[Federal Register Volume 86, Number 227 (Tuesday, November 30, 2021)]
[Notices]
[Pages 67933-67942]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2021-26032]


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DEPARTMENT OF ENERGY

Federal Energy Regulatory Commission

[Docket No. RM22-2-000]


Reactive Power Capability Compensation

AGENCY: Federal Energy Regulatory Commission, Department of Energy.

ACTION: Notice of inquiry.

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SUMMARY: The Federal Energy Regulatory Commission (Commission) is 
inviting comments on reactive power

[[Page 67934]]

capability compensation and market design.

DATES: Initial Comments are due January 31, 2022, and Reply Comments 
are due February 28, 2022.

ADDRESSES: Comments, identified by docket number, may be filed in the 
following ways:
     Electronic Filing through http://www.ferc.gov. Documents 
created electronically using word processing software should be filed 
in native applications or print-to-PDF format and not in a scanned 
format.
     Mail/Hand Delivery: Those unable to file electronically 
may mail comments via the U.S. Postal Service to: Federal Energy 
Regulatory Commission, Secretary of the Commission, 888 First Street 
NE, Washington, DC 20426. Hand-delivered comments or comments sent via 
any other carrier should be delivered to: Federal Energy Regulatory 
Commission, 12225 Wilkins Avenue, Rockville, MD 20852.
    Instructions: For detailed instructions on submitting comments and 
additional information on the rulemaking process, see the Comment 
Procedures Section of this document.

FOR FURTHER INFORMATION CONTACT: 
Noah Schlosser (Technical Information), Federal Energy Regulatory 
Commission, 888 First Street NE, Washington, DC 20426, (202) 502-8356, 
[email protected]
Neil Yallabandi (Legal Information), Federal Energy Regulatory 
Commission, 888 First Street NE, Washington, DC 20426, (202) 502-8260, 
[email protected]

SUPPLEMENTARY INFORMATION:
    1. The Federal Energy Regulatory Commission (Commission) is issuing 
this Notice of Inquiry (NOI) to seek comments on reactive power 
capability compensation and market design.
    2. In an order issued in 2002,\1\ the Commission recommended that 
all resources that have actual cost data and support documentation use 
the method employed in American Electric Power Service Corporation to 
establish a rate for the provision of reactive power.\2\ Since the 
issuance of AEP, the electric markets and the generation resource mix 
have undergone significant change. For example, in 1999, when AEP 
issued, the majority of reactive power filings were made by synchronous 
resources that were owned by public utilities subject to the Uniform 
System of Accounts (USofA) and who annually submitted a FERC Form No. 
1.\3\ Today, the majority of the filings by entities seeking to 
establish a rate for reactive power capability compensation received at 
the Commission are made by owners of non-synchronous resources that 
produce reactive power using different types of equipment than used by 
synchronous resources. In addition, most filing entities (both 
synchronous and non-synchronous) received waivers of the requirement to 
maintain their accounts under the USofA rules and to file FERC Form No. 
1 when they were granted market-based rate (MBR) authority under Order 
No. 697.\4\ These changes have contributed, at least in part, to many 
such filings being set for hearing and settlement judge procedures.
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    \1\ WPS Westwood Generation, LLC, 101 FERC ] 61,290, at P 14 
(2002).
    \2\ Am. Elec. Power Serv. Corp., Opinion No. 440, 88 FERC ] 
61,141 (1999) (Opinion No. 440).
    \3\ The FERC Form No. 1 is a comprehensive financial and 
operating report submitted annually by Major electric utilities, 
licensees and others and used for electric accounting regulation, 
rate regulation, market oversight analysis, and planning audits. 18 
CFR 141.1.
    \4\ Market-Based Rates for Wholesale Sales of Electric Energy, 
Capacity and Ancillary Services by Public Utilities, Order No. 697, 
119 FERC ] 61,295, clarified, 121 FERC ] 61,260 (2007), order on 
reh'g, Order No. 697-A, 123 FERC ] 61,055, clarified, 124 FERC ] 
61,055, order on reh'g, Order No. 697-B, 125 FERC ] 61,326 (2008), 
order on reh'g, Order No. 697-C, 127 FERC ] 61,284 (2009), order on 
reh'g, Order No. 697-D, 130 FERC ] 61,206 (2010), aff'd sub nom. 
Mont. Consumer Counsel v. FERC, 659 F.3d 910 (9th Cir. 2011).
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    3. In light of these developments, we seek comment on various 
issues that have arisen regarding reactive power capability 
compensation and market design.

I. Background

A. Reactive Power and Regulation

    4. Almost all bulk electric power is generated, transported, and 
consumed in alternating current (AC) networks. Elements of AC systems 
supply and consume two kinds of power: Real power and reactive power. 
Real power accomplishes useful work (e.g., runs motors and lights 
lamps). Reactive power supports the voltages that must be controlled 
for system reliability. At times, resources must either supply or 
consume reactive power for the transmission system to maintain voltage 
levels required to reliably supply real power from generation to load. 
Inadequate reactive power supply lowers voltage; as voltage drops, 
current must increase to maintain the power supplied, causing the lines 
to consume more reactive power and the voltage to drop further, 
eventually leading to reliability problems such as loss of transmission 
system stability and voltage collapse.\5\
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    \5\ Payment for Reactive Power, Commission Staff Report, Docket 
No. AD14-7-000, at 4-6 (Apr. 22, 2014), https://www.ferc.gov/sites/default/files/2020-05/04-11-14-reactive-power.pdf.
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    5. In the Commission's pro forma LGIA, the power factor design 
criteria specify that, for synchronous resources, the ``Interconnection 
Customer shall design the Large Generating Facility to maintain a 
composite power delivery at continuous rated power output at the Point 
of Interconnection.'' \6\ For non-synchronous resources, the 
``Interconnection Customer shall design the Large Generating Facility 
to maintain a composite power delivery at continuous rated power output 
at the high side of the generator substation.'' \7\
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    \6\ See Pro Forma LGIA, Sec.  9.6.1.1.
    \7\ Id., Sec.  9.6.1.2.
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    6. Not only is reactive power necessary to operate the transmission 
system reliably, but it can also substantially improve the efficiency 
with which real power is delivered to customers. Increasing reactive 
power production at certain locations (usually near a load center) can 
sometimes alleviate transmission constraints and allow cheaper real 
power to be delivered into a load pocket.\8\
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    \8\ Id. at 7-8.
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    7. The rules for procuring reactive power can affect whether 
adequate reactive power supply is available, as well as whether the 
supply is procured efficiently from the most reliable and lowest-cost 
resources. This is readily apparent in the large portions of the United 
States where the transmission system is operated by regional 
transmission organizations (RTO) and independent system operators 
(ISO); these operators do not own generation and transmission 
facilities for producing and consuming reactive power and therefore 
must procure reactive power from others. But procurement rules also 
affect other parts of the United States where vertically integrated 
utilities operate the transmission system because reactive power 
capability is also available from independent companies.\9\ Therefore, 
it is necessary to ensure that system operators, whether they are 
independent or vertically integrated, have adequate reactive power 
supplies at a just and reasonable rate.
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    \9\ Id. at 11-13.
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    8. The modern history of compensation for reactive power begins 
with the Commission's Order No. 888, its Open Access Rule, issued in 
April 1996.\10\ In that order, the Commission

