Compensation for Reactive Power Within the Standard Power Factor Range, 21454-21468 [2024-06556]

Download as PDF 21454 Federal Register / Vol. 89, No. 61 / Thursday, March 28, 2024 / Proposed Rules (4) You may view this material at the FAA, Airworthiness Products Section, Operational Safety Branch, 2200 South 216th St., Des Moines, WA. For information on the availability of this material at the FAA, call 206–231–3195. (5) You may view this material at the National Archives and Records Administration (NARA). For information on the availability of this material at NARA, visit www.archives.gov/federal-register/cfr/ ibr-locations, or email fr.inspection@ nara.gov. Issued on March 21, 2024. Victor Wicklund, Deputy Director, Compliance & Airworthiness Division, Aircraft Certification Service. [FR Doc. 2024–06520 Filed 3–27–24; 8:45 am] BILLING CODE 4910–13–P DEPARTMENT OF ENERGY Federal Energy Regulatory Commission 18 CFR Part 35 [Docket No. RM22–2–000] Compensation for Reactive Power Within the Standard Power Factor Range Federal Energy Regulatory Commission, Department of Energy. AGENCY: ACTION: Notice of proposed rulemaking. The Federal Energy Regulatory Commission (Commission) proposes to revise Schedule 2 of its pro forma open-access transmission tariff (pro forma OATT), section 9.6.3 of its pro forma large generator interconnection agreement (LGIA), and section 1.8.2 of its pro forma small generator interconnection agreement (SGIA) to prohibit the inclusion in transmission rates of unjust and unreasonable charges related to the provision of reactive power within the standard power factor range by generating facilities. The Commission invites all interested persons to submit comments on the proposed reforms and in response to specific questions. DATES: Comments are due May 28, 2024. Reply comments are due June 26, 2024. ADDRESSES: Comments, identified by docket number, may be filed in the following ways. Electronic filing through https://www.ferc.gov is preferred. • Electronic Filing: Documents must be filed in acceptable native applications and print-to-PDF, but not in scanned or picture format. • For those unable to file electronically, comments may be filed SUMMARY: by USPS mail or by hand (including courier) delivery. Æ Mail via U.S. Postal Service Only: Addressed to: Federal Energy Regulatory Commission, Secretary of the Commission, 888 First Street NE, Washington, DC 20426. Æ Hand (including courier) delivery: Deliver to: Federal Energy Regulatory Commission, 12225 Wilkins Avenue, Rockville, MD 20852. The Comment Procedures section of this document contains more detailed filing procedures. FOR FURTHER INFORMATION CONTACT: Noah Schlosser (Technical Information), Office of Energy Market Regulation, 888 First Street NE, Washington, DC 20426, (202) 502–8356, Noah.Schlosser@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. ddrumheller on DSK120RN23PROD with PROPOSALS1 I. Introduction ............................................................................................................................................................................................. II. Background ............................................................................................................................................................................................ A. What is reactive power? ................................................................................................................................................................ B. How has reactive power been compensated? .............................................................................................................................. C. Notice of Inquiry ............................................................................................................................................................................. III. Discussion ............................................................................................................................................................................................ A. Need for Reform ............................................................................................................................................................................ 1. Compensation for Providing Reactive Power Within the Standard Power Factor Range May Be Unjust and Unreasonable ..... 2. Adverse Impacts of the Commission’s Current Reactive Power Compensation Policy ................................................................ B. Proposed Reform ........................................................................................................................................................................... 1. Eliminating Separate Compensation Will Not Affect Reliability ..................................................................................................... 2. Eliminating Separate Compensation Does Not Preclude Generating Facilities From Recovering Their Costs ........................... C. Proposed Revisions for Eliminating Compensation for Reactive Power Supply Within the Standard Power Factor Range ...... 1. Revise Schedule 2 of the Pro Forma OATT .................................................................................................................................. 2. Revise Section 9.6.3 of the Pro Forma Large Generator Interconnection Agreement ................................................................. 3. Revise Section 1.8.2 of the Pro Forma Small Generator Interconnection Agreement ................................................................. IV. Proposed Compliance Procedures ...................................................................................................................................................... V. Information Collection Statement .......................................................................................................................................................... VI. Environmental Analysis ........................................................................................................................................................................ VII. Regulatory Flexibility Act Certification ................................................................................................................................................ VIII. Comment Procedures ........................................................................................................................................................................ IX. Document Availability ........................................................................................................................................................................... I. Introduction 1. The Commission is proposing to revise Schedule 2 of its pro forma OATT to prohibit transmission providers from including in their transmission rates any charges associated with the supply of reactive power within the standard VerDate Sep<11>2014 17:37 Mar 27, 2024 Jkt 262001 power factor range 1 from generating facilities. We further propose to remove from the pro forma LGIA and pro forma 1 Operating ‘‘inside the standard power factor range’’ refers to a generating facility providing reactive power within the power factor range set forth in the generating facility’s interconnection agreement when the unit is online and synchronized to the transmission system. PO 00000 Frm 00014 Fmt 4702 Sfmt 4702 1 10 10 12 20 24 24 28 34 41 43 45 50 51 52 53 54 57 71 72 76 79 SGIA the requirement that a transmission provider pay an interconnection customer for reactive power within the standard power factor range if the transmission provider pays its own or affiliated generators for the same service. Accordingly, transmission providers would be required to pay an interconnection customer for reactive E:\FR\FM\28MRP1.SGM 28MRP1 Federal Register / Vol. 89, No. 61 / Thursday, March 28, 2024 / Proposed Rules ddrumheller on DSK120RN23PROD with PROPOSALS1 power only when the transmission provider asks the interconnection customer to operate its facility outside the standard power factor range set forth in its interconnection agreement. 2. The Commission’s policy on reactive power compensation has evolved since issuing Order No. 888 in 1996.2 In Order No. 888, the Commission required that reactive supply and voltage control from generating facilities be offered as a discrete ancillary service by transmission providers and, to the extent feasible, charged for on the basis of the amount required. The Commission explained that there are two ways of supplying reactive power and controlling voltage. One is to install facilities as part of the transmission system, the cost of which is part of the cost of basic transmission service. The second is to use generating facilities to supply reactive power and voltage control, which must be unbundled from basic transmission service. 3. With respect to compensation, the Commission stated that the transmission provider’s ‘‘rates for ancillary services should be cost-based.’’ 3 The Commission expected, however, that transmission customers would be in a position to change the amount of reactive power service they required. The Commission also identified the possibility that reactive power could potentially someday be supplied by ‘‘a competitive market for such service’’ if ‘‘technology or industry changes’’ made such a market possible. 4. Then, in Order No. 2003, the Commission specifically addressed the circumstances and manner in which a transmission provider must pay for reactive power, inside and outside the standard power factor range (sometimes referred to as the ‘‘deadband’’).4 In 2 Promoting Wholesale Competition Through Open Access Non-Discriminatory Transmission Servs. by Pub. Utils.; Recovery of Stranded Costs by Pub. Utils. & Transmitting Utils., Order No. 888, 61 FR 21540 (May 10, 1996), FERC Stats. & Regs. ¶ 31,036, at 31,705–07 & n.359 (1996) (crossreferenced at 75 FERC ¶ 61,080), order on reh’g, Order No. 888–A, 62 FR 12274 (Mar. 14, 1997), FERC Stats. & Regs. ¶ 31,048 (cross-referenced at 78 FERC ¶ 61,220), order on reh’g, Order No. 888–B, 81 FERC ¶ 61,248 (1997), order on reh’g, Order No. 888–C, 82 FERC ¶ 61,046 (1998), aff’d in relevant part sub nom. Transmission Access Pol’y Study Grp. v. FERC, 225 F.3d 667 (D.C. Cir. 2000), aff’d sub nom. N. Y. v. FERC, 535 U.S. 1 (2002). 3 Id. at 31,720. 4 Standardization of Generator Interconnection Agreements & Procs., Order No. 2003, 68 FR 49846 (Aug. 19, 2003), 104 FERC ¶ 61,103, at P 546 (2003), order on reh’g, Order No. 2003–A, 69 FR 15932 (Mar. 26, 2004), 106 FERC ¶ 61,220, order on reh’g, Order No. 2003–B, 70 FR 265 (Jan. 4, 2005), 109 FERC ¶ 61,287 (2004), order on reh’g, Order No. 2003–C, 70 FR 37661 (June 30, 2005), 111 FERC ¶ 61,401 (2005), aff’d sub nom. Nat’l Ass’n of Regul. VerDate Sep<11>2014 17:37 Mar 27, 2024 Jkt 262001 Order No. 2003, the Commission adopted a standard agreement for the interconnection of large generating facilities (the pro forma LGIA), which included the requirement that interconnection customers maintain a composite power delivery at continuous rated power output at the point of interconnection at a power factor within the range of 0.95 leading to 0.95 lagging 5 when synchronized to the transmission system, unless the transmission provider has established a different power factor range. Order No. 2003 required that a transmission provider compensate an interconnection customer for the provision of reactive power when the transmission provider requests the interconnection customer to operate its generating facility outside the established power factor range. With respect to reactive power within the established power factor range, the Commission initially concluded that the interconnection customer should not be compensated for reactive power when operating within the range established in the interconnection agreement because doing so ‘‘is only meeting [the generating facility’s] obligation.’’ 6 But in Order No. 2003–A, the Commission clarified that ‘‘if the Transmission Provider pays its own or its affiliated generators for reactive power within the established range, it must also pay the Interconnection Customer.’’ 7 This Util. Comm’rs v. FERC, 475 F.3d 1277 (D.C. Cir. 2007). 5 A generating facility’s leading reactive power indicates its ability to absorb reactive power and its lagging reactive power indicates its ability to produce reactive power. 6 Order No. 2003, 104 FERC ¶ 61,103 at P 546 (‘‘We agree that the Interconnection Customer should not be compensated for reactive power when operating its Generating Facility within the established power factor range, since it is only meeting its obligation.’’). 7 Order No. 2003–A, 106 FERC ¶ 61,220 at P 416. Section 9.6.3 of the pro forma LGIA provided as follows: Transmission Provider is required to pay Interconnection Customer for reactive power that Interconnection Customer provides or absorbs from the Large Generating Facility when Transmission Provider requests Interconnection Customer to operate its Large Generating Facility outside the range specified in Article 9.6.1, provided that if Transmission Provider pays its own or affiliated generators for reactive power service within the specified range, it must also pay Interconnection Customer. Similarly, section 1.8.2 of the pro forma SGIA provided as follows: The Transmission Provider is required to pay the Interconnection Customer for reactive power that the Interconnection Customer provides or absorbs from the Small Generating Facility when the Transmission Provider requests the Interconnection Customer to operate its Small Generating Facility outside the range specified in article 1.8.1. In addition, if the Transmission Provider pays its own or affiliated generators for reactive power service within the specified range, it must also pay the Interconnection Customer. PO 00000 Frm 00015 Fmt 4702 Sfmt 4702 21455 standard is generally referred to as the comparability standard. 