generator interconnection process and have completed an interconnection
facilities study.\276\
---------------------------------------------------------------------------

    \275\ ANOPR, 176 FERC ] 61,024 at P 23.
    \276\ ANOPR, 176 FERC ] 61,024 at P 23. Id.
---------------------------------------------------------------------------

    156. The ANOPR sought comment on whether reforms are necessary to
improve coordination between the regional transmission planning and
cost allocation and generator interconnection processes.\277\ In
particular, the ANOPR sought comment on whether interconnection
requests that trigger the need for interconnection-related network
upgrades that may provide regional transmission benefits could be
studied in a way that accounts for the potential broader transmission
benefits in coordination with the regional transmission planning
process.\278\ The ANOPR also sought comment on whether it may be
possible and beneficial to combine certain aspects of the regional
transmission planning and generator interconnection processes.\279\
---------------------------------------------------------------------------

    \277\ ANOPR, 176 FERC ] 61,024 atId. P 65.
    \278\ ANOPR, 176 FERC ] 61,024 atId. P 66.
    \279\ ANOPR, 176 FERC ] 61,024 at P 66. Id.
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(b) Comments
    157. Each of the RTOs/ISOs filed comments in response to the ANOPR
related to the coordination of their regional transmission planning and
cost allocation and generator interconnection processes. CAISO states
that it includes interconnection-related network upgrades identified
during its interconnection study process and that meet specific voltage
and/or capital cost thresholds as an input into the regional
transmission planning process. CAISO asserts that it does so to ensure
that it identifies and approves all major transmission additions and
upgrades under a single comprehensive process and allocates the
available amount of transmission capacity to the proposed generating
facilities in each area.\280\ PJM states that it leverages
opportunities to address supplemental projects and new interconnection
service requests through its baseline transmission projects. For
instance, when increasing the capabilities of a regional transmission
facility would obviate the need for an interconnection-related network
upgrade, PJM factors the interconnection customer's incremental need
into the transmission project and the interconnection customer is only
responsible for the costs of the incremental portion of the
transmission facility.\281\ ISO-NE explains how its regional
transmission planning and generator interconnection processes are
coordinated presently but acknowledges that improvements may be
necessary to optimize transmission solutions.\282\ NYISO and SPP each
identify an ongoing or potential stakeholder process to improve the
coordination of the generator interconnection and regional

transmission planning processes.\283\ MISO explains how its generator
interconnection and regional transmission planning processes are
currently related to each other and contends that the regional
transmission planning process is the right avenue to determine more
holistic transmission needs but considers the generator interconnection
process more appropriate to focus on the specific needs associated with
interconnecting new generation.\284\
---------------------------------------------------------------------------

    \280\ CAISO Comments at 71-72.
    \281\ PJM Comments at 17-18.
    \282\ ISO-NE Comments at 25-26.
    \283\ NYISO Comments at 41; SPP Comments at 9-11.
    \284\ MISO Comments at 75-76.
---------------------------------------------------------------------------

    158. Several commenters support better coordination between the
regional transmission planning and cost allocation and generator
interconnection processes, including the need for similar timelines and
assumptions.\285\ Anbaric and Public Systems ask the Commission to
require a regional transmission planning assessment if an
interconnection study identifies significant interconnection-related
network upgrades beyond the interconnection facility line needed to
reach a substation and any directly interconnected substation upgrades
to ``shift the evaluation of development of needed upgrades to the
[regional transmission] planning process.'' \286\ Anbaric and Public
Systems state that the needed upgrades could be eligible for
competitive bidding as part of the regional transmission planning
process. Similarly, Duke suggests that public utility transmission
providers can identify an ex ante measure, such as the change in the
levelized cost of a transmission network upgrade, to determine whether
an interconnection-related network upgrade should be incorporated into
its regional transmission plan for purposes of cost allocation
according to a defined cost allocation method.\287\
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    \285\ See, e.g., AEP Comments at 30-31; APPA Comments at 22;
Certain TDUs Comments at 18; NARUC Comments at 6, 11, 18; NERC
Comments at 17-18; NewSun Comments at 24; Northwest and
Intermountain Comments at 33; OMS Comments at 11-13; Indicated PJM
TOs Comments at 27; REBA Comments at 2-3; SDG&E Comments at 5.
    \286\ Anbaric Comments at 23; Public System Comments at 6-7, 19.
    \287\ Duke Comments at 8-9.
---------------------------------------------------------------------------

    159. Enel outlines a detailed proposal for consolidating the
generator interconnection and regional transmission planning processes
to limit generator interconnection studies to focus on direct,
localized impacts of new generation and directly assign costs for
interconnection-related network upgrades to generators when the cost
causation relationship is ``strong and justified.'' \288\ Under Enel's
proposal, interconnection requests that meet significant readiness
criteria required by the public utility transmission provider, such as
a non-refundable cash deposit or letter of credit in the amount of 100%
of the costs of the ``local'' interconnection-related network upgrades,
would be included in the regional transmission planning process after
the public utility transmission provider conducts a basic
interconnection study (e.g., Energy Resource Interconnection
Study).\289\ AEE states that implementing Enel's proposal would help
resolve the cost allocation and market entry barrier problems
associated with the current funding paradigm for interconnection-
related network upgrades and could also help unburden constrained and
backlogged interconnection queues that are creating barriers to
entry.\290\
---------------------------------------------------------------------------

    \288\ Enel Comments at 3.
    \289\ Enel Comments, Id. attach. 1 (Plugging In) at 12. Enel
proposes that the Transfer Distribution Factor is a good metric for
determining electrical distance from a generation facility and what
constitutes ``local.'' See Enel Comments, attach. 1 (Plugging In)
id. at 6.
    \290\ AEE Comments at 52-53.
---------------------------------------------------------------------------

    160. Other commenters oppose further coordination of the generator
interconnection and regional transmission planning processes.\291\ Some
consumer groups express a general concern that coordination reforms
would shift costs of generator interconnection to consumers.\292\
Finally, some commenters expect that a regional transmission planning
process that better accounts for anticipated future generation would
address generator interconnection issues that are due to a lack of
coordination, or co-optimization, of the two processes.\293\
---------------------------------------------------------------------------

    \291\ Southern Comments at 38-39; US Chamber of Commerce
Comments at 4; see also ACORE Comments at 26-27; APPA Comments at
22-23; Berkshire Comments at 10-11; CAISO Comments at 70; LPPC
Comments at 18; ITC Comments at 31.
    \292\ Industrial Customers Comments at 25; Consumer
Organizations Comments at 26.
    \293\ EEI Comments at 37; Exelon Comments at 33-34; Policy
Integrity Comments at 27-28; Indicated PJM TOs Comments at 27.
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(c) Need for Reform
    161. For the reasons set forth below, we believe that there may be
a need for better coordination between regional transmission planning
and cost allocation and generator interconnection processes to ensure
just and reasonable and not unduly discriminatory or preferential
Commission-jurisdictional rates. As the Commission explained in the
ANOPR, the interaction between regional transmission planning and cost
allocation processes on the one hand and the generator interconnection
process on the other appears limited--the baseline regional
transmission planning models generally only incorporate interconnection
projects that have completed an interconnection facilities study, and
are therefore near the end of the generator interconnection
process.\294\ But where transmission system needs are repeatedly
identified through generator interconnection processes, we believe that
more efficient or cost-effective transmission expansion could be
achieved through regional transmission planning and cost allocation
that allocates costs in a manner that is at least roughly commensurate
with estimated benefits and eliminates a potential barrier to entry for
new generation resources.
---------------------------------------------------------------------------

    \294\ ANOPR, 176 FERC ] 61,024 at P 23.
---------------------------------------------------------------------------

    162. We are most concerned with the prevalence of interconnection-
related network upgrades being repeatedly identified in the generator
interconnection process in multiple interconnection queue cycles in a
short period of time (e.g., five years) but not being developed because
the interconnection request(s) driving the need for the upgrade are all
withdrawn. As explained above, there has been a dramatic increase in
recent years in the level of spending on interconnection-related
network upgrades, driving the cost of interconnecting new generation to
the transmission system higher and higher.\295\ The evidence suggests
that this trend is leading to more and more interconnection customers
withdrawing their interconnection requests in the face of significant
costs associated with interconnection-related network upgrades.
According to a January 2021 report, ``the high cost of interconnection
is increasing the rate at which generators drop out of the
interconnection queue.'' \296\ For example, between January 2016 and
July 2020, 245 generation projects in advanced stages in the MISO
generator interconnection process withdrew from the queue, with the
project developers citing high interconnection-related network upgrade
costs as the primary reason for their withdrawal.\297\ While
interconnection customers may choose to withdraw from the
interconnection queue for a number of reasons, in recent

years, the deciding factor has become the interconnection customer's
``sticker shock'' at its cost responsibility for interconnection-
related network upgrades.\298\
---------------------------------------------------------------------------

    \295\ Supra section_Supra Need for Reform: Unjust and
Unreasonable and Unduly Discriminatory and Preferential Commission-
Jurisdictional Rates (detailing the sharp rise in total investment
in interconnection-related network upgrades along with the jump in
the cost per kW for newly interconnecting generators to
interconnect).
    \296\ ACEG Jan. 2021 Interconnection Report at 17.
    \297\ Id. (naming the high cost of interconnection-related
network upgrades as the fundamental problem that interconnection
queue reform has failed to address thus far).
    \298\ See ACORE Comments at 12.
---------------------------------------------------------------------------

    163. When interconnection customers withdraw from the
interconnection queue, the identified interconnection-related network
upgrades associated with those interconnection customers remain unbuilt
and the underlying interconnection-related needs go unaddressed. In
many cases, when the interconnection-related need is not addressed via
development of interconnection-related network upgrades in one
interconnection queue cycle, the same interconnection-related need--and
oftentimes the same or a substantially similarly interconnection-
related network upgrade--will appear in interconnection studies for
different interconnection requests or clusters in subsequent
interconnection queue cycles. This scenario can occur even if
subsequent interconnection requests or clusters vary considerably from
previous interconnection requests or clusters in terms of size, fuel
type, technical specifications, or location. One study, which analyzed
12 specific interconnection-related network upgrades identified by MISO
and SPP, found that SPP identified three of the upgrades in two
interconnection queue cycles and one in three interconnection queue
cycles, and MISO identified three of the upgrades in two
interconnection queue cycles and two in three interconnection queue
cycles.\299\ In other words, both SPP and MISO were repeatedly
identifying the same interconnection-related network upgrades as
interconnection customers withdrew from the interconnection queue,
leaving next-in-line interconnection customers to address the same
interconnection-related needs.
---------------------------------------------------------------------------

    \299\ ICF Sept. 2021 Report at 25-26.
---------------------------------------------------------------------------

    164. Where interconnection-related needs are repeatedly identified
in interconnection studies, the implication may be that the area,
despite the potentially prohibitive interconnection costs, is otherwise
desirable for generators to locate (e.g., it is located close to fuel
sources). At the same time, the recurrent need for an interconnection-
related network upgrade is unlikely to go away without someone
investing in the transmission system in that location. As
interconnection customers that have invested time and resources in
proposing a project, entering the interconnection queue, and engaging
in the generator interconnection process choose to withdraw rather than
fund the interconnection-related network upgrades, it becomes more and
more likely that it will never be economic for an interconnection
customer (or small cluster of interconnection customers) to resolve the
interconnection-related need.
    165. At the same time, interconnection-related network upgrades can
provide widespread transmission benefits that extend beyond the
interconnection customer.\300\ As a result, planning these transmission
upgrades exclusively through the generator interconnection process may
result in a mismatch between the beneficiaries of the transmission
upgrade and those to whom the costs are allocated. In other words, by
upgrading the transmission system in a piecemeal fashion through the
generator interconnection process, the current transmission planning
paradigm appears to impose costs on interconnection customers for
transmission facilities that would provide benefits beyond those
received by the interconnection customer. This paradigm can present a
potential barrier to entry for new generation resources that might
otherwise be economic if not for the cost of interconnection-related
network upgrades. We believe that reforms may be necessary to allow for
the consideration of transmission facilities to meet interconnection-
related needs repeatedly identified in the generator interconnection
process through Long-Term Regional Transmission Planning and Cost
Allocation process instead, which we believe would result in more
efficient or cost-effective transmission expansion, cost allocation for
such transmission facilities that is at least roughly commensurate with
estimated benefits, and elimination of a barrier to entry for new
generation resources. In turn, we expect that these reforms would
ensure just and reasonable and not unduly discriminatory or
preferential Commission-jurisdictional rates.
---------------------------------------------------------------------------

