93410 Federal Register / Vol. 89, No. 228 / Tuesday, November 26, 2024 / Rules and Regulations 

1Section 201(e) of the FPA, 16 U.S.C. 824(e), 

defines ‘‘public utility’’ to mean ‘‘any person who 

owns or operates facilities subject to the jurisdiction 

of the Commission under this subchapter.’’ As 

stated in the Order No. 888 pro forma OATT, 

‘‘transmission provider’’ is a ‘‘public utility (or its 

Designated Agent) that owns, controls, or operates 

facilities used for the transmission of electric energy 

in interstate commerce and provides transmission 

service under the Tariff.’’ Promoting Wholesale 

Competition Through Open Access NonDiscriminatory Transmission Servs. by Pub. Utils.; 

Recovery of Stranded Costs by Pub. Utils. & 

Transmitting Utils., Order No. 888, FERC Stats. & 

Regs. ¶ 31,036 (1996) (cross-referenced at 75 FERC 

¶ 61,080), order on reh’g, Order No. 888–A, FERC 

Stats. & Regs. ¶ 31,048 (cross-referenced at 78 FERC 

¶ 61,220), order on reh’g, Order No. 888–B, 81 FERC 

¶ 61,248 (1997), order on reh’g, Order No. 888–C, 

82 FERC ¶ 61,046 (1998), aff’d in relevant part sub 

nom. Transmission Access 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); Pro forma OATT 

section I.1 (Definitions). The term ‘‘transmission 

provider’’ includes a public utility transmission 

owner when the transmission owner is separate 

from the transmission provider, as is the case in 

regional transmission organizations (RTO) and 

independent system operators (ISO). 

DEPARTMENT OF ENERGY 

Federal Energy Regulatory 

Commission 

18 CFR Part 35 

[Docket No. RM22–2–000; Order No. 904] 

Compensation for Reactive Power 

Within the Standard Power Factor 

Range 

AGENCY: Federal Energy Regulatory 

Commission. 

ACTION: Final determination. 

SUMMARY: In this final determination, 

the Federal Energy Regulatory 

Commission (Commission) finds that 

allowing transmission providers to 

charge transmission customers for a 

generating facility’s provision of 

reactive power within the standard 

power factor range is unjust and 

unreasonable. The Commission, 

therefore, is revising Schedule 2 of its 

pro forma open-access transmission 

tariff (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 any charges related to the 

provision of reactive power within the 

standard power factor range by 

generating facilities. 

DATES: Effective January 27, 2025. 

FOR FURTHER INFORMATION CONTACT: 

Paul Robinson (Technical Information), 

Office of Energy Market Regulation, 

888 First Street NE, Washington, DC 

20426, (202) 502–8460, 

Paul.Robinson@ferc.gov 

Jennifer Enos (Legal Information), Office 

of the General Counsel, 888 First 

Street NE, Washington, DC 20426, 

(202) 502–6247, Jennifer.Enos@

ferc.gov 

SUPPLEMENTARY INFORMATION: 

Table of Contents 

Paragraph 

Nos. 

I. Background ............................................................................................................................................................................................. 3 

A. Historical Framework Including Order Nos. 888 and 2003 ........................................................................................................... 3 

B. Notice of Inquiry and Notice of Proposed Rulemaking ................................................................................................................. 16 

II. Discussion ............................................................................................................................................................................................. 20 

A. Need for Reform ............................................................................................................................................................................ 27 

1. Comments ...................................................................................................................................................................................... 29 

2. Commission Determination ............................................................................................................................................................ 49 

B. Cost of Producing Reactive Power ................................................................................................................................................ 62 

1. Comments ...................................................................................................................................................................................... 66 

2. Commission Determination ............................................................................................................................................................ 89 

C. Cost Recovery ............................................................................................................................................................................... 109 

1. Comments ...................................................................................................................................................................................... 113 

2. Commission Determination ............................................................................................................................................................ 141 

D. Reliability ........................................................................................................................................................................................ 155 

1. Comments ...................................................................................................................................................................................... 157 

2. Commission Determination ............................................................................................................................................................ 165 

E. Investment ...................................................................................................................................................................................... 170 

1. Comments ...................................................................................................................................................................................... 171 

2. Commission Determination ............................................................................................................................................................ 178 

F. Additional Comments ..................................................................................................................................................................... 187 

1. Comments ...................................................................................................................................................................................... 187 

2. Commission Determination ............................................................................................................................................................ 201 

III. Compliance Procedures ....................................................................................................................................................................... 202 

A. Revisions to Eliminate Compensation for Reactive Power Supply Within the Standard Power Factor Range ........................... 202 

1. Revise Schedule 2 of the Commission’s Pro Forma OATT .......................................................................................................... 203 

2. Revise Section 9.6.3 of the Pro Forma Large Generator Interconnection Agreement ................................................................. 204 

3. Revise Section 1.8.2 of the Pro Forma Small Generator Interconnection Agreement ................................................................. 205 

4. Compliance Procedures ................................................................................................................................................................. 206 

B. Transition Period ............................................................................................................................................................................ 207 

1. Comments ...................................................................................................................................................................................... 210 

2. Commission Determination ............................................................................................................................................................ 224 

IV. Information Collection Statement ......................................................................................................................................................... 228 

V. Environmental Analysis ......................................................................................................................................................................... 242 

VI. Regulatory Flexibility Act ...................................................................................................................................................................... 243 

VII. Document Availability .......................................................................................................................................................................... 247 

VIII. Effective Date and Congressional Notification .................................................................................................................................. 250 

1. In this final determination, 

pursuant to section 206 of the Federal 

Power Act (FPA), the Federal Energy 

Regulatory Commission finds that 

allowing public utility transmission 

providers (transmission providers) 1 to 

charge transmission customers for a 

generating facility’s provision of 

reactive power within the standard 

power factor range is unjust and 

unreasonable. The Commission, 

therefore, is revising Schedule 2 of the 


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2Operating ‘‘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. The 

standard power factor range is sometimes referred 

to as the ‘‘deadband.’’ Compensation for Reactive 

Power Within the Standard Power Factor Range, 

Notice of Proposed Rulemaking, 89 FR 21,454 (Mar. 

28, 2024) (cross-referenced at 186 FERC ¶ 61,203, at 

P 2 n.1) (NOPR). 

3MVAr is the typical unit of measurement for 

reactive power. 

4A 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. 

5Order No. 888, FERC Stats. & Regs. ¶ 31,036, at 

31,705–07 & n.359. 

6 Id. at 31,720. 

7 Id. at 31,707 & n.359. 

8 Id. at 31,705–07 & n.359. 

9Standardization 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). 

10The power factor is the ratio of a generating 

facility’s real power to its apparent power, where 

apparent power is the total power output of the 

system (both real and reactive power). Power factors 

can range from 1.0 to 0.0, with 1.0 representing only 

real power and 0.0 representing only reactive 

power. 

11Order No. 2003, 104 FERC ¶ 61,103 at P 546. 

12Order No. 2003–A, 106 FERC ¶ 61,220 at P 416. 

Order No. 2003–A also exempted wind generating 

facilities from maintaining the established power 

factor range. Id. P 34. 

13 In Order No. 2006, the Commission adopted 

identical power factor and compensation 

requirements for small generating facilities (those 

with a capacity of 20 MW or less) and initially 

exempted small wind generating facilities from the 

reactive power requirement before Order No. 827 

eliminated such exemptions. Reactive Power 

Requirements for Non-Synchronous Generation, 

Order No. 827, 81 FR 40793 (June 23, 2016), 155 

FERC ¶ 61,277, order on clarification and reh’g, 157 

FERC ¶ 61,003 (2016); 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), 

Continued 

Commission’s pro forma OATT to 

prohibit transmission providers from 

including in their transmission rates any 

charges associated with the provision of 

reactive power within the standard 

power factor range from generating 

facilities and requiring transmission 

providers to make compliance filings to 

update Schedule 2 of their OATTs 

accordingly.2 The final determination 

further revises the Commission’s pro 

forma LGIA and pro forma SGIA to 

remove 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 generating facilities 

for the same service, and the final 

determination requires transmission 

providers to make compliance filings to 

update their pro forma interconnection 

agreements accordingly. As a result of 

this final determination, transmission 

providers will be required to pay an 

interconnection customer for reactive 

power only when the transmission 

provider requests or directs the 

interconnection customer to operate its 

facility outside the standard power 

factor range set forth in its 

interconnection agreement. 

2. As discussed below, the 

Commission has a statutory duty to 

ensure that transmission rates are and 

remain just and reasonable. We find that 

this reform will ensure that 

transmission providers do not pass onto 

transmission customers unjust and 

unreasonable charges that lack a 

sufficient economic basis or justification 

and yield no commensurate benefit for 

ratepayers. 

I. Background 

A. Historical Framework Including 

Order Nos. 888 and 2003 

3. 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),3 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 4 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. 

4. 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.5 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. 

5. With respect to compensation, the 

Commission stated that the transmission 

provider’s ‘‘rates for ancillary services 

should be cost-based.’’ 6 The 

Commission expected, however, that 

transmission customers would be able 

to change the amount of reactive power 

service they required. The Commission 

also identified the possibility that 

reactive power could potentially be 

supplied by ‘‘a competitive market for 

such service’’ if ‘‘technology or industry 

changes’’ made such a market possible.7

6. The Commission’s policy on 

reactive power compensation has 

evolved since issuing Order No. 888 in 

1996.8 In Order No. 2003, the 

Commission adopted a standard 

agreement for the interconnection of 

large generating facilities (the pro forma 

LGIA), and specifically addressed the 

circumstances under which a 

transmission provider must pay an 

interconnection customer for reactive 

power depending upon whether such 

reactive power was inside or outside the 

standard power factor range.9 This 

standard agreement included the 

requirement that interconnection 

customers maintain a composite power 

delivery at a 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.10 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 concluded in Order No. 

2003 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.’’ 11 However, 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.’’ 12 This 

standard is generally referred to as the 

‘‘comparability standard.’’ 13


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113 FERC ¶ 61,195 (2005), order granting 

clarification, Order No. 2006–B, 71 FR 42587 (July 

27, 2006), 116 FERC ¶ 61,046 (2006). 14 Interconnection for Wind Energy, Order No. 

661, 70 FR 34993 (June 16, 2005), 111 FERC 

¶ 61,353, order on reh’g, Order No. 661–A, 70 FR 

75005 (Dec. 19, 2005), 113 FERC ¶ 61,254 (2005). 15Order No. 2006, 111 FERC ¶ 61,220. 16Order No. 827, 155 FERC ¶ 61,277. 17See also PJM Interconnection, L.L.C., 151 FERC 

¶ 61,097, at P 28 (2015) (finding that, since Order 

No. 661, the cost of the technology necessary for a 

non-synchronous resource to provide reactive 

power has lessened such that the cost of installing 

equipment that is capable of providing reactive 

power is comparable to the costs of a traditional 

generator). 

18Bonneville 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). See 

also BPA Rehearing Order, 125 FERC ¶ 61,273 at P 

15 & n.24 (‘‘[N]either affiliated nor non-affiliated 

generators have an inherent right to any 

compensation for reactive power inside the 

deadband.’’). Accord., 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); Sw. Power Pool, Inc., 119 FERC 

¶ 61,199 (SPP), order on reh’g, Sw. Power Pool, Inc., 

121 FERC ¶ 61,196, at 61,968 (2007) (SPP Order on 

Rehearing) (‘‘[R]eactive power is required for an 

interconnecting generator to deliver its power and 

reactive power produced within the deadband and 

is, therefore, generally not compensable.’’); Mich. 

Elec. Transmission Co., 97 FERC ¶ 61,187, at 

61,852–53 (2001) (METC Rehearing Order) 

(‘‘Providing reactive power within design 

limitations is not providing an ancillary service; it 

is simply ensuring that a generator lives up to its 

obligations.’’); Consumers Energy Co., 94 FERC 

¶ 61,230, at 61,834 (2000) (affirming the 

Commission’s rejection of generators’ request for 

reactive power compensation when operating 

within a facility’s reactive power design limitation, 

stating that as a condition of interconnecting to the 

transmission provider’s system, ‘‘to ensure system 

security,’’ the generator was required to provide 

equipment, ‘‘at its own cost, to meet its reactive 

power obligations as provided for in [its 

interconnection agreement].’’(emphasis added)); 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.’’). 

19MISO Rehearing Order, 184 FERC ¶ 61,022 at 

P 23. 

20See, e.g., id. at PP 23–24 (citing METC 

Rehearing Order, 97 FERC at 61,852–53). 

21See, e.g., MISO, 182 FERC ¶ 61,033 at PP 52– 

53; MISO Rehearing Order, 184 FERC ¶ 61,022 at PP 

26–27; 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). 

22BPA, 120 FERC ¶ 61,211 at PP 19–20; BPA 

Rehearing Order, 125 FERC ¶ 61,273 at PP 10–11. 

23BPA, 120 FERC ¶ 61,211 at PP 19–20 (citing 

Order No. 2003, FERC Stats. & Regs. ¶ 31,146 at P 

546); METC Rehearing Order, 97 FERC at 61,852 

(‘‘Providing reactive power within design 

limitations is not providing an ancillary service; it 

is simply ensuring that a generator lives up to its 

obligations.’’). 

24 Id. PP 19–22. 

25 Id. P 21 (citing Sw. Power Pool, Inc., 119 FERC 

¶ 61,199, at P 39). 

26 Id. 

7. 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.14 In Order No. 2006,15 the 

Commission adopted identical power 

factor and compensation requirements 

for small generating facilities (facilities 

that have a capacity of no more than 20 

megawatts (MW)) but exempted small 

wind generating facilities from the 

reactive power requirement. 

Subsequently, in Order No. 827,16 the 

Commission eliminated the exemptions 

for both small and large wind generating 

facilities, thus requiring those facilities 

to provide reactive power. The 

Commission explained that it had 

previously exempted wind generators 

from the uniform reactive power 

requirement because, historically, the 

costs to design and build a wind 

generator that could provide reactive 

power were high and could have created 

an obstacle to the development of wind 

generation. But the Commission found 

in Order No. 827 that, due to 

technological advancements since the 

establishment of those exemptions, the 

cost of providing reactive power no 

longer presented an obstacle to the 

development of wind generation, and 

therefore found that the exemptions had 

become unjust and unreasonable.17 The 

Commission therefore required all 

newly interconnecting non-synchronous 

generating facilities to provide reactive 

power within the range of 0.95 leading 

to 0.95 lagging at the high-side of the 

generator substation transformer as a 

condition of interconnection. 

8. 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.’’ 18

‘‘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.’’ 19 By 

contrast, 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,20 and 

thus, the Commission has required 

compensation for such service. 

9. Consistent with Order Nos. 2003 

and 2003–A and Commission precedent 

that pre-dated those Orders, the 

Commission has permitted transmission 

providers to eliminate separate 

compensation for generating facilities 

providing reactive power within the 

standard power factor range.21 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 within the standard 

power factor range, often referred to as 

a ‘‘deadband,’’ were no longer just and 

reasonable given BPA’s decision to no 

longer pay its own or affiliated 

generators for providing this service.22

The Commission found that 

‘‘Commission policy clearly allows BPA 

to discontinue paying all its merchants 

for inside the deadband reactive power 

service,’’ explaining that ‘‘[t]he 

Commission’s policy is not new; we 

confirmed it in Order No. 2003, when 

we stated that an interconnecting 

generator ‘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.’’ 23

10. The Commission has also found 

that a transmission provider’s decision 

to end compensation for reactive power 

within the standard power factor range 

does not compromise a generating 

facility’s ability to recover costs that it 

may incur in producing reactive power 

within this range.24 For example, the 

Commission has observed that 

generating facilities ‘‘may be able to 

recover the costs for reactive power 

within the deadband in other ways— 

such as through higher power sales rates 

of their own.’’ 25 In response to 

arguments by certain independent 

power producers that such recovery is 

infeasible because of competition, the 

Commission has found that ‘‘since the 

incremental cost of reactive power 

service within the deadband is minimal, 

the infeasibility argument lacks 

plausibility. The 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.’’ 26

11. The Commission made similar 

findings in MISO, wherein it accepted 

an FPA section 205 application by 


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27 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 PP 29, 33 

(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). 

28 MISO, 182 FERC ¶ 61,033 at P 53. The 

Commission found ‘‘those protests that challenge 

these well-established policies to be collateral 

attacks on these earlier determinations.’’ Id. 

29Synchronous 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, Payment for 

Reactive Power, 7 (Apr. 22, 2014) (2014 Staff 

Report), https://www.ferc.gov/sites/default/files/ 

2020-05/04-11-14-reactive-power.pdf. 

30MISO 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 

Rehearing Order, 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.’’). 

31MISO Rehearing Order, 184 FERC ¶ 61,022 at 

PP 40–42; SPP, 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.’’). 

32See, e.g., MISO, 182 FERC ¶ 61,033 at PP 52– 

53; MISO Rehearing Order, 184 FERC ¶ 61,022 at P 

26; PNM, 178 FERC ¶ 61,088 at PP 29–31; Nev. 

Power Co., 179 FERC ¶ 61,103 at PP 20–21; BPA, 

120 FERC ¶ 61,211 at P 20; E.ON U.S. LLC, 119 

FERC ¶ 61,340 at P 15; Entergy Servs., Inc., 113 

FERC ¶ 61,040 at P 38. 

33PJM Interconnection, L.L.C., Intra-PJM Tariffs, 

OATT Schedule 2, (Reactive Supply and Voltage 

Control from Generation or Other Sources Service) 

(4.0.0). 

34The 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). 

35 ISO New England Inc., ISO New England Inc. 

Transmission, Markets and Services Tariff, 

Schedule 2 (Reactive Supply and Voltage Control 

Service) (8.0.0). 

36New York Independent System Operator, Inc., 

NYISO Tariffs, NYISO OATT, § 6.2 OATT Schedule 

2 (Charges For Voltage Support Service) (6.0.0). 

37Both 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). 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). 

38CAISO 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). 

39SPP, 119 FERC ¶ 61,199 at P 30. 

40 MISO, 182 FERC ¶ 61,033 at PP 52–66; MISO 

Rehearing Order, 184 FERC ¶ 61,022 at PP 23–55. 

41See, 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 [Arizona 

Public Service Company] 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 ± 

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 [Arizona Public Service 

Company].’’); 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.’’). 

Midcontinent Independent System 

Operator, Inc. (MISO) transmission 

owners to end generator compensation 

for the provision of reactive power 

within the standard power factor 

range.27 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.’’ 28 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 given that, for 

both synchronous and non-synchronous 

generating facilities,29 the same 

equipment is used for the production of 

real power and reactive power.30 In 

addition, the Commission found that 

generating facilities have other 

opportunities, beyond Schedule 2, to 

seek to recover their costs of providing 

reactive power.31

12. Consistent with Order Nos. 2003 

and 2003–A and other Commission 

precedent, multiple RTOs/ISOs and 

non-RTO/ISO transmission providers 

have elected not to compensate 

generating facilities for providing 

reactive power within the standard 

power factor range under Schedule 2 of 

their OATTs.32

13. Of the six Commissionjurisdictional 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) 33

generally use the cost-based AEP 

Methodology to calculate cost-of-service 

rates for the production of reactive 

power.34 Because the same generation 

equipment contributes to the production 

of both real power and reactive power, 

the AEP Methodology allocates the costs 

of each piece of equipment to real 

power service and reactive power 

service by assigning the cost of each 

piece of equipment to either real power 

service, reactive power service, or both. 

ISO New England Inc. (ISO–NE) 35 and 

New York Independent System 

Operator, Inc. (NYISO) 36 compensate 

generating facilities for reactive power 

under flat rate designs that are adjusted 

for inflation.37

14. California Independent System 

Operator Corporation (CAISO),38

Southwest Power Pool, Inc. (SPP),39 and 

MISO 40 do not pay separately for 

reactive power within the standard 

power factor range. 

15. Outside the RTOs/ISOs, 

transmission providers that pay for the 

provision of reactive power within the 

standard power factor range generally 

use the AEP Methodology to set reactive 

power compensation on an individual 

generating facility basis. Many nonRTO/ISO transmission providers do not 

pay separately for reactive power 

provided within the standard power 

factor range.41


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93414 Federal Register / Vol. 89, No. 228 / Tuesday, November 26, 2024 / Rules and Regulations 

42Reactive Power Capability Compensation, 

Notice of Inquiry, 177 FERC ¶ 61,118 (2021) (NOI). 

43 Id. P 19. 

44Real power, which accomplishes useful work 

(e.g., runs motors), is typically measured in MWs. 

45 16 U.S.C. 824e. 

46See pro forma OATT, Schedule 2. 

47See pro forma LGIA, § 9.6.3. 

48See pro forma SGIA, § 1.8.2. 

49See app. A. 

50C T Gaunt states that reactive power cannot be 

delivered and also that it cannot be lost in 

transmission through a transformer or power 

system. Thus, C T Gaunt claims that there are no 

grounds for arguing against the Commission’s 

determination in the NOPR. C T Gaunt Reply 

Comments at 2–3. 

51American Electric Power Service Corporation 

(AEP) (on behalf of itself and its affiliates, including 

Appalachian Power Company, Indiana Michigan 

Power Company, Kentucky Power Company, 

Kingsport Power Company, Ohio Power Company, 

Wheeling Power Company, Public Service 

Company of Oklahoma, Southwestern Electric 

Power Company, AEP Appalachian Transmission 

Company, Inc., AEP Indiana Michigan 

Transmission Company, Inc., AEP Kentucky 

Transmission Company, Inc., AEP Ohio 

Transmission Company, Inc., AEP West Virginia 

Transmission Company, Inc., AEP Oklahoma 

Transmission Company, Inc., and AEP 

Southwestern Transmission Company, Inc.); 

Ameren Service Company (Ameren) (on behalf of 

Ameren Illinois Company d/b/a Ameren Illinois, 

Union Electric Company d/b/a Ameren Missouri 

and Ameren Transmission Company of Illinois); C 

T Gaunt; New England Consumer Advocates 

(consisting of the Office of Massachusetts Attorney 

General Andrea Joy Campbell, the Connecticut 

Office of Consumer Counsel, the Maine Office of 

Public Advocate, the New Hampshire Office of 

Consumer Advocate, and the Rhode Island Division 

of Public Utilities and Carriers); Joint Consumer 

Advocates (including the Illinois Attorney General, 

Illinois Citizens Utility Board, Maryland Office of 

People’s Counsel, the New Jersey Division of Rate 

Counsel, the North Carolina Utilities Commission 

Public Staff, the Office of the People’s Counsel for 

the District of Columbia, and the West Virginia 

Consumer Advocate Division of the Public Service 

Commission), Joint Customers (including Old 

Dominion Electric Cooperative, Northern Virginia 

Electric Cooperative, Inc., and Dominion Energy 

Services, Inc. on behalf of Virginia Electric and 

Power Company d/b/a Dominion Energy Virginia); 

Liberty Utilities (Granite State Electric) Corp. d/b/ 

a Liberty (Liberty); MISO; MISO Transmission 

Owners (including Ameren, as agent for Union 

Electric Company d/b/a Ameren Missouri, Ameren 

Illinois Company d/b/a Ameren Illinois, and 

Ameren Transmission Company of Illinois; 

Arkansas Electric Cooperative Corporation; City 

Water, Light & Power; Cooperative Energy; 

Dairyland Power Cooperative; East Texas Electric 

Cooperative; Entergy Arkansas, LLC; Entergy 

Louisiana, LLC; Entergy Mississippi, LLC; Entergy 

Texas, Inc.; Great River Energy; Indianapolis Power 

& Light Company; Lafayette Utilities System; 

MidAmerican Energy Company; Minnesota Power 

(and its subsidiary Superior Water, L&P); Missouri 

River Energy Services; Montana-Dakota Utilities 

Co.; Northern States Power Company, a Minnesota 

corporation, and Northern States Power Company, 

a Wisconsin corporation, subsidiaries of Xcel 

Energy Inc.; Northwestern Wisconsin Electric 

Company; Otter Tail Power Company; Prairie 

Power, Inc.; Southern Indiana Gas & Electric 

Company (d/b/a CenterPoint Energy Indiana South); 

and Southern Minnesota Municipal Power Agency); 

the Ohio Office of the Federal Energy Advocate of 

the Public Utilities Commission of Ohio (Ohio 

FEA); Portland General Electric Company (PGE); 

PJM; the PJM IMM; the Transmission Access Policy 

Study Group (TAPS) (an association of transmission 

dependent utilities in 35 states). For convenience, 

we have listed each commenter and the parties they 

represent. For brevity, for the remainder of this rule, 

we will refer to each commenter by their 

abbreviated names as defined in this footnote. 

52The American Council on Renewable Energy 

(ACORE); Calpine Corporation (Calpine); Eagle 

Creek Reactive Generators (including Mahoning 

Creek Hydroelectric Company, LLC, York Haven 

Power Company, LLC, Eagle Creek Reusens Hydro, 

LLC, Great Falls Hydroelectric Company Limited 

Partnership, Lake Lynn Generation, LLC, PE Hydro 

Generation, LLC, Black River Hydroelectric, LLC, 

All Dams Generation, LLC, and Eagle Creek Hydro 

Power, LLC); EDP Renewables North America LLC 

(EDPR); Elevate Renewables F7, LLC (Elevate); 

Generation Developers (including Vistra Corp. and 

Dynegy Marketing and Trade, LLC); Glenvale LLC 

(Glenvale); Indicated Reactive Power Suppliers 

(including KMC Thermo, LLC, Bitter Ridge Wind 

Farm, LLC, Guernsey Power Station LLC, Moxie 

Freedom LLC, Safe Harbor Water Power 

Corporation, BIF III Holtwood LLC, Brookfield 

Power Piney & Deep Creek LLC, Erie Boulevard 

Hydropower, L.P., Carr Street Generating Station, 

L.P., Bear Swamp Power Company LLC, Brookfield 

White Pine Hydro LLC, Brookfield Renewable 

Trading and Marketing LP, and Reworld Waste, LLC 

B. Notice of Inquiry and Notice of 

Proposed Rulemaking 

16. On November 18, 2021, the 

Commission issued a Notice of Inquiry 

(NOI) 42 in this proceeding, 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.’’ 43

17. On March 21, 2024, the 

Commission issued a NOPR in this same 

proceeding. Based on a review of the 

comments submitted in response to the 

Commission’s NOI in the instant docket, 

as well as the Commission’s experience 

in the years since the issuance of Order 

Nos. 2003 and 2003–A, the NOPR 

preliminarily found 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. In support of such 

preliminary finding, the NOPR 

explained that generating facilities 

provide reactive power within the 

standard power factor range at no cost 

or de minimis cost, and that providing 

reactive power within the standard 

power factor range is already an 

obligation of the generating facility as an 

interconnection customer and 

consistent with good utility practice.44

The NOPR also stated that current 

compensation may result in undue 

compensation or other market 

distortions. The NOPR proposed, 

pursuant to FPA section 206,45 that a 

just and reasonable replacement rate 

was 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. 

18. Specifically, the NOPR proposed 

to add the following sentence to the end 

of Schedule 2 of the pro forma OATT: 46

‘‘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, 

the NOPR proposed to remove the 

following clause from section 9.6.3 of 

the pro forma LGIA: 47 ‘‘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, the NOPR proposed 

to remove the following sentence from 

section 1.8.2 of the pro forma SGIA: 48

‘‘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.’’ 

19. Comments on the NOPR were due 

on June 26, 2024. Thirty-one parties 

filed comments.49 Comments were 

submitted by RTOs/ISOs and other 

transmission providers, generating 

facilities, generation developers, 

transmission owners, load-serving 

entities (LSE), Monitoring Analytics, 

LLC, acting in its capacity as the 

Independent Market Monitor for PJM 

(PJM IMM), trade associations 

representing specific generation 

technologies, and consumer advocates. 

Of these, and with few exceptions, 

transmission owners, LSEs, the PJM 

IMM, independent filers,50 and 

consumer advocates supported or did 

not oppose the NOPR proposal to 

eliminate compensation in the standard 

power factor range,51 while generating 

facilities, generation developers, and 

trade associations representing specific 

generation technologies oppose the 

NOPR proposal.52


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f/k/a Covanta; Independent Power Producers of 

New York, Inc. (IPPNY); Indicated Trade 

Associations (including Electric Power Supply 

Association, The PJM Power Providers Group the 

New England Power Generators Association, Inc., 

Independent Power Producers of New York, Inc., 

the Coalition of Midwest Power Producers); ISO– 

NE; Middle River Power LLC (including Coalition 

of Midwest Power Producers, the Electric Power 

Supply Association, the PJM Power Providers 

Group, the New England Power Generators 

Association, Inc., and the Independent Power 

Producers of New York, Inc.); National Hydropower 

Association (NHA) (a national trade association 

with over 320 member companies); New England 

Power Generators Association, Inc. (NEPGA); New 

England Power Pool (NEPOOL); New England 

States Committee on Electricity (NESCOE); Nuclear 

Energy Institute (NEI); North American Generator 

Forum (NAGF); NYISO; Onward Energy Holdings, 

LLC (Onward Energy); PSEG (including Public 

Service Electric and Gas Company, PSEG Power 

LLC, and PSEG Energy Resources & Trade LLC, and 

each wholly owned, direct or indirect subsidiaries 

of Public Service Enterprise Group Incorporated) 

(PSEG); Reactive Service Providers (including CIP, 

D. E. Shaw Renewable Investments, L.L.C., 

Invenergy Renewables LLC, Leeward Renewable 

Energy, LLC, Lightsource Renewable Energy 

Operations, LLC, NextEra Energy Resources, LLC,1 

;rsted Wind Power North America, LLC, and RWE 

Clean Energy, LLC); Clean Energy Associations 

(including Solar Energy Industries Association 

(SEIA) and American Clean Power Association 

(ACP)). For brevity, for the remainder of this rule, 

we will refer to each commenter by their 

abbreviated names as defined in this footnote. 

53Order No. 888, FERC Stats. & Regs. ¶ 31,036 at 

31,654 (‘‘We conclude that functional unbundling 

of wholesale services is necessary to implement 

non-discriminatory open access transmission.’’). 54Regional Transmission Orgs., Order No. 2000, 

FERC Stats. & Regs. ¶ 31,089 (1999) (crossreferenced at 89 FERC ¶ 61,285) (‘‘We conclude that 

properly structured RTOs throughout the United 

States can provide significant benefits in the 

operation of the transmission grid.’’), order on reh’g, 

Order No. 2000–A, FERC Stats. & Regs. ¶ 31,092 

(2000) (cross-referenced at 90 FERC ¶ 61,201), aff’d 

sub nom. Pub. Util. Dist. No. 1 of Snohomish Cty. 

v. FERC, 272 F.3d 607 (D.C. Cir. 2001). 

55See, e.g., Order No. 2003, 104 FERC ¶ 61,103 

at P 12 (explaining that standard interconnection 

procedures and a standard agreement will: ‘‘(1) 

limit opportunities for Transmission Providers to 

favor their own generation; (2) facilitate market 

entry for generation competitors by reducing 

interconnection costs and time; and (3) encourage 

needed investment in generator and transmission 

infrastructure’’). 

56See 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.’’); 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.’’); Richard A. 

Posner, Natural Monopoly and Its Regulation, 21 

Stan. L. Rev. 548, 595 (1969) (‘‘where 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?’’). 

57When both real power and reactive power rates 

were cost-based, the only effect of the allocation 

was to change the allocation of costs and the rates 

for transmission and generation service; the 

transmission provider would not exceed its total 

revenue requirement. 

II. Discussion 

20. In this final determination, the 

Commission adopts the NOPR as 

proposed, except with respect to the 

timing of the compliance procedures 

and implementation. Based on our 

review of the record, we find there is 

substantial evidence to support the 

conclusion that allowing transmission 

providers to charge transmission 

customers for a generating facility’s 

provision of reactive power within the 

standard power factor range results in 

unjust and unreasonable transmission 

rates. As explained in the NOPR, 

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 or at 

most de minimis variable costs beyond 

the cost of providing real power. 

Moreover, providing 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. 

21. We find that these reforms will 

not adversely impact reliability. We also 

find that generating facilities have the 

opportunity to seek to recover any costs 

associated with providing reactive 

power within the standard power factor 

range through their rates for selling real 

power, including energy or capacity 

sales, whether in organized or bilateral 

markets. Given that the primary 

function of a generating facility is to 

produce real power and that the 

provision of reactive power within the 

standard power factor range is necessary 

for the provision of real power, we find 

that the existing means of cost recovery 

for real power are not only reasonable 

but also the most logical outcome. 

22. Based on more than two decades 

of experience since Order No. 2003, and 

the record developed in this proceeding, 

we find that, even as a function of 

comparability, charging transmission 

customers under Schedule 2 for the 

provision of reactive power within the 

standard power factor range has become 

unjust and unreasonable. As explained 

above and for the reasons discussed 

below, in Order No. 2003, the 

Commission found generators should 

not receive compensation for the 

provision of reactive power within the 

standard power factor as it was an 

obligation of good utility practice. Based 

on rehearing requests, in Order No. 

2003–A, the Commission agreed that 

where vertically integrated transmission 

owners continued to have rate 

schedules providing payment to their 

affiliated generating facilities for 

reactive power service within the 

standard power factor range, such 

transmission owners were also required 

to pay non-affiliated interconnection 

customers for the same provision of 

reactive power. At the time of Order 

Nos. 2003 and 2003–A, functional 

unbundling of transmission service 53

and the development of organized 

wholesale electricity markets 54 were 

relatively nascent, and so too was the 

Commission’s experience with the 

impacts of establishing the 

comparability standard for the provision 

of reactive power within the standard 

power factor range. At the time, 

establishing the comparability standard 

appeared consistent with Order No. 

2003’s stated intent of ‘‘minimiz[ing] 

opportunities for undue discrimination 

and expedit[ing] the development of 

new generation, while protecting 

reliability and ensuring that rates are 

just and reasonable.’’ 55

23. Since Order No. 2003, however, 

many industry changes have occurred. 

Some vertically integrated utilities have 

divested their generation. Competitive 

markets have developed, leading many 

generators to recover their costs through 

market-based rather than cost-based 

rates. The development of competitive 

markets makes even more challenging 

any allocation of costs between real 

power production, under market-based 

rates, and reactive power service, under 

cost of service rates.56 When rates are 

market-based, challenges in allocation 

will affect the competitive positions of 

the entities.57 New technologies have 

developed that provide reactive power 

through different means and to which 

the AEP Methodology that predates 

these technologies does not squarely 

apply. With fewer vertically integrated 

utilities, the continued development of 

competitive markets, and new 

technologies, the initial justification for 

compensation (i.e., that the Commission 

required separate compensation on a 

comparable basis because vertically 

integrated transmission owners 

continued to have rate schedules 

providing payment to their affiliated 

generating facilities for reactive power 

service) is no longer broadly applicable. 

Indeed, the wide-ranging rates for 

reactive power resulting from cost-ofservice proceedings further undermine 

the principle of comparability as some 

generating facilities now receive 

substantially higher rates for the 

provision of reactive power within the 


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58The PJM IMM notes that total settled reactive 

power revenue requirements for oil-fueled steam 

units average $993/MW-year whereas other units 

have settled reactive power revenue requirements 

as high as $18,750/MW-year. IMM Initial Comments 

at 5. 

59See, e.g., PJM IMM Initial Comments at 11–12 

(‘‘The salient difference between PJM and CAISO, 

SPP, and MISO is that PJM customers paid 

$388,044,837.00 in out of market payments for 

reactive capability in 2023, and customers in 

CAISO, SPP and MISO, paid $0.00’’); For Schedule 

2 service in 2023, PJM paid $388 million, NYISO 

paid $75 million, and ISO–NE paid $18 million. See 

PJM 2023 Annual Report at 5, https://services.pjm.

com/annualreport2023/); 2023 NYISO Voltage 

Support Service Rates, https://www.nyiso.com/

documents/20142/35126567/2023-OATT-MSTSchedule-2-VSS-Rates-FINAL-for-posting.pdf/ 

f59317b0-41c6-9f41-5d61-e7f502af82c2); 2023 

Annual Markets Report at 154, iso-ne.com/staticassets/documents/100011/2023-annual-marketsreport.pdf. 

60See 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’’). 

61PJM Power Providers Grp. v. FERC, 88 F.4th 

250, 271–72 (3d Cir. 2023), amended sub nom. PJM 

Power Provisers Grp. v. FERC, No. 21–3068, 2024 

WL 259448 (3d Cir. Jan. 24, 2024) (‘‘An agency may 

alter its ‘view of what is in the public interest.’ The 

fact that contrary agency precedent exists ‘gives us 

no more power than usual to question the 

Commission’s substantive determinations.’ The 

agency need not establish that ‘the reasons for the 

new policy are better than the reasons for the old 

one; it suffices that the new policy is permissible 

under the statute, that there are good reasons for it, 

and that the agency believes it to be better.’ ’’) 

(citing FCC v. Fox Television Stations, Inc., 556 U.S. 

502, 515 (2009)); In re Permian Basin Area Rate 

Cases, 390 U.S. 747, 784 (1968) (Permian Basin); 

see also Motor Vehicle Mfrs. Ass’n of U.S., Inc. v. 

State Farm Mut. Auto. Ins. Co., 463 U.S. 29, 42 

(1983) (‘‘[W]e fully recognize that regulatory 

agencies do not establish rules of conduct to last 

forever.’’) (internal quotations omitted); Greater 

Bos. Television Corp. v. FCC, 444 F.2d 841, 852 

(D.C. Cir. 1970) (an agency may change its course 

as long as it ‘‘suppl[ies] a reasoned analysis 

indicating that prior policies and standards are 

being deliberately changed, not casually ignored.’’), 

cert. denied, 403 U.S. 923 (1971)). 

62NOPR, 186 FERC ¶ 61,203 at PP 25, 40. 

63 Id. PP 28–33. 

64 Id. PP 34–40. 

65 Id. P 35. 

66 Id. PP 36–38. 

67 Id. P 39. 68 Id. P 40. 69 Id. P 42. 70AEP Initial Comments at 1–2; Ameren Initial 

Comments at 2–3; Joint Consumer Advocates Initial 

Comments at 1; Joint Customers Initial Comments 

at 2; MISO Transmission Owners Initial Comments 

at 1, 5; New England Consumer Advocates Initial 

Comments at 6; Ohio FEA Initial Comments at 3; 

PGE Initial Comments at 1; PJM Initial Comments 

at 1, 3; PJM IMM Initial Comments at 2; TAPS 

Initial Comments at 1. 

71See, e.g., Joint Customers Reply Comments at 

10–11 (‘‘Standing on its own, the record in this 

proceeding is sufficient to justify the conclusion 

that compensating generators, any generators, for 

reactive service within the standard power factor 

range is not just and reasonable. Through the NOI 

comments, the development of the NOPR, and 

comments to the NOPR, the Commission has 

supported its conclusions and addressed potential 

concerns.’’). 

72 Joint Consumer Advocates Initial Comments at 

1, 5; Joint Customers Initial Comments at 5–6; Joint 

Customers Reply Comments at 1–2; MISO 

Transmission Owners Reply Comments at 2; PGE 

Initial Comments at 5; TAPS Initial Comments at 3. 

standard power factor range than 

others.58

24. All of these changes taken 

together, coupled with the record 

developed here, make clear that separate 

compensation for the provision of 

reactive power within the standard 

power factor range results in unjust and 

unreasonable rates to transmission 

customers, because such compensation 

is not necessary for comparability or to 

ensure continued investment in the 

capability of generating facilities to 

provide reactive power within the 

standard power factor range.59 We 

acknowledge that this final 

determination represents a change in 

policy,60 a change we find appropriate 

based on the record before us, as 

explained in detail herein.61

25. Accordingly, we are modifying 

Schedule 2 of the pro forma OATT, 

section 9.6.3 of the pro forma LGIA, and 

section 1.8.2 of the pro forma SGIA, and 

we are requiring transmission providers 

to make corresponding revisions to their 

OATTs and pro forma interconnection 

agreements, to prohibit transmission 

providers from including in their 

transmission rates any charges 

associated with the provision of reactive 

power within the standard power factor 

range from generating facilities. 

26. We discuss below the issues 

raised in the comments. 

