facilities that support future scenarios,
including anticipated future generation, and improve pricing and cost
allocation for interconnection-related network upgrades. In that
scenario, interconnection customers themselves could be considered
beneficiaries of transmission facilities that facilitate their
interconnection, even if those transmission facilities were built prior
to the generators entering the interconnection queue. We seek comment
on whether merely making interconnection customers the beneficiaries
fails to capture all of the relevant types of benefits for purposes of
cost allocation of a regional transmission facility built to
accommodate anticipated future generation. We also seek comment on
whether it may therefore be preferable to consider developing new
regional transmission cost allocation methods that measure all of the
benefits of regional transmission facilities that are being assessed
for potential selection in the regional transmission plan for purposes
of cost allocation and that accrue to both transmission and
interconnection customers.
    87. We cannot ignore, of course, that it may be difficult to
precisely quantify some of the benefits of transmission facilities,
which can be a barrier to more broadly allocating the costs of those
facilities among transmission and interconnection customers. Unlike
costs, which are clearly defined and easily quantified, the scope of
which transmission benefits count for purposes of cost allocation, and
how well they need to be documented in order to be allocated to
customers, is a distinct

challenge to achieving a fair allocation. Requiring transmission
providers to produce overly detailed reports on benefits before the
costs of a transmission facility can be allocated to transmission and
interconnection customers could lead to cost allocations that
undervalue the largest transmission expansions, no matter their
efficiency. The task is in striking the right balance to ensure just
and reasonable rates and the allocation of transmission costs roughly
commensurate with benefits.
    88. We also note that, with greater deployment of renewable
resources, and in part to the extent that regions focus on a project-
specific regional transmission cost allocation method, it is possible
that benefits may be distributed unevenly across regions. For example,
there are likely zones or sub-zones within a region that are rich in
renewable resources and therefore have generation significantly in
excess of the local load. These zones, and generators in these zones,
may not be the only beneficiaries of regional transmission facilities
built to access these resources as customers outside those zones may
reap reliability or economic benefits that result from the expanded
transmission system and access to low cost resources. We seek comment
on whether current regional transmission cost allocation approaches may
not adequately address these circumstances and may not provide workable
frameworks for the identification of transmission beneficiaries and
sharing of benefits.
    89. We seek comment on whether there should be reforms to cost
allocation in regional transmission planning and cost allocation
processes, including considering potentially a portfolio approach to
assessing regional transmission facilities and consideration of a
minimum set of transmission benefits, while seeking additional
information about cost allocation approaches that may inform such
reforms. Commenters proposing specific changes to cost allocation
should address how such proposals will result in costs being allocated
in a manner roughly commensurate with benefits, and demonstrate that
costs will not be disproportionately borne by any given class of
customers in a manner inconsistent with the requirements of the FPA and
precedent. Commenters should also address how such proposals impact
customers of load serving entities and whether and how proposed new
cost allocation formulae may shift costs to new categories of customers
and whether such cost-shifting is just and reasonable and consistent
with the requirements of the FPA.
c. Potential Reforms and Request for Comment
    90. We seek comment on whether broader transmission benefits should
be taken into account when planning the transmission system for
anticipated future generation, and how such benefits should be
identified and quantified. Some transmission providers, e.g., SPP,
MISO, CAISO, and recently the New York Independent System Operator,
Inc. (NYISO), have used broader transmission benefits in selecting
regional transmission facilities for purposes of cost allocation in
their regional transmission planning processes.
    91. In addition, under a portfolio approach to regional
transmission cost allocation, multiple transmission facilities are
considered together, and the collective benefits of the transmission
facilities are measured. MISO's MVP and SPP's Balanced Portfolio method