    \300\ See, e.g., CAISO Comments at 52-53 (stating that in CAISO
``transmission facilities at 200 kV and above are eligible for
regional cost allocation,'' including location-constrained resources
interconnection facilities, because ``this voltage threshold . . .
recognizes that high voltage transmission facilities support and
provide benefits to all customers to the CAISO grid''); Order No.
2003, 104 FERC ] 61,103 at P 65 (stating that ``[f]acilities beyond
the Point of Interconnection [(i.e., interconnection-related network
upgrades)] are part of the Transmission Provider's Transmission
System and benefit all users''); ACORE Comments, Ex. 5, at 4-7.
---------------------------------------------------------------------------

(d) Proposed Reform
    166. We propose to require that public utility transmission
providers consider in their Long-Term Regional Transmission Planning
regional transmission facilities that address certain interconnection-
related needs that the public utility transmission provider has
identified multiple times in the generator interconnection process but
that have never been constructed due to the withdrawal of the
underlying interconnection request(s). In particular, we propose to
require that public utility transmission providers evaluate for
selection in the regional transmission plan for purposes of cost
allocation regional transmission facilities to address interconnection-
related needs that have been identified in the generator
interconnection process as requiring interconnection-related network
upgrades where: (1) The public utility transmission provider has
identified interconnection-related network upgrades in interconnection
studies to address those interconnection-related needs in at least two
interconnection queue cycles during the preceding five years (beginning
at the time of the withdrawal of the first underlying interconnection
request); (2) the interconnection-related network upgrade identified to
meet those interconnection-related needs has a voltage of at least 200
kV and/or an estimated cost of at least $30 million; (3) those
interconnection-related network upgrades have not been developed and
are not currently planned to be developed because the interconnection
request(s) driving the need for the upgrade has been withdrawn; and (4)
the public utility transmission provider has not identified an
interconnection-related network upgrade to address the relevant
interconnection-related need in an executed generator interconnection
agreement or in a generator interconnection agreement that the
interconnection customer requested that the public utility transmission
provider file unexecuted with the Commission.
    167. We propose to require that public utility transmission
providers in each transmission planning region consider regional
transmission facilities to address interconnection-related needs
pursuant to this reform through the proposed Long-Term Regional
Transmission Planning. We recognize that the Long-Term Regional
Transmission Planning proposal requires that public utility
transmission providers incorporate interconnection queue withdrawals
into Long-Term Scenario development. Consequently, we propose to
require that public utility transmission providers in each transmission
planning region incorporate the specific

interconnection-related needs identified through this reform as a
factor used to develop Long-Term Scenarios.
    168. We preliminarily find that this requirement will support the
establishment of just and reasonable and not unduly discriminatory or
preferential Commission-jurisdictional rates by addressing a potential
barrier to integrating new sources of generation that may otherwise
continue to exist absent such requirements in the regional transmission
planning process. Additionally, to the extent that such transmission
facilities are selected in the regional transmission plan for purposes
of cost allocation, this proposal would provide an avenue to allocate
these regional transmission facilities' costs more broadly in
recognition of their more widespread benefits (as identified through
the regional transmission planning process), helping to ensure that
their costs are allocated in a manner that is at least roughly
commensurate with the estimated benefits that they provide. We believe
that the criteria proposed above that the public utility transmission
provider must use to identify the interconnection-related needs that
should be considered in the regional transmission planning process will
help to ensure that the associated interconnection-related network
upgrades are likely to have produced benefits beyond those provided to
the interconnection customers whose interconnection requests the
interconnection-related network upgrades are needed to accommodate. It
is important to note that we are not proposing that all
interconnection-related needs that satisfy the above criteria must
result in transmission facilities being selected in the regional
transmission plan for purposes of cost allocation; rather, those
regional transmission facilities would have to independently satisfy
the criteria for such selection in Long-Term Regional Transmission
Planning as the more efficient or cost-effective transmission facility.
    169. As noted above, we propose that the first qualifying criterion
for this potential reform is that the public utility transmission
provider has identified a needed interconnection-related network
upgrade in generator interconnection studies to address the same
interconnection-related need in at least two interconnection queue
cycles during the preceding five years. The five-year look-back for
each interconnection-related need would begin on the date that an
interconnection customer with an interconnection study that identifies
an interconnection-related network upgrade that meets the voltage or
cost estimate threshold withdraws its interconnection request.\301\ We
propose to choose this starting point because, arguably, this is the
earliest point at which the transmission provider will have notice that
the costs associated with an identified interconnection-related network
upgrade may have caused a withdrawal. We also believe that this
criterion appropriately limits the scope of this requirement to those
interconnection-related needs that are likely to persist, are not
unique to a single interconnection customer's request, and have the
potential, if evaluated through the regional transmission planning
process, to provide more widespread benefits to transmission customers.
---------------------------------------------------------------------------

    \301\ We propose that when an interconnection-related network
upgrade is identified for the interconnection of more than one
interconnection customer in an interconnection queue cycle, the
withdrawal of all interconnection customers assigned to that
interconnection-related network upgrade qualifies as one withdrawal.
The withdrawal of a single interconnection customer when other
interconnection customers assigned to the interconnection-related
network upgrade remain in the interconnection queue cycle does not
qualify as a withdrawal of an interconnection queue interconnection
request for the purposes of this reform.
---------------------------------------------------------------------------

    170. We propose that the initial five-year time period begin five
calendar years prior to the initial effective date of the accepted
tariff provisions proposed to comply with this reform. Thus, upon the
acceptance of such tariff provisions in a Commission or delegated
letter order, the public utility transmission provider would consider
interconnection-related network upgrades identified to address the same
interconnection-related need in at least two interconnection queue
cycles in the five calendar years prior to the effective date
established in the order accepting those tariff revisions. Thus, if the
Commission adopts this proposal, the public utility transmission
provider should not look back to a point earlier than that date and,
going forward, this requirement would apply to any repeat
identification of an interconnection-related need identified in at
least two interconnection queue cycles in the immediately preceding
five calendar years. We believe that such a limitation would prevent
consideration of regional transmission facilities (more specifically,
interconnection-related network upgrades) identified using data that
may be stale by the time the public utility transmission providers in a
transmission planning region consider regional transmission facilities
to address the identified interconnection-related needs in their
regional transmission planning process. We believe that five years is
short enough to provide public utility transmission providers with
accurate information on interconnection-related needs and also long
enough for public utility transmission providers to identify the same
interconnection-related need, which is likely to persist, in at least
two interconnection queue cycles.
    171. We do not propose to limit this reform to interconnection-
related network upgrades that are identical to those identified in
prior interconnection queue cycles. Instead, we propose to focus on the
relevant interconnection-related needs that those upgrades are intended
to address. To this point, we propose to require that public utility
transmission providers in each transmission planning region consider
whether the interconnection-related need for which the public utility
transmission provider identified the interconnection-related network
upgrade is the same in multiple interconnection queue cycles. That is,
if an interconnection-related need is driving the identification of an
interconnection-related network upgrade on the transmission system in
one interconnection queue cycle and an interconnection-related network
upgrade with, for example, a different voltage, starting point, or
ending point is identified in the next interconnection queue cycle to
address the same interconnection-related need, then the first criterion
would be satisfied. We believe that this approach will appropriately
account for differences in technology, study assumptions, system
topology, and/or interconnection requests that may occur over time that
may result in different interconnection-related network upgrades to
address the same interconnection-related need.
    172. We also propose to limit the scope of this reform to those
interconnection-related network upgrades that have a voltage of at
least 200 kV and/or an estimated cost of at least $30 million. We note
that we have previously found a 200 kV voltage threshold to be just and
reasonable in the context of an analogous provision in CAISO's
tariff.\302\ With respect to the

$30 million estimated cost threshold, evidence suggests that requiring
interconnection customers to be responsible for this level of costs
from a single interconnection-related network upgrade can lead to
withdrawal from the interconnection queue, signaling that this level
may be an appropriate dividing line for consideration in regional
transmission planning processes.\303\
---------------------------------------------------------------------------

    \302\ Section <IP_ADDRESS> of CAISO's Comprehensive Transmission
Planning Process provides that interconnection-related network
upgrades identified in the generator interconnection process that
are not already included in a signed LGIA may be assessed in the
Comprehensive Transmission Planning Process if they ``consist of new
transmission lines 200 kV or above, and have capital costs of $100
million or greater; . . . [are] a new 500 kV substation that has
capital costs of $100 million or greater; or, . . . have a capital
cost of $200 million or more.'' CAISO, Tariff, sectionSec.  <IP_ADDRESS>
(LGIP Network Upgrades) (1.0.0).
    \303\ TheAn ACEG Reportreport notes that 3.5 of 5 GW of
renewable energy projects in the MISO West 2017 study group dropped
out because each project ``faced transmission costs in the range of
tens to hundreds of millions of dollars.'' ACEG ReportSee Americans
for a Clean Energy Grid, Disconnected: The Need for New Generator
Interconnection Policy, at 17. (Jan. 2021). We also note that thean
ICF Report indicates that the Wichita-Benton 345 kV line in SPP
South, which has appeared in two different interconnection queue
cycles and has not been constructed, has an estimated cost of $32.1
million. See ICF ReportResources, LLC, Just & Reasonable?
Transmission Upgrades Charged to Interconnection Generators are
Delivering System-Wide Benefits, at 5, 26. (Sep. 2021). As a further
reference point, wind and solar industry advocates claim that ``the
`implied cost threshold' beyond which new generators are often no
longer financially viable is . . . . . . an average of about
$100,000 per megawatt of installed capacity.'' See American Wind
Energy Association, Clean Grid Alliance, and SEIA, Generator
Contributions to Transmission Expansion, at 2 (AugustAug. 2020),
https://cleangridalliance.org/_uploads/_media_uploads/_source/Generator_Contrib_Xmission-V3a-FINAL.pdf.
---------------------------------------------------------------------------