[[Page 67935]]

concluded that ``reactive supply and voltage control from generation 
sources'' is one of six ancillary services that transmission providers 
must include in an open access transmission tariff.\11\ The Commission 
noted that there are two approaches for supplying reactive power to 
control voltage: (1) Installing facilities as part of the transmission 
system and (2) using generation resources. The Commission concluded 
that the costs associated with the first approach would be recovered as 
part of the cost of basic transmission service and, thus, would not be 
a separate ancillary service. The second (using generation resources) 
would be considered a separate ancillary service and must be unbundled 
from basic transmission service. The Commission stated that, in the 
absence of proof that the generation seller lacks market power in 
providing reactive power, rates for this ancillary service should be 
cost-based and established as price caps, from which transmission 
providers may offer a discount.
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    \10\ Promoting Wholesale Competition Through Open Access 
Nondiscriminatory Transmission Services by Public Utilities; 
Recovery of Stranded Costs by Public Utilities and Transmitting 
Utilities, Order No. 888, FERC Stats. & Regs. ] 31,036, at 31,705-06 
and 31,716-17 (1996) (cross-referenced at 75 FERC ] 61,080), Order 
No. 888-A, FERC Stats. & Regs. ] 31,048 (cross-referenced at 78 FERC 
] 61,220), order on reh'g, Order No. 888-B, 81 FERC ] 61,248 (1997), 
order on reh'g, Order No. 888-C, 82 FERC ] 61,046 (1998), aff'd in 
relevant part sub nom. Transmission Access Policy Study Group v. 
FERC, 225 F.3d 667 (DC Cir. 2000), aff'd sub nom. New York v. FERC, 
535 U.S. 1 (2002).
    \11\ Order No. 888, FERC Stats. & Regs. ] 31,036 at 31,705. The 
pro forma open access transmission tariff (OATT) includes six 
schedules that set forth the details pertaining to each ancillary 
service. The details concerning reactive power are included in 
Schedule 2 of the pro forma OATT. Id. at 31,960.
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    9. In Opinion No. 440,\12\ the Commission approved a method 
presented by American Electric Power Service Corp. (AEP), a vertically 
integrated utility, for allocating the costs of generator equipment 
between real power capability and reactive power capability, as well as 
the related operations and maintenance costs. AEP identified four 
components of a generation plant related to the production of reactive 
power: (1) The generator and its exciter, (2) the generator step-up 
transformer, (3) accessory electric equipment that supports the 
operation of the generator-exciter, and (4) the remaining total 
production investment required to provide real power and operate the 
exciter. Because these plant items produce both real and reactive 
power, AEP developed an allocation factor to sort the annual revenue 
requirements of these components between real and reactive power 
production. The factor for allocating to reactive power, developed by 
AEP, is MVAR\2\/MVA\2\, where MVAR is megavolt amperes reactive 
capability and MVA is megavolt amperes capability at a power factor of 
1. Subsequently, the Commission indicated that all resources that have 
actual cost data and support should use AEP's methodology in seeking to 
recover reactive power capability costs pursuant to individual cost-
based revenue requirements (hereinafter, the AEP Methodology).\13\
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    \12\ AEP, Opinion No. 440, 88 FERC ] 61,141.
    \13\ WPS Westwood Generation, LLC, 101 FERC ] 61,290 at P 14; 
FPL Energy Marcus Hook, L.P., 110 FERC ] 61,087, at P 16, order on 
reh'g, 111 FERC ] 61,168 (2005).
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    10. In Order No. 2003,\14\ the Commission adopted standard large 
generator interconnection procedures and a standard agreement for the 
interconnection of large generation facilities (the pro forma Large 
Generator Interconnection Agreement (LGIA)), which included the 
requirement that interconnection customers maintain a power factor 
range of 0.95 leading to 0.95 lagging, unless the transmission provider 
has established a different power factor range.\15\ Order No. 2003 
required payment for reactive power to an interconnection customer only 
when the transmission provider requests the interconnection customer to 
operate its generating facility outside the established power factor 
range.\16\ With respect to reactive power within the established power 
factor range, the Commission initially concluded that an 
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.'' \17\ In Order 
No. 2003-A, however, 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.'' \18\ Subsequently, in Order No. 2003-C, the 
Commission disagreed with commenters that reactive power capability 
compensation would result in a windfall to generators, explaining that 
reactive power is an important service.\19\ Order No. 2003-A also 
exempted wind generators from maintaining the established power factor 
range.\20\
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    \14\ Standardization of Generator Interconnection Agreements and 
Procedures, Order No. 2003, 104 FERC ] 61,103 (2003), order on 
reh'g, Order No. 2003-A, 106 FERC ] 61,220, order on reh'g, Order 
No. 2003-B, 109 FERC ] 61,287 (2004), order on reh'g, Order No. 
2003-C, 111 FERC ] 61,401 (2005), aff'd sub nom. Nat'l Ass'n of 
Regulatory Util. Comm'rs v. FERC, 475 F.3d 1277 (D.C. Cir. 2007).
    \15\ Id. P 542.
    \16\ Id. P 546.
    \17\ Id.
    \18\ Order No. 2003-A, 106 FERC ] 61,220 at P 416.
    \19\ Order No. 2003-C, 111 FERC ] 61,401 at P 42.
    \20\ Order No. 2003-A, 106 FERC ] 61,220 at P 34.
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    11. Order No. 661 established technical requirements for 
interconnecting large wind resources and maintained the exemption from 
providing reactive power, except where the transmission provider 
showed, through a system impact study, that reactive power capability 
was required to ensure safety or reliability.\21\ In Order No. 
2006,\22\ the Commission adopted identical power factor and 
compensation requirements for small generating facilities (facilities 
having a capacity of no more than 20 MW) but exempted small wind 
generators from the reactive power requirement. In Order No. 827,\23\ 
the Commission eliminated the exemptions for wind resources from the 
requirement to provide reactive power. As a result, all newly 
interconnecting non-synchronous generators were required to provide 
reactive power within the range of 0.95 leading to 0.95 lagging at the 
high-side of the generator substation as a condition of 
interconnection. Order No. 827 also clarified that the amount of 
reactive power required from non-synchronous resources should be 
proportionate to the actual (real) power output.\24\ With respect to 
compensation, the Commission concluded that it did not have a 
sufficient record for determining a new methodology for non-synchronous 
generation reactive power compensation and stated that any non-
synchronous resource seeking reactive power compensation would need to 
propose a method for calculating that compensation as part of its 
filing.\25\
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    \21\ Interconnection for Wind Energy, Order No. 661, 111 FERC ] 
61,353, order on reh'g, Order No. 661-A, 113 FERC ] 61,254 (2005).
    \22\ Standardization of Small Generator Interconnection 
Agreements and Procedures, Order No. 2006, 111 FERC ] 61,220, order 
on reh'g, Order No. 2006-A, 113 FERC ] 61,195 (2005), order granting 
clarification, Order No. 2006-B, 116 FERC ] 61,046 (2006).
    \23\ Reactive Power Requirements for Non-Synchronous Generation, 
Order No. 827, 155 FERC ] 61,277, order on clarification and reh'g, 
157 FERC ] 61,003 (2016).
    \24\ Id. P 49.
    \25\ Id. PP 47, 52.
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B. Approaches to Reactive Power Capability Compensation

    12. In RTOs/ISOs where transmission providers compensate for 
reactive power capability, the compensation is either (1) based on 
individual reactive power revenue requirements determined in cases for 
individual resources (or fleets \26\ of resources) established pursuant 
to a cost-based methodology (e.g., the AEP

[[Page 67936]]