A. Need for Reform 

27. The NOPR preliminarily found 

that where transmission providers 

require transmission customers to pay 

for generating facilities’ provision of 

reactive power within the standard 

power factor range, transmission rates 

may be unjust and unreasonable, as 

such rates may include costs without a 

sufficient economic basis or justification 

and such costs may not result in 

transmission customers receiving 

commensurate reliability benefits.62 In 

support of the need for reform, the 

NOPR preliminarily found that 

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 or at 

most a de minimis increase in variable 

costs beyond the cost of providing real 

power.63 The NOPR also highlighted 

various adverse impacts of the 

Commission’s policy on reactive power 

compensation, which have been 

exacerbated by the increasing volume of 

filings for reactive power compensation 

and in turn, increasing reactive powerrelated costs to transmission 

customers.64 For example, in many 

regions, generating facilities 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.65

Additionally, adjudicating cost-ofservice reactive power rates has become 

increasingly administratively 

burdensome and may result in 

inconsistent rate treatment across 

generating facilities.66 Furthermore, in 

regions where generating facilities may 

seek to 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.67

Finally, as explained in the NOPR, the 

costs to transmission customers have 

increased substantially without any 

commensurate increase in benefits.68

28. The NOPR also preliminarily 

found that cessation of payments for 

reactive power within the standard 

power factor range for generating 

facilities does not compromise a 

generating facility’s ability to recover 

costs–if any–that it may incur in 

producing reactive power within such 

range because generating facilities have 

the opportunity to seek to recover such 

costs in other ways, such as through 

energy or capacity sales.69

1. Comments 

29. AEP, Ameren, Joint Consumer 

Advocates, Joint Customers, MISO 

Transmission Owners, New England 

Consumer Advocates, Ohio FEA, PGE, 

PJM, the PJM IMM, and TAPS agree 

there is a need for reform and, 

accordingly, support the NOPR proposal 

to eliminate compensation for reactive 

power within the standard power factor 

range.70

30. Many commenters argue that there 

is substantial evidence to support the 

conclusion that allowing transmission 

providers to charge transmission 

customers for a generating facility’s 

provision of reactive power from within 

the standard power factor range results 

in unjust and unreasonable transmission 

rates.71 They also agree that current 

generator compensation for the 

provision of reactive power within the 

standard power factor range lacks 

sufficient economic basis or 

justification,72 and that customers may 


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73 Joint Customers Initial Comments at 13–17; 

MISO Transmission Owners Reply Comments at 8, 

19; New England Consumer Advocates Initial 

Comments at 4–6; TAPS Initial Comments at 3. 

74 Joint Customers Reply Comments at 10–11. 

75 Id. at 11 (emphasis in original). 

76PJM Initial Comments at 1–3. 

77MISO Initial Comments at 2. 

78 Id. 

79MISO Transmission Owners Initial Comments 

at 5. 

80 Joint Customers Initial Comments at 12; MISO 

Transmission Owners Initial Comments at 19; MISO 

Transmission Owners Reply Comments at 3–5; New 

England Consumer Advocates Initial Comments at 

4–6; TAPS Initial Comments at 3–5. 

81See, e.g., PJM IMM Initial Comments at 11–12 

(‘‘There will be no adverse reliability impacts in 

PJM (or other similarly situated regions) for the 

same reasons that . . . there have been no 

observable impacts in regions that do not 

compensate generating facilities for the supply of 

reactive power with the standard power factor 

range. As in the case of CAISO, SPP and MISO, new 

and existing generating facilities in PJM are 

required to provide reactive power within the 

standard power factor range as a condition of 

obtaining and maintaining interconnection service. 

There is no evidence that expanding the just and 

reasonable approach to compensation already in 

place in CAISO, SPP and MISO to PJM will have 

any adverse impact on reliability in PJM.’’); MISO 

Transmission Owners Initial Comments at 13 

(‘‘When the MISO Transmission Owners proposed 

to eliminate compensation for producing reactive 

power within the deadband, the most common 

protest from generators was that it would impact 

the reliability of the grid. However, such claims are 

not supported by evidence and distract from the 

underlying fact that generators are obligated to 

provide reactive power within the deadband 

whether or not they are compensated for it.’’ 

(citations omitted)). 

82See, e.g., Ohio FEA Initial Comments at 5 (‘‘As 

a result, in areas like PJM, generators currently 

receive compensation regardless of proximity to 

locations on the transmission system where there is 

an actual need for additional reactive power.’’); 

Joint Customers Initial Comments at 17 (‘‘Further, 

the failure to account for transmission system needs 

or grid geography in the current regime in regions 

like PJM undermine the reliability benefits of 

generators that interconnect to the system with 

reactive capabilities, whether meeting or exceeding 

their baseline interconnection requirements. The 

current paradigm has resulted in the development 

and deployment of generator based reactive 

capability that is ill-suited to the needs of the 

transmission system, and specifically that is well in 

excess of needs. Eliminating the incentive to 

overbuild reactive capability will not negatively 

impact reliability.’’). 

83TAPS Initial Comments at 4–5. 

84 Joint Customers Initial Comments at 12 (citing 

Ill. Com. Comm’n. v. FERC, 576 F.3d 470, 477 (7th 

Cir. 2009)). 

85AEP Initial Comments at 4–6; Joint Customers 

Initial Comments at 1–5; PJM IMM Initial 

Comments at 9. 

86 Joint Consumer Advocates Initial Comments at 

7. See also PJM IMM Initial Comments at 9 

(‘‘Applying cost of service rules is costly, 

burdensome and unnecessary. Most reactive 

proceedings for generators in PJM are resolved in 

black box settlements that require substantial time 

and resources from all parties, fail to address the 

merits of the cost support provided, result from an 

unsupported split the difference approach, and that 

produce a wide, unreasonable and discriminatory 

disparity among the rates per paid per MW-year for 

the same service.’’); Joint Customers Initial 

Comments at 7 (‘‘As well documented in comments 

to the NOI and described in the NOPR, the current 

individualized consideration of reactive filings 

purporting to apply the AEP [M]ethodology places 

a heavy burden on customers, Transmission 

Providers, and the Commission while resulting in 

customer charges with dubious connection to any 

clear benefits to the customers paying those 

charges. This combination created an intolerable 

condition necessitating Commission action to 

reform the compensation structure.’’). 

87AEP Initial Comments at 4–5. 

not be receiving commensurate 

reliability benefits.73

31. Joint Customers maintain, for 

example, that the NOPR builds on 

longstanding Commission policy, 

reaffirmed since Order No. 2003, that no 

compensation is appropriate for reactive 

service within the standard power factor 

range and that challenges to the 

sufficiency of the record or the process 

are unfounded.74 Joint Customers 

explain that ‘‘[t]he only change the 

Commission is making in the NOPR is 

to determine that transmission 

providers no longer should have the 

option to compensate, affiliate and nonaffiliate alike. And for that discrete 

change, that the exception to the general 

rule on compensation should be closed, 

the Commission has plainly created a 

sufficient record.’’ 75

32. PJM supports the NOPR and 

asserts that it would largely eliminate 

the problems with the current reactive 

power compensation regime in PJM, 

including the resource-intensive 

administrative burdens of reactive 

power rate proceedings and the ‘‘black 

box’’ settlements that ‘‘seem[ ] at odds 

with the Commission’s general 

precedent on efficient energy and 

ancillary service price formation.’’ 76

MISO explains that it has not 

experienced reliability concerns since 

eliminating compensation for reactive 

power within the standard power factor 

range in December 2022 77 and that it 

would not expect to see any effect on 

reliability through eliminating 

compensation for reactive power within 

the standard power factor range.78

33. MISO Transmission Owners 

support the need for reform, arguing 

that the current framework for reactive 

power compensation is neither just nor 

reasonable given that it results in 

transmission customers being required 

to pay for a service that generators 

already are required to provide and that 

costs them little or nothing to provide.79

34. Many commenters agree that the 

current reactive power framework does 

not result in commensurate reliability 

benefits.80 First, many commenters 

agree that compensation for providing 

reactive power within the standard 

power factor range is unnecessary to 

maintain reliability.81 Second, many 

commenters also agree with the NOPR 

that under the current framework, 

compensation for reactive power within 

the standard power factor range is not 

tied to whether there is a particular 

geographic need for reactive power.82

TAPS, for example, contends that the 

existing approach to reactive power 

capability compensation does not 

adequately consider a generator’s actual 

contribution to reliability or lack thereof 

and thus requires consumers to pay 

excessive charges for reactive power 

that may not be needed or is in the 

wrong location.83 Similarly, Joint 

Customers contend that ‘‘[t]his incentive 

structure to provide payment based on 

reactive capability results in the 

building of unnecessary capabilities in 

locations it is not or may not be needed 

and does not allocate the costs 

associated with reactive capability in a 

manner that is at least roughly 

commensurate with the benefits 

received.’’ 84

35. Further, like PJM, many 

commenters agree with the NOPR 

regarding the administrative burden for 

all parties to determine Schedule 2 

rates.85 Joint Consumer Advocates argue 

that ‘‘the existing compensation 

framework for generators that supply 

reactive power has led to unjust and 

unreasonable rates’’ and note that ‘‘[d]ue 

to limited resources, the [Joint 

Consumer Advocates] have generally 

been unable to participate in the 

numerous reactive proceedings and 

assist the Commission with the review 

and scrutiny of generator submissions. 

But such review and scrutiny are 

essential given the sheer number of 

filings and the absence of standardized 

accounting for the costs claimed in them 

by generators.’’ 86

36. AEP states that it supports the 

Commission’s proposal to prospectively 

terminate reactive power compensation 

to generators for maintaining the ability 

to produce reactive power within the 

standard power factor range because it 

‘‘will more equitably balance the 

interests of customers and generators, 

ensure that reactive power will continue 

to be provided as a requirement of 

interconnection, and significantly 

decrease the administrative burdens 

associated with individualized, opaque, 

and inconsistent cost-of-service reactive 

power rate proceedings.’’ 87

37. Similarly, New England Consumer 

Advocates state that ‘‘[t]ransmission 

rates have been rising in recent years 

and costs are only expected to increase 

in the near term to accommodate 

projected future transmission system 


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88New England Consumer Advocates Initial 

Comments at 3–4. See also PJM IMM Initial 

Comments at 5 (‘‘Most recent cases settled prior to 

issuance of the NOPR have settled for costs well in 

excess of the average cost and well in excess of the 

ARR offset amount. The issue is growing in 

significance.’’); MISO Transmission Owners Initial 

Comments at 5 (‘‘The Commission’s preliminary 

findings that led to the changes proposed in the 

NOPR are accurate. The current framework for 

reactive power compensation can result in 

transmission customers being required to pay for a 

service that generators already are required to 

provide and that costs them little or nothing to 

provide. Therefore, the current framework allows 

for compensation that is neither just nor 

reasonable.’’). 

89PJM IMM Reply Comments at 1–2. 90Clean Energy Associations Initial Comments at 

2–3; Indicated Trade Associations Reply Comments 

at 16; NEI Initial Comments at 1. 91Reactive Service Providers Initial Comments at 

4, 29–34. 92 Id. at 41–43. 93 Id. at 43–48. 94 Id. at 48–52. 95 Id. at 53–54. 

96 Id. at 76–77. 

97 Id. at 77. 

98 Indicated Trade Associations Reply Comments 

at 16–17. 

99 Id. at 8–9. 

100 ISO–NE Initial Comments at 1–2, NESCOE 

Reply Comments at 2; NEPGA Reply Comments at 

6–7; NEPOOL Reply Comments at 6–7. ISO–NE 

explains that its VAR service consists of four 

components: (1) the fixed Capacity Cost (CC) rate, 

under which Qualified Reactive Resources are 

eligible to receive VAR payments for their 

measurable capability to provide VAR service to the 

New England Transmission System; (2) the variable 

Lost Opportunity Cost, which compensates for the 

value of a resource’s lost opportunity in the 

wholesale energy market in situations where a 

resource that would otherwise be economically 

dispatched is directed by the ISO to reduce real 

power output to provide more reactive power; (3) 

the variable Cost of Energy Consumed, which 

compensates for the cost of energy consumed by the 

resource solely to provide reactive power; and (4) 

the Cost of Energy Produced, which compensates 

for the difference between the locational marginal 

price and a resource’s offer price, if the locational 

marginal price is lower than the offer price, for each 

hour the resource provides reactive power. ISO–NE 

Initial Comments at 3–4. ISO–NE notes that the 

components other than the CC component may 

occur infrequently and are far less than the CC rate 

component. ISO–NE Initial Comments at 4 n.5. 

101 ISO–NE Initial Comments at 1–2. 

102 Id. at 3–5, 14. The ISO New England Ancillary 

Service Schedule 2 Business Procedure is available 

on the ISO–NE website: https://www.iso-ne.com/ 

static-assets/documents/rules_proceds/operating/ 

gen_var_cap/schedule_2_var_business_

procedure.pdf. Operating Procedures include 

primarily: ISO New England Operating Procedure 

No. 12—Voltage and Reactive Control, available at 

https://www.iso-ne.com/static-assets/documents/ 

rules_proceds/operating/isone/op12/op12_rto_

final.pdf; and ISO New England Operating 

Procedures No. 23—Generating Resource Auditing, 

available at http://www.iso-ne.com/static-assets/ 

documents/rules_proceds/operating/isone/op23/ 

op23_rto_final.pdf. 

103NEPOOL Reply Comments at 6–7. 

104 Id. at 6–7. 

105NYISO Initial Comments at 1. 

106 Id. at 2; IPPNY Reply Comments at 1–2. 

needs. At this time of increasingly 

onerous retail energy costs, particularly 

in New England, the Commission must 

ensure that transmission providers are 

passing on to consumers only those 

costs which are just and reasonable, and 

for which consumers receive 

commensurate benefit.’’ 88

38. The PJM IMM argues that 

opposing comments come largely from 

generation owners opposed to the 

removal of subsidies that have benefited 

them, even though such subsidies are 

primarily the result of the ‘‘nonsensical, 

wasteful and unworkable’’ attempts to 

allocate a portion of costs recoverable in 

markets to a guaranteed reactive 

payment based on an outdated and 

arbitrary cost-of-service approach 

referred to as the AEP Methodology.89

39. Other commenters opposed the 

NOPR, arguing that existing reactive 

power rates remain just and 

reasonable.90 Reactive Service Providers 

argue that ‘‘changes to cost allocation’’ 

following Order No. 888 (i.e., functional 

unbundling) do not warrant a change to 

reactive power compensation.91

Reactive Service Providers contend that 

reactive power supply being unaffected 

in regions where transmission providers 

no longer pay for reactive power is not 

evidence that reactive power 

compensation is unjust and 

unreasonable,92 that the 

‘‘comparability’’ policy cannot be used 

as a basis to end compensation,93 that 

administrative burden is not a basis to 

find that compensation is unjust and 

unreasonable,94 and that inconsistent 

rate treatment across generating 

facilities does not mean that 

compensation is unjust and 

unreasonable.95

40. Reactive Service Providers argue 

that the Commission should study 

individual generating facilities to 

determine if reactive power is still 

needed.96 Reactive Service Providers 

also argue that the Commission must 

ensure that compensation for providing 

reactive power outside the standard 

power factor range is adequate.97

41. Indicated Trade Associations 

assert that the NOPR would grant 

transmission providers unlawfully 

preferential treatment, creating a 

preference for higher cost transmission 

solutions, and suggest that the 

Commission should withdraw the 

NOPR proposal and refocus its efforts 

on improving the methodologies used to 

determine reactive power rates.98

Further, Indicated Trade Associations 

assert that concerns raised about the 

AEP Methodology being burdensome 

and a lack of refund protections for 

customers do not justify eliminating 

reactive power compensation within the 

standard power factor range 

altogether.99

42. ISO–NE argues that ISO–NE’s 

Schedule 2 VAR compensation program 

should not be disturbed.100 ISO–NE 

asserts that its treatment of reactive 

power is distinct from its energy and 

capacity markets.101 ISO–NE further 

states that its VAR service is not based 

on cost-of-service and is different from 

the standard AEP Methodology but is 

instead based on a resource’s capability 

to provide reactive power. ISO–NE 

explains that its VAR service 

compensates resources at a uniform 

payment rate (i.e., a single rate for 

reactive power provided within and 

outside of the standard power factor 

range) and is not resource-intensive to 

calculate.102 ISO–NE adds that total 

VAR payments amounted to 0.25% of 

the total energy, ancillary services, and 

capacity markets combined (or 

approximately 18–20 million dollars) 

for the same given period. NEPOOL 

argues that one of the reasons Schedule 

2 has worked well for New England is 

that it provides a simple fixed rate for 

the main component of VAR service, 

which pays part of the costs of a reactive 

power resource’s capability to provide 

VAR service to the transmission system 

when needed. NEPOOL explains that 

this same fixed rate is provided to all 

qualified resources without further 

analysis of, or dispute about, resourcespecific costs.103 NEPOOL argues that 

one of the reasons Schedule 2 has 

worked well for New England is that it 

provides a simple fixed rate for the main 

component of VAR service, which pays 

part of the costs of a reactive power 

resource’s capability to provide VAR 

service to the transmission system when 

needed, without further analysis of, or 

dispute about, resource-specific 

costs.104

43. NYISO challenges the 

Commission’s preliminary conclusion 

that compensating generating facilities 

for providing reactive power within the 

standard power factor range has resulted 

in unjust and unreasonable transmission 

rates and urges the Commission to allow 

NYISO to maintain its current reactive 

power compensation program.105

NYISO states that it supports the 

NOPR’s objective to avoid 

administratively burdensome processes 

and procedures to determine 

individualized cost-of-service reactive 

power rates for generation facilities. 

NYISO adds that NYISO’s existing 

reactive power and Voltage Support 

Service (VSS) compensation structure, 

which uses a flat dollars per MVAr-year 

structure, is just and reasonable.106

NYISO maintains that this structure 

aligns costs directly with services 

provided, ensures reliability benefits 


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107NYISO Initial Comments at 2–5. 

108 Id. at 7–8. 

109 Id. at 7–8. 

110 Id. at 14. 

111 Indicated Trade Associations Initial 

Comments at 22–24 (citing Smyth v. Ames, 169 U.S. 

466, 546 (1898)). 

112 Generation Developers Initial Comments at 26 

(citing Horne v. Dept. of Ag., 576 U.S. 350, 359, 367 

(2015); FPC v. Hope Nat. Gas Co., 320 U.S. 591, 603 

(1944); Bluefield Waterworks & Improvement Co. v. 

Pub. Serv. Comm’n, 262 U.S. 679, 690 (1923)). 

113PSEG Initial Comments at 18–19 (citing 

Bluefield Waterworks & Improvement Co. v. Pub. 

Serv. Comm’n, 262 U.S. at 690; Duquesne Light Co. 

v. Barash, 488 U.S. 299, 308 (1989) (‘‘If the rate does 

not afford sufficient compensation, the State has 

taken the use of the utility property without paying 

just compensation.’’)). 

114PSEG Initial Comments at 19–20 (citing 

Ameren Servs. Co. v. FERC, 880 F.3d 571, 581–82 

(D.C. Cir. 2018)). 

115MISO Transmission Owners Reply Comments 

at 12 n.33. 

116 Id. (citing Transmission Plan. & Cost 

Allocation by Transmission Owning & Operating 

Pub. Utils., Order No. 1000–A, 77 FR 32184 (May 

31, 2012), 139 FERC ¶ 61,132, at P 368 (citing 

Connolly v. Pension Guar. Corp., 475 U.S. 211, 224 

(1986)), order on reh’g and clarification, Order No. 

1000–B, 77 FR 64890 (Oct. 24, 2012), 141 FERC 

¶ 61,044 (2012), aff’d sub nom. S.C. Pub. Serv. 

Auth. v. FERC, 762 F.3d 41 (D.C. Cir. 2014)). 

117 Id. (citing Order No. 1000–A, 139 FERC 

¶ 61,132 at P 369 (citing Connolly v. Pension Guar. 

Corp., 475 U.S. at 223)). 

118 Id. (citing Bd. of Regents of State Coll. v. Roth, 

408 U.S. 564, 577 (1972) (‘‘To have a property 

interest in a benefit, a person clearly must have 

more than an abstract need or desire for it. He must 

have more than a unilateral expectation of it. He 

must, instead, have a legitimate claim of 

entitlement to it.’’); Del. Riverkeeper Network v. 

FERC, 895 F.3d 102, 108–09 (D.C. Cir. 2018) (citing 

Town of Castle Rock, Colo. v. Gonzales, 545 U.S. 

748, 756 (2005)). 

119Eagle Creek Initial Comments at 4; NHA Initial 

Comments at 8–9. 

120Eagle Creek Initial Comments at 4; NHA Initial 

Comments at 8. 

121Eagle Creek Initial Comments at 4–5; NHA 

Initial Comments at 8. 

122NHA Initial Comments at 8–9; see also Eagle 

Creek Initial Comments at 4–5. 

123 Joint Customers Reply Comments at 13–14. 

124 Id. (‘‘There is no validity to the argument that 

individual rate challenges must be pursued by the 

Commission or complainants, and it is well 

established that a change to the underlying 

Schedule 2 in a transmission provider’s tariff, as 

proposed by the Commission in the NOPR, will 

contemporaneously end compensation to thirdparty generators with no further action required.’’); 

see also PJM IMM Initial Comments at 9 (‘‘The 

NOPR does not propose a new Commission policy. 

Rather, it extends and makes uniform policies that 

have long applied in jurisdictional markets.’’). 

commensurate with expenses,107

provides market-like incentives, and 

encourages resources to offer reactive 

power cost-effectively by rewarding 

increased capability and maintaining 

necessary equipment,108 which reduces 

the need for complex, individualized 

cost-based payments and integrates 

reactive power support efficiently into 

the broader market framework, 

promoting economic efficiency and 

reliability.109 NYISO contends that a 

uniform implementation approach is 

not suitable given the varying regional 

needs and existing effective 

compensation frameworks.110

44. Indicated Trade Associations, 

Generation Developers, NEI and PSEG 

raise constitutional claims with respect 

to the NOPR proposal. Indicated Trade 

Associations argue that the proposed 

rule violates the Takings Clause of the 

Fifth Amendment to the United States 

Constitution.111 They argue that public 

utilities have the statutory and 

constitutional right to compensation for 

the services they provide, including 

reactive power, and the Commission 

cannot deprive public utilities of just 

and reasonable compensation simply by 

characterizing the provision of reactive 

power as a condition of interconnection, 

particularly where it was the 

Commission that established this 

condition. Similarly, Generation 

Developers argue that forcing generators 

to supply an identifiable portion of the 

reactive power they generate, without 

any compensation, as a condition of 

interconnection to the transmission 

system, falls squarely within the kinds 

of takings prohibited by the Takings 

Clause.112 PSEG states that, in 

accordance with the FPA and the 

Supreme Court precedent in Hope, the 

Commission has a duty to protect public 

utilities from rates that are 

confiscatory.113 PSEG argues that the 

proposed rule, not unlike the 

Commission denying transmission 

owners the opportunity to earn a return 

on network upgrades in Ameren, 

essentially compels generators to 

provide a service without the ability to 

recover their fixed associated costs, 

which is unjust and unreasonable, 

unduly discriminatory, and confiscatory 

and in violation of the FPA and judicial 

precedent.114

45. MISO Transmission Owners 

disagree with commenters arguing that 

the NOPR proposal constitutes an 

unconstitutional taking.115 They 

contend that the commenters’ claim that 

the Order No. 2003 requirement for 

generators to provide reactive power 

within the standard power factor range 

violates the Takings Clause of the U.S. 

Constitution is a collateral attack on 

Order No. 2003. They contend that, 

while some contractual rights are 

considered ‘‘property’’ within the 

meaning of the Takings Clause of the 

Fifth Amendment, the contractual 

relationship entered into when a 

generator interconnects with a 

transmission system does not implicate 

a taking that must be compensated.116

MISO Transmission Owners state that 

the Commission determined in Order 

No. 2003 that generators ‘‘should not be 

compensated for reactive power when 

operating [their] Generating Facilit[ies] 

within the established power factor 

range, since [they are] only meeting 

[their] obligation.’’ Moreover, they state 

that ‘‘as ‘legislation [that] readjust[s] 

rights and burdens is not unlawful 

solely because it upsets otherwise 

settled expectations,’ the Commission’s 

action implementing the changes in the 

NOPR would not constitute an 

unconstitutional taking just because the 

changes would ‘impact the benefits and 

burdens’ of the agreement entered into 

by generators interconnecting with the 

Transmission System.’’ 117 They 

contend that ‘‘[g]enerators have only a 

unilateral expectation of payment for 

the provision of reactive power and not 

a legitimate claim of entitlement to 

compensation.’’ 118

46. Eagle Creek and the NHA both 

assert that existing reactive service rates 

enjoy the Mobile-Sierra presumption. 

The NHA asserts that, in order for the 

Commission to disallow the existing 

reactive service rates, each rate on-file 

must be demonstrated by the 

Commission to ‘‘seriously harm the 

public interest.’’ 119 Eagle Creek and the 

NHA both note that, given the highly 

localized nature of reactive power, it is 

unclear how the Commission could 

assess these individual contracts 

without conducting a case-by-case 

analysis through individual section 206 

proceedings.120 Eagle Creek and the 

NHA claim that absent such 

proceedings, generating facilities would 

be deprived of their current just and 

reasonable compensation and previous 

investments made by generating 

facilities would be compromised.121 The 

NHA and Eagle Creek assert that, by 

relying on a generic rulemaking to 

effectively cancel all reactive power 

rates, the NOPR is an ‘‘act of 

convenience’’ and ‘‘an indirect attempt 

to strip the value of existing rates 

without facing the legal challenge that 

the Mobile-Sierra doctrine presents.’’ 122

47. Joint Customers disagree with 

Eagle Creek and the NHA’s argument 

that the Commission cannot eliminate 

compensation within the standard 

power factor range without initiating 

individual rate proceedings.123 Joint 

Customers explain that precedent cases, 

such as PNM and MISO, demonstrate 

that changes to the underlying Schedule 

2 tariff provisions effectively eliminate 

compensation for third-party generators 

without separate rate challenges.124

48. Reactive Service Providers and 

Generation Developers argue that the 

NOPR violates the D.C. Circuit’s holding 


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125Atl. City Elec. Co. v. FERC, 295 F.3d 1 (D.C. 

Cir. 2002) (Atl. City). 

126 Generation Developers Initial Comments at 

31–32 (citing Atl. City, 295 F.3d at 9–10); Reactive 

Service Providers Initial Comments at 54. 

127NOPR, 186 FERC ¶ 61,203 at PP 24–27, 28. 

128See, e.g., MISO Transmission Owners Initial 

Comments at 5; Joint Customers Initial Comments 

at 6–16, PJM IMM Initial Comments at 1–4, 6–9; 

PJM IMM Reply Comments at 2–3, 6–7; Ameren 

Initial Comments 2–3; AEP Initial Comments at 4– 

5; Ohio FEA Initial Comments at 5–6; TAPs Initial 

Comments at 1, 3–8; PGE Initial Comments at 3–4. 

129See, e.g., New England Consumer Advocates 

Initial Comments at 3 & n.7 (citing, e.g., 

Massachusetts Attorney General Maura Healey, 

Initial Comments, Docket No. RM21–17–000, at 28 

(filed Aug. 17, 2022); see also New England States 

Committee on Electricity, New England States’ 

Vision for a Clean, Affordable, and Reliable 21st 

Century Regional Electric Grid (2020), https://

nescoe.com/resource-center/vision-stmt-oct2020/). 

130See PSC VSMPO-Avisma Corp. v. U.S., 688 

F.3d 751, 756 (Fed. Cir. 2012) (‘‘[J]oint products 

[are] two dissimilar end products that are produced 

from a single production process.’’) (citing Robert 

A. Anthony & James S. Reece, Accounting 

Principles 442 (5th ed. 1983). 

131A 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. Permian Basin, 390 U.S. at 761 n.25 (citing 

Accounting Tools, The Supply and Price of Natural 

Gas 25 (1962)) (‘‘Joint costs ‘are incurred when 

products cannot be separately produced.’’’); https:// 

www.accountingtools.com/articles/joint-cost. 

132See SPP, 119 FERC ¶ 61,199, at P 28 (‘‘[I]f a 

generator is to sell (and be able to deliver) its power 

to a customer, reactive power is essential to the 

transaction. Thus, it is hardly surprising that the 

Commission has concluded, . . . , that the 

provision of sufficient reactive power is an 

obligation of a generator interconnected to the 

system, and that, . . . , a generator is not entitled 

to separate compensation for providing reactive 

power within its deadband.’’). 

133See, e.g., Eagle Creek Initial Comments at 3– 

4; Indicated Trade Associations Initial Comments at 

7; ACORE Initial Comments at 2; Elevate 

Renewables Initial Comments at 9–12; Generation 

Developers Initial Comments at 13; Glenvale Initial 

Comments at 9–10; Indicated Reactive Power 

Suppliers Initial Comments at 2, 9–10; Indicated 

Trade Associations Initial Comments at 2, 6; Middle 

River Power Initial Comments at 2–3; NEI Initial 

Comments at 4–5, 8–9; NHA Initial Comments at 2, 

4–5. 

134Although the Commission found in the MISO 

Rehearing Order, and earlier, that ‘‘Reactive Service 

requires little or no incremental investment’’ see, 

e.g., MISO Rehearing Order, 184 FERC ¶ 61,022 at 

P 29 (emphasis added), we note that beyond vague 

assertions that incremental fixed costs are incurred, 

no evidence of investment or fixed costs specific to 

providing reactive power was provided in response 

to requests for such costs in the MISO Rehearing 

Order, the NOI, or the NOPR. As such, the 

Commission concludes below that there are no 

incremental or fixed costs to provide reactive power 

beyond those to provide real power. 

135Under certain transmission system conditions, 

the generating facility may operate at a power factor 

of 1.0, which represents zero incremental variable 

costs and thus zero total costs of providing reactive 

power. A generating facility operating at any 

reactive power level (i.e., a power factor other than 

1.0) will incur some amount of incremental fuel 

cost, but the Commission generally considers these 

costs de minimis within the standard power factor 

range. See, e.g., APS, 94 FERC at 61,080 (‘‘We note 

that operating a generating unit within the proposed 

[standard power factor range] does not affect the 

generation output of a unit.’’); Commission Staff 

Report, Principles for Efficient and Reliable 

Reactive Power Supply and Consumption, Docket 

No. AD05–1–000, at 96 (2005 Staff Report) (2005) 

(‘‘The marginal cost of providing reactive power 

from within a generator’s capability curve (D-curve) 

is near zero.’’). 

136Panda Stonewall, LLC, 176 FERC ¶ 61,072, at 

P 6 n.9 (2021). We note that the heating losses 

component reflects the incremental fuel cost of 

providing reactive power. See, e.g., Panda 

Stonewall, LLC, 174 FERC ¶ 61,266, at P 155 (2021) 

(‘‘The AEP methodology already has a means in 

place to provide compensation for the small amount 

of additional fuel used during the production of 

reactive power, which is a heating loss calculation 

based on the MW-hours of actual reactive power 

production and the usage charges for fuel.’’). 

137See Belmont Mun. Light Dep’t v. FERC, 38 

F.4th at 173, 179, 186 (2022) (finding that the 

Commission’s approval of a portion of ISO–NE’s 

Inventoried Energy Program ‘‘was not reasoned 

decisionmaking’’ 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). 

in Atlantic City.125 They assert that by 

using the Commission’s authority under 

section 206 of the FPA to eliminate 

reactive power compensation, the NOPR 

essentially strips generating facilities of 

their ability to make filings under 

section 205 of the FPA to recover the 

costs of the reactive power service that 

they provide.126

2. Commission Determination 

49. Based on our review of the record, 

we find that there is substantial 

evidence to support the conclusion that 

transmission rates are unjust and 

unreasonable to the extent they include 

charges associated with the provision of 

reactive power within the standard 

power factor range. We therefore adopt 

the preliminary findings in the NOPR 

concerning the need for reform 127 and, 

pursuant to section 206 of the FPA, 

conclude that certain revisions to 

Schedule 2 of the pro forma OATT, pro 

forma LGIA, and pro forma SGIA are 

necessary to ensure rates that are just, 

reasonable, and not unduly 

discriminatory or preferential. 

50. We agree with commenters that 

the current framework allows for 

transmission rates that are ‘‘neither just 

nor reasonable’’ and ‘‘can result in 

transmission customers being required 

to pay for a service that generators 

already are required to provide and that 

costs them little or nothing to 

provide.’’ 128 As reflected in the record, 

absent reform, transmission customers 

would be required to continue to pay 

charges associated with generating 

facilities’ provision of reactive power 

within the standard power factor range 

even though such charges are without a 

sufficient economic basis and do not 

result in transmission customers 

receiving commensurate reliability 

benefits. The need for reform is 

particularly acute given that 

‘‘transmission rates have been rising in 

recent years and costs are only expected 

to increase in the near term to 

accommodate projected future 

transmission system needs.’’ 129

51. As described below, most 

commenters agree or do not dispute that 

real and reactive power are provided as 

joint products,130 with joint costs.131

Similarly, most commenters agree or do 

not dispute that, under their 

interconnection agreements and in 

accordance with good utility practice, 

generating facilities have a longstanding obligation to provide reactive 

power within the standard power factor 

range in order to interconnect reliably to 

the transmission system. Most 

commenters agree or do not dispute that 

generating facilities must produce 

reactive power within the standard 

power factor range to allow the 

generating facilities’ real power to 

reliably flow to load.132 As such, we 

disagree with some commenters who 

challenge the Commission’s preliminary 

finding that providing reactive power 

within the standard power factor range 

has no or de minimis costs 133 and find, 

as discussed in greater detail below, that 

there is substantial evidence to 

conclude that in satisfying such 

obligations generating facilities incur no 

incremental investment, or fixed costs, 

and at most de minimis variable costs 

over and above those needed to provide 

real power.134 This is because no 

additional equipment is required to 

provide reactive power; rather the same 

equipment that is needed to produce, 

and is used to produce, real power also 

provides reactive power functions, at no 

additional capital cost. Variable costs, if 

any, are limited to the fuel costs (in 

synchronous facilities) or the cost of 

foregone direct current power (in nonsynchronous facilities) necessary to 

provide the reactive power and to 

reliably inject real power into the 

transmission system.135 For example, in 

Panda Stonewall the annual revenue 

requirement of $2,051,894 included just 

$10,018 of identified variable costs.136

In light of this evidence, we find that 

charging transmission customers for the 

provision of reactive power within the 

standard power factor range results in 

unjust and unreasonable rates.137

52. ISO–NE and NYISO oppose the 

NOPR and seek flexibility to preserve 

their existing reactive power 

compensation regimes. We deny their 

requests. ISO–NE and NYISO 

principally argue that their flat-rate 


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138See, e.g., BPA, 120 FERC ¶ 61,211 at P 21 

(‘‘The 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.’’); SPP, 119 FERC ¶ 61,199 

at P 28 (‘‘[I]f a generator is to sell (and be able to 

deliver) its power to a customer, reactive power is 

essential to the transaction’’). See also PJM 

Interconnection, L.L.C., 145 FERC ¶ 61,280, at P 17 

(2013) (approving tariff revisions that require 

interconnection customers to pay for upgraded 

telecommunication equipment (phasor 

measurement units) as the ‘‘data is integral to 

improved communication and to the reliability of 

the system and, as such, benefits both the system 

and the generators’’). 

139New England Consumer Advocates Initial 

Comments at 5 (‘‘To the extent . . . benefits are 

achieved by compliance with a generating facility’s 

interconnection agreement and/or as ‘good utility 

practice,’ [New England Consumer Advocates] 

agree[] with the Commission that ratepayers should 

not be paying separately for the costs to produce a 

joint reactive power product.’’). 

140See, e.g., Ill. Com. Comm’n. v. FERC, 576 F.3d 

at 476 (‘‘[The Commission] is not authorized to 

approve a pricing scheme that requires a group of 

utilities to pay for facilities from which its members 

derive no benefits, or benefits that are trivial in 

relation to the costs sought to be shifted to its 

members.’’). 

141See infra II.D.2. 

142 ISO–NE notes that not all generating facilities 

are obligated to provide reactive power within the 

standard power factor range. ISO–NE Initial 

Comments at 9. Specifically, ISO–NE notes that 

several older generating facilities in New England 

have interconnection agreements that pre-date the 

obligation to provide reactive power within the 

standard power factor range. Id. ISO–NE states that 

these resources choose to participate in the 

Schedule 2 VAR compensation program, incurring 

an obligation to maintain and provide VAR service 

in New England. Id. Any generating facilities with 

individualized bilateral contracts providing for 

reactive power compensation within the standard 

power factor range may pursue claims that they 

have an independent contractual right to reactive 

power compensation within the standard power 

factor range, but we express no opinion here as to 

whether any such generator would be entitled to 

such compensation. 

143See, e.g., BPA, 120 FERC ¶ 61,211 at P 21 

(‘‘The 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.’’); SPP Order on 

Rehearing, 121 FERC ¶ 61,196 at P 15 (‘‘As we have 

previously explained, reactive power is required for 

an interconnecting generator to deliver its power 

and reactive power produced within the [standard 

power factor range] and is, therefore, generally not 

compensable.’’ (emphasis added)). 

144 Joint Customers Initial Comments at 12 (‘‘This 

incentive structure to provide payment based on 

reactive capability results in the building of 

unnecessary capabilities in locations it is not or 

may not be needed and does not allocate the costs 

associated with reactive capability in a manner that 

is at least roughly commensurate with the benefits 

received.’’ (citing Ill. Com. Comm’n. v. FERC, 576 

F.3d at 477)); MISO Transmission Owners Initial 

Comments at 8 (‘‘Moreover, the capability-based 

compensation methodology currently permitted by 

the Commission . . . allows and even incentivizes 

generators to add as much reactive equipment as 

they desire, i.e., to gold plate a facility’s reactive 

capability, regardless of whether that reactive 

support is needed at that point on the grid.’’); TAPS 

Initial Comments at 4–5 (‘‘Nor can customers be 

assured they are receiving reliability benefits 

commensurate to the reactive power compensation 

paid under the current approach. The existing 

approach to reactive power capability 

compensation does not adequately consider a 

generator’s actual contribution to reliability, or lack 

thereof. For example, that approach does not 

account for relevant factors such as location, the 

need for reactive power, deliverability to where 

reactive power may be needed, possible degradation 

in generator performance or other changes over 

time. The result is that the current approach to 

reactive power compensation requires consumers to 

pay excessive charges for reactive power that may 

not be needed or is in the wrong location.’’ 

(citations omitted)). See Belmont Mun. Light Dep’t 

v. FERC, 38 F.4th at 187–90 (finding that the 

Commission’s acceptance of ISO–NE’s Inventoried 

Energy Program ‘‘was not reasoned decision 

making’’ because record evidence indicated that 

certain types of generating facilities ‘‘would not 

change their behavior in response to payments.’’). 

compensation regimes are transparent, 

not administratively burdensome, 

designed to prevent double-recovery, 

and able to procure significant 

reliability benefits at ‘‘reasonable’’ or 

‘‘low’’ cost. However, these arguments 

ignore the preliminary findings of the 

NOPR, namely that generating facilities 

providing reactive power within the 

standard power factor range are only 

meeting their obligations under their 

interconnection agreements in 

accordance with good utility practice, 

and in doing so incur no or at most a 

de minimis increase in variable costs 

beyond the cost of providing real power. 

As explained in this final determination 

and decades of prior Commission 

precedent, in order to reliably 

interconnect to the transmission system 

and deliver real power to customers, 

generating facilities must be capable of 

maintaining voltage levels for injecting 

real power into the transmission 

system.138 As relevant here, these 

findings apply equally to flat-rate 

compensation regimes like ISO–NE’s 

and NYISO’s, as well as the 

compensation regimes of PJM and 

certain non-RTO regions. Thus, the 

ISO–NE and NYISO regimes, while 

easier to implement administratively, 

also impose unreasonable and 

unsupportable costs on transmission 

customers. 

53. ISO–NE’s and NYISO’s claims 

regarding transparency, administrative 

burden, and preventing double recovery 

all presuppose that compensation is 

due, and thus that a compensation 

method is needed. But, where 

compensation is found to be unjust and 

unreasonable, as we find here, such a 

compensation methodology will 

necessarily result in unjust and 

unreasonable rates and thus is not 

permissible. 

54. Additionally, we agree with New 

England Consumer Advocates,139 who 

argue that any payment for reactive 

power capability within the standard 

power factor range must yield some 

roughly commensurate incremental 

benefit above and beyond that which 

would accrue absent payment.140 As 

discussed below,141 ISO–NE and NYISO 

allude generally to reliability benefits 

from reactive power compensation over 

the full range of a resource’s capability 

to provide reactive power—that is, both 

within and outside of the standard 

power factor range—rather than the 

narrower focus of this final 

determination. And, in both ISO–NE 

(except for certain circumstances as 

explained by ISO–NE) 142 and NYISO, as 

everywhere, generating facilities must 

provide reactive power within the 

standard power factor range to make 

sales of real power regardless of whether 

they receive separate compensation.143

55. We do not dispute that the 

provision of reactive power within the 

standard power factor range provides 

reliability benefits, only that there are 

no incremental fixed costs other than 

joint costs that are also associated with 

the production of real power and at 

most de minimis incremental variable 

costs that would warrant a separate 

compensation mechanism. We also find 

that there is substantial evidence to 

conclude that, under the current 

reactive power compensation 

framework, reactive power-related 

transmission charges are not tied to 

geographic need and result in excess 

reactive power capability that is not 

required for interconnection and does 

not provide transmission customers 

with commensurate reliability 

benefits.144 Accordingly, we deny ISO– 

NE’s and NYISO’s respective requests 

for flexibility to include in transmission 

rates charges associated with the 

provision of reactive power within the 

standard power factor range. 