    173. To avoid shifting costs inappropriately from generators in the
generator interconnection process to transmission customers through the
regional transmission planning process, we further propose to limit the
scope of interconnection-related needs to be considered in the regional
transmission planning process to those interconnection-related needs
not addressed by interconnection-related network upgrades memorialized
in an executed generator interconnection agreement (or in a generator
interconnection agreement that the interconnection customer requested
to be filed unexecuted with the Commission). This proposed limitation
would ensure that public utility transmission providers only consider
in their regional transmission planning process interconnection-related
network upgrades that remain unconstructed despite the existence of a
demonstrated interconnection-related need. We reiterate that regional
transmission facilities identified through this process would have to
independently satisfy the public utility transmission provider's
criteria for selection in the regional transmission plan for purposes
of cost allocation as the more efficient or cost-effective transmission
solution.
    174. We seek comment on the requirements proposed in this section
of the NOPR. In particular, we seek comment on whether this proposed
reform could delay the processing of existing interconnection queues
and what reforms, if any, would be necessary to ensure that the
generator interconnection and regional transmission planning processes
are not significantly delayed by this proposed reform. We also seek
comment on the appropriateness of the criteria that we propose a public
utility transmission provider must use to identify the interconnection-
related needs that should be considered in the regional transmission
planning process, and whether there are alternative criteria public
utility transmissions providers may use to identify significant
interconnection-related needs that warrant consideration in the
regional transmission planning process. Finally, we seek comment on how
this proposed reform should interact with existing regional
transmission planning processes and the Long-Term Regional Transmission
Planning proposed herein.
iii. Evaluation of the Benefits of Regional Transmission Facilities
    175. As discussed above, we propose to require that public utility
transmission providers in each transmission planning region identify
transmission needs driven by changes in the resource mix and demand
using Long-Term Scenarios that meet the requirements proposed above. As
explained in this section, once the public utility transmission
providers in a transmission planning region have identified the
region's transmission needs driven by changes in the resource mix and
demand, we propose to require that, as part of public utility
transmission providers' identification and evaluation of more efficient
or cost-effective regional transmission facilities that may resolve
those transmission needs in the regional transmission planning process,
public utility transmission providers must: (1) Evaluate the benefits
of regional transmission facilities to meet identified transmission
needs driven by changes in the resource mix and demand, identify which
benefits they will use in Long-Term Regional Transmission Planning,
explain how they will calculate those benefits, and explain how the
benefits will reasonably reflect the benefits of regional transmission
facilities to meet identified transmission needs driven by changes in
the resource mix and demand ; and (2) evaluate the benefits of regional
transmission facilities over a time horizon that covers, at a minimum,
20 years starting from the estimated in-service date of the
transmission facilities. Further, we propose to allow (but not require)
public utility transmission providers to evaluate the benefits of a
portfolio of regional transmission facilities instead of doing so on a
facility-by-facility basis. Finally, we identify and describe a broad
set of benefits that we believe public utility transmission providers
could consider using in Long-Term Regional Transmission Planning (Long-
Term Regional Transmission Benefits) to reasonably capture the benefit
of regional transmission facilities to meet identified transmission
needs driven by changes in the resource mix and demand.
(a) Evaluations of Long-Term Regional Transmission Benefits
    176. In Order No. 1000, the Commission neither prescribed a
particular definition of ``benefits'' or ``beneficiaries,'' nor
required consideration of any specific benefits. Instead, the
Commission stated that the proper context for consideration of such
matters would be on review of compliance proposals.\304\ The Commission
stated that allowing greater flexibility to accommodate a variety of
approaches better advanced the goals of Order No. 1000.\305\ The
Commission also stated that, in determining the beneficiaries of
transmission facilities, a regional transmission planning process could
consider benefits including, but not limited to, the extent to which
transmission facilities, individually or in the aggregate, provide for
maintaining reliability and sharing reserves, production cost savings
and congestion relief, and/or meeting Public Policy Requirements.\306\
The result is that there are no specific requirements for public
utility transmission providers to consider any particular benefit or
set of benefits in evaluating transmission facilities for selection in
the regional transmission plan for purposes of cost allocation as the
more efficient or cost-effective solution to a regional transmission
need.
---------------------------------------------------------------------------

    \304\ Order No. 1000, 136 FERC ] 61,051 at P 624.
    \305\ Id. PP 624-625.
    \306\ Id. P 622.
---------------------------------------------------------------------------

    177. In the ANOPR, the Commission sought comment on whether the
Commission should require public utility transmission providers to use
a minimum set of benefits to identify more efficient or cost-effective
regional transmission facilities, and what those benefits should
be.\307\ The Commission

sought comment as to whether the existing regional transmission
planning and cost allocation processes fully accounted for the full
suite of benefits, including hard-to-quantify benefits. Further, the
Commission sought comment on the types of benefits provided by
transmission facilities needed to meet the transmission needs of the
changing resource mix, as well as the manner in which those benefits
can be quantified, if at all. The Commission also sought comment on how
public utility transmission providers can document and account for
benefits if those benefits cannot be quantified, but are real.\308\
---------------------------------------------------------------------------

    \307\ ANOPR, 176 FERC ] 61,024 at P 53.
    \308\ Id. P 70.
---------------------------------------------------------------------------

(1) Comments
    178. Many commenters support consideration of a wider set of
benefits than those currently used to evaluate transmission facilities
for potential selection in the regional transmission plan for purposes
of cost allocation.\309\ Further, many commenters support the
consideration of all possible benefits of regional transmission
facilities when discussing benefits in the context of the current
approach to separately consider reliability, economic, and public
policy benefits--however, even some commenters that support maintaining
the Order No. 1000 framework acknowledge that the benefits assessed
could be expanded.\310\ Commenters that support requiring consideration
of an expanded set of transmission benefits argue that existing
regional transmission planning processes are unjust and unreasonable
because they ignore the full range of transmission benefits and
therefore fail to select net beneficial transmission facilities,
leading to underinvestment in transmission and higher consumer costs in
the long run.\311\ PIOs assert that the Commission should conduct a
survey of all potential benefits that can result from multi-value,
scenario-based planning and should require that public utility
transmission providers consider those benefits for regional
transmission planning.\312\ Numerous commenters point to a list of
transmission benefits identified by The Brattle Group as providing a
useful framework for delineating a minimum set of benefits that the
Commission could require public utility transmission providers to
consider when evaluating alternative regional transmission
facilities.\313\
---------------------------------------------------------------------------

    \309\ ACORE Comments at ii; AEE Comments at 31-32; ACEG Comments
at 6-8; ACPA and ESA Comments at 75; AEP Comments at 14; Amazon
Comments at 4; Anbaric Comments at 29; Avangrid Comments at 9;
Business Council for Sustainable Energy Comments at 2; Citizens
Energy Comments at 6-7; City of New York Comments at 3-4; Union of
Concerned Scientists Comments at 66-75; Consumers Council Comments
at 4, 16; Duke Comments at 12; EDF Comments at 8-10; EEI Comments at
33; ITC Comments at 28-34; Massachusetts Attorney General Comments
at 24-25; New Jersey Commission at 13-14, 17-19; NextEra Comments at
83-88; Northwest and Intermountain Comments at 35-38; Orsted
Comments at 6-7; PIOs Comments at 30, 60; Policy Integrity Comments
at 43; PSEG Comments at 25-27; REBA Comments at 17; RMI Comments at
4; SEIA Comments at 9; Shell Comments at 18-20; State Agencies
Comments at 21-22; State of Massachusetts Comments at 16-17; U.S.
DOE Comments at 7-9, 23-24; WIRES Comments at 18; see also Joint
Fed.-State Task Force on Elec. Transmission, Transcript of Feb. 16,
2022 Meeting, Docket No. AD21-15-000, at 19:15-18, 22:9-12 (Comm'r
Rechtschaffen) (supporting expanded list of benefits and arguing
that a more comprehensive benefit-cost analysis would lead to better
transmission planning).
    \310\ City of New York Comments at 7; PIOs Comments at 81-82;
EEI Comments at 24-25; PG&E Comments at 8-9; Anbaric Comments at 29;
Union of Concerned Scientists Comments at 38; State of Massachusetts
Comments at 16-19; Orsted Comments at 6-7; RMI Comments at 4.
    \311\ See, e.g., ACEG Comments at 31-32 & app. A; ACORE Comments
at 31-32 & Ex. 6; ACPA and ESA Comments at 24-27; NextEra Comments
at 84-86; PIOs Comments at 82; PIOs Reply Comments at 55.
    \312\ PIOs Comments at 30; see also Orsted Comments at 6.
    \313\ See, e.g., ACEG Comments at 34 & app. A; ACORE Comments at
34 & Ex. 6; ACPA and ESA Comments at 24-26; EDF Comments at 9;
NextEra Comments at 84-86; PIOs Comments at 34 & Ex. A; RMI Comments
at 4; U.S. DOE Comments at 37; WIRES Comments at 2; ACEG Reply
Comments at 11; Enel Reply Comments at 3-4; PIOs Reply Comments at
55; see also February Joint Task Force Tr 49:8-13 (Ted Thomas)
(stating that The Brattle Group list of benefits is ``characterized
by rigor'').
---------------------------------------------------------------------------

    179. Many commenters generally request regional flexibility to
consider benefits. Ameren opposes requiring a specific set of benefits,
arguing that such a reform could lead to controversy and delays.\314\
Consumer Organizations and District of Columbia's Office of the
People's Counsel express that, if additional benefits are added to the
equation, additional costs to communities and landowners (for example,
additional farm production costs, local road use, and local emergency
services) should be, too.\315\ Consumer Organizations and LPPC assert
that it is not within the Commission's authority to create ``new
speculative benefits'' in an effort to broaden cost allocation.\316\
District of Columbia's Office of the People's Counsel urges that
greater specificity is needed regarding what is a benefit.\317\ APPA
does not support considering environmental benefits associated with
particular types of resources in planning transmission facilities and
allocating costs.\318\
---------------------------------------------------------------------------

    \314\ Ameren Comments at 9-11.
    \315\ Consumer Organizations Comments at 18-19; District of
Columbia's Office of the People's Counsel Comments at 26-27.
    \316\ Consumer Organizations Comments at 18; LPPC Comments at
20-23.
    \317\ District of Columbia's Office of the People's Counsel
Comments at 3-4.
    \318\ APPA Comments at 15-16.
---------------------------------------------------------------------------

    180. MISO states that it has adopted benefit metrics such as
avoided/deferred reliability projects and reduced MISO-SPP settlement
costs that go beyond adjusted production cost savings. However, MISO
states that it has not been able to adopt other metrics explored in the
stakeholder process, including: (1) Transmission outage and
transmission energy losses; and (2) reduced capacity cost due to
reduced peak load losses and future capacity expansion deferral due to
increased capacity import and export limits.\319\ MISO seeks
flexibility on benefits that are considered to reflect changing
circumstances but calls for direction or guidance from the Commission
on identification and quantification of challenging benefits like
resilience.\320\
---------------------------------------------------------------------------

    \319\ MISO Comments at 23-26.
    \320\ Id. at 52-53; see also February Joint Task Force Tr 20:5-
8, 21:4-12 (Clifford Rechtschaffen) (suggesting that the reliability
category should be expanded to include resilience, particularly in
light of extreme events in the West and increasingly intense
hurricanes in the East), 51:10-15 (Matthew Nelson) (stating that
having commonality in terminology for benefits and where they are
considered would be valuable), 69:16-18 (Jason Stanek) (concluding
that if there is a fourth category of benefits, it may be
resilience), 73:1-4 (Riley Allen) (arguing for not ignoring
difficult to quantify benefits but rather for finding sensible ways
to quantify them).
---------------------------------------------------------------------------

    181. NYISO supports identifying economic benefits when studying
reliability projects. NYISO states that the current economic
calculation is based on net production cost savings and does not
consider other economic benefits such as installed capacity cost
savings to load-serving entities.\321\
---------------------------------------------------------------------------

    \321\ NYISO Comments at 27-31, 34-37; see also February Joint
Task Force Tr 20:9-12 (Clifford Rechtschaffen) (advocating for
expanding the economic category to include improved connectivity to
lower-cost generation).
---------------------------------------------------------------------------

    182. The PJM Market Monitor claims that PJM incorrectly defines the
benefits of proposed market efficiency transmission projects, resulting
in uneconomic transmission upgrades. In particular, the PJM Market
Monitor argues that PJM uses speculative transmission-related benefits
over a 15-year period while limiting the analysis to the existing
generation fleet and existing patterns of fuel costs and congestion,
which eliminates the possibility that new generation could respond to
market signals and meet the same needs.\322\ The PJM Market Monitor
cautions against considering congestion reduction or localized
locational marginal price reductions as an economic benefit to a
potential transmission project without accurately

accounting for how the congestion dollars are or are not returned to
load through the financial transmission rights (or their
equivalent).\323\
---------------------------------------------------------------------------

    \322\ PJM Market Monitor Comments at 10.
    \323\ Id. at 11.
---------------------------------------------------------------------------

