Proposed Rule2024-06556
Compensation for Reactive Power Within the Standard Power Factor Range
Primary source
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Published
March 28, 2024
Issuing agencies
Energy DepartmentFederal Energy Regulatory Commission
Abstract
The Federal Energy Regulatory Commission (Commission) proposes to revise Schedule 2 of its pro forma open-access transmission tariff (pro forma OATT), section 9.6.3 of its pro forma large generator interconnection agreement (LGIA), and section 1.8.2 of its pro forma small generator interconnection agreement (SGIA) to prohibit the inclusion in transmission rates of unjust and unreasonable charges related to the provision of reactive power within the standard power factor range by generating facilities. The Commission invites all interested persons to submit comments on the proposed reforms and in response to specific questions.
Full Text
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<title>Federal Register, Volume 89 Issue 61 (Thursday, March 28, 2024)</title>
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[Federal Register Volume 89, Number 61 (Thursday, March 28, 2024)]
[Proposed Rules]
[Pages 21454-21468]
From the Federal Register Online via the Government Publishing Office [<a href="http://www.gpo.gov">www.gpo.gov</a>]
[FR Doc No: 2024-06556]
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DEPARTMENT OF ENERGY
Federal Energy Regulatory Commission
18 CFR Part 35
[Docket No. RM22-2-000]
Compensation for Reactive Power Within the Standard Power Factor
Range
AGENCY: Federal Energy Regulatory Commission, Department of Energy.
ACTION: Notice of proposed rulemaking.
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SUMMARY: The Federal Energy Regulatory Commission (Commission) proposes
to revise Schedule 2 of its pro forma open-access transmission tariff
(pro forma OATT), section 9.6.3 of its pro forma large generator
interconnection agreement (LGIA), and section 1.8.2 of its pro forma
small generator interconnection agreement (SGIA) to prohibit the
inclusion in transmission rates of unjust and unreasonable charges
related to the provision of reactive power within the standard power
factor range by generating facilities. The Commission invites all
interested persons to submit comments on the proposed reforms and in
response to specific questions.
DATES: Comments are due May 28, 2024. Reply comments are due June 26,
2024.
ADDRESSES: Comments, identified by docket number, may be filed in the
following ways. Electronic filing through <a href="https://www.ferc.gov">https://www.ferc.gov</a> is
preferred.
<bullet> Electronic Filing: Documents must be filed in acceptable
native applications and print-to-PDF, but not in scanned or picture
format.
<bullet> For those unable to file electronically, comments may be
filed by USPS mail or by hand (including courier) delivery.
[cir] Mail via U.S. Postal Service Only: Addressed to: Federal
Energy Regulatory Commission, Secretary of the Commission, 888 First
Street NE, Washington, DC 20426.
[cir] Hand (including courier) delivery: Deliver to: Federal Energy
Regulatory Commission, 12225 Wilkins Avenue, Rockville, MD 20852.
The Comment Procedures section of this document contains more
detailed filing procedures.
FOR FURTHER INFORMATION CONTACT:
Noah Schlosser (Technical Information), Office of Energy Market
Regulation, 888 First Street NE, Washington, DC 20426, (202) 502-8356,
<a href="/cdn-cgi/l/email-protection#155b7a747d3b46767d797a6666706755737067763b727a63"><span class="__cf_email__" data-cfemail="7a34151b1254291912161509091f083a1c1f0819541d150c">[email protected]</span></a>
Jennifer Enos (Legal Information), Office of the General Counsel, 888
First Street NE, Washington, DC 20426, (202) 502-6247,
<a href="/cdn-cgi/l/email-protection#1a507f7474737c7f68345f7475695a7c7f6879347d756c"><span class="__cf_email__" data-cfemail="115b747f7f787774633f547f7e6251777463723f767e67">[email protected]</span></a>
SUPPLEMENTARY INFORMATION:
Table of Contents
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Paragraph
Nos.
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I. Introduction............................................. 1
II. Background.............................................. 10
A. What is reactive power?.............................. 10
B. How has reactive power been compensated?............. 12
C. Notice of Inquiry.................................... 20
III. Discussion............................................. 24
A. Need for Reform...................................... 24
1. Compensation for Providing Reactive Power Within the 28
Standard Power Factor Range May Be Unjust and
Unreasonable...........................................
2. Adverse Impacts of the Commission's Current Reactive 34
Power Compensation Policy..............................
B. Proposed Reform...................................... 41
1. Eliminating Separate Compensation Will Not Affect 43
Reliability............................................
2. Eliminating Separate Compensation Does Not Preclude 45
Generating Facilities From Recovering Their Costs......
C. Proposed Revisions for Eliminating Compensation for 50
Reactive Power Supply Within the Standard Power Factor
Range..................................................
1. Revise Schedule 2 of the Pro Forma OATT.............. 51
2. Revise Section 9.6.3 of the Pro Forma Large Generator 52
Interconnection Agreement..............................
3. Revise Section 1.8.2 of the Pro Forma Small Generator 53
Interconnection Agreement..............................
IV. Proposed Compliance Procedures.......................... 54
V. Information Collection Statement......................... 57
VI. Environmental Analysis.................................. 71
VII. Regulatory Flexibility Act Certification............... 72
VIII. Comment Procedures.................................... 76
IX. Document Availability................................... 79
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I. Introduction
1. The Commission is proposing to revise Schedule 2 of its pro
forma OATT to prohibit transmission providers from including in their
transmission rates any charges associated with the supply of reactive
power within the standard power factor range \1\ from generating
facilities. We further propose to remove from the pro forma LGIA and
pro forma SGIA the requirement that a transmission provider pay an
interconnection customer for reactive power within the standard power
factor range if the transmission provider pays its own or affiliated
generators for the same service. Accordingly, transmission providers
would be required to pay an interconnection customer for reactive
[[Page 21455]]
power only when the transmission provider asks the interconnection
customer to operate its facility outside the standard power factor
range set forth in its interconnection agreement.
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\1\ Operating ``inside the standard power factor range'' refers
to a generating facility providing reactive power within the power
factor range set forth in the generating facility's interconnection
agreement when the unit is online and synchronized to the
transmission system.
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2. The Commission's policy on reactive power compensation has
evolved since issuing Order No. 888 in 1996.\2\ In Order No. 888, the
Commission required that reactive supply and voltage control from
generating facilities be offered as a discrete ancillary service by
transmission providers and, to the extent feasible, charged for on the
basis of the amount required. The Commission explained that there are
two ways of supplying reactive power and controlling voltage. One is to
install facilities as part of the transmission system, the cost of
which is part of the cost of basic transmission service. The second is
to use generating facilities to supply reactive power and voltage
control, which must be unbundled from basic transmission service.
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\2\ Promoting Wholesale Competition Through Open Access Non-
Discriminatory Transmission Servs. by Pub. Utils.; Recovery of
Stranded Costs by Pub. Utils. & Transmitting Utils., Order No. 888,
61 FR 21540 (May 10, 1996), FERC Stats. & Regs. ] 31,036, at 31,705-
07 & n.359 (1996) (cross-referenced at 75 FERC ] 61,080), order on
reh'g, Order No. 888-A, 62 FR 12274 (Mar. 14, 1997), FERC Stats. &
Regs. ] 31,048 (cross-referenced at 78 FERC ] 61,220), order on
reh'g, Order No. 888-B, 81 FERC ] 61,248 (1997), order on reh'g,
Order No. 888-C, 82 FERC ] 61,046 (1998), aff'd in relevant part sub
nom. Transmission Access Pol'y Study Grp. v. FERC, 225 F.3d 667
(D.C. Cir. 2000), aff'd sub nom. N. Y. v. FERC, 535 U.S. 1 (2002).
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3. With respect to compensation, the Commission stated that the
transmission provider's ``rates for ancillary services should be cost-
based.'' \3\ The Commission expected, however, that transmission
customers would be in a position to change the amount of reactive power
service they required. The Commission also identified the possibility
that reactive power could potentially someday be supplied by ``a
competitive market for such service'' if ``technology or industry
changes'' made such a market possible.
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\3\ Id. at 31,720.
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4. Then, in Order No. 2003, the Commission specifically addressed
the circumstances and manner in which a transmission provider must pay
for reactive power, inside and outside the standard power factor range
(sometimes referred to as the ``deadband'').\4\ In Order No. 2003, the
Commission adopted a standard agreement for the interconnection of
large generating facilities (the pro forma LGIA), which included the
requirement that interconnection customers maintain a composite power
delivery at continuous rated power output at the point of
interconnection at a power factor within the range of 0.95 leading to
0.95 lagging \5\ when synchronized to the transmission system, unless
the transmission provider has established a different power factor
range. Order No. 2003 required that a transmission provider compensate
an interconnection customer for the provision of reactive power when
the transmission provider requests the interconnection customer to
operate its generating facility outside the established power factor
range. With respect to reactive power within the established power
factor range, the Commission initially concluded that the
interconnection customer should not be compensated for reactive power
when operating within the range established in the interconnection
agreement because doing so ``is only meeting [the generating
facility's] obligation.'' \6\ But in Order No. 2003-A, the Commission
clarified that ``if the Transmission Provider pays its own or its
affiliated generators for reactive power within the established range,
it must also pay the Interconnection Customer.'' \7\ This standard is
generally referred to as the comparability standard.
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\4\ Standardization of Generator Interconnection Agreements &
Procs., Order No. 2003, 68 FR 49846 (Aug. 19, 2003), 104 FERC ]
61,103, at P 546 (2003), order on reh'g, Order No. 2003-A, 69 FR
15932 (Mar. 26, 2004), 106 FERC ] 61,220, order on reh'g, Order No.
2003-B, 70 FR 265 (Jan. 4, 2005), 109 FERC ] 61,287 (2004), order on
reh'g, Order No. 2003-C, 70 FR 37661 (June 30, 2005), 111 FERC ]
61,401 (2005), aff'd sub nom. Nat'l Ass'n of Regul. Util. Comm'rs v.
FERC, 475 F.3d 1277 (D.C. Cir. 2007).
\5\ A generating facility's leading reactive power indicates its
ability to absorb reactive power and its lagging reactive power
indicates its ability to produce reactive power.
\6\ Order No. 2003, 104 FERC ] 61,103 at P 546 (``We agree that
the Interconnection Customer should not be compensated for reactive
power when operating its Generating Facility within the established
power factor range, since it is only meeting its obligation.'').
\7\ Order No. 2003-A, 106 FERC ] 61,220 at P 416. Section 9.6.3
of the pro forma LGIA provided as follows:
Transmission Provider is required to pay Interconnection
Customer for reactive power that Interconnection Customer provides
or absorbs from the Large Generating Facility when Transmission
Provider requests Interconnection Customer to operate its Large
Generating Facility outside the range specified in Article 9.6.1,
provided that if Transmission Provider pays its own or affiliated
generators for reactive power service within the specified range, it
must also pay Interconnection Customer.
Similarly, section 1.8.2 of the pro forma SGIA provided as
follows:
The Transmission Provider is required to pay the Interconnection
Customer for reactive power that the Interconnection Customer
provides or absorbs from the Small Generating Facility when the
Transmission Provider requests the Interconnection Customer to
operate its Small Generating Facility outside the range specified in
article 1.8.1. In addition, if the Transmission Provider pays its
own or affiliated generators for reactive power service within the
specified range, it must also pay the Interconnection Customer.
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5. In sum, ``Order Nos. 2003 and 2003-A establish a reactive power
compensation policy that, in the first instance, treats the provision
of reactive power inside the [standard power factor range] as an
obligation of good utility practice rather than as a compensable
service and permits compensation inside the [standard power factor
range] only as a function of comparability.'' \8\ The Commission took
this approach because, where the generating facility is operating
within the standard power factor range, it is doing no more than
meeting its obligation as a generator, as specified in its
interconnection agreement, to maintain the appropriate power factor
required to maintain voltage levels for electric power injected into
the transmission system during normal operations.\9\ By comparison,
reactive power provided outside of the standard power factor range is
considered an ancillary service for transmitting power across the
transmission system to serve load,\10\ and thus, the Commission has
required compensation for such service.
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\8\ Bonneville Power Admin. v. Puget Sound Energy, Inc., 120
FERC ] 61,211 (2007) (BPA), order denying reh'g and granting
clarification, 125 FERC ] 61,273, at P 18 (2008) (BPA Rehearing
Order).
\9\ See, e.g., Midcontinent Indep. Sys. Operator, Inc., 182 FERC
] 61,033 (MISO), order on reh'g, 184 FERC ] 61,022, at P 23 (2023)
(MISO Rehearing Order) (citing Mich. Elec. Transmission Co., 97 FERC
] 61,187, at 61,852-53 (2001) (METC)).
\10\ Id.
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6. The Commission has also recognized that there is little to no
incremental capital expenditure associated with the equipment necessary
for the production of reactive power within the standard power factor
range. That is because, for both synchronous and non-synchronous
generating facilities,\11\ the same equipment is used for the
production of real power and reactive power.\12\ In
[[Page 21456]]
addition, the Commission has noted that any purported costs associated
with such provision of reactive power can be recovered in other ways--
such as through energy or capacity sales.\13\
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\11\ Synchronous generating facilities (e.g., coal, gas, nuclear
resources) produce electricity in sync with the transmission system
at the system frequency. Non-synchronous generating facilities
(e.g., solar, wind, battery storage resources) produce electricity
that is initially not in sync with the transmission system and use
inverters to convert their electrical output to synchronize with the
transmission system. See FERC Staff Report, Payment for Reactive
Power, Docket No. AD14-7-000, 7 (Apr. 22, 2014), <a href="https://www.ferc.gov/sites/default/files/2020-05/04-11-14-reactive-power.pdf">https://www.ferc.gov/sites/default/files/2020-05/04-11-14-reactive-power.pdf</a>.