56. We reject commenters’ arguments 

that the final determination violates the 

Fifth and Fourteenth Amendments of 

the U.S. Constitution. The final 

determination’s elimination of reactive 

power payments for the provision of 

reactive power within the standard 

power factor range is not confiscatory 

and would not amount to a taking of 

property. As noted above, generating 

facilities incur no or at most a de 

minimis increase in variable costs 

beyond the cost of providing real power 

and have the opportunity to seek 

recovery of any costs they do incur. In 

addition, commenters’ arguments that 

the obligation to provide reactive power 

within the standard power factor range 

is unconstitutional are impermissible 


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145MISO Transmission Owners Reply Comments 

at 12 n.33 (‘‘Moreover, as ‘legislation [that] 

readjust[s] rights and burdens is not unlawful solely 

because it upsets otherwise settled expectations,’ 

the Commission’s action implementing the changes 

in the NOPR would not constitute an 

unconstitutional taking just because the changes 

would ‘impact the benefits and burdens’ of the 

agreement entered into by generators 

interconnecting with the Transmission System. 

Generators have only a unilateral expectation of 

payment for the provision of reactive power and not 

a legitimate claim of entitlement to compensation.’’) 

(citations omitted). See also MISO, 182 FERC 

¶ 61,033 at P 62; MISO Rehearing Order, 184 FERC 

¶ 61,022 at PP 52–54 (‘‘Vistra has not persuaded us 

that it has a property interest in continued Reactive 

Service compensation under the Tariff, nor that 

MISO TOs’ proposal would unconstitutionally 

deprive generators of that putative property interest 

under the Takings Clause or Due Process Clause of 

the Fifth Amendment.’’). 

146See, e.g., MISO, 182 FERC ¶ 61,033 at P 62 

(citing SPP, 119 FERC ¶ 61,199 at P 28); MISO 

Rehearing Order, 184 FERC ¶ 61,022 at P 52 

(finding that protesters constitutional claims were 

impermissible collateral attacks on the 

Commission’s prior determinations given ‘‘[t]he 

obligation to provide Reactive Service exists 

independent of, and was not altered by, MISO TOs’ 

proposal: it was stated in Order No. 2003 and 

applies to individual generators through their 

GIAs.’’). 

147See, e.g., MISO Rehearing Order, 184 FERC 

¶ 61,022 at P 53 (‘‘[T]he function of generators’ 

Reactive Service is to ensure that generators’ real 

power can enter the transmission grid while 

maintaining system reliability.’’); SPP, 119 FERC 

¶ 61,199 at P 28 (explaining that if a generator is 

to sell (and be able to deliver) its power to a 

customer, reactive power is essential to the 

transaction). 

148NOPR, 186 FERC ¶ 61,203 at P 4 (citing Order 

No. 2003–A, 106 FERC ¶ 61,220 at P 416). See also 

MISO Rehearing Order, 184 FERC ¶ 61,022 at P 26 

(‘‘On rehearing, we continue to reject, as collateral 

attacks on that longstanding policy, arguments that 

stand-alone compensation for Reactive Service is 

generically required—for example, to ensure that 

generators can recover their costs for Reactive 

Service capability. These arguments would negate 

the conclusions in Order Nos. 2003 and 2003–A 

that such compensation should not be provided, 

except as required by the comparability standard.’’). 

149See MISO Transmission Owners Initial 

Comments at 6 (‘‘The MISO Transmission Owners’ 

experience supports the Commission’s preliminary 

finding that providing reactive power within the 

standard power factor range requires little or no 

cost to generators. Generators incur little or no costs 

beyond what is already needed to produce real 

power because the same equipment used to produce 

real power includes reactive power functions.’’ 

(citations omitted)); PJM IMM Reply Comments at 

3 (‘‘Neither the [Indicated Trade Associations] nor 

any other opposing commenter, nor any of the 

precedent relied upon by opposing commenters, 

identify any additional costs or more than de 

minimis costs incurred by generators in order to 

provide reactive capability.’’). 

150MISO Rehearing Order, 184 FERC ¶ 61,022 at 

P 53; BPA, 120 FERC ¶ 61,211 at P 20; BPA 

Rehearing Order, 125 FERC ¶ 61,273 at P 11; see 

also NOPR, 186 FERC ¶ 61,203 at P 24; see also 

MISO Transmission Owners Initial Comments at 6; 

PJM IMM Reply Comments at 3. 

151Eagle Creek Initial Comments at 4; NHA Initial 

Comments at 8–9. 

152The Commission has explained that the 

Mobile-Sierra ‘‘public interest’’ presumption 

applies to an agreement only if the agreement has 

certain characteristics that justify the presumption. 

In ruling on whether the characteristics necessary 

to justify a Mobile-Sierra presumption are present, 

the Commission must determine whether the 

agreement at issue embodies either: (1) 

individualized rates, terms, or conditions that apply 

only to sophisticated parties who negotiated them 

freely at arm’s length; or (2) rates, terms, or 

conditions that are generally applicable or that 

arose in circumstances that do not provide the 

assurance of justness and reasonableness associated 

with arm’s-length negotiations. Unlike the latter, 

the former constitute contract rates, terms, or 

conditions that necessarily qualify for a MobileSierra presumption. E.g., Linden VFT, LLC v. Pub. 

Serv. Elec. & Gas Co., 161 FERC ¶ 61,264, at P 27 

(2017); PJM Interconnection, L.L.C., 161 FERC 

¶ 61,262, at P 18 (2017); Sw. Power Pool, Inc., 144 

FERC ¶ 61,059, at P 127 (2013), order on reh’g and 

compliance, 149 FERC ¶ 61,048, at P 94 (2014) 

(citations omitted); Midwest Indep. Transmission 

Sys. Operator, Inc., 142 FERC ¶ 61,215, at P 177 

(2013), order on reh’g and compliance, 147 FERC 

¶ 61,127, at P 108 (2014) (citations omitted). 

153See, e.g., Wabash Valley Power Ass’n, Inc. v. 

FERC, 45 F.4th 115, 120 (D.C. Cir. 2022) (‘‘[A] 

contract requiring the purchaser to pay a utility’s 

‘going rate’ on file with FERC, without more, does 

not eliminate review under the ordinary just-andreasonable standard.’’). 

154Cf. Whitetail Solar 3, LLC, Opinion No. 583, 

184 FERC ¶ 61,145, at P 45 (2023) (affirming the 

Presiding Judge’s finding that Schedule 2, not 

Applicants’ interconnection agreements, determines 

whether generating facilities are eligible for 

compensation, therefore, ‘‘there is no reason for the 

Commission to amend the [interconnection 

agreements] of all existing distribution-connected 

generation, as Applicants suggest would be 

necessary in light of the Initial Decision.’’); see also 

MISO, 182 FERC ¶ 61,033 at P 63 (‘‘As described 

above, MISO [Transmission Owners] have the 

unilateral right to change Schedule 2 through an 

FPA section 205 filing and by doing so, they 

automatically change the rate payable for Reactive 

Service that generators contractually agreed to in 

section 9.6.3 of their GIAs.’’ (citations omitted)). 

collateral attacks on our prior 

determinations and unpersuasive.145

57. The Commission has repeatedly 

held that ‘‘the provision of sufficient 

reactive power is an obligation of a 

generator interconnected to the system, 

and . . . as a general matter, a generator 

is not entitled to separate compensation 

for providing reactive power within its 

deadband.’’ 146 A generating facility 

must in fact produce reactive power to 

move real power from the generating 

facility to the transmission system to 

deliver its real power to customers, 

while maintaining system reliability.147

It is only by virtue of comparability that 

generating facilities were previously 

entitled to reactive power 

compensation.148

58. Simply stated, the obligation to 

provide reactive power within the 

standard power range exists 

independent of, and was not altered by, 

the NOPR’s proposal: it was stated in 

Order No. 2003 and applies to 

individual generating facilities through 

their interconnection service 

agreements. This final determination 

changes only the allowance for 

transmission providers to provide 

compensation at their discretion to their 

own and affiliated generating facilities, 

and then to third-party generating 

facilities under the comparability 

standard for the provision of reactive 

power within the standard power factor 

range. This change eliminates a stream 

of revenue under Schedule 2, but we 

find here that such elimination is just 

and reasonable given that the record 

demonstrates that generating facilities 

incur no or at most a de minimis 

increase in variable costs beyond the 

cost of providing real power.149

Moreover, to the extent that generating 

facilities have any costs associated with 

providing reactive power within the 

standard power factor range, generating 

facilities may seek to recover these costs 

through energy or capacity sales.150

Accordingly, and consistent with 

precedent, commenters have not 

persuaded us that they have a property 

interest in continued compensation 

under Schedule 2, or that this final 

determination would unconstitutionally 

deprive generating facilities of that 

putative property interest under the 

Takings Clause or Due Process Clause of 

the Fifth Amendment. 

59. We disagree with Eagle Creek’s 

and the NHA’s assertions that most 

reactive service rate schedules on file 

enjoy the Mobile-Sierra presumption 

and as a result, in order for the 

Commission to disallow the existing 

reactive service rates, each rate on file 

must be demonstrated by the 

Commission to ‘‘seriously harm the 

public interest.’’ 151 While the MobileSierra doctrine establishes a more 

rigorous application of the just and 

reasonable standard when the 

Commission proposes to change an 

individual contract negotiated at armslength,152 reactive power-related 

transmission rates are not individually 

negotiated contract rates, but rather 

transmission owner tariff-based rates of 

general applicability reflected in the 

transmission owner’s Schedule 2.153

The fact that the Commission has 

accepted generating facilities’ rate 

filings setting forth reactive power rates 

covering the provision of reactive power 

within the standard power factor range 

establishes only the rate at which the 

generating facility is obligated to sell 

reactive power to a transmission 

provider; that rate does not establish an 

obligation for the transmission provider 

to purchase such reactive power. Those 

individual rates establish only the 

charges that transmission providers will 

include in transmission rates if, and 

only if the transmission providers’ 

OATTs require the payment of 

compensation for reactive power.154

60. As discussed above, the final 

determination requires revisions to 


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155See Joint Customers Reply Comments at 14 

(‘‘There is no validity to the argument that 

individual rate challenges must be pursued by the 

Commission or complainants, and it is well 

established that a change to the underlying 

Schedule 2 in a transmission provider’s tariff, as 

proposed by the Commission in the NOPR, will 

contemporaneously end compensation to thirdparty generators with no further action required.’’). 

156For example, ISO–NE and NEPOOL claim that 

certain agreements exist that do not obligate certain 

non-generator resources to provide reactive power 

either within or outside of the standard power 

factor range and are still entitled to compensation. 

See supra n.142; ISO–NE Initial Comments at 9; 

NEPOOL Reply Comments at 9. We express no 

opinion here as to whether any such generating 

facility, such as those situations noted by ISO–NE 

and NEPOOL, would be entitled to such 

compensation under such agreements. 

157 Generation Developers Initial Comments at 

31–32 (citing Atl. City, 295 F.3d at 9–10); Reactive 

Service Providers Initial Comments at 54. 

158Cf. MISO, 182 FERC ¶ 61,033 at P 65 (‘‘[W]e 

find that MISO TOs’ proposal does not restrict 

independent power producers’ FPA section 205 

rights to file a rate for reactive power; instead, the 

proposal addresses only the rates chargeable to 

transmission customers under Schedule 2 and by 

extension, payable to resources consistent with 

their GIAs, not any independent right of generators 

to seek compensation under FPA section 205.’’); 

Opinion No. 583, 184 FERC ¶ 61,145 at P 45 

(‘‘Applicants’ [interconnection agreements] do not 

establish an independent right outside the context 

of Schedule 2 to reactive power compensation for 

merely meeting the technical requirements required 

for interconnection.’’); see also Joint Customers 

Initial Comments at 14 (‘‘Without comparability as 

an issue, it is existing Commission policy that it is 

inappropriate to compensate within the standard 

power factor range. The Order No. 2003 

determination that compensation should not be 

paid for reactive service meeting interconnection 

requirements remains well supported.’’ (emphasis 

in original)). We also note that individual 

generating facility reactive power tariffs themselves 

do not establish a payment obligation, only the rate 

that a buyer will pay if it takes service. A tariff rate 

is an offer to sell service at the stated rate; it does 

not establish an obligation on any party to pay that 

rate. See 18 CFR 35.2(c)(1) (‘‘The term tariff as used 

herein shall mean a statement of (1) electric service 

as defined in paragraph (a) of this section offered 

on a generally applicable basis) (emphasis added)); 

Sw. Power Pool, Inc., 149 FERC ¶ 61,048 at P 106 

(‘‘The Commission’s use of the term ‘tariff rates’ as 

generally applicable rates is justified by the 

definition of the term ‘tariff’ set forth in the 

Commission’s regulations under the FPA, which 

state, in part, that a tariff is ‘a statement of . . . 

electric service . . . offered on a generally 

applicable basis.’ ’’). In order to constitute an 

obligation, a party must sign a pro forma or other 

service agreement. See Cal. Indep. Sys. Operator 

Corp., 100 FERC ¶ 61,234, at 61,834 (2002) (‘‘[T]he 

Commission moved to a paradigm of standard 

agreements in which terms and conditions that are 

included in a public utility’s OATT and bilateral 

contracts are replaced by pro forma service 

agreements’’). Therefore, if transmission providers 

revise their Schedule 2’s to eliminate compensation 

for the provision of reactive power within the 

standard power factor range, no party will exist to 

pay the generating facility’s filed tariff rate. See, 

e.g., PNM, 178 FERC ¶ 61,088 (finding that the 

transmission owner is not required to pay for 

reactive power, but not instituting section 206 

proceedings to cancel reactive power tariffs). 

159NOPR, 186 FERC ¶ 61,203 at PP 29–31 

(‘‘[S]ynchronous and non-synchronous resources 

provide real and reactive power as joint products, 

with joint costs.’’). 

160 Id. P 31. 

161 Id. PP 8, 28. 

162 Id. P 33 (citing 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 PP 

29, 33 (rejecting generating facility’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 facility’s 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 

Continued 

Schedule 2 to prohibit the inclusion in 

transmission rates of charges associated 

with reactive power in the standard 

power factor range and, for consistency, 

also requires conforming revisions to 

the pro forma LGIA and pro forma SGIA 

to remove language related to the 

comparability standard. Since Schedule 

2 is a tariff-based rate, that rate can be 

modified under the ordinary just and 

reasonable standard.155 However, this 

final determination does not affect the 

ability of generating facilities to pursue 

claims that they have an independent 

contractual right to reactive power 

compensation within the standard 

power factor range, based on a bilateral 

agreement with the relevant 

transmission owner.156

61. We also find that Generation 

Developers’ and Reactive Service 

Providers’ 157 assertions that the final 

determination would violate Atlantic 

City by depriving generating facilities of 

their FPA section 205 filing rights lack 

merit. The Commission is not depriving 

generating facilities of their filing rights. 

The commenters’ arguments 

fundamentally misunderstand 

generating facility compensation under 

the Commission’s pro forma OATT and 

interconnection agreements. The final 

determination is not adjusting, 

overturning, or reducing to zero any 

generating facility’s rate for reactive 

power within the standard power factor 

range. The final determination 

addresses only the justness and 

reasonableness of transmission rates 

chargeable to transmission customers 

under Schedule 2 and by extension, 

payable to the transmission providers’ 

own generating facilities or affiliated 

generating facilities and third-party 

generating facilities under the 

comparability standard, consistent with 

their interconnection agreements, not 

any independent right of generating 

facilities to establish a rate under FPA 

section 205. While this does result in 

generating facilities, affiliated and nonaffiliated, no longer being entitled to 

compensation for the provision of 

reactive power within the standard 

power factor range as a function of 

comparability, the Commission has 

found that such an outcome does not 

undermine the generating facilities’ FPA 

section 205 filing rights.158

B. Cost of Producing Reactive Power 

62. The NOPR preliminarily found 

that providing compensation for the 

provision of reactive power within the 

standard power factor range is unjust 

and unreasonable. The Commission 

relied on three key points to support 

this preliminary finding. 

63. First, the NOPR relied on the 

Commission’s prior findings that, for 

both synchronous and non-synchronous 

generating facilities, because all 

equipment used to produce reactive 

power is also necessary to produce and 

deliver real power to the transmission 

system, there are no incremental fixed 

costs associated with the provision of 

reactive power within the standard 

power factor range.159 The NOPR also 

explained that the Commission has 

repeatedly found, that ‘‘[v]ariable costs 

of generating reactive power are de 

minimis’’ and ‘‘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.’’ 160 Thus, by providing reactive 

power within the standard power factor 

range, both synchronous and 

nonsynchronous facilities incur no 

additional fixed costs and at most de 

minimis variable costs beyond which 

they already incur to provide real 

power.161

64. Second, the NOPR relied on the 

fact that all generating facilities must 

provide reactive power within the 

standard power factor range as an 

obligation of good utility practice and to 

meet the obligations under their 

interconnection agreements.162


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interconnection); Order No. 2003, 104 FERC 

¶ 61,103 at P 546. 

163NOPR, 186 FERC ¶ 61,203 at P 13 (citing MISO 

Rehearing Order, 184 FERC ¶ 61,022 at P 23). 

164 Id. at P 39. 

165 Id. 

166 Id. 

167 Id. at 39 & nn.100–02. The Commission noted 

that, in PJM for example, while the capacity market 

rules currently account for reactive power payments 

to resources by assuming average reactive power 

compensation of $2,546 per MW-year, reactive 

power revenue requirements in PJM range from 

roughly $1,000 per MW-year to $13,000 per MWyear. The Commission noted that this wide range 

of actual compensation, which is both above and 

below the assumed reactive power compensation in 

the capacity market rules, can lead to market 

distortions. 168AEP; Ameren; Joint Consumer Advocates; 

Joint Customers; MISO Transmission Owners; New 

England Consumer Advocates; Ohio FEA; PGE; 

PJM; the PJM IMM; the Transmission Access Policy 

Study Group. 169See Ameren Initial Comments at 3; Joint 

Customers Reply Comments at 11–13; MISO 

Transmission Owners Initial Comments at 5–7; New 

England Consumer Advocates Initial Comments at 

4–6; PJM IMM Initial Comments at 4. 170Ameren Initial Comments at 3 (citing BPA, 120 

FERC ¶ 61,211 at P 21 (‘‘Evidence from numerous 

reactive power rate filings demonstrates newly 

interconnecting resources have the capability to 

provide reactive power, some well in excess of the 

required 0.95 leading to 0.95 lagging. It is also welldocumented that the same equipment used to 

produce real power includes reactive power 

functions and thus there is little, if any, incremental 

cost associated with providing reactive power.’’)); 

MISO Transmission Owners Initial Comments at 5– 

7 (citing MISO, 182 FERC ¶ 61,033 at P 55; MISO 

Rehearing Order, 184 FERC ¶ 61,022 at PP 25 n.76, 

29–30, 34, 41–42 (‘‘[T]he record establishes, that 

Reactive Service requires little or no incremental 

investment.’’)); MISO Transmission Owners Reply 

Comments at 9; see also Ohio FEA Initial Comments 

at 3. 

171MISO Transmission Owners Initial Comments 

at 7 & n.18 (citing MISO Rehearing Order, 184 FERC 

¶ 61,022 at P 30 n.98 (‘‘[O]lder wind generators 

could not produce and control reactive power 

without the use of costly equipment [ ] ‘because 

they did not use inverters like other nonsynchronous generators’ but modern turbines now 

use inverters and newer wind generators now 

can.’’)). 

172 Id. at 7. 

173 Id. at 9. 

174 Joint Customers Reply Comments at 11–13. 

175 Id. 

176 Id. at 13 (citing Order No. 827, 155 FERC 

¶ 61,277 at P 11 (‘‘Prior to Order No. 827, nonsynchronous generators were exempt from 

complying with power factor requirements. The 

entire point of Order No. 827 was to find that 

technological advancements had reduced the cost of 

compliance such that non-synchronous generators 

no longer needed the exemption. The order also 

explicitly maintained the compensation scheme for 

reactive power, with all that means for the 

elimination of compensation if not justified by 

comparability.’’). 

177PJM IMM Initial Comments at 6–9 (citing PJM, 

OATT, Attachment O, §§ 4.7.1.1.1., 4.7.1.2. (3.0.0)); 

Joint Consumer Advocates Initial Comments at 6– 

7; MISO Transmission Owners Reply Comments at 

4; TAPS Initial Comments at 6; Ohio FEA Initial 

Comments at 5; Joint Customers Initial Comments 

at 14–16; PGE Initial Comments at 4 (citing MISO, 

182 FERC ¶ 61,033 at P 53 (noting that in the 

acceptance of the MISO Transmission Owners 

application to end compensation within the 

standard power application, the Commission 

reiterated its 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.’’)). 

Additionally, the NOPR emphasized 

that ‘‘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.’’ 163 In other 

words, a generating facility must 

produce reactive power within the 

standard power factor range in order to 

generate and safely inject real power 

into the transmission system and 

comply with reliability requirements. 

As such, providing reactive power 

within the standard power factor range 

can be regarded as a joint product with 

providing real power, with joint costs. 

65. Third, the NOPR noted that in 

regions where generating facilities 

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 

distortions in ways that did not exist 

prior to the existence of organized 

markets.164 The NOPR explained that 

the AEP Methodology was created in an 

era of vertically integrated utilities, 

when most utilities filed FERC Form 

No. 1s, used the Uniform System of 

Accounts (USofA) to classify their costs, 

and recovered those costs through costbased rates.165 Today, however, most 

generating facilities recover their costs 

through competitive markets in both 

RTO/ISO and non-RTO/ISO regions, so 

the imprecision of the AEP 

Methodology, the NOPR explained, 

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.166 The NOPR added 

that this is especially true when markets 

fail to account for separate, cost-based 

reactive power revenues by using 

standard rate making techniques.167

1. Comments 

66. Many commenters support the 

NOPR’s finding that transmission 

charges for generating facilities’ 

provision of reactive power within the 

standard power factor range are unjust 

and unreasonable.168 Likewise, many 

commenters support the NOPR’s 

preliminary finding that generating 

facilities already provide reactive power 

within the standard power factor range 

at no cost or de minimis cost.169 Ameren 

and MISO Transmission Owners agree 

with the NOPR that providing reactive 

power within the standard power factor 

range requires little or no cost to 

generators because the same equipment 

used to produce real power includes 

reactive power functions.170 In support, 

MISO Transmission Owners point to 

MISO and the MISO Rehearing Order 

wherein the Commission also 

concluded that, based on that record, 

reactive power service within the 

standard power factor range required 

little or no incremental investment. 

MISO Transmission Owners add that, as 

the Commission found in the MISO 

Rehearing Order, even newer wind 

turbines use inverters that allow 

generating facilities to produce and 

control reactive power without costly 

additional equipment.171 MISO 

Transmission Owners also state that 

generating facility equipment typically 

comes with reactive power capabilities 

that not only meet the standard range 

requirements (i.e., 0.95 leading and 0.95 

lagging) but exceed them (e.g., 0.80– 

0.90).172 MISO Transmission Owners 

argue that since generating facilities 

bear no or at most de minimis 

incremental costs to provide reactive 

power within the standard power factor 

range, one must consider what the 

actual purpose is of compensating 

generating facilities for such service.173

67. Joint Customers state that attempts 

to undermine the NOPR, such as 

challenging the assertion that 

incremental costs of providing reactive 

service within the standard power factor 

range are de minimis, are meritless.174

Joint Customers argue that the costs 

incurred by generators to meet 

interconnection requirements are 

necessary for safe and reliable grid 

operations and that arguments against 

the de minimis designation often 

misrepresent the incremental costs 

involved in meeting interconnection 

requirements versus providing 

additional reactive capability.175 Joint 

Customers note that claims of excessive 

costs for non-synchronous generators to 

comply with power factor requirements 

are collateral attacks on prior 

Commission orders, particularly Order 

No. 827.176

68. The PJM IMM, MISO 

Transmission Owners, and several other 

commenters assert that providing 

reactive power within the standard 

power factor range is an obligation of 

interconnection and consistent with 

good utility practice.177 The PJM IMM 

asserts that the Commission has a long 


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178PJM IMM Initial Comments at 6–8 (citing 

NOPR, 186 FERC ¶ 61,203 at P 5 (citing BPA 

Rehearing Order, 125 FERC ¶ 61,273 at P 18)); see 

also MISO Transmission Owners Initial Comments 

at 10–12. 179PJM IMM Initial Comments at 8. 180 Id. (citing PJM, OATT, Attachment O § 4.7.2. 

(3.0.0)). 181MISO Transmission Owners Initial Comments 

at 9 & n.24 (citing SEIA, Reactive Power 

Compensation: How to Unlock New Revenue 

Opportunities for Solar and Storage Projects, Solar 

Energy Industries Association 4 (July 29, 2020), 

https://old.seia.org/sites/default/files/2023-01/ 

Speaker%20Q&A%20-%20Reactive%20Power

%20Compensation%20Webinar.pdf (also attached 

as Exhibit I) (‘‘Filing for and receiving reactive 

revenues has no impact on the generator’s operating 

profile. The ISO/RTOs have a right to dispatch 

generators to provide reactive service as needed to 

maintain reliability.’’)). The MISO Transmission 

Owners also add that ‘‘[a]t the same time MISO was 

experiencing a dramatic increase in the amounts 

transmission customers paid for reactive power 

service prior to its elimination of compensation for 

reactive power service within the deadband, SEIA 

highlighted that MISO was one of the two ‘most 

lucrative’ regions for reactive power compensation, 

where generators received millions of dollars in 

compensation for having the capability to produce 

reactive power within the deadband, a capability 

that was already a condition of obtaining 

interconnection.’’ Id. at 9–11. 

182 Id. at 10–11 (citing Order No. 2003, 104 FERC 

¶ 61,103 at P 546; Order No. 2003–A, 106 FERC 

¶ 61,220 at PP 410, 416; Order No. 827, 155 FERC 

¶ 61,277 at P 59). 

183 Id. at 11 & n.29 (citing MISO Rehearing Order, 

184 FERC ¶ 61,022 at P 35 n.116 (‘‘[G]enerators 

have incentives to install equipment to ensure that 

their generation remains online and delivering real 

power.’’)). 

184 Id. at 11–12 (citing Reliability Standard VAR– 

002–3—Generator Operation for Maintaining 

Network Voltage Schedules), at 2 (Aug. 1, 2014), 

http://www.nerc.com/pa/Stand/Reliability%20

Standards/VAR-002-3.pdf (‘‘R2 . . . Generator 

Operator shall maintain the generator voltage or 

Reactive Power schedule (within each generating 

Facility’s capabilities).’’). 

185 Id. at 8; PJM IMM Initial Comments at 4–6; see 

also Joint Customers Initial Comments at 4–6. 

186PJM IMM Initial Comments at 3–4. 

187 Id. at 4–6. 

188 Id. at 4. The PJM IMM asserts that these 

revenues provide a nonmarket advantage to 

generating facilities that receive them, resulting in 

an arbitrary and nonmarket-based advantage (i.e., 

distortionary). 

189 Id. at 6 (explaining that in PJM’s capacity 

market, ‘‘the parameters that define the demand 

curve . . . are based on the costs of new entry of 

a reference generating unit, less net revenues from 

other PJM markets’’ such as reactive power 

revenues). The PJM IMM explains that the level of 

these net revenues that are subtracted, or offset, 

from the costs of new entry, are based on a 

calculation from the PJM IMM of the average 

Schedule 2 payment for reactive done in 2008 and 

based on reactive rates from prior years. However, 

the PJM IMM states that ‘‘[m]ost recent cases settled 

prior to issuance of the NOPR have settled for costs 

well in excess of the average cost and well in excess 

of the [] offset amount’’ and that ‘‘[t]he issue is 

growing in significance.’’ Id. at 5. 

190Eagle Creek Initial Comments at 3–4; Indicated 

Trade Associations Initial Comments at 7; ACORE 

Initial Comments at 2; Elevate Renewables Initial 

Comments at 9–12; Generation Developers Initial 

Comments at 13; Glenvale Initial Comments at 9– 

10; Indicated Reactive Power Suppliers Initial 

Comments at 2, 9–10; Indicated Trade Associations 

Initial Comments at 2, 6; Middle River Power Initial 

Comments at 2–3; NEI Initial Comments at 4–5, 8– 

9; NHA Initial Comments at 2, 4–5. Indicated Trade 

Associations also assert that prior Commission 

orders cited by the NOPR to support the assertion 

that no costs or de minimis costs are incurred to 

provide reactive power within the standard power 

factor range do not provide evidence to support the 

conclusion. Indicated Trade Associations Initial 

Comments at 8 (citing BPA, 120 FERC ¶ 61,211 at 

P 21; BPA Rehearing Order, 125 FERC ¶ 61,273 at 

P 7 n.7; Ariz. Pub. Serv. Co., 94 FERC ¶ 61,027, at 

61,080 (2001) (APS)); Onward Energy Reply 

Comments at 2. 

191 Indicated Trade Associations Initial 

Comments at 10; Generation Developers Initial 

Comments at 13. 

192 Indicated Trade Associations Reply Comments 

at 6–7; NEPGA Reply Comments at 3 (citing 

Indicated Trade Association Initial Comments, 

Affidavit of Michael Borgatti, Docket No. RM22–2– 

000 at 9–10 (filed May 28, 2024)); Reactive Service 

Providers Initial Comments at 37–40. 

193See Indicated Trade Associations Initial 

Comments at 11–12 (‘‘[F]or renewable resources, 

Continued 

standing policy that ‘‘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.’’ 178

69. The PJM IMM states that reactive 

power is not the only design obligation 

the generation interconnection 

customers assume.179 The PJM IMM 

notes, for example, that generating 

facilities are required to provide 

primary frequency response capability, 

but the PJM OATT does not provide an 

out of market payment for such service 

because it is treated as an obligation 

assumed by generation interconnection 

customers for receiving interconnection 

service.180 MISO Transmission Owners 

also point out that the SEIA, the 

national trade association for the U.S. 

solar industry, has acknowledged that 

reactive power compensation does not 

affect a generator’s operations and that 

provision of reactive power within the 

standard power factor range is required 

regardless of compensation.181

70. Additionally, MISO Transmission 

Owners agree that the Commission’s 

line of precedent since Order No. 2003 

has required interconnecting generators 

to be able to provide reactive power 

within the standard power factor range 

without compensation, with few 

exceptions.182 MISO Transmission 

Owners argue that generators are 

incented by their own reliability 

requirements to install the equipment 

that will help keep their projects on-line 

and delivering real power, and that 

‘‘skimping’’ on equipment that can 

provide reactive power across a range of 

operating conditions is not in 

generators’ best operational interests or 

consistent with good utility practice.183

MISO Transmission Owners state that 

generating facilities are also required by 

the North American Electric Reliability 

Corporation (NERC) reliability standards 

to operate in automatic voltage control 

mode and maintain a voltage set point 

provided by the transmission 

provider.184

71. MISO Transmission Owners and 

the PJM IMM agree with the NOPR’s 

preliminary finding that the current 

reactive power compensation 

framework allows for undue 

compensation and potential market 

distortions, and they argue that the 

current compensation framework leads 

to ‘‘black-box’’ settlements that lack 

transparency and result in vastly 

disparate rates.185 The PJM IMM argues 

that separately compensating resources 

based on a judgment-based allocation of 

capital costs is not appropriate in the 

PJM markets.186 The PJM IMM argues 

that cost-of-service compensation for 

reactive power distorts markets and 

undermines competition.187 The PJM 

IMM asserts that the current rules create 

strong incentives for generating facilities 

to attempt to maximize the allocation of 

capital costs to reactive service in order 

to maximize guaranteed, nonmarket 

revenues.188 The PJM IMM claims that 

there is no reasonable basis for the 

disparity in the price to customers from 

different types of generators for the 

same service and that reactive power is 

a homogeneous product which should 

have the same price for all sellers. The 

PJM IMM notes that the most recent 

reactive power rate cases settled prior to 

issuance of the NOPR have resulted in 

costs well in excess of the reactive 

power revenue offset assumed in PJM’s 

capacity market.189

72. Many other commenters, in 

contrast, challenge the Commission’s 

preliminary finding that providing 

reactive power within the standard 

power factor range has no or de minimis 

costs.190 The Indicated Trade 

Associations and Generation Developers 

emphasize that the costs of equipment 

and production associated with reactive 

power, particularly for renewable 

resources, are substantial and involve 

significant capital investments.191

Indicated Reactive Power Suppliers, 

NEPGA, and Reactive Service Providers 

assert that eliminating compensation for 

reactive power within the standard 

power factor range is unjust and 

unreasonable, given the substantial 

capital costs incurred by generators.192

They argue that the NOPR’s proposal 

fails to account for these costs as well 

as for lost opportunities for real power 

generation and renewable energy 

credits.193 They assert that the 


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having to back down generation in order to produce 

reactive power would also result in lost renewable 

electricity production tax credits, renewable energy 

certificates, and similar benefits’’); Generation 

Developers Initial Comments at 13. 

194See Indicated Trade Associations Reply 

Comments at 7; Generation Developers Initial 

Comments at 13, 20–21. 

195 Generation Developers Initial Comments at 

24–25; Middle River Power Initial Comments at 4; 

NEI Initial Comments at 7; PSEG Initial Comments 

at 2–3, 11–12; Reactive Service Providers Initial 

Comments at 7–54; NYISO Initial Comments at 1. 

196 Generation Developers Initial Comments at 25. 

197 Id. 

198 Id. at 31; PSEG Initial Comments at 12–13. 

199NEI Initial Comments at 8. 

200 Generation Developers Initial Comments at 

13–17. 

201 Id. at 13 (citing Order No. 2003, 104 FERC 

¶ 61,103 (noting that the Commission exempted 

wind generation from the requirement because 

‘‘wind generators for the most part cannot maintain 

the required power factor, simply because the 

necessary technology does not exist for wind 

generators’’)). 

202 Id. at 13–14 (citing Order No. 661, 111 FERC 

¶ 61,353 at P 46; Order No. 661–A, 113 FERC 

¶ 61,254). Generation Developers add that in Order 

No. 661, the Commission was presented with 

evidence that ‘‘wind turbines cannot meet the 

proposed power factor standard over the full range 

of real power output, and that dynamic VAR control 

(DVAR) banks or static capacitors would have to be 

installed at an additional expense to meet the 

proposed power factor over the entire range.’’ 

Generation Developers Initial Comments at 13 

(citing Order No. 661–A, 113 FERC ¶ 61,254 at P 45 

(emphasis added)). Generation Developers state that 

while Order No. 661 was limited to wind resources, 

the Commission extended the exemption to other 

non-synchronous resources on a case-by-case basis. 

Generation Developers Initial Comments at 14 

(citing Nev. Power Co., 130 FERC ¶ 61,147, at P 27 

(2010)). 

203Order No. 827, 155 FERC ¶ 61,277 at P 21. 

204 Generation Developers Initial Comments at 14. 

205 Id. (citing Order No. 827, 155 FERC ¶ 61,277 

at P 4) (‘‘The Commission instead made its decision 

to apply reactive power requirements to nonsynchronous resources based on its ‘balancing the 

costs to newly-interconnecting non-synchronous 

generators of providing reactive power with the 

benefits to the transmission system of having 

another source of reactive power.’ ’’). 

206 Id. at 17. 

207 Id. at 14–15 (citing 2014 Staff Report (‘‘[M]ost 

dynamic reactive power, which is crucial to 

transmission system reliability, is provided by 

generators.’’). Specifically, Generation Developers 

state that the 2014 Staff Report made the following 

findings: ‘‘(1) the costs of reactive power equipment 

for wind generators range from 3.18% to 4% of their 

capital costs; and (2) the costs of adding reactive 

power capability to solar photovoltaic generators 

range from 2% to 20% of a project’s total costs, 

depending on project size.’’ Id. at 15 (citing 2014 

Staff Report app. 2 at 2–3). 

208 Id. at 15 (citing NOPR, 186 FERC ¶ 61,203 at 

P 29 n.70 (citing MISO Rehearing Order, 184 FERC 

¶ 61,022 at P 30)). 

209 Id. 

210 Id. at 16 (citing BPA, 120 FERC ¶ 61,211; 

METC Rehearing Order, 97 FERC at 61,852–53; 

APS, 94 FERC at 61,080). 

211 Id. at 16–17 n.52 (citing Duke Energy 

Corporation Initial Comments to the NOI at 4). 

Commission’s proposal is inconsistent 

with the FPA’s purpose of ensuring just 

and reasonable returns on investment, 

particularly for inverter-based resources, 

which incur distinct incremental costs 

for reactive power provision.194

73. Some commenters argue that there 

is an insufficient legal foundation under 

section 206 of the FPA to demonstrate 

that all existing reactive power rates are 

unjust and unreasonable.195 Generation 

Developers assert that the fact that many 

generators are required to provide 

reactive power as a condition of 

receiving interconnection service and 

consistent with good utility practice 

does not provide a basis for concluding 

that the compensation received by 

generating facilities is unjust and 

unreasonable.196 Generation Developers 

assert that the Commission’s reasoning 

improperly assumes that generating 

facilities investing in reactive power 

capability are not performing a service 

that benefits the transmission system, 

but is instead only needed to support 

their own deliveries.197 Generation 

Developers assert that the NOPR’s 

categorical determination that the just 

and reasonable reactive power rate is 

zero, and thus all reactive rates that are 

not zero are unjust and unreasonable, 

fails to comply with the requirements of 

section 206 of the FPA.198 NEI adds that 

the Commission failed to meet its 

section 206 burden because the NOPR 

does not offer substantial evidence that 

reactive power costs are zero or 

minimal, cost allocation is 

inappropriate, or reducing reactive 

power compensation to zero would 

allow generators to recover their costs, 

plus a reasonable rate of return.199

74. Generation Developers assert that 

the Commission ignores welldocumented evidence that certain types 

of generating facilities, namely inverterbased generating facilities, incur 

distinct, incremental costs associated 

with providing reactive power.200

Generation Developers assert that, when 

the Commission first required that 

generating facilities be capable of 

supplying reactive power within the 

standard power factor range in Order 

No. 2003, it explicitly exempted wind 

generating facilities from that 

requirement because most wind 

generators could not maintain the power 

factor range.201 Generation Developers 

state that the Commission also generally 

exempted wind generators from 

operating within the standard power 

factor range in Order No. 661 because 

‘‘for wind plants, reactive power 

capability is a significant added 

cost.’’ 202 Generation Developers assert 

that while the Commission removed this 

exemption in Order No. 827 203 after 

finding that technological advancements 

made it so the cost of reactive power no 

longer presented an obstacle to the 

development of wind generation, it 

‘‘notably did not find that there were no 

such costs or even de minimis costs 

associated with the provision of reactive 

power by wind resources.’’ 204 Instead, 

Generation Developers argue that the 

Commission removed this exemption 

based on its finding that imposing an 

obligation on non-synchronous 

generating facilities to provide reactive 

power within the standard power factor 

range was necessary to support 

transmission service and reliability.205

Generation Developers add that, even if 

costs have declined over the years, the 

Commission has not demonstrated that 

it would be just and reasonable to 

nullify the rate schedules of facilities 

that came online years before the 

technological advancements referenced 

in Order No. 827 and had to make 

incremental investments to its facility to 

produce reactive power within the 

standard power factor range.206

75. Generation Developers argue that 

the 2014 Staff Report is the most recent 

and comprehensive evidence on the 

costs that non-synchronous generating 

facilities incur in providing reactive 

power.207 Generation Developers assert 

that the NOPR does not provide any 

evidence to support that the costs of 

providing reactive power have changed 

since the Commission’s observations in 

the 2014 Staff Report, but instead relies 

on a rehearing order in a proceeding 

concerning the MISO transmission 

owners’ proposal to eliminate reactive 

power compensation within the 

standard power factor range for the 

proposition that non-synchronous 

generating facilities have no or de 

minimis costs.208 Generation Developers 

assert that the Commission’s reliance on 

a statement from the MISO Rehearing 

Order, and the purported failure of 

parties in that proceeding to 

demonstrate costs of non-synchronous 

facilities, does not satisfy the 

Commission’s burden in this case.209

Generation Developers add that the 

Commission’s reliance on cases that predate the emergence of non-synchronous 

generating facilities for the proposition 

that all generating facilities have no or 

de minimis costs is misplaced.210 For 

example, Generation Developers 

contend that the Commission erred in 

citing Duke Energy Corporation’s 

comments to the NOI in support of its 

finding that the inverter is the most 

critical equipment for the production of 

reactive power from non-synchronous 

resources.211

76. PSEG similarly notes that the 

Commission has long used the AEP 

Methodology to allocate costs associated 


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212PSEG Initial Comments at 9. 

213 Id., Prepared Testimony of Dr. Paul A. Dumais 

at 11, 1:11. 

214 Indicated Trade Association Initial Comments 

at 7–8. 

215 Id. at 8 (citing BPA, 120 FERC ¶ 61,211 at P 

21). 

216 Id. (citing BPA Rehearing Order, 125 FERC 

¶ 61,273 at n.7). 

217 Id. (quoting APS, 94 FERC at 61,080; citing 

NOPR, 186 FERC ¶ 61,203 at P 29 n.70). 

218Elevate Initial Comments at 9–12; Elevate 

Reply Comments at 7–9; Glenvale Initial Comments 

at 9–10. 

219Elevate Initial Comments at 9–12; Elevate 

Reply Comments at 7–9. 

220Elevate Reply Comments at 8. 

221 Id. 

222Elevate Initial Comments at 12. 