(2) Proposed Reform
    183. At this time, consistent with Order No. 1000, we decline to
propose to prescribe any particular definition of ``benefits'' or
``beneficiaries,'' nor require use of any specific benefits.\324\
Instead, we continue to acknowledge the benefits of regional
flexibility, and consistent with Order No. 1000, propose to consider
such matters on review of compliance proposals.\325\ Nevertheless, we
acknowledge the support for the adoption of a common set of minimum
benefits, and we propose a list of Long-Term Regional Transmission
Benefits described below that public utility transmission providers may
consider in Long-Term Regional Transmission Planning and cost
allocation processes. In addition, we propose to require that public
utility transmission providers identify on compliance the benefits they
will use in Long-Term Regional Transmission Planning, how they will
calculate those benefits, and how the benefits will reasonably reflect
the benefits of regional transmission facilities to meet identified
transmission needs driven by changes in the resource mix and demand. As
part of this compliance obligation, public utility transmission
providers should explain the rationale for using the benefits
identified.
---------------------------------------------------------------------------

    \324\ See Order No. 1000, 136 FERC ] 61,051 at PP 624-625.
    \325\ See id. P 624.
---------------------------------------------------------------------------

    184. We believe that the Long-Term Regional Transmission Benefits
discussed below account for many of the benefits that regional
transmission facilities to address transmission needs driven by changes
in the resource mix and demand identified as part of Long-Term Regional
Transmission Planning are most likely to provide. However, we clarify
that this list of potential benefits is not mandatory or exhaustive and
public utility transmission providers would have flexibility to propose
what benefits to use as part of their Long-Term Regional Transmission
Planning. For example, public utility transmission providers may wish
to use benefits previously accepted by the Commission for existing
regional transmission planning processes that are not included in the
Long-Term Regional Transmission Benefits discussed herein.
    185. We believe that the following set of Long-Term Regional
Transmission Benefits may be useful in evaluating transmission
facilities for selection in the regional transmission plan for purposes
of cost allocation as the more efficient or cost-effective solutions to
meet transmission needs driven by changes in the resource mix and
demand: (1) Avoided or deferred reliability transmission projects and
aging infrastructure replacement; (2) either reduced loss of load
probability or reduced planning reserve margin; (3) production cost
savings; (4) reduced transmission energy losses; (5) reduced congestion
due to transmission outages; (6) mitigation of extreme events and
system contingencies; (7) mitigation of weather and load uncertainty;
(8) capacity cost benefits from reduced peak energy losses; (9)
deferred generation capacity investments; (10) access to lower-cost
generation; (11) increased competition; and (12) increased market
liquidity.

            Table 1--Long-Term Regional Transmission Benefits
------------------------------------------------------------------------
                Benefit                            Description
------------------------------------------------------------------------
Avoided or deferred reliability          Reduced costs of avoided or
 transmission facilities and aging        delayed transmission
 transmission infrastructure              investment otherwise required
 replacement.                             to address reliability needs
                                          or replace aging transmission
                                          facilities.
Reduced loss of load probability [OR     Reduced frequency of loss of
 next benefit].                           load events by providing
                                          additional pathways for
                                          connecting generation
                                          resources with load (if
                                          planning reserve margin is
                                          constant), resulting in
                                          benefit of reduced expected
                                          unserved energy by customer
                                          value of lost load.
Reduced planning reserve margin [OR      While holding loss of load
 prior benefit].                          probabilities constant, system
                                          operators can reduce their
                                          resource adequacy requirements
                                          (i.e., planning reserve
                                          margins), resulting in a
                                          benefit of reduced capital
                                          cost of generation needed to
                                          meet resource adequacy
                                          requirements.
Production cost savings................  Reduction in production costs,
                                          including savings in fuel and
                                          other variable operating costs
                                          of power generation, that are
                                          realized when transmission
                                          facilities allow for the
                                          increased dispatch of
                                          suppliers that have lower
                                          incremental costs of
                                          production, displacing higher-
                                          cost supplies; also reduction
                                          in market prices as lower-cost
                                          suppliers set market clearing
                                          prices; when adjusted to
                                          account for purchases and
                                          sales outside the region,
                                          called adjusted production
                                          cost savings.
Reduced transmission energy losses.....  Reduced energy losses incurred
                                          in transmittal of power from
                                          generation to loads, thereby
                                          reducing total energy
                                          necessary to meet demand.
Reduced congestion due to transmission   Reduced production costs during
 outages.                                 transmission outages that
                                          significantly increase
                                          transmission congestion.
Mitigation of extreme events and system  Reduced production costs during
 contingencies.                           extreme events, such as
                                          unusual weather conditions,
                                          fuel shortages, and multiple
                                          or sustained generation and
                                          transmission outages, through
                                          more robust transmission
                                          system reducing high-cost
                                          generation and emergency
                                          procurements necessary to
                                          support the system.
Mitigation of weather and load           Reduced production costs during
 uncertainty.                             higher than normal load
                                          conditions or significant
                                          shifts in regional weather
                                          patterns.
Capacity cost benefits from reduced      Reduced energy losses during
 peak energy losses.                      peak load reduces generation
                                          capacity investment needed to
                                          meet the peak load and
                                          transmission losses.
Deferred generation capacity             Reduced costs of needed
 investments.                             generation capacity
                                          investments through expanded
                                          import capability into
                                          resource-constrained areas.

Access to lower-cost generation........  Reduced total cost of
                                          generation due to ability to
                                          locate units in a more
                                          economically efficient
                                          location (e.g., low permitting
                                          costs, low-cost sites on which
                                          plants can be built, access to
                                          existing infrastructure, low
                                          labor costs, low fuel costs,
                                          access to valuable natural
                                          resources, locations with high-
                                          quality renewable energy
                                          resources).
Increased competition..................  Reduced bid prices in wholesale
                                          electricity markets due to
                                          increased competition among
                                          generators and reduced overall
                                          market concentration/market
                                          power.
Increased market liquidity.............  Reduced transaction costs
                                          (e.g., bid-ask spreads) of
                                          bilateral transactions,
                                          increased price transparency,
                                          increased efficiency of risk
                                          management, improved
                                          contracting, and better
                                          clarity for long-term
                                          transmission planning and
                                          investment decisions through
                                          increased number of buyers and
                                          sellers able to transact with
                                          each other as a result of
                                          transmission expansion.
------------------------------------------------------------------------

    186. Below, we describe each benefit along with examples of how
each benefit may be calculated. We clarify that these are just
examples, and we are not proposing to require that public utility
transmission providers use any specific benefits or calculate those
benefits in a particular manner when conducting Long-Term Regional
Transmission Planning. At this time, we are only proposing to require
public utility transmission providers to identify what benefits they
will use in Long-Term Regional Transmission Planning and explain how
they will be calculated and how the benefits will reasonably reflect
the benefits of regional transmission facilities to meet identified
transmission needs driven by changes in the resource mix and demand.
    187. We seek comment on each of the Long-Term Regional Transmission
Benefits discussed in this section of the NOPR. Additionally, we seek
comment on how to ensure that each type of benefit is distinct such
that the list of benefits does not ``double count'' benefits. We also
seek comment on the application of the Long-Term Regional Transmission
Benefits in non-RTO/ISO regions.
    188. Finally, we seek comment on whether public utility
transmission providers should be required to use some or all of the
Long-Term Regional Transmission Benefits as a minimum set of benefits
for their Long-Term Regional Transmission Planning process.
(3) Description of Long-Term Regional Transmission Benefits
    189. The benefits of transmission facilities identified in Long-
Term Regional Transmission Planning may include a set of benefits
related to avoided or deferred reliability transmission facilities and
aging transmission infrastructure replacement, which we describe as
reduced costs on avoided or delayed transmission investment otherwise
required to address reliability needs or replace aging transmission
facilities. The Commission has recognized that regional transmission
planning could lead to the development of transmission facilities that
span the service territories of multiple public utility transmission
providers, which in turn would obviate the need for transmission
facilities that would otherwise be identified in multiple local
transmission plans.\326\
---------------------------------------------------------------------------

    \326\ Order No. 1000, 136 FERC ] 61,051 at P 81.
---------------------------------------------------------------------------

    190. The Commission has accepted accounting for such ``avoided
costs'' as part of a method for identifying beneficiaries and
allocating costs in almost all the regional cost allocation methods in
non-RTO/ISO regions. Using this method, public utility transmission
providers in a transmission planning region determine the beneficiaries
of a regional transmission facility or portfolio of facilities by
identifying the local and regional transmission facilities that a new
proposed regional transmission facility or portfolio of facilities
would displace. The method defines the benefits of the regional
transmission facility or facilities as the costs that public utility
transmission providers in the transmission planning region ``avoid''
because they no longer need to build the displaced local and regional
transmission facilities. The method allocates costs among public
utility transmission providers whose local or regional transmission
facilities the new proposed regional transmission facility or
facilities would displace in proportion to their share of the total
benefits (i.e., the total avoided costs). If the new proposed regional
transmission facility or facilities do not displace any local or
regional transmission facilities in existing local or regional
transmission plans, the avoided cost method determines the benefits of
the applicable facilities by considering the costs of local or regional
transmission facilities that would otherwise be needed to meet the same
need that the new proposed regional transmission facility will
meet.\327\
---------------------------------------------------------------------------

    \327\ See, e.g., S.C. Elec. & Gas Co., 143 FERC ] 61,058, at P
232 (2013).
---------------------------------------------------------------------------

    191. In calculating this benefit, public utility transmission
providers in each transmission planning region could first identify
transmission facilities that could defer or replace an identified
reliability transmission solution. Avoided cost benefits could be
calculated by comparing the cost of transmission facilities required to
address the reliability need without the proposed regional transmission
facility to the cost of transmission facilities needed to address the
reliability need assuming the regional transmission solution were in
place.\328\
---------------------------------------------------------------------------

    \328\ Brattle-Grid Strategies Oct. 2021 Report at 37.
---------------------------------------------------------------------------

    192. Similarly, this benefit could also include the separate
benefits stream caused by a deferral of replacement of other
transmission facilities through identification and selection for
purposes of cost allocation in the regional transmission plan of a
transmission facility or facilities. This could be measured through
calculation of the present value savings for the period of deferral of
additional replacement transmission facilities multiplied by their
estimated capital cost.
    193. A number of public utility transmission providers already
evaluate the avoided or deferred costs of reliability transmission
projects. For example, SPP uses a power flow model to analyze the
ability of potential economic and Public Policy transmission facilities
to meet the same thermal reliability needs addressed by a potential
reliability transmission facility. The costs of these avoided or
delayed reliability transmission

facilities are used to determine the reliability benefit of the
potential economic or Public Policy Requirements transmission
facilities.\329\ Public utility transmission providers could also use
avoided costs to calculate the benefits of replacing aging transmission
facilities. NYISO, for example, estimates the benefits associated with
the replacement of aging transmission facilities by quantifying the
savings of not having to refurbish the facilities in the future.\330\
---------------------------------------------------------------------------

    \329\ SPP Benefit Metrics Manual, SPP Engineering, at 15 (Nov.
6, 2020).
    \330\ The Brattle Group, Benefit-Cost Analysis of Proposed New
York AC Transmission Upgrades, The Brattle Group, at 114 (Sept. 15,
2015).
---------------------------------------------------------------------------

    194. Another potential benefit of regional transmission
infrastructure is reduced frequency of loss of load events by providing
additional pathways for connecting generation resources with load in
regions that can be constrained by weather events and unplanned outages
(if planning reserve margin is not changed despite lower loss of load
events), as well as improved physical reliability benefits by reducing
the likelihood of load shed events; or reduced planning reserve margin,
which we propose to define as the reduction in capital costs of
generation needed to meet resource adequacy requirements (i.e.,
planning reserve margins) while holding loss of load probability
constant. There is an overlap between reduced loss of load probability
benefits and reduced planning reserve margin benefits, such that a
single transmission facility can either reduce loss of load events if
the planning reserve margin is unchanged or allow for the reduction in
planning reserve margins if loss of load events remain constant, but
not both simultaneously.
    195. As for reduction in loss of load probability benefits,
transmission investments, even those not made to satisfy a reliability
need, generally enhance the reliability of the transmission system by
increasing transfer capability, which, in turn, reduces the likelihood
that a public utility transmission provider will be unable to serve its
load due to a shortage of generation over a given period. This
enhancement in reliability can be measured as a reduction in loss of
load probability, or the likelihood of system demand exceeding
generation over a given period. One example of how a reduction of loss
of load probability benefit could be calculated can be found in a
report by SPP's Metrics Task Force. The report proposes quantifying the
incremental increase in system reliability by determining the reduction
in expected unserved energy between the base case and the change case,
obtaining the value of lost load, and multiplying these two values to
obtain the monetary benefit of enhanced reliability associated with a
transmission expansion.\331\
---------------------------------------------------------------------------