5. In sum, ‘‘Order Nos. 2003 and 2003–A establish a reactive power compensation policy that, in the first instance, treats the provision of reactive power inside the [standard power factor range] as an obligation of good utility practice rather than as a compensable service and permits compensation inside the [standard power factor range] only as a function of comparability.’’ 8 The Commission took this approach because, where the generating facility is operating within the standard power factor range, it is doing no more than meeting its obligation as a generator, as specified in its interconnection agreement, to maintain the appropriate power factor required to maintain voltage levels for electric power injected into the transmission system during normal operations.9 By comparison, reactive power provided outside of the standard power factor range is considered an ancillary service for transmitting power across the transmission system to serve load,10 and thus, the Commission has required compensation for such service. 6. The Commission has also recognized that there is little to no incremental capital expenditure associated with the equipment necessary for the production of reactive power within the standard power factor range. That is because, for both synchronous and non-synchronous generating facilities,11 the same equipment is used for the production of real power and reactive power.12 In 8 Bonneville Power Admin. v. Puget Sound Energy, Inc., 120 FERC ¶ 61,211 (2007) (BPA), order denying reh’g and granting clarification, 125 FERC ¶ 61,273, at P 18 (2008) (BPA Rehearing Order). 9 See, e.g., Midcontinent Indep. Sys. Operator, Inc., 182 FERC ¶ 61,033 (MISO), order on reh’g, 184 FERC ¶ 61,022, at P 23 (2023) (MISO Rehearing Order) (citing Mich. Elec. Transmission Co., 97 FERC ¶ 61,187, at 61,852–53 (2001) (METC)). 10 Id. 11 Synchronous generating facilities (e.g., coal, gas, nuclear resources) produce electricity in sync with the transmission system at the system frequency. Non-synchronous generating facilities (e.g., solar, wind, battery storage resources) produce electricity that is initially not in sync with the transmission system and use inverters to convert their electrical output to synchronize with the transmission system. See FERC Staff Report, Payment for Reactive Power, Docket No. AD14–7– 000, 7 (Apr. 22, 2014), https://www.ferc.gov/sites/ default/files/2020-05/04-11-14-reactive-power.pdf. 12 MISO Rehearing Order, 184 FERC ¶ 61,022 at PP 29–30 (citing S. Co. Servs., Inc., 80 FERC ¶ 61,318, at 62,091 (1997) (noting also that the primary function of a generating plant is to produce real power; thus, if costs were allocated based on the ‘‘predominant’’ function of the equipment, ‘‘all of the costs of generation would thus be assigned to real power production and there would be no basis for any separate reactive power charge’’); BPA, 120 FERC ¶ 61,211 at P 21 (finding that the E:\FR\FM\28MRP1.SGM Continued 28MRP1 21456 Federal Register / Vol. 89, No. 61 / Thursday, March 28, 2024 / Proposed Rules ddrumheller on DSK120RN23PROD with PROPOSALS1 addition, the Commission has noted that any purported costs associated with such provision of reactive power can be recovered in other ways—such as through energy or capacity sales.13 7. Consistent with Order Nos. 2003 and 2003–A, multiple regional transmission organizations (RTO), independent system operators (ISOs), and non RTO/ISO transmission providers have elected not to compensate generating facilities for the provision of reactive power within the standard power factor range under Schedule 2 of the OATT.14 Within these regions, there is no evidence that this lack of compensation has led to an insufficient supply of reactive power or that generating facilities in these regions have been unable to recover any costs associated with the production of reactive power. Additionally, the experiences of these regions where reactive power within the standard power factor range is not separately compensated indicate that investors are able to, and in fact do, develop generating facilities that can satisfy the obligations in their interconnection agreements without separate reactive power compensation. 8. Based on our review of the comments submitted in response to the Commission’s Notice of Inquiry 15 in the instant docket, as well as the Commission’s experience in the years since the issuance of Order No. 2003– A, we preliminarily find that allowing transmission providers to compensate generating facilities, affiliated and unaffiliated, for providing reactive power within the standard power factor range has resulted in unjust and unreasonable transmission rates. This is because generating facilities providing reactive power within the standard power factor range are only meeting their obligations under their interconnection agreements and in accordance with good utility practice, incremental cost of reactive power service within the standard power factor range is minimal); METC, 97 FERC at 61,852–53 (‘‘[R]eactive power provided, not as an ancillary service, but rather as a ‘no cost’ service within reactive design limitations, may therefore, be provided without compensation.’’). 13 See, e.g., MISO Rehearing Order, 184 FERC ¶ 61,022 at P 42; BPA, 120 FERC ¶ 61,211 at P 21; Sw. Power Pool, Inc., 119 FERC ¶ 61,199, at P 39 (2007) (stating that IPPs ‘‘are free to negotiate rates that they charge their customers for real power that are sufficient to compensate them for any costs that they may incur in producing reactive power within their deadbands, just as affiliated generators may seek to negotiate rates that they charge their customers that are sufficient to compensate them for the costs of any reactive power that they provide within their deadbands.’’). 14 MISO, 182 FERC ¶ 61,033 at P 1. 15 Reactive Power Capability Compensation, 177 FERC ¶ 61,118 (2021) (NOI). VerDate Sep<11>2014 17:37 Mar 27, 2024 Jkt 262001 and in doing so, incur no additional costs or de minimis costs beyond that which they already incur to provide real power.16 Accordingly, we propose to prohibit transmission providers from including in their transmission rates any charges associated with the supply of reactive power within the standard power factor range from a generating facility, including those owned by the transmission owner or its affiliates. 9. First, we propose to add the following sentence to the end of Schedule 2 of the pro forma OATT: 17 ‘‘However, such rates shall not include compensation to generating facilities for the supply of reactive power within the power factor range specified in its interconnection agreement.’’ Second, we propose to remove the following clause from the pro forma LGIA: 18 ‘‘provided that if Transmission Provider pays its own or affiliated generators for reactive power service within the specified range, it must also pay Interconnection Customer.’’ Third, we propose to remove the following sentence from the pro forma SGIA: 19 ‘‘In addition, if the Transmission Provider pays its own or affiliated generators for reactive power service within the specified range, it must also pay the Interconnection Customer.’’ II. Background A. What is reactive power? 10. Almost all bulk electric power is generated, transported, and consumed in alternating current (AC) networks. Reactive power, which is measured in megavolt-amperes reactive (MVAr),20 is a critical component of operating an AC electricity system and is required to control system voltage within appropriate ranges for efficient and reliable operation of the transmission system. Reactive power supports the voltages that must be controlled to provide for delivery of real power and for system reliability. Reactive power can be produced or absorbed 21 by generating facilities, power electronic equipment such as flexible AC transmission system devices, transmission lines and equipment, and load. As relevant here, generating facilities must either produce or absorb reactive power for the transmission system to maintain voltage levels 16 Real power, which accomplishes useful work (e.g., runs motors), is typically measured in megawatts (MW). 17 See pro forma OATT, Schedule 2. 18 See pro forma LGIA, section 9.6.3. 19 See pro forma SGIA, section 1.8.2. 20 MVAr is the typical unit of measurement for reactive power. 21 See supra n.5. PO 00000 Frm 00016 Fmt 4702 Sfmt 4702 required to reliably supply real power from generation to load. 11. The power factor is the ratio of a generating facility’s real power to its apparent power.22 Power factors can range from 1.0 to 0.0, with 1.0 representing only real power and 0.0 representing only reactive power. Most generating facilities have interconnection agreements that specify a standard power factor range within which the generating facility must be able to operate while producing its full real power capacity. B. How has reactive power been compensated? 12. As noted above, the Commission’s policy on reactive power compensation has evolved since issuing Order No. 888, which included provisions regarding reactive power from generating facilities as an ancillary service in Schedule 2 of the pro forma OATT.23 As relevant here, in Order No. 2003, the Commission adopted a standard agreement for the interconnection of large generating facilities (the pro forma LGIA). This standard agreement included the requirement that interconnection customers maintain a composite power delivery at continuous rate of power output at the generating facility’s point of interconnection at a power factor within the range of 0.95 leading to 0.95 lagging when synchronized to the transmission system, unless the transmission provider has established a different power factor range. Order No. 2003 required that a transmission provider compensate an interconnection customer for reactive power when the transmission provider requests that the interconnection customer operate its generating facility outside the established power factor range. With respect to reactive power within the established power factor range, the Commission initially concluded that the interconnection customer should not be compensated for reactive power when operating within the range established in the interconnection agreement because doing so ‘‘is only meeting [the generating facility’s] obligation.’’ 24 But, in Order No. 2003–A, the Commission clarified that ‘‘if the Transmission Provider pays its own or its affiliated generators for reactive power within the established range, it must also pay the Interconnection Customer.’’ 25 Order No. 2003–A also exempted wind generating 22 Apparent power is the total power output of the system (both real and reactive power). 23 Order No. 888, FERC Stats. & Regs. ¶ 31,036 at 31,705–07 & n.359. 24 Order No. 2003, 104 FERC ¶ 61,103 at P 546. 25 Order No. 2003–A, 106 FERC ¶ 61,220 at P 416. E:\FR\FM\28MRP1.SGM 28MRP1 Federal Register / Vol. 89, No. 61 / Thursday, March 28, 2024 / Proposed Rules facilities from maintaining the established power factor range.26 13. The Commission treats the provision of reactive power within the standard power factor range differently from that outside the standard power factor range. Where reactive power is provided outside of the standard power factor range, it is considered ‘‘an ancillary service for transmitting power across the grid to serve load.’’ 27 By contrast, where the generating facility is operating within the standard power factor range, ‘‘it is meeting its obligation as a generator to maintain the appropriate power factor in order to maintain voltage levels for energy entering the grid during normal operations.’’ 28 ‘‘Put differently, reactive support by generating facilities operating within the standard power factor range ensures that when these facilities inject real power—the product that their facilities exist to create and sell—onto the grid under normal conditions, they can do their part to maintain adequate voltages and to not threaten reliability.’’ 29 14. In Order No. 2006,30 the Commission adopted identical power factor and compensation requirements for small generating facilities (facilities that have a capacity of no more than 20 MW) but exempted small wind generating facilities from the reactive power requirement. Subsequently, in Order No. 827,31 the Commission eliminated the exemptions for both small and large wind generating facilities, thus requiring those facilities to provide reactive power. As a result, all newly interconnecting nonsynchronous generating facilities were required to provide reactive power within the range of 0.95 leading to 0.95 lagging at the high-side 32 of the 26 Id. P 34. e.g., METC, 97 FERC at 61,852–53 (emphasis added); MISO Rehearing Order, 184 FERC ¶ 61,022 at PP 23–24. 28 METC, 97 FERC at 61,852–53; see also MISO Rehearing Order, 184 FERC ¶ 61,022 at PP 23–24; BPA, 120 FERC ¶ 61,211 at P 19; cf. Dynegy Midwest Generation, Inc., 125 FERC ¶ 61,280, at P 16 (2008) (‘‘Reactive power is a localized service that is quickly used by transmission system components and cannot be transported over long distances.’’). 29 MISO Rehearing Order, 184 FERC ¶ 61,022 at P 23. 