223 Glenvale Initial Comments at 9–10. 

224 Id. at 9. 

225 Id. 

226 Id. at 9–10 & n.29 (citing Ramanathan 

Thiagarajan, Adarsh Nagarajan, Peter Hacke, and 

Ingrid Repins, Effect of Reactive Power on 

Photovoltaic Inverter Reliability and Lifetimes 

(2019), https://www.nrel.gov/docs/fy19osti/ 

73648.pdf.) (‘‘One characterization in recent 

research is that providing reactive power within the 

standard power factor range reduces service life by 

one year, and that providing reactive power outside 

of the standard range reduces service life by a 

second year.’’)). 

227 Id. at 10. 

228NEI Initial Comments at 5. 

229 Id. at 14–16. 

230Reactive Service Providers Initial Comments at 

37–40. 

231 Id. at 31–34. 

232 Id. at 37–41. 

233Eagle Creek Initial Comments at 3–4. Eagle 

Creek argues that, for each of its tariff cases, it 

submitted evidence documentation of the fixed and 

sunk costs that it invested to increase its reactive 

power generation. Id. 

234ACORE Initial Comments at 2; Indicated 

Reactive Power Suppliers Initial Comments at 9; 

Middle River Power Initial Comments at 2–3 

(noting that Middle River Power owns 19 fossilfired generating facilities that recover 

approximately $4.5 million in annual reactive 

power revenues through their reactive service tariffs 

Continued 

with the provision of reactive power 

within the standard power factor 

range.212 PSEG witness Dr. Dumais 

observes that the AEP Methodology 

identifies four categories of equipment 

costs that are involved in the production 

of reactive power from synchronous 

generating facilities.213

77. Indicated Trade Associations 

argue that the cases cited to in the 

NOPR to support the finding that there 

are no or de minimis costs associated 

with producing reactive power do not 

support the Commission’s assertion.214

For example, Indicated Trade 

Associations assert that in BPA, the 

Commission summarily stated without 

evidence that ‘‘the incremental cost of 

reactive power service within the 

deadband is minimal.’’ 215 Indicated 

Trade Associations assert that, on 

rehearing, however, when a party 

argued that ‘‘ ‘only the short-run 

marginal cost of producing the next 

increment of reactive power ‘can 

logically be described as minimal’ 

because it excludes capability costs,’ 

. . . the Commission sidestepped this 

issue, stating that ‘the issue of whether 

or not the cost is minimal is not relevant 

to whether the independent power 

producers are entitled to 

compensation.’ ’’ 216 Indicated Trade 

Associations argue that in APS, another 

order cited in the NOPR, ‘‘the 

Commission simply noted that 

intervenors ‘have not demonstrated that 

[the proposed reactive power] 

requirement will limit the real power 

output of a generating unit and therefore 

will not result in any lost opportunity 

costs.’ ’’ 217

78. Elevate and Glenvale further argue 

that the Commission’s assumption that 

all resource classes, including energy 

storage resources, incur no or minimal 

costs is unsupported by evidence.218

Elevate asserts that recurring capital 

investments are required to address 

battery degradation caused by the 

provision of reactive power.219

Specifically, Elevate argues that while 

the level of degradation increases as the 

reactive power to real power ratio 

moves further from unity, even the 

provision of reactive power within the 

standard power factor range contributes 

to the degradation of the storage 

resource’s capability.220 Elevate states 

that energy storage resources must make 

significant and recurring capital 

investments to address this degradation, 

which, in Elevate’s experience, costs 

approximately one percent of the 

resource’s original capital investment 

annually.221 Elevate asserts that the 

record is devoid of any evidence that 

energy storage resources incur no or de 

minimis costs to provide reactive 

power.222 Glenvale argues that there are 

marginal, operational, and replacement 

costs associated with providing reactive 

power within the power factor range for 

solar generating facilities.223

Specifically, Glenvale asserts that, at the 

capital investment stage, there are 

different inverter options that allow 

generating facilities to provide reactive 

service outside of generating hours (e.g., 

allowing solar generating facilities to 

provide reactive power at night) and 

that this incurs additional costs which 

would not be required if the generating 

facility were not set up to provide 

reactive power at night.224 Glenvale also 

asserts that inverters use electricity to 

provide reactive power, explaining that 

when a generating facility is 

synchronized, this presents as reduced 

generation, and when a generating 

facility is not synchronized, the 

generator must either use an alternate 

power source or it presents as negative 

generation (both of which Elevate states 

result in additional costs).225 Glenvale 

also states that the provision of reactive 

power can result in a reduced inverter 

service life.226 Glenvale notes that it is 

difficult to allocate these costs among 

each of the three service conditions— 

within the standard power factor range 

while synchronized, within the 

standard power factor range at night, 

and outside the standard power factor 

range at all times—but Glenvale asserts 

that at least some of the costs are 

attributable to providing reactive power 

within the standard power factor 

range.227 NEI asserts that there are real 

costs for nuclear generating facilities to 

provide and maintain reactive power 

capability, including: properly sized 

generators, maintenance associated with 

normal operations to preserve reactive 

power capability, and additional repairs 

that may be needed to address agerelated degradation to equipment that 

might otherwise impair reactive power 

capability.228

79. Relatedly, NEI explains that 

nuclear generators are most likely to be 

called upon to provide reactive power 

services and thus are the generators 

most likely to face accelerated 

degradation and damage to reactive 

power equipment.229

80. Reactive Service Providers argue 

that there is no evidence to support the 

claim that providing reactive power 

within the standard power factor range 

requires no incremental investment, and 

that even if the investment needed were 

de minimis, that would not be a reason 

to not provide compensation.230

Reactive Service Providers further 

contend that there is no evidence that 

the costs of providing reactive service 

have increased since the advent of RTOs 

and IPPs 231 or that generating facilities 

are recovering their costs in regions 

where transmission providers do not 

provide compensation.232

81. Eagle Creek criticizes the 

Commission’s determination that there 

are no or de minimis costs associated 

with the provision of reactive power in 

the standard power factor range as 

flawed based on its own tariff cases 

under the AEP Methodology and argues 

that eliminating compensation for 

reactive power would be arbitrary and 

capricious.233 ACORE, Indicated 

Reactive Power Suppliers, and Middle 

River Power similarly argue that their 

facilities have demonstrated just and 

reasonable compensation covering 

actual reactive power costs during 

settlement negotiations.234


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on file with Commission, which it argues were 

‘‘demonstrated in rigorous proceedings before the 

Commission’’ to be just and reasonable 

compensation covering actual costs). 

235 Indicated Trade Associations Initial 

Comments at 9; see also id. (citing Va. Elec. & 

Power Co., 114 FERC ¶ 61,318, at P 3 (2006)) (‘‘[T]he 

Commission expressly instructed generators to use 

the AEP Methodology ‘to compute the portion of 

plant investment attributable to reactive power 

production . . . Because these production plants 

produce real and reactive power, AEP developed an 

allocation factor to segregate the reactive 

production function from the real power production 

function. The allocation factor is used to determine 

the amount of investment allocable to reactive 

power.’ ’’) (emphasis added by Indicated Trade 

Associations)). 

236NEI Initial Comments at 10 (citing NOPR, 186 

FERC ¶ 61,203 at P 30) 

237 Id. at 10–11; Generation Developers Initial 

Comments at 7–9. 

238 Generation Developers Initial Comments at 8– 

9 (citing Dynegy Midwest Generation, Inc., 125 

FERC ¶ 61,280 at P 11; Bluegrass Generation Co., 

L.L.C., 118 FERC ¶ 61,214, order on reh’g, 121 FERC 

¶ 61,018, at P 12 (2007)). 

239 Id. (citing Bluegrass Generation Co., 121 FERC 

¶ 61,018 at P 12 (‘‘This policy is not a matter of 

administrative convenience . . . but the result of 

the Commission’s deliberate determination that the 

AEP methodology is a just and reasonable manner 

of calculating a reactive power revenue 

requirement’’). 

240NHA Initial Comments at 4–5 (noting that 

‘‘[t]here is no basis for this assumption, especially 

if the Commission believes the AEP Methodology 

is incapable of isolating real and reactive cost.’’). 

241Clean Energy Associations Initial Comments at 

7. 

242Middle River Power Initial Comments at 3. 

243Clean Energy Associations Initial Comments at 

6–7. 

244 Id. 

245ACORE Initial Comments at 2. 

246Elevate Initial Comments at 9–10; Indicated 

Trade Associations Initial Comments at 9. 

247 Indicated Trade Associations Initial 

Comments at 9 (citing Order No. 888, FERC Stats. 

& Regs. ¶ 31,036 at 31,720–21). 

248Middle River Power Initial Comments at 2–3. 

249Reactive Service Providers Initial Comments at 

7 (citing NOPR, 186 FERC ¶ 61,203 at P 5). 

250 Id. at 9. 

251 Id. at 8. 

252 Id. at 8–9 (citing Affidavit of Dennis W. 

Bethel). 

253 Id. at 9 (citing Order No. 888, FERC Stats. & 

Regs. ¶ 31,036 at 31,349 (noting that the 

Commission adopted the following definition of 

ancillary services: ‘‘Those services that are 

necessary to support the transmission of capacity 

and energy from resources to load while 

maintaining reliable operation of the Transmission 

Provider’s Transmission System in accordance with 

Good Utility Practice’’ and that the Commission 

determined that ‘‘A control area is part of an 

interconnected power system with a common 

generation control system. It may contain one or 

several utilities. The operator of the control area is 

responsible for balancing generation and load and 

for maintaining reliable system operation.’’)). 

254 Id. 

82. Indicated Trade Associations 

assert that the Commission fails to 

reconcile the NOPR’s insistence that 

there are no segregable costs associated 

with the provision of reactive power 

with its longstanding precedent of the 

AEP Methodology, where the 

Commission approved isolating costs of 

providing reactive power.235 NEI asserts 

that, rather than point to actual data that 

demonstrates generating facility costs 

for providing reactive power, the NOPR 

relies on the misplaced theory that 

‘‘because both synchronous and nonsynchronous resources provide real and 

reactive power as joint products, with 

joint costs, . . . any allocation of joint 

fixed costs between real and reactive 

power could be viewed as inherently 

arbitrary.’’ 236 NEI and Generation 

Developers argue that the AEP 

Methodology compensates generators 

based on their actual costs and reactive 

capabilities, providing them with a just 

and reasonable opportunity to recover 

their investments in reactive service 

capability, and asserts that the 

Commission has repeatedly confirmed 

this cost allocation methodology and its 

underlying factual predicates in 

numerous proceedings.237 Generation 

Developers suggest that the Commission 

has allocated real and reactive power 

costs using the AEP Methodology for 

over two decades 238 and has rejected 

arguments that the AEP Methodology 

results in an improper allocation of 

costs or is used merely as a matter of 

administrative convenience.239 The 

NHA asserts that the Commission 

correctly identifies real power and 

reactive power as jointly produced 

commodities, but it incorrectly 

attributes the cost of all generation 

equipment to be predominantly for the 

production of real power.240

83. Clean Energy Associations assert 

that reactive power is not always 

coupled with real power as they believe 

the Commission states in the NOPR.241

Middle River Power argues that the 

Commission’s statement that generating 

facilities are being asked to provide 

reactive power in order to offset the 

impact of the power they inject into the 

system is incorrect.242 Similarly, Middle 

River Power asserts that the 

Commission has previously found that 

generators are being asked to supply 

reactive power to support load. Clean 

Energy Associations argues that the 

Commission conflates the cost of 

equipment with the cost of providing an 

essential transmission service and that 

providing reactive power—even within 

the standard power factor range—comes 

at the expense of providing real 

power.243 Clean Energy Associations 

note that a possible solution to this 

problem could be that the Commission 

distinguish ‘‘reactive power capability’’ 

from the ‘‘reactive power service.’’ 244

84. ACORE asserts that a requirement 

to provide a service does not negate the 

fact that costs are incurred to provide 

that service.245 Similarly, Elevate and 

Indicated Trade Associations argue that, 

even if it were true that resources do not 

incur distinct costs associated with 

reactive power, the Commission fails to 

point to precedent to support its 

conclusion that the lack of distinct costs 

is an appropriate basis on which to deny 

resources the ability to recover those 

costs.246 The Indicated Trade 

Associations assert that the NOPR’s 

assumption that there are no or minimal 

costs associated with the provision of 

reactive power directly contradicts 

Order No. 888, which Indicated Trade 

Associations argue found that reactive 

service from generating facilities must 

be priced at cost, thereby 

acknowledging that there are 

distinguishable costs associated with 

the provision of reactive power.247

Middle River Power argues that the 

Commission has historically required 

compensation for reactive power as a 

separate ancillary service.248

85. Reactive Service Providers assert 

that the Commission has not supported 

its claim that generating facilities (and 

specifically IPP) already have an 

obligation to provide reactive service 

within the standard power factor 

range.249 Reactive Service Providers 

argue that the NOPR’s finding is 

contrary to decades of Commission 

precedent,250 and the Commission ‘‘lost 

its way as it proceeded to Order No. 

2003 and beyond, caught up in a 

myopic view that unbundling and the 

emergence of the IPP industry somehow 

transferred the ‘obligation’ to provide 

reactive service within the standard 

range from the Transmission Provider to 

the IPP generator.’’ 251 Reactive Service 

Providers assert that transmission 

providers alone have the obligation to 

maintain a reliable and stable 

transmission system, and generating 

facilities are purely a tool that 

transmission providers use to fulfill this 

obligation.252 Reactive Service 

Providers assert that in Order No. 888, 

the Commission determined that 

various ancillary services support the 

transmission system so that load can be 

served, but the Commission notably did 

not find that generating facilities have 

this obligation.253 Instead, Reactive 

Service Providers argue that the 

Commission merely recognized that 

generating facilities were a critical tool 

that transmission providers can use to 

maintain the safe and reliable operation 

of the transmission system.254 Reactive 

Service Providers assert that, for 

Reactive Supply and Voltage Control 

from Generation Sources (which 


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255 Id. at 10 (citing Order No. 888, FERC Stats. & 

Regs. ¶ 31,036 at 31,355). 

256 Id. 

257 Id. at 11. 

258 Id. at 11–12. 

259 Id. at 12. 

260 Id. at 12–19 (citing Order No. 661, 111 FERC 

¶ 61,353 at PP 50–51 (‘‘this Final Rule requires the 

wind plant to maintain the required power factor 

range only if the Transmission Provider shows 

through the System impact Study, that such 

capability is required of that plant to ensure safety 

or reliability. . . . ‘‘[B]ecause the Transmission 

Provider is responsible for the safe and reliable 

operation of its transmission system (pursuant to 

NERC and regional reliability council standards), it 

is in the best position to establish if reactive power 

is needed in individual circumstances.’’); Order No. 

827, 155 FERC ¶ 61,277 at P 35 (‘‘balancing the 

costs to newly-interconnecting non-synchronous 

generators of providing reactive power with the 

benefits to the transmission system of having 

another source of reactive power’’) (emphasis added 

by Reactive Service Providers)); id. at 18 (‘‘[I]n 

Order No. 901, the [Commission] continued the 

clear distinction between a Transmission Provider 

that has the obligation to plan and operate the 

Transmission System and generation that is a tool 

that Transmission Providers must account for and 

uses to fulfill its obligation to plan and operate the 

Transmission System.’’) (citing Reliability 

Standards to Address Inverter-Based Res., Order 

No. 901, 88 FR 74250 (Oct. 30, 2023) 185 FERC 

¶ 61,042, at P 174 (2023)). 

261 Id. at 19. 

262 Id. at 19–20 (quoting at Order No. 2003, 104 

FERC ¶ 61,103 at P 56) (emphasis added by Reactive 

Service Providers). Reactive Service Providers 

assert that the Commission adopted the same 

definition of ‘‘good utility practice’’ in Order No. 

2003 as it did in Order No. 888. Id. at 19. 

263 Id. at 20. 

264 Indicated Trade Associations Initial 

Comments at 23 (citing Banton v. Belt Line Ry. 

Corp., 268 U.S. 413, 420 (1925) (‘‘[t]he commission 

under the guise of regulation may not compel the 

use and operation of the company’s property for 

public convenience without just compensation.’’); 

Gulf Power Co. v. U.S., 187 F.3d 1324, 1331 (11th 

Cir. 1999) (‘‘[c]haracterizing the mandatory access 

provision as a regulatory condition . . . cannot 

change the fact that it effects a taking by requiring 

a utility to submit to a permanent, physical 

occupation of its property’’)). 

265 Generation Developers Initial Comments at 27 

(citing CAISO, 2022 Annual Report on Market 

Issues & Performance 15 (July 11, 2023), http://

www.caiso.com/market/Pages/MarketMonitoring/ 

AnnualQuarterlyReports/Default.aspx; PJM, Energy 

Transition in PJM: Resource Retirements, 

Replacements and Risks 10 (Feb. 24, 2023), https:// 

insidelines.pjm.com/pjm-details-resourceretirements-replacements-and-risks.). 

266 Indicated Trade Associations Reply Comments 

at 9. 

267PJM IMM Initial Comments at 6–9; Joint 

Consumer Advocates Initial Comments at 6–7; 

MISO Transmission Owners Reply Comments at 4; 

TAPS Initial Comments at 6; Ohio FEA Initial 

Comments at 5; Joint Customers Initial Comments 

at 14–16; PGE Initial Comments at 4 (citing MISO, 

182 FERC ¶ 61,033 at P 53 (noting that in the 

acceptance of the MISO Transmission Owners 

application to end compensation within the 

standard power application, the Commission 

reiterated its 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.’’)). 

ultimately became Schedule 2), the 

Commission noted that: 

NERC states that reactive supply is 

provided from both generation resources and 

transmission facilities (e.g., capacitors), and 

lists its provision as two services, 

distinguished by the facilities that supply 

them. NERC further distinguishes reactive 

supply service based on the source of the 

need for the service: (1) reactive supply 

needed to support the voltage of the 

transmission system; and (2) reactive supply 

needed to correct for the reactive portion of 

the customer’s load at the delivery point.255

Reactive Service Providers assert that 

NERC did not identify the impact of 

generating facilities to the transmission 

system as a reason or need for reactive 

supply, but instead only identified the 

transmission system and load as 

needing the reactive service, noting that 

generating facilities would serve those 

needs at the point of interconnection.256

Reactive Service Providers assert that, 

while both before and after Order No. 

888, transmission providers holistically 

relied on generation- and transmissionbased reactive assets to fulfill their 

obligations to maintain the voltage of 

the transmission system, generating 

facilities never had an independent 

obligation to provide reactive service, as 

the Commission asserts in the NOPR.257

86. Reactive Service Providers assert 

that when the Commission issued Order 

No. 2003, it summarily stated that, as a 

condition to obtain interconnection 

service, the generating facility must 

provide reactive service within the 

standard power factor range.258 Reactive 

Service Providers argue that the 

Commission did not amass any 

evidence in the Order No. 2003 

proceeding to explain why generating 

facilities have an obligation to provide 

reactive service within the standard 

power factor range and posit that the 

Commission may have come to this 

conclusion in Order No. 2003 and the 

NOPR ‘‘because the Transmission 

Provider has always relied on generators 

as one of its tools to enable the 

Transmission Provider to fulfill its 

obligation to maintain the Transmission 

System in a safe and reliable 

manner.’’ 259 Reactive Service Providers 

assert that none of the transmission 

system operators, NERC, and the 

Commission, in nearly all precedent, 

have ever concluded that generation has 

an ‘‘obligation’’ to provide reactive 

service within the standard range; the 

Commission’s statement in Order No. 

2003 is an outlier.260

87. Similarly, Reactive Service 

Providers assert that ‘‘good utility 

practice’’ does not entail an obligation 

for generating facilities to provide 

reactive power for free, and the 

Commission has not explained why it 

believes such obligation exists.261

Reactive Service Providers argue that 

the current compensation scheme for 

reactive power is consistent with the 

Commission’s definition of good utility 

practice because it includes practices 

that ‘‘could have been expected to 

accomplish the desired result at a 

reasonable cost consistent with good 

business practices, reliability, safety and 

expedition.’’ 262 Reactive Service 

Providers assert that good utility 

practice does not address what the 

electric industry (i.e., the transmission 

provider) can achieve for free, but rather 

a cost that the transmission provider 

must pay as a matter of ‘‘good business 

practices’’ in order to fulfill its 

obligation.263 Indicated Trade 

Associations argue that the Commission 

cannot deprive public utilities from just 

and reasonable compensation for 

reactive power within the standard 

power factor range by simply classifying 

it as a condition of interconnection, 

particularly when the Commission 

established that condition.264

88. Generation Developers assert that 

the NOPR errs in concluding that 

separate compensation for reactive 

power may result in a windfall to 

generators. Generation Developers note 

that many generators across markets are 

in fact increasingly unable to recover 

their costs.265 Indicated Trade 

Associations similarly refute the 

NOPR’s preliminary conclusion that 

separate compensation for reactive 

power within the standard power factor 

range may result in market distortions, 

contending that all rates are approved 

by the Commission and that any 

distortions are a result of PJM’s capacity 

market rules.266

2. Commission Determination 

89. Based on our review of the record, 

we conclude that compensation for the 

provision of reactive power within the 

standard power factor range is unjust 

and unreasonable because: (1) the 

provision of such reactive power 

requires either no or at most a de 

minimis increase in variable costs 

beyond the cost of providing real power; 

(2) such compensation may result in 

undue compensation and other market 

distortions; and (3) the provision of 

reactive power within the standard 

power factor range is an obligation of 

the generating facility as an 

interconnection customer and 

consistent good utility practice.267

90. As explained in the NOPR, 

because real and reactive power are 

provided as joint products with joint 

costs produced from the same 


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93430 Federal Register / Vol. 89, No. 228 / Tuesday, November 26, 2024 / Rules and Regulations 

268NOPR, 186 FERC ¶ 61,203 at P 30; (citing PJM 

IMM Initial Comments to the NOI 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; 

Permian Basin, 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., 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.’’)). 

269NOPR, 186 FERC ¶ 61,203 at P 31 (citing SPP 

Initial Comments to NOI at 2; PJM IMM Initial 

Comments to NOI at 4.). 

270Ameren Initial Comments at 3; MISO 

Transmission Owner Reply Comments at 9. See also 

NOPR, 186 FERC ¶ 61,203 at P 29 (citing Edison 

Electric Institute Initial Comments to the NOI at 6). 

271 Duke Energy Corporation Initial Comments to 

the NOI at 4. 

272See, e.g., MISO Transmission Owners Initial 

Comments at 7 (‘‘[E]ven newer wind turbines use 

inverters that allow for the generator to produce and 

control reactive power without costly additional 

equipment.); 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)). 

273PJM IMM Initial Comments to the NOI at 4; 

see also MISO Transmission Owners Reply 

Comments at 7–8. 

274MISO Transmission Owners Initial Comments 

at 6 (‘‘The MISO Transmission Owners’ experience 

supports the Commission’s preliminary finding that 

providing reactive power within the standard 

power factor range requires little or no cost to 

generators. Generators incur little or no costs 

beyond what is already needed to produce real 

power because the same equipment used to produce 

real power includes reactive power functions.’’ 

(citations omitted)); PJM IMM Reply Comments at 

3 (‘‘Neither [Indicated Trade Associations] nor any 

other opposing commenter, nor any of the 

precedent relied upon by opposing commenters, 

identify any additional costs or more than de 

minimis costs incurred by generators in order to 

provide reactive capability.’’); MISO Transmission 

Owners Reply Comments at 9–10 & n.29. See also, 

BPA, 120 FERC ¶ 61,211 at P 21 (finding that the 

incremental cost of reactive power service within 

the deadband is minimal); METC Rehearing Order, 

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.’’); 

APS, 94 FERC at 61,080 (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’’). 

275NOPR, 186 FERC ¶ 61,203 at PP 8, 28. 

276The only incremental costs identified in the 

NOPR were heating losses. NOPR, 186 FERC 

¶ 61,203 at P 28 & n.74. 

277Eagle Creek Initial Comments at 3–4; 

Generation Developers Initial Comments at 13; 

Glenvale Initial Comments at 9–10 Indicated Trade 

Associations Initial Comments at 7–12; Middle 

River Power Initial Comments at 2–3. 

278See Clean Energy Associations Initial 

Comments at 6–7 (‘‘However, during certain 

generating facility and grid operating conditions, 

when the generator provides an actual service (i.e., 

injects reactive power to support voltage) it could 

come at the cost of production of real power. During 

that time, reactive power is prioritized and real 

power generated by the plant may be limited. In 

such a case the generation facility is prioritizing the 

utilization of their asset to assist or enhance grid 

stability at the cost of their revenue, which is 

primarily obtained from real power sales. The 

Commission should consider this opportunity cost 

in the context of interconnection customers that 

participate in regional wholesale markets.’’) 

279See, e.g., Indicated Reactive Power Suppliers 

Initial Comments at 10 (‘‘Stripping generators of the 

ability to be compensated for reactive power 

supply, including lost opportunity costs, within the 

[standard power factor range] is not just and 

reasonable and not supported by the record.’’); 

Indicated Trade Associations Initial Comments at 

11 (‘‘The NOPR also completely ignores the fact that 

the provision of reactive power within the 

deadband represents a lost opportunity to produce 

real power, thereby resulting in lost opportunity 

costs.’’). 

280See, e.g., NOPR, 186 FERC ¶ 61,203 at P 32 

(‘‘[I]f 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.’’) (citing CAISO 

Initial Comments to NOI at 4). 

equipment, any allocation of joint fixed 

costs between real and reactive power 

could be viewed as inherently 

arbitrary.268 And while 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, we continue to find, based on the 

record and past precedent, that variable 

costs of generating reactive power 

within the standard power factor range 

are at most de minimis.269 With respect 

to fixed costs, for synchronous 

generating facilities, ‘‘the same 

equipment is used to provide real and 

reactive power.’’ 270 Non-synchronous 

generating facilities use a different 

physical process to produce reactive 

power, but ‘‘the most critical element in 

VAR production, the inverter,’’ 271 is 

also necessary for non-synchronous 

generating facilities to produce real 

power that can be reliably injected into 

AC systems.272 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’’ 273 beyond the investments in 

equipment already necessary to generate 

and supply real power to the 

transmission system.274

91. While most commenters agree or 

do not dispute that all equipment used 

to produce reactive power, for both 

synchronous and non-synchronous 

generating facilities, is also necessary in 

order to produce and deliver to the 

transmission system real power, several 

commenters dispute the NOPR’s 

findings that both synchronous and 

non-synchronous facilities incur no or 

at most a de minimis increase in costs 

beyond the cost of providing real 

power.275 However, these commenters 

do not identify any specific costs 

beyond those incurred to ensure that 

real power can be reliably injected into 

the transmission system.276 For 

example, Indicated Trade Associations, 

Generation Developers, and Glenvale 

emphasize that there are costs of 

equipment and production associated 

with reactive power, but they provide 

only vague references to those specific 

equipment costs and identify no distinct 

equipment (apart from equipment 

already needed for real power 

production).277 Many of the commenters 

opposing the rule also conflate the cost 

of providing reactive power capability 

within and outside the standard power 

factor range.278 For example, 

commenters suggest that there are 

opportunity costs to provide reactive 

power capability, even within the 

standard power factor range, because 

doing so requires a generating facility to 

forgo real power production.279 As 

explained in the NOPR and in other 

Commission precedent, however, 

reactive power opportunity costs are an 

issue only when providing reactive 

power outside the standard power factor 

range. This is because, unlike operating 

within the standard power factor range, 

generating facilities operating outside 

the standard power factor range forgo 

generating more real power output and 

thus, forgo sales of real power.280

Importantly, commenters do not provide 

any evidence to support their assertion 

that operating within the standard 

power factor range will limit the real 

power output of their generating 

facilities. To the contrary, rather than 

limiting real power output, real power 

cannot be supplied from a generating 

facility unless that facility is producing 

reactive power within the standard 

power factor range to generate and 

safely inject real power into the 


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281See, e.g., MISO Rehearing Order, 184 FERC 

¶ 61,022 at P 29 (‘‘We continue to conclude, and the 

record establishes, that Reactive Service requires 

little or no incremental investment.’’); METC 

Rehearing Order, 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.’’); APS, 94 FERC at 61,080 (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’’); BPA, 120 FERC 

¶ 61,211 at P 21 (‘‘[T]he incremental cost of reactive 

power service within the [standard power factor 

range] is minimal.’’). See also S. Co. Servs., Inc., 80 

FERC at 62,091 (noting also that the primary 

function of a generating plants 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’’). 

282MISO Transmission Owners Initial Comments 

at 7 (citing MISO Rehearing Order, 184 FERC 

¶ 61,022 at P 30 n.98 (‘‘[O]lder wind generators 

could not produce and control reactive power 

without the use of costly equipment [ ] because they 

did not use inverters like other non-synchronous 

generators but modern turbines now use inverters 

and newer wind generators now can.’’)). 

283METC Rehearing Order, 97 FERC at 61,852– 

53. 

284 Generation Developers Initial Comments at 15. 

285 Id. at 16 (citing BPA, 120 FERC ¶ 61,211; 

METC Rehearing Order, 97 FERC at 61,852–53; 

APS, 94 FERC at 61,080). 

286 Indicated Trade Associations Initial 

Comments at 8 (citing BPA, 120 FERC ¶ 61,211 at 

P 21; BPA Rehearing Order, 125 FERC ¶ 61,273 at 

P 7 n.7; APS, 94 FERC at 61,080). 

287See, e.g., MISO, 182 FERC ¶ 61,033; PNM, 178 

FERC ¶ 61,088 at PP 29–31. 

288See, e.g., 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 nonsynchronous resources); PJM Interconnection, 

L.L.C., 151 FERC ¶ 61,097 at PP 7, 28 (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); 2005 

Staff Report at 96 (‘‘The marginal cost of providing 

reactive power from within a generator’s capability 

curve (D-curve) is near zero.’’). 

289We also note that Order No. 827, which was 

issued in 2016, after the 2014 Commission Staff 

Report, removed the exemption for wind generating 

facilities to provide reactive power because of 

‘‘declining costs’’ resulting from ‘‘improvements in 

technology.’’ Order No. 827, 155 FERC ¶ 61,277 at 

P 24. In Order No. 827, the Commission noted that 

other types of non-synchronous generating facilities 

were not exempt from the requirement to provide 

reactive power and that Order No. 827’s findings 

applied to all newly interconnecting nonsynchronous generating facilities. Id. P 22. 

290 Glenvale Initial Comments at 9–10. 

291See, e.g., Eagle Creek Initial Comments at 3 

(‘‘Where Eagle Creek Reactive Generators made 

specific capital investments that enhanced reactive 

service—for example, by installing upgraded 

exciters with demonstrable power factor 

improvements—their related reactive compensation 

case was necessarily strengthened.’’). 

292We note that the additional capabilities are not 

required as a condition of interconnection. 

Furthermore, all generating facilities are allowed to 

seek compensation when directed to provide 

reactive power beyond the standard power factor 

range. This final determination does not change the 

ability of generating facilities to seek compensation 

associated with providing reactive power outside 

the standard power factor range. 

293See, e.g., ACORE Initial Comments at 2 (‘‘A 

requirement to provide a service does not negate the 

fact that costs are incurred, as demonstrated by the 

multiple settlements reached for payment of this 

Continued 

transmission system and comply with 

reliability requirements. 

92. Like in MISO, the commenters 

here fail to identify any incremental 

fixed costs associated with the provision 

of reactive power within the standard 

power factor range and identify only de 

minimis variable costs.281 In MISO, the 

MISO transmission owners proposed to 

eliminate all charges under Schedule 2 

for the provision of reactive power 

within the standard power factor range. 

Like here, protesters opposing MISO’s 

proposal challenged the conclusion that 

reactive power within the standard 

power factor range required little or no 

incremental investment. The 

Commission rejected their protests, 

finding that they had failed to identify 

any record evidence demonstrating that 

there are more than minimal capital 

expenditures on equipment or 

additional operations and maintenance 

costs attributable to providing such 

reactive power. Like here, protesters 

alluded to alleged opportunity costs and 

operation and maintenance costs but 

failed to point to any evidence of such 

costs. 

93. Although Generation Developers 

claim that the report is the most recent 

and comprehensive evidence on the 

costs of non-synchronous generating 

facilities to provide reactive power, 

Generation Developers’ arguments 

regarding the evidence in the 2014 Staff 

Report ignore that the Commission 

found in the MISO Rehearing Order that 

even newer wind turbines use inverters 

that allow generating facilities to 

produce and control reactive power 

without costly additional equipment,282

and has found elsewhere 283 that the 

provision of reactive power requires no 

or at most de minimis variable costs 

beyond the cost of producing real 

power. 

94. Generation Developers also assert 

that the Commission’s reliance on a 

statement from the MISO Rehearing 

Order, and the purported failure of 

parties in that proceeding to 

demonstrate significant incremental 

costs of non-synchronous facilities, does 

not satisfy the Commission’s burden in 

this case.284 Generation Developers add 

that the Commission’s reliance on cases 

that pre-date the emergence of nonsynchronous generating facilities for the 

proposition that all generating facilities 

have no or de minimis costs is 

misplaced.285 Indicated Trade 

Associations similarly argue that 

Commission precedent cited in the 

NOPR (i.e., BPA and APS) does not 

support the conclusion that the 

incremental costs of the provision of 

reactive power within the standard 

power factor range are at most de 

minimis.286

95. We disagree with Indicated Trade 

Associations and Generation 

Developers. Commenters provide no 

support for the contention that decades 

of Commission precedent are irrelevant 

for purposes of supporting our findings 

here, including precedent from after the 

emergence of non-synchronous 

generating facilities.287 As demonstrated 

by the decades of Commission 

precedent cited in the NOPR and here, 

many of the findings in this final 

determination are not new. The 

Commission has reached similar 

conclusions based on similar evidence 

(or lack thereof) in other proceedings, 

including with respect to the provision 

of reactive power within the standard 

power factor range by non-synchronous 

generating facilities.288 This precedent 

coupled with the evidence in this 

record, supports this final 

determination, including with respect to 

non-synchronous generating 

facilities.289

96. Glenvale contends that certain 

types of non-synchronous generating 

facilities incur additional costs to 

provide reactive power when not 

providing real power, such as for solar 

generating facilities providing reactive 

power at night.290 However, as these 

capabilities relate to the provision of 

reactive power when not providing real 

power, such costs necessarily are for the 

provision of reactive power outside the 

standard power factor range and thus 

are not impacted by and are beyond the 

scope of this proceeding. 

97. Similarly, some commenters point 

to capital investments that expand a 

generating facility’s reactive power 

capability beyond the standard power 

factor range,291 but that capability, and 

thus that investment, does not address 

the relevant issue of whether 

transmission charges associated with 

the provision of reactive power within 

the standard range are just and 

reasonable.292

98. Eagle Creek and others argue that 

rates calculated using the AEP 

Methodology are themselves evidence of 

significant reactive-power-related 

capital investments.293 Putting aside 


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service.’’); Indicated Reactive Power Suppliers 

Initial Comments at 9 (‘‘[S]ubstantial cost support 

included with the proposed reactive service tariffs 

of each of the Indicated Reactive Power Suppliers 

. . .meticulously demonstrate the fixed and sunk 

costs allocable to reactive power production using 

the AEP [M]ethodology’’). 

294See, e.g., Joint Customers Reply Comments at 

6–7; ELCON Initial Comments at 5. 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. 

295PJM IMM Reply Comments at 3. See also PJM 

IMM Initial Comments at 3 (‘‘The AEP 

Method[ology] was based on three sentences in 

testimony filed in 1993 that provide no logical, 

engineering or economic support for allocating a 

part of generator capital investment to reactive. 

That testimony was about a subjective decision to 

reassign costs that were already fully accounted for 

and not about any asserted costs to provide reactive 

power that were not recovered elsewhere and not 

for any asserted additional costs of providing 

reactive power.’’); Joint Customers Reply Comments 

at 12 (‘‘The amount of total plant cost that is 

allocated to the reactive function based on a power 

factor for ratemaking purposes under the AEP 

[M]ethodology is not at all indicative of actual 

incremental costs for incremental levels of 

additional reactive capability.’’ (emphasis in 

original)). See also 2005 Staff Report at 69 (‘‘[T]he 

allocation factor used in the AEP Methodology does 

not directly relate to the incremental investment 

cost in providing reactive capability or supply’’). 

296 Fern Solar LLC, 183 FERC ¶ 63,004, at P 937 

(2023). 

297See, e.g., MISO Rehearing Order, 184 FERC 

¶ 61,022 at P 26 (‘‘[W]e continue to reject, as 

collateral attacks on that longstanding policy, 

arguments that stand-alone compensation for 

Reactive Service is generically required—for 

example, to ensure that generators can recover their 

costs for Reactive Service capability.’’); Entergy 

Servs. Inc., 114 FERC ¶ 61,303, at P 14 (2006) (‘‘In 

Order No. 2003, the Commission emphasized that 

an interconnecting generator 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. 

Generators interconnected to a transmission 

provider’s system need only be compensated where 

the transmission provider directs the generator to 

operate outside the dead band.’’ (internal citations 

omitted)). 

298PSEG Initial Comments at 13 & n.33 (citing 

Dynegy Midwest Generation, Inc. v. FERC, 633 F.3d 

1122, 1126 (D.C. Cir. 2011)). 

299MISO Rehearing Order, 184 FERC ¶ 61,022 at 

P 31 (‘‘Vistra challenges the conclusion that 

Reactive Service requires little or no incremental 

investment by claiming that the D.C. Circuit in 

Dynegy rejected that conclusion. We disagree with 

Vistra’s interpretation of Dynegy. Rather, in Dynegy, 

the court concluded that the Commission had not 

made any such finding in that case, instead 

providing only a ‘glancing remark’ to this effect, 

and that the record in that case did not support 

such a finding. Here, in addition to noting the 

Commission’s previous conclusions that Reactive 

Service capability requires little or no incremental 

investment, we have further explained immediately 

above the basis for this finding.’’). 

300See, e.g., Ameren Initial Comments at 3; MISO 

Transmission Owners Initial Comments at 6 

(‘‘Generators incur little or no costs beyond what is 

already needed to produce real power.’’); PJM IMM 

Initial Comments at 4 (‘‘There are few if any 

identifiable costs incurred by generators in order to 

provide reactive power. Separately compensating 

resources based on a judgment based allocation of 

capital costs was never and is not now appropriate 

in the PJM markets. Generating units are fully 

integrated power plants that produce both the real 

and reactive power required for grid operation 

. . . . [T]here is no reason to include complex rules 

that arbitrarily segregate a portion of a resource’s 

capital costs as related to reactive power.’’). 

301See PJM IMM Initial Comments at 12 (‘‘The 

market approach should be used, as it is 

overwhelmingly more efficient than the current rate 

case, cost of service approach. Supporters of the 

cost of service approach have never explained why 

a nonmarket approach is required in PJM or why 

it is preferable to a market approach.’’); id. at 11– 

12 (‘‘There is no evidence that units are built as a 

result of reactive revenue. There is no evidence that 

sources of revenue are not fungible and that a 

decrease in reactive revenues could be not replaced 

with other sources of revenue. There is no basis for 

adding new resources to the already very crowded 

interconnection queue solely based on out of 

market subsidies from reactive revenues.’’). 

302 MISO, 182 FERC ¶ 61,033 at PP 53–54 (citing 

Order No. 2003–A, 106 FERC ¶ 61,220 at P 416; 

that these commenters provide no 

support for their contentions, the AEP 

Methodology is a cost allocation 

methodology only; it is not designed to, 

and does not, establish ‘‘evidence of 

significant reactive-power-related 

capital investments.’’ To the contrary, 

were it possible to identify discrete, 

incremental capital investments made to 

provide reactive power within the 

standard power range, the AEP 

Methodology could be utilized to 

allocate such reactive power costs 

incurred by the generator; however, no 

such incremental capital costs exist 

here, and so the AEP Methodology is 

inapplicable. In addition, as noted in 

the NOPR, the AEP Methodology 

originated in an era of vertically 

integrated utilities that recovered both 

generation and transmission costs 

entirely through cost-based rates and 

classified those costs under USofA 

accounting requirements.294 The 

Commission accepted the AEP 

Methodology as a way to assign these 

costs using a cost-of-service allocation 

method for assigning joint costs between 

the generation and transmission 

functions. As the PJM IMM explains 

‘‘The AEP Method[ology] is not about 

identifying incremental costs incurred 

to provide reactive power . . . [but 

rather] allocates the costs of an 

integrated power plant between reactive 

power and real power.’’ 295 As noted in 

the Fern Initial Decision, ‘‘The standard 

techniques for addressing a facility that 

operates in both a monopoly market and 

a competitive market—cost allocation 

and revenue credit—have no connection 

to the AEP [M]ethod[ology],’’ and 

‘‘[a]uto-transporting a monopoly-era 

method into an organized-market 

context—which is exactly what this 

proceeding’s witnesses do, what dozens 

of settlements do and what this Initial 

Decision does—is not regulating based 

on physical facts.’’ 296

99. We also disagree with those 

commenters that suggest that the mere 

existence of joint products requires 

allocating costs to both real and reactive 

power production. These assertions 

disregard longstanding Commission 

precedent.297 PSEG, for example, relies 

on Dynegy Midwest Generation, Inc. v. 