    \331\ SPP, Benefits for the 2013 Regional Cost Allocation
Review, at 25 (Sept. 13, 2012).
---------------------------------------------------------------------------

    196. A lower planning reserve margin requirement is another way to
demonstrate a resource adequacy benefit. Investments in transmission
capacity can reduce the system-wide planning reserve margin requirement
of the system-wide or reserve margin requirement within individual
resource adequacy zones of a transmission planning region, which can
reduce the need for generation capital expenditures. It is important to
note that, due to the overlap between the benefit obtained from a
reduction in reserve margin requirements and the benefit associated
with loss of load probability, only one of these benefits should be
calculated for a transmission investment, but not both simultaneously.
    197. RTOs/ISOs have calculated the transmission benefits of reduced
planning reserve margins. MISO, for example, calculated a reduction in
planning reserves associated with its MVP portfolio, which reduced the
need for future generation buildout to meet reserve requirements, by
using loss of load expectation reliability simulations. MISO estimated
that its MVP portfolio was expected to reduce the required planning
reserve margin by up to one percentage point, which translated into a
projected savings of $1.0 to $5.1 billion in benefits over 10
years.\332\
---------------------------------------------------------------------------

    \332\ MISO, Proposed Multi Value Project Portfolio: Business
Case Workshop, at 36-38 (Sept. 19 & 29, 2011).
---------------------------------------------------------------------------

    198. Another potential benefit of regional transmission
infrastructure is production cost savings, which we describe as savings
in fuel and other variable operating costs of power generation that are
realized when transmission facilities allow for displacement of higher-
cost supplies through the increased dispatch of suppliers that have
lower incremental costs of production, as well as a reduction in market
prices as lower-cost suppliers set market clearing prices.\333\
---------------------------------------------------------------------------

    \333\ When this calculation is adjusted to account for purchases
and sales outside the region, we propose to define this as adjusted
production cost savings.
---------------------------------------------------------------------------

    199. Most regional transmission planning processes currently
estimate production cost savings. Generally, within RTOs/ISOs,
security-constrained production cost models simulate the hourly
operations of the electric system and the wholesale electricity market
by emulating how system operators would commit and dispatch generation
resources to serve load at least cost, subject to transmission and
operating constraints. The traditional method for estimating the
changes in adjusted production costs associated with proposed
transmission facilities (or portfolio of facilities) is to compare the
adjusted production costs with and without those facilities. Analysts
typically call the market simulations without the proposed transmission
facilities the ``Base Case'' and the simulations with those facilities
the ``Change Case.''
    200. Approaches used to calculate production cost savings vary.
MISO uses production cost savings (adjusted for import costs and export
revenues) to allocate the costs of its Market Efficiency Projects to
cost allocation zones based on each zone's share of the total adjusted
production cost savings.\334\ NYISO and PJM, in contrast, use
reductions to load energy payments (adjusted to reflect the reduced
value of transmission congestion contracts) to allocate the costs of
economic transmission facilities.\335\
---------------------------------------------------------------------------

    \334\ See MISO, FERC Electric Tariff, Attach. FF, Benefit
Metrics Sec.  (I)(A)(1) (33.0.0).
    \335\ See PJM Interconnection L.L.C.,142 FERC ] 61,214, at P 416
(2013) (PJM First Regional Compliance Order); New York Independent
System Operator Corp.,143 FERC ] 61,059 at PP 268, 269, n.516 (2013)
(NYISO First Regional Compliance Order); NYISO, NYISO Tariffs, OATT,
attach. Y, Sec.  31.5 (27.0.0), Sec.  <IP_ADDRESS>.2. For high voltage
economic transmission facilities, PJM allocates 50% of the costs in
accordance with its economic analysis and allocates the other 50% of
the costs on a load-ratio share basis.
---------------------------------------------------------------------------

    201. Non-RTO/ISO regions, without centrally organized energy
markets, rely on other tools to perform analyses of production cost
savings. For example, WestConnect's regional cost allocation method for
regional transmission facilities driven by economic considerations
identifies the benefits and beneficiaries of a proposed regional
transmission facility or facilities by modeling the potential of the
transmission facilities to support more economic bilateral transactions
between generators and loads in the region. Specifically, WestConnect
considers the transactions between loads and lower-cost generation that
a proposed regional transmission facilities could support and,
accounting for the costs associated with transmission service,
identifies the transactions that are likely to occur. WestConnect then
estimates any resulting cost savings (in the form of reductions in
production costs and reserve sharing requirements) and

allocates the costs of the regional transmission facilities on that
basis.\336\
---------------------------------------------------------------------------

    \336\ Pub. Serv. Co. of Colo., 142 FERC ] 61,206, at P 314
(2013).
---------------------------------------------------------------------------

    202. Another set of potential benefits of regional transmission
infrastructure is benefits related to reduced transmission energy
losses, which we describe as reduced total energy necessary to meet
demand stemming from reduced energy losses incurred in transmittal of
power from generation to loads. These benefits include the reduced
energy losses incurred when transmitting power from generation to
loads.
    203. Production cost savings metrics used today typically exclude
reduced transmission energy losses and the other three production cost
savings-related benefits in our proposed list described further below.
Including these additional benefits can produce a more robust set of
congestion and production cost benefits that can be quantified and
integrated into the method for calculating production cost savings,
and, therefore, help to ensure that the more efficient or cost-
effective transmission facilities are selected in the regional
transmission plan for purposes of cost allocation through Long-Term
Regional Transmission Planning.
    204. To measure reduced transmission energy losses, public utility
transmission providers could: (1) Simulate losses in production cost
models; (2) estimate changes in losses with power flow models for a
range of hours; or (3) estimate how the cost of supplying losses will
likely change with marginal loss charges. For example, American
Transmission Company (ATC) measured reduced transmission energy losses
based on changes in marginal loss charges and loss refund estimates
using the marginal loss component from the PROMOD \337\ electric market
simulation software simulations for the Paddock-Rockdale 345 kV Access
Project,\338\ which produced cost reduction benefits using adjusted
production cost analysis. Also, SPP's analysis for its Regional Cost
Allocation Review (RCAR) process estimated energy loss reductions
through post-processing the marginal loss component of the locational
marginal prices in PROMOD simulation results.\339\
---------------------------------------------------------------------------

    \337\ PROMOD is a generator and portfolio modeling system.
https://www.hitachienergy.com/us/en/offering/product-and-system/energy-planning-trading/market-analysis/promod.
    \338\ ATC explains that the marginal loss component for
transmitting internal generation to load is the marginal loss charge
differential between load and generation, and the loss refund
returns half of that amount. ATC, Planning Analysis of the Paddock-
Rockdale Project, Docket No. 137-CE-149, app. C, Ex. 1, at 34-38
(Wisc. Pub. Serv. Comm'n Apr. 5, 2007).
    \339\ SPP, Regional Cost Allocation Review (RCAR II), at 5 (July
11, 2016), https://www.spp.org/documents/46235/rcar%202%20report%20final.pdf.
---------------------------------------------------------------------------

    205. Another set of potential benefits of regional transmission
infrastructure is benefits related to reduced congestion due to
transmission outages, which we describe as reduced production costs
resulting from avoided congestion during transmission outages. Such
benefits include reduced production costs during transmission outages
that significantly increase transmission congestion. Production cost
simulations typically consider planned generation outages and, in most
cases, a random distribution of unplanned generation outages. In
contrast, they do not generally reflect transmission outages, planned
or unplanned.\340\ Public utility transmission providers could measure
this benefit, for example, by either building a data set of a
normalized outage schedule (not including extreme events) that can be
introduced into simulations or by inducing system constraints more
frequently. In its RCAR process, SPP measured the benefits of reducing
congestion resulting from transmission outages. There, SPP modeled
outage events and new constraints based on these outages in PROMOD for
a 2025 case year, and then conducted PROMOD simulations to calculate
adjusted production cost savings for a base case and the change case
including the transmission line.\341\ In another example, SPP
calculated the financial value of reducing congestion caused by outages
based on a rerun of its entire day-ahead and real-time market.
---------------------------------------------------------------------------

    \340\ Brattle-Grid Strategies Oct. 2021 Report at 79.
    \341\ SPP, Regional Cost Allocation Review (RCAR II), at 51-52.
To estimate incremental savings associated with mitigation of
transmission outage costs, SPP analyzed outage cases in PROMOD for
the 2025 study year. SPP developed cases based on 12 months of
historical SPP transmission data. SPP said that because of the high
volume of historical transmission outage data (approximately 7,000
outage events) and based on the expectation that many outages would
not lead to significant increases in congestion, SPP only modeled a
subset of outage events. The events selected were those expected to
create significant congestion and met at least one of three
conditions. Id. at 51.
---------------------------------------------------------------------------

    206. Another set of potential benefits of regional transmission
infrastructure is benefits related to mitigation of extreme events and
system contingencies, which we describe as reductions in production
costs resulting from reduced high-cost generation and emergency
procurements necessary to support the transmission system during
extreme events (such as unusual weather conditions, fuel shortages, or
multiple or sustained generation and transmission outages) and system
contingencies. These benefits include reduced production costs during
extreme events facilitated by a more robust transmission system that
reduces high-cost generation and emergency procurements necessary to
support the system.
    207. Public utility transmission providers can measure benefits
from the mitigation of extreme events and system contingencies by
calculating the probability-weighted production cost savings through
production cost simulation for a set of extreme historical market
conditions. One example is CAISO's analysis of Devers-Palo Verde Line
No. 2 (PVD2), where CAISO modeled several contingencies to determine
the value of the line during high-impact, low-probability events.\342\
Another example is ATC's production cost simulation analysis of
insurance benefits for the ATC Paddock-Rockdale transmission line. ATC
found that probability-weighted savings from reducing production and
power purchase costs during a number of simulated extreme events offset
20% of total project costs.\343\ Finally, a Grid Strategies study found
development of an additional 1,000 MW of transmission capacity into
Texas would have fully paid for itself over four days during Winter
Storm Uri and the same into MISO would have saved $100 million during
the same time period.\344\
---------------------------------------------------------------------------

    \342\ Opinion Granting Certificate of Public Convenience and
Necessity, In the Matter of the Application of Southern California
Edison Company (U 338-E) for a Certificate of Public Convenience and
Necessity Concerning the Devers-Palo Verde No. 2 Transmission Line
Project, Application 05-04-015 (Cal. Comm'n Jan. 27, 2007).
    \343\ ATC, Planning Analysis of the Paddock-Rockdale Project,
Docket No. 137-CE-149, app. C, Ex. 1, at 4, 50-53 (Wisc. Pub. Serv.
Comm'n Apr. 5, 2007).
    \344\ M. Goggin, Grid Strategies, LLC, Transmission Makes the
Power System Resilient to Extreme Weather (July 2020).
---------------------------------------------------------------------------