Methodology) using the resource's MVAR capability or (2) paid on a flat 
per-MVAR region-wide basis based on testing for the maximum MVAR 
capability of the resource. Resources in PJM Interconnection, Inc. 
(PJM) and Midcontinent Independent System Operator, Inc. (MISO) 
generally use the AEP Methodology to set reactive power compensation on 
an individual resource basis, whereas resources in ISO New England Inc. 
(ISO-NE) and New York Independent System Operator, Inc. (NYISO) are 
compensated for reactive power under a flat rate described further 
below. Outside of these RTOs/ISOs, when transmission providers pay for 
the capability to provide reactive power within the standard power 
factor range, resources generally propose to use the AEP Methodology to 
set reactive power compensation on an individual resource basis.\27\
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    \26\ Fleet-based rate schedules consist of a single rate for 
multiple resources, sometimes developed over an extended period of 
time, which do not specify which resources are being compensated 
under the rate schedule.
    \27\ In addition, California Independent System Operator 
Corporation (CAISO); Southwest Power Pool, Inc. (SPP); and some non-
RTO/ISO transmission operators (e.g., Bonneville Power 
Administration, Arizona Public Service Company, Southern Companies) 
do not pay for reactive power capability.
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    13. PJM and MISO compensate each resource owner with an amount 
equal to the resource owner's monthly reactive power capability service 
revenue requirement for reactive power capability, as accepted by the 
Commission. Although PJM and MISO both conduct regular reactive power 
capability testing,\28\ because they compensate based on the reactive 
power revenue requirements on file with the Commission, they do not 
link the tested capability to compensation, and neither PJM nor MISO is 
required to notify the Commission when a resource fails to achieve its 
nameplate MVAR capability when tested.
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    \28\ Under Schedule 2 of MISO's tariff, MISO's technical 
requirements dictate that within the past five years the generation 
resource meets the testing requirements for voltage control 
capability required by the Regional Reliability Council where the 
generation resource is located. See MISO, FERC Electric Tariff, 
Sched. 2, Sec.  II.B.3 (38.0.0). In PJM, resource owners are 
required to test 20% of their resources that receive reactive power 
capability compensation for reactive power capability annually, 
totaling 100% of such facilities over a 66 month period. However, 
individual resources that (1) have nameplate ratings below 20 MVA, 
(2) form part of aggregate generating facilities with nameplate 
ratings below 75 MVA, or (3) are not directly connected to the Bulk 
Electric System are exempt from these testing requirements. See PJM 
Manual 14D (Generator Operational Requirements), attach. E Sec.  
E.2.
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    14. ISO-NE and NYISO compensate resources for reactive power 
capability using a flat rate representing dollars per MVAR-year,\29\ 
which is multiplied by the resource's tested reactive power 
capability.\30\
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    \29\ Both ISO-NE and NYISO proposed their respective reactive 
power capability compensation mechanisms pursuant to section 205 
filings. See ISO New England Inc., 122 FERC ] 61,056, at P 1 (2008) 
(settling, in part, for a new flat rate in $/kVAR-yr). Note that, 
although NYISO also has a fixed rate for reactive power capability 
compensation, NYISO proposed the approach pursuant to an FPA section 
205 filing, with stakeholder support. N.Y. Indep. Sys. Operator, 
Inc., Docket No. ER02-617-000 (Feb. 5, 2002) (delegated order 
accepting NYISO's amended Rate Schedule 2 of the Market 
Administration and Control Area Services Tariff).
    \30\ ISO-NE, Transmission, Markets and Services Tariff, Schedule 
2--Reactive Supply and Voltage Control Service (10.0.0); NYISO, 
NYISO Market Administration and Control Area Services Tariff (MST), 
Section 15.2, Rate Schedule 2--Payments for Supplying Voltage Supply 
(11.0.0). ISO-NE and NYISO conduct reactive power capability testing 
at least once every five years and annually, respectively. See ISO-
NE, Transmission, Markets and Services Tariff, Schedule 2, Sec.  
IV.A.12(a); NYISO, NYISO MST, Section 15.2.2.1, Annual Payment for 
Voltage Support Service; NYISO, Ancillary Services Manual, Sec.  3.6 
(Oct. 2021).
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    15. In ISO-NE, reactive power compensation is established by 
adding: (a) A flat rate for capacity costs designed to compensate for 
fixed capital costs related to providing reactive power; (b) a variable 
rate for lost opportunity costs; (c) a variable rate for energy 
consumed to produce reactive power; and (d) a variable rate for costs 
for the resource to come online or to increase its output above its 
economic loading point.\31\ ISO-NE periodically adjusts the base flat 
rates for inflation.
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    \31\ See, e.g., Me. Pub. Utils. Comm'n v. ISO New England Inc., 
126 FERC ] 61,090, at P 6 (2009).
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    16. The NYISO flat rate is based on the average cost-of-service in 
NYISO for providing leading and lagging reactive power.\32\ In NYISO, 
the annual payment to qualified reactive power suppliers equals the 
product of the compensation rate and the sum of the lagging and the 
absolute value of the leading MVAR capacity \33\ of the resource, as 
evidenced by the resource's tested reactive power capability. NYISO 
adjusts the base flat rates annually for inflation. In NYISO, only the 
flat rate portion is paid.\34\
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    \32\ NYISO, Deficiency Letter Response, Docket No. ER15-1042-
001, at 1 (filed Apr. 30, 2015). NYISO explained that the $2,592/
MVAR flat rate was calculated ``by dividing the total VSS [Voltage 
Support Service] program compensation paid to qualified VSS 
Suppliers in 2012 by the total lagging and leading reactive power 
capability of all qualified VSS Suppliers in 2012.'' Voltage Support 
Service is the ability to produce or absorb reactive power and the 
ability to maintain a specific voltage level under both steady-state 
and post-contingency operating conditions subject to the limitations 
of the resource's stated reactive capability.
    \33\ Reactive power capability is measured in MVAR. A resource's 
lagging reactive power capability indicates its ability to produce 
reactive power, and its leading reactive power capability indicates 
its ability to consume reactive power.
    \34\ Like the AEP Methodology, these flat rates are intended to 
compensate resources for the costs of reactive power capability.
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II. Discussion

    17. Generation owners seeking compensation for reactive power 
capability in PJM, MISO, and non-RTO/ISO regions that compensate for 
reactive power capability based on the costs of individual resources or 
on a fleet-wide basis generally submit individual cost-of-service 
filings based on the AEP Methodology.\35\ As explained above, the AEP 
Methodology was designed based on the physical attributes of 
synchronous resources owned by a public utility that utilized the USofA 
and annually submitted a FERC Form No. 1. Since the AEP Methodology was 
established in 1999, the electric industry has undergone significant 
changes, both in the generation resource mix and a general shift away 
from cost-of-service rates for generators selling into Commission-
jurisdictional markets. Now, the majority of the reactive power filings 
submitted to the Commission are made by owners of non-synchronous 
resources that, relying on waivers granted by the Commission in 
conjunction with sellers obtaining MBR authority under Order No. 697, 
neither use the USofA nor file FERC Form No. 1. Because the AEP 
Methodology was designed based on the physical attributes of a 
synchronous resource and because of this lack of FERC Form No. 1 
information for independent power producers (synchronous and non-
synchronous alike), customers and the Commission have faced challenges 
in evaluating proposed reactive power rate schedules submitted pursuant 
to section 205 of the Federal Power Act (FPA), resulting in the 
majority of the filings being set for hearing and settlement 
procedures.
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    \35\ Am. Elec. Power Serv. Corp., 80 FERC ] 63,006, at 65,071 
(1997), aff'd in part, rev'd in part, Opinion No. 440, 88 FERC ] 
61,141 at 61,437 (establishing the AEP Methodology); see also WPS 
Westwood Generation, L.L.C., 101 FERC ] 61,290 at P 14 (recommending 
that all resources seeking to recover reactive power capability 
costs pursuant to individual cost-based revenue requirements use the 
AEP Methodology); Dynegy Midwest Generation, Inc., Opinion No. 498, 
121 FERC ] 61,025, at P 71 (2007), order on reh'g, 125 FERC ] 61,280 
(2008) (discussing the AEP Methodology and recovery of heating 
losses).
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    18. Furthermore, in PJM, several resources that have interconnected 
to the distribution system rather than the transmission system have 
still sought compensation from transmission operators for their 
reactive power capabilities.\36\ Monitoring Analytics, LLC, the 
Independent Market Monitor