\12\ MISO Rehearing Order, 184 FERC ] 61,022 at PP 29-30 (citing
S. Co. Servs., Inc., 80 FERC ] 61,318, at 62,091 (1997) (noting also
that the primary function of a generating plant is to produce real
power; thus, if costs were allocated based on the ``predominant''
function of the equipment, ``all of the costs of generation would
thus be assigned to real power production and there would be no
basis for any separate reactive power charge''); BPA, 120 FERC ]
61,211 at P 21 (finding that the incremental cost of reactive power
service within the standard power factor range is minimal); METC, 97
FERC at 61,852-53 (``[R]eactive power provided, not as an ancillary
service, but rather as a `no cost' service within reactive design
limitations, may therefore, be provided without compensation.'').
\13\ See, e.g., MISO Rehearing Order, 184 FERC ] 61,022 at P 42;
BPA, 120 FERC ] 61,211 at P 21; Sw. Power Pool, Inc., 119 FERC ]
61,199, at P 39 (2007) (stating that IPPs ``are free to negotiate
rates that they charge their customers for real power that are
sufficient to compensate them for any costs that they may incur in
producing reactive power within their deadbands, just as affiliated
generators may seek to negotiate rates that they charge their
customers that are sufficient to compensate them for the costs of
any reactive power that they provide within their deadbands.'').
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7. Consistent with Order Nos. 2003 and 2003-A, multiple regional
transmission organizations (RTO), independent system operators (ISOs),
and non RTO/ISO transmission providers have elected not to compensate
generating facilities for the provision of reactive power within the
standard power factor range under Schedule 2 of the OATT.\14\ Within
these regions, there is no evidence that this lack of compensation has
led to an insufficient supply of reactive power or that generating
facilities in these regions have been unable to recover any costs
associated with the production of reactive power. Additionally, the
experiences of these regions where reactive power within the standard
power factor range is not separately compensated indicate that
investors are able to, and in fact do, develop generating facilities
that can satisfy the obligations in their interconnection agreements
without separate reactive power compensation.
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\14\ MISO, 182 FERC ] 61,033 at P 1.
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8. Based on our review of the comments submitted in response to the
Commission's Notice of Inquiry \15\ in the instant docket, as well as
the Commission's experience in the years since the issuance of Order
No. 2003-A, we preliminarily find that allowing transmission providers
to compensate generating facilities, affiliated and unaffiliated, for
providing reactive power within the standard power factor range has
resulted in unjust and unreasonable transmission rates. This is because
generating facilities providing reactive power within the standard
power factor range are only meeting their obligations under their
interconnection agreements and in accordance with good utility
practice, and in doing so, incur no additional costs or de minimis
costs beyond that which they already incur to provide real power.\16\
Accordingly, we propose to prohibit transmission providers from
including in their transmission rates any charges associated with the
supply of reactive power within the standard power factor range from a
generating facility, including those owned by the transmission owner or
its affiliates.
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\15\ Reactive Power Capability Compensation, 177 FERC ] 61,118
(2021) (NOI).
\16\ Real power, which accomplishes useful work (e.g., runs
motors), is typically measured in megawatts (MW).
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9. First, we propose to add the following sentence to the end of
Schedule 2 of the pro forma OATT: \17\ ``However, such rates shall not
include compensation to generating facilities for the supply of
reactive power within the power factor range specified in its
interconnection agreement.'' Second, we propose to remove the following
clause from the pro forma LGIA: \18\ ``provided that if Transmission
Provider pays its own or affiliated generators for reactive power
service within the specified range, it must also pay Interconnection
Customer.'' Third, we propose to remove the following sentence from the
pro forma SGIA: \19\ ``In addition, if the Transmission Provider pays
its own or affiliated generators for reactive power service within the
specified range, it must also pay the Interconnection Customer.''
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\17\ See pro forma OATT, Schedule 2.
\18\ See pro forma LGIA, section 9.6.3.
\19\ See pro forma SGIA, section 1.8.2.
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II. Background
A. What is reactive power?
10. Almost all bulk electric power is generated, transported, and
consumed in alternating current (AC) networks. Reactive power, which is
measured in megavolt-amperes reactive (MVAr),\20\ is a critical
component of operating an AC electricity system and is required to
control system voltage within appropriate ranges for efficient and
reliable operation of the transmission system. Reactive power supports
the voltages that must be controlled to provide for delivery of real
power and for system reliability. Reactive power can be produced or
absorbed \21\ by generating facilities, power electronic equipment such
as flexible AC transmission system devices, transmission lines and
equipment, and load. As relevant here, generating facilities must
either produce or absorb reactive power for the transmission system to
maintain voltage levels required to reliably supply real power from
generation to load.
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\20\ MVAr is the typical unit of measurement for reactive power.
\21\ See supra n.5.
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11. The power factor is the ratio of a generating facility's real
power to its apparent power.\22\ Power factors can range from 1.0 to
0.0, with 1.0 representing only real power and 0.0 representing only
reactive power. Most generating facilities have interconnection
agreements that specify a standard power factor range within which the
generating facility must be able to operate while producing its full
real power capacity.
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\22\ Apparent power is the total power output of the system
(both real and reactive power).
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B. How has reactive power been compensated?
12. As noted above, the Commission's policy on reactive power
compensation has evolved since issuing Order No. 888, which included
provisions regarding reactive power from generating facilities as an
ancillary service in Schedule 2 of the pro forma OATT.\23\ As relevant
here, in Order No. 2003, the Commission adopted a standard agreement
for the interconnection of large generating facilities (the pro forma
LGIA). This standard agreement included the requirement that
interconnection customers maintain a composite power delivery at
continuous rate of power output at the generating facility's point of
interconnection at a power factor within the range of 0.95 leading to
0.95 lagging when synchronized to the transmission system, unless the
transmission provider has established a different power factor range.
Order No. 2003 required that a transmission provider compensate an
interconnection customer for reactive power when the transmission
provider requests that the interconnection customer operate its
generating facility outside the established power factor range. With
respect to reactive power within the established power factor range,
the Commission initially concluded that the interconnection customer
should not be compensated for reactive power when operating within the
range established in the interconnection agreement because doing so
``is only meeting [the generating facility's] obligation.'' \24\ But,
in Order No. 2003-A, the Commission clarified that ``if the
Transmission Provider pays its own or its affiliated generators for
reactive power within the established range, it must also pay the
Interconnection Customer.'' \25\ Order No. 2003-A also exempted wind
generating
[[Page 21457]]
facilities from maintaining the established power factor range.\26\
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\23\ Order No. 888, FERC Stats. & Regs. ] 31,036 at 31,705-07 &
n.359.
\24\ Order No. 2003, 104 FERC ] 61,103 at P 546.
\25\ Order No. 2003-A, 106 FERC ] 61,220 at P 416.
\26\ Id. P 34.
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13. The Commission treats the provision of reactive power within
the standard power factor range differently from that outside the
standard power factor range. Where reactive power is provided outside
of the standard power factor range, it is considered ``an ancillary
service for transmitting power across the grid to serve load.'' \27\ By
contrast, where the generating facility is operating within the
standard power factor range, ``it is meeting its obligation as a
generator to maintain the appropriate power factor in order to maintain
voltage levels for energy entering the grid during normal operations.''
\28\ ``Put differently, reactive support by generating facilities
operating within the standard power factor range ensures that when
these facilities inject real power--the product that their facilities
exist to create and sell--onto the grid under normal conditions, they
can do their part to maintain adequate voltages and to not threaten
reliability.'' \29\
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\27\ See, e.g., METC, 97 FERC at 61,852-53 (emphasis added);
MISO Rehearing Order, 184 FERC ] 61,022 at PP 23-24.
\28\ METC, 97 FERC at 61,852-53; see also MISO Rehearing Order,
184 FERC ] 61,022 at PP 23-24; BPA, 120 FERC ] 61,211 at P 19; cf.
Dynegy Midwest Generation, Inc., 125 FERC ] 61,280, at P 16 (2008)
(``Reactive power is a localized service that is quickly used by
transmission system components and cannot be transported over long
distances.'').
\29\ MISO Rehearing Order, 184 FERC ] 61,022 at P 23.
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14. In Order No. 2006,\30\ the Commission adopted identical power
factor and compensation requirements for small generating facilities
(facilities that have a capacity of no more than 20 MW) but exempted
small wind generating facilities from the reactive power requirement.
Subsequently, in Order No. 827,\31\ the Commission eliminated the
exemptions for both small and large wind generating facilities, thus
requiring those facilities to provide reactive power. As a result, all
newly interconnecting non-synchronous generating facilities were
required to provide reactive power within the range of 0.95 leading to
0.95 lagging at the high-side \32\ of the generator substation
transformer as a condition of interconnection. With respect to
compensation, the Commission applied the existing policies on
compensation for reactive power as articulated in Order Nos. 2003 and
2003-A and reflected in the pro forma LGIA and SGIA. The Commission,
however, stated that the record did not contain a sufficient basis for
determining a method for calculating compensation for non-synchronous
generating facilities and therefore stated that any non-synchronous
generating facility seeking reactive power compensation would need to
propose a method for calculating that compensation as part of its
filing.\33\
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\30\ Standardization of Small Generator Interconnection
Agreements & Procs., Order No. 2006, 111 FERC ] 61,220, order on
reh'g, Order No. 2006-A, 70 FR 71760 (Nov. 30, 2005), 113 FERC ]
61,195 (2005), order granting clarification, Order No. 2006-B, 71 FR
42587 (July 27, 2006), 116 FERC ] 61,046 (2006).
\31\ Reactive Power Requirements for Non-Synchronous Generation,
Order No. 827, 81 FR 40793 (June 23, 2006), 155 FERC ] 61,277, order
on clarification and reh'g, 157 FERC ] 61,003 (2016).
\32\ High-side refers to the side of the transformer with higher
voltages. Generally, real power must be stepped up through a
transformer to transmission-level voltages before being injected
into the transmission system.
\33\ Order No. 827, 155 FERC ] 61,277 at P 52.
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15. Consistent with Order Nos. 2003 and 2003-A, the Commission has
permitted transmission providers to eliminate separate compensation for
generating facilities providing reactive power within the standard
power factor range.\34\ In these cases, the Commission affirmed its
determination that the provision of reactive power within the standard
power factor range is not compensable except as a matter of
comparability. For example, in BPA, the Commission granted a complaint
filed by Bonneville Power Administration (BPA) arguing that the rate
schedules of certain independent power producers (IPP) for reactive
power were no longer just and reasonable given BPA's decision to no
longer pay its own or affiliated generators.\35\ The Commission found
that ``Commission policy clearly allows BPA to discontinue paying all
its merchants for inside the deadband reactive power service.'' \36\
The Commission also found that a transmission provider's decision to
end compensation for reactive power within the standard power factor
range did not compromise an IPP's ability to recover costs that they
may incur in producing reactive power within such range.\37\ The
Commission stated that such generating facilities ``may be able to
recover such costs in other ways--such as through higher power sales
rates of their own.'' \38\ To the extent that it could be argued that
such recovery was not feasible for IPPs, the Commission found that such
arguments lacked plausibility ``since the incremental cost of reactive
power service within the deadband is minimal.'' \39\ The Commission
explained that ``[t]he purpose for which generation assets are built
(including reactive power capability to maintain voltage levels for
generation entering the grid) is to make sales of real power.'' \40\
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\34\ See, e.g., MISO, 182 FERC ] 61,033 at PP 52-53; MISO
Rehearing Order, 184 FERC ] 61,022 at P 26; Pub. Serv. Co. of N.M.,
178 FERC ] 61,088, at PP 29-31 (2022) (PNM); Nev. Power Co., 179
FERC ] 61,103, at PP 20-21 (2022); BPA, 120 FERC ] 61,211 at P 20;
E.ON U.S. LLC, 119 FERC ] 61,340, at P 15 (2007); Entergy Servs.,
Inc., 113 FERC ] 61,040, at P 38 (2005).
\35\ BPA, 120 FERC ] 61,211 at PP 19-20; BPA Rehearing Order,
125 FERC ] 61,273 at PP 10-11.
\36\ BPA, 120 FERC ] 61,211 at P 20.
\37\ Id. PP 19-22.
\38\ Id. P 21 (citing Sw. Power Pool, Inc., 119 FERC ] 61,199 at
P 39).
\39\ Id.
\40\ Id.
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16. The Commission made similar findings in MISO, wherein it
accepted an FPA section 205 application by Midcontinent Independent
System Operator, Inc. (MISO) transmission owners to end generator
compensation for the provision of reactive power within the standard
power factor range.\41\ In accepting MISO transmission owners'
proposal, the Commission reiterated its longstanding policy ``that the
provision of reactive power within the standard power factor range is,
in the first instance, an obligation of the interconnecting generator
and good utility practice,'' such that ``MISO transmission owners do
not have an obligation to continue to compensate an independent
generator for reactive power within the standard power factor range
when its own or affiliated generators are no longer being
compensated.'' \42\ The Commission also rejected any reliance
arguments, reasoning in part that the provision of reactive power
within the standard power factor range required little or no
incremental investment.\43\ In addition, the Commission found that
generating facilities have other opportunities, beyond Schedule 2,
through which they have the opportunity to seek to recover
[[Page 21458]]
their costs of providing reactive power.\44\
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\41\ MISO, 182 FERC ] 61,033 at P 53 (``Bearing in mind that the
provision of reactive power within the standard power factor range
is, in the first instance, an obligation of the interconnecting
generator and good utility practice, MISO [transmission owners] do
not have an obligation to continue to compensate an independent
generator for reactive power within the standard power factor range
when its own or affiliated generators are no longer being
compensated.'' (citation omitted)); see also PNM, 178 FERC ] 61,088
at P 29 (accepting PNM's revisions to eliminate compensation for
reactive service under Schedule 2 and rejecting generators'
arguments that it is ``just and reasonable for it to be compensated
for investments made'' to provide reactive support consistent with
interconnection requirements even though PNM elected to no longer
pay its own or affiliated generators for such reactive power).