30 Standardization of Small Generator Interconnection Agreements & Procs., Order No. 2006, 111 FERC ¶ 61,220, order on reh’g, Order No. 2006–A, 70 FR 71760 (Nov. 30, 2005), 113 FERC ¶ 61,195 (2005), order granting clarification, Order No. 2006–B, 71 FR 42587 (July 27, 2006), 116 FERC ¶ 61,046 (2006). 31 Reactive Power Requirements for NonSynchronous Generation, Order No. 827, 81 FR 40793 (June 23, 2006), 155 FERC ¶ 61,277, order on clarification and reh’g, 157 FERC ¶ 61,003 (2016). 32 High-side refers to the side of the transformer with higher voltages. Generally, real power must be ddrumheller on DSK120RN23PROD with PROPOSALS1 27 See, VerDate Sep<11>2014 17:37 Mar 27, 2024 Jkt 262001 generator substation transformer as a condition of interconnection. With respect to compensation, the Commission applied the existing policies on compensation for reactive power as articulated in Order Nos. 2003 and 2003–A and reflected in the pro forma LGIA and SGIA. The Commission, however, stated that the record did not contain a sufficient basis for determining a method for calculating compensation for non-synchronous generating facilities and therefore stated that any non-synchronous generating facility seeking reactive power compensation would need to propose a method for calculating that compensation as part of its filing.33 15. Consistent with Order Nos. 2003 and 2003–A, the Commission has permitted transmission providers to eliminate separate compensation for generating facilities providing reactive power within the standard power factor range.34 In these cases, the Commission affirmed its determination that the provision of reactive power within the standard power factor range is not compensable except as a matter of comparability. For example, in BPA, the Commission granted a complaint filed by Bonneville Power Administration (BPA) arguing that the rate schedules of certain independent power producers (IPP) for reactive power were no longer just and reasonable given BPA’s decision to no longer pay its own or affiliated generators.35 The Commission found that ‘‘Commission policy clearly allows BPA to discontinue paying all its merchants for inside the deadband reactive power service.’’ 36 The Commission also found that a transmission provider’s decision to end compensation for reactive power within the standard power factor range did not compromise an IPP’s ability to recover costs that they may incur in producing reactive power within such range.37 The Commission stated that such generating facilities ‘‘may be able to recover such costs in other ways—such as through higher power sales rates of their stepped up through a transformer to transmissionlevel voltages before being injected into the transmission system. 33 Order No. 827, 155 FERC ¶ 61,277 at P 52. 34 See, e.g., MISO, 182 FERC ¶ 61,033 at PP 52– 53; MISO Rehearing Order, 184 FERC ¶ 61,022 at P 26; Pub. Serv. Co. of N.M., 178 FERC ¶ 61,088, at PP 29–31 (2022) (PNM); Nev. Power Co., 179 FERC ¶ 61,103, at PP 20–21 (2022); BPA, 120 FERC ¶ 61,211 at P 20; E.ON U.S. LLC, 119 FERC ¶ 61,340, at P 15 (2007); Entergy Servs., Inc., 113 FERC ¶ 61,040, at P 38 (2005). 35 BPA, 120 FERC ¶ 61,211 at PP 19–20; BPA Rehearing Order, 125 FERC ¶ 61,273 at PP 10–11. 36 BPA, 120 FERC ¶ 61,211 at P 20. 37 Id. PP 19–22. PO 00000 Frm 00017 Fmt 4702 Sfmt 4702 21457 own.’’ 38 To the extent that it could be argued that such recovery was not feasible for IPPs, the Commission found that such arguments lacked plausibility ‘‘since the incremental cost of reactive power service within the deadband is minimal.’’ 39 The Commission explained that ‘‘[t]he purpose for which generation assets are built (including reactive power capability to maintain voltage levels for generation entering the grid) is to make sales of real power.’’ 40 16. The Commission made similar findings in MISO, wherein it accepted an FPA section 205 application by Midcontinent Independent System Operator, Inc. (MISO) transmission owners to end generator compensation for the provision of reactive power within the standard power factor range.41 In accepting MISO transmission owners’ proposal, the Commission reiterated its longstanding policy ‘‘that the provision of reactive power within the standard power factor range is, in the first instance, an obligation of the interconnecting generator and good utility practice,’’ such that ‘‘MISO transmission owners do not have an obligation to continue to compensate an independent generator for reactive power within the standard power factor range when its own or affiliated generators are no longer being compensated.’’ 42 The Commission also rejected any reliance arguments, reasoning in part that the provision of reactive power within the standard power factor range required little or no incremental investment.43 In addition, the Commission found that generating facilities have other opportunities, beyond Schedule 2, through which they have the opportunity to seek to recover 38 Id. P 21 (citing Sw. Power Pool, Inc., 119 FERC ¶ 61,199 at P 39). 39 Id. 40 Id. 41 MISO, 182 FERC ¶ 61,033 at P 53 (‘‘Bearing in mind that the provision of reactive power within the standard power factor range is, in the first instance, an obligation of the interconnecting generator and good utility practice, MISO [transmission owners] do not have an obligation to continue to compensate an independent generator for reactive power within the standard power factor range when its own or affiliated generators are no longer being compensated.’’ (citation omitted)); see also PNM, 178 FERC ¶ 61,088 at P 29 (accepting PNM’s revisions to eliminate compensation for reactive service under Schedule 2 and rejecting generators’ arguments that it is ‘‘just and reasonable for it to be compensated for investments made’’ to provide reactive support consistent with interconnection requirements even though PNM elected to no longer pay its own or affiliated generators for such reactive power). 42 MISO, 182 FERC ¶ 61,033 at P 53 (finding ‘‘those protests that challenge these wellestablished policies to be collateral attacks on these earlier determinations.’’). 43 MISO Rehearing Order, 184 FERC ¶ 61,022 at P 29. E:\FR\FM\28MRP1.SGM 28MRP1 21458 Federal Register / Vol. 89, No. 61 / Thursday, March 28, 2024 / Proposed Rules their costs of providing reactive power.44 17. Of the six Commissionjurisdictional RTOs/ISOs, only three currently compensate generating facilities for reactive power provided within the standard power factor range. Generating facilities in PJM Interconnection, L.L.C. (PJM) generally use the cost-based AEP Methodology to calculate cost-of-service rates for the production of reactive power.45 Because the same generation equipment contributes to the production of both real power and reactive power, the AEP Methodology attempts to functionalize each piece of equipment as between its contribution to real power and reactive power. Then, using allocators calculated based on the facility’s output, the AEP Methodology allocates the cost of each piece of equipment based on its relative contribution to each function. 18. Generating facilities in ISO New England Inc. (ISO–NE) and New York Independent System Operator, Inc. (NYISO) are compensated for reactive power under flat rate designs that are adjusted for inflation.46 California Independent System Operator Corporation (CAISO),47 Southwest Power Pool, Inc. (SPP),48 and MISO 49 do not pay separately for reactive power within the standard power factor range. 19. Outside the RTOs/ISOs, transmission providers that pay for the provision of reactive power within the standard power factor range generally compensate generating facilities using the AEP Methodology to set reactive power compensation on an individual generating facility basis. Many nonRTO/ISO transmission providers do not pay separately for reactive power 44 Id. P 41. 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). 46 NOI, 177 FERC ¶ 61,118 at PP 14–16. 47 CAISO never provided compensation for reactive power within the standard power factor range. See Cal. Indep. Sys. Operator Corp., 160 FERC ¶ 61,035, at P 7 (2017) (explaining that CAISO considered the possibility of compensating generating facilities for reactive power in its stakeholder process, but decided against it, reasoning that the ability to provide reactive power is part of a generator’s fixed costs, which are recovered through power purchase agreements). 48 Sw. Power Pool, Inc., 119 FERC ¶ 61,199 at P 30. 49 MISO, 182 FERC ¶ 61,033 at PP 52–66; MISO Rehearing Order, 184 FERC ¶ 61,022 at PP 23–55. ddrumheller on DSK120RN23PROD with PROPOSALS1 45 The VerDate Sep<11>2014 17:37 Mar 27, 2024 Jkt 262001 provided within the standard power factor range.50 C. Notice of Inquiry 20. On November 18, 2021, the Commission issued an NOI 51 in the instant docket seeking comment on various issues regarding reactive power compensation and market design as a result of the significant changes that have taken place in the electric industry in the last two decades, including changes in the generation resource mix and a general shift away from cost-ofservice rates for generating facilities selling into Commission-jurisdictional markets. Generally, the Commission sought to ‘‘examine whether the current regime for reactive power capability compensation requires revisions to ensure that payments for reactive power capability accurately reflect the costs associated with reactive power capability.’’ 52 Specifically, the Commission sought comment on various constructs used by transmission providers to allow for reactive power cost recovery, including issues related to the application of the AEP Methodology as well as on issues regarding recovery of reactive power costs through existing energy and/or capacity markets. 21. The Commission received 37 initial comments and 10 reply comments in response to the NOI. The commenters to the NOI are listed and group members are identified in Appendix A. Groups representing transmission customers, such as Joint Customers, the Electricity Consumers Resource Council (ELCON), and the National Rural Electric Cooperative Association (NRECA), believe that the AEP Methodology results in unjust and unreasonable rates and recommend that the Commission establish a new rate 50 See, e.g., Arizona Public Service Company, FERC Electric Tariff Vol. No. 2, Schedule 2 (Reactive Supply and Voltage Control from Generation or Other Sources Service) (6.0.0) (‘‘This service will be provided at no charge until APS has developed a rate that has been filed with the Commission and allowed to be implemented; however, Transmission Customers taking service at transmission voltage levels shall be responsible for maintaining a power factor of ± 95.0%, and Transmission Customers taking service at distribution voltage levels shall maintain a power factor of not less than 90% lagging but in no event leading, unless agreed to by APS.’’); Public Service Company of New Mexico, PNM Open Access Transmission Tariff, Schedule 2 (Reactive Supply and Voltage Control from Generation or Other Sources Service) (2.1.0) (‘‘As of October 1, 2021, the Effective Date of this Schedule 2, the Transmission Provider is not charging for Reactive Supply and Voltage Control from Generation or Other Sources Service from its own resources. As a result, there will be no separate charge for such service.’’). 51 NOI, 177 FERC ¶ 61,118. 52 Id. P 19. PO 00000 Frm 00018 Fmt 4702 Sfmt 4702 methodology.53 In particular, Joint Customers argue that ‘‘reactive capability alone should not be the basis for compensation.’’ 54 By contrast, resource developers, power generation industry groups, and commenters who support the increased use of renewable energy argue in favor of retaining and modifying the AEP Methodology to address the issues discussed in the NOI.55 22. The Independent Market Monitor for PJM (PJM IMM) contends that costof-service compensation for the provision of reactive power within the standard power factor range is an ‘‘atavistic regulatory paradigm’’ that predates the introduction of wholesale power markets and, therefore, is unnecessary in light of potential compensation through the PJM markets.56 ELCON states that it supports the PJM IMM’s position and encourages the Commission to rely on ‘‘competitive markets for the procurement of essential grid services such as reactive power— rather than reliance on traditional costof-service rates’’ in order to ‘‘ensure that electricity consumers pay the lowest price possible for reliable service.’’ 57 23. RTOs/ISOs generally limit their comments to describing the rate designs in their respective regions, but PJM and CAISO did provide some commentary 53 Joint Customers Initial Comments at 8–13; Joint Customers Reply Comments at 2–10, 12–15; ELCON Initial Comments at 5–7, NRECA Initial Comments at 4–5. 54 Joint Customers Initial Comments at 9. 55 See, e.g., EDF Renewables, Inc. (EDFR) Initial Comments at 2–4; Edison Electric Institute (EEI) Initial Comments at 5; Indicated Generation Owners Initial Comments at 5–7; Nuclear Energy Institute (NEI) Initial Comments at 4; PJM Power Providers Initial Comments at 2–4; Renewable Generation Companies Initial Comments at 6–7, 11–15; Renewable Generation Companies Reply Comments at 2–5, 10–11; Clean Energy Coalition Initial Comments at 1–5; Electric Power Supply Association (EPSA) Initial Comments at 2–9; Vistra Corp. and Dynegy Marketing and Trade, LLC (collectively, Vistra) Initial Comments at 6–7; Vistra Reply Comments at 6–7; Pine Gate Renewables, LLC (Pine Gate) Initial Comments at 7–8. 