# Compensation for Reactive Power Within the Standard Power Factor Range > Briefs, arguments, decisions, and more. URL: https://www.frixlaw.com/law-library/documents/fr%3A2024-24528 ## Record - **Collection:** Federal Register - **Document type:** Rule - **Published:** November 26, 2024 - **Citation:** 89 FR 93410 ## Text 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 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. 1 Section 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 Non-Discriminatory 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). 2 Operating “inside the standard power factor range” refers to a generating facility providing reactive power within the power factor range set forth in the generating facility's interconnection agreement when the unit is online and synchronized to the transmission system. 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). 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. 3 MVAr is the typical unit of measurement for reactive power. 4 A generating facility's leading reactive power indicates its ability to absorb reactive power, and its lagging reactive power indicates its ability to produce reactive power. 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 Order No. 888, FERC Stats. & Regs. ¶ 31,036, at 31,705-07 & n.359. 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 Id. at 31,720. 7 Id. at 31,707 & n.359. 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 8 Id. at 31,705-07 & n.359. 9 Standardization of Generator Interconnection Agreements & Procs., Order No. 2003, 68 FR 49846 (Aug. 19, 2003), 104 FERC ¶ 61,103, at P 546 (2003), order on reh'g, Order No. 2003-A, 69 FR 15932 (Mar. 26, 2004), 106 FERC ¶ 61,220, order on reh'g, Order No. 2003-B, 70 FR 265 (Jan. 4, 2005), 109 FERC ¶ 61,287 (2004), order on reh'g, Order No. 2003-C, 70 FR 37661 (June 30, 2005), 111 FERC ¶ 61,401 (2005), aff'd sub nom. Nat'l Ass'n of Regul. Util. Comm'rs v. FERC, 475 F.3d 1277 (D.C. Cir. 2007). 10 The 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. 11 Order No. 2003, 104 FERC ¶ 61,103 at P 546. 12 Order 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), 113 FERC ¶ 61,195 (2005), order granting clarification, Order No. 2006-B, 71 FR 42587 (July 27, 2006), 116 FERC ¶ 61,046 (2006). 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. 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). 15 Order No. 2006, 111 FERC ¶ 61,220. 16 Order No. 827, 155 FERC ¶ 61,277. 17 See 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). 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. 18 Bonneville Power Admin. v. Puget Sound Energy, Inc., 120 FERC ¶ 61,211 (2007) ( BPA ), order denying reh'g and granting clarification, 125 FERC ¶ 61,273, at P 18 (2008) (BPA Rehearing Order). 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.”). 19 MISO Rehearing Order, 184 FERC ¶ 61,022 at P 23. 20 See, e.g., id. at PP 23-24 (citing METC Rehearing Order, 97 FERC at 61,852-53). 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 21 See, 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). 22 BPA, 120 FERC ¶ 61,211 at PP 19-20; BPA Rehearing Order, 125 FERC ¶ 61,273 at PP 10-11. 23 BPA, 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.”). 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 24 Id. PP 19-22. 25 Id. P 21 (citing Sw. Power Pool, Inc., 119 FERC ¶ 61,199, at P 39). 26 Id. 11. The Commission made similar findings in MISO, wherein it accepted an FPA section 205 application by Midcontinent Independent System Operator, Inc. (MISO) transmission owners to end generator compensation for the provision of reactive power within the standard power factor range. 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 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. 29 Synchronous generating facilities ( e.g., coal, gas, nuclear resources) produce electricity in sync with the transmission system at the system frequency. Non-synchronous generating facilities ( e.g., solar, wind, battery storage resources) produce electricity that is initially not in sync with the transmission system and use inverters to convert their electrical output to synchronize with the transmission system. See FERC, 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. 30 MISO Rehearing Order, 184 FERC ¶ 61,022 at PP 29-30 (citing S. Co. Servs., Inc., 80 FERC ¶ 61,318, at 62,091 (1997) (noting also that the primary function of a generating plant is to produce real power; thus, if costs were allocated based on the “predominant” function of the equipment, “all of the costs of generation would thus be assigned to real power production and there would be no basis for any separate reactive power charge”); BPA, 120 FERC ¶ 61,211 at P 21 (finding that the incremental cost of reactive power service within the standard power factor range is minimal); METC 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.”). 31 MISO 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.”). 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 32 See, 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. 13. Of the six Commission-jurisdictional RTOs/ISOs, only three currently compensate generating facilities for reactive power provided within the standard power factor range. Generating facilities in PJM Interconnection, L.L.C. (PJM) 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 33 PJM Interconnection, L.L.C., Intra-PJM Tariffs, OATT Schedule 2, (Reactive Supply and Voltage Control from Generation or Other Sources Service) (4.0.0). 34 The AEP Methodology derives its name from Opinion No. 440, where the Commission approved AEP's, a vertically integrated utility, method for calculating the costs of synchronous generation equipment associated with the production of reactive power. See Am. Elec. Power Serv. Corp., Opinion No. 440, 88 FERC ¶ 61,141 (1999), order on reh'g, 92 FERC ¶ 61,001 (2000). In WPS Westwood, the Commission recommended that all generating facilities that have actual cost data and support documentation use the AEP Methodology. See WPS Westwood Generation, LLC, 101 FERC ¶ 61,290, at P 14 (2002). 