\42\ MISO, 182 FERC ] 61,033 at P 53 (finding ``those protests
that challenge these well-established policies to be collateral
attacks on these earlier determinations.'').
\43\ MISO Rehearing Order, 184 FERC ] 61,022 at P 29.
\44\ Id. P 41.
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17. Of the six Commission-jurisdictional RTOs/ISOs, only three
currently compensate generating facilities for reactive power provided
within the standard power factor range. Generating facilities in PJM
Interconnection, L.L.C. (PJM) generally use the cost-based AEP
Methodology to calculate cost-of-service rates for the production of
reactive power.\45\ Because the same generation equipment contributes
to the production of both real power and reactive power, the AEP
Methodology attempts to functionalize each piece of equipment as
between its contribution to real power and reactive power. Then, using
allocators calculated based on the facility's output, the AEP
Methodology allocates the cost of each piece of equipment based on its
relative contribution to each function.
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\45\ The AEP Methodology derives its name from Opinion No. 440,
where the Commission approved AEP's, a vertically integrated
utility, method for calculating the costs of synchronous generation
equipment associated with the production of reactive power. See Am.
Elec. Power Serv. Corp., Opinion No. 440, 88 FERC ] 61,141 (1999),
order on reh'g, 92 FERC ] 61,001 (2000). In WPS Westwood, the
Commission recommended that all generating facilities that have
actual cost data and support documentation use the AEP Methodology.
See WPS Westwood Generation, LLC, 101 FERC ] 61,290, at P 14 (2002).
---------------------------------------------------------------------------
18. Generating facilities in ISO New England Inc. (ISO-NE) and New
York Independent System Operator, Inc. (NYISO) are compensated for
reactive power under flat rate designs that are adjusted for
inflation.\46\ California Independent System Operator Corporation
(CAISO),\47\ Southwest Power Pool, Inc. (SPP),\48\ and MISO \49\ do not
pay separately for reactive power within the standard power factor
range.
---------------------------------------------------------------------------
\46\ NOI, 177 FERC ] 61,118 at PP 14-16.
\47\ CAISO never provided compensation for reactive power within
the standard power factor range. See Cal. Indep. Sys. Operator
Corp., 160 FERC ] 61,035, at P 7 (2017) (explaining that CAISO
considered the possibility of compensating generating facilities for
reactive power in its stakeholder process, but decided against it,
reasoning that the ability to provide reactive power is part of a
generator's fixed costs, which are recovered through power purchase
agreements).
\48\ Sw. Power Pool, Inc., 119 FERC ] 61,199 at P 30.
\49\ MISO, 182 FERC ] 61,033 at PP 52-66; MISO Rehearing Order,
184 FERC ] 61,022 at PP 23-55.
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19. Outside the RTOs/ISOs, transmission providers that pay for the
provision of reactive power within the standard power factor range
generally compensate generating facilities using the AEP Methodology to
set reactive power compensation on an individual generating facility
basis. Many non-RTO/ISO transmission providers do not pay separately
for reactive power provided within the standard power factor range.\50\
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\50\ See, e.g., Arizona Public Service Company, FERC Electric
Tariff Vol. No. 2, Schedule 2 (Reactive Supply and Voltage Control
from Generation or Other Sources Service) (6.0.0) (``This service
will be provided at no charge until APS has developed a rate that
has been filed with the Commission and allowed to be implemented;
however, Transmission Customers taking service at transmission
voltage levels shall be responsible for maintaining a power factor
of <plus-minus> 95.0%, and Transmission Customers taking service at
distribution voltage levels shall maintain a power factor of not
less than 90% lagging but in no event leading, unless agreed to by
APS.''); Public Service Company of New Mexico, PNM Open Access
Transmission Tariff, Schedule 2 (Reactive Supply and Voltage Control
from Generation or Other Sources Service) (2.1.0) (``As of October
1, 2021, the Effective Date of this Schedule 2, the Transmission
Provider is not charging for Reactive Supply and Voltage Control
from Generation or Other Sources Service from its own resources. As
a result, there will be no separate charge for such service.'').
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C. Notice of Inquiry
20. On November 18, 2021, the Commission issued an NOI \51\ in the
instant docket seeking comment on various issues regarding reactive
power compensation and market design as a result of the significant
changes that have taken place in the electric industry in the last two
decades, including changes in the generation resource mix and a general
shift away from cost-of-service rates for generating facilities selling
into Commission-jurisdictional markets. Generally, the Commission
sought to ``examine whether the current regime for reactive power
capability compensation requires revisions to ensure that payments for
reactive power capability accurately reflect the costs associated with
reactive power capability.'' \52\ Specifically, the Commission sought
comment on various constructs used by transmission providers to allow
for reactive power cost recovery, including issues related to the
application of the AEP Methodology as well as on issues regarding
recovery of reactive power costs through existing energy and/or
capacity markets.
---------------------------------------------------------------------------
\51\ NOI, 177 FERC ] 61,118.
\52\ Id. P 19.
---------------------------------------------------------------------------
21. The Commission received 37 initial comments and 10 reply
comments in response to the NOI. The commenters to the NOI are listed
and group members are identified in Appendix A. Groups representing
transmission customers, such as Joint Customers, the Electricity
Consumers Resource Council (ELCON), and the National Rural Electric
Cooperative Association (NRECA), believe that the AEP Methodology
results in unjust and unreasonable rates and recommend that the
Commission establish a new rate methodology.\53\ In particular, Joint
Customers argue that ``reactive capability alone should not be the
basis for compensation.'' \54\ By contrast, resource developers, power
generation industry groups, and commenters who support the increased
use of renewable energy argue in favor of retaining and modifying the
AEP Methodology to address the issues discussed in the NOI.\55\
---------------------------------------------------------------------------
\53\ Joint Customers Initial Comments at 8-13; Joint Customers
Reply Comments at 2-10, 12-15; ELCON Initial Comments at 5-7, NRECA
Initial Comments at 4-5.
\54\ Joint Customers Initial Comments at 9.
\55\ See, e.g., EDF Renewables, Inc. (EDFR) Initial Comments at
2-4; Edison Electric Institute (EEI) Initial Comments at 5;
Indicated Generation Owners Initial Comments at 5-7; Nuclear Energy
Institute (NEI) Initial Comments at 4; PJM Power Providers Initial
Comments at 2-4; Renewable Generation Companies Initial Comments at
6-7, 11-15; Renewable Generation Companies Reply Comments at 2-5,
10-11; Clean Energy Coalition Initial Comments at 1-5; Electric
Power Supply Association (EPSA) Initial Comments at 2-9; Vistra
Corp. and Dynegy Marketing and Trade, LLC (collectively, Vistra)
Initial Comments at 6-7; Vistra Reply Comments at 6-7; Pine Gate
Renewables, LLC (Pine Gate) Initial Comments at 7-8.
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22. The Independent Market Monitor for PJM (PJM IMM) contends that
cost-of-service compensation for the provision of reactive power within
the standard power factor range is an ``atavistic regulatory paradigm''
that predates the introduction of wholesale power markets and,
therefore, is unnecessary in light of potential compensation through
the PJM markets.\56\ ELCON states that it supports the PJM IMM's
position and encourages the Commission to rely on ``competitive markets
for the procurement of essential grid services such as reactive power--
rather than reliance on traditional cost-of-service rates'' in order to
``ensure that electricity consumers pay the lowest price possible for
reliable service.'' \57\
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\56\ PJM IMM Initial Comments at 2; see also PJM IMM, Comments,
Docket No. AD16-17-000, at 1, 6-10 (filed Aug. 1, 2016) (detailing
the PJM IMM's view that reactive power costs can--and should--be
recovered through PJM's capacity market instead of under a cost-of-
service paradigm); Monitoring Analytics, 2020 State of the Market
Report for PJM, 523 (Mar. 11, 2021), <a href="https://www.monitoringanalytics.com/reports/PJM_State_of_the_Market/2020.shtml">https://www.monitoringanalytics.com/reports/PJM_State_of_the_Market/2020.shtml</a> (describing the PJM IMM's position and recommended
improvements)); PJM IMM, Brief on Exceptions, Docket No. ER17-1821-
002, at 3-16 (filed June 12, 2019) (discussing the PJM IMM's
concerns about what it termed a ``hybrid of market-based rates and
cost of service rates''); PJM IMM, Rehearing Request, Docket No.
ER17-1821-005, at 3-5 (filed Apr. 30, 2021) (addressing issues
regarding the Energy and Ancillary Services Offset (E&AS Offset) and
a generator's proposed reactive power rates).
\57\ ELCON Initial Comments at 4-5.
---------------------------------------------------------------------------
23. RTOs/ISOs generally limit their comments to describing the rate
designs in their respective regions, but PJM and CAISO did provide some
commentary
[[Page 21459]]
on the merits. While PJM does not advocate for a particular solution in
this proceeding, PJM highlights several issues with its current
reactive power rate scheme.\58\ Specifically, PJM asserts that
``enormous'' amounts of time and resources must be expended to file,
litigate, and perform testing for each individual generating facility's
cost-of-service rate case,\59\ which PJM notes often results in a rate
product that is ``of exceptionally poor quality for an important
ancillary service.'' \60\ CAISO states that despite the fact that it
does not compensate for reactive power within the standard power factor
range, it ``has seen no evidence to this point that resources cannot
comply with reactive power dispatch instructions because they have
insufficient funds for the equipment to meet the reactive power
dispatch.'' \61\
---------------------------------------------------------------------------
\58\ PJM Initial Comments at 1-2.
\59\ Id. at 2-3, 5-7. PJM notes that ``many other parties beyond
the generator are drawn into the proceeding, including PJM, FERC
Trial Staff, zonal transmission customers, transmission owners, and/
or the Independent Market Monitor for PJM, among others. These
parties must in turn expend time and resources of their own in
discovery and analysis of the generator's specific cost
characteristics and claims, in order to formulate their own position
in the proceeding and form a basis for negotiations or litigation.''
\60\ PJM Initial Comments at 3.
\61\ CAISO Initial Comments at 5-6.
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III. Discussion
A. Need for Reform
24. Since Order No. 2003-A, the Commission has permitted
transmission providers to compensate resources for providing reactive
power within the standard power factor range provided that, to ensure
comparability, the transmission provider pays both affiliated and
unaffiliated resources. But, as explained in more detail below,
providing reactive power within the standard power factor range is a
``no cost'' \62\ or de minimis cost service in addition to being a
resource's obligation under its interconnection agreement and good
utility practice. Further, the record indicates that to the extent that
generating facilities have any purported costs associated with
providing reactive power within the standard power factor range, these
costs can be recovered through energy or capacity sales and do not
require separate compensation.
---------------------------------------------------------------------------
\62\ METC, 97 FERC at 61,852-53.
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25. We thus preliminarily find that where transmission providers
require transmission customers to pay for the provision of reactive
power within the standard power factor range, transmission rates may be
unjust and unreasonable, as they include costs without a sufficient
economic basis or justification.
26. The Commission's experience since Order No. 2003-A and the
comments submitted into this record demonstrate that where transmission
providers provide compensation, the costs to transmission customers
have increased substantially without any commensurate increase in
benefits. For example, in many regions today, resources are sited
without regard to where there is a geographic need for reactive power,
which is significant given that (unlike real power) reactive power
cannot be efficiently transmitted long distances. Where such resources
are compensated for reactive power that is not needed or necessarily
deliverable to areas of the transmission system where reactive power
may be needed, customers may be paying for a perceived reliability
benefit that they are not receiving.
27. Additionally, implementing the Commission-approved AEP
Methodology has become increasingly administratively burdensome to
transmission providers, transmission customers, other stakeholders, and
the Commission due to the resource- and time-intensity involved in
determining individualized, cost-of-service reactive power rates for
generation facilities through hearing and settlement judge
procedures.\63\ It also often results in inconsistent rate treatment
across facilities.
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\63\ Today, most reactive power filings are made by IPPs and
concern non-synchronous resources that produce reactive power using
different types of equipment than that contemplated by the AEP
Methodology. Additionally, almost all filing entities (both
synchronous and non-synchronous) have received waivers of the
requirement to maintain their accounts under the Uniform System of
Accounts (USofA) rules and to file a FERC Form No. 1 when they were
granted market-based rate authority.
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1. Compensation for Providing Reactive Power Within the Standard Power
Factor Range May Be Unjust and Unreasonable
28. We preliminarily find that providing compensation for the
provision of reactive power within the standard power factor range is
unjust and unreasonable because the generating facility already
provides reactive power within the standard power factor range at no
cost or de minimis cost, because such compensation may result in undue
compensation or other market distortions, and because providing
reactive power within the standard power factor range is an obligation
of the generating facility as an interconnection customer and
consistent with good utility practice.