[[Page 67937]]

for PJM (PJM Market Monitor), has argued that these resources are not 
technically capable of providing reactive power capability service 
consistent with Schedule 2 of PJM's tariff. Furthermore, it is unclear 
whether all such distribution-connected resources are technically 
capable of providing their full reactive power capability to the 
transmission system such that they are properly compensated through the 
applicable transmission rate schedules.\37\
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    \36\ See, e.g., Ingenco Wholesale Power, LLC, 173 FERC ] 61,247 
(2020) (Ingenco); Whitetail Solar 3, LLC, 173 FERC ] 61,288 (2020); 
Whitetail Solar 2, LLC, 174 FERC ] 61,238 (2021); Elk Hill Solar 2, 
LLC, 175 FERC ] 61,188 (2021); Mechanicsville Solar, LLC, 176 FERC ] 
61,076 (2021).
    \37\ See infra Section II.C.
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    19. Due to the aforementioned differences in the generation 
resource mix and divergent reporting requirements between market-based 
and cost-based sellers since the time when the AEP Methodology was 
established, the Commission seeks 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.

A. Issues With AEP Methodology-Based Reactive Power Compensation

    20. We wish to explore several potential issues with reactive power 
capability compensation based on the AEP Methodology. These include the 
failure to account for the degradation of a resource's reactive power 
capability over time, any difficulties associated with applying the AEP 
Methodology to non-synchronous resources, any difficulty in verifying 
the revenue requirements proposed by owners of resources that have been 
granted waiver of certain accounting and reporting requirements, and 
any potential overcompensation in PJM stemming from the reactive power 
offset used in the PJM capacity market.\38\
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    \38\ See infra notes 40-41, 47.
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1. Degradation
    21. Although the Commission has established that resources that 
seek reactive power capability compensation under the AEP Methodology 
are required to submit test reports of their reactive power capability 
that support the company's proposed level of reactive power capability 
for which the company is seeking a proposed reactive power revenue 
requirement,\39\ the AEP Methodology does not account for the fact that 
a resource's reactive power capability may degrade. As a result, over 
time the reactive power revenue requirement originally established 
under the AEP Methodology may no longer reflect the actual reactive 
power capability of the associated resource(s). However, unless a 
resource voluntarily files to revise its Commission-accepted revenue 
requirement or is otherwise required to do so under an applicable 
tariff, it will receive the same revenue over the course of its life, 
regardless of whether it maintains the capability to produce its stated 
power factor at its full real power capacity, which it supported with 
test reports at the time of its filing before the Commission. 
Furthermore, it can be difficult for the Commission to determine if the 
test reports accurately reflect the reactive power capability of the 
resource, particularly when the data the resource submits may be 
incomplete.\40\
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    \39\ The Commission required all resources to submit test 
reports when seeking a reactive power revenue requirement in Wabash 
Valley Power Ass'n, Inc., 154 FERC ] 61,245, at P 29 (2016); Wabash 
Valley Power Ass'n, Inc., 154 FERC ] 61,246, at P 28 (2016) 
(together, Wabash). The Commission also reiterated ``that revenue 
requirements established pursuant to Schedule 2 of the pro forma 
Open Access Transmission Tariff . . . are based on a particular 
level of reactive power capability for a particular generating unit 
or group of units'' and ``should reflect'' the present circumstances 
of the unit. See Wabash, 154 FERC ] 61,245 at P 28; 154 FERC ] 
61,246 at P 27.
    \40\ The test report data does not always support the revenue 
requirement, and a resource's test reports are one of the issues 
often set for hearing and settlement procedures. See, e.g., Talen 
Energy Mktg., LLC, 155 FERC ] 61,297, at P 9 (2016); Dynegy Lee II, 
LLC, 161 FERC ] 61,016, at P 16 (2017); Buckeye Power, Inc., 162 
FERC ] 61,145, at P 10 (2018); Ingenco, 173 FERC ] 61,247 at P 30.
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2. Accounting and Ratemaking Issues Related to Non-Synchronous 
Resources
    22. A lack of accounting and ratemaking guidance for non-
synchronous resources under the AEP Methodology has contributed to 
litigation over reactive power compensation.\41\ As noted above, the 
AEP Methodology was originally developed to determine the cost-of-
service for reactive power production equipment owned by cost-of-
service-regulated sellers and intended solely for synchronous 
resources. When compared to synchronous resources, non-synchronous 
resources have different physical processes and electric plant that is 
utilized in reactive power production. For example, relevant components 
of producing and controlling reactive power for synchronous resources 
include generator-exciters, step-up transformers, and accessory 
electric equipment. In contrast, non-synchronous resources may be 
capable of producing reactive power using only inverters.\42\ As a 
result, when non-synchronous resources propose reactive power revenue 
requirements based on the AEP Methodology, they generally propose to 
populate AEP Methodology cost categories with equipment different from 
those used by synchronous resources.
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    \41\ See Locke Lord LLP, 174 FERC ] 61,033 (2021).
    \42\ Typically, inverter-based resources will shut down without 
sufficient power supply; however, if configured to do so, some 
inverter-based resources can produce reactive power without real 
power. E.g., North American Electric Reliability Corporation, 
Reliability Guideline--BPS-Connected Inverter-Based Resource 
Performance at 34 (Sept. 2018), https://www.nerc.com/comm/PC_Reliability_Guidelines_DL/Inverter-Based_Resource_Performance_Guideline.pdf.
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    23. For example, although the original AEP Methodology did not 
contemplate inclusion of a collection system as equipment necessary for 
production of reactive power, applicants have claimed that the 
collection system is comparable to the isolated phase bus of a 
synchronous facility, which is considered part of accessory electric 
equipment costs for synchronous resources. The isolated phase bus of a 
synchronous resource carries current between a synchronous resource and 
its step-up transformer. An isolated phase bus may be several feet in 
length, whereas a collection system for a non-synchronous resource may 
exceed a mile in length. The typical collection system in a non-
synchronous resource uses multiple distribution voltage lines in a 
radial configuration to connect the power from the wind turbines or 
solar panels back to a central point, and the long length of the 
collector system lines causes reactive power losses. In comparison, the 
enclosed conductors of an isolated phase bus are short in length, thus 
causing much smaller reactive power losses, and provide fault 
protection between the synchronous resource and the step-up 
transformer. Due to these differences, the collection system of a non-
synchronous resource generally represents a significantly higher 
proportion of the resource's total investment cost than the isolated 
phase bus represents for synchronous resources. Thus, non-synchronous 
resources' interpretation of the AEP Methodology under this approach 
increases the annual revenue requirement for those resources on a 
relative basis as compared to the annual revenue requirements for 
synchronous resources. The Commission has yet to formally address any 
difference in cost structures across generation types for reactive 
power compensation under the AEP Methodology.
    24. Furthermore, the Commission's USofA does not include accounts 
that clearly accommodate non-hydro non-synchronous resources and 
associated operation and maintenance expenses. The Commission recently 
issued a separate NOI seeking input on whether