FERC for the proposition that ‘‘the 

NOPR . . . conflicts with Commission 

and judicial precedents that have long 

recognized that there are specific fixed 

costs associated with the production of 

reactive power.’’ 298 But the Commission 

explicitly rejected this same argument 

when Dynegy made it in the MISO 

proceeding.299

100. Thus, based on the totality of the 

record, we agree with Ameren that, for 

both synchronous and non-synchronous 

generating facilities, ‘‘it is [ ] welldocumented that the same equipment 

used to produce real power includes 

reactive power functions,’’ and thus 

‘‘there is little, if any, incremental cost 

associated with providing reactive 

power’’ beyond the investments in 

equipment already necessary to generate 

and supply real power to the 

transmission system.300 As discussed 

below, we also find that the joint costs 

associated with the production of real 

and reactive power are costs that 

generating facilities must incur to 

provide the real power for which they 

are compensated.301

101. Reactive Service Providers argue 

that the Commission has not supported 

its claim that generating facilities 

already have an obligation to provide 

reactive service within the standard 

power factor range. Specifically, 

Reactive Service Providers assert that 

when the Commission issued Order No. 

2003, it summarily stated that a 

generating facility must provide reactive 

service within the standard power factor 

range as a condition to obtain 

interconnection service, but it did not 

amass any evidence to explain why 

generating facilities have this obligation. 

Reactive Service Providers claim that 

Order No. 2003 is an outlier among 

Commission precedent and that none of 

the transmission system operators, 

NERC, or the Commission, in nearly all 

precedent, has ever articulated such 

obligation. However, as discussed at 

length above, outlined in the NOPR, and 

reiterated in recent Commission 

decisions, the Commission has for 

decades stated 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.’’ 302 We find Reactive 


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SPP, 119 FERC ¶ 61,199 at P 28) (‘‘Accordingly, by 

designing their generating facilities to have the 

capability to provide reactive support, 

interconnecting generators are meeting the 

conditions of interconnection required of all 

generators and as a general matter are not entitled 

to compensation under the Commission’s precedent 

unless the transmission provider pays its own or 

affiliated generators for reactive power within the 

standard power factor range.’’); NOPR, 186 FERC 

¶ 61,203 at P 16. 

303See e.g., ISO N. England Inc., 138 FERC 

¶ 61,238, at P 17 (2012) (‘‘[A] collateral attack is 

‘[a]n attack on a judgment in a proceeding other 

than a direct appeal,’ and is ‘generally prohibited.’ ’’ 

(quoting N. England Conf. of Pub. Utils. Comm’rs 

v. Bangor Hydro-Elec. Co., 135 FERC ¶ 61,140, at P 

27 (2011))). 

304See, e.g., MISO, 182 FERC ¶ 61,033; MISO 

Rehearing Order, 184 FERC ¶ 61,022 at P 23 (citing 

METC Rehearing Order, 97 FERC at 61,852–53); see 

also MISO Transmission Owners Initial Comments 

at 11 (‘‘Moreover, generators are incented by their 

own reliability requirements to install the 

equipment that is most likely to keep their projects 

on-line and delivering real power.’’ (citations 

omitted)); NOPR, 186 FERC ¶ 61,203 at P 33 (‘‘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.’’) (citing CAISO 

Initial Comments to the NOI at 3). 

305SPP, 119 FERC ¶ 61,199 at P 28. This has 

always been a physical reality of the transmission 

system, even for wind generating facilities that were 

exempted from providing reactive service within 

the standard power factor range prior to Order No. 

827. Specifically, in Order No. 827, the Commission 

‘‘exempted wind generators from the uniform 

reactive power requirement because, historically, 

the costs to design and build a wind generator that 

could provide reactive power were high and could 

have created an obstacle to the development of 

wind generation.’’ Order No. 827, 155 FERC 

¶ 61,277 at P 4 (emphasis added). During this 

period of exemption, wind generating facilities 

would have had to rely on dynamic reactive power 

service supplied by other generating facilities and 

equipment on the transmission system capable of 

providing reactive support to allow their real power 

to reliably flow onto the transmission system. In 

essence, prior to Order No. 827, the Commission 

allowed the nascent wind industry to make up for 

these reactive power deficiencies by relying on 

transmission customers for reactive support because 

it determined that the costs of requiring them to 

provide their own reactive power could have been 

prohibitive. By the time of Order No. 827, that 

rationale for the exemption no longer existed, and 

the Commission, in removing this exemption for 

wind generating facilities in Order No. 827, noted 

that ‘‘[d]ue to technological advancements, the cost 

of providing reactive power no longer presents an 

obstacle to the development of wind generation.’’ 

Id. Additionally, the Commission expressed its 

concern ‘‘that, as the penetration of nonsynchronous generators continues to grow, 

exempting a class of generators from providing 

reactive power could create reliability concerns, 

especially if those generators represent a substantial 

amount of total generation in a particular region, or 

if many of the resources that currently provide 

reactive power are retired from operation. In 

addition, as noted above, maintaining the 

exemptions for wind generators places an undue 

burden on synchronous generators to supply 

reactive power without a reasonable technological 

or cost-based distinction between synchronous and 

non-synchronous generators.’’ Id. P 25. 

306See, e.g., Indicated Trade Associations Initial 

Comments at 9 (‘‘This assumption is at odds with 

Order No. 888, which expressly found that reactive 

service from generation facilities must be priced at 

cost’’); NEI Initial Comments at 4 (‘‘Unsurprisingly, 

in Order No. 888 the Commission found that 

reactive power is one of six ancillary services 

necessary to provide basic transmission service 

within every control area. Schedule 2 of the Open 

Access Transmission Tariff thus required that 

transmission providers provide—and transmission 

customers pay for—reactive power.’’); PSEG Initial 

Comments at 13 (‘‘The NOPR, if adopted, would 

effectively eliminate reactive power as one of 

ancillary services that the Commission has 

recognized since Order No. 888.’’); Middle River 

Power Initial Comments at 2–3 (citing Indicated 

Energy Trade Associations Initial Comments at 21; 

Order No. 888, FERC Stats. & Regs. ¶ 31,036 at 

31,707 (‘‘[T]ransmission customer actions do not 

eliminate entirely the need for generator-supplied 

reactive power.’’ ‘‘The transmission provider must 

provide at least some reactive power from 

generation sources.’’)). 

307NOPR, 186 FERC ¶ 61,203 at P 12; Order No. 

888, FERC Stats. & Regs. ¶ 31,036 at 31,705–07 & 

n.359; see also BPA Rehearing Order, 125 FERC 

¶ 61,273 at P 18. 

308Order No. 2003, 104 FERC ¶ 61,103 at P 546. 

309Order No. 2003–A, 106 FERC ¶ 61,220 at P 

416; see also MISO Rehearing Order, 184 FERC 

¶ 61,022 at P 24 (‘‘Order No. 2003 reflects the 

distinction between these two different reactive 

power concepts. When the transmission provider 

asks the interconnecting generator to operate its 

facility outside the established power factor range, 

the transmission provider is required to pay the 

interconnecting generator for the provision of such 

reactive power. By contrast, compensation for 

reactive power when the generating facility is 

operating within the established power factor range 

is generally not required. The sole exception the 

Commission identified was 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.’ ’’ (internal citations omitted)). 

310BPA Rehearing Order 125 FERC ¶ 61,273 at P 

18. 

311See, e.g., MISO, 182 FERC ¶ 61,033 at PP 52– 

53; MISO Rehearing Order, 184 FERC ¶ 61,022 at PP 

23–25, 41; PNM, 178 FERC ¶ 61,088 at PP 29–31; 

Nev. Power Co., 179 FERC ¶ 61,103 at PP 20–21; 

BPA, 120 FERC ¶ 61,211 at P 20; E.ON U.S. LLC, 

119 FERC ¶ 61,340 at P 15; Entergy Servs., Inc., 113 

FERC ¶ 61,040 at P 38. 

312Elevate Initial Comments at 9–12; Elevate 

Reply Comments at 7–9. 

Service Providers’ comments 

challenging this well-established policy 

to be a collateral attack on Order No. 

2003.303

102. Further, as the Commission has 

explained, to interconnect reliably to 

the transmission system and deliver 

power to customers, generating facilities 

must be capable of maintaining voltage 

levels for injecting real power into the 

transmission system.304 Said differently, 

‘‘if a generator is to sell (and be able to 

deliver) its power to a customer, 

reactive power is essential to the 

transaction.’’ 305 Thus, standalone 

compensation for the provision of 

reactive power within the standard 

power factor range does not result in 

just and reasonable transmission rates. 

103. Some commenters note that 

because Order No. 888 defined voltage 

support as a distinct ancillary service, it 

must be compensated separately.306 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.307 Specifically, in Order No. 

2003, when adopting the pro forma 

LGIA, 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.’’ 308

And 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.’’ 309 As a result, since Order 

No. 2003–A, the sole basis for reactive 

power capability compensation within 

the standard power factor range has 

been comparability (i.e., to ensure 

comparable treatment between affiliated 

and unaffiliated generating facilities), 

not compensability (i.e., an independent 

right to receive compensation for 

reactive power within the standard 

power factor range).310 The Commission 

has reiterated these findings in 

subsequent orders permitting 

transmission providers to eliminate 

separate compensation for generating 

facilities providing reactive power 

within the standard power factor 

range.311 Accordingly, commenters’ 

arguments in this regard are without 

merit. 

104. We also find Elevate’s and 

Glenvale’s arguments that some 

resource classes incur additional costs, 

including Elevate’s claims about battery 

degradation, unpersuasive.312 Elevate 

highlights battery degradation caused by 

the provision of reactive power, while 

Glenvale notes the operational and 

replacement costs associated with 

providing reactive power within the 

standard power factor range but neither 

explains how or why such costs are 

different and separate from the costs to 

provide real power. Degradation of 

components of a generator, including 

degradation of batteries, is a natural and 

inevitable result of power plant 

operation. As a result, the costs incurred 

by a generator to address such 

degradation, like other costs discussed 

above, are costs that generating facilities 

must incur to provide the real power for 

which they may seek compensation; nor 


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313PJM IMM Reply Comments at 4–5 (‘‘The 

NOPR does not require a finding that generators 

recover all of their cost in markets. Markets do not 

include such guarantees. In competitive markets, 

generation owners may overrecover their costs in 

markets at times and generators may underrecover 

their costs at times. The point is that when markets 

provide an opportunity to recover all costs, those 

same costs should not be recovered in a separate 

cost of service rate. The same investment should 

not be recoverable and recovered in two parallel 

regulatory regimes. That result is plainly unjust and 

unreasonable.’’). 

314See MISO Transmission Owners Initial 

Comments at 11–12 (citing VAR–002–3— Generator 

Operation for Maintaining Network Voltage 

Schedules, North American Electric Reliability 

Corporation, at 2 (Aug. 1, 2014), http://

www.nerc.com/pa/Stand/Reliability%20Standards/ 

VAR-002-3.pdf (‘‘R2 . . . Generator Operator shall 

maintain the generator voltage or Reactive Power 

schedule (within each generating Facility’s 

capabilities).’’). 

315Clean Energy Associations Initial Comments at 

7. 

316See, e.g., PJM IMM Initial Comments at 4 

(‘‘The current rules create strong incentives for 

generators to attempt to maximize the allocation of 

capital costs to reactive in order to maximize 

guaranteed, nonmarket revenues. Those nonmarket 

revenues provide a nonmarket advantage to those 

generators who receive them. This is a return to 

using the regulatory process for advantage rather 

than competing in the market. That advantage is 

arbitrary, not market based and therefore 

distortionary.’’). 

317Reactive Service Providers Initial Comments at 

27. 

318 Indicated Trade Associations Reply Comments 

at 9. 

319See infra II.C.2; see also Joint Customers 

Initial Comments at 16 (‘‘Finally, there is no reason 

to believe incremental costs of reactive power could 

not be recovered in the same way other costs are 

recovered. This could be through capacity markets 

and through power sales, depending on the regional 

characteristics of how generators cover other 

costs.’’). 

320NOPR, 186 FERC ¶ 61,203 at P 45. 

321For example, as of February 21, 2024, there 

were 453 total generating facilities in the CAISO 

interconnection queue, 440 of which were nonsynchronous 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, https://

rimspub.caiso.com/rimsui/logon.do (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 nonsynchronous 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, https://

opsportal.spp.org/Studies/GIActive (last visited 

Feb. 21, 2024). 

322NOPR, 186 FERC ¶ 61,203 at P 45. 

323 Id. 

324 Id. P 47 (citing BPA, 120 FERC ¶ 61,211 at P 

21). 

do transmission customers receive 

benefits that are commensurate with the 

charges for the provision of reactive 

power within the standard power factor 

range. Moreover, as discussed further 

below, battery storage resources, like all 

other generating facilities, still have the 

opportunity to seek to recover their 

costs through sales of energy and 

capacity, and the Commission’s actions 

here do not undercut those 

opportunities.313

105. Similarly, regarding NEI’s 

assertion that nuclear generating 

facilities incur disproportionate 

degradation from the provision of 

reactive power within the standard 

power factor range, we find that to the 

extent there are de minimis variable 

costs associated with providing reactive 

power within the standard power factor 

range, generating facilities in RTO/ISO 

markets could seek to recover such costs 

through energy and capacity markets. 

Transmission providers are responsible 

for maintaining voltage levels within 

their regions and have authority to 

direct generating facilities to operate at 

appropriate power factors to ensure 

system reliability.314

106. In response to Clean Energy 

Associations’ assertion that reactive 

power is not always coupled with real 

power,315 we reiterate that the final 

determination addresses only 

compensation for the provision of 

reactive power within the standard 

power factor range and that producing 

solely reactive power (i.e., a power 

factor of zero) entails reactive power 

production outside of the standard 

power factor range. As such, we find 

Clean Energy Associations’ concerns 

outside the scope of this final 

determination. 

107. We also find that compensation 

for the provision of reactive power 

within the standard power factor range 

could result in undue compensation and 

other market distortions.316 In response, 

Reactive Service Providers assert that 

generating facilities cannot be receiving 

windfalls from reactive power 

compensation because many generating 

facilities across multiple regions are 

retiring due to economic factors.317

However, these statements confuse 

compensation for reactive power within 

the standard power factor range with 

general cost recovery for generating 

facilities, which involves many other 

revenue streams. Our findings here are 

that generating facilities incur no 

incremental fixed costs and at most de 

minimis variable costs incremental to 

the cost of providing real power, 

because no additional equipment is 

required to provide reactive power and 

variable costs are limited to the fuel 

costs (in synchronous facilities) or 

foregone direct current power (in nonsynchronous facilities) necessary to 

provide the reactive power required to 

safely inject real power into the 

transmission system and comply with 

reliability requirements. Similarly, 

Indicated Trade Associations 318

contend that separate reactive power 

compensation cannot lead to market 

distortions because such rates have been 

approved by the Commission. But this 

argument ignores the final 

determination’s central logic that such 

rates lack a sufficient economic basis, 

and the comments in this proceeding 

have not refuted that central logic. 

108. As discussed further below, any 

purported de minimis variable costs 

associated with providing reactive 

within the standard power factor range 

can be recovered through other 

means.319

C. Cost Recovery 

109. In the NOPR, the Commission 

preliminarily found that separate 

compensation for providing reactive 

power within the standard power factor 

range is not necessary for generating 

facilities to recover their costs.320 The 

Commission noted that, 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.321 Furthermore, the 

NOPR explained that the basis for these 

payments has always been 

comparability rather than 

compensability.322

110. Instead, in the context of RTO/ 

ISO markets, the Commission 

preliminarily found it would be more 

efficient for generating facilities to seek 

to recover any identified costs to 

provide reactive power within the 

standard power factor range, to the 

extent they exist, through energy and 

capacity sales, because competition 

between generating facilities may 

incentivize efficiency and increase 

transparency.323

111. The Commission noted that it 

has previously and repeatedly rejected 

arguments that generating facilities need 

separate reactive power payments, 

because the incremental cost of reactive 

power within the standard power factor 

range is minimal.324 Therefore, 

consistent with those findings, the 

NOPR preliminarily found that 

eliminating compensation for reactive 

power within the standard power factor 

range would not compromise the ability 

of IPPs in non-RTO/ISO regions to 

recover their costs associated with 

producing reactive power within the 

range because generating facilities have 

the opportunity to seek to recover such 

costs in other ways, such as through 

higher power sales rates or through 


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325 Id. 

326 Id. P 48. 

327 Id. P 49. 

328See AEP Initial Comments at 4–6; Joint 

Consumer Advocates Initial Comments at 7–8 

(‘‘[Joint Consumer Advocates] assert that PJM 

generators will still have a more than ample 

opportunity to recover the costs associated with 

their provision of reactive power’’); Joint Customers 

Initial Comments at 15 (‘‘Generators have other 

means of covering costs incurred to meet 

interconnection design requirements.’’); Joint 

Customers Reply Comments at 15; MISO 

Transmission Owners Initial Comments at 16–17; 

MISO Transmission Owners Initial Comments at 15 

(‘‘Moreover, transmission providers have 

mechanisms for maintaining system reliability in 

the face of premature retirements, including 

identifying resources as ‘‘system support 

resources.’’) (citations omitted)); Ohio FEA Initial 

Comments at 5 (‘‘Ohio . . . supports competitive 

markets to induce efficiency and control costs’’). 

329TAPS Initial Comments at 7 & n.19 (citing 

CXA La Paloma, LLC v. CAISO, 165 FERC ¶ 61,148, 

at P 71 (2018) (‘‘The Commission has been clear 

that suppliers in competitive wholesale electricity 

markets are not guaranteed full cost recovery, but 

only the opportunity to recover their costs.’’)). 

330 Id. at 6–7 & n.18 (citing MISO, 182 FERC 

¶ 61,033 at P 53 (‘‘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.’’); Id. (citing PNM, 178 FERC ¶ 61,088 

at P 29; Nev. Power Co., 179 FERC ¶ 61,103, P 20 

(2022); BPA, 120 FERC ¶ 61,211 at P 20; E.ON U.S. 

LLC, 119 FERC ¶ 61,340 at P 15; Entergy Servs., Inc., 

113 FERC ¶ 61,040 at P 38) (‘‘Commission’s 

precedent allows transmission providers to 

eliminate compensation for reactive power within 

the standard power factor range for all generators, 

regardless of whether the generator is owned by or 

otherwise affiliated with a transmission owner or is 

independent.’’)). 

331New England Consumer Advocates Initial 

Comments at 4–6. See also id. at 5 (‘‘To the extent 

. . . benefits are achieved by compliance with a 

generating facility’s interconnection agreement and/ 

or as ‘good utility practice,’ [New England 

Consumer Advocates] agree[] with the Commission 

that ratepayers should not be paying separately for 

the costs to produce a joint reactive power 

product.’’). 

332Ohio FEA Initial Comments at 5. 

333Ameren Initial Comments at 3; Joint 

Customers Initial Comments at 12–13; TAPS Initial 

Comments at 4–5; MISO Transmission Owners 

Reply Comments at 11–12; MISO Transmission 

Owners Initial Comments at 5; PGE Initial 

Comments at 3–4. 

334 Joint Customers Initial Comments at 12–13; 

Ameren Initial Comments at 3; TAPS Initial 

Comments at 4–5; MISO Transmission Owners 

Reply Comments at 11–13. See also Joint Customers 

Initial Comments at 5–6 (‘‘The Commission’s policy 

of looking strictly to capability for determining cost 

recovery for Reactive Service incentivized 

overbuilding of capability beyond what was 

required based on interconnection requirements. 

This policy of not considering need or requiring a 

demonstration of need by the transmission owner 

has resulted in compensation for reactive capability 

without an actual demonstrated benefit to 

transmission system customers. This disconnect 

between capability and any actual demonstrated 

benefit highlights serious concerns that charges to 

customers are not related to any benefits received.’’ 

(citations omitted)). 

335 Joint Customers Initial Comments at 12–13; 

Ameren Initial Comments at 3; TAPS Initial 

Comments at 4–5; MISO Transmission Owners 

Reply Comments at 11–13. See also MISO 

Transmission Owners Initial Comments at 15 

(‘‘Moreover, transmission providers have 

mechanisms for maintaining system reliability in 

the face of premature retirements. When generators 

advise MISO of a planned retirement via 

Attachment Y of the MISO Tariff, MISO completes 

a review to determine whether any Transmission 

System reliability concerns are caused by the 

retirement. If voltage concerns arise in the 

Attachment Y study, options to address the voltage 

concerns are reviewed and ultimately a permanent 

solution is identified. If the permanent solution 

cannot be implemented before the planned 

retirement date, then the MISO Tariff has a 

designation for ‘‘system support resources,’’ under 

which generators are eligible to receive cost-based 

compensation to support their continued operation 

until an alternative solution to the reliability 

problem posed by the resources’ retirement is 

developed.’’ (citations omitted)). 

336MISO Transmission Owners Reply Comments 

at 11. 

337 Id. at 12 (citing K N Energy, Inc. v. FERC, 968 

F.2d 1295, 1300 (D.C. Cir. 1992) (‘‘[A]ll approved 

rates [must] reflect to some degree the costs actually 

caused by the customer who must pay them.’’); 

Entergy Ark., LLC v. FERC, 40 F.4th 689, 692 (D.C. 

Continued 

power purchase agreements (PPA).325

The Commission further noted that the 

experiences of CAISO, SPP, MISO, and 

non-RTO/ISO regions where generating 

facilities do not receive separate 

compensation for the provision of 

reactive power within the standard 

power factor range and the evidence in 

the record 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.326

112. In the NOPR, the Commission 

sought comment on whether, and if so 

how, the elimination of separate 

compensation for reactive power within 

the standard power range would affect 

generating facilities’ ability to recover 

their costs—if any.327

1. Comments 

113. Several Commenters argue that 

the record supports the finding that 

generating facilities can recover any 

purported costs of providing reactive 

power in the standard power factor 

range through their sales of energy and 

capacity.328 TAPS contends that the 

Commission is not required to guarantee 

that generating facilities recover their 

incremental costs of providing reactive 

power in the standard power factor 

range (to the extent those costs exist), 

but rather the ‘‘opportunity to recover 

costs is all that is required.’’ 329 TAPS 

explains that the Commission has never 

required payment of separate, costbased reactive power compensation 

within the standard power factor range 

to all interconnecting generators in all 

circumstances, but has rather given 

transmission providers the option to 

provide for such reactive power 

compensation for its own generation, 

provided all generators on its system 

were treated comparably, and 

transmission providers could also 

eliminate such compensation for itself 

and others on a comparable basis.330

New England Consumer Advocates 

states that any final determination 

should ensure that ratepayer costs for 

reactive power compensation are 

sufficiently justified, and that ISO–NE 

should articulate specific benefits and 

compare those benefits with the cost of 

compensation.331

114. Ohio FEA states that it supports 

prohibiting, as expeditiously as 

possible, the inclusion in transmission 

rates of charges related to the provision 

of reactive power within the standard 

power factor range because generators 

have an opportunity to recover all costs, 

including reactive power costs, through 

PJM markets.332

115. Several commenters argue that 

the NOPR’s proposal would resolve cost 

causation issues that result from the 

current practice of providing separate 

compensation for reactive power within 

the standard power factor range.333 Joint 

Customers, Ameren, TAPS, and MISO 

Transmission Owners argue that the 

current incentive to provide payment 

based on reactive power capability 

results in the building of unnecessary 

capabilities in locations it may not be 

needed and does not allocate costs 

associated with reactive power in a 

manner that is roughly commensurate 

with the benefits received.334 They 

assert that the current scheme results in 

a proliferation of charges for reactive 

power that is disconnected from the 

actual benefits received.335

116. MISO Transmission Owners 

argue that, contrary to some 

commenters’ claims, the NOPR’s 

proposed changes do not violate cost 

causation principles because generating 

facilities will still be compensated for 

the reactive power their generating 

facilities supply when they are required 

to operate outside the standard power 

factor range.336 MISO Transmission 

Owners state that ‘‘cost causation 

involves customers paying for a cost 

that they cause, not suppliers receiving 

compensation for services provided,’’ 

and assert that some ‘‘commenters 

attempt to turn this concept on its head’’ 

by ‘‘plac[ing] the focus on the service 

provider rather than the paying 

customer in an attempt to require 

payment for a service they are already 

obligated to provide as a condition of 

interconnection.’’ 337 MISO 


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93436 Federal Register / Vol. 89, No. 228 / Tuesday, November 26, 2024 / Rules and Regulations 

Cir. 2022) (‘‘In assessing whether a rate is ‘just and 

reasonable,’ FERC and the courts determine, among 

other things, whether the rate comports with the 

‘cost-causation principle’ which requires that the 

rates charged for electricity reflect the costs of 

providing it.’’ (citing Old Dominion Elec. Coop. v. 

FERC, 898 F.3d 1254, 1255 (D.C. Cir. 2018))). 

338 Id. at 11–13. See also MISO Transmission 

Owners Initial Comments at 16 (‘‘As the 

Commission explains, compensation for providing 

reactive power within the deadband is unnecessary, 

as resources are otherwise able to recover their 

costs. The Commission is correct in finding that 

there are many other mechanisms through which 

generators may recover the costs of reactive power 

service, if they need to. This is consistent with 

Commission precedent that has repeatedly 

highlighted how generators have the opportunity to 

recover any legitimate costs through other means. 

The Commission has found generators may recover 

such costs through power purchase agreements or 

capacity and energy market offers. As the 

Commission found when accepting the elimination 

of reactive power compensation in MISO, 

generators can still include the costs of reactive 

service in energy offers or capacity offers, even if 

subject to market power mitigation.’’ (citations 

omitted)). 

339MISO Transmission Owners Reply Comments 

at 12–13. 

340Ohio FEA Initial Comments at 4; New England 

Consumer Advocates Initial Comments at 3–4. 

341 Joint Customers Reply Comments at 14–15. 

342 Id. at 15. 

343See, e.g., Joint Customers Initial Comments, 

Affidavit of Dr. Albert W. Bremser at 6:3–7 (‘‘When 

a generating facility is operating within the 

standard power factor range, the generating facility 

is meeting its responsibility to maintain appropriate 

operational voltage levels for real power moving 

onto the transmission system. It is only when a 

generating facility is called upon to operate outside 

the standard power factor range that it is providing 

an ancillary service.’’ (citations omitted)). 

344See, e.g., Clean Energy Associations Initial 

Comments at 8–9; EDPR Initial Comments at 4–5; 

Elevate Initial Comments at 8–9; Generation 

Developers Initial Comments at 18–19; Glenvale 

Initial Comments at 5–6, 8–9; Indicated Reactive 

Power Suppliers Initial Comments at 14; Indicated 

Trade Associations Initial Comments at 3, 15; ISO– 

NE Initial Comments at 1–2; NAGF Initial 

Comments at 1; NEI Initial Comments at 12–13; 

NEPGA Reply Comments at 1, 4–6; NHA Initial 

Comments at 6–7; PSEG Initial Comments at 2–3, 

6, 14–15; Reactive Service Providers Initial 

Comments at 56–62, 77. 

345 Glenvale Initial Comments at 6. 

346 Indicated Reactive Power Suppliers Initial 

Comments at 11–12. 

347 Indicated Trade Associations Initial 

Comments at 15 (citing PJM OATT, Attachment DD, 

§ 6.6A(c) (0.0.0) (providing a categorical exception 

from the capacity must-offer obligation for certain 

types of resources)). 

348EDPR Initial Comments at 4–5; Generation 

Developers Initial Comments at 19; Indicated Trade 

Associations Initial Comments at 18; Reactive 

Service Providers Initial Comments at 59–62. 

349 Indicated Trade Associations Initial 

Comments at 17–18. 

350 Id. 

351 Generation Developers Initial Comments at 19. 

352 Id. at 18–19, 34–35; Glenvale Initial Comments 

at 6; Indicated Trade Associations Initial Comments 

at 12–15; Reactive Service Providers Initial 

Comments at 77. 

353 Indicated Trade Associations Initial 

Comments at 12–13 (citing Offer Caps in Mkts. 

Operated by Reg’l Transmission Orgs. and Indep. 

Sys. Operators, Order No. 831, 81 FR 87770 (Dec. 

5, 2016), 157 FERC ¶ 61,115, at PP 5, 7 (2016), on 

reh’g, Order No. 831–A, 82 FR 53403 (Nov. 16, 

2017), 161 FERC ¶ 61,156 (2017)). 

354 Generation Developers Initial Comments at 

34–35. 

355 Id. at 18. 

356 Id. 

357 Id. at 19. 

Transmission Owners argue that 

commenters’ claims that the NOPR’s 

proposed changes violate cost causation 

principles is a collateral attack on 

principles first promulgated in Order 

No. 2003 and its progeny because that 

series of orders required generators to 

provide reactive power within the 

standard power factor range without 

compensation, with few exceptions.338

MISO Transmission Owners argue that 

the NOPR’s proposed changes do not 

change generating facilities’ obligation 

to provide reactive power within the 

deadband, but rather they remove the 

unnecessary costs associated with 

payments to generating facilities.339

117. Ohio FEA and New England 

Consumer Advocates state that they 

support the Commission’s efforts to 

mitigate escalating transmission costs 

for customers, particularly when those 

costs provide no incremental benefit to 

the customers who pay them.340

118. Joint Customers acknowledge 

that the Commission generally allows 

for flexibility to account for regional 

differences. However, Joint Customers 

argue that such regional variations do 

not undermine the general rule against 

compensation for meeting 

interconnection requirements related to 

the standard power factor range.341 Joint 

Customers contend that ‘‘[t]here is a 

sufficient record for a determination 

that compensation for meeting 

interconnection requirements related to 

the standard power factor range should 

be prohibited as a general matter, with 

the understanding that generators 

directed to operate outside that range 

will continue to be compensated.’’ 342

Joint Customers witness Dr. Bresmer 

argues that a generating facility 

providing reactive power within the 

standard power factor range is simply 

meeting its interconnection obligations 

and not providing an ancillary 

service.343

119. Several commenters 344 argue 

that there is not sufficient evidence to 

support the conclusion that energy 

markets or capacity markets could or 

should be used to recover the costs of 

providing reactive power. Glenvale 345

and Indicated Reactive Power 

Suppliers 346 each state that reactive 

power and capacity are two distinct 

types of services and should not be 

combined. Glenvale argues that energy 

markets do not necessarily provide 

revenue opportunities due to 

competition and long-term contracts 

that do not allow certain generators 

access to these energy markets for 

several years. Indicated Trade 

Associations note that certain types of 

resources may not even participate in 

the capacity market.347 For example, 

Glenvale argues that some generators 

that provide reactive power but choose 

not to participate in the capacity market 

will not be able to recover lost reactive 

revenues. 

120. Some commenters argue that 

generating facilities will be unable to 

recover reactive power costs in their 

PPAs.348 Indicated Trade Associations 

argue that generators may have relied on 

existing reactive power compensation 

policies when they structured their 

PPAs, bilateral arrangements, and 

behind the meter arrangements.349

Indicated Trade Associations 350 and 

Generation Developers 351 each claim 

that the notion that PPA counterparties 

will be willing to renegotiate their 

contracts to allow them to charge a 

higher rate to recover the costs of a 

different service belies a basic 

understanding of wholesale markets. 

121. Some commentators 352 point to 

RTO/ISO market rules as potential 

barriers to recouping reactive power 

costs. Indicated Trade Associations 

assert that the Commission has required 

RTOs and ISOs to implement energy 

offer caps based on generators’ verifiable 

marginal costs.353 Generation 

Developers argue that the Commission 

should require RTOs/ISOs to revise 

their tariffs to eliminate existing barriers 

to the recovery of reactive power costs 

and permit generating facilities to 

accurately reflect their investments in 

reactive power capability in their 

capacity offers.354

122. Generation Developers argue that 

energy markets allow resources to sell 

energy on a day-ahead and real-time 

basis, with prices generally reflecting 

variable costs that are insufficient to 

allow resources to recover their fixed 

costs.355 Generation Developers state 

that RTO/ISO market mitigation rules 

generally prohibit generating facilities 

from reflecting fixed costs in their 

mitigated energy offer costs, often 

referred to as the ‘‘missing money 

problem,’’ and eliminating reactive 

power compensation would exacerbate 

this issue.356 Generation Developers 

argue that relying on capacity markets 

for reactive power compensation would 

result in arbitrary differences in the 

ability of resources to recover their costs 

because they would be required to 

provide reactive power regardless of 

whether they clear the capacity 

market.357 Generation Developers also 


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358 Id. 

359 Id. at 6. 

360 Indicated Trade Associations Initial 

Comments at 14. 

361 Indicated Reactive Power Suppliers Initial 

Comments at 9; Generation Developers Initial 

Comments at 4, 9–12; Reactive Service Providers 

Initial Comments at 62–63. 

362 Indicated Reactive Power Suppliers Initial 

Comments at 9; Generation Developers Initial 

Comments at 4, 9–12; Reactive Service Providers 

Initial Comments at 62–63. 

363 Generation Developers Initial Comments at 9– 

10 (citing Sithe/Indep. Power Partners, L.P. v. FERC, 

285 F.3d 1, 5 (D.C. Cir. 2002)). 

364 Id. at 10; Reactive Service Providers Initial 

Comments at 62–63. 

365 Generation Developers Initial Comments at 

10–13. 

366ACORE Initial Comments at 3; Generation 

Developers Initial Comments at 8–9; Indicated 

Trade Associations Initial Comments at 27; NEI 

Initial Comments at 2, 16; PSEG Initial Comments 

at 1–3, 17; Reactive Service Providers Initial 

Comments at 63–64. 

367 Indicated Trade Associations Initial 

Comments at 25–27; Reactive Service Providers 

Initial Comments at 64; PSEG Initial Comments at 

17; ACORE Initial Comments at 3. 

368ACORE Initial Comments at 3. 

369NEI Initial Comments at 16 (citing 2005 Staff 

Report at 4); PSEG Initial Comments at 17 (citing 

same). 

370Reactive Service Providers Initial Comments at 

64. 

371 Indicated Trade Associations Initial 

Comments at 24–26; Indicated Trade Associations 

Reply Comments at 16; NEI Initial Comments at 17. 

372 Indicated Trade Associations Initial 

Comments at 14; Reactive Service Providers Initial 

Comments at 45–46 

373Reactive Service Providers Initial Comments at 

45–46.; Indicated Trade Associations Initial 

Comments at 14 (arguing that including reactive 

power costs in energy offers would increase a 

generating facility’s risk of not clearing in the 

energy market, and that this risk is ‘‘particularly 

acute in jurisdictions where independent power 

producers compete with vertically integrated 

utilities whose generators recover costs through 

state-jurisdictional retail rates.’’ (citations omitted)). 

374Reactive Service Providers Initial Comments at 

46. 

375 Id. 

376NEI Initial Comments at 16. 

377 Id. at 16–17 & n.47. NEI asserts that the 

‘‘Commission still has an obligation to consider 

whether wholesale rates (or as here, proposed rates) 

are unduly discriminatory when considered in 

relation to retail rates, even though the latter is not 

subject to Commission jurisdiction.’’ Id. (citing Fed. 

Power Comm’n v. Conway Corp., 426 U.S. 271 

(1976); Commonwealth Edison Co., 8 FERC 

¶ 61,277, at 61,848 (1979); Sunoco, Inc. (R&M) v. 

Transcontinental Gas Pipe Line Corp., 114 FERC 

¶ 61,180 at P 28 & n.20 (2006)). 

assert that there is no nexus between the 

capacity value assigned to a generating 

facility and its reactive power 

capability.358 In addition, Generation 

Developers state that ‘‘[t]he Commission 

has a statutory obligation to ensure that 

[Commission]-jurisdictional rates are 

just, reasonable, and not unduly 

discriminatory or preferential’’ and 

assert that this requirement ‘‘prohibits 

the Commission from denying utilities 

the opportunity to recover their costs, 

plus a reasonable rate of return.’’ 359

123. Indicated Trade Associations 

argue that including reactive power 

costs in energy offers would increase a 

generator’s risk of not clearing in the 

energy market. Indicated Trade 

Associations further contend that 

capacity markets do not provide for 

recovery of reactive power costs because 

capacity offers from existing resources 

are limited to avoidable or going 

forward costs and do not allow for 

inclusion of costs that have already been 

incurred to provide reactive power.360

124. Some commenters 361 argue that 

the NOPR violates the cost causation 

and beneficiary pays principles because 

customers benefit from reactive power, 

including reactive power provided 

within the standard power factor range, 

and thus generating facilities should be 

compensated for this service.362

Generation Developers argue that while 

the cost causation principle does not 

require ‘‘exact precision,’’ it does 

require that Commission-approved rates 

‘‘be based on the costs of providing the 

service to the utility’s customers, plus a 

just and fair return on equity.’’ 363

Generation Developers and Reactive 

Service Providers assert that the NOPR’s 

proposal would insulate transmission 

providers and customers from any 

responsibility to pay for costs associated 

with the services they are receiving, 

which is ‘‘precisely the type of free 

ridership that the [FPA] and the cost 

causation principle are intended to 

prevent.’’ 364 Generation Developers 

argue that the Commission is essentially 

directing generating facilities to recover 

the costs of reactive power from 

customers purchasing energy and 

capacity, rather than the transmission 

customers that benefit from the reactive 

service.365

125. Several commenters 366 who 

oppose the NOPR assert that removing 

compensation within the standard 

power factor range would result in 

discriminatory treatment between 

generating facilities and transmission 

owners. These commenters argue that, 

under the NOPR, generating facilities 

would be prohibited from recovering 

their costs to provide reactive power 

under Schedule 2, yet transmission 

owners that install reactive power 

equipment and assets as part of their 

transmission system would be able to 

recover the costs of those assets through 

transmission rates charged to 

transmission service customers. They 

contend that transmission owners 

would have guaranteed cost recovery for 

the very same service that generating 

facilities would be prohibited from 

collecting under this NOPR.367 ACORE 

asserts that reactive power provides the 

same benefit to the system, regardless of 

who owns the capacitor banks.368

126. NEI and PSEG both argue that the 

2005 Staff Report recognized this 

discriminatory concern and contend 

that the Commission therefore 

recommended that all providers of 

reactive power should be paid on a 

nondiscriminatory basis.369 Reactive 

Service Providers add that unless and 

until the Commission proposes to also 

eliminate the opportunity for 

transmission providers to collect costs 

associated with providing reactive 

service, the NOPR’s proposal is per se 

discriminatory and preferential, in 

violation of the FPA.370 Indicated Trade 

Associations suggest that by 

disincentivizing generators from 

competing to provide reactive power 

service, the NOPR creates a preference 

for higher-cost transmission solutions 

installed by transmission owners, which 

will harm consumers.371

127. Relatedly, Reactive Service 

Providers and Indicated Trade 

Associations assert that the NOPR raises 

competition concerns.372 Reactive 

Service Providers argue that even if the 

transmission provider elects to no 

longer pay generating facilities for 

reactive power service, the transmission 

provider will still be able to collect the 

costs of generation-based reactive power 

service through retail rates.373 Reactive 

Service Providers assert that this ‘‘is a 

sweet deal that allows the Transmission 

Provider to lean on the IPP to provide 

the service for free under the 

[Commission]’s jurisdiction, with the 

utility simply shifting to another forum 

to recover the same generation-based 

costs.’’ 374 Reactive Service Providers 

argue that the NOPR undermines the 

competition that the Commission sought 

to facilitate in Order No. 2003, and 

while IPPs are disadvantaged by losing 

a revenue stream, utility-generation is 

able to make that revenue stream up 

through retail rates, thereby putting 

utility generation in a stronger position 

to compete.375 To the extent that 

reactive power service costs are 

recoverable by transmission owners 

through state retail rates, NEI recognizes 

that such rates are outside the 

Commission’s jurisdiction.376 NEI 

asserts, however, that this does not 

excuse the Commission from 

considering transmission owners’ ability 

to recover their reactive power costs at 

the state level when the Commission is 

setting its own jurisdictional wholesale 

rates.377


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378 Id. at 2. 

379 Id. at 16–17. 

380Elevate Initial Comments at 12–13 (citing Elec. 

Storage Participation in Mkts. Operated by Reg’l 

Transmission Orgs. & Indep. Sys. Operators, Order 

No. 841, 83 FR 9580 (Mar. 6, 2018), 162 FERC 

¶ 61,127, at P 79 (2018), order on reh’g, Order No. 

841–A, 167 FERC ¶ 61,154 (2019)). 

381 Indicated Trade Associations Initial 

Comments at 30. 

382 Id. at 31–32. 

383NHA Initial Comments at 5–7. 

384Reactive Service Providers Initial Comments at 

31–34. 

385 ISO–NE Initial Comments at 1–2; NESCOE 

Reply Comments at 2; NEPGA Reply Comments at 

6–7; NEPOOL Reply Comments at 6–7. 

386 ISO–NE Initial Comments at 9–10 (citing Me. 

Pub. Util. Comm’n v. ISO New England Inc., 126 

FERC ¶ 61,090 (2009)). 

387 In ISO–NE, a generating facility may submit a 

request, including documentation, to ISO–NE to 

receive additional compensation based on their 

verified leading and lagging reactive capability. See 

ISO–NE Schedule 2, § 3.1 (10.0.0). 

388NEPOOL Reply Comments at 9–11. 

389NEPGA Reply Comments at 4–6. 

390NYISO Initial Comments at 1. 391 Id. at 2; IPPNY Reply Comments at 1–2. 392NYISO Initial Comments at 2; IPPNY Reply 

Comments at 1–2. 393NYISO Initial Comments at 2–5. 394 Id. 395 Id. at 7–8. 396 Id. 