56 PJM IMM Initial Comments at 2; see also PJM IMM, Comments, Docket No. AD16–17–000, at 1, 6– 10 (filed Aug. 1, 2016) (detailing the PJM IMM’s view that reactive power costs can—and should— be recovered through PJM’s capacity market instead of under a cost-of-service paradigm); Monitoring Analytics, 2020 State of the Market Report for PJM, 523 (Mar. 11, 2021), https:// www.monitoringanalytics.com/reports/PJM_State_ of_the_Market/2020.shtml (describing the PJM IMM’s position and recommended improvements)); PJM IMM, Brief on Exceptions, Docket No. ER17– 1821–002, at 3–16 (filed June 12, 2019) (discussing the PJM IMM’s concerns about what it termed a ‘‘hybrid of market-based rates and cost of service rates’’); PJM IMM, Rehearing Request, Docket No. ER17–1821–005, at 3–5 (filed Apr. 30, 2021) (addressing issues regarding the Energy and Ancillary Services Offset (E&AS Offset) and a generator’s proposed reactive power rates). 57 ELCON Initial Comments at 4–5. E:\FR\FM\28MRP1.SGM 28MRP1 Federal Register / Vol. 89, No. 61 / Thursday, March 28, 2024 / Proposed Rules on the merits. While PJM does not advocate for a particular solution in this proceeding, PJM highlights several issues with its current reactive power rate scheme.58 Specifically, PJM asserts that ‘‘enormous’’ amounts of time and resources must be expended to file, litigate, and perform testing for each individual generating facility’s cost-ofservice rate case,59 which PJM notes often results in a rate product that is ‘‘of exceptionally poor quality for an important ancillary service.’’ 60 CAISO states that despite the fact that it does not compensate for reactive power within the standard power factor range, it ‘‘has seen no evidence to this point that resources cannot comply with reactive power dispatch instructions because they have insufficient funds for the equipment to meet the reactive power dispatch.’’ 61 III. Discussion A. Need for Reform 24. Since Order No. 2003–A, the Commission has permitted transmission providers to compensate resources for providing reactive power within the standard power factor range provided that, to ensure comparability, the transmission provider pays both affiliated and unaffiliated resources. But, as explained in more detail below, providing reactive power within the standard power factor range is a ‘‘no cost’’ 62 or de minimis cost service in addition to being a resource’s obligation under its interconnection agreement and good utility practice. Further, the record indicates that to the extent that generating facilities have any purported costs associated with providing reactive power within the standard power factor range, these costs can be recovered through energy or capacity sales and do not require separate compensation. 25. We thus preliminarily find that where transmission providers require transmission customers to pay for the provision of reactive power within the standard power factor range, transmission rates may be unjust and unreasonable, as they include costs 58 PJM Initial Comments at 1–2. at 2–3, 5–7. PJM notes that ‘‘many other parties beyond the generator are drawn into the proceeding, including PJM, FERC Trial Staff, zonal transmission customers, transmission owners, and/ or the Independent Market Monitor for PJM, among others. These parties must in turn expend time and resources of their own in discovery and analysis of the generator’s specific cost characteristics and claims, in order to formulate their own position in the proceeding and form a basis for negotiations or litigation.’’ 60 PJM Initial Comments at 3. 61 CAISO Initial Comments at 5–6. 62 METC, 97 FERC at 61,852–53. ddrumheller on DSK120RN23PROD with PROPOSALS1 59 Id. VerDate Sep<11>2014 17:37 Mar 27, 2024 Jkt 262001 without a sufficient economic basis or justification. 26. The Commission’s experience since Order No. 2003–A and the comments submitted into this record demonstrate that where transmission providers provide compensation, the costs to transmission customers have increased substantially without any commensurate increase in benefits. For example, in many regions today, resources are sited without regard to where there is a geographic need for reactive power, which is significant given that (unlike real power) reactive power cannot be efficiently transmitted long distances. Where such resources are compensated for reactive power that is not needed or necessarily deliverable to areas of the transmission system where reactive power may be needed, customers may be paying for a perceived reliability benefit that they are not receiving. 27. Additionally, implementing the Commission-approved AEP Methodology has become increasingly administratively burdensome to transmission providers, transmission customers, other stakeholders, and the Commission due to the resource- and time-intensity involved in determining individualized, cost-of-service reactive power rates for generation facilities through hearing and settlement judge procedures.63 It also often results in inconsistent rate treatment across facilities. 1. Compensation for Providing Reactive Power Within the Standard Power Factor Range May Be Unjust and Unreasonable 28. We preliminarily find that providing compensation for the provision of reactive power within the standard power factor range is unjust and unreasonable because the generating facility already provides reactive power within the standard power factor range at no cost or de minimis cost, because such compensation may result in undue compensation or other market distortions, and because providing reactive power within the standard power factor range is an obligation of the generating facility as an 63 Today, most reactive power filings are made by IPPs and concern non-synchronous resources that produce reactive power using different types of equipment than that contemplated by the AEP Methodology. Additionally, almost all filing entities (both synchronous and non-synchronous) have received waivers of the requirement to maintain their accounts under the Uniform System of Accounts (USofA) rules and to file a FERC Form No. 1 when they were granted market-based rate authority. PO 00000 Frm 00019 Fmt 4702 Sfmt 4702 21459 interconnection customer and consistent with good utility practice. 29. We begin by explaining why providing reactive power within the standard power factor range imposes no cost or de minimis cost to producers. Both synchronous and non-synchronous resources provide real and reactive power as joint products,64 with joint costs.65 For synchronous generating facilities, ‘‘the same equipment is used to provide real and reactive power.’’ 66 Non-synchronous generating facilities use a different physical process to produce reactive power, but ‘‘the most critical element in VAR production, the inverter,’’ 67 is also necessary for nonsynchronous generating facilities to produce real power that can be injected into AC systems.68 In other words, for both synchronous and non-synchronous generating facilities, ‘‘[t]here are few if any identifiable costs incurred by generators in order to provide reactive power’’ 69 beyond the investments in equipment already necessary to generate and supply real power to the transmission system.70 64 See PSC VSMPO-Avisma Corp. v. U.S., 688 F.3d 751, 756 (Fed. Cir. 2012) (defining ‘‘joint products’’ as ‘‘two dissimilar end products that are produced from a single production process.’’). 65 A joint cost is an expenditure that benefits more than one product, and for which it is not possible to separate the contribution to each product. In re Permian Basin Area Rate Cases, 390 U.S. 747, 761 n.25 (1968) (‘‘Joint costs ‘are incurred when products cannot be separately produced.’ ’’ (citing M. Adelman, The Supply and Price of Natural Gas 25 (1962))); see also AccountingTools, Joint Cost (Aug. 25, 2023), https:// www.accountingtools.com/articles/joint-cost. 66 EEI Initial Comments at 6. 67 Duke Energy Corporation Initial Comments at 4. 68 See also MISO Rehearing Order, 184 FERC ¶ 61,022 at P 30 (‘‘As to non-synchronous resources, the principal piece of equipment required for nonsynchronous resources to produce reactive power is the inverter, which is already necessary to convert the direct current produced by non-synchronous resources to alternating current—i.e., to supply real power that can be injected into alternating current power systems. On rehearing and in earlier protests, no party points to any other equipment costs incurred by non-synchronous generating facilities that are attributable to providing Reactive Service.’’ (citations omitted)). 69 PJM IMM Initial Comments at 4; see also MISO Transmission Owners Reply Comments at 7–8. 70 See, e.g., BPA, 120 FERC ¶ 61,211 at P 21 (finding that the incremental cost of reactive power service within the deadband is minimal); METC, 97 FERC at 61,852–53 (‘‘[R]eactive power provided, not as an ancillary service, but rather as a ‘‘no cost’’ service within reactive design limitations, may therefore, be provided without compensation.’’); Ariz. Pub. Serv. Co., 94 FERC ¶ 61,027, at 61,080 (2001) (rejecting generators’ arguments for reactive power compensation for operating within standard power factor range because the generators failed to demonstrate that ‘‘such a requirement will limit the real power output of a generating unit and therefore will not result in any lost opportunity costs’’ or that operating a generating unit within the proposed E:\FR\FM\28MRP1.SGM Continued 28MRP1 ddrumheller on DSK120RN23PROD with PROPOSALS1 21460 Federal Register / Vol. 89, No. 61 / Thursday, March 28, 2024 / Proposed Rules 30. Moreover, because real and reactive power are provided as joint products with joint costs, any allocation of joint fixed costs between real and reactive power could be viewed as inherently arbitrary.71 When separate reactive power payments were first established, utilities typically provided both generation and transmission as vertically integrated utilities under a cost-of-service regime. In such a construct, the allocation of costs between generation and transmission facilities had little significance because it affected only the allocation of costs between transmission and generation rates. In other words, prior to the advent of IPPs (which operate only generation facilities), market-based rates for energy, and the development of RTOs/ISOs and bilateral markets, the allocation of fixed costs between real and reactive power did not have a major effect on the overall revenues of a combined vertically integrated utility.72 However, for reactive power cost recovery, the introduction of RTO/ISO markets and bilateral transactions in non-RTO/ISO regions has provided more efficient and transparent means of compensating resources than the cost-of-service model. For example, RTO/ISO markets provide generating facilities with a means to recover the costs they incur to provide various services, such as real power sales, that rely on the same equipment used for reactive power supply.73 Additionally, generating facilities in non-RTO/ISO regions (e.g., IPP) can compete in bilateral markets to recover their investment, production, and operating costs. 31. We recognize that the production of reactive power within the standard power factor range can result in certain incremental variable costs such as fuel, maintenance, and potentially other costs. That said, the Commission has repeatedly found,74 and commenters agree, that ‘‘[v]ariable costs of generating reactive power are de minimis.’’ 75 Indeed, as SPP notes, variable costs ‘‘are generally limited to changes in losses within the generating facility which are part of the overall efficiency of the resource and, as such, are typically captured in the resource offers.’’ 76 Similarly, Joint Customers state that, in CAISO, SPP, and other regions that do not separately compensate for reactive power within the standard power factor range, ‘‘perhaps generators are adequately recovering their costs through some other means.’’ 77 standard power factor range will ‘‘affect the generation output of a unit’’). 71 See PJM IMM Initial Comments at 2 (‘‘There is no reason to include complex rules that arbitrarily segregate a portion of a resource’s capital costs as related to reactive power and that require recovery of that arbitrary portion through guaranteed revenue requirement payments based on burdensome cost of service rate proceedings.’’); id. at 3, 5, 21, 24; In re Permian Basin Area Rate Cases, 390 U.S. at 804 (‘‘There is ample support for the Commission’s judgment that the apportionment of actual costs between two jointly produced commodities, only one of which is regulated by the Commission, is intrinsically unreliable.’’); Richard A. Posner, Natural Monopoly and Its Regulation, 21 Stan. L. Rev. 548, 595 (1969) (‘‘[W]here services involve joint or common costs a rational allocation is impossible even in theory. How much of the cost of a telephone handset is assignable to local and how much to interstate telephone service?’’); see also A.A. Poultry Farms, Inc. v. Rose Acre Farms, Inc., 881 F.2d 1396, 1400 (7th Cir. 1989) (‘‘How does one allocate the cost of activities that have joint products? Agencies engaged in ratemaking struggle with these problems for years, even decades, without producing clear answers.’’). 72 See N. States Power Co., 64 FERC ¶ 61,324, at 63,379 (1993) (‘‘In general, so long as a utility was selling generation and transmission services on a bundled basis (i.e., full requirements service), the functionalization of costs between generation and transmission was not critical. The historical functionalization of costs, or bright line approach, was administratively simple, it had little or no impact on the overall (i.e., bundled) rate for requirements service, and problems involving crosssubsidization between the generation and transmission functions were minimal. However, strict application of the traditional bright line approach may need to be reexamined in light of changes taking place in the electric industry— particularly the increase in transmission-only service.’’). 