[[Page 67938]]

to create new accounts to accommodate these resources, how to modify 
FERC Form No. 1 to reflect any new accounts, and the rate setting 
implications, including for reactive power, of these potential 
accounting and reporting changes.\43\
---------------------------------------------------------------------------

    \43\ See Accounting and Reporting Treatment of Certain Renewable 
Energy Assets, 174 FERC ] 61,032, at P 3 (2021) (citations omitted) 
(``Recently, parties have expressed disagreement regarding which 
Other Production accounts should be used to book non-hydro renewable 
assets. In Docket No. AC20-103, the Commission received a request 
for confirmation that the costs of certain wind and solar generating 
equipment are properly booked to the Other Production Accounts 343 
(Prime Movers), 344 (Generators), and 345 (Accessory Electric 
Equipment). In that proceeding, commenters argued that the proposal 
booked an inappropriate amount of costs to Account 345, which are 
included in reactive power rates pursuant to the AEP Methodology. 
Commenters, including the Edison Electric Institute, suggested that 
the Commission consider creating new accounts for wind, solar, and 
other non-hydro renewables to resolve this issue.'').
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3. Evidentiary Support
    25. The AEP Methodology originally contemplated the use of USofA 
accounting structures and the sworn and attested-to accounting entries 
in the FERC Form No. 1 to support the proposed reactive power rates. 
This reliance enables resources to develop a cost-of-service rate that 
is verifiable by Commission staff and parties. However, the vast 
majority of resource owners currently applying for reactive power 
compensation reflecting the AEP Methodology received waivers of the 
Commission's accounting and reporting requirements when they were 
granted MBR authority under Order No. 697, meaning they do not submit 
the FERC Form No. 1, nor are they required to track their costs 
consistent with USofA accounting.\44\ Thus, when resources that have 
been granted these waivers propose revenue requirements using the AEP 
Methodology, it is difficult for the Commission and affected customers 
to easily verify that the proposed rates accurately reflect the AEP 
Methodology.
---------------------------------------------------------------------------

    \44\ Per Order No. 697, the Commission grants MBR sellers waiver 
of the accounting and reporting requirements in its approval of 
initial applications for MBR authority.
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4. Market-Based Compensation and Potential Overcompensation in PJM
    26. The PJM Market Monitor has argued for some time that the best 
approach to reactive power compensation in PJM is through the capacity 
market rather than compensation through a separate cost-of-service 
construct as currently provided for under Schedule 2 of the PJM 
Tariff.\45\ The PJM Market Monitor contends that cost-of-service 
compensation for reactive power capability is an anachronistic approach 
that predates the introduction of wholesale power markets and is 
unnecessary in light of potential compensation through the PJM markets. 
The PJM Market Monitor states that generating resources are required to 
have reactive capability to receive interconnection service. The PJM 
Market Monitor argues that Schedule 2 should be eliminated from the PJM 
tariff and PJM should rely on the capacity markets to ensure resource 
adequacy, including the capability to provide real power and reactive 
power at the lowest possible cost. More specifically, under the PJM 
Market Monitor's approach, if PJM's Schedule 2 were eliminated 
entirely, the gross costs of the entire plant, including any costs 
associated with the production of reactive power, would be included in 
the gross Cost of New Entry (CONE) and the generic offset for reactive 
power capability service compensation \46\ would no longer be used to 
calculate Net CONE.
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    \45\ See, e.g., PJM Market Monitor, Comments, Docket No. AD16-
17-000, at 1, 6-10 (filed Aug. 1, 2016) (detailing the PJM Market 
Monitor's view that reactive capability 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 at 523, https://www.monitoringanalytics.com/reports/PJM_State_of_the_Market/2020.shtml (describing the PJM Market 
Monitor's position and recommended improvements).
    \46\ The Energy and Ancillary Services Offset (E&AS Offset) is 
used to calculate Net CONE in the PJM capacity market and it 
includes a revenue offset of $2,199/MW-year to reflect the average 
annual reactive power revenue for combustion turbines from 2005 
through 2007, based on the actual costs reported to the Commission 
in reactive power capability service filings of combustion turbines. 
The result of this offset is that, conceptually, the cost of 
reactive capability is not part of Net CONE.
---------------------------------------------------------------------------

    27. The PJM Market Monitor alternatively argues that, if PJM 
retains Schedule 2, Schedule 2 should be revised to avoid the potential 
overpayment for reactive power capability.\47\ The PJM Market Monitor 
explains that the E&AS Offset associated with the reference resource in 
the capacity market is assumed to recover $2,199/MW-year in reactive 
power payments. The PJM Market Monitor states that, as a result of the 
offset rules, reactive power capability rates of up to $2,199/MW-year, 
do not result in double recovery for reactive power capability. On the 
other hand, the PJM Market Monitor contends that any separate reactive 
power capability payments through Schedule 2 that exceed $2,199/MW-year 
result in overcompensation as such costs can and should be recovered 
through the capacity market. In short, the PJM Market Monitor contends 
that when the market design allows for the recovery of specific costs 
for reactive power capability, it is inappropriate to also include 
those costs in a separate cost-of-service rate.
---------------------------------------------------------------------------

    \47\ See, e.g., PJM Market Monitor, Comments, Docket No. AD16-
17-000, at 8, 10 (filed Aug. 1, 2016) (explaining that ``[i]f 
revenues for reactive capacity were removed from the Net Energy and 
Ancillary Services Revenue Offset, then the fixed costs for 
investment in reactive capability would be recoverable through the 
capacity market,'' obviating the need for separate cost-of-service 
reactive power rates); PJM Market Monitor, Brief on Exceptions, 
Docket No. ER17-1821-002, at 3-16 (filed June 12, 2019) (discussing 
the PJM Market Monitor's concerns about what it termed a ``hybrid of 
market-based rates and cost of service rates''); PJM Market Monitor, 
Rehearing Request, Docket No. ER17-1821-005, at 3-5 (filed Apr. 30, 
2021) (addressing issues regarding the E&AS Offset and a generator's 
proposed reactive power rates).
---------------------------------------------------------------------------

5. Questions Regarding AEP Methodology-Based Compensation
    28. Given the backdrop of the issues discussed herein, we wish to 
explore in this NOI, whether the AEP Methodology remains a just and 
reasonable approach to determining reactive power revenue requirements 
in all circumstances. We encourage comments regarding the topics 
broadly discussed above. The following questions are designed to 
identify potential modifications to the AEP Methodology and related 
market designs and reporting requirements necessary to ensure just and 
reasonable rates for reactive power capability compensation. Commenters 
need not answer every question enumerated below.
    a. Does compensating resources based on their costs of investment 
in reactive power capability continue to be the appropriate basis for 
reactive power capability compensation? Why or why not?
    i. If so, does the AEP Methodology accurately reflect a resource's 
investment costs? Why or why not? To the extent your answer depends on 
the type of resource, please be specific.
    b. What is the appropriate time period for compensation from a rate 
developed under the AEP Methodology? Should payments be limited based 
on the useful lives of the plant at issue? Why or why not?
    c. As noted earlier, the power factor design criteria in the 
Commission's pro forma LGIA specify that the Large Generating Facility 
should be designed to maintain a composite power delivery at continuous 
rated power output, either at the Point of Interconnection for 
synchronous resources or at the high side of the generator substation 
for non-synchronous resources. Given this, when a resource conducts 
testing to demonstrate its reactive power capability, over what minimum 
amount