128. NEI contends that the proposed 

replacement rate would result in undue 

discrimination against nuclear 

generators by imposing disproportionate 

burdens on them without fair 

compensation.378 NEI states that the 

Commission has an obligation to 

consider whether the proposed rates are 

unduly discriminatory, meaning that the 

Commission must consider transmission 

owners’ ability to recover their reactive 

power costs at the state level.379 Elevate 

argues that the NOPR is inconsistent 

with the spirit of Order No. 841, which 

required that energy storage resources 

‘‘be eligible to provide services that the 

RTOs/ISOs do not procure through an 

organized market mechanism (such as 

blackstart service, primary frequency 

response service, and reactive power 

service) if they are technically capable 

of providing those services.’’ 380 Elevate 

argues that the unique physical and 

operational characteristics of energy 

storage resources correspond with the 

unique revenue profile of energy storage 

resources. 

129. Indicated Trade Associations 

argue that the Commission must ensure 

that it adopts comprehensive transition 

plans that account for the specific 

market design and rules of each RTO/ 

ISO and direct each RTO/ISO to make 

filings identifying modifications to be 

made to existing market rules to 

implement the NOPR.381 Indicated 

Trade Associations contend that the 

Commission must clarify how 

generating facilities will be 

compensated for reactive power 

dispatch outside the standard power 

factor range and note that Consolidated 

Edison Company of New York, Inc. 

requires newly connecting generating 

facilities to be able to provide reactive 

power 0.85 lagging to 0.95 leading.382

The NHA further argues that the 

Commission should allow individual 

RTOs/ISOs to retain their reactive 

power compensation frameworks, as 

they are better suited to address regional 

reliability needs, and to develop 

compensation mechanisms to reflect 

locational needs.383 Reactive Service 

Providers contend that there is no 

evidence that generating facilities are 

being sited without respect to whether 

there is a geographic need for reactive 

power, or that costs are no longer 

commensurate with benefits.384

130. Several commenters also 

submitted RTO/ISO-specific comments 

addressing cost recovery. As discussed 

above, ISO–NE, NESCOE, NEPGA, and 

NEPOOL argue that ISO–NE’s Schedule 

2 VAR compensation program should 

not be disturbed.385 ISO–NE notes that 

the Commission denied Maine Public 

Utilities Commission’s complaint to 

only allow reactive power compensation 

outside the power factor range, as VAR 

payments were a ‘‘negotiated value and 

is not equal to, nor is it intended to 

recover, the cost of service of any 

particular generating Resource.’’ 386

131. NEPOOL explains that three 

factors specific to Schedule 2 contribute 

to the reliability benefits of reactive 

service in New England: (1) the 

generator must be dispatchable and 

ready to respond to the ISO’s instruction 

to produce or absorb reactive power; (2) 

to be designated as a Qualified Reactive 

Resource,387 a generator must have 

automatic voltage regulation equipment 

and telemetry in place to enable the ISO 

to determine that it is providing 

‘‘measurable dynamic reactive power 

voltage support to the New England 

Transmission System’’; and (3) 

Schedule 2 requires reactive power 

testing of Qualified Reactive Resources 

in accordance with the applicable ISO– 

NE Operating Procedures.388 NEPOOL 

argues that these three factors show that 

any final determination should allow 

flexibility for transmission providers, 

such as ISO–NE, to maintain 

compensation mechanisms that pay for 

reactive power across the full power 

factor range when payment is 

contingent on the reactive power 

resource meeting enhanced reliabilityrelated requirements. 

132. NEPGA states that ISO–NE’s 

wholesale energy and capacity markets 

do not compensate for reactive power 

capability or costs, but rather 

transmission rates compensate for 

reactive power capability through ISO– 

NE’s Schedule 2 rate design.389 NEPGA 

argues that the Tariff provisions 

governing capacity market offers in 

ISO–NE do not allow a generator to 

include the costs for providing reactive 

power in its offer prices nor does the 

capacity market value reactive power 

capability. Further, NEPGA states that 

ISO–NE’s energy market offer-price 

rules (both day-ahead and in real-time) 

likewise limit costs to those necessary to 

produce real power versus reactive 

power. Therefore, NEPGA contends that 

ISO–NE’s wholesale markets do not, as 

the Commission suggests, provide an 

opportunity to recover the costs of the 

capability to provide reactive power and 

the actual costs to deliver reactive 

power. 

133. NYISO states that it supports the 

NOPR’s objective to avoid 

administratively burdensome processes 

and procedures to determine 

individualized cost-of-service reactive 

power rates for generation facilities.390

As discussed above, NYISO and IPPNY 

argue that NYISO’s existing reactive 

power and VSS compensation structure, 

which uses a flat dollars per MVAr-year 

structure, is just and reasonable.391

NYISO and IPPNY each assert that 

NYISO’s flat rate compensation 

structure for VSS has been effective for 

over 20 years, ensuring adequate 

reactive power capability and system 

reliability in the New York Control Area 

at a reasonable cost to consumers.392

NYISO explains that the structure, 

accepted by the Commission since 1999, 

was developed with stakeholder input 

and Commission approval, with 

significant revisions in 2016 to include 

leading and lagging reactive power 

capabilities.393 NYISO maintains that 

this structure aligns costs directly with 

services provided, ensuring reliability 

benefits commensurate with 

expenses.394

134. NYISO states that its flat rate 

compensation provides market-like 

incentives, encouraging resources to 

offer reactive power cost-effectively by 

rewarding increased capability and 

maintaining necessary equipment.395

NYISO explains that this approach 

reduces the need for complex, 

individualized cost-based payments and 

integrates reactive power support 

efficiently into the broader market 

framework, promoting economic 

efficiency and reliability.396

135. NYISO contends that as the 

current system ensures direct 


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397 Id. at 8–11. 

398 Id. at 11–13. 

399 Id. at 13–14; IPPNY Reply Comments at 2. 

400NYISO Initial Comments at 14. 

401PJM Initial Comments at 3–4. 

402 Id. at 6–7. 

403PJM IMM Initial Comments at 1–2. See also 

id.at 4 (‘‘[T]here is no reason that part of those 

capital costs should be paid directly in a 

nonmarket, guaranteed, riskless revenue stream 

rather than in the market.’’); id. at 6 (‘‘Elimination 

of the reactive revenue requirement and the reactive 

revenue offset would increase prices in the capacity 

market. The VRR curve, or demand curve, would 

shift to the right, the maximum VRR price would 

increase and offer caps in the capacity market 

would increase.’’). 

404PJM IMM Reply Comments at 5 (‘‘When 

buyers and sellers enter into power purchase 

agreements, the contracting parties define and 

assign regulatory risk. Customers are not 

responsible to manage or pay for suppliers’ risks.’’). 

405PJM IMM Initial Comments at 8 (‘‘Reactive 

power is not the only design obligation that 

generation interconnection customers assume. 

Generators are also obligated to provide primary 

frequency response capability ‘‘by installing, 

maintaining, and operating a functioning governor 

or equivalent controls . . .’’ Primary frequency 

response capability is required for the reliable 

operation of the system. The PJM OATT does not, 

however, provide for an out of market payment for 

such capability. The provision of primary frequency 

capability is treated as an obligation assumed by 

generation interconnection customers for receiving 

interconnection service.’’) (citations omitted)); Id. at 

9 (‘‘The PJM OATT includes a number of other 

obligations on generation interconnection 

customers, many of which are important and 

impose costs, but does so without including any 

special provisions for out of market 

compensation.’’); PJM IMM Reply Comments at 6 

(‘‘The fundamental logic of the obligation to 

provide reactive service, frequency control service 

and other essential elements of interconnecting to 

the power grid is that the grid is a network. All 

generators who connect to the grid benefit from that 

network effect. All generators who connect to the 

grid have corresponding obligations to the grid that 

permit the grid to function as an effective and 

reliable network. It has always been the case that 

there are standards for interconnecting to the 

network. Meeting those standards is part of being 

a resource on the network. The actual costs of 

interconnecting to the grid can be significant for 

resources but those costs are part of the cost of 

building a resource and part of the investment 

decision for resource owners and not a reason for 

a separate guaranteed payment.’’). 

406PJM IMM Initial Comments at 12–13. 

407We emphasize that our findings in this final 

determination do not affect any party’s filing rights 

under section 205 of the FPA, including the right 

of generating facilities to seek cost recovery for the 

provision of reactive power outside the standard 

power factor range. See supra II.A.2. 

408See, e.g., PJM IMM Initial Comments at 1–2, 

4, 6, 9, 12–13; PJM IMM Reply Comments at 2–5; 

Joint Customers Initial Comments at 16; MISO 

Transmission Owners Initial Comments at 16–17; 

Ohio FEA Initial Comments at 3, 5; Joint Consumer 

Advocates Initial Comments at 7–8; TAPS Initial 

Comments at 7–8; see also MISO Rehearing Order, 

184 FERC ¶ 61,022 at P 42 (‘‘On rehearing, we 

conclude that Vistra has still not adequately 

explained why generators cannot include the costs 

attributable to Reactive Service in energy offers or 

capacity offers, even if subject to market power 

mitigation, . . . . As 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 capability. 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 

capability (e.g., fuel costs, short-term variable 

operations and maintenance) in such offers. 

Moreover, while Vistra claims that ‘‘a generation 

resource that attempts to recover its fixed costs of 

reactive power through its energy or capacity offers 

runs the risk that it will trigger application of 

MISO’s market power mitigation rules,’’ even 

assuming this were correct, this would not preclude 

generators from recovering such costs in the 

capacity market, but rather would require that they 

verify the costs with the independent market 

monitor. The cases Vistra cites also do not establish 

that where Schedule 2 compensation for Reactive 

Service is not available, seeking compensation 

Continued 

compensation for reactive power that is 

critical for maintaining system 

reliability, altering the compensation 

mechanism could lead to increased 

costs and complicate market operations, 

undermining the efficiency and 

effectiveness of its existing 

framework.397

136. NYISO emphasizes that as the 

resource mix evolves with more 

asynchronous and renewable resources, 

its flexible compensation structure is 

crucial for maintaining and enhancing 

reactive power support.398 NYISO 

argues that this adaptability will ensure 

ongoing system reliability amidst 

changing resource dynamics. 

137. Lastly, NYISO and IPPNY each 

highlight the need for continued 

flexibility in adjusting compensation 

rules to incentivize maximum reactive 

power capability and minimize out-ofmarket commitments.399 NYISO 

contends that a uniform implementation 

approach is not suitable given the 

varying regional needs and existing 

effective compensation frameworks.400

138. PJM states that the NOPR would 

largely eliminate a number of problems 

that PJM and its stakeholder processes 

have identified. PJM explains that given 

that PJM stakeholders have been unable 

to reach consensus on a new rate 

paradigm after two years of work, PJM 

supports the proposed reforms 

identified in the NOPR and encourages 

the Commission to adopt them as 

proposed.401 As discussed further 

below, PJM also proposes that RTOs/ 

ISOs be allowed to implement any 

needed conforming changes to their 

market rules as part of the compliance 

process.402

139. The PJM IMM states that the 

NOPR would extend a just and 

reasonable, pro competition policy to all 

jurisdictional markets and public 

utilities while protecting PJM customers 

from unjust and unreasonable charges 

for reactive capability that generation 

owners are already required to 

provide.403 The PJM IMM also argues 

that power suppliers, not customers, are 

responsible for the regulatory risk 

related to their PPAs.404

140. The PJM IMM adds that 

generating facilities in PJM incur other 

obligations, such as primary frequency 

response, as a condition of 

interconnection without separate 

compensation for such obligations.405

The PJM IMM maintains that: 

There is no evidence that units are built as 

a result of reactive [power] revenue. There is 

no evidence that sources of revenue are not 

fungible and that a decrease in reactive 

[power] revenues could be not replaced with 

other sources of revenue. There is no basis 

for adding new resources to the already very 

crowded interconnection queue solely based 

on out of market subsidies from reactive 

revenues.406

2. Commission Determination 

141. Based on the record here, we 

adopt the NOPR’s preliminary findings 

and conclude that separate 

compensation for providing reactive 

power within the standard power factor 

range is not necessary for generating 

facilities to have the opportunity to 

recover their costs. As explained above, 

for both synchronous and nonsynchronous generating facilities, real 

and reactive power are joint products, 

with joint costs and there are no 

identifiable fixed costs incurred by 

generating facilities to provide reactive 

power within the standard power factor 

range beyond the investments in 

equipment already necessary to generate 

and supply real power to the 

transmission system. Further, the record 

demonstrates that there are at most de 

minimis variable costs, such as fuel and 

maintenance costs, associated with 

providing reactive power within the 

standard power factor range. Given that 

the primary function of a generating 

facility is to produce real power, and 

that the provision of reactive power 

within the standard power factor range 

is necessary to the provision of real 

power, we find that a generating 

facility’s fixed and variable costs are 

appropriately recovered through 

payments for real power, such as energy 

and/or capacity sales, whether in 

organized or bilateral markets.407

Accordingly, we find that this final 

determination does not prevent a 

generating facility from seeking to 

recover its costs because resource 

owners have the opportunity to recover 

any of their appropriate fixed and 

variable costs through other revenue 

streams, including the opportunity to 

make up for lost revenues, if any, from 

the cessation of reactive power 

compensation.408 We find that such an 


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through other mechanisms is impermissible.’’ 

(citations omitted)). 

409PJM IMM Initial Comments at 1–6, 9, 12–13; 

PJM IMM Reply Comments at 2–5. 

410See, e.g., PJM IMM Initial Comments at 6. 

411See PJM IMM Initial Comments at 6 

(‘‘Elimination of the reactive revenue requirement 

and the reactive revenue offset would increase 

prices in the capacity market. The VRR curve, or 

demand curve, would shift to the right, the 

maximum VRR price would increase and offer caps 

in the capacity market would increase.’’). 

412See infra III.B.2. 

413See III.B.2; see, e.g., MISO Rehearing Order, 

184 FERC ¶ 61,022 at PP 40–42; BPA, 120 FERC 

¶ 61,211 at P 21 (finding that the argument that it 

is not feasible for IPPs to recover their costs through 

higher power sales rates ‘‘lacks plausibility’’ ‘‘since 

the incremental cost of reactive power service 

within the deadband is minimal,’’ and ‘‘[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’’). See also Joint Customers 

Initial Comments at 15 (‘‘Generators have other 

means of covering costs incurred to meet 

interconnection design requirements.’’); MISO 

Transmission Owners Initial Comments at 16 (‘‘As 

the Commission explains, compensation for 

providing reactive power within the deadband is 

unnecessary, as resources are otherwise able to 

recover their costs. The Commission is correct in 

finding that there are many other mechanisms 

through which generators may recover the costs of 

reactive power service, if they need to. This is 

consistent with Commission precedent that has 

repeatedly highlighted how generators have the 

opportunity to recover any legitimate costs through 

other means. The Commission has found generators 

may recover such costs through power purchase 

agreements or capacity and energy market offers. As 

the Commission found when accepting the 

elimination of reactive power compensation in 

MISO, generators can still include the costs of 

reactive service in energy offers or capacity offers, 

even if subject to market power mitigation.’’ 

(citations omitted)). 

414See, e.g., PJM IMM Initial Comments at 4 

(‘‘[T]here is no reason that part of those capital costs 

should be paid directly in a nonmarket, guaranteed, 

riskless revenue stream rather than in the market.’’); 

Joint Customers Initial Comments at 15 

(‘‘Generators have other means of covering costs 

incurred to meet interconnection design 

requirements.’’). 

415AEP Initial Comments at 4–6; Joint Consumer 

Advocates Initial Comments at 7–8; Joint Customers 

Initial Comments at 15–18; Ohio FEA Initial 

Comments at 5 (‘‘Through the PJM markets, 

generators have an opportunity to recover all costs, 

including reactive power costs.’’). See also MISO 

Transmission Owners Initial Comments at 15–17 

(‘‘The Commission is correct in finding that there 

are many other mechanisms through which 

generators may recover the costs of reactive power 

service, if they need to.’’). 

416NOPR, 186 FERC ¶ 61,203 at P 48 (citing 

CAISO Initial Comments to NOI at 5–6). 

417 Id. (citing LRE/UCS Initial Comments to NOI 

at 16). 

418See PJM Initial Comments at 6–7; infra III.B.2. 

419NHA Initial Comments at 5–7. 

outcome is not only appropriate given 

the nature of the costs but also more 

efficient because competition between 

generating facilities may incentivize 

efficiency.409

142. We recognize, however, the 

current interplay between existing 

reactive power revenue compensation 

mechanisms and energy and capacity 

market rules in ISO–NE, NYISO, and 

PJM,410 and, as a result, the RTOs/ISOs 

may request, by setting forth the specific 

bases and reasoning therefore for the 

Commission’s consideration an effective 

date for their compliance filings that 

allows them to develop and propose 

changes to their markets that are 

necessary in order to accommodate this 

final determination’s elimination of 

compensation for the provision of 

reactive power within the standard 

power factor range. As recognized in the 

NOPR and affirmed in the comments, 

the existing capacity market rules in 

PJM, ISO–NE and NYISO reflect the 

existence of generator payments under 

Schedule 2 through a revenue offset and 

reduce capacity market revenues 

accordingly. For example, as PJM and 

the PJM IMM explain, the PJM capacity 

market rules currently reflect a reactive 

power revenue offset in both the market 

seller offer caps and the Net Cost of New 

Entry (CONE) for the reference resource, 

which affects the shape of PJM’s 

capacity market demand curve. 

Therefore, both PJM and the PJM IMM 

argue that the market rules will have to 

be revised to reflect the impacts of this 

final determination.411 Similarly, 

NYISO and ISO–NE may need to 

propose changes to market rules to 

reflect the elimination of reactive power 

revenues resulting from this final 

determination. Therefore, as discussed 

below, we recognize that ISO–NE, 

NYISO, and PJM may need to develop 

and propose changes to their markets 

that may be necessary to accommodate 

this final determination’s elimination of 

compensation for the provision of 

reactive power within the standard 

power factor range.412 For the reasons 

explained above, we also disagree with 

those commenters who argue that there 

is not sufficient evidence to support the 

conclusion that energy markets or 

capacity markets could or should be 

used to seek to recover the costs 

currently recovered through payments 

for reactive power, as well as those 

commenters that argue that because 

capacity and reactive power service are 

separate products, their costs should 

likewise be recovered separately under 

Schedule 2. Given the same equipment 

is used for real and reactive power and 

the incremental variable costs of 

reactive power service within the 

deadband are minimal, as explained in 

the section above, we disagree with 

commenters’ claims that costs, if any, 

currently recovered through reactive 

power payments cannot be recovered 

through other markets, especially given 

the transition period provided in this 

final determination, which addresses 

concerns about existing market rules 

that may impact cost recovery from 

those markets.413 Furthermore, our 

finding here is supported both by 

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, and the evidence in 

the record to date.414 Specifically, 

experience and evidence demonstrate 

that: (1) eliminating compensation has 

not led to an insufficient supply of 

reactive power in those regions; and (2) 

generating facilities in these regions 

have been able to recover their fixed and 

variable costs through other means.415

For example, CAISO ‘‘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.’’ 416

Rather, ‘‘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.’’ 417

143. We also find it of no 

consequence that a generating facility 

participates in only the energy market, 

as no commenter has demonstrated why 

these joint costs could not be recovered 

via energy sales, as these costs are 

necessary for the production and 

delivery of real power. However, as 

discussed herein, to the extent that 

current RTO/ISO market rules require 

generating facilities to subtract their 

separate revenue streams for reactive 

power from the avoidable costs they are 

permitted to reflect in their capacity 

market offers, we encourage RTOs/ISOs 

to propose any necessary conforming 

changes to their market rules in section 

205 filings accompanying their 

compliance filings to this final 

determination.418

144. The NHA asserts that capacity 

markets are unequipped to situate 

reactive power where it is most needed 

because capacity markets do not allow 

for granular clearing prices based on 

specific geographic locations. In turn, 

the NHA argues that RTOs/ISOs should 

instead develop reactive power 

compensation rules to reflect locational 

requirements.419 However, we find that 

generating facilities are required to 

provide reactive power within the 

standard power factor range as a matter 

of good utility practice and to meet the 

obligations under their interconnection 

agreements under Order No. 2003, 


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420See supra II.A.2; MISO Transmission Owners 

Reply Comments at 12–13 (‘‘That series of orders 

required, among other things, that interconnecting 

generators be able to provide reactive power within 

the deadband without compensation.’’). 

421See MISO Transmission Owners Initial 

Comments at 15 (‘‘Moreover, transmission 

providers have mechanisms for maintaining system 

reliability in the face of premature retirements. 

When generators advise MISO of a planned 

retirement via Attachment Y of the MISO Tariff, 

MISO completes a review to determine whether any 

Transmission System reliability concerns are 

caused by the retirement. If voltage concerns arise 

in the Attachment Y study, options to address the 

voltage concerns are reviewed and ultimately a 

permanent solution is identified. If the permanent 

solution cannot be implemented before the planned 

retirement date, then the MISO Tariff has a 

designation for ‘system support resources,’ under 

which generators are eligible to receive cost-based 

compensation to support their continued operation 

until an alternative solution to the reliability 

problem posed by the resources’ retirement is 

developed.’’ (citations omitted)). 

422EDPR Initial Comments at 4–5; Generation 

Developers Initial Comments at 19; Indicated Trade 

Associations Initial Comments at 18; Reactive 

Service Providers Initial Comments at 59–62. 

423See, e.g., PJM IMM Reply Comments at 5 

(‘‘When buyers and sellers enter into power 

purchase agreements, the contracting parties define 

and assign regulatory risk. Customers are not 

responsible to manage or pay for suppliers’ risks.’’). 

424See MISO Rehearing Order, 184 FERC 

¶ 61,022 at P 33 (‘‘Sophisticated parties, like 

independent power producers, have the ability to 

manage risks of this sort in entering long-term 

arrangements rather than assuming that this 

compensation will be available in perpetuity.’’). 

425See, e.g., Nev Power Co., 179 FERC ¶ 61,103; 

PNM, 178 FERC ¶ 61,088 at PP 26–36; SPP, 119 

FERC ¶ 61,199 at PP 20, 30–33. 

426See MISO Rehearing Order, 184 FERC 

¶ 61,022 at P 33 (‘‘[W]e find that generators’ 

assumption that such compensation will continue 

to be available does not give rise to reliance 

interests that justify requiring that such 

compensation continue to be provided.’’). 

427PNM, 178 FERC ¶ 61,088 at P 33 (‘‘[B]y 

designing its generating facility to have the 

capability to provide reactive support, Aragonne 

Wind is only meeting the conditions of 

interconnection required of all generators and is not 

entitled to compensation unless the transmission 

provider pays its own or affiliated generators for 

reactive power within the established range.’’). 

428 Generation Developers Initial Comments at 18. 

429 Indicated Trade Associations Initial 

Comments at 14. 

430See MISO Transmission Owners Initial 

Comments at 14 (‘‘Moreover, all charges under 

Schedule 2 of the MISO Tariff for the provision of 

reactive power within the standard power factor 

range were eliminated in the MISO region effective 

December 1, 2022. MISO has since experienced no 

reliability issues as a result and generator 

interconnection applications, the first step of a 

process that ends with execution of an 

interconnection agreement that obligates the 

generator to provide reactive power within the 

deadband, remain high.’’ (citations omitted)). 

431 Generation Developers Initial Comments at 6. 

432 Id. 

433See, e.g., N. Am. Elec. Reliability Corp., 183 

FERC ¶ 61,222 (2023) (explaining that the FPA 

requires only that Commission-jurisdictional rates 

provide an opportunity for the recovery of 

prudently incurred costs necessary to comply with 

reliability standards—not that all entities have 

identical outcomes) (citing ISO New England Inc., 

132 FERC ¶ 61,044, at P 28 (2010) (‘‘[R]esources are 

provided only an opportunity to recover their costs, 

not a guarantee that they will recover those costs.’’); 

Bridgeport Energy, LLC, 113 FERC ¶ 61,311, at P 29 

(2005) (‘‘[T]he Commission has no obligation in a 

competitive marketplace to guarantee Bridgeport its 

full traditional cost-of-service. Rather, in a 

competitive market, the Commission is responsible 

only for assuring that Bridgeport is provided the 

opportunity to recover its costs.’’) (emphasis in 

original). 

434 ISO–NE Initial Comments at 10. 

regardless of location.420 For that 

reason, Order No. 2003 does not contain 

a location-specific component for the 

provisions of reactive power within the 

standard power factor range. Any 

additional reactive power capability 

required to satisfy specific local 

reliability needs, as well as the 

compensation for costs incurred to 

provide that capability (e.g., capacitors, 

synchronous condensers), are for the 

transmission provider to determine and 

are beyond the scope of this final 

determination.421

145. In response to commenters 422

who argue that generating facilities will 

be unable to recover through their 

existing PPAs costs that are currently 

recovered through separate reactive 

power payments, the record lacks any 

concrete evidence showing whether, 

and to what extent, generating facilities 

factored reactive power revenues into 

their PPAs. Even if a generator were able 

to demonstrate that eliminating 

compensation under our rule might 

impact some generating facility’s 

profitability, we do not believe that 

potential disrupted expectations weigh 

in favor of a different outcome in this 

situation. As a general matter, the risk 

of regulatory change is inherent in any 

long-term PPA.423 Moreover, as 

explained above, because no generating 

facility could have reasonably relied on 

an inherent right to separate 

compensation for reactive power 

capability within the standard power 

factor range since Order Nos. 2003 and 

2003–A (i.e., because such 

compensation is required only to ensure 

‘‘comparability’’), there has always been 

some risk in relying on compensation, 

because market rules can change.424

Indeed, developers and generating 

facilities have been on notice since at 

least 2003 that the Commission regards 

reactive power compensation within the 

standard power factor range as noncompensable (other than where the 

comparability standard applies) —a 

conclusion that was patent in those 

orders, and reinforced repeatedly in 

subsequent Commission orders 

accepting transmission owner filings 

under section 205 that eliminated 

reactive power compensation within the 

standard power factor range.425

Additionally, the Commission rejected 

reliance arguments in the MISO 

Rehearing Order 426 and PNM.427 We 

similarly find unsupported Generation 

Developers’428 concerns about energy 

markets being insufficient to recover 

fixed costs and Indicated Trade 

Associations’ 429 concerns about not 

clearing the energy market when 

including reactive power costs in energy 

market bids. The record demonstrates 

that, in regions such as MISO, where 

separate compensation for the provision 

of reactive power within the standard 

power factor range has been eliminated, 

generating facilities continue to be 

developed, indicating that such 

developers believe there to be sufficient 

opportunity to recover their costs, 

including any costs associated with the 

provision of reactive power within the 

standard power factor range.430 In light 

of this evidence, Indicated Trade 

Associations’ and Generation 

Developers’ arguments that organized 

markets do not provide sufficient 

opportunities for generating facilities to 

recover their costs fall flat. 

146. We agree with Generation 

Developers that ‘‘[t]he Commission has 

a statutory obligation to ensure that 

[Commission]-jurisdictional rates are 

just, reasonable, and not unduly 

discriminatory or preferential.’’ 431

Indeed, our actions here do nothing to 

deny generating facilities their 

‘‘opportunity to recover their costs, plus 

a reasonable rate of return.’’ 432 As noted 

above, generating facilities have an 

opportunity to recover appropriately 

recoverable fixed and variable costs 

through other markets, including the 

opportunity to potentially make up for 

lost revenue from the cessation of 

reactive power compensation within the 

standard power factor range.433 And if 

market rules in RTOs/ISOs currently 

inhibit such recovery, as discussed 

herein, we are permitting the RTOs/ 

ISOs to request additional time to 

update those market rules, as may be 

appropriate and consistent with this 

final determination. 

147. Regarding ISO–NE’s 434 reliance 

on the Commission’s denial of the 

Maine Public Utilities Commission’s 

complaint to support its assertion that 

ISO–NE’s reactive power scheme was, 

and continues to be, just and reasonable, 

we acknowledge that our findings in 

this final determination represent a 

change in policy from prior Commission 

findings on compensation for the 

provision of reactive power within the 

standard power factor range. However, 

as discussed above, we find that the 

record in this proceeding demonstrates 

that such a change is appropriate. 


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435ACORE Initial Comments at 3; Generation 

Developers Initial Comments at 4, 9–12; Indicated 

Trade Associations Initial Comments at 27; NEI 

Initial Comments at 2, 16; PSEG Initial Comments 

at 1–3, 17; Reactive Service Providers Initial 

Comments at 62–64; Indicated Reactive Power 

Suppliers Initial Comments at 9. 

436See II.B.2. 

437 Indicated Trade Associations Initial 

Comments at 24–26; Indicated Trade Associations 

Reply Comments at 16; NEI Initial Comments at 17. 

438See SPP Rehearing Order, 121 FERC ¶ 61,196 

at P 15 (‘‘As we have previously explained, reactive 

power is required for an interconnecting generator 

to deliver its power and reactive power produced 

within the [standard power factor range] and is, 

therefore, generally not compensable.’’ (emphasis 

added)); BPA Rehearing Order, 120 FERC ¶ 61,211 

at P 21 (‘‘The 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.’’); see supra 

II.A.2. 

439 Indicated Trade Associations Initial 

Comments at 24–27; Reactive Service Providers 

Initial Comments at 64; PSEG Initial Comments at 

17; ACORE Initial Comments at 3; NEI Initial 

Comments at 2, 16. 

440Order No. 888, FERC Stats. & Regs. ¶ 31,036 

at 31,706 (‘‘We accept NERC’s identification of two 

ways of supplying reactive power and controlling 

voltage. One is to install facilities, usually 

capacitors, as part of the transmission system. We 

will consider the cost of these facilities as part of 

the cost of basic transmission service. Providing 

reactive power and voltage control in this way is 

not a separate ancillary service. The second is to 

use generating facilities to supply reactive power 

and voltage control. This use is the service named 

here, which must be unbundled from basic 

transmission service.’’). 

441 Id. (‘‘NERC further distinguishes reactive 

supply services based on the source of the need for 

the service: (1) reactive supply needed to support 

the voltage of the transmission system; and (2) 

reactive supply needed to correct for the reactive 

portion of the customer’s load at the delivery 

point.’’); see also supra n.439. 

442NEI Initial Comments at 16 (citing 2005 Staff 

Report at 4); PSEG Initial Comments at 17 (citing 

same). 

443SPP Order on Rehearing, 121 FERC ¶ 61,196 

at P18 (‘‘[T]ransmission owners’ generators are not 

entitled to charge retail customers retail rates that 

guarantee full recovery of their costs; rather, they 

must first justify their rates to state authorities’’). 

444BPA, 120 FERC ¶ 61,211 at P 21 (citing SPP, 

119 FERC ¶ 61,199 at P 39). 445 Id. 446SPP, 119 FERC ¶ 61,199 at P 38. See N. Am. 

Elec. Reliability Corp., 183 FERC ¶ 61,222 (rejecting 

claims that reliability standard gives vertically 

integrated utilities a competitive advantage; 

explaining that, while the approval of the new 

standard may have different implications for 

different entities depending on their existing 

compensation mechanisms, the FPA requires only 

that Commission-jurisdictional rates provide an 

opportunity for the recovery of prudently incurred 

costs necessary to comply with reliability 

standards—not that all entities have identical 

outcomes). 

447Supra n.415. 

148. We disagree with 

commenters’ 435 contention that 

eliminating compensation for reactive 

power within the standard power factor 

range would violate the cost causation 

principle. As discussed above, real and 

reactive power are provided as joint 

products, with joint costs, and are 

produced using the same equipment; 

therefore, a separate cost compensation 

mechanism for the provision of reactive 

power within the standard power factor 

range is not necessary.436 We are not 

persuaded that eliminating 

compensation for reactive power within 

the standard power factor range violates 

cost causation. 

149. Additionally, we disagree with 

claims that transmission customers are 

the sole beneficiaries and cost-causers, 

as well as assertions 437 that eliminating 

compensation for reactive power within 

the standard power factor range would 

insulate transmission providers and 

customers from paying for any costs 

associated with the services they are 

receiving—essentially requiring 

generating facilities to recover the costs 

of reactive power from energy and 

capacity market customers, rather than 

the transmission customers that benefit 

from the reactive power service. These 

arguments fail because they are 

inconsistent with Commission 

precedent that explains that providing 

reactive power within the standard 

power factor range enables generating 

facilities to reliably deliver real power 

to the transmission system (i.e., make 

real power sales).438 In effect, these 

costs are ‘‘caused’’ by the operating 

requirements of the generating facilities 

to deliver real power, not by the 

separate needs of the transmission 

customers. 

150. We similarly disagree with 

commenters’439 assertions that 

eliminating compensation for reactive 

power within the standard power factor 

range would result in undue 

discrimination between generating 

facilities and transmission assets, where 

owners of the latter would still have 

guaranteed recovery of their costs of 

reactive power assets through 

transmission rates. The Commission has 

long held that reactive power supply 

from transmission facilities is distinct 

from reactive power supply from 

generating facilities, with the former 

constituting a basic part of transmission 

service.440 This is because generating 

facilities must produce reactive power 

within the standard power factor range 

to allow the generating facilities’ real 

power to reliably flow onto the 

transmission system, while transmission 

provider investment in capacitor banks 

is to control transmission system voltage 

levels to provide reliable transmission 

service.441 These findings also address 

similar arguments raised by NEI and 

PSEG.442

151. Similarly, we find without merit 

Reactive Service Providers’ and 

Indicated Trade Associations’ argument 

that transmission owners that own 

generation will have a competitive 

advantage over IPPs by virtue of their 

ability to recover their costs through 

retail rates. Putting aside that 

commenters provide no support for 

their contention that transmission 

owners that own generation will be able 

to recover their reactive power costs 

through retail rates,443 the Commission 

has rejected similar arguments on 

multiple occasions. In SPP and BPA, the 

Commission explained ‘‘that merchant 

generators 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.’’ 444

The Commission also observed that 

‘‘[i]n this regard, all that the protestors 

have done is to note that an incumbent 

utility’s generators may be able to make 

up the revenue that they previously 

might have earned through a separate 

charge for reactive power within the 

deadband in other ways—such as 

through higher power sales rates. But 

merchant generators are no differently 

situated and their ability to recover such 

costs has not been compromised. They, 

equally, may be able to recover the costs 

for reactive power within the deadband 

in other ways—such as through higher 

power sales rates of their own.’’ 445 As 

in those other cases, we believe that our 

action here ‘‘maintains a level playing 

field for all generators subject to 

Commission jurisdiction, such that 

compensation for reactive power 

support is separately paid when reactive 

power outside the deadband is 

dispatched to the point on the 

transmission system where it is needed, 

and in the magnitude required to ensure 

a stable grid.’’ 446

152. Regarding Elevate’s assertion that 

Commission precedent, including Order 

No. 841, requires compensation for any 

service that a generating facility is 

technically capable of providing, we 

note that many regions do not provide 

separate compensation for each 

obligation of interconnection. For 

example, as the PJM IMM notes, 

generating facilities in PJM are required 

to provide primary frequency response 

and other essential transmission system 

services as a condition of 

interconnection without a separate, 

dedicated revenue stream.447

Furthermore, as explained above, 


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448See, II.B.2. 

449See, II.A.2. 

450New England Consumer Advocates Initial 

Comments at 5 (‘‘To the extent . . . benefits are 

achieved by compliance with a generating facility’s 

interconnection agreement and/or as ‘good utility 

practice,’ [New England Consumer Advocates] 

agree[] with the Commission that ratepayers should 

not be paying separately for the costs to produce a 

joint reactive power product.’’). 

451See, e.g., supra n.140. 

452 Joint Customers Initial Comments at 5–6 (‘‘The 

Commission’s policy of looking strictly to capability 

for determining cost recovery for Reactive Service 

incentivized overbuilding of capability beyond 

what was required based on interconnection 

requirements. This policy of not considering need 

or requiring a demonstration of need by the 

transmission owner has resulted in compensation 

for reactive capability without an actual 

demonstrated benefit to transmission system 

customers. This disconnect between capability and 

any actual demonstrated benefit highlights serious 

concerns that charges to customers are not related 

to any benefits received.’’ (citations omitted)). 

453NOPR, 186 FERC ¶ 61,203 at P 43 (citing 

Essential Reliability Servs. & the Evolving BulkPower Sys. Frequency Response, Order No. 842, 83 

FR 9639 (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.’’)). 

454 Id. P 15 (citing MISO, 182 FERC ¶ 61,033 at 

PP 52–53; MISO Rehearing Order, 184 FERC 

¶ 61,022 at P 26; PNM, 178 FERC ¶ 61,088, at PP 

29–31; Nev. Power Co., 179 FERC ¶ 61,103 at PP 20– 

21; BPA, 120 FERC ¶ 61,211 at P 20; E.ON U.S. LLC, 

119 FERC ¶ 61,340 at P 15; Entergy Servs., Inc., 113 

FERC ¶ 61,040 at P 38); see also id. P 18 (noting 

that CAISO, SPP, and MISO do not pay separately 

for reactive power within the standard power factor 

range). 

455 Id. 

456 Id. P 44. 

457See, e.g., Joint Consumer Advocates Initial 

Comments at 6–8; Joint Customers Reply Comments 

at 1–2; MISO Initial Comments at 2; MISO 

Transmission Owners Initial Comments at 12–16; 

New England Consumer Advocates Initial 

Comments at 4–5; Ohio FEA Initial Comments at 4; 

PGE Initial Comments at 2–3; PJM IMM Initial 

Comments at 11–12. 

458MISO Initial Comments at 2. 

459 Joint Customers Reply Comments at 2–6; 

MISO Initial Comments at 2; MISO Transmission 

Owners Initial Comments at 14–15; TAPS Initial 

Comments at 5. 

460PJM IMM Initial Comments at 11–12. 

461 Joint Customers Reply Comments at 2; see also 

id. at 3 (‘‘The Commission is, in fact, in an enviable 

position where the pro forma revisions 

contemplated in the NOPR have recently been 

implemented on a large regional scale. For the 

purposes of establishing record support for the 

NOPR and addressing transition, discussed below, 

the MISO proceeding essentially point by point 

addresses the arguments recycled to oppose the 

NOPR. The same is true with respect to the 

arguments concerning reliability, which were 

extensively addressed in the MISO order and order 

on rehearing. But with respect to reliability, MISO 

Continued 

generating facilities have an opportunity 

to recover their appropriate fixed and 

variable costs through other markets, 

including the opportunity to make up 

for lost revenue from the cessation of 

reactive power compensation within the 

standard power factor range. 

153. Although ISO–NE and NYISO 

argue to maintain their existing reactive 

power compensation schemes, as 

discussed above, these arguments ignore 

the findings in this final determination, 

which apply equally to flat-rate 

compensation regimes like ISO–NE’s 

and NYISO’s, as to the compensation 

regimes of PJM and certain non-RTO 

regions. That is, generating facilities 

incur no incremental fixed costs and at 

most de minimis variable costs 

incremental to the cost of providing real 

power, because no additional 

equipment is required to provide 

reactive power and variable costs are 

limited to the fuel costs (in synchronous 

facilities) or foregone direct current 

power (in non-synchronous facilities) 

necessary to provide the reactive power 

required to safely inject real power into 

the transmission system and comply 

with reliability requirements.448

154. These commenters argue that 

transparency, administrative burden, 

and preventing double recovery 

problems are reduced or eliminated in 

either ISO–NE, NYISO, or both. 

However, all those arguments suppose 

that compensation is due, and thus that 

a compensation method is needed. But, 

if no separate compensation is due, all 

compensation methodologies will 

necessarily result in unjust and 

unreasonable rates.449 Furthermore, we 

agree with New England Consumer 

Advocates,450 who argue that any 

payment for reactive power capability 

within the standard power factor range 

must yield some roughly commensurate 

incremental benefit above and beyond 

that which would accrue absent 

payment.451 Given those arguments, 

transmission customers in ISO–NE and 

NYISO, just like transmission customers 

in PJM and non-RTO regions, do not 

receive benefits that are commensurate 

with the costs of reactive power charges, 

even if the compensation methods used 

in these regions are less 

administratively burdensome than the 

methods used in other regions.452

D. Reliability 

155. The NOPR preliminarily found 

that ‘‘compensation for providing 

reactive power within the standard 

power factor range is unnecessary to 

maintain reliability’’ and 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.’’ 453 In addition to noting that 

multiple RTOs, 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,454 the NOPR 

observed that CAISO has not seen major 

issues of concern with the level of 

reactive power in its region despite not 

providing separate compensation for 

reactive power within the standard 

power factor range. The Commission 

also preliminarily found in the NOPR 

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 within 

the standard power factor range.455

156. The NOPR sought comment on 

the reliability impact of prohibiting 

transmission providers from including 

in their transmission rates any charges 

associated with the provision of reactive 

power within the standard power factor 

range from a generating facility in 

regions where generating facilities 

currently receive such compensation.456

1. Comments 

157. Many commenters do not expect 

to see an impact on reliability under the 

NOPR proposal.457 For example, ‘‘MISO 

has not experienced reliability concerns 

since December 1, 2022 due to the 

elimination of compensation for reactive 

power within the standard power factor 

range.’’ 458 Furthermore, several 

commenters observe that regions like 

MISO, which implemented similar 

reforms, and CAISO, which does not 

compensate for reactive power service, 

have not experienced related reliability 

concerns.459 The PJM IMM argues that 

‘‘there is no evidence that expanding the 

just and reasonable approach to 

compensation already in place in 

CAISO, SPP, and MISO to PJM will have 

any adverse impact on reliability in 

PJM’’ and that ‘‘[t]he salient difference 

between PJM and CAISO, SPP, and 

MISO is that PJM customers paid 

$388,044,837.00 in out of market 

payments for reactive capability in 

2023, and customers in CAISO, SPP and 

MISO, paid $0.00’’ 460 for the same 

service. Joint Customers agree with the 

NOPR that the Commission’s 

‘‘precedent is crystal clear that 

compensation is not required’’ 461 for 


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is dispositive not only for its precedential value, but 

also in setting up a real-world test of the 

countervailing predictions regarding the impact of 

eliminating compensation for reactive service 

within the standard power factor range.’’ (citations 

omitted)); id. at 4 (‘‘MISO’s experience validates the 

Commission’s conclusions in approving the MISO 

Transmission Owners’ proposed tariff revisions, as 

well as the Commission’s skepticism regarding 

speculative warnings of reliability impacts. It 

similarly validates PJM’s support for the NOPR and 

the conclusions of the PJM Independent Market 

Monitor that amending Schedule 2 of the PJM Tariff 

will not lead to reliability concerns.’’ (internal 

citations omitted)). 