73 See, e.g., PJM IMM Initial Comments at 2 (‘‘The current process is an inefficient waste of time because it relies on an atavistic regulatory paradigm that is not relevant in the PJM market framework. The AEP Method[ology] was created, before the creation of the PJM markets, by a regulated utility that had regulatory and financial reasons to want to define some generation costs as transmission costs.’’); ELCON Initial Comments at 5 (‘‘The AEP Methodology was established as a workable heuristic during a period in which organized markets were in their infancy and nearly all new resources were synchronous.’’). 74 MISO Rehearing Order, 184 FERC ¶ 61,022 at PP 29–31 (finding that providing reactive service requires ‘‘little or no incremental investment’’ by both synchronous and non-synchronous resources); PJM Interconnection, L.L.C., 151 FERC ¶ 61,097, at PP 7, 28 (2015) (finding that non-synchronous generating facilities are comparable to traditional synchronous generating facilities, in that there are for both types of generating facilities very little if any incremental costs incurred to provide reactive power); Panda Stonewall, LLC, 176 FERC ¶ 61,072, at P 6 n.9 (2021) (stating that Panda Stonewall’s annual revenue requirement of $2,051,894 reflected a heating losses component of $10,018). We note that the heating losses component reflects the incremental cost of providing reactive power. 75 SPP Initial Comments at 2; see also PJM IMM Initial Comments at 4. 76 SPP Initial Comments at 2–3. 77 Joint Customers Initial Comments at 9; see also PJM IMM Initial Comments at 1–4; CAISO Initial Comments at 3–4; Dominion Initial Comments at 12; MISO, 182 FERC ¶ 61,033 at P 58 (‘‘[J]ust as the MISO [transmission owners’] generators may try to recover their lost revenue through higher power sales rates, so too may independent power producers try to recover their lost revenue through their own higher power sales rates.’’); BPA, 120 FERC ¶ 61,211 at P 21; Sw. Power Pool, Inc., 119 FERC ¶ 61,199 at P 39 (stating that IPPs ‘‘are free to negotiate rates that they charge their customers VerDate Sep<11>2014 17:37 Mar 27, 2024 Jkt 262001 PO 00000 Frm 00020 Fmt 4702 Sfmt 4702 32. By contrast, but outside the scope of this rulemaking, the production of reactive power outside of the standard power factor range, for which transmission providers are required to provide compensation, may result in increased costs, including opportunity costs to the generating facility.78 As such, if the transmission provider requires a generating facility to provide reactive power outside of the standard power factor range, the generating facility may have to ‘‘reduce its MW output in order to comply with such an instruction[,]’’ which could limit the generating facility’s opportunity to receive compensation for real power sales.79 33. Lastly, consistent with Order No. 2003 and multiple subsequent Commission orders since then, generating facilities must produce reactive power in order to be allowed to interconnect to the transmission system, and the industry has recognized that regulating voltage among interconnected generating facilities is a necessary component of good utility practice in an interconnected transmission system. For example, CAISO states that ‘‘[t]he rationale for the CAISO’s existing approach to reactive power compensation is that the reactive power ranges called for in each interconnection agreement represent a reasonable range of what a generator is expected to provide the CAISO without additional compensation in accordance with good utility practice and as a condition of being part of the CAISO markets and CAISO grid.’’ 80 The Commission, therefore, has required generating facilities to provide reactive power within the standard power factor range under their interconnection agreements and good utility practice.81 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.’’). 78 See, e.g., SPP Initial Comments at 2 (‘‘SPP’s current Schedule 2 rate per MVArh was calculated to represent the cost of reactive power production from recently constructed generators so as to reflect the upper end of such costs. This rate is applied to compensate qualifying generators located throughout the SPP region that provide reactive power support outside a power factor dead band.’’ (emphasis added) (citations omitted)). 79 CAISO Initial Comments at 4. 80 CAISO Initial Comments at 3. 81 See, e.g., MISO, 182 FERC ¶ 61,033 at P 53 (‘‘Bearing in mind that the provision of reactive power within the standard power factor range is, in the first instance, an obligation of the interconnecting generator and good utility practice, MISO [transmission owners] do not have an obligation to continue to compensate an independent generator for reactive power within E:\FR\FM\28MRP1.SGM 28MRP1 Federal Register / Vol. 89, No. 61 / Thursday, March 28, 2024 / Proposed Rules Thus, the obligation for generating facilities to provide reactive power within the standard power factor range pursuant to their interconnection agreements is separate from any compensation for reactive power. In turn, because providing reactive power within the standard power factor range is already obligated (a no cost or de minimis cost service), compensating for providing such reactive power could result in undue compensation to generating facilities 82 at the expense of transmission customers. ddrumheller on DSK120RN23PROD with PROPOSALS1 2. Adverse Impacts of the Commission’s Current Reactive Power Compensation Policy 34. In the years since the issuance of Order No. 2003–A, numerous issues have arisen in regions that provide compensation to generators for the provision of reactive power within the standard power factor range. the standard power factor range when its own or affiliated generators are no longer being compensated.’’ (citations omitted)); id. P 54 (‘‘We find unpersuasive protesters arguments that it is not just and reasonable to eliminate compensation for Reactive Service within the standard power factor range because generators have come to rely on the compensation for Reactive Service in order for the generators to remain financially viable. The Commission has previously rejected such arguments, finding that all newly interconnecting generators are required to provide reactive power within the power factor range of 0.95 leading to 0.95 lagging as a condition of interconnection.’’ (citations omitted)); PNM, 178 FERC ¶ 61,088 at P 29 (rejecting generator’s arguments that it is ‘‘just and reasonable for it to be compensated for investments made’’ to provide reactive support consistent with interconnection requirements even though transmission provider elected to no longer pay its own or affiliate generators for such reactive power); Nev. Power Co., 179 FERC ¶ 61,103 at P 22 (finding that the generating companies’ argument, ‘‘that it is not just and reasonable to eliminate their compensation for reactive service because they made investments in their generating facilities based on the expectation that they would receive compensation for reactive service,’’ unpersuasive because all newly interconnecting generators are required to provide reactive power within the standard power factor range as a condition of interconnection); Order No. 2003, 104 FERC ¶ 61,103 at P 546. 82 See Belmont Mun. Light Dep’t v. FERC, 38 F.4th 173, 179, 186 (D.C. Cir. 2022) (finding that the Commission’s approval of a portion of ISO–NE’s Inventoried Energy Program ‘‘was not reasoned decision making’’ and ‘‘thwart[ed] the [Commission’s] own ‘longstanding policy that rate incentives must be prospective and that there must be a connection between the incentive and the conduct meant to be induced’ ’’ because it would compensate market participants for conduct they already engage in as part of standard business operations). Compensating for reactive power that is already required for interconnection purposes could create a ‘‘windfall’’ as suggested by the D.C. Circuit in Belmont. Id. at 186 (citing San Diego Gas & Elec. Co. v. FERC, 913 F.3d 127, 137 (D.C. Cir. 2019)). But see Order No. 2003–C, 111 FERC ¶ 61,401 at P 42 (finding that because providing reactive power within the established range is an ‘‘important service,’’ payment for such service does not constitute a ‘‘windfall.’’). VerDate Sep<11>2014 17:37 Mar 27, 2024 Jkt 262001 35. First, compensation for reactive power within the standard power factor range is not tied to whether there is a particular geographic need for reactive power. As noted above, reactive power cannot be transferred over long distances across the transmission system and, as a result, the reliability benefits of a generating facility’s reactive power depend, in part, on its location.83 But, compensation in a region for reactive power within the standard power factor range does not vary based on location, meaning that some generating facilities are compensated for reactive power that is not needed at the generating facilities’ location on the transmission system. As the MISO transmission owners argue, ‘‘[t]he current framework is . . . unjust and unreasonable because resources are being paid for reactive power capability in geographic areas where not all of the available reactive power is necessary. There are service areas with concentrations of generation but very little load, creating an exporting region where load pays for reactive capability that is unneeded.’’ 84 Joint Customers add that, with the vastly increased amount of generation and increase in the number of generators seeking reactive compensation, the Commission ‘‘should reconsider whether unbounded payment for reactive power capability is appropriate, or, to the contrary, whether transmission customers are paying for capability for which they do not receive commensurate benefits.’’ 85 It appears that under the current framework, generating facilities are eligible to receive cost-based reactive power payments that do not reflect the reliability benefits of the reactive power at each facility’s location (i.e., the extent to which the generating facility supports the voltage of the transmission system), and that the reliability benefit may be zero for certain generating facilities. 36. Second, many commenters explain that in regions that allow generating facilities to file 83 FERC Staff Report, Payment for Reactive Power, Docket No. AD14–7–000, 5 (Apr. 22, 2014), https:// www.ferc.gov/sites/default/files/2020-05/04-11-14reactive-power.pdf. 84 MISO Transmission Owners Initial Comments at 7–8; see also Joint Customers Initial Comments at 8–9; Alliant Initial Comments at 4; NYISO, Reliability and Market Considerations for a Grid in Transition, at 105 (2019), https://www.nyiso.com/ documents/20142/2224547/Reliability-and-MarketConsiderations-for-a-Grid-in-Transition20191220%20Final.pdf/61a69b2e-0ca3-f18c-cc3988a793469d50 (‘‘Moreover, because voltage support needs are local, the NYISO will need voltage support within specific narrow regions, not necessarily at the locations at which resources able to provide reactive power without incurring substantial commitment costs may be located.’’). 85 Joint Customers Initial Comments at 8–9. PO 00000 Frm 00021 Fmt 4702 Sfmt 4702 21461 individualized cost-of-service reactive power rates, the process for determining those rates has proven to be resourceintensive, time-intensive, and administratively burdensome for ratepayers, transmission providers, and market participants.86 Moreover, commenters explain that in addition to being burdensome, the resulting black box settlements produce a ‘‘rate product’’ that is ‘‘of exceptionally poor quality for an important ancillary service.’’ 87 37. As noted in the NOI, most of the filings at the Commission seeking to establish rates for reactive power compensation are made by generating facilities (both synchronous and nonsynchronous) that have received waivers of the Commission’s requirement to maintain their accounts under the USofA rules and to file FERC Form No. 1.88 Due, in part, to the lack 86 Id. at 4–5, 12–13 (‘‘[T]he case-by-case approach to reactive capability rates based on the AEP methodology makes it very difficult for proceedings to be resolved in an efficient manner.’’); PJM IMM Initial Comments at 2, 4 (noting that ‘‘[a]pplying cost of service rules is costly and burdensome and unnecessary’’ and asserting that ‘‘[r]emoving cost of service rules would avoid the significant waste of resources incurred to develop unneeded cost of service rates’’); PJM Initial Comments at 10 (‘‘[T]he current construct for reactive power capability compensation in PJM imposes a significant administrative burden on PJM and its resource owners, both in terms of settlements and testing.’’); Dominion Initial Comments at 2–3 (noting that settlement proceedings are time consuming and not transparent); see also Clean Energy Coalition Reply Comments at 5; ELCON Initial Comments at 6–7; Renewable Generation Reply Comments at 25; EDFR Initial Comments at 4–5; Pine Gate Renewables Initial Comments at 6–7; PJM Power Providers Group Initial Comments at 4–5; American Electric Power Service Corporation Initial Comments at 2–3; EPSA Initial Comments at 2; Nuclear Energy Institute Initial Comments at 6–7; PJM IMM Initial Comments at 2 (‘‘Most reactive proceedings for generators in PJM are resolved in black box settlements that fail to address the merits of the cost support provided, result from an unsupported split the difference approach, and that, not surprisingly, produce a wide, unreasonable and discriminatory disparity among the rates per paid per MW-year.’’). 