[[Page 67939]]

of time should a resource be required to maintain its maximum real 
power output while operating across its claimed reactive power factor 
range? Please specify to which type(s) of resource your proposed 
minimum time period corresponds.
    i. The Commission has found that, to the extent the resource has 
established that it is able to produce reactive power up to its 
nameplate capability, a resource may use up to its nameplate power 
factor in calculating its reactive power revenue requirements.\48\ Is 
there any reason for the Commission to believe that the nameplate 
capability aspect of calculating reactive power revenue requirements 
should be revised in order to produce a more accurate result? Why or 
why not? If so, in what manner (for example, should the power factor 
range identified in the interconnection agreement be considered)?
---------------------------------------------------------------------------

    \48\ See, e.g., Panda Stonewall LLC, 174 FERC ] 61,266, at PP 
99, 107-109 (2021) (finding that a reactive power supplier was 
entitled to use its nameplate power factor in calculating its 
reactive power revenue requirement, rather than being limited to the 
power factor specified in its interconnection agreement, since the 
facility was a new synchronous generator facility and degradation of 
its reactive power output was not an issue).
---------------------------------------------------------------------------

    d. Many resources have an interconnection agreement in which 
reactive power requirements are addressed; however, to the extent that 
reactive power capability requirements are not addressed in a 
resource's interconnection agreement and a resource seeks compensation 
for supplying reactive power capability, how should the Commission 
address this? For example, should the Commission require that the 
resource and its transmission provider propose updates or additions to 
the interconnection agreement to specify the resource's reactive power 
capability requirements as a condition of establishing or maintaining a 
reactive power revenue requirement or should other methods be used in 
this regard?
    e. Reactive power filings set for hearing and settlement judge 
procedures often do not have active intervening parties other than the 
market monitor and RTO/ISO. Why do other parties not participate more 
in these proceedings?
a. Degradation
    f. How does a resource's reactive power capability degrade over 
time? Does the degradation follow a predictable pattern over a certain 
period of time? Does this answer vary depending on the generation type, 
real power capacity, and/or other aspects of a particular resource? If 
so, how?
    i. Should resources receiving reactive power capability 
compensation undergo periodic reactive power capability testing to 
demonstrate that their reactive power capability compensation remains 
accurate?
    1. If so, how frequently should this testing be performed?
    2. Should the frequency of testing be influenced by other factors, 
including the generation type, real power capacity, and/or other 
aspects of a particular resource?
    3. Is there a period after a new resource begins operating during 
which testing is unnecessary? If so, what is the appropriate length of 
this period and why? Please clarify which type of resource(s) this 
period should apply to and why.
    4. Should reactive power capability compensation in all cases be 
linked to tested capability? If not, why not? If so, how? And, if so, 
should test results be updated and how frequently?
    g. Should the AEP Methodology be modified to account for reactive 
power capability degradation over the lifetime of the resource and, if 
so, how?
    i. If the Commission makes such a modification, should the revised 
methodology only consider the resource's most recent reactive power 
capability testing results, or should the Commission incorporate 
degradation curves or other processes to estimate continued degradation 
between tests? If using degradation curves, should this methodology 
vary by resource type? If so, how? Should a resource have the 
opportunity to rebut the application of a degradation curve if it can 
demonstrate that its test results exceed the estimate derived from a 
degradation curve?
    ii. Should the Commission adopt a standard minimum testing 
frequency for resources that receive reactive power capability 
compensation? If not, why not? If so, what time period should the 
minimum frequency be (e.g., testing required annually, biannually, 
every five years, etc.)? Please indicate to which type(s) of resources 
your proposed minimum frequency corresponds.
    h. Over what time period does the NERC MOD-25-2 Reliability 
Standard \49\ accurately represent a resource's capability to provide 
reactive power?
---------------------------------------------------------------------------

    \49\ The NERC MOD-25-2 standard refers to verification and data 
reporting of generator real and reactive power capability as well as 
synchronous condenser reactive power capability. Under this 
standard, each Generator Owner shall provide its Transmission 
Planner with verification of the Reactive Power capability of its 
applicable facilities within 90 calendar days of the date the data 
is recorded for a staged test or the date the data is selected for 
verification using historical operating data. Reliability Standard 
MOD-25-2 (Verification and Data Reporting of Generator Real and 
Reactive Power Capability and Synchronous Condenser Reactive Power 
Capability), at Requirement R2.
---------------------------------------------------------------------------

    i. For how long is this data valid? Please explain.
    ii. If these standards do not accurately represent a resource's 
reactive power capability, what additional data should resources 
provide to verify their reactive power capability? Should this data 
vary by resource type? If so, how and why?
    i. Are there maintenance activities needed to maintain reactive 
power capability that do not also contribute to real power capability?
    i. If so, what percentage of a generating facility's operating and 
maintenance budget is necessary to maintain reactive power capability?
    ii. Does this differ by type of generating resource? If so, how?
b. Non-Synchronous Resources
    j. Is the existing AEP Methodology appropriate to allocate the 
costs associated with reactive power revenue requirements of non-
synchronous resources? If not, why and can changes be made to the 
existing AEP Methodology to establish just and reasonable reactive 
power revenue requirements for non-synchronous resources? If so, please 
provide detailed descriptions of any potential changes and explain why 
they are necessary.
    k. As discussed above,\50\ the AEP Methodology determines a 
resource's cost of reactive power capability by applying an allocation 
factor to four groups of costs that are involved in the production or 
consumption of reactive power for a synchronous resource: (1) The 
generator and exciter, (2) the step-up transformer, (3) accessory 
electric equipment used to support the operation of the generator and 
exciter, and (4) the remaining production plant investment. For each of 
these groups of costs, assuming that the non-synchronous resource type 
can provide reactive power capability, please identify what non-
synchronous resource equipment corresponds to the synchronous resource 
equipment used in the AEP Methodology and how that equipment is related 
to the production of reactive power. Please explain if that equipment 
is also related to the production of real power. Please specify if the 
equipment identified is specific to a type of non-synchronous resource 
(e.g., wind, solar, battery).
---------------------------------------------------------------------------

    \50\ See supra Section I.
---------------------------------------------------------------------------

    i. In the alternative, please describe what groups of costs are 
involved in the production or consumption of reactive

[[Page 67940]]

power for a non-synchronous resource and how a non-synchronous 
resource's equipment would be allocated to each of those groups. Please 
explain if these groups are involved in the production or consumption 
of power other than reactive power.
    l. Which, if any, of the four groups under the AEP Methodology do 
costs associated with the collection system of a non-synchronous 
resource fall into and why?
    i. If they do not fall into any of those groups, should those costs 
related to the collection system be recovered? Why?
    ii. Is the collection system comparable to the isolated phase bus 
of a synchronous resource? Why or why not? In what ways are they 
similar and in what ways are they different? What other aspects of a 
non-synchronous resource does a collection system serve?
    m. Please explain whether it is necessary for a Type 3 wind 
turbine,\51\ Type 4 wind turbine,\52\ or solar PV facility to produce 
real power at a particular time in order for the resource to provide 
reactive power capability at that time.
---------------------------------------------------------------------------