29. We begin by explaining why providing reactive power within the
standard power factor range imposes no cost or de minimis cost to
producers. Both synchronous and non-synchronous resources provide real
and reactive power as joint products,\64\ with joint costs.\65\ For
synchronous generating facilities, ``the same equipment is used to
provide real and reactive power.'' \66\ Non-synchronous generating
facilities use a different physical process to produce reactive power,
but ``the most critical element in VAR production, the inverter,'' \67\
is also necessary for non-synchronous generating facilities to produce
real power that can be injected into AC systems.\68\ In other words,
for both synchronous and non-synchronous generating facilities,
``[t]here are few if any identifiable costs incurred by generators in
order to provide reactive power'' \69\ beyond the investments in
equipment already necessary to generate and supply real power to the
transmission system.\70\
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\64\ See PSC VSMPO-Avisma Corp. v. U.S., 688 F.3d 751, 756 (Fed.
Cir. 2012) (defining ``joint products'' as ``two dissimilar end
products that are produced from a single production process.'').
\65\ A joint cost is an expenditure that benefits more than one
product, and for which it is not possible to separate the
contribution to each product. In re Permian Basin Area Rate Cases,
390 U.S. 747, 761 n.25 (1968) (``Joint costs `are incurred when
products cannot be separately produced.' '' (citing M. Adelman, The
Supply and Price of Natural Gas 25 (1962))); see also
AccountingTools, Joint Cost (Aug. 25, 2023), <a href="https://www.accountingtools.com/articles/joint-cost">https://www.accountingtools.com/articles/joint-cost</a>.
\66\ EEI Initial Comments at 6.
\67\ Duke Energy Corporation Initial Comments at 4.
\68\ See also MISO Rehearing Order, 184 FERC ] 61,022 at P 30
(``As to non-synchronous resources, the principal piece of equipment
required for non-synchronous resources to produce reactive power is
the inverter, which is already necessary to convert the direct
current produced by non-synchronous resources to alternating
current--i.e., to supply real power that can be injected into
alternating current power systems. On rehearing and in earlier
protests, no party points to any other equipment costs incurred by
non-synchronous generating facilities that are attributable to
providing Reactive Service.'' (citations omitted)).
\69\ PJM IMM Initial Comments at 4; see also MISO Transmission
Owners Reply Comments at 7-8.
\70\ See, e.g., BPA, 120 FERC ] 61,211 at P 21 (finding that the
incremental cost of reactive power service within the deadband is
minimal); METC, 97 FERC at 61,852-53 (``[R]eactive power provided,
not as an ancillary service, but rather as a ``no cost'' service
within reactive design limitations, may therefore, be provided
without compensation.''); Ariz. Pub. Serv. Co., 94 FERC ] 61,027, at
61,080 (2001) (rejecting generators' arguments for reactive power
compensation for operating within standard power factor range
because the generators failed to demonstrate that ``such a
requirement will limit the real power output of a generating unit
and therefore will not result in any lost opportunity costs'' or
that operating a generating unit within the proposed standard power
factor range will ``affect the generation output of a unit'').
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[[Page 21460]]
30. Moreover, because real and reactive power are provided as joint
products with joint costs, any allocation of joint fixed costs between
real and reactive power could be viewed as inherently arbitrary.\71\
When separate reactive power payments were first established, utilities
typically provided both generation and transmission as vertically
integrated utilities under a cost-of-service regime. In such a
construct, the allocation of costs between generation and transmission
facilities had little significance because it affected only the
allocation of costs between transmission and generation rates. In other
words, prior to the advent of IPPs (which operate only generation
facilities), market-based rates for energy, and the development of
RTOs/ISOs and bilateral markets, the allocation of fixed costs between
real and reactive power did not have a major effect on the overall
revenues of a combined vertically integrated utility.\72\ However, for
reactive power cost recovery, the introduction of RTO/ISO markets and
bilateral transactions in non-RTO/ISO regions has provided more
efficient and transparent means of compensating resources than the
cost-of-service model. For example, RTO/ISO markets provide generating
facilities with a means to recover the costs they incur to provide
various services, such as real power sales, that rely on the same
equipment used for reactive power supply.\73\ Additionally, generating
facilities in non-RTO/ISO regions (e.g., IPP) can compete in bilateral
markets to recover their investment, production, and operating costs.
---------------------------------------------------------------------------
\71\ See PJM IMM Initial Comments at 2 (``There is no reason to
include complex rules that arbitrarily segregate a portion of a
resource's capital costs as related to reactive power and that
require recovery of that arbitrary portion through guaranteed
revenue requirement payments based on burdensome cost of service
rate proceedings.''); id. at 3, 5, 21, 24; In re Permian Basin Area
Rate Cases, 390 U.S. at 804 (``There is ample support for the
Commission's judgment that the apportionment of actual costs between
two jointly produced commodities, only one of which is regulated by
the Commission, is intrinsically unreliable.''); Richard A. Posner,
Natural Monopoly and Its Regulation, 21 Stan. L. Rev. 548, 595
(1969) (``[W]here services involve joint or common costs a rational
allocation is impossible even in theory. How much of the cost of a
telephone handset is assignable to local and how much to interstate
telephone service?''); see also A.A. Poultry Farms, Inc. v. Rose
Acre Farms, Inc., 881 F.2d 1396, 1400 (7th Cir. 1989) (``How does
one allocate the cost of activities that have joint products?
Agencies engaged in ratemaking struggle with these problems for
years, even decades, without producing clear answers.'').
\72\ See N. States Power Co., 64 FERC ] 61,324, at 63,379 (1993)
(``In general, so long as a utility was selling generation and
transmission services on a bundled basis (i.e., full requirements
service), the functionalization of costs between generation and
transmission was not critical. The historical functionalization of
costs, or bright line approach, was administratively simple, it had
little or no impact on the overall (i.e., bundled) rate for
requirements service, and problems involving cross-subsidization
between the generation and transmission functions were minimal.
However, strict application of the traditional bright line approach
may need to be reexamined in light of changes taking place in the
electric industry--particularly the increase in transmission-only
service.'').
\73\ See, e.g., PJM IMM Initial Comments at 2 (``The current
process is an inefficient waste of time because it relies on an
atavistic regulatory paradigm that is not relevant in the PJM market
framework. The AEP Method[ology] was created, before the creation of
the PJM markets, by a regulated utility that had regulatory and
financial reasons to want to define some generation costs as
transmission costs.''); ELCON Initial Comments at 5 (``The AEP
Methodology was established as a workable heuristic during a period
in which organized markets were in their infancy and nearly all new
resources were synchronous.'').
---------------------------------------------------------------------------
31. We recognize that the production of reactive power within the
standard power factor range can result in certain incremental variable
costs such as fuel, maintenance, and potentially other costs. That
said, the Commission has repeatedly found,\74\ and commenters agree,
that ``[v]ariable costs of generating reactive power are de minimis.''
\75\ Indeed, as SPP notes, variable costs ``are generally limited to
changes in losses within the generating facility which are part of the
overall efficiency of the resource and, as such, are typically captured
in the resource offers.'' \76\ Similarly, Joint Customers state that,
in CAISO, SPP, and other regions that do not separately compensate for
reactive power within the standard power factor range, ``perhaps
generators are adequately recovering their costs through some other
means.'' \77\
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\74\ MISO Rehearing Order, 184 FERC ] 61,022 at PP 29-31
(finding that providing reactive service requires ``little or no
incremental investment'' by both synchronous and non-synchronous
resources); PJM Interconnection, L.L.C., 151 FERC ] 61,097, at PP 7,
28 (2015) (finding that non-synchronous generating facilities are
comparable to traditional synchronous generating facilities, in that
there are for both types of generating facilities very little if any
incremental costs incurred to provide reactive power); Panda
Stonewall, LLC, 176 FERC ] 61,072, at P 6 n.9 (2021) (stating that
Panda Stonewall's annual revenue requirement of $2,051,894 reflected
a heating losses component of $10,018). We note that the heating
losses component reflects the incremental cost of providing reactive
power.
\75\ SPP Initial Comments at 2; see also PJM IMM Initial
Comments at 4.
\76\ SPP Initial Comments at 2-3.
\77\ Joint Customers Initial Comments at 9; see also PJM IMM
Initial Comments at 1-4; CAISO Initial Comments at 3-4; Dominion
Initial Comments at 12; MISO, 182 FERC ] 61,033 at P 58 (``[J]ust as
the MISO [transmission owners'] generators may try to recover their
lost revenue through higher power sales rates, so too may
independent power producers try to recover their lost revenue
through their own higher power sales rates.''); BPA, 120 FERC ]
61,211 at P 21; Sw. Power Pool, Inc., 119 FERC ] 61,199 at P 39
(stating that IPPs ``are free to negotiate rates that they charge
their customers for real power that are sufficient to compensate
them for any costs that they may incur in producing reactive power
within their deadbands, just as affiliated generators may seek to
negotiate rates that they charge their customers that are sufficient
to compensate them for the costs of any reactive power that they
provide within their deadbands.'').
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32. By contrast, but outside the scope of this rulemaking, the
production of reactive power outside of the standard power factor
range, for which transmission providers are required to provide
compensation, may result in increased costs, including opportunity
costs to the generating facility.\78\ As such, if the transmission
provider requires a generating facility to provide reactive power
outside of the standard power factor range, the generating facility may
have to ``reduce its MW output in order to comply with such an
instruction[,]'' which could limit the generating facility's
opportunity to receive compensation for real power sales.\79\
---------------------------------------------------------------------------
\78\ See, e.g., SPP Initial Comments at 2 (``SPP's current
Schedule 2 rate per MVArh was calculated to represent the cost of
reactive power production from recently constructed generators so as
to reflect the upper end of such costs. This rate is applied to
compensate qualifying generators located throughout the SPP region
that provide reactive power support outside a power factor dead
band.'' (emphasis added) (citations omitted)).
\79\ CAISO Initial Comments at 4.
---------------------------------------------------------------------------
33. Lastly, consistent with Order No. 2003 and multiple subsequent
Commission orders since then, generating facilities must produce
reactive power in order to be allowed to interconnect to the
transmission system, and the industry has recognized that regulating
voltage among interconnected generating facilities is a necessary
component of good utility practice in an interconnected transmission
system. For example, CAISO states that ``[t]he rationale for the
CAISO's existing approach to reactive power compensation is that the
reactive power ranges called for in each interconnection agreement
represent a reasonable range of what a generator is expected to provide
the CAISO without additional compensation in accordance with good
utility practice and as a condition of being part of the CAISO markets
and CAISO grid.'' \80\ The Commission, therefore, has required
generating facilities to provide reactive power within the standard
power factor range under their interconnection agreements and good
utility practice.\81\
[[Page 21461]]
Thus, the obligation for generating facilities to provide reactive
power within the standard power factor range pursuant to their
interconnection agreements is separate from any compensation for
reactive power. In turn, because providing reactive power within the
standard power factor range is already obligated (a no cost or de
minimis cost service), compensating for providing such reactive power
could result in undue compensation to generating facilities \82\ at the
expense of transmission customers.
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\80\ CAISO Initial Comments at 3.
\81\ See, e.g., MISO, 182 FERC ] 61,033 at P 53 (``Bearing in
mind that the provision of reactive power within the standard power
factor range is, in the first instance, an obligation of the
interconnecting generator and good utility practice, MISO
[transmission owners] do not have an obligation to continue to
compensate an independent generator for reactive power within the
standard power factor range when its own or affiliated generators
are no longer being compensated.'' (citations omitted)); id. P 54
(``We find unpersuasive protesters arguments that it is not just and
reasonable to eliminate compensation for Reactive Service within the
standard power factor range because generators have come to rely on
the compensation for Reactive Service in order for the generators to
remain financially viable. The Commission has previously rejected
such arguments, finding that all newly interconnecting generators
are required to provide reactive power within the power factor range
of 0.95 leading to 0.95 lagging as a condition of interconnection.''
(citations omitted)); PNM, 178 FERC ] 61,088 at P 29 (rejecting
generator's arguments that it is ``just and reasonable for it to be
compensated for investments made'' to provide reactive support
consistent with interconnection requirements even though
transmission provider elected to no longer pay its own or affiliate
generators for such reactive power); Nev. Power Co., 179 FERC ]
61,103 at P 22 (finding that the generating companies' argument,
``that it is not just and reasonable to eliminate their compensation
for reactive service because they made investments in their
generating facilities based on the expectation that they would
receive compensation for reactive service,'' unpersuasive because
all newly interconnecting generators are required to provide
reactive power within the standard power factor range as a condition
of interconnection); Order No. 2003, 104 FERC ] 61,103 at P 546.
\82\ See Belmont Mun. Light Dep't v. FERC, 38 F.4th 173, 179,
186 (D.C. Cir. 2022) (finding that the Commission's approval of a
portion of ISO-NE's Inventoried Energy Program ``was not reasoned
decision making'' and ``thwart[ed] the [Commission's] own
`longstanding policy that rate incentives must be prospective and
that there must be a connection between the incentive and the
conduct meant to be induced' '' because it would compensate market
participants for conduct they already engage in as part of standard
business operations). Compensating for reactive power that is
already required for interconnection purposes could create a
``windfall'' as suggested by the D.C. Circuit in Belmont. Id. at 186
(citing San Diego Gas & Elec. Co. v. FERC, 913 F.3d 127, 137 (D.C.
Cir. 2019)). But see Order No. 2003-C, 111 FERC ] 61,401 at P 42
(finding that because providing reactive power within the
established range is an ``important service,'' payment for such
service does not constitute a ``windfall.'').