462 Joint Customers Reply Comments at 4–6; 

MISO Transmission Owners Initial Comments at 

12–16; MISO Transmission Owners Reply 

Comments at 3–4; Ohio FEA Initial Comments at 4; 

PGE Initial Comments at 2–4. 

463MISO Transmission Owners Initial Comments 

at 12. 

464MISO Transmission Owners Reply Comments 

at 6 (citing Order No. 2003, 104 FERC ¶ 61,103 at 

P 546; Order No. 2003–A, 106 FERC ¶ 61,220 at PP 

410, 416). 

465 Joint Customers Reply Comments at 4–6. 

466Supra n.448. 

467 Joint Consumer Advocates Initial Comments at 

7–8; MISO Transmission Owners Initial Comments 

at 12–16; TAPS Initial Comments at 5. 

468See, e.g., Indicated Trade Associations Initial 

Comments at 21. 

469MISO Transmission Owners Initial Comments 

at 11 (citing MISO Rehearing Order, 184 FERC 

¶ 61,022 at P 35 n.116 (‘‘[G]enerators have 

incentives to install equipment to ensure that their 

generation remains online and delivering real 

power.’’)). 

470See, e.g., Clean Energy Associations Initial 

Comments at 5; Elevate Initial Comments at 4–9; 

Elevate Reply Comments at 4–6; Generation 

Developers Initial Comments at 2–6; Indicated 

Trade Associations Initial Comments at 18–19; 

NAGF Initial Comments at 2; NEI Initial Comments 

at 2; NEPGA Reply Comments at 2–3 (citing ISO– 

NE Initial Comments at 6–7); NESCOE Reply 

Comments at 2–3 (citing ISO–NE Initial Comments 

at 5–8); NHA Initial Comments at 1–2, 4; NYISO 

Initial Comments at 8–11; PSEG Initial Comments 

at 4–5, 8, 16–20, 22–24; Reactive Service Providers 

Initial Comments at 22. 

471Elevate Initial Comments at 4–9; Elevate Reply 

Comments at 4–6. 

472NHA Initial Comments at 2. 

473 Id. at 6. 

474Elevate Initial Comments at 5 (citing 

Meyersdale Storage, LLC Proposed Revenue 

Requirement under PJM Interconnection, L.L.C. 

Open Access Transmission Tariff, Schedule 2, 

Reactive Supply and Voltage Control From 

Generation Sources Service, Docket No. ER21–864– 

000, Exh. No. MEY–0001 at 11:19–22 (filed Jan. 11, 

2021)). 

475 Generation Developers Initial Comments at 2– 

3. 

476 Indicated Trade Associations Initial 

Comments at 18–19; Indicated Trade Associations 

Reply Comments at 12. 

477 Indicated Trade Associations Initial 

Comments at 19–20. 

478NEI Initial Comments at 3 (citing Letter from 

FERC Chairman Pat Wood, III, 1 (Feb. 4, 2005), 

https://www.ferc.gov/sites/default/files/2020-05/ 

20050310144430-02-04-05-rp-letter-wood.pdf; 2005 

Staff Report at 3 (‘‘Inadequate reactive power has 

led to voltage collapses and has been a major cause 

of several recent major power outages 

worldwide.’’)). 

479NEI Initial Comments at 3–4 citing NERC, 

Essential Reliability Services Task Force Measures 

Framework Report 16 (Nov. 2015), https://

www.nerc.com/comm/Other/ 

essntlrlbltysrvcstskfrcDL/ERSTF%20

Framework%20Report%20-%20Final.pdf. 

480NEPOOL Reply Comments at 12. 

481 Indicated Trade Associations Initial 

Comments at 21. 

482 Indicated Trade Associations Reply Comments 

at 12. 

483NYISO Initial Comments at 8–11; IPPNY 

Reply Comments at 1–2. 

484NYISO Initial Comments at 5–7. 

generators meeting interconnection 

requirements of providing reactive 

service within the standard power factor 

range. In addition, MISO Transmission 

Owners assert that eliminating reactive 

power compensation will not adversely 

affect reliability because generators are 

required to provide reactive power 

pursuant to their interconnection 

agreements,462 NERC requirements,463

and Order No. 2003.464 Joint Customers 

argue that there is a ‘‘lack of concrete 

evidence of adverse reliability impacts 

(including in regions where this exact 

change has been implemented)’’ in the 

record and the commenters’ concern 

that ‘‘if there is not an unjustifiable free 

revenue stream ostensibly related to 

reactive service and capability, there 

will not be sufficient generation for real 

power and capacity at some unspecified 

point in the future’’ is ‘‘speculative to 

the point of incoherence.’’ 465

158. MISO Transmission Owners 

refute the claim that the transmission 

system will face increased retirements 

due to the loss of reactive power 

revenue by arguing that transmission 

providers have mechanisms for 

maintaining system reliability in the 

face of premature retirements.466

Relatedly, Joint Consumer Advocates, 

MISO Transmission Owners, and TAPS 

each point to ample backlogs in 

generator interconnection queues 

nationwide as protection against any 

threat to reliability from eliminating 

reactive power compensation.467

159. MISO Transmission Owners also 

counter fears 468 of inadequate 

incentives to make the necessary capital 

investments to provide reactive power 

by explaining that generators are 

incented by their own operating and 

reliability requirements to install the 

equipment that is most likely to keep 

their projects online and delivering real 

power.469

160. Other commenters express 

general reliability concerns under the 

NOPR proposal.470 Commenters also 

argue that specific types of resources 

especially benefit from reactive power 

revenue, including energy storage,471

hydro,472 and nuclear.473 Elevate 

explains that ‘‘[b]ecause energy storage 

resources ‘have the capability to operate 

at any power factor, they are 

exceptionally valuable as reactive power 

resources.’’’ 474

161. Generation Developers argue 

that, without the reactive power 

capability of generating facilities, 

transmission providers will need to 

further invest in transmission 

equipment capable of providing reactive 

support.475 Indicated Trade 

Associations assert that eliminating a 

source of stable, expected reactive 

power compensation could lead to more 

retirements.476 Relatedly, Indicated 

Trade Associations also state that, while 

CAISO does not currently compensate 

reactive power service, it has had to rely 

on reliability must-run (RMR) 

agreements to maintain the needed 

reactive power.477 NEI emphasizes the 

importance of reactive power, noting 

Chairman Wood’s statement that proper 

reactive power management would have 

‘‘delayed’’ or possibly prevented the 

2003 August blackout,478 and NERC’s 

finding that ‘‘reactive power is critical 

to the reliable and efficient operation of 

the power system.’’ 479 NEPOOL argues 

that payment for reactive power 

broadens the base of resources willing to 

seek to become Qualified Reactive 

Resources and support reliability in 

ISO–NE.480

162. Indicated Trade Associations 

also argue that eliminating 

compensation for reactive power service 

within the standard power factor range 

will hamper generators’ ability to 

provide reactive power service outside 

the standard power factor range because 

such events do not happen with enough 

regularity to warrant the capital costs 

associated with such capability.481

Similarly, Indicated Trade Associations 

argue that the increasing reliance on 

non-synchronous resources makes it 

even more important to ensure that 

generators have incentives to go beyond 

the bare minimum requirements 

outlined in their interconnection 

agreements.482

163. NYISO and IPPNY warn that 

transitioning away from NYISO’s 

current reactive power compensation 

structure could introduce reliability 

risks and operational complexities.483

NYISO asserts that its reactive power 

compensation supports electric system 

reliability because it requires resources 

to undergo annual capability tests and 

maintain automatic voltage control 

equipment to ensure consistent reactive 

power support.484 NYISO explains that 

these resources dynamically produce or 

absorb reactive power, supporting the 

electric system within and beyond 

standard power factor ranges without 

operator intervention. NYISO 

emphasizes that this automatic and 


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485 Id. 

486Reactive Service Providers Initial Comments at 

21–23. 

487 Generation Developers Initial Comments at 25; 

Reactive Service Providers Initial Comments at 21– 

23. 

488NYISO Initial Comments at 7. 

489 Id. at 9. 

490Elevate Reply Comments at 6–7 (citing Energy 

Storage News, Europe’s largest transmissionconnected BESS begins ‘world first’ reactive power 

services contract, (Feb. 13, 2023), https://

www.energy-storage.news/europes-largesttransmission-connected-bess-begins-world-firstreactive-power-services-contract/). 

491 Id. at 7 (citing ESO, Obligatory Reactive Power 

Service, https://www.nationalgrideso.com/industryinformation/balancing-services/reactive-powerservices/obligatory-reactive-powerservice#Document-Library (last visited June 26, 

2024); ESO, Enhanced Reactive Power Service, 

https://www.nationalgrideso.com/industryinformation/balancing-services/reactive-powerservices/enhanced-reactive-power-serviceerps#Document-library (last visited June 26, 2024)). 

492NOPR, 186 FERC ¶ 61,203 at P 43. 

493 Joint Consumer Advocates Initial Comments at 

6–8; Joint Customers Reply Comments at 1–2; MISO 

Initial Comments at 2; MISO Transmission Owners 

Initial Comments at 12–16; New England Consumer 

Advocates Initial Comments at 4–5; Ohio FEA 

Initial Comments at 4; PGE Initial Comments at 2– 

3; PJM IMM Initial Comments at 11–12. See also 

Order No. 842, 162 FERC ¶ 61,128 (‘‘[T]here are 

interconnection requirements for generating 

facilities in which the recovery of capital costs and 

operating expenses are not necessarily ensured.’’). 

494See, e.g, MISO, 182 FERC ¶ 61,033 (accepting 

MISO transmission owners’ proposal to eliminate 

compensation for the provision of reactive power 

within the standard power factor range); Cal. Indep. 

Sys. Operator Corp., 160 FERC ¶ 61,035 at P 19 

(‘‘[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.’’); 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.’’). 

495Clean Energy Associations Initial Comments at 

5; Indicated Trade Associations Initial Comments at 

18–19; Indicated Trade Associations Reply 

Comments at 12; NEPOOL Reply Comments at 12; 

Elevate Initial Comments at 4–9; Elevate Reply 

Comments at 4–6; NEI Initial Comments at 6, 15; 

NHA Initial Comments at 2, 4. 

496CAISO Initial Comments to the NOI at 5–6 

(explaining that despite the fact that it does not 

compensate for reactive power within the standard 

power factor range, CAISO ‘‘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’’); MISO Transmission 

Owners Initial Comments at 15 (‘‘The claim that 

generators may have to retire units in the absence 

of compensation for reactive power service within 

the deadband is pure speculation. Prior to the 

elimination of compensation for reactive power 

within the deadband in MISO, a number of 

generators in MISO operated without compensation 

for reactive power within the deadband as they did 

not file their revenue requirements for reactive 

power when their projects came on-line.’’). 

497TAPS Initial Comments at 5. 

498See, e.g., Joint Customers Reply Comments at 

6 (arguing that there is a ‘‘lack of concrete evidence 

of adverse reliability impacts (including in regions 

where this exact change has been implemented)’’ in 

the record and that commenters’ concern that ‘‘if 

there is not an unjustifiable free revenue stream 

ostensibly related to reactive service and capability, 

there will not be sufficient generation for real power 

and capacity at some unspecified point in the 

Continued 

dynamic support is essential for 

maintaining system reliability.485

Reactive Service Providers explains that 

inverter-based generation can and does 

provide VAR support even when no 

MW are sold.486 Generation Developers 

and Reactive Service Providers highlight 

the pivotal role in maintaining 

reliability that transmission providers 

with a dynamic source of reactive power 

supply provide.487 NYISO is concerned 

that eliminating compensation for 

reactive power within the standard 

power factor range will introduce 

confusion among existing generators 

and new generators, and, in the longer 

term, introduce reliability issues onto 

the electric system.488 NYISO also 

believes that the final determination 

will result in eliminating the price 

signals and incentives for the reactive 

power necessary to maintain system 

reliability, instead blending those costs 

and payments into payments made to all 

capacity suppliers without a direct link 

to provision of the reactive power 

necessary to support a reliable electric 

system.489

164. Elevate adds that international 

electric markets recognize the 

importance of energy storage resources 

to maintaining long-term transmission 

system reliability.490 For example, 

Elevate states that in the United 

Kingdom, the National Grid Electricity 

System Operator (ESO) has entered into 

a contract with the largest transmission 

system connected battery project in 

Europe to provide reactive power 

support services to maintain system 

voltages in the face of growing system 

variability and the retirement of thermal 

generation resources. Elevate states that 

the ESO entered this contract despite 

already providing compensation to 

resources for providing or absorbing 

reactive power as a condition of 

interconnecting and through regular 

solicitations to secure resources to 

provide more reactive power than what 

is required to interconnect to the 

transmission system.491

2. Commission Determination 

165. Based on our review of the 

record, and consistent with the 

preliminary finding in the NOPR,492 we 

conclude that prohibiting transmission 

providers from including in their 

transmission rates any charges 

associated with the provision of reactive 

power from a generating facility within 

the standard power factor range and 

thereby eliminating compensation to 

generating facilities for reactive power 

within the standard power factor range, 

would not negatively impact reliability. 

The record in this proceeding affirms 

our preliminary finding in the NOPR 

that requiring transmission customers 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, as new and existing generating 

facilities are, and will continue to be, 

required to provide reactive power 

within the standard power factor range 

as a condition of obtaining and 

maintaining interconnection.493 As 

commenters note, these findings are 

supported by the fact that generating 

facilities in CAISO, SPP, MISO, and 

certain non-RTO regions (e.g., BPA, 

Arizona Public Service Company, 

Southern Companies) do not receive 

compensation for reactive power 

capability within the standard power 

factor range,494 and there is no evidence 

in the record that the lack of reactive 

power compensation anywhere has led 

to an insufficient supply of reactive 

power in those regions. 

166. For these same reasons, we also 

find speculative and without merit 

claims that elimination of compensation 

for reactive power within the standard 

power factor range will mute investment 

in real and reactive power capability, 

hasten generating facility retirements 

and/or RMR agreements and as a result, 

negatively impact reliability and require 

increased transmission provider 

investment in transmission equipment 

capable of providing reactive 

support.495 We see no record evidence 

supporting these concerns, and 

substantial record evidence to the 

contrary. For example, CAISO stated 

that 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 respect to the level of 

reactive power,496 and TAPS points out 

that reliability has not suffered in 

regions in which reactive power in the 

standard power factor range is not 

compensated, as confirmed by years of 

experience in regions in which the 

absence of such compensation is a longstanding practice.497 Reliability has not 

been weakened in those regions because 

the Commission’s 20 year old 

requirement that interconnection 

customers have equipment to provide 

such reactive power ensures that 

generating facilities can interconnect 

reliably.498


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future’’ is ‘‘speculative to the point of 

incoherence’’); TAPS Initial Comments at 5; MISO 

Initial Comments at 2 (explaining that it would not 

expect to see any effect on reliability through 

eliminating compensation for reactive power within 

the standard power factor range and in fact, MISO 

has not experienced reliability concerns since 

December 1, 2022 due to the elimination of 

compensation for reactive power within the 

standard power factor range). See also Order No. 

842, 162 FERC ¶ 61,128 at P 121 (‘‘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 reliabilityrelated 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.’’). 

499See, e.g., MISO Rehearing Order, 184 FERC 

¶ 61,022 at P 23 (citing METC Rehearing Order, 97 

FERC at 61,852–53). 

500 Indicated Trade Associations Reply Comments 

at 12. 

501 Indicated Trade Associations Initial 

Comments at 21. 

502NYISO Initial Comments at 5–7. 

503See, e.g., Joint Consumer Advocates Initial 

Comments at 6–8; Joint Customers Reply Comments 

at 1–2; MISO Transmission Owners Initial 

Comments at 12–16. 

504 Generation Developers Initial Comments at 25; 

Reactive Service Providers Initial Comments at 21– 

23. 

505See supra II.B.2. 

506Supra n.508. 

507Supra n.509. 

508See 2005 Staff Report at 69; see also APS, 94 

FERC at 61,080 (‘‘We note that operating a 

generating unit within the proposed [standard 

power factor range] does not affect the generation 

output of a unit.’’). 

509MISO Transmission Owners Initial Comments 

at 13–14 (‘‘When the MISO Transmission Owners 

proposed to eliminate compensation for producing 

reactive power within the deadband, the most 

common protest from generators was that it would 

impact the reliability of the grid. However, such 

claims are not supported by evidence and distract 

from the underlying fact that generators are 

obligated to provide reactive power within the 

deadband whether or not they are compensated for 

it . . . MISO has since experienced no reliability 

issues as a result and generator interconnection 

applications, the first step of a process that ends 

with execution of an interconnection agreement 

that obligates the generator to provide reactive 

power within the deadband, remain high.’’ 

(citations omitted)); PJM IMM Reply Comments at 

5 (‘‘There is no evidence from any of the markets 

where this policy already exists that it has created 

a reliability issue.’’). 

510NOPR, 186 FERC ¶ 61,203 at P 49. 

511 Id. P 16 (citing MISO Rehearing Order, 184 

FERC ¶ 61,022 at P 29); 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 nonsynchronous resources); PJM Interconnection, 

L.L.C., 151 FERC ¶ 61,097 at PP 7, 28 (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). 

512PGE Initial Comments at 5. 

513MISO Transmission Owners Reply Comments 

at 3–7. 

514ACORE Initial Comments at 3–4; Calpine 

Initial Comments at 2; Clean Energy Associations 

Initial Comments at 4–5; Generation Developers 

Initial Comments at 33; EDPR Initial Comments at 

1, 3–4; Elevate Initial Comments at 6; Indicated 

Reactive Power Suppliers Initial Comments at 13– 

167. In response to the reliability 

concerns raised by ISO–NE and NYISO, 

we find that their stated concerns are 

not specific to the proposal being 

adopted in this final determination— 

that is, their arguments are not limited 

to the provision of reactive power 

within the standard power factor 

range—and as a result, we find their 

concerns unpersuasive. ISO–NE and 

NYISO allude generally to reliability 

benefits from reactive power 

compensation over the full range of a 

generating facility’s capability to 

provide reactive power. As such, ISO– 

NE’s and NYISO’s comments appear to 

address the reliability implications of 

eliminating reactive power 

compensation entirely—that is, 

eliminating compensation both within 

and outside of the standard power factor 

range—rather than the narrower focus of 

this final determination, which 

addresses only the provision of reactive 

power within the standard power factor 

range. However, as explained herein, 

the long-existing obligation of 

generating facilities to provide reactive 

power within the standard power range 

in order to reliably interconnect to the 

transmission system remains 

unchanged, as do the rules regarding the 

provision of reactive power outside the 

standard power factor range, which is 

considered a compensable ancillary 

service for transmitting power across the 

transmission system to serve load.499

We also reject arguments about the 

provision of reactive power service 

beyond the requirements of generating 

facilities’ interconnection 

agreements,500 outside of the standard 

power factor range,501 and Elevate’s 

claims about the ESO’s decision to 

double-compensate reactive power 

service in the United Kingdom for 

similar reasons. 

168. We agree with NYISO’s 502 and 

others’ 503 statements about the 

importance of reactive power to 

reliability, including statements of 

dynamic reactive power sources,504 but 

we note that such statements are equally 

true with or without reactive power 

compensation within the standard 

power factor range. Once again, 

requiring transmission customers to 

continue paying for reactive power 

within the standard power factor range 

already required by a generating 

facility’s interconnection agreement is 

not necessary to ensure that generating 

facilities provide reactive power when 

required, as new and existing generating 

facilities are, and will continue to be, 

required to provide reactive power 

within the standard power factor range 

as a condition of obtaining and 

maintaining interconnection.505

169. In response to NEI’s statements 

about the importance of reactive power 

in the 2005 Staff Report,506 and NERC’s 

Essential Reliability Services Task Force 

Measures Framework report,507 we note 

that the 2005 Staff Report also explains 

that ‘‘[i]nvestment that results in 

reactive power capability by generation 

facilities is driven by interconnection 

requirements, historical inertia and 

potential cost recovery for capacity. 

There is little interaction between the 

actual system need or value of reactive 

power capability and its supply by 

independent generation resources.’’ 508

Additionally, to support our finding 

here, we are relying on more recent 

evidence, which indicates that RTOs/ 

ISOs and non-RTO regions that have 

eliminated compensation for reactive 

power capability within the standard 

power factor range are not experiencing 

any adverse reliability impacts due to 

absence of reactive power compensation 

within the standard power factor 

range.509

E. Investment 

170. The NOPR sought 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, generating 

facilities, and whether, and if so, how 

the elimination could otherwise affect 

generating facilities’ business decisions 

in those markets.510 The NOPR also 

noted that in MISO, the Commission 

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.511

1. Comments 

171. PGE argues that the NOPR 

proposal would not have a measurable 

impact on investment decisions.512

MISO Transmission Owners also reject 

the claim that the proposed rule will 

disincentivize investment in new 

generating and storage resources.513

172. However, several commenters 

claim that ending compensation for 

reactive power service in the standard 

power factor range would have a 

negative impact on investment. Many 

commenters claim that such an action 

would be disruptive to generators and/ 

or their investors, who include forecasts 

of such compensation as the basis for 

financing arrangements.514


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14; Indicated Trade Associations Initial Comments 

at 16; Middle River Power Initial Comments at 6; 

NEI Initial Comments at 2, 5–6, 8; NHA Initial 

Comments at 4–5. 

515PJM IMM Initial Comments at 12–13. 

516MISO Transmission Owners Reply Comments 

at 4–6. 

517 Id. at 3. 

518 Id. at 7. 

519 Joint Customers Initial Comments at 20. 

520NEI Initial Comments at 8; Calpine Initial 

Comments at 2; Indicated Reactive Power Suppliers 

Initial Comments at 13; Generation Developers 

Initial Comments at 33–34. 

521PSEG Initial Comments at 4, 20–22 (citing PJM 

Providers Grp. v. FERC, 88 F.4th at 271–72 (quoting 

FCC v. Fox Television Stations, Inc., 556 U.S. at 

515); Ass’n of Oil Pipe Lines v. FERC, 876 F.3d 336, 

342 (D.C. Cir. 2017)). 

522ACORE Initial Comments at 3–4; Indicated 

Reactive Power Suppliers Initial Comments at 14. 

523ACORE Initial Comments at 3–4; Calpine 

Initial Comments at 2. 

524 Indicated Reactive Power Suppliers Initial 

Comments at 13–14. 

525Middle River Power Initial Comments at 6. 

526 Indicated Trade Associations Initial 

Comments at 16. 

527Clean Energy Associations Initial Comments at 

4–5. 

528See, e.g., MISO Transmission Owners Reply 

Comments at 3–4, 5–7; PGE Initial Comments at 5; 

PJM IMM Initial Comments at 12–13. 

529See Cal. Indep. Sys. Operator Corp., 160 FERC 

¶ 61,035 at P 19 (‘‘[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.’’). See also 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.’’); Order No. 842, 162 FERC 

¶ 61,128 (‘‘[T]here are interconnection requirements 

for generating facilities in which the recovery of 

capital costs and operating expenses are not 

necessarily ensured.’’). 

530MISO Transmission Owners Reply Comments 

at 3–4. 

531See, e.g., MISO, 182 FERC ¶ 61,033 at P 55; 

MISO Rehearing Order, 184 FERC ¶ 61,022 at PP 

35–36; see also MISO Transmission Owners Initial 

Comments at 9–10 (‘‘At the same time MISO was 

experiencing a dramatic increase in the amounts 

transmission customers paid for reactive power 

service prior to its elimination of compensation for 

reactive power service within the deadband, SEIA 

highlighted that MISO was one of the two ‘most 

lucrative’ regions for reactive power compensation, 

where generators received millions of dollars in 

compensation for having the capability to produce 

reactive power within the deadband, a capability 

that was already a condition of obtaining 

interconnection.’’ (citations omitted)). 

532MISO Transmission Owners Initial Comments 

at 19. See also Joint Customers Reply Comments at 

Continued 

173. The PJM IMM maintains that: 

There is no evidence that units are built as 

a result of reactive [power] revenue. There is 

no evidence that sources of revenue are not 

fungible and that a decrease in reactive 

[power] revenues could be not replaced with 

other sources of revenue. There is no basis 

for adding new resources to the already very 

crowded interconnection queue solely based 

on out of market subsidies from reactive 

revenues.515

174. Similarly, PGE notes that 

transmission providers that have 

eliminated reactive power 

compensation have not observed a 

decrease in proposed investment.516

MISO Transmission Owners assert that 

Indicated Trade Associations’ claim that 

reactive power revenue streams can 

make the difference in overall 

profitability is unsupported by 

evidence.517 Moreover, MISO 

Transmission Owners argue that 

investors could not reasonably have 

relied on reactive power compensation 

within the standard power factor range 

in perpetuity and should have 

considered the risk of its elimination 

when making investment decisions.518

Similarly, Joint Customers explain that 

to the extent that generators voluntarily 

and unilaterally installed greater 

reactive capability than that required by 

their respective interconnection 

agreements, they did so at their own risk 

and for their own strategies, none of 

which mean that they should continue 

to be compensated for costs that they 

did not have to incur and which do not 

benefit transmission customers.519

175. NEI, Calpine, Indicated Reactive 

Power Suppliers, and Generation 

Developers argue that they relied on the 

Commission’s longstanding precedent 

and policy of allowing compensation for 

reactive power within the standard 

power factor range in making their 

investment decisions and suggest that 

the final determination would be highly 

disruptive to market participants.520

PSEG asserts that the final 

determination represents a significant 

departure from existing Commission 

policy without an adequate 

explanation.521

176. ACORE and Indicated Reactive 

Power Suppliers highlight the costs and 

potential challenges of generators with 

PPAs who may be unable to renegotiate 

those agreements to include costs 

related to reactive power service.522

ACORE and Calpine argue that the 

NOPR proposal would impede project 

development during a period of greater 

need for generation resources.523

Indicated Reactive Power Suppliers 

states that the loss of reactive power 

compensation could lead to generators 

not developing other projects because 

the revenue loss impacts these projects’ 

ability to leverage finite capital based on 

this cash flow reduction.524 Middle 

River Power also claims that the NOPR 

proposal may prompt investors to 

question the reliability and stability of 

other Commission-approved rates and 

markets.525 Indicated Trade 

Associations argue that, given the 

narrow margins for competitive 

generators, small reactive power 

revenue streams can make the difference 

between whether a generator will be 

profitable over its life or not.526

177. Clean Energy Associations argue 

that the proposal is also disruptive to a 

host of interconnection customers with 

operating or near-completed projects 

and extant PPAs.527 Clean Energy 

Associations also argues that the NOPR 

fails to consider IPP projects located in 

PJM with reactive power rates that are 

the result of Commission-approved 

settlements. Clean Energy Associations 

also argues that the Commission has not 

adequately considered the fundamental 

differences between IPP projects and 

projects that are utility-owned. 

2. Commission Determination 

178. Based on the record, we find that 

there is substantial evidence to support 

the conclusion that prohibiting the 

inclusion in transmission rates of 

reactive power rates within the standard 

power factor range will not have a 

significant impact on investment in new 

generating facilities.528

179. First, as stated above, generating 

facilities in CAISO, SPP, MISO, and 

certain non-RTO regions do not receive 

compensation for the provision of 

reactive power within the standard 

power factor range,529 and, as MISO 

Transmission Owners explain,530 there 

is no evidence in the record that: (1) 

these policies have led to an insufficient 

supply of reactive power in those 

regions, or (2) generating facilities in 

these regions have been unable to 

recover any costs associated with the 

provision of such reactive power. 

Because new and existing generating 

facilities are required to provide reactive 

service within the standard power factor 

range as a condition of interconnection, 

eliminating compensation for providing 

that service would not negatively 

impact investment.531

180. Second, we also agree with the 

MISO Transmission Owners, who note 

that because compensation for the 

provision of reactive power within the 

standard power factor range has always 

been based on comparability rather than 

compensability, ‘‘[r]eactive power 

compensation is not a given’’ and that 

‘‘[t]he Commission has consistently 

followed these principles, allowing 

transmission providers across the nation 

to eliminate compensation for reactive 

power service within the deadband.’’ 532


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6–7 (‘‘Additionally, claims that investors made 

decisions relying on the revenue stream associated 

with the capability to provide reactive power 

within the deadband fail to contend with the many 

instances in which the Commission accepted 

transmission providers’ elimination of 

compensation for reactive power within the 

deadband. Sophisticated investors could not 

reasonably have relied on compensation for 

providing reactive power within the deadband in 

perpetuity, but rather should have considered the 

risk of elimination of this revenue stream when 

making investment decisions.’’ (citations omitted)). 

533See BPA Rehearing Order, 125 FERC ¶ 61,273, 

at P 15 & n.24 (‘‘[N]either affiliated nor nonaffiliated generators have an inherent right to any 

compensation for reactive power inside the 

deadband.’’). 

534See Joint Customers Initial Comments at 20 

(‘‘To the extent that generators voluntarily and 

unilaterally installed greater reactive capability 

than that required by their respective 

interconnection agreements, they did so at their 

own risk and for their own strategies, none of which 

mean that they should continue to be compensated 

for costs that they did not have to incur and which 

do not benefit transmission customers.’’). 

535See, e.g., ACORE Initial Comments at 3–4; 

Calpine Initial Comments at 2; Clean Energy 

Associations Initial Comments at 4–5; EDPR Initial 

Comments at 1, 3–4; Elevate Initial Comments at 6; 

Generation Developers Initial Comments at 33; 

Indicated Reactive Power Suppliers Initial 

Comments at 14; Indicated Trade Associations 

Initial Comments at 16; Middle River Power Initial 

Comments at 6; NHA Initial Comments at 4–5. 

536See Clean Energy Associations Initial 

Comments at 5. 

537 Id. 

538See supra II.C.2. 

539 Indicated Trade Associations Initial 

Comments at 16. 

540See supra II.B.2. 

541See supra II.A.2, II.B.2, II.C.2. 

542Solar Energy Indus. Ass’n v. FERC, 80 F.4th 

956, 979 (9th Cir. 2023) (citing Motor Vehicle Mfrs. 

Ass’n of U.S., Inc. v. State Farm Mut. Auto. Ins. Co., 

463 U.S. at 43). 

543Middle River Power Initial Comments at 6. 

544 16 U.S.C. 824e(a) (‘‘Whenever the 

Commission, after a hearing held upon its own 

motion or upon complaint, shall find that any rate, 

charge, or classification, demanded, observed, 

charged, or collected by any public utility for any 

transmission or sale subject to the jurisdiction of 

the Commission, or that any rule, regulation, 

practice, or contract affecting such rate, charge, or 

classification is unjust, unreasonable, unduly 

discriminatory or preferential, the Commission 

shall determine the just and reasonable rate, charge, 

classification, rule, regulation, practice, or contract 

to be thereafter observed and in force, and shall fix 

the same by order.’’). 

545PJM IMM Reply Comments at 6 (‘‘Such attacks 

on the rules and standards can be disregarded 

because they are collateral attacks on final rules and 

standards that are not within the scope of this 

proceeding. Reactive Service Providers arguments 

challenging longstanding Commission policy and 

multiple Commission orders are also beside the 

point.’’). 

546 Joint Consumer Advocates Initial Comments at 

8 (‘‘[S]ection 206 of the FPA requires that the 

Commission act to eliminate unjust and 

unreasonable rates where and when it finds them. 

There is no statutory authorization to allow an 

unjust and unreasonable rate to continue.’’) 

547 Joint Customers Reply Comments, Reply 

Affidavit of Dr. Albert W. Bremser at 4:1–3 (‘‘My 

second conclusion is that permanent reliance on 

[Commission]-jurisdictional practices as never 

changing is not consistent with the typical 

experience of [Commission]-jurisdictional entities 

and ratepayers.’’; id. at 10:2–6 (‘‘In terms of reliance 

on Commission past practices or what the 

Commission has allowed, it is my experience that 

the Commission can and does change its practices 

and what it allows. This can impact the rates 

charged to ratepayers and the rates collected by 

companies.’’). 

548See, e.g., Indep. Mkt. Monitor for PJM v. PJM 

Interconnection, L.L.C., 176 FERC ¶ 61,137 (2021); 

order on reh’g, 178 FERC ¶ 61,121 (2022). 

As previously noted, developers have 

been on notice since at least Order No. 

2003 and Order No. 2003–A that 

reactive power is not compensable 

within the standard power factor range 

(other than for comparability reasons), 

and so could not have relied, reasonably 

or otherwise, on the permanence of such 

compensation for investment 

purposes.533

181. Third, to the extent that 

generating facilities may have incurred 

costs by increasing their generating 

facilities’ reactive power capabilities 

beyond the requirements of their 

interconnection agreements, we find 

that it is unreasonable to charge 

transmission customers for these costs 

as they were not required for 

interconnection and do not fit within 

the least justifiable cost to customers.534

Further, as noted herein, this final 

determination does not address 

compensation for reactive power 

provided outside of the standard power 

factor range, which will continue to be 

compensable. 

182. Fourth and finally, as discussed 

herein and further below, generating 

facilities have other opportunities to 

recover any de minimis variable costs of 

providing reactive power within the 

standard power factor range, and this 

final determination establishes a 

transition mechanism to give RTOs/ 

ISOs time to adjust their market rules to 

ensure that generating facilities 

continue to have such other 

opportunities after this final 

determination. 

183. Some commenters expressed 

general concerns about generating 

facilities and investors relying on 

reactive power revenues for planning 

purposes,535 including concerns of 

interconnection customers with nearcompleted or operating projects, and 

extant PPAs,536 as well as with IPP 

projects located in PJM with reactive 

power rates that are the result of 

Commission-approved settlements.537

However, we reiterate that in this final 

determination 538 we have rejected any 

reliance arguments, reasoning in part 

that the provision of reactive power 

within the standard power factor range 

requires no incremental investment or 

fixed costs and at most de minimis 

incremental variable costs. 

184. Relatedly, Indicated Trade 

Associations 539 argue that narrow profit 

margins mean that the loss of reactive 

power revenues could tip generating 

facilities out of profitability. We 

reiterate our finding above that the 

variable and incremental costs of 

providing reactive power within the 

standard power factor range requires no 

or at most a de minimis increase in 

variable costs beyond the cost of 

providing real power 540 and that 

generating facilities can recover any de 

minimis variable costs through other 

means. Additionally, no commenter 

provided any evidence that the loss of 

reactive power compensation would 

make a project that was otherwise 

profitable, unprofitable. 

185. Further, we disagree with PSEG’s 

assertions that the NOPR represents a 

significant departure from existing 

Commission policy without an adequate 

explanation and refer PSEG to the 

evidence and reasoning presented 

herein that we are relying upon in this 

final determination.541 Consequently, 

we are revising the pro forma Schedule 

2, pro forma LGIA, and pro forma 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. As courts 

of appeals have articulated on several 

occasions, ‘‘[t]he APA does not require 

‘regulatory agencies [to] establish rules 

of conduct to last forever,’ ’’ but rather, 

‘‘agencies may ‘adapt their rules and 

policies to the demands of changing 

circumstances.’ ’’ 542

186. Similarly, in response to Middle 

River Power’s 543 claims about the 

reliability and stability of other 

Commission-approved rates and 

markets, we note when the Commission 

finds that a rate is unjust and 

unreasonable, as we do here, the 

Commission has not only the right but 

the obligation under section 206 of the 

FPA to modify that rate in order to 

ensure it is just and reasonable.544 As 

the PJM IMM,545 Joint Consumer 

Advocates,546 and Dr. Bremser,547 note 

the Commission has previously changed 

compensation policies when it has 

determined that existing practices were 

resulting in unjust and unreasonable 

rates.548

F. Additional Comments 

1. Comments 

187. Ameren asserts that it was the 

right decision to eliminate 

compensation for reactive power 


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549Ameren Initial Comments at 5 (citing Docket 

Nos. ER21–1046, ER21–2329, ER21–2695, ER21– 

2892, ER22–526, ER22–616, ER22–615, ER22–1554, 

ER22–1610, ER22–1815). 

550NHA Initial Comments at 6–7. 

551 Indicated Trade Associations Initial 

Comments at 32. 

552 Id. at 1, 7. 

553 Id. at 5–6. 

554 Glenvale Initial Comments at 8. 

555Clean Energy Associations Initial Comments at 

9–10. 

556Reactive Service Providers Initial Comments at 

24–29. 

557 Id. at 35–36. 

558Clean Energy Associations Initial Comments at 

2–3. 

559ACORE Initial Comments at 4. 

560 Joint Customers Initial Comments at 7–11. 

561Liberty Initial Comments at 1. 

562Middle River Power Initial Comments at 5. 

563NEI Initial Comments at 5. 

564 Id. at 11. 

565TAPS Initial Comments at 4. 

capability in MISO, as evident by the 

numerous reactive power cases in 

which Ameren intervened from 2018– 

2022 that were set for hearing and 

settlement judge procedures, with 

resulting revenue requirements reduced 

substantially from what the filing 

generator proposed, and in some cases 

by over 50%.549

188. The NHA asserts that individual 

RTOs/ISOs should develop and/or 

improve upon reactive power capability 

compensation market rules to reflect 

locational requirements.550

189. Indicated Trade Associations 

request that the Commission clarify that 

the NOPR will not be applied in 

determining refunds in cases where the 

Commission has established settlement 

and hearing judge proceedings for 

reactive rates.551

190. Indicated Trade Associations 

argue that the Commission should not 

implement the NOPR proposal.552

Indicated Trade Associations assert that 

the NOPR is not supported by the NOI 

record, which they argue was focused 

on changes and improvements to the 

methodology used to determine 

appropriate reactive power 

compensation, rather than the NOPR’s 

proposal to eliminate reactive power 

compensation within the standard 

power factor range altogether.553

191. Glenvale avows that some 

generators provide reactive power 

within the power factor range but 

outside of the requirements of their 

interconnection agreements, such as 

solar generators that are not 

synchronized to the transmission 

system but still provide reactive power 

service.554

192. Clean Energy Associations also 

proposes their own reactive power 

compensation format in which the 

Commission would develop a new, 

objective, cost-based, technology-neutral 

rate for reactive power to encourage the 

proliferation of reactive power resources 

in a non-discriminatory way.555

193. Reactive Service Providers also 

argue that a ± 0.95 standard power 

factor range is arbitrary. As support, 

they claim that it is not NERCmandated, that many generating 

facilities are not actually satisfying it, 

and that ‘‘it is in essence a mandate to 

create headroom if and when it is 

needed by the Transmission 

Provider.’’ 556 Reactive Service 

Providers argue that there is no 

difference operationally between 

operating within and outside the 

standard power factor range because 

that distinction does not reflect the 

operational realities of an integrated 

transmission system, where the 

transmission provider is ‘‘balancing all 

resources instantaneously such that all 

load everywhere benefits.’’ 557

194. Clean Energy Associations asks 

that, should the Commission proceed 

with its proposal, that the Commission 

should clarify that interconnection 

agreements cannot adopt a standard 

power factor range other than 0.95 

leading and lagging and specify that 

compensation must be provided for 

reactive power provided outside of the 

range.558

195. ACORE recommends that instead 

of removing all compensation within 

the standard power factor range, a costbased, technology-neutral rate be 

established for reactive power, with a 

focus on reducing the administrative 

burdens of the AEP Methodology.559

196. Joint Customers highlight the 

burdens associated with the 

individualized review of reactive rate 

filings arguing that it leads to higher 

costs for customers without 

corresponding benefits and that the 

case-by-case approach using the AEP 

Methodology is resource-intensive and 

results in inconsistent outcomes.560

197. Liberty states that it believes the 

current methodology has resulted in 

ambiguity on cost formation and could 

lead to unjust rates for customers.561

Liberty explains that it would generally 

support a cost recovery methodology 

change that results in reasonable rates 

for customers that are not duplicative in 

nature, in line with industry standards, 

and sufficiently compensates reactive 

power capability services. 