    208. Another set of potential benefits of regional transmission
infrastructure is benefits related to mitigation of weather and load
uncertainty, which we describe as reduced production costs during
higher-than-normal load conditions or significant shifts in regional
weather patterns. This is beyond the effects of extreme weather
described above and may account for, for example, regional and sub-
regional load variances that will occur due to changing weather
patterns. This ignores the potential benefit of transmission expansions
under more normal system operating conditions, such as when the system
experiences higher-than-normal load conditions or significant shifts in

regional weather patterns that change the relative power consumption
levels across multiple regions or sub-regions.
    209. One example of the mitigation of weather and load uncertainty
benefits is the simulations that ERCOT performed for normal loads,
higher-than-normal loads, and lower-than-normal loads for a Houston
import project, which showed increased benefits with a probability-
weighted average for all three simulated load conditions.\345\ To
measure this benefit, production cost model inputs under high and low
load conditions can be used to develop regional variations of relative
benefits under these conditions. Production cost benefits can then be
modeled based upon a probability weighted average anticipating varying
load conditions, with the increment over a base case representing
additional production cost savings.
---------------------------------------------------------------------------

    \345\ ERCOT, Economic Planning Criteria: Question 1: 1/7/2011
Joint CMWG/PLWG Meeting, at 10 (Mar. 4, 2011). The $57.8 million
probability-weighted estimate is calculated based on ERCOT's
simulation results for three load scenarios and Luminant Energy
estimated probabilities for the same scenarios.
---------------------------------------------------------------------------

    210. Another set of potential benefits of regional transmission
infrastructure is capacity cost benefits related to reduced peak energy
losses, which we describe as reduced generation capacity investment
needed to meet peak load.
    211. Capacity cost savings from reduced peak energy losses benefits
refer to the ability of proposed transmission facilities to lessen the
amount of transmission system energy losses during peak-load conditions
which, over time, would decrease the need for new generation capacity
installations or purchases. To the extent that new transmission
facilities result in changes to generation dispatch and flows,
transmission system energy losses will also change. If transmission
system losses are reduced via the new transmission facilities, public
utility transmission providers will not have to construct or procure
additional generation to satisfy installed capacity requirements for
peak-load conditions. If there is a reduction in energy losses during
peak conditions, this would result in, presumably, lowered investments
for generation capacity resources to meet the peak load. For example,
Entergy found that potential transmission facilities in its footprint
could reduce peak-load transmission losses and associated needed
generation investment by 2% of total transmission facility costs.\346\
We note that capacity cost savings from reduced peak energy losses only
attempt to evaluate benefits for peak-load conditions.
---------------------------------------------------------------------------

    \346\ ITC Holdings Co., Joint Application, Docket No. EC12-145-
000, at Ex. ITC-600, 77-78 (Test. of Pfeifenberger) (filed Sept. 24,
2012).
---------------------------------------------------------------------------

    212. One potential way to calculate capacity cost savings from
reduced peak energy losses is to calculate the present value of capital
cost savings associated with the reduction in installed generation
requirements.\347\ To arrive at the value of capital cost savings
associated with these savings, the estimated net cost of new entry (Net
CONE) (i.e., the cost of new peaking generating capacity net of
operating margins earned in energy and ancillary services markets when
the region is resource constrained) would be multiplied by the
reduction in installed generation capacity requirements. The resulting
value would represent the avoided cost of procuring more generation to
cover transmission system losses during peak-load conditions that would
be passed on to consumers via lowered generation capacity costs.
---------------------------------------------------------------------------

    \347\ Id.
---------------------------------------------------------------------------

    213. Another set of potential benefits of regional transmission
infrastructure is benefits related to deferred generation capacity
investments, which we describe as reduced costs of needed generation
capacity investments realized through expanded import capability into
resource-constrained areas.
    214. Deferred generation capacity investments benefits reflect the
value of increased transfer capability, provided by new transmission
facilities, that either defers or negates the need to invest in
generation capacity resources within a transmission planning region by
increasing import capability from neighboring regions into resource-
constrained areas. By expanding the transmission system's capacity to
deliver energy to load centers, public utility transmission providers
may avoid additional generation capacity investments closer to load
centers. We note, for example, an ITC study examining transmission
facilities between the eastern, non-ERCOT region of Texas that can
import energy from Arkansas and Louisiana. The study highlighted that,
by enabling imports of surplus energy from Arkansas and Louisiana,
additional generation capacity investments were not needed in the
eastern, non-ERCOT region of Texas.\348\
---------------------------------------------------------------------------

    \348\ Id. at 58-59.
---------------------------------------------------------------------------

    215. One potential manner of calculating deferred generation
capacity investments is to calculate the present value of generation
capacity cost savings resulting from deferred generation investments,
based on Net CONE. Specifically, the total value of deferred generation
investments could be determined by multiplying the change in the public
utility transmission provider's installed capacity requirement by Net
CONE. The value of deferred generation capacity investments would
ultimately benefit consumers through lower generation capacity costs.
    216. Another set of potential benefits of regional transmission
infrastructure is benefits related to access to lower-cost generation,
which we describe as reduced total cost of needed generation due to the
ability to locate generating units in a more economically efficient
location (e.g., low permitting costs, low-cost sites on which plants
can be built, access to existing infrastructure, low labor costs, low
fuel costs, access to valuable natural resources). In other words, this
refers to the value of savings that may accrue to consumers who,
because of a new regional transmission facility or portfolio of
facilities, are able to access lower cost generation resources that
they would have been unable to otherwise. For example, if the new
regional transmission facilities extend to generation located farther
from load centers that may be lower-cost compared to generation located
closer to load centers that may be higher-priced, the new regional
transmission facilities will provide savings to consumers via increased
access lower-cost generation. We note, for example, that CAISO found
that its proposed PVD2 transmission project, which provided an
additional link between Arizona and California, permitted CAISO to meet
reliability requirements through imports of lower-cost, new generation
in Arizona.\349\
---------------------------------------------------------------------------

    \349\ Opinion Granting Certificate of Public Convenience and
Necessity, In the Matter of the Application of Southern California
Edison Company (U 338-E) for a Certificate of Public Convenience and
Necessity Concerning the Devers-Palo Verde No. 2 Transmission Line
Project, Application 05-04-015 (Cal. Comm'n Jan. 27, 2007).
---------------------------------------------------------------------------

    217. One potential way to calculate benefits from access to lower-
cost generation enabled by a regional transmission facility or
portfolio of facilities would be calculating them akin to how
production cost savings are calculated. Specifically, public utility
transmission providers could calculate the reduction in total
generation investment costs by comparing the status quo (i.e., higher-
cost local generation) to a future (i.e., lower-cost distant
generation) where the proposed new regional transmission facilities
allow for the import of those lower-cost generation. By allowing for
the import of lower-cost generation, consumers

would benefit via reduced total cost of generation.
    218. While we acknowledge calculating benefits from access to
lower-cost generation may be similar to methodologies for calculating
production cost savings, we believe that calculating production cost
savings using traditionally used methodologies would not adequately
capture benefits associated with capacity cost savings. Such
methodologies do not account for capacity cost savings since they do
not consider load variances during hotter or colder than normal weather
conditions; do not consider transmission system outages or other
situations where less than the full transfer capability of the
transmission facility is available; do not consider extreme events like
multiple generator outages; and do not capture ``real-world''
operational issues such as forecasting errors or unexpected loop
flows.\350\ Additionally, we believe that calculating access to lower-
cost generation benefits, as Brattle Group explains, may require
additional or separate analysis by public utility transmission
providers since accurately capturing the aforementioned benefits may
require a different generation mix than specified in the production
cost simulations between the Base Case (e.g., with generation located
in lower-quality or higher-cost locations) and the Change Case (e.g.,
with more generation located in higher-quality or lower-cost
locations).\351\
---------------------------------------------------------------------------

    \350\ TC Holdings, Joint Application, Docket No. EC12-145-000,
Ex. No. ITC-600, at 54-55 (filed Sept. 24, 2012) (Pfeifenberger,
Direct Testimony on behalf of ITC Holdings).
    \351\ Brattle-Grid Strategies Oct. 2021 Report at 46-47.
---------------------------------------------------------------------------

    219. Another set of potential benefits of regional transmission
infrastructure is benefits related to increased competition. We
describe increased competition as reduced bid prices in wholesale
electricity markets due to increased competition among generators and
reduced overall market concentration. Regional transmission facilities
can increase competition in, and the liquidity of, wholesale electric
power markets by increasing the number of wholesale electricity
suppliers that are able to compete to supply electricity at locations
in the transmission network served by the transmission facility,\352\
which helps to ensure just and reasonable Commission-jurisdictional
rates.
---------------------------------------------------------------------------

    \352\ F.A. Wolak, Managing Unilateral Market Power in
Electricity, Policy Research Working Paper; No. 3691. World Bank,
Washington, DC, at 8 (2005).
---------------------------------------------------------------------------

    220. More specifically, to the extent that certain portions of a
transmission planning region remain import-constrained, such that a
single resource, or even a small number of resources, can have an
outsized influence on the price of energy paid by load by increasing
the price in their offer to sell energy, additional transmission
capacity may reduce such influence, and thereby create benefits to
transmission customers in the form of reduced energy prices.
    221. Some public utility transmission providers have considered
this benefit for certain transmission facilities. For example, CAISO
evaluated the PVD2 and Path 26 Upgrade projects, and ATC evaluated its
Paddock-Rockdale project, for increased competition benefits.\353\ We
highlight three possible methods to calculate increased competition
benefits, all of which ATC employed in evaluating the benefits of the
Paddock-Rockdale Project, as examples of how public utility
transmission providers could calculate this benefit. The first two
methods that ATC employed are similar in that ATC estimated the change
in a measure of market concentration (i.e., the extent to which the
largest supplier is pivotal)--called the Residual Supplier Index
\354\--which assumes a certain percentage of load is subject to market-
based pricing, and measured the subsequent effect on generators'
ability to offer above their marginal costs (measured as a price-cost
markup) and related energy prices. ATC calculated the change in the
Residual Supplier Index using an assumed change in import capability to
the area served by the new transmission facility.
---------------------------------------------------------------------------

    \353\ Opinion Granting Certificate of Public Convenience and
Necessity, In the Matter of the Application of Southern California
Edison Company (U 338-E) for a Certificate of Public Convenience and
Necessity Concerning the Devers-Palo Verde No. 2 Transmission Line
Project, Application 05-04-015 (Cal. Comm'n Jan. 27, 2007); CAISO,
Transmission Economic Assessment Methodology, Chapter 4 (Jun. 2004);
ATC, Planning Analysis of the Paddock-Rockdale Project, at 44-49
(Apr. 5, 2007).
    \354\ The Residual Supplier Index is calculated as the ratio of
residual supply (i.e., total supply minus the capacity of the
largest supplier in the market) to the total demand. If the Residual
Supplier Index is less than 1.0, it means the largest supplier is
``pivotal,'' meaning that a load cannot be served without the
largest supplier making available at least some of its capacity.
With inelastic demand, a pivotal supplier theoretically would be
able to set the market price at any desired level above the
competitive price. See von der Fehr, Nils-Henrik & David Harbord,
Spot Market Competition in the UK Electricity Industry, Economic
Journal, at 103, 531-46 (1993); ATC, Planning Analysis of the
Paddock-Rockdale Project, Docket No. 137-CE-149, app. C, Ex. 1, at
44 & n.11 (Wisc. Pub. Serv. Comm'n Apr. 5, 2007).
---------------------------------------------------------------------------

    222. The first method ATC employed to calculate the increased
competition benefit, called the ``Modified MISO IMM Method,'' draws
from two key assumptions to determine price mark-ups. First, the
Modified MISO IMM Method requires an estimate of the pivotal supplier's
price-cost markup for the area served by the transmission facility for
all times when the supplier is pivotal.\355\ Second, this method
assumes that the price-cost markup increases linearly as the Residual
Supplier Index falls below 1.2,\356\ such that there is no price-cost
markup where the Residual Supplier Index for an hour is above 1.2
(i.e., no improved competition benefit) and the price markup is half
the estimated price-cost markup from the first assumption where the
Residual Supplier Index for an hour is less than 1.0. Finally, this
method assumes that the pivotal supplier is the marginal resource that
sets the energy price when the Residual Supplier Index is below 1.2.
The difference in price-cost markup for hours when the Residual
Supplier Index is below 1.2 provides the benefits from increased
competition.
---------------------------------------------------------------------------

    \355\ In the case of the Paddock-Rockdale Project, the MISO
independent market monitor had designated the area as a ``Narrow
Constrained Area'' and estimated that, whenever a resource became
pivotal in that area its offer would exceed its marginal costs by up
to $36/MWh. While the MISO independent market monitor provided such
an estimate for the Paddock-Rockdale Project, we do not suggest that
any specific entity conduct the necessary study deriving this
estimate (e.g., the public utility transmission providers in a
transmission planning region could also conduct such a study).
    \356\ This assumption is based on a study analyzing summer 2000
peak hourly data from the California Power Exchange. Sheffrin, A.,
(2002), ``Predicting Market Power Using the Residual Supplier
Index,'' Mimeo, Department of Market Analysis, CAISO.
---------------------------------------------------------------------------

    223. The second potential method to calculate increased competition
benefits that ATC employed, the ``Modified CAISO Method,'' estimates
the energy price impacts of a new transmission facility by using
regression analysis to find the relationship between historical market
structure and price-bid markups. CAISO first developed this regression
equation and its coefficients in its 2004 report evaluating the
economic viability of certain transmission upgrades, including the PVD2
and Path 26 Upgrade projects.357 CAISO's study also used two binary
indicator variables: One for the summer period in CAISO and another for
peak hours. We note that public utility transmission providers using
the Modified CAISO approach may find that coefficients developed using
data specific to the transmission planning region where the public
utility transmission provider is located are more appropriate and may
also wish to include more independent variables specific to their
respective transmission planning regions.