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2. Adverse Impacts of the Commission's Current Reactive Power
Compensation Policy
34. In the years since the issuance of Order No. 2003-A, numerous
issues have arisen in regions that provide compensation to generators
for the provision of reactive power within the standard power factor
range.
35. First, compensation for reactive power within the standard
power factor range is not tied to whether there is a particular
geographic need for reactive power. As noted above, reactive power
cannot be transferred over long distances across the transmission
system and, as a result, the reliability benefits of a generating
facility's reactive power depend, in part, on its location.\83\ But,
compensation in a region for reactive power within the standard power
factor range does not vary based on location, meaning that some
generating facilities are compensated for reactive power that is not
needed at the generating facilities' location on the transmission
system. As the MISO transmission owners argue, ``[t]he current
framework is . . . unjust and unreasonable because resources are being
paid for reactive power capability in geographic areas where not all of
the available reactive power is necessary. There are service areas with
concentrations of generation but very little load, creating an
exporting region where load pays for reactive capability that is
unneeded.'' \84\ Joint Customers add that, with the vastly increased
amount of generation and increase in the number of generators seeking
reactive compensation, the Commission ``should reconsider whether
unbounded payment for reactive power capability is appropriate, or, to
the contrary, whether transmission customers are paying for capability
for which they do not receive commensurate benefits.'' \85\ It appears
that under the current framework, generating facilities are eligible to
receive cost-based reactive power payments that do not reflect the
reliability benefits of the reactive power at each facility's location
(i.e., the extent to which the generating facility supports the voltage
of the transmission system), and that the reliability benefit may be
zero for certain generating facilities.
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\83\ FERC Staff Report, Payment for Reactive Power, Docket No.
AD14-7-000, 5 (Apr. 22, 2014), <a href="https://www.ferc.gov/sites/default/files/2020-05/04-11-14-reactive-power.pdf">https://www.ferc.gov/sites/default/files/2020-05/04-11-14-reactive-power.pdf</a>.
\84\ MISO Transmission Owners Initial Comments at 7-8; see also
Joint Customers Initial Comments at 8-9; Alliant Initial Comments at
4; NYISO, Reliability and Market Considerations for a Grid in
Transition, at 105 (2019), <a href="https://www.nyiso.com/documents/20142/2224547/Reliability-and-Market-Considerations-for-a-Grid-in-Transition-20191220%20Final.pdf/61a69b2e-0ca3-f18c-cc39-88a793469d50">https://www.nyiso.com/documents/20142/2224547/Reliability-and-Market-Considerations-for-a-Grid-in-Transition-20191220%20Final.pdf/61a69b2e-0ca3-f18c-cc39-88a793469d50</a>
(``Moreover, because voltage support needs are local, the NYISO will
need voltage support within specific narrow regions, not necessarily
at the locations at which resources able to provide reactive power
without incurring substantial commitment costs may be located.'').
\85\ Joint Customers Initial Comments at 8-9.
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36. Second, many commenters explain that in regions that allow
generating facilities to file individualized cost-of-service reactive
power rates, the process for determining those rates has proven to be
resource-intensive, time-intensive, and administratively burdensome for
ratepayers, transmission providers, and market participants.\86\
Moreover, commenters explain that in addition to being burdensome, the
resulting black box settlements produce a ``rate product'' that is ``of
exceptionally poor quality for an important ancillary service.'' \87\
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\86\ Id. at 4-5, 12-13 (``[T]he case-by-case approach to
reactive capability rates based on the AEP methodology makes it very
difficult for proceedings to be resolved in an efficient manner.'');
PJM IMM Initial Comments at 2, 4 (noting that ``[a]pplying cost of
service rules is costly and burdensome and unnecessary'' and
asserting that ``[r]emoving cost of service rules would avoid the
significant waste of resources incurred to develop unneeded cost of
service rates''); PJM Initial Comments at 10 (``[T]he current
construct for reactive power capability compensation in PJM imposes
a significant administrative burden on PJM and its resource owners,
both in terms of settlements and testing.''); Dominion Initial
Comments at 2-3 (noting that settlement proceedings are time
consuming and not transparent); see also Clean Energy Coalition
Reply Comments at 5; ELCON Initial Comments at 6-7; Renewable
Generation Reply Comments at 25; EDFR Initial Comments at 4-5; Pine
Gate Renewables Initial Comments at 6-7; PJM Power Providers Group
Initial Comments at 4-5; American Electric Power Service Corporation
Initial Comments at 2-3; EPSA Initial Comments at 2; Nuclear Energy
Institute Initial Comments at 6-7; PJM IMM Initial Comments at 2
(``Most reactive proceedings for generators in PJM are resolved in
black box settlements that fail to address the merits of the cost
support provided, result from an unsupported split the difference
approach, and that, not surprisingly, produce a wide, unreasonable
and discriminatory disparity among the rates per paid per MW-
year.'').
\87\ PJM Initial Comments at 3; see also PJM IMM Initial
Comments at 2.
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37. As noted in the NOI, most of the filings at the Commission
seeking to establish rates for reactive power compensation are made by
generating facilities (both synchronous and non-synchronous) that have
received waivers of the Commission's requirement to maintain their
accounts under the USofA rules and to file FERC Form No. 1.\88\ Due, in
part, to the lack
[[Page 21462]]
of availability of this cost-of-service information, many of these
filings are set for hearing and settlement judge procedures.\89\ Many
commenters, including Joint Customers, note that these settlement
proceedings ``require a significant expenditure of resources that
include legal and technical consultants,'' and while many of the cases
settle on a ``black box'' basis, ``significant effort is undertaken by
the Joint Customers [and other participants] in order to obtain
information necessary to perform an AEP-like calculation and develop
settlement proposals.'' \90\ The PJM IMM notes that, in its experience,
``[m]ost reactive proceedings for generators in PJM are resolved in
black box settlements that fail to address the merits of the cost
support provided, result from an unsupported split the difference
approach, and that, not surprisingly, produce a wide, unreasonable and
discriminatory disparity among the rates paid per MW-year.'' \91\ Joint
Customers also note that the time-consuming process for resolving
individual reactive service rate proceedings may leave customers
without adequate refund protection.\92\
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\88\ The Commission's accounting and reporting requirements are
particularly important to the evaluation and monitoring of cost-
based rates. See, e.g., Alcoa Power Generating Inc., 172 FERC ]
61,052, at P 29 (2020); Third-Party Provision of Ancillary Servs.;
Acct. & Fin. Reporting for New Elec. Storage Technologies, Order No.
784, 78 FR 46178 (July 30, 2013), 144 FERC ] 61,056 (2013)
(accounting and reporting requirements ``support the rate oversight
needs of both this Commission and State Commissions'' and are
``important in developing and monitoring rates, making policy
decisions, compliance and enforcement initiatives, and informing the
Commission and the public about the activities of entities that are
subject to these accounting and reporting requirements.''); Carville
Energy LLC, 104 FERC ] 61,252, at 61,833 n.13 (2003) (``For example,
non-exempt public utilities keep financial records, required by this
Commission, which, among other things, are designed to aid in the
development of the cost-based rates.'' (emphasis added)).
\89\ Indeed, as the Commission has explained, Parts 41, 101, and
141 of its regulations are critical to its statutory obligation
under sections 205 and 206 of the FPA to ensure that rates are just,
reasonable, and not unduly discriminatory or preferential. See PSEG
Fossil, LLC, 97 FERC ] 61,211, at 61,920-21 (2001) (PSEG), reh'g
denied, 98 FERC ] 61,169 (2002). Moreover, the Commission has stated
that customers subject to cost-based rates have a right to cost data
so that they may evaluate the ongoing reasonableness of their rates.
See also PSEG, 97 FERC at 61,920-21.
\90\ Joint Customers Initial Comments at 5. When the cases do
not settle, Joint Customers note that even more resources must be
expended to litigate the individual revenue requirement proposal.
For example, Joint Customers note that the Panda Stonewall
proceeding lasted four years from the effective date of Panda's
reactive service rate to the Commission's order establishing the
just and reasonable rate. Id. (citing Panda Stonewall, LLC, Opinion
No. 574, 174 FERC ] 61,266, reh'g denied, 175 FERC ] 62,132 (2023)).
During this time, Joint Customers note that they and others paid the
approximately $6.2 million annual revenue requirement filed by
Panda. Joint Customers state that the Commission's Order on Initial
Decision established an approximately $2 million annual revenue
requirement. Joint Customers note that this difference resulted in
``approximately $17 million in overcollection and delayed refunds
due to customers.'' Id.
\91\ PJM IMM Initial Comments at 2. Many other commenters
express concern over the lack of transparency associated with how
these rates are calculated. See, e.g., American Electric Power
Service Corporation Initial Comments at 2; Renewable Generation
Companies Initial Comments at 22-23; ELCON Initial Comments at 6-7;
Joint Customers Initial Comments at 6; PJM Initial Comments at 3-4,
11; Nuclear Energy Institute Initial Comments at 6-7; PSE&G Initial
Comments at 10.
\92\ See, e.g., Joint Customers Initial Comments at 13, 26; see
also id. at 28-29 (``The 15-month statutory limitation on refunds
[in FPA section 206 proceedings] creates an incentive for the
applicant to delay the proceeding in order to profit from their
delay by running out the clock to enter a period where the applicant
continues to collect the rate as filed (likely to later be
determined unjust and unreasonable) without any ongoing refund
obligation. While the statute provides for further refunds upon a
showing of dilatory behavior by the applicant, it would be difficult
to demonstrate such dilatory behavior when the delay in resolution
is due to settlement proceedings, or the procedural schedule in a
litigated proceeding. Therefore, customers are left in the position
of either foregoing or prematurely ending settlement discussions in
order to try to achieve a litigated outcome within the 15-month
refund period.'').
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38. Third, the process for testing and verification under the AEP
Methodology is unduly burdensome. Under that process, resources must
coordinate with the transmission provider to test and verify capability
to produce reactive power under certain conditions, which often
requires multiple tests over a series of months and that yields
inconsistent results across resources. PJM notes that this has caused a
``significant influx of resources that are not [otherwise] required to
test under PJM Manual 14-D . . . seeking to test solely for purposes of
filing and/or litigating reactive power capability cases.'' \93\ PJM
notes that ``under the current regulatory structure, rather than PJM
spending time and resources testing units based on PJM's operational
needs as the Transmission Provider, PJM is now often spending time and
resources testing units based on the resource owner's need to file and
litigate its individual cost-of-service rate case.'' \94\
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\93\ PJM Initial Comments at 6-7.
\94\ Id. at 7 (emphasis in original); see also Vistra Reply
Comments at 8 (``The time and resources that PJM must expend to
conduct testing for the purposes of supporting individual rate cases
is an anathema to the core purpose of the tests, which is system
reliability.'').
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39. Fourth, as discussed above, in regions where resources recover
their costs by participating in organized competitive wholesale
markets, providing separate compensation for the provision of reactive
power within the standard power factor range risks overcompensation and
market distortion in ways that did not exist prior to the existence of
organized markets.\95\ As noted above, the AEP Methodology originated
in an era of vertically integrated utilities, when most utilities
(including AEP) filed FERC Form No. 1s, used the USofA to classify
their costs, and recovered those costs entirely through cost-based
rates.\96\ It was thus intended to be a cost-of-service allocation
method for assigning joint costs between the generation and
transmission functions, but, as the PJM IMM argues, ``[t]he false
precision of the AEP Method is entirely based on arbitrary
assumptions.'' \97\ The PJM IMM argues that even proponents of the AEP
Methodology do not claim that the methodology's goal is to recover only
the specific costs associated with the production of reactive power,
which the PJM IMM claims is not possible in most cases. The PJM IMM
further argues that the AEP Methodology was not intended to define such
costs. The imprecision associated with the AEP Methodology was less
problematic when the total amount that a utility recovered was largely
unchanged by the allocation of fixed costs between a generation and
transmission function. But, as commenters point out, today most
generating facilities recover their costs through competitive markets
in both RTO/ISO and non-RTO/ISO regions. The AEP Methodology's
imprecision therefore becomes more significant because it can lead to
arbitrary increases in the utility's total recovery when cost-based
reactive power payments are added to any market recoveries.\98\ That is
especially true when markets fail to account for separate, cost-based
reactive power revenues by using standard rate making techniques (i.e.,
revenue crediting).\99\ For example, in PJM, the
[[Page 21463]]
capacity market rules currently account for reactive power payments to
resources by assuming average reactive power compensation of $2,546 per
MW-year.\100\ But reactive power revenue requirements in PJM, many of
which result from ``black-box'' settlements, range from roughly $1,000
per MW-year to $13,000 per MW-year.\101\ As the PJM IMM explains, this
wide range of actual compensation, which is both above and below the
amount of assumed reactive power compensation in the capacity market
rules, can lead to market distortions.\102\
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\95\ See ELCON Initial Comments at 5; PJM IMM Initial Comments
at 22-23.
\96\ See, e.g., Joint Customers Reply Comments at 6-7; ELCON
Initial Comments at 5.
\97\ PJM IMM Initial Comments at 5. As a point of comparison,
black start compensation also requires some cost allocation of joint
costs, but this is arguably distinct from allocation for reactive
power because incremental costs incurred to provide black start
service can be separately identified (e.g., unlike most generators,
which require power from the transmission system during start-up,
black start-capable generators may have small, on-site diesel
generation units, or equivalent equipment, to independently support
their station power needs and other electricity-using activities
during start-up). See, e.g., PJM Interconnection, L.L.C., Intra-PJM
Tariffs, OATT Schedule 6A (12.2.0). Payment is not related only to
identifiable costs. Such black start resources will also generally
have a different interconnection arrangement which allows for black
start service. The determination of whether a particular unit is a
black start unit is ultimately defined in the applicable tariff and
relates to capability rather than the presence of specific
equipment.