198. Middle River Power argues that 

the AEP Methodology has consistently 

produced just and reasonable rates for 

Middle River Power-affiliated 

generation and others and that if 

administrative burden were a problem 

that must be remedied, the solution 

would be to reform the administrative 

process by which just and reasonable 

rates are determined.562

199. NEI suggests that the 

Commission should continue to support 

the AEP Methodology.563 NEI notes that 

while there are implementation 

challenges to the AEP Methodology, as 

highlighted by NEI previously, such 

process-related concerns do not render 

it unjust and unreasonable.564

200. TAPS argues that the AEP 

Methodology that many generators use 

in their reactive power compensation 

filings, and which was derived many 

years ago for synchronous generators, is 

not well-suited for non-synchronous 

generators to which the methodology is 

now being applied.565 For example, 

TAPS explains that TAPS members 

have found it very difficult to verify the 

inputs to the AEP Methodology for a 

specific generator based on publicly 

available data, because many generators 

seeking compensation do not submit a 

FERC Form No. 1. 

2. Commission Determination 

201. We appreciate the concerns 

raised by numerous commenters 

requesting that we undertake various 

initiatives, as set forth above. However, 

we find that the requested initiatives go 

beyond the scope of this rulemaking, 

which addresses only compensation for 

reactive power service within the 

standard power factor range. 

Accordingly, we will not address those 

concerns here. 

III. Compliance Procedures 

A. Revisions To Eliminate 

Compensation for Reactive Power 

Supply Within the Standard Power 

Factor Range 

202. To effectuate the changes 

discussed herein, we are taking the 

following four actions. 

1. Revise Schedule 2 of the 

Commission’s Pro Forma OATT 

203. We revise Schedule 2 of the 

Commission’s pro forma OATT to 

include 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 

revision prohibits separate 

compensation for the provision of 

reactive power within the standard 

power factor range specified in an 

interconnection agreement. 


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566See Order No. 888, FERC Stats. & Regs. 

¶ 31,036 at 31,760–63. 

567See Order No. 2003, 104 FERC ¶ 61,103 at PP 

822–27; Order No. 2006, 111 FERC ¶ 61,220 at PP 

546–50). 

568See Order No. 888, FERC Stats. & Regs. 

¶ 31,036 at 31,760–63; Order No. 2003, 104 FERC 

¶ 61,103 at PP 822–27; Order No. 2006, 111 FERC 

¶ 61,220 at PP 546–50). 

569NOPR, 186 FERC ¶ 61,203 at P 54. 

570 Id. P 56. 

571 Id. 

572 Id. 

573See PGE Initial Comments at 5; TAPS Initial 

Comments at 8; PGE Initial Comments at 5. 

574MISO Transmission Owners Initial Comments 

at 17–19. 

575 Id. at 2. 

576 Joint Customers Reply Comments at 7–8 

(citing PNM, 178 FERC ¶ 61,088 at P 32; MISO, 182 

FERC ¶ 61,033 at P 67; MISO Rehearing Order, 184 

FERC ¶ 61,022 at PP 32–33.) 

577 Joint Customers Initial Comments at 18–21. 

578PGE Initial Comments at 5. 

2. Revise Section 9.6.3 of the Pro Forma 

Large Generator Interconnection 

Agreement 

204. We 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 

prohibits 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 

205. We similarly are revising 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.’’ 

4. Compliance Procedures 

206. To effectuate these changes, we 

require each transmission provider to 

submit a compliance filing as discussed 

below to make changes to their 

Schedule 2s or other OATT provisions 

relating to charges and payments for 

reactive power, as well as to their pro 

forma LGIAs and pro forma SGIAs in 

their OATTs. To the extent that any 

transmission provider believes that it 

already complies with the reforms 

adopted in this final determination, the 

transmission provider is required to 

demonstrate how it complies in the 

compliance filing required 60 days after 

the effective date of the final 

determination. In reviewing compliance 

filings proposed by non-RTO/ISO 

transmission providers, the Commission 

will apply the ‘‘consistent with or 

superior to’’ standard to deviations from 

the adopted pro forma Schedule 2 566

and to deviations from the pro forma 

LGIA and pro forma SGIA.567 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.568

B. Transition Period 

207. In the NOPR, the Commission 

proposed to require each transmission 

provider to submit a compliance filing 

within 60 days of the effective date of 

the final determination. The 

Commission further proposed to allow 

90 days from the date of the compliance 

filing for implementation of the 

proposed reforms to become 

effective.569 The NOPR sought comment 

on whether a transition period beyond 

the 90-day implementation period 

proposed was necessary and for what 

duration any transition period should 

last.570 Specifically, the NOPR asked if 

any factors, such as potential business 

or investment impacts, should be 

considered in determining whether any 

transition period is appropriate and 

what transition mechanisms other than 

delaying the implementation date of the 

final determination would minimize 

such disruptions. 

208. The NOPR also sought comment 

on whether existing generating facilities 

that have previously received 

compensation for reactive power 

capability should be allowed to 

continue to receive compensation for a 

limited period, as an interim rate during 

a transition period, while prohibiting 

new generating facilities from receiving 

reactive power capability 

compensation.571 The NOPR asks how it 

should determine eligibility for 

continued compensation. 

209. In addition, for regions that have 

an established capacity market, the 

NOPR sought comment on whether 

transmission providers should be 

allowed to make the implementation of 

their compliance filing align with the 

region’s capacity market timelines to 

allow costs associated with reactive 

power production, if any, to be 

incorporated into capacity market 

bids.572 For regions without a capacity 

market, the NOPR sought comment on 

whether a different transition 

mechanism, if any, would be necessary 

and whether it would be unduly 

discriminatory or preferential to set 

different implementation dates for the 

final determination in different markets 

and regions. 

1. Comments 

210. Several commenters who support 

the NOPR assert that no transition 

beyond the 90-day transition period in 

the NOPR is necessary.573 MISO 

Transmission Owners urge the 

Commission to neither provide a 

transition period nor compensate 

generators that previously received 

reactive power compensation for a 

limited period.574 MISO Transmission 

Owners urge the Commission to adopt 

the NOPR’s proposed rule to be effective 

immediately.575 While Joint Customers 

oppose a transition period, citing 

Commission policy and precedent,576

they state that only a brief transition 

period, if any, is necessary for the 

implementation of the NOPR reforms.577

211. PGE states that it does not 

believe the decision to implement these 

provisions in the 90-day 

implementation period will have a 

measurable impact on business or 

investment decisions.578

212. Joint Customers and MISO 

Transmission Owners suggest that 


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579 Joint Customers Reply Comments at 9–10; 

MISO Transmission Owners Initial Comments at 

18–19 (noting that generating facilities have been on 

notice of the prospect of the elimination of reactive 

power compensation since Order No. 2003 and 

reminded of it routinely since then). 

580 Joint Customers Initial Comments at 21. 

581MISO Transmission Owners Initial Comments 

at 18–19. 

582 Id.; TAPS Initial Comments at 8. 

583MISO Transmission Owners Initial Comments 

at 18 (citing MISO, 182 FERC ¶ 61,033 at P 67; 

MISO Rehearing Order, 184 FERC ¶ 61,022 at P 55 

n.186 (rejecting an argument that the Commission 

should have declined to waive the 60-day notice 

requirement)). 

584 Id.at 17–18. 

585 Id. at 19. 

586TAPS Initial Comments at 8. 

587 Id. 

588 Joint Customers Reply Comments at 8. 

589Calpine Initial Comments at 2–3. 

590 Indicated Trade Associations Initial 

Comments at 29–30. 

591 Indicated Reactive Power Suppliers Initial 

Comments at 2; Glenvale Initial Comments at 6–7. 

592Middle River Power Initial Comments at 6–7 

(citing Indicated Energy Trade Associations Initial 

Comments at 24; PJM Interconnection, L.L.C., 110 

FERC ¶ 61,053, at P 61, order on reh’g, 112 FERC 

¶ 61,031 (2005) (finding it appropriate to 

grandfather units for which construction 

commenced in reliance on a prior rule), order on 

reh’g, 114 FERC ¶ 61,302 (2006); Tenn. Gas Pipeline 

Co., 62 FERC ¶ 61,062 (1993) (explaining that, the 

Commission had decided to ‘‘grandfather’’ prior 

storage arrangements ‘‘in light of the fact that . . . 

historical customers have already made their 

conversion elections in reliance on access to this 

storage’’)). 

593Reactive Service Providers Initial Comments at 

67–76. 

594 Generation Developers Initial Comments at 

33–34. 

595EDPR Initial Comments at 5. 

596Eagle Creek Initial Comments at 5. 

597Reactive Service Providers Initial Comments at 

75–76. 

598 Indicated Reactive Power Suppliers Initial 

Comments at 2–3. 

599AEP Initial Comments at 7–8. 

600ACORE Initial Comments at 4. 

601Calpine Initial Comments at 4. 

602AEP Initial Comments at 7–8 (citing PJM 

Interconnection, L.L.C., 117 FERC ¶ 61,331, at P 73 

(2006) (‘‘The adoption of a transition period must 

strike a reasonable balance between the need to 

implement RPM to generate relevant prices, and the 

provision of some period to enable parties to 

understand and make adjustments to the new 

market.’’), order on reh’g, 119 FERC ¶ 61,318 (2007); 

Midcontinent Independent System Operator, 180 

FERC ¶ 61,141, at PP 248–249 (2022) (‘‘The 

transition period appropriately balances the need to 

implement the SAC methodology with the 

recognition that resource owners and LSEs may 

need to adjust their operations—including outage 

timing—and their contractual arrangements to 

maximize their potential SAC values.’’); PJM 

Interconnection, L.L.C., 155 FERC ¶ 61,157, at PP 

150–151 (2016) (accepting a phase-in of PJM’s 

capacity performance requirements as just and 

reasonable because the benefits of providing 

relevant entities adequate time to adjust Fixed 

Resource Requirement plans based on the new rules 

were weighed in conjunction with the interest in 

applying the requirements in an even-handed 

manner)). 

603EDPR Initial Comments at 3–4. 

generators should have made business 

or investment decisions in anticipation 

of the potential elimination of reactive 

power within the standard power factor 

range.579 Joint Customers explain that 

the move towards these reforms has 

been ongoing for years, providing ample 

time for market participants to adjust 

their investment strategies.580 Similarly, 

MISO Transmission Owners assert that 

generators have been on notice of the 

prospect of the elimination of reactive 

power since Order No. 2003 and 

reminded of it routinely since then.581

213. MISO Transmission Owners and 

TAPS both oppose a transition period so 

that reduced rate relief can be provided 

to customers.582 MISO Transmission 

Owners emphasize that the Commission 

found that by eliminating compensation 

for reactive power within the standard 

power factor range MISO would ‘‘reduce 

charges to MISO’s transmission 

customers.’’ 583 MISO Transmission 

Owners further state that the 

Commission should not compensate 

generators that previously received 

reactive power compensation for a 

limited period for such reasons.584

MISO Transmission Owners add that, 

under the current compensation 

scheme, generating facilities are able to 

‘‘gold-plate their reactive capabilities to 

the detriment of ratepayers,’’ so the 

Commission ‘‘should refrain from 

imposing any transition period or 

vintaging carve-outs that allow 

capability-based compensation to 

continue.’’ 585 TAPS claims that 

customers, including TAPS members, 

have been harmed by excessive reactive 

power compensation thus far and 

accompanying inefficient, 

administratively burdensome, case-bycase determinations.586 Therefore, TAPS 

argues against a transition period 

because generators should no longer 

benefit from currently unjust and 

unreasonable rates.587 Likewise, Joint 

Customers noted the Commission has 

previously rejected the continuation of 

compensation beyond the tariff effective 

date.588

214. Calpine and Indicated Trade 

Associations oppose the NOPR proposal 

and request that if the Commission were 

to move forward, the Commission 

exempt existing resources, applying the 

proposed reforms only to new resources. 

Calpine reasons that the Commission 

exempted existing resources from new 

requirements in Order Nos. 827 and 842 

and that exemptions would support 

market stability and investments needed 

for reliability.589 Indicated Trade 

Associations further assert that in 

addition to existing resources, the 

exemption should also be allowed for 

resources in advanced stages of 

development.590 Indicated Reactive 

Power Suppliers state that Commissionapproved cost-based tariffs should last 

the remaining life, transfer of 

ownership, or expiration of PPAs for 

existing resources.591 Middle River 

Power requests that the Commission 

consider implementing a legacy rate 

provision for generators that have 

existing reactive rate tariffs to mitigate 

adverse impacts on its current 

investments and contends that the 

Commission has a history of adopting 

similar measures under similar 

circumstances.592 Reactive Service 

Providers state that the Commission 

should consider grandfathering the 

agreements of existing or nearcompletion generating facilities.593

Generation Developers argue that the 

Commission should not eliminate 

reactive power compensation for 

resources receiving compensation 

pursuant to a rate schedule or tariff in 

effect prior to the effective date of any 

final determination in this 

proceeding.594 EDPR also proposes that 

facilities which have already concluded 

long-term PPAs but do not yet have an 

established rate be allowed to prove that 

the long-term PPA for a facility seeking 

reactive power compensation was 

executed prior to the issuance of the 

NOPR.595

215. In absence of an exemption for 

existing resources, or grandfathering of 

existing rates and generator agreements, 

commenters who oppose the proposal 

advocate for a transition period to 

comply with the final determination. 

Eagle Creek 596 recommends a transition 

period of at least three to five years, 

Reactive Service Providers 597 a period 

of five years, and Indicated Reactive 

Power Suppliers 598 a period of seven to 

ten years respectively. Other 

commenters who ask for a transition 

period include AEP, requesting at least 

120 days,599 and ACORE, requesting a 

five to ten-year transition period.600

Calpine 601 and AEP 602 both expressed 

concerns of affected generators’ ability 

to recover their costs as justification for 

a transition period and cite times that 

the Commission has approved of a 

transition period in the past. 

216. EDPR proposes a 10-year 

transition period for existing rates and 

PPAs. EDPR explains that it will under 

collect its revenues under PPAs that 

include an offset for reactive power 

compensation.603 Therefore, EDPR 

proposes that facilities with an 

established reactive rate schedule 

should be allowed to keep that 

established rate on file during a 10-year 

transition period. Similarly, Reactive 

Service Providers argue that the 


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604 Indicated Reactive Power Suppliers Initial 

Comments at 2. 

605 Glenvale Initial Comments at 5. 

606 Id. 

607NHA Initial Comments at 9–10. 

608 Generation Developers Initial Comments at 35. 

609NAGF Initial Comments at 2. 

610Clean Energy Associations Initial Comments at 

2–3, 9–10. 

611 Indicated Trade Associations Initial 

Comments at 14–15. 

612Reactive Service Providers Initial Comments at 

57. 

613NYISO Initial Comments at 9–10. 

614PJM Initial Comments at 6. 

615NAGF Initial Comments at 3. 

616PJM Initial Comments at 4–6. 

617 Id. (requesting that ‘‘transmission providers in 

regions with centralized capacity markets such as 

PJM be permitted flexibility to propose effective 

dates on compliance that will align with applicable 

capacity market and billing and settlements 

timelines’’ to ‘‘allow costs associated with reactive 

power production to be incorporated into capacity 

market bids, and also ensure alignment with 

applicable billing and settlements dates.’’) 

618Calpine Initial Comments at 4 & n.7 (noting 

that the Commission has recently approved a 

transition period associated with PJM’s 

implementation of generator interconnection 

reforms (citing PJM Interconnection, L.L.C., 181 

FERC ¶ 61,162, at PP 8, 60 (2022))); PJM Initial 

Comments at 4–6 (explaining that a transition 

period could be ‘‘to permit generators who are 

currently receiving reactive power revenues under 

Tariff, Schedule 2 to continue to do so until the 

Delivery Year of the first Base Residual Auction 

(‘‘BRA’’) where the removal of these reactive 

revenues from the Energy and Ancillary Services 

(‘‘E&AS’’) offset can be reflected in the auction 

parameters. This concept would be based on the 

idea that these generators submitted their bids in 

prior auctions without the knowledge that Tariff, 

Schedule 2 revenues would no longer exist, which 

may have impacted the bids they ultimately 

submitted.’’). 

619NAGF Initial Comments at 3. 

620PJM Initial Comments at 4–6. 

621PJM IMM Initial Comments at 14. 

622PJM IMM Initial Comments at 15 (‘‘Given the 

schedule for upcoming capacity market auctions in 

PJM, the timing for the transition will be a direct 

result of the effective date of a final determination. 

Given this schedule, there will be a significant lag 

before the Offset can be removed for an identified 

delivery year. For example, if the effective date of 

the final determination were March 1, 2025, the 

Offset could be eliminated and payments under 

Schedule 2 eliminated effective June 1, 2027, the 

start of the delivery year for the base residual 

auction scheduled to be run in June 2025.’’). 

623 Id. 

Commission should allow PPAs to be 

reevaluated.604

217. Glenvale requests that if cost 

recovery is not possible for certain 

projects, the run-off for legacy projects 

be extended to 10 years. Glenvale 

explains that eligible projects would be 

those which are unable to access 

revenue in the substitute market 

designated by the Commission, and 

reasonably rely on the current tariff.605

Glenvale claims that an extension 

would motivate these generators to 

build technologies that both support the 

transmission system and are a low cost 

to consumers.606

218. Several commenters argue that a 

transition period is necessary for RTOs/ 

ISOs to implement the NOPR. The NHA 

explains that a transition period would 

allow RTOs/ISOs to adjust their tariffs 

and market designs accordingly.607

Generation Developers assert that the 

Commission should direct RTOs/ISOs to 

propose a transition period that 

accounts for discrepancies between 

implementation of any market rule 

changes and when resources will be 

able to benefit from these changes.608

Similarly, NAGF states that a transition 

period specific to each market based on 

their design and rules allows generators 

to evaluate lost revenue, cost recovery 

options, and the possibility of retiring, 

all while also providing time for 

planners to contemplate other 

generation options.609 Clean Energy 

Associations ask that the Commission, 

should it proceed with its proposal, 

implement a transition period that takes 

into consideration regional and market 

differences.610 Additionally, Indicated 

Trade Associations state that PJM, ISO– 

NE, and NYISO each currently subtract 

expected energy and ancillary services 

revenues, including reactive power 

revenues, from the Net CONE value 

used to develop demand curves for 

capacity market auctions.611 Relatedly, 

Reactive Service Providers explain that 

PJM, ISO–NE, and NYISO have 

completed capacity auctions and 

assigned capacity obligations for years 

from now and that the Commission 

cannot reopen those auctions to make 

up for lost revenue.612

219. NYISO notes that shifting to 

event-specific reactive power 

compensation only when a resource is 

instructed to operate outside its 

standard power factor range would 

require complex market design rules— 

including developing market rules, 

incorporating reactive power into the 

NYISO’s co-optimization of real power 

(i.e., energy to meet load), operating 

reserves, and regulation service which 

would require extensive software 

changes that would take years to 

develop and implement based on 

current obligations and initiatives.613

PJM requests that as part of their 

compliance filings implementing the 

new rate paradigm, RTOs/ISOs be 

permitted to propose rules around 

testing, monitoring, and penalties. PJM 

argues that this is to ensure that 

generators provide the reactive power 

capability that they are required to 

provide under their Commissionjurisdictional interconnection 

agreements when called upon, as 

correctly identified in the NOPR.614

220. NAGF 615 and PJM 616 both 

propose allowing transmission 

providers the flexibility to propose 

effective dates on compliance that will 

align with regional capacity market 

timelines. PJM further notes that 

compliance dates should align with 

billing and settlements timelines as 

well.617 In a similar manner, Calpine 

suggests that in PJM, any new reactive 

service compensation policy should 

take effect no sooner than the first 

delivery year of the first PJM capacity 

auction administered under 

comprehensively updated new rules.618

NAGF explains that alignment with 

capacity market timelines would allow 

costs associated with reactive power 

production to be incorporated into 

capacity market bids if the capacity 

market reforms permit recovery and to 

allow generators to better evaluate their 

cost recovery process and probability.619

Likewise, PJM argues that such timeline 

alignments will permit generators 

currently receiving reactive power 

revenues to continue to do so until the 

related offsets are removed from the 

capacity market auction parameters.620

221. The PJM IMM recommends a 

transition period as short as possible, 

emphasizing that a faster transition will 

speed up benefits to customers and 

reduced revenues to generation 

owners.621 The PJM IMM recommends 

reducing current approved rates under 

Schedule 2 that exceed the E&AS Offset 

to the level of the E&AS Offset that was 

applicable to the auctions for each RPM 

Delivery Year. The PJM IMM also 

suggests that pending reactive filings 

submitted prior to the NOPR proposal 

should not be approved exceeding the 

same aforementioned level of the E&AS 

Offset. The PJM IMM proposes that the 

E&AS Offset be reduced to zero dollars 

and removed from the rules 

immediately. As for Schedule 2 to the 

PJM OATT, the PJM IMM believes it 

should be revised to immediately 

remove the ability to file for new 

reactive capability rates and then 

eliminated in its entirety effective at the 

start of the first Delivery Year where the 

E&AS Offset included in the capacity 

market base residual auctions for such 

Delivery Year is zero dollars.622

222. The PJM IMM makes similar 

recommendations if PJM eliminates the 

E&AS Offset as a component of the 

market seller offer caps in the capacity 

market prior to the end of the proposed 

transition period: (1) that the E&AS 

Offset be reduced to zero dollars and 

removed from the rules immediately; (2) 

that Schedule 2 be eliminated from the 

OATT.623


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624PJM Initial Comments at 4–6. 

625NOPR, 186 FERC ¶ 61,203 at P 54. 

626Any RTO/ISO that proposes an effective date 

longer than 90 days from the date of the compliance 

filing must include an indeterminate 12/31/9998 

effective date in eTariff with their compliance filing 

and must provide the Commission with an estimate 

of when the changes will become effective and must 

make a filing with the Commission if they are 

unable to meet their estimated effective date. 

Further, the RTO/ISO must also notify the 

Commission at least 7 days prior to the effective 

date of their proposed changes so that Commission 

staff may make the required changes in eTariff. 

627PJM Initial Comments at 7. 

628 Generation Developers Initial Comments at 

34–35 (‘‘Additionally, as part of any compliance 

filings submitted in response to a final rule in this 

proceeding, the Commission should require RTOs 

and [ISOs] to make revisions to their tariffs 

eliminating existing barriers to the recovery of 

reactive power costs through sales of other 

products. This would include, for instance, 

requiring RTOs/ISOs with organized capacity 

markets to revise their tariffs to permit resources to 

accurately reflect their investment in reactive power 

in their capacity offers. The Commission also 

should require RTOs/ISOs to revise their market 

power mitigation frameworks to permit generation 

resources to reflect reactive power costs in their 

cost-based energy curves.’’). 

629See, e.g., PJM IMM Reply Comments at 5 

(‘‘When buyers and sellers enter into power 

purchase agreements, the contracting parties define 

and assign regulatory risk. Customers are not 

responsible to manage or pay for suppliers’ risks.’’). 

630See, e.g., Nev Power Co., 179 FERC ¶ 61,103; 

PNM, 178 FERC ¶ 61,088 at PP 26–36; SPP, 119 

FERC ¶ 61,199 at PP 20, 30–33. 

631Calpine Initial Comments at 2–3; EDPR Initial 

Comments at 5; Generation Developers Initial 

Comments at 33–34; Glenvale Initial Comments at 

6–7; Indicated Trade Associations Initial Comments 

at 29–30; Middle River Power Initial Comments at 

6–7; Reactive Service Providers Initial Comments at 

67–76. 

632See Dynegy Midwest Generation, Inc. v. FERC, 

633 F.3d 1122. 

633See, e.g., Reactive Service Providers Initial 

Comments at 67–76 (citing Order No. 2003, 104 

FERC ¶ 61,103; Order No. 661, 111 FERC ¶ 61,353; 

Order No. 827, 155 FERC ¶ 61,277; Order No. 2023, 

184 FERC ¶ 61,054; Cal. Indep. Sys. Op., 124 FERC 

¶ 61,031, at PP 12, 13, 20 (2008); Midcontinent 

Independent System Operator, Inc., 158 FERC 

¶ 61,003, at PP 44, 45, 59 (2017); Sw. Power Pool, 

Inc., 167 FERC ¶ 61,275, at P 19 (2019)) (noting that 

‘‘[i]t is common for the Commission to allow 

grandfathering of existing agreements and rate 

Continued 

223. PJM states that it would like 

flexibility to implement an interim rate 

during the transition period.624 PJM 

notes that it contemplates a number of 

different scenarios, including 

disallowing any units without existing 

reactive power rate schedules to collect 

reactive power revenue or an interim 

flat rate per MVAr of capability. 

2. Commission Determination 

224. For all transmission providers in 

an RTO/ISO or non-RTO/ISO region, we 

direct a compliance filing within 60 

days of the effective date of the final 

determination, including a proposed 

effective date within 90 days from the 

date of the compliance filing, as 

proposed by the NOPR.625 We find that 

the NOPR’s proposal to only allow 90 

days from the date of the compliance 

filing for implementation of the 

proposed reforms to become effective is 

appropriate. However, in recognition of 

the concerns raised by commenters with 

respect to the interplay between existing 

reactive power revenue compensation 

mechanisms and energy and capacity 

market rules in ISO–NE, NYISO, and 

PJM, we will permit those RTOs/ISOs to 

each request a later effective date,626 for 

the Commission’s consideration, in 

order to allow them to develop and 

propose any changes to their market 

rules that may be necessary in order to 

accommodate this final determination’s 

elimination of compensation for the 

provision of reactive power within the 

standard power factor range. With any 

such request, the RTO/ISO must 

affirmatively demonstrate why such a 

requested effective date is necessary, 

given, for example, its existing market 

rules, and what market rule changes the 

RTO/ISO believes may be needed to 

accommodate this final determination. 

We find that this approach reasonably 

balances concerns about expediently 

addressing unjust and unreasonable 

transmission rates for reactive power 

with concerns raised by commenters 

about existing cost recovery rules in the 

organized markets and will ensure that 

the ability of generating facilities to seek 

any appropriate cost recovery will not 

be impeded. 

225. This flexibility would 

accommodate the potential section 205 

filings that some RTOs/ISOs mentioned 

may accompany any final determination 

compliance filings, such as PJM’s 

adjustments to market rules to remove 

the offset in auction parameters as well 

as ‘‘propose rules around testing, 

monitoring, and penalties, to ensure that 

generators actually provide the reactive 

power capability that they are required 

to provide under their Commissionjurisdictional interconnection 

agreements when called upon.’’ 627 The 

Commission welcomes these and 

similar section 205 filings to adapt 

markets to accommodate the final 

determination as well as to clarify each 

RTO’s/ISO’s compensation scheme for 

reactive power service outside of the 

standard power factor range, if 

necessary.628

226. We decline to adopt a transition 

period in non-RTO/ISO regions beyond 

the 90-day implementation period 

proposed in the NOPR. Some generating 

facilities in non-RTO/ISO regions 

contend that the compliance period 

should extend until the termination of 

existing PPAs or request that we require 

all PPAs to be reevaluated to cover the 

foregone revenue. As explained above, 

the record lacks any concrete evidence 

showing whether, and to what extent, 

generating facilities factored reactive 

power revenues into their PPAs. And 

even if a generating facility were able to 

demonstrate that eliminating 

compensation under our rule might 

impact some generating facility’s 

profitability, which they have not, we 

do not believe that potential disrupted 

expectations weigh in favor of a 

different outcome in this situation. As a 

general matter, the risk of regulatory 

change is inherent in any long-term 

PPA.629 Moreover, as explained above, 

we are skeptical of any purported 

reliance interests given that generating 

facilities have not had an inherent right 

to separate compensation for reactive 

power capability within the standard 

power factor range since Order Nos. 

2003 and 2003–A (i.e., because such 

compensation is required only to ensure 

‘‘comparability’’). Finally, developers 

and generating facilities have been on 

notice since at least 2003 that the 

Commission regards reactive power 

compensation within the standard 

power factor range as non-compensable 

(other than where the comparability 

standard applies)—a conclusion that 

was patent in those orders, and 

reinforced repeatedly in subsequent 

Commission orders accepting 

transmission owner filings under 

section 205 that eliminated reactive 

power compensation within the 

standard power factor range.630

227. We disagree with commenters 

who request that generating facilities 

with reactive rates on file prior to the 

effective date of the final determination 

be provided legacy treatment.631 Given 

that the Commission finds above 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, it would raise undue 

discrimination concerns to continue to 

provide payment through Schedule 2 for 

reactive power supply within the 

standard power factor range to 

generating facilities with rates already 

on file when those rates have been 

found to be unjust and unreasonable.632

Although commenters point to other 

situations where the Commission has 

provided legacy treatment for existing 

rates, in those situations the existing 

rate had not been found to be unjust and 

unreasonable.633


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schedules when making sweeping industry 

changes,’’ that the Commission ‘‘has long 

implemented new Tariff rules in view of the 

economic impact to late-stage projects,’’ and 

‘‘woven throughout each transition period ordered 

by the [Commission] is a need to carefully balance 

interests and preserve the expectations of the 

parties’’)); Indicated Trade Associations Initial 

Comments at 29–30 (citing PJM Interconnection, 

L.L.C., 110 FERC ¶ 61,053 at P 61; Tenn. Gas 

Pipeline Co., 62 FERC at 61,306) (noting that when 

the Commission eliminated an exemption from 

market power mitigation, the Commission provided 

legacy treatment for units that commenced 

construction in reliance of the rule)). 

634 ‘‘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. 

635Commission staff estimates that the 

respondents’ skill set (and wages and benefits) for 

Docket No. RM22–2–000 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 fulltime employee), $100/hour is used. 

IV. Information Collection Statement 

228. 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. 

229. This final determination will 

amend the Commission’s regulations 

pursuant to section 206 of the FPA, 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 pro 

forma LGIA, the pro forma SGIA, and 

Schedule 2 in its OATT to implement 

the reforms proposed in this final 

determination. Such filings should be 

made under Part 35 of the Commission’s 

regulations. Subsequently, the final 

determination 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]. 

230. 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 accepted 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. 

231. 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: oira_submission@omb.eop.gov. 

Comments submitted to OMB should 

refer to OMB Control No. 1902–0303, 

1902–0096, or 1902–0203. 

232. Please submit a copy of your 

comments on the information collection 

to the Commission via the eFiling link 

on the Commission’s website at https:// 

www.ferc.gov. 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. 

233. 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]. 

234. Action: Revision of the 

information collection in accordance 

with Docket No. RM22–2–000. 

235. OMB Control No.: 1902–0303, 

1902–0096, 1902–0203 

236. Respondents for this 

Rulemaking: Public utility transmission 

providers, including RTOs/ISOs. 

237. Frequency of Information 

Collection: One-time compliance filing. 

238. Necessity of Information: The 

final determination will require that 

transmission providers submit to the 

Commission a one-time compliance 

filing proposing tariff revisions. 

239. 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. 

240. Public Reporting Burden: The 

Commission’s estimate consists of our 

estimated effort related to updating the 

proposed revisions to the pro forma 

OATT, and subsequent revisions to the 

pro forma LGIA and pro forma SGIA, 

and the effort related to submitting a 

one-time compliance filing. 

241. The Commission estimates 

burden 634 and cost 635 as follows: 

A. 

Collection 

B. 

Number of 

respondents 

C. 

Annual 

number of 

responses per 

respondent 

D. 

Total 

number of 

responses 

E. 

Average 

burden 

Hrs. & 

cost per 

response 

F. 

Total annual 

Hr. burdens & 

total annual cost 

G. 

Cost per 

respondent 

(Column B × Column C) (Column D × Column 

E) 

(Column F ÷ Column B) 

FERC 516H: Pro Forma Open Access Transmission Tariff 

Transmission Providers (Schedule 2 one-time compliance filing).40 1 40 4 hrs.; $400 .......... 160 hrs.; $16,000 ....... $400 

FERC 516: Electric Tariff Filings 

Transmission Providers (pro forma LGIA one-time 

compliance filing).

43 1 43 4 hrs.; $400 .......... 172 hrs.; $17,200 ....... 400 


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636Reguls. Implementing the Nat’l Env’t Pol’y 

Act, Order No. 486, 52 FR 47897 (Dec. 17, 1987), 

FERC Stats. & Regs. Preambles 1986–1990 ¶ 30,783 

(1987) (cross-referenced at 41 FERC ¶ 61,284). 637 18 CFR 380.4(a)(15). 

638 5 U.S.C. 601–612. 

639 13 CFR 121.201. 

640The 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). 

641NERC, NCR Active Entities List, (Jan. 12, 

2024), NERC_Compliance_Registry_Matrix_

Excel.xlsx. 

642U.S. Small Business Administration, A Guide 

for Government Agencies How to Comply with the 

Regulatory Flexibility Act, 18 (Aug. 2017), https:// 

cdn.advocacy.sba.gov/wp-content/uploads/2019/ 

06/21110349/How-to-Comply-with-the-RFA.pdf. 

A. 

Collection 

B. 

Number of 

respondents 

C. 

Annual 

number of 

responses per 

respondent 

D. 

Total 

number of 

responses 

E. 

Average 

burden 

Hrs. & 

cost per 

response 

F. 

Total annual 

Hr. burdens & 

total annual cost 

G. 

Cost per 

respondent 

(Column B × Column C) (Column D × Column 

E) 

(Column F ÷ Column B) 

FERC 516A: Standardization of Small Generator Interconnection Agreements and Procedures 

Transmission Providers (pro forma SGIA one-time 

compliance filing).

43 1 43 4 hrs.; $400 .......... 172 hrs.; $17,200 ....... 400 

Totals .................................................................. ...................... .......................... ...................... ............................... 504 hrs.; $50,400 ....... ......................

V. Environmental Analysis 

242. 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.636 We conclude that 

neither an Environmental Assessment 

nor an Environmental Impact Statement 

is required for this final determination 

under § 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.637

VI. Regulatory Flexibility Act 

243. The Regulatory Flexibility Act of 

1980 (RFA) 638 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,639 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).640

244. We estimate that there are 43 

transmission providers that are affected 

by the reforms proposed in this final 

determination, based on the NERC 

Active Compliance Registry Matrix as of 

January 11, 2024.641 The Commission 

used a combination of sources to 

determine the number of employees 

within each entity using open-source 

data and information provided by Dunn 

& Bradstreet. We estimate that 6 of the 

43 transmission providers, 

approximately 14% (rounded), are small 

entities. 

245. We estimate that one-time costs 

(in Year 1) associated with the reforms 

proposed in this final determination for 

one transmission provider (as shown in 

the table above) would be $1,200 to 

submit the compliance filing. Following 

Year 1, the Commission estimates no 

ongoing costs associated with this final 

determination. 

246. 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.’’ 642 We do not consider the 

estimated cost of $1,200 to be a 

significant economic impact for any of 

the entities that would be impacted by 

this final determination. As a result, we 

certify that the reforms proposed in this 

final determination would not have a 

significant economic impact on a 

substantial number of small entities. 

VII. Document Availability 

247. 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). 

248. 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. 

249. 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 

ferconlinesupport@ferc.gov, or the 

Public Reference Room at (202) 502– 

8371, TTY (202)502–8659. Email the 

Public Reference Room at 

public.referenceroom@ferc.gov. 

VIII. Effective Date and Congressional 

Notification 

250. These regulations are effective 

January 27, 2025. The Commission has 

determined, with the concurrence of the 

Administrator of the Office of 

Information and Regulatory Affairs of 

OMB, that this rule is not a ‘‘major rule’’ 

as defined in section 351 of the Small 

Business Regulatory Enforcement 

Fairness Act of 1996. 

By the Commission. Commissioner Chang 

is not participating. 

Issued: October 17, 2024 

Debbie-Anne A. Reese, 

Secretary. 

Note: The following appendices will not 

appear in the Code of Federal Regulations. 

Appendix A: Abbreviated Names of 

Commenters 


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Abbreviation Commenter(s) 

ACORE ........................................................ American Council on Renewable Energy. 

AEP .............................................................. American Electric Power Service Corporation. 

Ameren ........................................................ Ameren Service Company. 

Calpine ......................................................... Calpine Corporation. 

Clean Energy Associations ......................... Solar Energy Industries Association (SEIA) and American Clean Power Association. 

C T Gaunt .................................................... Dr. Charles Trevor Gaunt. 

Eagle Creek ................................................. Eagle Creek Reactive Generators. 

EDPR ........................................................... EDP Renewables North America LLC. 

Elevate ......................................................... Elevate Renewables F7, LLC. 

Generation Developers ................................ Vistra Corp. and Dynegy Marketing and Trade, LLC. 

Glenvale ....................................................... Glenvale LLC. 

IPPNY .......................................................... Independent Power Producers of New York, Inc. 

Indicated Reactive Power Suppliers ........... KMC Thermo, LLC, Bitter Ridge Wind Farm, LLC, Guernsey Power Station LLC, Moxie Freedom 

LLC, Safe Harbor Water Power Corporation, BIF III Holtwood LLC, Brookfield Power Piney & 

Deep Creek LLC, Erie Boulevard Hydropower, L.P., Carr Street Generating Station, L.P., Bear 

Swamp Power Company LLC, Brookfield White Pine Hydro LLC, Brookfield Renewable Trading 

and Marketing LP, and Reworld Waste, LLC f/k/a Covanta. 

Indicated Trade Associations ...................... Electric Power Supply Association, The PJM Power Providers Group the New England Power Generators Association, Inc., Independent Power Producers of New York, Inc., the Coalition of Midwest Power Producers. 

ISO–NE ........................................................ ISO New England Inc. 

Joint Consumer Advocates ......................... Illinois Attorney General, Illinois Citizens Utility Board, Maryland Office of People’s Counsel, the 

New Jersey Division of Rate Counsel, the North Carolina Utilities Commission Public Staff, the 

Office of the People’s Counsel for the District of Columbia, and the West Virginia Consumer Advocate Division of the Public Service Commission. 

Joint Customers ........................................... Old Dominion Electric Cooperative, Northern Virginia Electric Cooperative, Inc., and Dominion Energy Services, Inc. on behalf of Virginia Electric and Power Company d/b/a Dominion Energy Virginia. 

Liberty .......................................................... Liberty Utilities. 

Middle River Power ..................................... Middle River Power LLC. 

MISO ............................................................ Midcontinent Independent System Operator, Inc. 

MISO Transmission Owners ....................... Ameren Services Company, as agent for Union Electric Company d/b/a Ameren Missouri, Ameren 

Illinois Company d/b/a Ameren Illinois, and Ameren Transmission Company of Illinois; Arkansas 

Electric Cooperative Corporation; City Water, Light & Power; Cooperative Energy; Dairyland 

Power Cooperative; East Texas Electric Cooperative; Entergy Arkansas, LLC; Entergy Louisiana, 

LLC; Entergy Mississippi, LLC; Entergy Texas, Inc.; Great River Energy; Indianapolis Power & 

Light Company; Lafayette Utilities System; MidAmerican Energy Company; Minnesota Power 

(and its subsidiary Superior Water, L&P); Missouri River Energy Services; Montana-Dakota Utilities Co.; Northern States Power Company, a Minnesota corporation, and Northern States Power 

Company, a Wisconsin corporation, subsidiaries of Xcel Energy Inc.; Northwestern Wisconsin 

Electric Company; Otter Tail Power Company; Prairie Power, Inc.; Southern Indiana Gas & Electric Company (d/b/a CenterPoint Energy Indiana South); and Southern Minnesota Municipal 

Power Agency. 

NAGF ........................................................... North American Generator Forum. 

NEPGA ........................................................ New England Power Generators Association, Inc. 

NEPOOL ...................................................... New England Power Pool. 

NESCOE ...................................................... New England States Committee on Electricity. 

New England Consumer Advocates ........... Office of Massachusetts Attorney General Andrea Joy Campbell, the Connecticut Office of Consumer Counsel, the Maine Office of Public Advocate, the New Hampshire Office of Consumer 

Advocate, and the Rhode Island Division of Public Utilities and Carriers 

NEI ............................................................... Nuclear Energy Institute. 

NYISO .......................................................... New York Independent System Operator, Inc. 

NHA ............................................................. National Hydropower Association. 

Ohio FEA ..................................................... Ohio Office of the Federal Energy Advocate of the Public Utilities Commission of Ohio. 

Onward Energy ............................................ Onward Energy Holdings, LLC. 

PGE ............................................................. Portland General Electric Company. 

PJM .............................................................. PJM Interconnection, L.L.C. 

PJM IMM ..................................................... Monitoring Analytics, LLC, acting in its capacity as the Independent Market Monitor for PJM. 

PSEG ........................................................... Public Service Electric and Gas Company, PSEG Power LLC, and PSEG Energy Resources & 

Trade LLC, and each wholly-owned, direct or indirect subsidiaries of Public Service Enterprise 

Group Incorporated. 

Reactive Service Providers ......................... CIP, D. E. Shaw Renewable Investments, L.L.C., Invenergy Renewables LLC, Leeward Renewable 

Energy, LLC, Lightsource Renewable Energy Operations, LLC, NextEra Energy Resources, 

LLC,1 ;rsted Wind Power North America, LLC, and RWE Clean Energy, LLC. 

TAPS ........................................................... Transmission Access Policy Study Group. 

[FR Doc. 2024–24528 Filed 11–25–24; 8:45 am] 

BILLING CODE 6717–01–P 


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