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). 36 New York Independent System Operator, Inc., NYISO Tariffs, NYISO OATT, § 6.2 OATT Schedule 2 (Charges For Voltage Support Service) (6.0.0). 37 Both ISO-NE and NYISO proposed their respective reactive power capability compensation mechanisms pursuant to section 205 filings. See ISO New England Inc., 122 FERC ¶ 61,056, at P 1 (2008) (settling, in part, for a new flat rate in $/kVAR-yr). 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). 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. 38 CAISO never provided compensation for reactive power within the standard power factor range. See Cal. Indep. Sys. Operator Corp., 160 FERC ¶ 61,035, at P 7 (2017) (explaining that CAISO considered the possibility of compensating generating facilities for reactive power in its stakeholder process, but decided against it, reasoning that the ability to provide reactive power is part of a generator's fixed costs, which are recovered through power purchase agreements). 39 SPP, 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. 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 non-RTO/ISO transmission providers do not pay separately for reactive power provided within the standard power factor range. 41 41 See, e.g., Arizona Public Service Company, FERC Electric Tariff Vol. No. 2, Schedule 2 (Reactive Supply and Voltage Control from Generation or Other Sources Service) (6.0.0) (“This service will be provided at no charge until [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.”). 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 42 Reactive Power Capability Compensation, Notice of Inquiry, 177 FERC ¶ 61,118 (2021) (NOI). 43 Id. P 19. 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. 44 Real power, which accomplishes useful work ( e.g., runs motors), is typically measured in MWs. 45 16 U.S.C. 824e. 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.” 46 See pro forma OATT, Schedule 2. 47 See pro forma LGIA, § 9.6.3. 48 See pro forma SGIA, § 1.8.2. 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 49 See app. A. 50 C 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. 51 American 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. 52 The 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 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 Ørsted 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. 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 53 Order 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.”). 54 Regional Transmission Orgs., Order No. 2000, FERC Stats. & Regs. ¶ 31,089 (1999) (cross-referenced 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). 55 See, 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”). 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-of-service proceedings further undermine the principle of comparability as some generating facilities now receive substantially higher rates for the provision of reactive power within the standard power factor range than others. 58 56 See 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?”). 57 When 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. 58 The 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. 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 59 See, 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-MST-Schedule-2-VSS-Rates-FINAL-for-posting.pdf/f59317b0-41c6-9f41-5d61-e7f502af82c2 ); 2023 Annual Markets Report at 154, iso-ne.com/static-assets/documents/100011/2023-annual-markets-report.pdf. 60 See Order No. 2003-C, 111 FERC ¶ 61,401 at P 42 (finding that because providing reactive power within the established range is an “important service,” payment for such service does not constitute a “windfall”). 61 PJM 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)). 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 power-related 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-of-service 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 62 NOPR, 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. 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 69 Id. P 42. 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 70 AEP 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. 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 not be receiving commensurate reliability benefits. 73 71 See, 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. 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. 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 non-affiliate 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 74 Joint Customers Reply Comments at 10-11. 75 Id. at 11 (emphasis in original). 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 76 PJM Initial Comments at 1-3. 77 MISO Initial Comments at 2. 78 Id. 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 79 MISO Transmission Owners Initial Comments at 5. 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 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. 81 See, 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)). 82 See, 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.”). 83 TAPS 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)). 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 85 AEP 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.”). 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 87 AEP Initial Comments at 4-5. 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 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 88 New 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.”). 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 89 PJM IMM Reply Comments at 1-2. 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 90 Clean Energy Associations Initial Comments at 2-3; Indicated Trade Associations Reply Comments at 16; NEI Initial Comments at 1. 91 Reactive 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. 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 96 Id. at 76-77. 