\98\ PJM IMM Initial Comments at 9-10; PJM IMM Reply Comments at
4 (``[T]he AEP Method allocates a portion (X percent) of the cost of
the plant to MVAR production and the balance (1-X percent) to MW
production. In a pure cost of service world, the allocators add to
100% and there can be no over recovery, regardless of the value of
X. But that is not true when the units operate in a competitive
wholesale power market.'').
\99\ See PJM IMM Reply Comments at 3 (``The Commission has
recognized the relevance of the issue associated with a `resource
receiving cost-based rate recovery while concurrently receiving
compensation for market-based rate services involves potential
double recovery of costs borne by the relevant cost-based
ratepayers.' '' (quoting Utilization of Elec. Storage Res. for
Multiple Servs. When Receiving Cost-Based Rate Recovery, 158 FERC ]
61,051, at P 15 (2017)); ELCON Initial Comments at 5 (``[R]ecouping
costs through organized markets while separately recouping the same
costs through a cost-of-service rate--would result in double
recovery, imposing additional and unnecessary costs on
consumers.'').
\100\ See PJM Interconnection, L.L.C., 182 FERC ] 61,073, at P
135 (2023).
\101\ PJM IMM Initial Comments at 21-22; see also PJM Initial
Comments at 4 (``There is a wide range of revenue requirements that
may ultimately be agreed to by the parties to a given proceeding,
and the willingness of parties to agree or not agree to a particular
number may be influenced by factors completely exogenous to the
actual cost and service characteristics of the unit (e.g.[,] the
legal fees associated with continuing the litigation).'').
\102\ PJM IMM Initial Comments at 21-22 (``For example, a
marginal resource with reactive revenue of $5,000 per MW-year
reflected in their net ACR offer would suppress the capacity market
clearing price. Conversely, a marginal resource with a reactive
revenue of $1,000 per MW-year reflected in their net ACR offer would
inflate the capacity market clearing price.'').
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40. The challenges experienced under the Commission's current
reactive power compensation policy are exacerbated by the increasing
volume of filings for reactive power compensation. Since Order No.
2003-A, and particularly in recent years, the number of reactive power
filings has significantly increased.\103\ In turn, the amount of
reactive power compensation paid to generating facilities by
transmission providers and collected from transmission customers has
likewise increased.\104\ We are concerned that transmission customers
may not be receiving a roughly commensurate increase in reliability
benefit.\105\
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\103\ See, e.g., Joint Customers Initial Comments at 4-5 (``In
PJM's Dominion zone, there has been a significant increase in the
number of reactive revenue requirements filings as well as a drastic
increase in the proposed revenue requirements for Reactive
Service.''); Vistra Initial Comments at 10 (noting the ``sheer
volume of reactive power hearing and settlement proceedings in
recent years''); PJM IMM Initial Comments at 13 (explaining that as
of February 2022, there were ``over two dozen active proceedings''
and that since 2016, there have been ``more than 100'' reactive
power proceedings).
\104\ For example, as of December 2023, the total RTO-wide
reactive power compensation paid to generating facilities in PJM was
approximately $384 million. See PJM, Reactive Supply and Voltage
Control Revenue Requirements 2023, <a href="https://www.pjm.com/markets-and-operations/billing-settlements-and-credit.aspx">https://www.pjm.com/markets-and-operations/billing-settlements-and-credit.aspx</a> (cell D296 in the
.xls file for December 2023).
\105\ See also Joint Customers Initial Comments at 8-9 (citing
Ill. Com. Comm'n v. FERC, 576 F.3d 470, 477 (2009)); Alliant Initial
Comments at 5; MISO Transmission Owners Reply Comments at 10; Joint
Customer Reply Comments at 5-6.
---------------------------------------------------------------------------
B. Proposed Reform
41. Having preliminarily found that allowing transmission providers
to include charges associated with the supply of reactive power within
the standard power factor range from generating facilities results in
transmission rates that may be unjust and unreasonable, we propose,
pursuant to FPA section 206,\106\ that a just and reasonable
replacement rate is to prohibit transmission providers from including
in their transmission rates any charges associated with the supply of
reactive power within the standard power factor range from a generating
facility.
---------------------------------------------------------------------------
\106\ 16 U.S.C. 824e.
---------------------------------------------------------------------------
42. Eliminating such charges ensures that transmission customers do
not pay transmission rates that include costs without an economic basis
or justification. Moreover, eliminating compensation is consistent with
the Commission's original statement in Order No. 2003 (as modified in
Order No. 2003-A) and in subsequent cases on the non-compensability of
providing reactive power within the standard power factor range.
Eliminating compensation also addresses the undue discrimination
concerns articulated by the Commission in Order No. 2003-A regarding
the disparate treatment of affiliated and non-affiliated generating
facilities, which led to the Commission's comparability policy. By
requiring the same approach to compensation for all generating
facilities, which necessarily includes both affiliates and non-
affiliates, we address the potential for undue discrimination by the
transmission provider by providing that comparability would no longer
be a justification for payment. To the extent that there are
incremental costs to provide reactive power within a generating
facility's standard power factor range, we see no reason why such costs
should not be reflected through energy or capacity offers made in
organized and bilateral markets.\107\
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\107\ See, e.g., SPP Initial Comments at 2-3 (``Variable costs
of generating reactive power are de minimis and are generally
limited to changes in losses within the generating facility which
are part of the overall efficiency of the resource and, as such, are
typically captured in the resource offers submitted to the SPP
Integrated Marketplace.''); PJM IMM Initial Comments at 2-3
(``Payments based on cost of service approaches result in
distortionary impacts on PJM markets. Elimination of the reactive
revenue requirement and the recognition that capital costs are not
distinguishable by function would increase prices in the capacity
market. . . . The simplest way to address this distortion would be
to recognize that all capacity costs are recoverable in the PJM
markets.'').
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1. Eliminating Separate Compensation Will Not Affect Reliability
43. We preliminarily find that prohibiting transmission providers
from including in their transmission rates any charges associated with
the supply of reactive power within the standard power factor range
from a generating facility is just and reasonable because compensation
for providing reactive power within the standard power factor range is
unnecessary to maintain reliability.\108\ Several commenters argue that
separate reactive power compensation is necessary to maintain
reliability. For example, Vistra, among others, argues that separate
compensation for reactive power is necessary because without it,
regions seeing increasing shares of non-synchronous generating
facilities in their generation mixes may not have sufficient reactive
power.\109\ We preliminarily disagree with this argument because we
preliminarily find that requiring transmission providers to continue
paying for reactive power already required by a generating facility's
interconnection agreement is not necessary to ensure that generating
facilities provide reactive power when required.\110\ As explained in
MISO, new
[[Page 21464]]
and existing generating facilities will still be required to provide
reactive power within the standard power factor range as a condition of
obtaining and maintaining interconnection.\111\ Additionally, as CAISO
notes, its current approach to not compensate for reactive power
provided within the standard power factor range has not resulted in
major issues of concern with the level of reactive power.\112\
---------------------------------------------------------------------------
\108\ See CAISO Initial Comments at 5-6; Joint Customers Reply
Comments at 5-6 (``Despite unsubstantiated claims to the contrary,
there has been no demonstration that there is any dearth of reactive
power sufficient to maintain reliability in regions where reactive
compensation is not based on the AEP methodology.''); MISO Initial
Comments at 6 (explaining that the ``method of compensation is
incidental to reliability'' because generating facilities'
obligation to provide reactive power within the standard power
factor range ``ensures that reactive power will be provided to
support the Transmission System.'').
\109\ Vistra Comments at 4 (citing NYISO, Reliability and Market
Considerations for a Grid in Transition, 25-26, 104-06 (2019),
<a href="https://www.nyiso.com/documents/20142/2224547/Reliability-and-Market-Considerations-for-a-Grid-in-Transition-20191220%20Final.pdf/61a69b2e-0ca3-f18c-cc39-88a793469d50">https://www.nyiso.com/documents/20142/2224547/Reliability-and-Market-Considerations-for-a-Grid-in-Transition-20191220%20Final.pdf/61a69b2e-0ca3-f18c-cc39-88a793469d50</a> and CAISO, Reactive Power
Requirements--Automatic Voltage Regulator Systems, Docket No. ER17-
490-000 (filed Dec. 5, 2016)). But see Joint Customers Reply
Comments at 6 (urging ``the Commission to maintain a focus on
reliability as the basis for compensating for Reactive Service, but
also to be wary of attempts by others to use `reliability' to
justify over-compensation for Reactive Service or to preserve
outdated methodologies.'').
\110\ See Essential Reliability Servs. & the Evolving Bulk-Power
Frequency Response, Order No. 842, 83 FR 639 (Mar. 6, 2018), 162
FERC ] 61,128, at P 121, order on reh'g and clarification, 164 FERC
] 61,135 (2018) (``While the Commission has approved specific
compensation for discrete services that require substantial
identifiable costs, such as for frequency regulation and operating
reserves, the Commission has not required specific compensation for
all reliability-related costs. We agree with those commenters who
observe that minimal reliability-related costs such as those
incurred to provide primary frequency response, are reasonably
considered to be part of the general cost of doing business, and are
not specifically compensated.'').
\111\ MISO, 182 FERC ] 61,033 at P 55.
\112\ CAISO Initial Comments at 5.
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44. We seek comment on the reliability impact of prohibiting
transmission providers from including in their transmission rates any
charges associated with the supply of reactive power within the
standard power factor range from a generating facility in regions where
generating facilities currently receive such compensation.
2. Eliminating Separate Compensation Does Not Preclude Generating
Facilities From Recovering Their Costs
45. We preliminarily find that separate compensation for providing
reactive power within the standard power factor range is not necessary
for resources to be able to recover their costs. Some commenters argue
that cost-of-service payment for reactive power is important for
obtaining financing. Although the prospect of receiving separate, fixed
reactive power payments may be beneficial for developing certain
generating facilities, resource developers continue to develop new
generating facilities in regions without such payments.\113\
Furthermore, the basis for these payments has always been
comparability. Therefore, these arguments do not demonstrate why
allowing for separate reactive power payments at the transmission
provider's discretion is just and reasonable.
---------------------------------------------------------------------------
\113\ For example, as of February 21, 2024, there were 453 total
generating facilities in the CAISO interconnection queue, 440 of
which were non-synchronous generating facilities. This corresponds
to 122,885 MW of capacity, 120,043 MW of which comes from the non-
synchronous generating facilities in the queue. See CAISO, Formatted
Generator Interconnection Queue Report, <a href="https://rimspub.caiso.com/rimsui/logon.do">https://rimspub.caiso.com/rimsui/logon.do</a> (last visited Feb. 21, 2024). Similarly, as of
February 21, 2024, there were 947 total generating facilities in the
SPP interconnection queue, 770 of which were non-synchronous
generating facilities. This corresponds to 175,243 MW of capacity,
141,879 MW of which comes from the non-synchronous generating
facilities in the queue. See SPP, Generator Interconnection Active
Requests, <a href="https://opsportal.spp.org/Studies/GIActive">https://opsportal.spp.org/Studies/GIActive</a> (last visited
Feb. 21, 2024).
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46. Instead, in the context of RTO/ISO markets, we preliminarily
find that it is both more efficient and less administratively
burdensome for generating facilities to recover any identified reactive
power costs, to the extent they exist, through energy and capacity
sales,\114\ since competition between generating facilities may
incentivize efficiency.\115\ Another benefit of any such market-based
compensation in RTOs/ISOs is that any costs of providing reactive power
within the standard power factor range would be more transparent to
market participants because they would be included in RTO/ISO energy
and/or capacity prices as opposed to generating facility-specific out-
of-market cost-of-service agreements.
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\114\ See MISO Rehearing Order, 184 FERC ] 61,022 at P 42
(dismissing Vistra's claim that they would be unable to recover any
costs attributable to providing reactive service through mechanisms
other that Schedule 2, such as in energy offers and capacity offers.
The Commission noted that ``[a]s to capacity offers, among the
`going forward' costs that can be recovered are `mandatory capital
expenditures necessary to comply with federal . . . reliability
requirements,' which would appear to include any (hypothetical)
capital investments and expenditures associated with Reactive
Service. As to energy offers, Vistra does not explain the basis for
its assertion that the Tariff bars including any incremental costs
associated with Reactive Service (e.g., fuel costs, short-term
variable operations and maintenance) in such offers.'').
\115\ For example, in PJM, capital costs are included in the Net
Cost of New Entry (Net CONE) parameter of the Variable Resource
Requirement (VRR) curve in the capacity market and the Net CONE
parameter directly affects clearing prices by affecting both the
maximum capacity price and the location of the downward sloping part
of the VRR. As a result, if the Commission were to eliminate
reactive power compensation within the standard power factor range,
the only change that would be required would be to exclude the
reactive power revenues from the Net CONE parameter and to exclude
any reactive power revenues from the energy and ancillary services
offset from the offer caps for resources that provide reactive
power. See PJM IMM Initial Comments at 21-22, 25.
---------------------------------------------------------------------------
47. The Commission has repeatedly rejected arguments that
generating facilities need separate reactive power payments ``since the
incremental cost of reactive power service within the deadband is
minimal.'' \116\ Therefore, consistent with those findings, for IPPs
operating in non-RTO regions, we preliminarily find that cessation of
payments for reactive power within the standard power factor range set
forth in the Commission's pro forma LGIA and SGIA does not compromise
an IPP's ability to recover costs that it may incur in producing
reactive power within such range because generating facilities have the
opportunity to recover such costs in other ways, ``such as through
higher power sales rates of their own.'' \117\
---------------------------------------------------------------------------
\116\ BPA, 120 FERC ] 61,211 at P 21 (citing Sw. Power Pool,
Inc., 119 FERC ] 61,199 at P 39).