    224. The third potential method to calculate increased competition
benefits, the ``Bidding Behavior Method,'' relies on a simulation model
that optimizes bidding behavior from a supplier perspective given each
supplier's supply portfolio and load obligations. This model could be
based on the theoretical incentive that suppliers have to increase
price-cost markups in proportion to the absolute value of the slope of
residual demand (i.e., total demand less the supply of all other
resources serving the same load).\358\ Public utility transmission
providers in a transmission planning region would develop a study
estimating market prices for a future period matching the planning
horizon as load, generation supply, transmission constraints, and
import capability changed. Public utility transmission providers in a
transmission planning region would also assume that a percentage of
load was exposed to congestion.
---------------------------------------------------------------------------

    \358\ See, e.g., F.A. Wolak, Measuring the competitiveness
benefits of a transmission investment policy: The case of the
Alberta electricity market 86 Energy Policy 426-444 (June 2015); N.
Ryan, The Competitive Effects of Transmission Infrastructure in the
Indian Electricity Market, 13 American Economic Journal:
Microeconomic 2, 202-42 (May 2021).
---------------------------------------------------------------------------

    225. Finally, another set of potential benefits of regional
transmission infrastructure is benefits related to increased market
liquidity. We describe increased market liquidity as enabling a larger
number of entities, both buyers and sellers, to participate in a
market. By increasing the number of market participants, both buyers
and sellers, transmission facilities may provide benefits through
reduced transaction costs (e.g., bid-ask spreads) of bilateral
transactions, increased pricing transparency, increased efficiency of
risk management, improved contracting, and better clarity for long-term
transmission planning and investment decisions.\359\ The primary
increased market liquidity benefit to transmission customers is the
decrease in energy prices. For example, bid-ask spreads for bilateral
trades at less liquid hubs have been found to be between $0.50 to
$1.50/MWh higher than the bid-ask spreads at more liquid hubs.\360\
Public utility transmission providers could quantify increased market
liquidity benefits to transmission customers by estimating (1) how
additional transmission facilities may increase liquidity and (2) how
increased liquidity may reduce bid-asks spreads or energy prices.
---------------------------------------------------------------------------

    \359\ Brattle-Grid Strategies Oct. 2021 Report at 50.
    \360\ Id.
---------------------------------------------------------------------------

(b) Evaluation of Transmission Benefits Over Longer Time Horizon
(1) Comments
    226. Several commenters responding to the ANOPR recommend that the
Commission allow or require public utility transmission providers to
evaluate the benefits of transmission facilities over a longer time
horizon.\361\ For example, ACPA and ESA argue that proper economic
analysis entails an analysis of the benefits of a proposed transmission
facility over the asset's life, which is at least 40 years for
transmission lines.\362\ Other commenters, however, raise concerns with
attempts to forecast future transmission system conditions in order to
consider potential benefits on a longer time horizon.\363\ For example,
Xcel argues that planning for the future is inherently uncertain, and
that the benefits of transmission facilities can change over time.\364\
---------------------------------------------------------------------------

    \361\ See, e.g., NYISO Comments at 34-37 (stating that NYISO
limits consideration of benefits to 10 years and recommending that
the Commission grant public utility transmission providers
discretion to plan for up to 20 years of needs and benefits); see
also NextEra Comments at 79-80 (recommending a similar length of
time for consideration of benefits as for scenario planning); see
also February Joint Task Force Tr 20:23-25 (Clifford Rechtschaffen)
(arguing that the Commission should extend the timeframe over which
benefits are calculated to be 15-20 years or longer), 24:4-8
(Matthew Allen) (advocating for recognizing benefits over at least a
20-year timeframe given the long life of transmission assets).
    \362\ ACPA and ESA Comments at 44-45; see also PIOs Comments at
121-122.
    \363\ Entergy Comments at 10-11; see also EEI Comments at 30-31
(arguing for maintaining the Commission's policies on abandoned
plant recovery because of the additional uncertainty inherent in
longer-term transmission planning); Minnesota Commerce Comments at 3
(stating that future uncertainty is compounded by the rapid pace of
technological change).
    \364\ Xcel Comments at 20 n.52.
---------------------------------------------------------------------------

(2) Proposed Reform
    227. We propose to require that public utility transmission
providers in each transmission planning region evaluate, as part of
Long-Term Regional Transmission Planning, the benefits of regional
transmission facilities over a time horizon that covers, at a minimum,
20 years starting from the estimated in-service date of the
transmission facilities. For example, if Long-Term Regional
Transmission Planning identifies transmission facilities that are
estimated to be in-service in year 10 of the 20-year long-term
transmission planning horizon, then the estimate of benefits for those
same transmission facilities will commence at year 10 and cover an
additional 20 years. We believe that 20 years may strike an appropriate
balance that reasonably illustrates the benefits a transmission
facility is likely to provide over its useful life, which can exceed 40
years, while recognizing the inherent difficulties in attempting to
predict system conditions too far into the future. Moreover, we note
that some public utility transmission providers currently conduct long-
term transmission planning over a 20-year horizon, and thus have some
experience with modelling and making assumptions over this period,
though such modelling is typically for informational purposes and not
to select transmission facilities in the regional transmission plan for
purposes of cost allocation.\365\
---------------------------------------------------------------------------

    \365\ See MISO, LRTP Business Case, Long Range Transmission
Planning Workshop, at slide 7 (Jan. 21, 2022, Revised Feb. 2, 2022),
https://cdn.misoenergy.org/20220121%20LRTP%20Workshop%20Item%2004%20Business%20Case%20Presentation619895.pdf; CAISO, 20-Year Transmission Outlook (Draft Jan. 31,
2022), https://www.caiso.com/InitiativeDocuments/Draft20-YearTransmissionOutlook.pdf; SPP Engineering, 2021 SPP Transmission
Expansion Plan Report (Jan. 11, 2021), https://spp.org/documents/56611/2021%20step%20report.pdf.
---------------------------------------------------------------------------

    228. We propose to require that public utility transmission
providers evaluate benefits over this time horizon in all stages of
Long-Term Regional Transmission Planning, which includes evaluating
regional transmission facilities, selecting more efficient or cost-
effective regional transmission facilities in the regional transmission
plan for purposes of cost allocation, and allocating the costs of such
transmission facilities in a manner that is at least roughly
commensurate with estimated benefits. We also note that for consistency
and a matching comparison of benefits and costs over time, to the
extent that public utility transmission providers estimate the costs of
transmission facilities beyond the in-service date of the transmission
facilities, we propose that they should estimate those future costs
over the same time horizon as the estimated benefits.
    229. Finally, while we propose to establish a minimum requirement
for the time horizon over which benefits must be evaluated, we clarify
that public utility transmission providers may propose approaches that
exceed this minimum requirement. In particular, while we believe that
20 years may strike a reasonable balance, we also believe that a time
horizon longer than 20 years for the evaluation of benefits may be
consistent with the long life of transmission facilities--

which generally exceeds 20 years by a substantial margin--and also
consistent with the fact that transmission facilities provide
significant benefits over their entire useful life.\366\ To the extent
public utility transmission providers would like to evaluate
transmission benefits beyond the proposed minimum time horizon, we
propose to require that they demonstrate that their proposal is
consistent with or superior to any final rule in this proceeding.
---------------------------------------------------------------------------

    \366\ ACPA and ESA Comments at 44-45; see also WIRES Comments at
7-8 (recommending accounting for benefits of transmission facilities
over their useful lives).
---------------------------------------------------------------------------

    230. We seek comment on the requirements proposed in this section
of the NOPR.
(c) Evaluation of the Benefits of Portfolios of Transmission Facilities
    231. In the ANOPR, the Commission sought comment on whether public
utility transmission providers would identify more efficient or cost-
effective transmission facilities in their regional transmission
planning processes if they evaluated the benefits of a portfolio of
transmission facilities collectively rather than individual
transmission facilities separately.\367\
---------------------------------------------------------------------------

    \367\ ANOPR, 176 FERC ] 61,024 at PP 53, 89, 91.
---------------------------------------------------------------------------

(1) Comments
    232. Many commenters recommend that the Commission permit or
require public utility transmission providers to use a portfolio
approach when evaluating the benefits of transmission facilities.\368\
Under such an approach, public utility transmission providers would
evaluate multiple transmission facilities in an aggregated, integrated
fashion rather than doing so on a facility-by-facility basis. For
example, U.S. DOE argues that a portfolio approach is more likely to
result in an accurate evaluation of the benefits of transmission
facilities than would an approach requiring evaluation of each facility
individually,\369\ while PIOs claim that facility-by-facility rather
than portfolio-based evaluation underestimates the benefits of regional
transmission facilities.\370\ Other commenters explain that public
utility transmission providers could achieve administrative
efficiencies using a portfolio approach, which can help avoid the
necessity of running the same analyses on each facility.\371\
---------------------------------------------------------------------------

    \368\ ITC Comments at 11; State Agencies Comments at 21; ELCON
Reply Comments at 3-4; see also Southern Comments at 13-14 (stating
that vertically-integrated utilities already use a portfolio
approach).
    \369\ U.S. DOE Comments at 40-41.
    \370\ PIOs Comments at 50-51.
    \371\ ACEG Reply Comments at 5, 8; ITC Comments at 6, 11, 28.
---------------------------------------------------------------------------

(2) Proposed Reform
    233. We propose to afford public utility transmission providers in
each transmission planning region the flexibility to propose to use a
portfolio approach in the evaluation of benefits of regional
transmission facilities through their Long-Term Regional Transmission
Planning. Evaluating the benefits of a portfolio of regional
transmission facilities appears to contain several advantages compared
to evaluating the benefits of each proposed regional transmission
facility individually. Several commenters explain that future benefits
may be more stable or evenly distributed over time if they are
evaluated for a portfolio of transmission facilities.\372\ These
comments are consistent with the fact that benefits from transmission
facilities may change over time due to the inherent uncertainty in
Long-Term Regional Transmission Planning and actual use of transmission
facilities. An example of the evaluation of expanded benefits for a
portfolio of transmission facilities is the MISO MVP Portfolio, which
is a collection of 17 distinct transmission facilities, for which MISO
evaluated a collective distribution of benefits.\373\ Given the suite
of minimum benefits proposed above, we believe that evaluating these
benefits across a portfolio of transmission facilities as opposed to
each individual transmission facility may result in significant
administrative efficiencies for public utility transmission providers.
Moreover, we believe that a more stable or even distribution of
benefits from a portfolio of transmission facilities may also
facilitate agreement on regional cost allocation that is at least
roughly commensurate with estimated benefits.
---------------------------------------------------------------------------