97 Id. at 77. 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 98 Indicated Trade Associations Reply Comments at 16-17. 99 Id. at 8-9. 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, resource-specific 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. 104 100 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 . 103 NEPOOL Reply Comments at 6-7. 104 Id. at 6-7. 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 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. 110 105 NYISO Initial Comments at 1. 106 Id. at 2; IPPNY Reply Comments at 1-2. 107 NYISO Initial Comments at 2-5. 108 Id. at 7-8. 109 Id. at 7-8. 110 Id. at 14. 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. 114 111 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)). 113 PSEG 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.”)). 114 PSEG Initial Comments at 19-20 (citing Ameren Servs. Co. v. FERC, 880 F.3d 571, 581-82 (D.C. Cir. 2018)). 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.” 118 115 MISO 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)). 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.” 122 119 Eagle Creek Initial Comments at 4; NHA Initial Comments at 8-9. 120 Eagle Creek Initial Comments at 4; NHA Initial Comments at 8. 121 Eagle Creek Initial Comments at 4-5; NHA Initial Comments at 8. 122 NHA Initial Comments at 8-9; see also Eagle Creek Initial Comments at 4-5. 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. 124 123 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 third-party 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.”). 48. Reactive Service Providers and Generation Developers argue that the NOPR violates the D.C. Circuit's holding 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. 126 125 Atl. 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. 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. 127 NOPR, 186 FERC ¶ 61,203 at PP 24-27, 28. 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.” 129 128 See, 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. 129 See, 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/ ). 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 long-standing 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 non-synchronous 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. 137 130 See 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). 131 A joint cost is an expenditure that benefits more than one product, and for which it is not possible to separate the contribution to each product. 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. 132 See 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.”). 133 See, 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. 134 Although 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. 135 Under 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.”). 136 Panda 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.”). 137 See 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). 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 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. 138 See, 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”). 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. 143 139 New 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.”). 140 See, 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.”). 141 See 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. 143 See, 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)). 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. 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.”). 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 collateral attacks on our prior determinations and unpersuasive. 145 145 MISO 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.”). 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. 148 146 See, 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.”). 147 See, 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). 148 NOPR, 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.”). 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. 149 See 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.”). 150 MISO 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. 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 Mobile-Sierra doctrine establishes a more rigorous application of the just and reasonable standard when the Commission proposes to change an individual contract negotiated at arms-length, 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. 154 151 Eagle Creek Initial Comments at 4; NHA Initial Comments at 8-9. 152 The 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 Mobile-Sierra 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). 153 See, 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-and-reasonable standard.”). 154 Cf. 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)). 60. As discussed above, the final determination requires revisions to 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. 156 155 See 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 third-party generators with no further action required.”). 156 For 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. 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 non-affiliated, 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. 158 157 Generation Developers Initial Comments at 31-32 (citing Atl. City, 295 F.3d at 9-10); Reactive Service Providers Initial Comments at 54. 158 Cf. 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). 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. 161 159 NOPR, 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. 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 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. 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 [Text truncated at 120,000 characters. The full text is on the page linked above.] --- Source: Frix Law Library, https://www.frixlaw.com/law-library/documents/fr%3A2024-24528. Public record. Not legal advice.