\117\ Id.
---------------------------------------------------------------------------
48. Both experience in CAISO, SPP, MISO and certain non-RTO regions
where generating facilities do not receive compensation for the
provision of reactive power within the standard power factor
range,\118\ and the evidence in the record to date supports these
findings. Specifically, experience and evidence demonstrate that: (1)
eliminating compensation has not led to an insufficient supply of
reactive power in those regions; and that (2) generating facilities in
these regions have been able to recover any purported costs associated
with the production of reactive power. For example, CAISO notes that it
``has seen no evidence to this point that resources cannot comply with
reactive power dispatch instructions because they have insufficient
funds for the equipment to meet the reactive power dispatch.'' \119\ As
Leeward Renewable Energy, LLC, and Union of Concerned Scientists (LRE/
UCS) notes, ``the lack of separate reactive power compensation in CAISO
or SPP means that all costs have to be recovered through the applicable
PPA, which also means that those PPA prices are higher, all other
variables being equal, than they would otherwise be.'' \120\
---------------------------------------------------------------------------
\118\ See Cal. Indep. Sys. Operator Corp., 160 FERC ] 61,035 at
P 19. In 2017, the Commission considered the CAISO's approach and
found ``a separate payment for the provision of reactive power
capability inside the standard power factor range is not required,
and we see no reason to require a separate cost recovery mechanism
for reactive power capability based on the record here.'' The
Commission later affirmed this approach when it was proposed by
different transmission providers. See PNM, 178 FERC ] 61,088 at P 29
(``Consistent with Commission precedent, a transmission provider may
decide to eliminate compensation for having the capability of
providing reactive service within the standard power factor
range.''); MISO, 182 FERC ] 61,033 at P 55 (``As stated by MISO
[transmission owners] and supporting commenters, new and existing
generators in MISO will still be required to provide reactive power
within the standard power factor range as a condition of obtaining
and maintaining an interconnection. MISO [transmission owners] do
not propose to change MISO's ability to manually redispatch
individual generators for voltage control and generators will
continue to be compensated under a separate Tariff mechanism if MISO
directs a generation resource to provide reactive power outside of
the standard power factor range.'' (citations omitted)); see also
Order No. 842, 162 FERC ] 61,128 at P 120 (explaining that ``there
are interconnection requirements for generating facilities in which
the recovery of capital costs and operating expenses are not
necessarily ensured.'').
\119\ CAISO Initial Comments at 5-6.
\120\ LRE/UCS Initial Comments at 16.
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[[Page 21465]]
49. The record from the Notice of Inquiry contains comments arguing
that removal of all reactive power compensation under the standard
power factor range without a transition period or other similar
mechanism has the potential to disrupt business and investment
decisions for generating entities in certain markets in the near
term.\121\ We seek comment on whether and, if so, how the elimination
of separate reactive power payments will affect generating facilities'
ability to recover their costs in the markets that currently provide
reactive power compensation within the standard power factor range. We
also seek comment on whether, and if so how, eliminating separate
reactive power compensation within the standard power factor range may
affect investment decisions to build, or finish building, generation
facilities, and whether, and if so how, the elimination could otherwise
affect generators' business decisions in those markets.
---------------------------------------------------------------------------
\121\ See, e.g., EDF Renewables Initial Comments at 11-12
(``Since independent power producers . . . rely on project financing
to finance their project development, predictability of the revenue
stream is very important to this industry segment.); Joint Customers
Reply Comments at 17 (noting that ``resource developers or owners
may have made the decision to invest in resources under the
Commission's currently approved methods for determining reactive
compensation,'' while also cautioning against allowing unjust
reactive power rates to ``remain effective indefinitely.''); Duke
Energy Comments at 4 (``Developers have . . . obtained financing
based on [the AEP] methodology being in place.'').
---------------------------------------------------------------------------
C. Proposed Revisions for Eliminating Compensation for Reactive Power
Supply Within the Standard Power Factor Range
50. To effectuate the changes discussed herein, we propose three
revisions discussed further below. Our preliminary findings and these
proposed revisions are consistent with the Commission's previous
initial statements in Order No. 2003 (which was subsequently revised in
Order No. 2003-A) and in subsequent cases on the non-compensability of
providing reactive power within the standard power factor range. They
also address the undue discrimination concerns articulated by the
Commission in Order No. 2003-A, which led to the Commission's
comparability policy.\122\ By requiring the same approach to
compensation for all resources, which necessarily includes both
affiliates and non-affiliates, there is no potential for undue
discrimination by the transmission provider and comparability would no
longer be a justification for payment.
---------------------------------------------------------------------------
\122\ See supra notes 7-9 and associated text.
---------------------------------------------------------------------------
1. Revise Schedule 2 of the Pro Forma OATT
51. We propose to revise Schedule 2 of the pro forma OATT to add
the following sentence at the end of Schedule 2: ``However, such rates
shall not include any charges associated with the compensation to a
generating facility for the supply of reactive power within the power
factor range specified in its interconnection agreement.'' This
proposed revision would prohibit separate compensation for the
provision of reactive power within the standard power factor range
specified in an interconnection agreement.
2. Revise Section 9.6.3 of the Pro Forma Large Generator
Interconnection Agreement
52. We propose to revise section 9.6.3 of the pro forma LGIA to
remove the proviso: ``provided that if Transmission Provider pays its
own or affiliated generators for reactive power service within the
specified range, it must also pay Interconnection Customer.''
Accordingly, under our proposal here, section 9.6.3 of the pro forma
LGIA would read as follows: ``Payment for Reactive Power. Transmission
Provider is required to pay Interconnection Customer for reactive power
that Interconnection Customer provides or absorbs from the Large
Generating Facility when Transmission Provider requests Interconnection
Customer to operate its Large Generating Facility outside the range
specified in Article 9.6.1. Payments shall be pursuant to Article 11.6
or such other agreement to which the Parties have otherwise agreed.''
Along with the other proposed revisions, this proposed revision would
prohibit a transmission provider from including in its transmission
rates any charges associated with the supply of reactive power within
the specified power factor range from a generating facility.
Accordingly, transmission providers would be required to pay an
interconnection customer for reactive power only when the transmission
provider requests the interconnection customer to operate its facility
outside the power factor range set forth in its interconnection
agreement.
3. Revise Section 1.8.2 of the Pro Forma Small Generator
Interconnection Agreement
53. We propose to revise section 1.8.2 of the pro forma SGIA to
remove the following sentence: ``In addition, if the Transmission
Provider pays its own or affiliated generators for reactive power
service within the specified range, it must also pay the
Interconnection Customer.'' Accordingly, under our proposal here,
section 1.8.2 of the pro forma SGIA would read as follows: ``The
Transmission Provider is required to pay the Interconnection Customer
for reactive power that the Interconnection Customer provides or
absorbs from the Small Generating Facility when the Transmission
Provider requests the Interconnection Customer to operate its Small
Generating Facility outside the range specified in article 1.8.1.''
Along with the other proposed revisions, this proposed revision would
prohibit a transmission provider from including in its transmission
rates any charges associated with the supply of reactive power within
the specified power factor range from a generating facility.
Accordingly, as above, transmission providers would be required to pay
an interconnection customer for reactive power only when the
transmission provider requests the interconnection customer to operate
its facility outside the power factor range set forth in its
interconnection agreement.
IV. Proposed Compliance Procedures
54. We propose to require each transmission provider to submit a
compliance filing within 60 days of the effective date of the final
rule in this proceeding revising its OATT, pro forma LGIA, and pro
forma SGIA, as necessary, to comply with the requirements set forth in
any final rule issued in this proceeding. In addition, we propose to
allow 90 days from the date of the compliance filing for implementation
of the proposed reforms to become effective.
55. To the extent that any transmission provider believes that it
already complies with the reforms adopted in any final rule in this
proceeding, the transmission provider would be required to demonstrate
how it complies in the compliance filing required 60 days after the
effective date of any final rule in this proceeding. In reviewing
compliance filings, the Commission will apply the ``consistent with or
superior to'' standard to deviations from the adopted pro forma
language proposed by non-RTO/ISO transmission providers. In evaluating
compliance filings made by RTOs/ISOs, the Commission will apply the
``consistent with or superior to'' standard to deviations from the
adopted pro forma Schedule 2 and the ``independent entity variation
standard'' to deviations from the pro forma LGIA and pro forma SGIA.
56. We seek comment on whether the proposed compliance and
[[Page 21466]]
implementation timeline would allow sufficient time for changes to be
implemented in response to a final rule or whether a limited transition
period (beyond the 90-day implementation period proposed in this NOPR)
may be necessary. Specifically, we seek comment on the following
questions:
<bullet> Is a transition period necessary? Please provide
discussion supporting any opinion.
<bullet> What factors, if any, such as potential business or
investment impacts, should be considered in determining whether any
transition period is appropriate, how any transition period for
reactive power compensation may be structured to minimize impacts, and
for what duration any transition period should last? Absent a
transition period, would the final rule disrupt business and investment
decisions or not? If so, what transition mechanisms other than delaying
the implementation date of the final rule would minimize such
disruptions and be just and reasonable?
<bullet> For regions that have an established capacity market,
should transmission providers be allowed to make the implementation
date of their compliance filing align with the region's capacity market
timelines in order to allow costs associated with reactive power
production, if any, to be incorporated into capacity market bids? Would
a different transition mechanism, if any, be necessary for regions
without a capacity market? Would it be unduly discriminatory or
preferential to set different implementation dates for the final rule
in different markets and regions?
<bullet> If the Commission allows existing generation resources
that have previously received compensation for reactive power supply to
continue to receive compensation for a limited period while prohibiting
new generation resources from receiving reactive power compensation,
how should it determine eligibility for continued compensation in a
manner that is just and reasonable and not unduly discriminatory or
preferential?
V. Information Collection Statement
57. The Office of Management and Budget's (OMB) regulations require
approval of certain information collection requirements imposed by
agency rules. Upon approval of a collection(s) of information, OMB will
assign an OMB control number and an expiration date. Respondents
subject to the filing requirements of a rule will not be penalized for
failing to respond to these collections of information unless the
collections of information display a valid OMB control number.
58. This notice of proposed rulemaking proposes to amend the
Commission's regulations pursuant to section 206 of the Federal Power
Act, to eliminate compensation to generating facilities for the
provision of reactive power within the standard power factor range set
forth in each generating facility's individual interconnection
agreement. To accomplish this, the Commission proposes to require each
transmission provider to amend the standard large interconnection
agreement and the standard small generator interconnection agreement in
its open access transmission tariff to implement the reforms proposed
in this NOPR. Such filings should be made under Part 35 of the
Commission's regulations. Subsequently, the proposed rule would revise
the following currently approved information collections: FERC 516H
(OMB control. No. 1902-0303): Pro Forma Open Access Transmission
Tariff, FERC 516 (OMB control No. 1902-0096): Electric Tariff Filings,
and FERC 516A (OMB control No. 1902-0203): Standardization of Small
Generator Interconnection Agreements and Procedures [SGIA and SGIP].
59. The Commission is submitting these reporting requirements to
OMB for its review and approval under section 3507(d) of the Paperwork
Reduction Act. Comments are solicited on whether the information will
have practical utility, the accuracy of provided burden estimates, ways
to enhance the quality, utility, and clarity of the information to be
collected, and any suggested methods for minimizing the respondent's
burden, including the use of automated information techniques.
60. Please send comments concerning the collection of information
and the associated burden estimates to: Office of Information and
Regulatory Affairs, Office of Management and Budget, 725 17th Street
NW, Washington, DC 20503, Attention: Desk Officer for the Federal
Energy Regulatory Commission. Due to security concerns, comments should
be sent electronically to the following email address:
<a href="/cdn-cgi/l/email-protection#610e0813003e1214030c081212080e0f210e0c034f040e114f060e17"><span class="__cf_email__" data-cfemail="7c13150e1d230f091e11150f0f1513123c13111e5219130c521b130a">[email protected]</span></a>. Comments submitted to OMB should refer to
OMB Control No. 1902-0303, 1902-0096, or 1902-0203.
61. Please submit a copy of your comments on the information
collection to the Commission via the eFiling link on the Commission's
website at <a href="https://www.ferc.gov">https://www.ferc.gov</a>. If you are not able to file comments
electronically, please send a copy of your comments to: Federal Energy
Regulatory Commission, Secretary of the Commission, 888 First Street
NE, Washington, DC 20426. Comments on the information collection that
are sent to FERC should refer to Docket No. RM22-2-000.
62. Title: FERC 516H: Pro Forma Open Access Transmission Tariff,
FERC 516: Electric Tariff Filings, and FERC 516A: Standardization of
Small Generator Interconnection Agreements and Procedures [SGIA and
SGIP].
63. Action: Proposed revision of the information collection in
accordance with RM22-2-000.
64. OMB Control No.: 1902-0303, 1902-0096, 1902-0203.
65. Respondents for This Rulemaking: Public utility transmission
providers, including RTOs/ISOs.
66. Frequency of Information Collection: One-time compliance
filing.
67. Necessity of Information: The proposed rule will require that
transmission providers submit to the Commission a one-time compliance
filing proposing tariff revisions.