87 PJM Initial Comments at 3; see also PJM IMM Initial Comments at 2. 88 The Commission’s accounting and reporting requirements are particularly important to the evaluation and monitoring of cost-based rates. See, e.g., Alcoa Power Generating Inc., 172 FERC ¶ 61,052, at P 29 (2020); Third-Party Provision of Ancillary Servs.; Acct. & Fin. Reporting for New Elec. Storage Technologies, Order No. 784, 78 FR 46178 (July 30, 2013), 144 FERC ¶ 61,056 (2013) (accounting and reporting requirements ‘‘support the rate oversight needs of both this Commission and State Commissions’’ and are ‘‘important in developing and monitoring rates, making policy decisions, compliance and enforcement initiatives, and informing the Commission and the public about the activities of entities that are subject to these accounting and reporting requirements.’’); Carville Energy LLC, 104 FERC ¶ 61,252, at 61,833 n.13 (2003) (‘‘For example, non-exempt public utilities keep financial records, required by this E:\FR\FM\28MRP1.SGM Continued 28MRP1 21462 Federal Register / Vol. 89, No. 61 / Thursday, March 28, 2024 / Proposed Rules ddrumheller on DSK120RN23PROD with PROPOSALS1 of availability of this cost-of-service information, many of these filings are set for hearing and settlement judge procedures.89 Many commenters, including Joint Customers, note that these settlement proceedings ‘‘require a significant expenditure of resources that include legal and technical consultants,’’ and while many of the cases settle on a ‘‘black box’’ basis, ‘‘significant effort is undertaken by the Joint Customers [and other participants] in order to obtain information necessary to perform an AEP-like calculation and develop settlement proposals.’’ 90 The PJM IMM notes that, in its experience, ‘‘[m]ost reactive proceedings for generators in PJM are resolved in black box settlements that fail to address the merits of the cost support provided, result from an unsupported split the difference approach, and that, not surprisingly, produce a wide, unreasonable and discriminatory disparity among the rates paid per MWyear.’’ 91 Joint Customers also note that the time-consuming process for resolving individual reactive service Commission, which, among other things, are designed to aid in the development of the costbased rates.’’ (emphasis added)). 89 Indeed, as the Commission has explained, Parts 41, 101, and 141 of its regulations are critical to its statutory obligation under sections 205 and 206 of the FPA to ensure that rates are just, reasonable, and not unduly discriminatory or preferential. See PSEG Fossil, LLC, 97 FERC ¶ 61,211, at 61,920–21 (2001) (PSEG), reh’g denied, 98 FERC ¶ 61,169 (2002). Moreover, the Commission has stated that customers subject to cost-based rates have a right to cost data so that they may evaluate the ongoing reasonableness of their rates. See also PSEG, 97 FERC at 61,920–21. 90 Joint Customers Initial Comments at 5. When the cases do not settle, Joint Customers note that even more resources must be expended to litigate the individual revenue requirement proposal. For example, Joint Customers note that the Panda Stonewall proceeding lasted four years from the effective date of Panda’s reactive service rate to the Commission’s order establishing the just and reasonable rate. Id. (citing Panda Stonewall, LLC, Opinion No. 574, 174 FERC ¶ 61,266, reh’g denied, 175 FERC ¶ 62,132 (2023)). During this time, Joint Customers note that they and others paid the approximately $6.2 million annual revenue requirement filed by Panda. Joint Customers state that the Commission’s Order on Initial Decision established an approximately $2 million annual revenue requirement. Joint Customers note that this difference resulted in ‘‘approximately $17 million in overcollection and delayed refunds due to customers.’’ Id. 91 PJM IMM Initial Comments at 2. Many other commenters express concern over the lack of transparency associated with how these rates are calculated. See, e.g., American Electric Power Service Corporation Initial Comments at 2; Renewable Generation Companies Initial Comments at 22–23; ELCON Initial Comments at 6–7; Joint Customers Initial Comments at 6; PJM Initial Comments at 3–4, 11; Nuclear Energy Institute Initial Comments at 6–7; PSE&G Initial Comments at 10. VerDate Sep<11>2014 17:37 Mar 27, 2024 Jkt 262001 rate proceedings may leave customers without adequate refund protection.92 38. Third, the process for testing and verification under the AEP Methodology is unduly burdensome. Under that process, resources must coordinate with the transmission provider to test and verify capability to produce reactive power under certain conditions, which often requires multiple tests over a series of months and that yields inconsistent results across resources. PJM notes that this has caused a ‘‘significant influx of resources that are not [otherwise] required to test under PJM Manual 14–D . . . seeking to test solely for purposes of filing and/or litigating reactive power capability cases.’’ 93 PJM notes that ‘‘under the current regulatory structure, rather than PJM spending time and resources testing units based on PJM’s operational needs as the Transmission Provider, PJM is now often spending time and resources testing units based on the resource owner’s need to file and litigate its individual cost-of-service rate case.’’ 94 39. Fourth, as discussed above, in regions where resources recover their costs by participating in organized competitive wholesale markets, providing separate compensation for the provision of reactive power within the standard power factor range risks overcompensation and market distortion in ways that did not exist prior to the existence of organized markets.95 As noted above, the AEP Methodology originated in an era of vertically integrated utilities, when most utilities (including AEP) filed FERC Form No. 1s, used the USofA to classify their costs, and recovered those costs entirely 92 See, e.g., Joint Customers Initial Comments at 13, 26; see also id. at 28–29 (‘‘The 15-month statutory limitation on refunds [in FPA section 206 proceedings] creates an incentive for the applicant to delay the proceeding in order to profit from their delay by running out the clock to enter a period where the applicant continues to collect the rate as filed (likely to later be determined unjust and unreasonable) without any ongoing refund obligation. While the statute provides for further refunds upon a showing of dilatory behavior by the applicant, it would be difficult to demonstrate such dilatory behavior when the delay in resolution is due to settlement proceedings, or the procedural schedule in a litigated proceeding. Therefore, customers are left in the position of either foregoing or prematurely ending settlement discussions in order to try to achieve a litigated outcome within the 15-month refund period.’’). 93 PJM Initial Comments at 6–7. 94 Id. at 7 (emphasis in original); see also Vistra Reply Comments at 8 (‘‘The time and resources that PJM must expend to conduct testing for the purposes of supporting individual rate cases is an anathema to the core purpose of the tests, which is system reliability.’’). 95 See ELCON Initial Comments at 5; PJM IMM Initial Comments at 22–23. PO 00000 Frm 00022 Fmt 4702 Sfmt 4702 through cost-based rates.96 It was thus intended to be a cost-of-service allocation method for assigning joint costs between the generation and transmission functions, but, as the PJM IMM argues, ‘‘[t]he false precision of the AEP Method is entirely based on arbitrary assumptions.’’ 97 The PJM IMM argues that even proponents of the AEP Methodology do not claim that the methodology’s goal is to recover only the specific costs associated with the production of reactive power, which the PJM IMM claims is not possible in most cases. The PJM IMM further argues that the AEP Methodology was not intended to define such costs. The imprecision associated with the AEP Methodology was less problematic when the total amount that a utility recovered was largely unchanged by the allocation of fixed costs between a generation and transmission function. But, as commenters point out, today most generating facilities recover their costs through competitive markets in both RTO/ISO and non-RTO/ISO regions. The AEP Methodology’s imprecision therefore becomes more significant because it can lead to arbitrary increases in the utility’s total recovery when costbased reactive power payments are added to any market recoveries.98 That is especially true when markets fail to account for separate, cost-based reactive power revenues by using standard rate making techniques (i.e., revenue crediting).99 For example, in PJM, the 96 See, e.g., Joint Customers Reply Comments at 6–7; ELCON Initial Comments at 5. 97 PJM IMM Initial Comments at 5. As a point of comparison, black start compensation also requires some cost allocation of joint costs, but this is arguably distinct from allocation for reactive power because incremental costs incurred to provide black start service can be separately identified (e.g., unlike most generators, which require power from the transmission system during start-up, black startcapable generators may have small, on-site diesel generation units, or equivalent equipment, to independently support their station power needs and other electricity-using activities during startup). See, e.g., PJM Interconnection, L.L.C., IntraPJM Tariffs, OATT Schedule 6A (12.2.0). Payment is not related only to identifiable costs. Such black start resources will also generally have a different interconnection arrangement which allows for black start service. The determination of whether a particular unit is a black start unit is ultimately defined in the applicable tariff and relates to capability rather than the presence of specific equipment. 98 PJM IMM Initial Comments at 9–10; PJM IMM Reply Comments at 4 (‘‘[T]he AEP Method allocates a portion (X percent) of the cost of the plant to MVAR production and the balance (1¥X percent) to MW production. In a pure cost of service world, the allocators add to 100% and there can be no over recovery, regardless of the value of X. But that is not true when the units operate in a competitive wholesale power market.’’). 99 See PJM IMM Reply Comments at 3 (‘‘The Commission has recognized the relevance of the issue associated with a ‘resource receiving cost- E:\FR\FM\28MRP1.SGM 28MRP1 Federal Register / Vol. 89, No. 61 / Thursday, March 28, 2024 / Proposed Rules ddrumheller on DSK120RN23PROD with PROPOSALS1 capacity market rules currently account for reactive power payments to resources by assuming average reactive power compensation of $2,546 per MWyear.100 But reactive power revenue requirements in PJM, many of which result from ‘‘black-box’’ settlements, range from roughly $1,000 per MW-year to $13,000 per MW-year.101 As the PJM IMM explains, this wide range of actual compensation, which is both above and below the amount of assumed reactive power compensation in the capacity market rules, can lead to market distortions.102 40. The challenges experienced under the Commission’s current reactive power compensation policy are exacerbated by the increasing volume of filings for reactive power compensation. Since Order No. 2003–A, and particularly in recent years, the number of reactive power filings has significantly increased.103 In turn, the amount of reactive power compensation paid to generating facilities by transmission providers and collected from transmission customers has likewise increased.104 We are concerned based rate recovery while concurrently receiving compensation for market-based rate services involves potential double recovery of costs borne by the relevant cost-based ratepayers.’ ’’ (quoting Utilization of Elec. Storage Res. for Multiple Servs. When Receiving Cost-Based Rate Recovery, 158 FERC ¶ 61,051, at P 15 (2017)); ELCON Initial Comments at 5 (‘‘[R]ecouping costs through organized markets while separately recouping the same costs through a cost-of-service rate—would result in double recovery, imposing additional and unnecessary costs on consumers.’’). 100 See PJM Interconnection, L.L.C., 182 FERC ¶ 61,073, at P 135 (2023). 101 PJM IMM Initial Comments at 21–22; see also PJM Initial Comments at 4 (‘‘There is a wide range of revenue requirements that may ultimately be agreed to by the parties to a given proceeding, and the willingness of parties to agree or not agree to a particular number may be influenced by factors completely exogenous to the actual cost and service characteristics of the unit (e.g.[,] the legal fees associated with continuing the litigation).’’). 102 PJM IMM Initial Comments at 21–22 (‘‘For example, a marginal resource with reactive revenue of $5,000 per MW-year reflected in their net ACR offer would suppress the capacity market clearing price. Conversely, a marginal resource with a reactive revenue of $1,000 per MW-year reflected in their net ACR offer would inflate the capacity market clearing price.’’). 