    \51\ Type 3 wind turbines have doubly-fed induction generators 
with rotor terminals connected to power converters. The stator 
terminals of Type 3 wind turbines are directly connected to the bulk 
electric system.
    \52\ Type 4 wind turbines use either synchronous or asynchronous 
generators with generator stator terminals connected to a power 
converter. The power converters of Type 4 wind turbines are directly 
connected to the bulk electric system.
---------------------------------------------------------------------------

    i. If so, what are the implications, if any, for the current 
proportionality requirement on reactive power from non-synchronous 
resources?
    n. Should the AEP Methodology be altered to account for the 
intermittent availability of some non-synchronous resources? Why or why 
not?
    o. Solar resources can be designed with power factors much lower 
than those of synchronous resources,\53\ which implies a much higher 
reactive power capability and results in higher revenue requirements 
under current application of the AEP Methodology for solar generating 
facilities versus a comparable synchronous resource, all else being 
equal. Should the AEP Methodology be altered to account for this 
difference? Why or why not?
---------------------------------------------------------------------------

    \53\ See, e.g., Delta's Edge Solar, LLC, Exhibit DES-1, Docket 
No. ER21-1452-000, at 8 (filed Mar. 16, 2021); Crossett Solar 
Energy, LLC, Exhibit CSE-1, Docket No. ER21-1453-000, at 8 (filed 
Mar. 16, 2021).
---------------------------------------------------------------------------

    i. Refer to Section II.A.5, question l.i. Would allocating the 
costs of solar generating facilities into cost categories different 
from those categories defined under the AEP Methodology, and using a 
solar generating facility's power factor, result in a revenue 
requirement more or less comparable to that of a synchronous generating 
facility, all else being equal?
c. Evidentiary Support
    p. What options are available to collect independently verifiable 
cost information from MBR sellers that have received waiver of the 
accounting and FERC Form No. 1 requirements to support their reactive 
power capability revenue requirements? For example, how should MBR 
sellers that receive reactive power capability compensation track their 
equipment costs and support their proposed reactive power revenue 
requirements?
    q. In order to simplify and provide transparency to proposed 
reactive power capability compensation filings, should the Commission 
require, in PJM, MISO, and non-RTO/ISO regions that compensate for 
reactive power capability based on the costs of individual resources or 
on a fleet-wide basis, reactive power filers to include with their 
filing a standardized form with recognized schedules and officer and 
independent accountant certification requirements? Please explain why 
or why not.
    i. Would the standardized form allow for better comparisons between 
reactive power rates and/or allow the reactive power rates to be more 
easily refreshed to reflect degradation or other changes to reactive 
power capability? If not, why not?
    ii. Should the form contain similar information as the relevant 
USofA accounts used in the AEP Methodology? If not, why not? If yes, 
please specify the types of information that would be necessary to 
calculate a reactive power revenue requirement.
    iii. If the Commission pursued a standardized form approach, what 
cost support should be included in a standardized form?
d. Potential Overcompensation in PJM
    r. Refer to the PJM Market Monitor's concerns regarding the 
potential in PJM of overpayment for reactive power capability.\54\ In 
PJM and other RTOs/ISOs with centralized capacity markets, how do 
resources typically account for revenues from reactive power 
compensation when calculating their capacity offers?
---------------------------------------------------------------------------

    \54\ See supra Section II.A.4.
---------------------------------------------------------------------------

    i. If a resource accounts for revenues from reactive power 
compensation when calculating its capacity offers, does that approach 
ensure that the resource does not receive double compensation for 
providing reactive power capability service? Please explain why or why 
not.
    ii. Please explain how the lack of accounting for revenues from 
reactive power compensation when calculating resources' capacity offers 
does not constitute double compensation.
    s. Do resources in PJM that receive reactive power capability 
compensation above $2,199/MW-year effectively receive double-recovery 
as alleged by the PJM Market Monitor?
    i. If so, how should such overcompensation be corrected?
    ii. If not, please explain why no double-recovery occurs.

B. Alternative Methodologies

    29. As noted above, the AEP Methodology is currently used as the 
Commission's approach to developing revenue requirements for reactive 
power capability in PJM, MISO, and by transmission providers in non-
RTO/ISO regions. The Commission, in this NOI, would like to explore 
whether other potential alternative methodologies not based on the 
costs of the particular resource(s) at issue in a given proceeding 
should be considered or better used to develop reactive power 
capability revenue requirements.
    30. One possible alternative approach is a flat rate methodology, 
which would be based on the total reactive power payments made by 
transmission customers in a region divided by the MVARs consumed in the 
region. This ``dollars per MVAR-year'' value may be determined either 
for each class of resource (solar, wind turbine, combined-cycle, 
combustion turbine, and hydroelectric) or a single value could be paid 
to all classes of resources similar to the approach used in ISO-NE and 
NYISO. We seek comment on the potential benefits and drawbacks of using 
any flat rate methodology for reactive power capability compensation.
    31. Another possible approach to reactive power capability 
compensation is replacement cost ratemaking. Under this approach, the 
lowest-cost technology capable of providing reactive power capability, 
such as a synchronous condenser, is used to establish a per-MVAR-year 
rate. Then, all resources would be paid the same amount based upon 
their tested MVAR capability. Replacement cost ratemaking derives from 
the Supreme Court's decision in Smyth v. Ames,\55\ in which the Court 
indicated that appropriate rate base is

[[Page 67941]]

based on the replacement cost or fair value of the rate base.\56\ Such 
a replacement cost approach could also form a benchmark for evaluating 
the justness and reasonableness of proposed reactive power capability 
revenue requirements, where any proposed rates above the cost of the 
alternative technology would be considered unjust and unreasonable 
unless the record demonstrates that the resource's costs of investment 
in reactive power capability supports the proposed revenue requirement.
---------------------------------------------------------------------------

    \55\ 169 U.S. 466 (1898). The U.S. Supreme Court permitted the 
Commission to use original cost ratemaking in place of replacement 
or reproduction cost given the difficulty of determining fair value 
in most cases. FPC v. Hope Nat. Gas Co., 320 U.S. 591 (1944).
    \56\ Smyth, 169 U.S. at 544 (``the rights of the public would be 
ignored if rates for the transportation of persons or property on a 
railroad are exacted without reference to the fair value of the 
property used for the public'').
---------------------------------------------------------------------------