68. Internal Review: The Commission has reviewed the changes and
has determined that such changes are necessary. These requirements
conform to the Commission's need for efficient information collection,
communication, and management within the energy industry in support of
the Commission's ensuring just and reasonable rates. The Commission has
specific, objective support for the burden estimates associated with
the information collection requirements.
69. Public Reporting Burden: The Commission's estimate consists of
our estimated effort related to updating the proposed revisions to the
Pro Forma Open Access Transmission Tariff, and subsequent revisions to
the Large Generator Interconnection Agreements and Small Generator
Interconnection agreements and the effort related to submitting a one-
time compliance filing.
[[Page 21467]]
70. The Commission estimates burden \123\ and cost \124\ as
follows:
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\123\ ``Burden'' is the total time, effort, or financial
resources expended by persons to generate, maintain, retain, or
disclose or provide information to or for a Federal agency. For
further explanation of what is included in the estimated burden,
refer to 5 CFR 1320.3.
\124\ Commission staff estimates that the respondents' skill set
(and wages and benefits) for Docket No. RM22-13-000 are comparable
to those of Commission employees. Based on the Commission's Fiscal
Year 2024 average cost of $207,786/year (for wages plus benefits,
for one full-time employee), $100/hour is used.
--------------------------------------------------------------------------------------------------------------------------------------------------------
C. Annual
B. Number of number of D. Total E. Average burden hours & F. Total annual hour burdens G. Cost per
A. Collection respondents responses per number of cost per response & total annual cost respondent
respondent responses
(Column B x (Column D x.................. (Column F /
Column C) Column E).................... Column B)
--------------------------------------------------------------------------------------------------------------------------------------------------------
FERC 516H: Pro Forma Open Access Transmission Tariff
--------------------------------------------------------------------------------------------------------------------------------------------------------
Transmission Providers (one-time 40 1 40 4 hrs.; $400.............. 160 hrs.; $16,000............ $400
compliance filing).
--------------------------------------------------------------------------------------------------------------------------------------------------------
FERC 516: Electric Tariff Filings
--------------------------------------------------------------------------------------------------------------------------------------------------------
Transmission Providers (one-time 43 1 43 4 hrs.; $400.............. 172 hrs.; $17,200............ 400
compliance filing).
--------------------------------------------------------------------------------------------------------------------------------------------------------
FERC 516A: Standardization of Small Generator Interconnection Agreements and Procedures
--------------------------------------------------------------------------------------------------------------------------------------------------------
Transmission Providers (one-time 43 1 43 4 hrs.; $400.............. 172 hrs.; $17,200............ 400
compliance filing).
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Totals........................ ............ ............... ............ .......................... 504 hrs.; $50,400............ ............
--------------------------------------------------------------------------------------------------------------------------------------------------------
VI. Environmental Analysis
71. The Commission is required to prepare an Environmental
Assessment or an Environmental Impact Statement for any action that may
have a significant adverse effect on the human environment.\125\ We
conclude that neither an Environmental Assessment nor an Environmental
Impact Statement is required for this NOPR under Sec. 380.4(a)(15) of
the Commission's regulations, which provides a categorical exemption
for approval of actions under sections 205 and 206 of the FPA relating
to the filing of schedules containing all rates and charges for the
transmission or sale of electric energy subject to the Commission's
jurisdiction, plus the classification, practices, contracts, and
regulations that affect rates, charges, classification, and
services.\126\
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\125\ Reguls. Implementing the Nat'l Env't Pol'y Act, Order No.
486, 52 FR 47,897 (Dec. 17, 1987), FERC Stats. & Regs. Preambles
1986-1990 ] 30,783 (1987) (cross-referenced at 41 FERC ] 61,284).
\126\ 18 CFR 380.4(a)(15).
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VII. Regulatory Flexibility Act Certification
72. The Regulatory Flexibility Act of 1980 (RFA) \127\ generally
requires a description and analysis of proposed rules that will have
significant economic impact on a substantial number of small entities.
The Small Business Administration (SBA) sets the threshold for what
constitutes a small business. Under SBA's size standards,\128\
transmission providers under the category of Electric Bulk Power
Transmission and Control (NAICS code 221121), have a size threshold of
950 employees (including the entity and its associates).\129\
---------------------------------------------------------------------------
\127\ 5 U.S.C. 601-612.
\128\ 13 CFR 121.201.
\129\ The RFA definition of ``small entity'' refers to the
definition provided in the Small Business Act, which defines a
``small business concern'' as a business that is independently owned
and operated and that is not dominant in its field of operation. The
Small Business Administrations' regulations at 13 CFR 121.201 define
the threshold for a small Electric Bulk Power Transmission and
Control entity (NAICS code 221121) to be 500 employees. See 5 U.S.C.
601(3) (citing to Section 3 of the Small Business Act, 15 U.S.C.
632).
---------------------------------------------------------------------------
73. We estimate that there are 43 transmission providers that are
affected by the reforms proposed in this NOPR, based on the NERC Active
Compliance Registry Matrix as of January 11, 2024.\130\ The Commission
used a combination of sources to determine the number of employees
within each entity using open-source data and information from Dunn &
Bradstreet. We estimate that 6 of the 43 transmission providers,
approximately 14% (rounded), are small entities.
---------------------------------------------------------------------------
\130\ North American Electric Reliability Corporation, NCR
Active Entities List, (Jan. 12, 2024),
NERC_Compliance_Registry_Matrix_Excel.xlsx.
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74. We estimate that one-time costs (in Year 1) associated with the
reforms proposed in this NOPR for one transmission provider (as shown
in the table above) would be $400. Following Year 1, the Commission
estimates no ongoing costs associated with this proposed rule.
75. According to SBA guidance, the determination of significance of
impact ``should be seen as relative to the size of the business, the
size of the competitor's business, and the impact the regulation has on
larger competitors.'' \131\ We do not consider the estimated cost of
$400 to be a significant economic impact for any of the entities that
would be impacted by this NOPR. As a result, we certify that the
reforms proposed in this NOPR would not have a significant economic
impact on a substantial number of small entities.
---------------------------------------------------------------------------
\131\ U.S. Small Business Administration, A Guide for Government
Agencies How to Comply with the Regulatory Flexibility Act, 18 (Aug.
2017), <a href="https://cdn.advocacy.sba.gov/wp-content/uploads/2019/06/21110349/How-to-Comply-with-the-RFA.pdf">https://cdn.advocacy.sba.gov/wp-content/uploads/2019/06/21110349/How-to-Comply-with-the-RFA.pdf</a>.
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VIII. Comment Procedures
76. The Commission invites interested persons to submit comments on
the matters and issues proposed in this document to be adopted,
including any related matters or alternative proposals that commenters
may wish to discuss. Comments are due May 28, 2024. Also, reply
comments are due June 26, 2024. Comments must refer to Docket No. RM22-
2-000, and must include the commenter's name, the organization they
represent, if applicable, and their address in their comments. All
comments will be placed in the Commission's public files and may be
viewed, printed, or downloaded remotely as described in the Document
Availability section below. Commenters on this proposal are not
required to serve copies of their comments on other commenters.
77. The Commission encourages comments to be filed electronically
via the eFiling link on the Commission's website at <a href="https://www.ferc.gov">https://www.ferc.gov</a>. The Commission accepts most standard word processing
formats. Documents created electronically using word
[[Page 21468]]
processing software must be filed in native applications or print-to-
PDF format and not in a scanned format. Commenters filing
electronically do not need to make a paper filing.
78. Commenters that are not able to file comments electronically
may file an original of their comment by USPS mail or by courier-or
other delivery services. For submission sent via USPS only, filings
should be mailed to: Federal Energy Regulatory Commission, Office of
the Secretary, 888 First Street NE, Washington, DC 20426. Submission of
filings other than by USPS should be delivered to: Federal Energy
Regulatory Commission, 12225 Wilkins Avenue, Rockville, MD 20852.
IX. Document Availability
79. In addition to publishing the full text of this document in the
Federal Register, the Commission provides all interested persons an
opportunity to view and/or print the contents of this document via the
internet through the Commission's Home Page (<a href="https://www.ferc.gov">https://www.ferc.gov</a>).
80. From the Commission's Home Page on the internet, this
information is available on eLibrary. The full text of this document is
available on eLibrary in PDF and Microsoft Word format for viewing,
printing, and/or downloading. To access this document in eLibrary, type
the docket number excluding the last three digits of this document in
the docket number field.
81. User assistance is available for eLibrary and the Commission's
website during normal business hours from FERC Online Support at (202)
502-6652 (toll free at 1-866-208-3676) or email at
<a href="/cdn-cgi/l/email-protection#85e3e0f7e6eaebe9ecebe0f6f0f5f5eaf7f1c5e3e0f7e6abe2eaf3"><span class="__cf_email__" data-cfemail="ff999a8d9c90919396919a8c8a8f8f908d8bbf999a8d9cd1989089">[email protected]</span></a>, or the Public Reference Room at (202) 502-
8371, TTY 202-502-8659. Email the Public Reference Room at
<a href="/cdn-cgi/l/email-protection#9bebeef9f7f2f8b5e9fefdfee9fef5f8fee9f4f4f6dbfdfee9f8b5fcf4ed"><span class="__cf_email__" data-cfemail="bdcdc8dfd1d4de93cfd8dbd8cfd8d3ded8cfd2d2d0fddbd8cfde93dad2cb">[email protected]</span></a>.
By direction of the Commission.
Issued: March 21, 2024.
Debbie-Anne A. Reese,
Acting Secretary.
Note: The following appendix will not appear in the Code of
Federal Regulations.
Appendix A: List of Commenters
A. Initial Commenters
<bullet> Haley Benson
<bullet> Nikhil Bhushan
<bullet> Market Monitoring Unit of Southwest Power Pool, Inc.
<bullet> Charles T. Gaunt
<bullet> Duke Energy Corporation
<bullet> Wolverine Power Supply Cooperative, Inc.
<bullet> Nuclear Energy Institute
<bullet> PJM Interconnection, L.L.C.
<bullet> Electricity Consumers Resource Council
<bullet> Southwest Power Pool, Inc.
<bullet> California Independent System Operator Corporation
<bullet> State Agencies \1\
---------------------------------------------------------------------------
\1\ State Agencies consist of the Connecticut Attorney General,
the Connecticut Department of Energy and Environmental Protection,
the Connecticut Office of Consumer Counsel, the Delaware Attorney
General, the Delaware Division of the Public Advocate, the Office of
the People's Counsel for the District of Columbia, the Maine Office
of the Public Advocate, the Massachusetts Attorney General, the
Attorney General of the State of Michigan, the Minnesota Attorney
General, the Oregon Attorney General, and the Rhode Island Attorney
General.
---------------------------------------------------------------------------
<bullet> Electric Power Service Corporation
<bullet> Renewable Generation Companies \2\
---------------------------------------------------------------------------
\2\ Renewable Generation Companies consist of D.E. Shaw
Renewable Investments, L.L.C., EDF Renewables, Inc., EDP Renewables
North America LLC, Enel North America, Inc., Invenergy Renewables
LLC, Lightsource Renewable Energy Operations, LLC, NextEra Energy
Resources, LLC, Open Road Renewables, LLC, and RWE Renewables
Americas, LLC.
---------------------------------------------------------------------------
<bullet> Midcontinent Independent System Operator, Inc.
<bullet> Clean Energy Coalition \3\
---------------------------------------------------------------------------
\3\ Clean Energy Coalition consists of the Solar Energy
Industries Association, the American Clean Power Association,
Earthjustice, and the Natural Resources Defense Council.
---------------------------------------------------------------------------
<bullet> Pine Gate Renewables, LLC
<bullet> Edison Electric Institute
<bullet> National Rural Electric Cooperative Association
<bullet> New York Independent System Operator, Inc.
<bullet> ISO New England Inc.
<bullet> MISO Transmission Owners
<bullet> PJM Power Providers Group
<bullet> Vistra Corp. and Dynegy Marketing and Trade, LLC
<bullet> National Hydropower Association
<bullet> Alliant Energy Corporate Services, Inc.
<bullet> Dominion Energy Services, Inc.
<bullet> Los Angeles Department of Water and Power
<bullet> Leeward Renewable Energy, LLC, and Union of Concerned
Scientists
<bullet> EDF Renewables, Inc.
<bullet> Ameren Services Company
<bullet> Electric Power Supply Association
<bullet> Indicated Generation Owners \4\
---------------------------------------------------------------------------
\4\ Indicated Generation Owners consists of Ares EIF Management,
LLC, Brookfield Renewable Trading and Marketing LP, Cogentrix Energy
Power Management, LLC, and Eagle Creek Renewable Energy, LLC.
---------------------------------------------------------------------------
<bullet> Joint Customers \5\
---------------------------------------------------------------------------
\5\ Joint Customers consist of Old Dominion Electric
Cooperative, Northern Virginia Electric Cooperative, Inc., and
Dominion Energy Services, Inc.
---------------------------------------------------------------------------
<bullet> PSEG
<bullet> Independent Market Monitor for PJM
<bullet> American Electric Power Service Corporation
B. Reply Commenters
<bullet> Renewable Generation Companies
<bullet> Electric Power Supply Association
<bullet> Clean Energy Coalition
<bullet> Vistra Corp. and Dynegy Marketing and Trade, LLC
<bullet> EDF Renewables, Inc.
<bullet> PSEG
<bullet> Ameren Services Company
<bullet> Joint Customers
<bullet> MISO Transmission Owners
<bullet> Independent Market Monitor for PJM
[FR Doc. 2024-06556 Filed 3-27-24; 8:45 am]
BILLING CODE 6717-01-P
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