103 See, e.g., Joint Customers Initial Comments at 4–5 (‘‘In PJM’s Dominion zone, there has been a significant increase in the number of reactive revenue requirements filings as well as a drastic increase in the proposed revenue requirements for Reactive Service.’’); Vistra Initial Comments at 10 (noting the ‘‘sheer volume of reactive power hearing and settlement proceedings in recent years’’); PJM IMM Initial Comments at 13 (explaining that as of February 2022, there were ‘‘over two dozen active proceedings’’ and that since 2016, there have been ‘‘more than 100’’ reactive power proceedings). 104 For example, as of December 2023, the total RTO-wide reactive power compensation paid to generating facilities in PJM was approximately $384 million. See PJM, Reactive Supply and Voltage VerDate Sep<11>2014 17:37 Mar 27, 2024 Jkt 262001 that transmission customers may not be receiving a roughly commensurate increase in reliability benefit.105 B. Proposed Reform 41. Having preliminarily found that allowing transmission providers to include charges associated with the supply of reactive power within the standard power factor range from generating facilities results in transmission rates that may be unjust and unreasonable, we propose, pursuant to FPA section 206,106 that a just and reasonable replacement rate is to prohibit transmission providers from including in their transmission rates any charges associated with the supply of reactive power within the standard power factor range from a generating facility. 42. Eliminating such charges ensures that transmission customers do not pay transmission rates that include costs without an economic basis or justification. Moreover, eliminating compensation is consistent with the Commission’s original statement in Order No. 2003 (as modified in Order No. 2003–A) and in subsequent cases on the non-compensability of providing reactive power within the standard power factor range. Eliminating compensation also addresses the undue discrimination concerns articulated by the Commission in Order No. 2003–A regarding the disparate treatment of affiliated and non-affiliated generating facilities, which led to the Commission’s comparability policy. By requiring the same approach to compensation for all generating facilities, which necessarily includes both affiliates and non-affiliates, we address the potential for undue discrimination by the transmission provider by providing that comparability would no longer be a justification for payment. To the extent that there are incremental costs to provide reactive power within a generating facility’s standard power factor range, we see no reason why such costs should not be reflected through energy or capacity offers made in organized and bilateral markets.107 Control Revenue Requirements 2023, https:// www.pjm.com/markets-and-operations/billingsettlements-and-credit.aspx (cell D296 in the .xls file for December 2023). 105 See also Joint Customers Initial Comments at 8–9 (citing Ill. Com. Comm’n v. FERC, 576 F.3d 470, 477 (2009)); Alliant Initial Comments at 5; MISO Transmission Owners Reply Comments at 10; Joint Customer Reply Comments at 5–6. 106 16 U.S.C. 824e. 107 See, e.g., SPP Initial Comments at 2–3 (‘‘Variable costs of generating reactive power are de minimis and are generally limited to changes in losses within the generating facility which are part PO 00000 Frm 00023 Fmt 4702 Sfmt 4702 21463 1. Eliminating Separate Compensation Will Not Affect Reliability 43. We preliminarily find that prohibiting transmission providers from including in their transmission rates any charges associated with the supply of reactive power within the standard power factor range from a generating facility is just and reasonable because compensation for providing reactive power within the standard power factor range is unnecessary to maintain reliability.108 Several commenters argue that separate reactive power compensation is necessary to maintain reliability. For example, Vistra, among others, argues that separate compensation for reactive power is necessary because without it, regions seeing increasing shares of nonsynchronous generating facilities in their generation mixes may not have sufficient reactive power.109 We preliminarily disagree with this argument because we preliminarily find that requiring transmission providers to continue paying for reactive power already required by a generating facility’s interconnection agreement is not necessary to ensure that generating facilities provide reactive power when required.110 As explained in MISO, new of the overall efficiency of the resource and, as such, are typically captured in the resource offers submitted to the SPP Integrated Marketplace.’’); PJM IMM Initial Comments at 2–3 (‘‘Payments based on cost of service approaches result in distortionary impacts on PJM markets. Elimination of the reactive revenue requirement and the recognition that capital costs are not distinguishable by function would increase prices in the capacity market. . . . The simplest way to address this distortion would be to recognize that all capacity costs are recoverable in the PJM markets.’’). 108 See CAISO Initial Comments at 5–6; Joint Customers Reply Comments at 5–6 (‘‘Despite unsubstantiated claims to the contrary, there has been no demonstration that there is any dearth of reactive power sufficient to maintain reliability in regions where reactive compensation is not based on the AEP methodology.’’); MISO Initial Comments at 6 (explaining that the ‘‘method of compensation is incidental to reliability’’ because generating facilities’ obligation to provide reactive power within the standard power factor range ‘‘ensures that reactive power will be provided to support the Transmission System.’’). 109 Vistra Comments at 4 (citing NYISO, Reliability and Market Considerations for a Grid in Transition, 25–26, 104–06 (2019), https:// www.nyiso.com/documents/20142/2224547/ Reliability-and-Market-Considerations-for-a-Gridin-Transition-20191220%20Final.pdf/61a69b2e0ca3-f18c-cc39-88a793469d50 and CAISO, Reactive Power Requirements—Automatic Voltage Regulator Systems, Docket No. ER17–490–000 (filed Dec. 5, 2016)). But see Joint Customers Reply Comments at 6 (urging ‘‘the Commission to maintain a focus on reliability as the basis for compensating for Reactive Service, but also to be wary of attempts by others to use ‘reliability’ to justify over-compensation for Reactive Service or to preserve outdated methodologies.’’). 110 See Essential Reliability Servs. & the Evolving Bulk-Power Frequency Response, Order No. 842, 83 E:\FR\FM\28MRP1.SGM Continued 28MRP1 21464 Federal Register / Vol. 89, No. 61 / Thursday, March 28, 2024 / Proposed Rules ddrumheller on DSK120RN23PROD with PROPOSALS1 and existing generating facilities will still be required to provide reactive power within the standard power factor range as a condition of obtaining and maintaining interconnection.111 Additionally, as CAISO notes, its current approach to not compensate for reactive power provided within the standard power factor range has not resulted in major issues of concern with the level of reactive power.112 44. We seek comment on the reliability impact of prohibiting transmission providers from including in their transmission rates any charges associated with the supply of reactive power within the standard power factor range from a generating facility in regions where generating facilities currently receive such compensation. 2. Eliminating Separate Compensation Does Not Preclude Generating Facilities From Recovering Their Costs 45. We preliminarily find that separate compensation for providing reactive power within the standard power factor range is not necessary for resources to be able to recover their costs. Some commenters argue that costof-service payment for reactive power is important for obtaining financing. Although the prospect of receiving separate, fixed reactive power payments may be beneficial for developing certain generating facilities, resource developers continue to develop new generating facilities in regions without such payments.113 Furthermore, the basis for these payments has always been comparability. Therefore, these arguments do not demonstrate why allowing for separate reactive power payments at the transmission provider’s discretion is just and reasonable. 46. Instead, in the context of RTO/ISO markets, we preliminarily find that it is both more efficient and less administratively burdensome for generating facilities to recover any identified reactive power costs, to the extent they exist, through energy and capacity sales,114 since competition between generating facilities may incentivize efficiency.115 Another benefit of any such market-based compensation in RTOs/ISOs is that any costs of providing reactive power within the standard power factor range would be more transparent to market participants because they would be included in RTO/ISO energy and/or capacity prices as opposed to generating facility-specific out-of-market cost-ofservice agreements. 47. The Commission has repeatedly rejected arguments that generating facilities need separate reactive power payments ‘‘since the incremental cost of reactive power service within the deadband is minimal.’’ 116 Therefore, consistent with those findings, for IPPs operating in non-RTO regions, we preliminarily find that cessation of payments for reactive power within the standard power factor range set forth in the Commission’s pro forma LGIA and SGIA does not compromise an IPP’s FR 639 (Mar. 6, 2018), 162 FERC ¶ 61,128, at P 121, order on reh’g and clarification, 164 FERC ¶ 61,135 (2018) (‘‘While the Commission has approved specific compensation for discrete services that require substantial identifiable costs, such as for frequency regulation and operating reserves, the Commission has not required specific compensation for all reliability-related costs. We agree with those commenters who observe that minimal reliability-related costs such as those incurred to provide primary frequency response, are reasonably considered to be part of the general cost of doing business, and are not specifically compensated.’’). 111 MISO, 182 FERC ¶ 61,033 at P 55. 112 CAISO Initial Comments at 5. 113 For example, as of February 21, 2024, there were 453 total generating facilities in the CAISO interconnection queue, 440 of which were nonsynchronous generating facilities. This corresponds to 122,885 MW of capacity, 120,043 MW of which comes from the non-synchronous generating facilities in the queue. See CAISO, Formatted Generator Interconnection Queue Report, https:// rimspub.caiso.com/rimsui/logon.do (last visited Feb. 21, 2024). Similarly, as of February 21, 2024, there were 947 total generating facilities in the SPP interconnection queue, 770 of which were nonsynchronous generating facilities. This corresponds to 175,243 MW of capacity, 141,879 MW of which comes from the non-synchronous generating facilities in the queue. See SPP, Generator Interconnection Active Requests, https:// opsportal.spp.org/Studies/GIActive (last visited Feb. 21, 2024). 114 See MISO Rehearing Order, 184 FERC ¶ 61,022 at P 42 (dismissing Vistra’s claim that they would be unable to recover any costs attributable to providing reactive service through mechanisms other that Schedule 2, such as in energy offers and capacity offers. The Commission noted that ‘‘[a]s to capacity offers, among the ‘going forward’ costs that can be recovered are ‘mandatory capital expenditures necessary to comply with federal . . . reliability requirements,’ which would appear to include any (hypothetical) capital investments and expenditures associated with Reactive Service. As to energy offers, Vistra does not explain the basis for its assertion that the Tariff bars including any incremental costs associated with Reactive Service (e.g., fuel costs, short-term variable operations and maintenance) in such offers.’’). 115 For example, in PJM, capital costs are included in the Net Cost of New Entry (Net CONE) parameter of the Variable Resource Requirement (VRR) curve in the capacity market and the Net CONE parameter directly affects clearing prices by affecting both the maximum capacity price and the location of the downward sloping part of the VRR. As a result, if the Commission were to eliminate reactive power compensation within the standard power factor range, the only change that would be required would be to exclude the reactive power revenues from the Net CONE parameter and to exclude any reactive power revenues from the energy and ancillary services offset from the offer caps for resources that provide reactive power. See PJM IMM Initial Comments at 21–22, 25. 116 BPA, 120 FERC ¶ 61,211 at P 21 (citing Sw. Power Pool, Inc., 119 FERC ¶ 61,199 at P 39). VerDate Sep<11>2014 17:37 Mar 27, 2024 Jkt 262001 PO 00000 Frm 00024 Fmt 4702 Sfmt 4702 ability to recover costs that it may incur in producing reactive power within such range because generating facilities have the opportunity to recover such costs in other ways, ‘‘such as through higher power sales rates of their own.’’ 117 48. Both experience in CAISO, SPP, MISO and certain non-RTO regions where generating facilities do not receive compensation for the provision of reactive power within the standard power factor range,118 and the evidence in the record to date supports these findings. Specifically, experience and evidence demonstrate that: (1) eliminating compensation has not led to an insufficient supply of reactive power in those regions; and that (2) generating facilities in these regions have been able to recover any purported costs associated with the production of reactive power. For example, CAISO notes that it ‘‘has seen no evidence to this point that resources cannot comply with reactive power dispatch instructions because they have insufficient funds for the equipment to meet the reactive power dispatch.’’ 