1. Questions Regarding Alternative Methodologies
    32. We encourage comments regarding the topics discussed above in 
this section. The following questions are designed to explore further 
potential alternative methodologies. Commenters need not answer every 
question enumerated below.
    a. Should alternative methodologies to the AEP Methodology be 
considered for the calculation of reactive power capability revenue 
requirements? If not, why not? If so, what alternative methodologies to 
the AEP Methodology could be used for calculating reactive power 
revenue requirements that would accurately capture the cost of 
providing reactive power capability? Please clarify if any methodology 
is specific to certain types of resources or not. For example, what 
methodology could appropriately account for the technical 
characteristics of non-synchronous resources that do not exist in 
synchronous resources? How would developing revenue requirements under 
such a new methodology compare to developing revenue requirements using 
the AEP Methodology?
    b. Should a flat rate approach to reactive power compensation 
differ depending on the type of resource, or should one rate be used 
for all resource types?
    c. Under a flat rate approach:
    i. How should the rate be initially set, and how would it be 
adjusted over time (e.g., for inflation)?
    ii. Should payments to a specific resource be based on the 
resource's tested reactive power capability or its actual reactive 
power output?
    iii. How often should the resource's reactive power capability be 
tested?
    d. Under a replacement cost approach:
    i. What alternative technology should be used to establish the rate 
and how should that alternative technology be determined?
    ii. How often should the alternative technology used to establish 
the rate be reevaluated?
    e. Would a change to a flat rate or replacement rate approach 
require resources to change any of their accounting, record keeping or 
any other administrative processes?
    i. Would such a change have an impact on capital investment 
decisions? Are there any other effects that such a change would cause? 
If possible, please provide numbers to quantify statements.
    f. In regions such as CAISO and SPP, where resources are not 
directly compensated for their reactive power capabilities, how do 
resources recover the costs of their investment in reactive power 
capability?
    g. Refer to the PJM Market Monitor's proposal to provide for 
reactive power compensation in PJM through the capacity market rather 
than through a separate cost-of-service construct.\57\ In regions with 
a centrally-cleared capacity market, would it be preferable for 
resources to recover the costs of their investment in reactive power 
capability by embedding those costs in their capacity market offers, 
rather than using a separate cost-based rate? Please describe any 
advantages or disadvantages to this approach and any modifications this 
would require in the applicable region's OATT and market rules.
---------------------------------------------------------------------------

    \57\ See supra Section II.A.4.
---------------------------------------------------------------------------

C. Distribution-Connected Resources

    33. The Commission has previously found that a transmission 
provider need not provide compensation to resources for reactive power 
if the resource is not under the control of the control area 
operator.\58\ Schedule 2 of the pro forma OATT similarly requires that 
generation facilities and non-generation resources capable of providing 
reactive power be ``under the control of the control area operator.''
---------------------------------------------------------------------------

    \58\ Otter Tail Power Co., 99 FERC ] 61,019, at 61,092 (2002).
---------------------------------------------------------------------------

    34. In several recent cases,\59\ the PJM Market Monitor has 
challenged the eligibility of distribution-connected resources with 
Commission-jurisdictional interconnection agreements to receive 
compensation for reactive power capability (within the standard power 
factor range) under Schedule 2 of PJM's tariff.\60\ The PJM Market 
Monitor has argued in these cases that such resources should not 
receive reactive power compensation from PJM because the resources have 
not established that they provide reactive power capability service to 
the PJM transmission system, as required by Schedule 2.\61\ The PJM 
Market Monitor likens such resources to pseudo-tied resources, which 
are excluded from eligibility to file for reactive power compensation 
under Schedule 2 of PJM's tariff. Other protestors have also argued 
that distribution-connected resources are not under the operational 
control of the transmission system operator and therefore cannot 
provide reactive power capability service consistent with the PJM 
tariff.\62\
---------------------------------------------------------------------------

    \59\ See supra note 36.
    \60\ Schedule 2 of PJM's tariff is nearly identical to Schedule 
2 of the pro forma OATT. It provides in relevant part as follows 
(emphasis added):
    In order to maintain transmission voltages on the Transmission 
Provider's transmission facilities within acceptable limits, 
generation facilities and non-generation resources capable of 
providing this service that are under the control of the control 
area operator are operated to produce (or absorb) reactive power. 
Thus, Reactive Supply and Voltage Control from Generation or Other 
Sources Service must be provided for each transaction on the 
Transmission Provider's transmission facilities. The amount of 
Reactive Supply and Voltage Control from Generation or Other Sources 
Service that must be supplied with respect to the Transmission 
Customer's transaction will be determined based on the reactive 
power support necessary to maintain transmission voltages within 
limits that are generally accepted in the region and consistently 
adhered to by the Transmission Provider.
    \61\ See, e.g., Mechanicsville Solar, LLC, Protest of the 
Independent Market Monitor for PJM, Docket No. ER21-2091-000 (filed 
June 28, 2021).
    \62\ See, e.g., Northern Virginia Electric Cooperative, Inc., 
Old Dominion Electric Cooperative, and Dominion Energy Services, 
Inc. on behalf of Virginia Electric and Power Company; 
Mechanicsville Solar, LLC, Protest and Comments Monitor for PJM, 
Docket No. ER21-2091-000 (filed June 25, 2021).
---------------------------------------------------------------------------

    35. We are interested in exploring the PJM Market Monitor's 
concerns further, as well as whether these concerns are relevant for 
other regions.
1. Questions Regarding Distribution-Connected Resources
    36. The Commission encourages comments regarding the topics broadly 
discussed above. The following questions are designed to identify 
whether resources in PJM and elsewhere that are interconnected to a 
distribution system and participate in wholesale markets are 
technically capable of providing reactive power to the transmission 
system in such a way that these resources should be eligible for 
reactive power capability compensation through transmission rates. 
Commenters need not answer every question enumerated below.
    a. For a distribution-connected resource, is reactive power 
dispatchable by direction of the transmission provider? Please explain, 
including whether the answer to this question depends on whether the 
resource has a

[[Page 67942]]

Commission-jurisdictional interconnection agreement with the 
transmission system owner/operator and whether the resource is 
synchronous or non-synchronous.
    b. If reactive power produced by a distribution-connected resource 
cannot be dispatched by the transmission system operator to provide 
voltage support to the transmission system, should a distribution-
connected resource be compensated through transmission rates for its 
reactive power capability? Why or why not?
    c. If distribution-connected resources are dispatchable for 
reactive power by the transmission provider, to what extent are 
distribution-connected resources able to provide reactive power 
capability service to the transmission system? Are there physical 
characteristics (e.g., distribution-connected resource characteristics 
and location, system topology, etc.) or other indicators that could be 
analyzed to determine accurately whether a distribution connected 
resource is able to provide reactive power capability service to the 
transmission system?
    d. Are resources connected to a distribution system subject to 
reactive power capability testing requirements? If so, what are those 
requirements?

III. Comment Procedures

    37. The Commission invites interested persons to submit comments on 
the matters and issues proposed in this notice, including any related 
matters or alternative proposals that commenters may wish to discuss. 
Initial Comments are due January 31, 2022, and Reply Comments are due 
February 28, 2022. 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.
    38. The Commission encourages comments to be filed electronically 
via the eFiling link on the Commission's website at http://www.ferc.gov. The Commission accepts most standard word processing 
formats. Documents created electronically using word processing 
software should 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.
    39. Those unable to file electronically may mail comments via the 
U.S. Postal Service to: Federal Energy Regulatory Commission, Secretary 
of the Commission, 888 First Street NE, Washington, DC, 20426. Hand-
delivered comments or comments sent via any other carrier should be 
delivered to: Federal Energy Regulatory Commission, 12225 Wilkins 
Avenue, Rockville, MD 20852.
    40. 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.

IV. Document Availability

    41. 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 (http://www.ferc.gov). At 
this time, the Commission has suspended access to the Commission's 
Public Reference Room due to the President's March 13, 2020 
proclamation declaring a National Emergency concerning the Novel 
Coronavirus Disease (COVID-19).
    42. 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.
    43. User assistance is available for eLibrary and the Commission's 
website during normal business hours from the Commission's Online 
Support at 202-502-6652 (toll free at 1-866-208-3676) or email at 
[email protected], or the Public Reference Room at (202) 502-
8371, TTY (202)502-8659. Email the Public Reference Room at 
[email protected].

    By direction of the Commission.

    Issued: November 18, 2021.
Kimberly D. Bose,
Secretary.
[FR Doc. 2021-26032 Filed 11-29-21; 8:45 am]
BILLING CODE 6717-01-P