    \372\ U.S. DOE Comments at 40-41; see also February Joint Task
Force Tr 24:15-22 (Matthew Allen) (stating his belief that
transmission planners should be looking at projects and benefits on
a portfolio basis to identify synergies).
    \373\ MISO, Multi Value Project Portfolio Results and Analyses
at 1-6 (2012), https://cdn.misoenergy.org/2011%20MVP%20Portfolio%20Analysis%20Full%20Report117059.pdf.
---------------------------------------------------------------------------

    234. Accordingly, we encourage this practice by public utility
transmission providers. We clarify that public utility transmission
providers that propose such an approach must include in their OATTs
provisions describing how they would analyze the benefits of regional
transmission facilities under a portfolio approach and whether the
portfolio approach would be used for Long-Term Regional Transmission
Planning universally to address transmission needs driven by changes in
the resource mix and demand or would be used only in certain specified
instances.
    235. We recognize that a variety of commenters request that we
require the use of a portfolio approach. While we recognize the
advantages to a portfolio approach, we also acknowledge that the
transition to a portfolio approach may represent a significant change
for many public utility transmission providers and that the potential
benefits may not warrant such a change in all instances.\374\ We seek
comment as to whether there are certain circumstances for which the
Commission should require the use of a portfolio approach.
---------------------------------------------------------------------------

    \374\ See, e.g., February Joint Task Force Tr. 76:10-12
(Kimberly Duffley) (asking that the Commission recognize regional
differences that may result in portfolio projects working for one
region but not for all regions).
---------------------------------------------------------------------------

iv. Selection of Regional Transmission Facilities
    236. Order No. 1000 requires public utility transmission providers
to include in their OATTs a transparent and not unduly discriminatory
process for evaluating whether to select a proposed regional
transmission facility in the regional transmission plan for purposes of
cost allocation.\375\ Order No. 1000 does not mandate that public
utility transmission providers select any transmission facility,\376\
and the Commission declined for the most part to set minimum standards
for the criteria used to select a transmission facility in a regional
transmission plan for purposes of cost allocation. However, the
Commission required that a public utility transmission provider's
selection criteria be transparent and not unduly discriminatory.\377\
---------------------------------------------------------------------------

    \375\ Order No. 1000, 136 FERC ] 61,051 at PP 328-331; Order No.
1000-A, 139 FERC ] 61,132 at P 452.
    \376\ Order No. 1000, 136 FERC ] 61,051 at P 331.
    \377\ See Order No. 1000-A, 139 FERC ] 61,132 at P 455.
---------------------------------------------------------------------------

    237. In the ANOPR, the Commission sought comment on whether and how
public utility transmission providers should use information developed
through long-term scenario planning to identify and select transmission
facilities that meet future needs. In addition, the Commission sought
comment on how public utility transmission providers should evaluate
the benefits of proposed transmission facilities in their regional
transmission planning processes, and whether the maximization of net
benefits is an appropriate criterion for selecting transmission
facilities in the regional transmission plan for purposes of cost

allocation.\378\ Finally, the Commission sought comment on whether
public utility transmission providers would select more efficient or
cost-effective transmission facilities in their regional transmission
planning processes if they selected a portfolio of transmission
facilities collectively.\379\
---------------------------------------------------------------------------

    \378\ ANOPR, 176 FERC ] 61,024 at P 53.
    \379\ See id. PP 89, 91.
---------------------------------------------------------------------------

(a) Comments
    238. With respect to the selection of transmission facilities in a
regional transmission plan for purposes of cost allocation, commenters
responding to the ANOPR provided a wide range of feedback. Several
commenters emphasize that scenario planning should ensure the selection
of more efficient or cost-effective transmission facilities,\380\ while
others argue that scenario planning should be solely for informational
purposes.\381\ Certain commenters believe that Commission guidance on
selection criteria is essential,\382\ while others argue that the
Commission instead should provide flexibility for public utility
transmission providers to adopt selection criteria.\383\
---------------------------------------------------------------------------

    \380\ AEP Comments at 10; Ameren Reply Comments at 3; see also
Anbaric Comments at 32 (recommending that the Commission impose
deadlines to ensure that transmission planning processes select
offshore wind transmission facilities rather than allowing results
to ``languish in protracted stakeholder processes''); AEE Reply
Comments at 7-8 (requesting the adoption of transparency and
enforcement mechanisms that would ensure the selection of
transmission facilities that meet regional needs).
    \381\ See PJM Comments at 44 (stating that PJM's proposed long-
term transmission planning process will ``inform stakeholder
discussions''); see also Xcel Energy Comments at 20 (``The
Commission should not require all issues identified in the holistic
planning process to result in planned projects.'').
    \382\ PJM Comments at 46; see also City of New York Comments at
11 (arguing that the Commission should adopt common project
selection criteria); Policy Integrity Comments at 17 (recommending
greater uniformity in selection criteria); Massachusetts Attorney
General Comments at 25 (arguing that consumer protection requires
that selection criteria be ``clear, real, and objective'').
    \383\ MISO Comments at 32; National Grid Comments at 14-15;
American Municipal Power Comments at 15.
---------------------------------------------------------------------------

    239. Many commenters also recommend that the Commission permit or
require public utility transmission providers to use a portfolio
approach when selecting transmission facilities.\384\ U.S. DOE explains
that the benefits of individual transmission facilities typically are
distributed unevenly across a region, whereas portfolios of
transmission facilities generally would be expected to confer benefits
more broadly and evenly.\385\
---------------------------------------------------------------------------

    \384\ ITC Comments at 9, 11, 33; NARUC Comments at 12; PIOs
Comments at 50-51; State Agencies Comments at 21; AEP Reply Comments
at 33; ELCON Reply Comments at 3-4; see also Southern Comments at
13-14 (stating that vertically-integrated utilities already use a
portfolio approach).
    \385\ U.S. DOE Comments at 40-41.
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    240. With respect to specific selection criteria or methods,
several commenters support an approach that would select transmission
facilities with the highest level of net benefits instead of facilities
with the highest benefit-cost ratio,\386\ whereas other commenters
support maintaining the maximum 1.25 benefit-cost ratio permitted by
Order No. 1000.\387\ Other commenters recommend a ``least-regrets''
approach to selecting transmission facilities, in which public utility
transmission providers would select a transmission facility identified
through scenario planning as beneficial across many or all
scenarios.\388\
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    \386\ ITC Comments at 11; ACEG Comments at 5-6; Policy Integrity
Comments at 44-46; AEP Comments at 16.
    \387\ NARUC Comments at 12, 22-24 (advocating for maximizing
benefit-cost ratio and retaining the benefit-cost ratio permitted by
Order No. 1000); Entergy Comments at 18 (asking the Commission to
retain the ability to have a benefit-cost ratio up to 1.25);
Mississippi Commission Comments at 13-14 (arguing for a strict
benefit-cost ratio of no less than 1.25 for economic projects with
the possibility of a higher benefit-cost ratio for specific
projects); Entergy Reply Comments at 12-13 (asserting that a higher
benefit-cost ratio may be appropriate for a longer-term planning
horizon).
    \388\ National Grid Comments at 16; American Municipal Power
Comments at 32; PIOs Comments at 79; Chamber of Commerce Comments at
4; WIRES Comments at 7-8; AEP Comments at 9-10.
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(b) Proposed Reform
    241. We propose to require that public utility transmission
providers, as part of the Long-Term Regional Transmission Planning that
we propose to require in this NOPR, include in their OATTs: (1)
Transparent and not unduly discriminatory criteria, which seek to
maximize benefits to consumers over time without over-building
transmission facilities, to identify and evaluate transmission
facilities for potential selection in the regional transmission plan
for purposes of cost allocation that address transmission needs driven
by changes in the resource mix and demand, consistent with the
discussion below; and (2) a process to coordinate with the relevant
state entities in developing such criteria.
    242. Subject to certain minimum requirements, we propose to provide
public utility transmission providers the flexibility to propose the
selection criteria that they, in consultation with their stakeholders,
believe will ensure that more efficient or cost-effective regional
transmission facilities to address the region's transmission needs
driven by changes in the resource mix and demand ultimately are
selected in the regional transmission plan for purposes of cost
allocation. As stated in Order No. 1000, to comply with Order Nos. 890
and 1000 transmission planning principles, the evaluation process must
result in a determination that is sufficiently detailed for
stakeholders to understand why a particular transmission project was
selected or not selected in the regional transmission plan for purposes
of cost allocation to address transmission needs driven by changes in
the resource mix and demand.\389\ Further, we propose that the
evaluation process and, specifically, the selection criteria must seek
to maximize benefits to consumers over time without over-building
transmission facilities.
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    \389\ Order No. 1000, 136 FERC ] 61,051 at P 328.
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    243. We believe that this proposed flexibility would help
accommodate the regional differences described in comments in response
to the ANOPR, such as the different transmission needs each
transmission planning region may have, the factors driving those needs,
or market structures. We also believe that providing flexibility to
public utility transmission providers in this regard would allow public
utility transmission providers, in consultation with their
stakeholders, to determine criteria for assessing the efficiency or
cost-effectiveness of various regional transmission facilities, whether
by reference, for example, to a benefit-cost ratio or by aggregate net
benefits.\390\
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    \390\ We do not propose to change the Order No. 1000 requirement
that public utility transmission providers may not impose a benefit-
cost ratio requirement higher than 1.25. See id. P 646.
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    244. Further, we believe this proposed flexibility would allow
public utility transmission providers in each transmission planning
region to develop selection criteria that could sufficiently balance
individual state interests within each transmission planning region. We
believe that providing an opportunity for state involvement in regional
transmission planning processes is becoming more important as states
take a more active role in shaping the resource mix and demand, which,
in turn, means that those state actions are increasingly affecting the
long-term transmission needs for which we are proposing to require
public utility transmission providers to plan in this NOPR. Given the
important role states play and the wide variety of potential approaches
to selection criteria, we propose, as part of this requirement, that
public utility transmission providers must consult with and seek
support from the relevant state entities, as defined below, within
their

transmission planning region's footprint to develop the selection
criteria. These selection criteria would be used in Long-Term Regional
Transmission Planning to evaluate a transmission facility (or a
portfolio of regional transmission facilities) for potential selection
in the regional transmission plan for purposes of cost allocation.
    245. While we propose significant flexibility in the development of
selection criteria, we believe that certain minimum requirements must
be in place for public utility transmission providers, their
stakeholders, and states. The selection criteria must be transparent
and not unduly discriminatory, and must aim to ensure that more
efficient or cost-effective transmission facilities are selected in the
regional transmission plan for purposes of cost allocation to address
transmission needs driven by changes in the resource mix and demand.
Public utility transmission providers should seek to maximize benefits
to consumers over time without over-building transmission facilities.
Public utility transmission providers should propose specific selection
criteria to achieve this balance over time. We note, as discussed
above, that regional transmission planning and cost allocation
processes generally have resulted in few regionally planned
transmission facilities being selected and ultimately built.\391\
However, the reforms proposed in this NOPR seek to better ensure that
the more efficient or cost-effective regional transmission facilities
are identified through Long-Term Regional Transmission Planning and
acknowledge commenters' concerns about over-building due to
uncertainties of future transmission system conditions.\392\ We
acknowledge the inherent uncertainty involved in predicting future
transmission needs and emphasize that we are not proposing to require
public utility transmission providers to achieve, ex post, any
particular outcome but rather to adopt an evaluation process that, ex
ante, aims to maximize consumer benefits over time without over-
building transmission facilities.
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    \391\ Supra Need For Reform: The Transmission Investment
Landscape Today (explaining in some transmission planning regions,
regional transmission investment declined after issuance of Order
No. 1000, while in other regions, regional transmission planning
processes have not resulted in the selection of a single regional