119 As Leeward Renewable Energy, LLC, and Union of Concerned Scientists (LRE/UCS) notes, ‘‘the lack of separate reactive power compensation in CAISO or SPP means that all costs have to be recovered through the applicable PPA, which also means that those PPA prices are higher, all other variables being equal, than they would otherwise be.’’ 120 117 Id. 118 See Cal. Indep. Sys. Operator Corp., 160 FERC ¶ 61,035 at P 19. In 2017, the Commission considered the CAISO’s approach and found ‘‘a separate payment for the provision of reactive power capability inside the standard power factor range is not required, and we see no reason to require a separate cost recovery mechanism for reactive power capability based on the record here.’’ The Commission later affirmed this approach when it was proposed by different transmission providers. See PNM, 178 FERC ¶ 61,088 at P 29 (‘‘Consistent with Commission precedent, a transmission provider may decide to eliminate compensation for having the capability of providing reactive service within the standard power factor range.’’); MISO, 182 FERC ¶ 61,033 at P 55 (‘‘As stated by MISO [transmission owners] and supporting commenters, new and existing generators in MISO will still be required to provide reactive power within the standard power factor range as a condition of obtaining and maintaining an interconnection. MISO [transmission owners] do not propose to change MISO’s ability to manually redispatch individual generators for voltage control and generators will continue to be compensated under a separate Tariff mechanism if MISO directs a generation resource to provide reactive power outside of the standard power factor range.’’ (citations omitted)); see also Order No. 842, 162 FERC ¶ 61,128 at P 120 (explaining that ‘‘there are interconnection requirements for generating facilities in which the recovery of capital costs and operating expenses are not necessarily ensured.’’). 119 CAISO Initial Comments at 5–6. 120 LRE/UCS Initial Comments at 16. E:\FR\FM\28MRP1.SGM 28MRP1 Federal Register / Vol. 89, No. 61 / Thursday, March 28, 2024 / Proposed Rules 49. The record from the Notice of Inquiry contains comments arguing that removal of all reactive power compensation under the standard power factor range without a transition period or other similar mechanism has the potential to disrupt business and investment decisions for generating entities in certain markets in the near term.121 We seek comment on whether and, if so, how the elimination of separate reactive power payments will affect generating facilities’ ability to recover their costs in the markets that currently provide reactive power compensation within the standard power factor range. We also seek comment on whether, and if so how, eliminating separate reactive power compensation within the standard power factor range may affect investment decisions to build, or finish building, generation facilities, and whether, and if so how, the elimination could otherwise affect generators’ business decisions in those markets. C. Proposed Revisions for Eliminating Compensation for Reactive Power Supply Within the Standard Power Factor Range ddrumheller on DSK120RN23PROD with PROPOSALS1 50. To effectuate the changes discussed herein, we propose three revisions discussed further below. Our preliminary findings and these proposed revisions are consistent with the Commission’s previous initial statements in Order No. 2003 (which was subsequently revised in Order No. 2003–A) and in subsequent cases on the non-compensability of providing reactive power within the standard power factor range. They also address the undue discrimination concerns articulated by the Commission in Order No. 2003–A, which led to the Commission’s comparability policy.122 By requiring the same approach to compensation for all resources, which necessarily includes both affiliates and non-affiliates, there is no potential for undue discrimination by the transmission provider and 121 See, e.g., EDF Renewables Initial Comments at 11–12 (‘‘Since independent power producers . . . rely on project financing to finance their project development, predictability of the revenue stream is very important to this industry segment.); Joint Customers Reply Comments at 17 (noting that ‘‘resource developers or owners may have made the decision to invest in resources under the Commission’s currently approved methods for determining reactive compensation,’’ while also cautioning against allowing unjust reactive power rates to ‘‘remain effective indefinitely.’’); Duke Energy Comments at 4 (‘‘Developers have . . . obtained financing based on [the AEP] methodology being in place.’’). 122 See supra notes 7–9 and associated text. VerDate Sep<11>2014 17:37 Mar 27, 2024 Jkt 262001 comparability would no longer be a justification for payment. 1. Revise Schedule 2 of the Pro Forma OATT 51. We propose to revise Schedule 2 of the pro forma OATT to add the following sentence at the end of Schedule 2: ‘‘However, such rates shall not include any charges associated with the compensation to a generating facility for the supply of reactive power within the power factor range specified in its interconnection agreement.’’ This proposed revision would prohibit separate compensation for the provision of reactive power within the standard power factor range specified in an interconnection agreement. 2. Revise Section 9.6.3 of the Pro Forma Large Generator Interconnection Agreement 52. We propose to revise section 9.6.3 of the pro forma LGIA to remove the proviso: ‘‘provided that if Transmission Provider pays its own or affiliated generators for reactive power service within the specified range, it must also pay Interconnection Customer.’’ Accordingly, under our proposal here, section 9.6.3 of the pro forma LGIA would read as follows: ‘‘Payment for Reactive Power. Transmission Provider is required to pay Interconnection Customer for reactive power that Interconnection Customer provides or absorbs from the Large Generating Facility when Transmission Provider requests Interconnection Customer to operate its Large Generating Facility outside the range specified in Article 9.6.1. Payments shall be pursuant to Article 11.6 or such other agreement to which the Parties have otherwise agreed.’’ Along with the other proposed revisions, this proposed revision would prohibit a transmission provider from including in its transmission rates any charges associated with the supply of reactive power within the specified power factor range from a generating facility. Accordingly, transmission providers would be required to pay an interconnection customer for reactive power only when the transmission provider requests the interconnection customer to operate its facility outside the power factor range set forth in its interconnection agreement. 3. Revise Section 1.8.2 of the Pro Forma Small Generator Interconnection Agreement 53. We propose to revise section 1.8.2 of the pro forma SGIA to remove the following sentence: ‘‘In addition, if the Transmission Provider pays its own or affiliated generators for reactive power PO 00000 Frm 00025 Fmt 4702 Sfmt 4702 21465 service within the specified range, it must also pay the Interconnection Customer.’’ Accordingly, under our proposal here, section 1.8.2 of the pro forma SGIA would read as follows: ‘‘The Transmission Provider is required to pay the Interconnection Customer for reactive power that the Interconnection Customer provides or absorbs from the Small Generating Facility when the Transmission Provider requests the Interconnection Customer to operate its Small Generating Facility outside the range specified in article 1.8.1.’’ Along with the other proposed revisions, this proposed revision would prohibit a transmission provider from including in its transmission rates any charges associated with the supply of reactive power within the specified power factor range from a generating facility. Accordingly, as above, transmission providers would be required to pay an interconnection customer for reactive power only when the transmission provider requests the interconnection customer to operate its facility outside the power factor range set forth in its interconnection agreement. IV. Proposed Compliance Procedures 54. We propose to require each transmission provider to submit a compliance filing within 60 days of the effective date of the final rule in this proceeding revising its OATT, pro forma LGIA, and pro forma SGIA, as necessary, to comply with the requirements set forth in any final rule issued in this proceeding. In addition, we propose to allow 90 days from the date of the compliance filing for implementation of the proposed reforms to become effective. 55. To the extent that any transmission provider believes that it already complies with the reforms adopted in any final rule in this proceeding, the transmission provider would be required to demonstrate how it complies in the compliance filing required 60 days after the effective date of any final rule in this proceeding. In reviewing compliance filings, the Commission will apply the ‘‘consistent with or superior to’’ standard to deviations from the adopted pro forma language proposed by non-RTO/ISO transmission providers. In evaluating compliance filings made by RTOs/ISOs, the Commission will apply the ‘‘consistent with or superior to’’ standard to deviations from the adopted pro forma Schedule 2 and the ‘‘independent entity variation standard’’ to deviations from the pro forma LGIA and pro forma SGIA. 56. We seek comment on whether the proposed compliance and E:\FR\FM\28MRP1.SGM 28MRP1 21466 Federal Register / Vol. 89, No. 61 / Thursday, March 28, 2024 / Proposed Rules implementation timeline would allow sufficient time for changes to be implemented in response to a final rule or whether a limited transition period (beyond the 90-day implementation period proposed in this NOPR) may be necessary. Specifically, we seek comment on the following questions: • Is a transition period necessary? Please provide discussion supporting any opinion. • What factors, if any, such as potential business or investment impacts, should be considered in determining whether any transition period is appropriate, how any transition period for reactive power compensation may be structured to minimize impacts, and for what duration any transition period should last? Absent a transition period, would the final rule disrupt business and investment decisions or not? If so, what transition mechanisms other than delaying the implementation date of the final rule would minimize such disruptions and be just and reasonable? • For regions that have an established capacity market, should transmission providers be allowed to make the implementation date of their compliance filing align with the region’s capacity market timelines in order to allow costs associated with reactive power production, if any, to be incorporated into capacity market bids? Would a different transition mechanism, if any, be necessary for regions without a capacity market? Would it be unduly discriminatory or preferential to set different implementation dates for the final rule in different markets and regions? • If the Commission allows existing generation resources that have previously received compensation for reactive power supply to continue to receive compensation for a limited period while prohibiting new generation resources from receiving reactive power compensation, how should it determine eligibility for continued compensation in a manner that is just and reasonable and not unduly discriminatory or preferential? ddrumheller on DSK120RN23PROD with PROPOSALS1 V. Information Collection Statement 57. The Office of Management and Budget’s (OMB) regulations require approval of certain information collection requirements imposed by agency rules. Upon approval of a VerDate Sep<11>2014 17:37 Mar 27, 2024 Jkt 262001 collection(s) of information, OMB will assign an OMB control number and an expiration date. Respondents subject to the filing requirements of a rule will not be penalized for failing to respond to these collections of information unless the collections of information display a valid OMB control number. 58. This notice of proposed rulemaking proposes to amend the Commission’s regulations pursuant to section 206 of the Federal Power Act, to eliminate compensation to generating facilities for the provision of reactive power within the standard power factor range set forth in each generating facility’s individual interconnection agreement. To accomplish this, the Commission proposes to require each transmission provider to amend the standard large interconnection agreement and the standard small generator interconnection agreement in its open access transmission tariff to implement the reforms proposed in this NOPR. Such filings should be made under Part 35 of the Commission’s regulations. Subsequently, the proposed rule would revise the following currently approved information collections: FERC 516H (OMB control. No. 1902–0303): Pro Forma Open Access Transmission Tariff, FERC 516 (OMB control No. 1902–0096): Electric Tariff Filings, and FERC 516A (OMB control No. 1902–0203): Standardization of Small Generator Interconnection Agreements and Procedures [SGIA and SGIP]. 59. The Commission is submitting these reporting requirements to OMB for its review and approval under section 3507(d) of the Paperwork Reduction Act. Comments are solicited on whether the information will have practical utility, the accuracy of provided burden estimates, ways to enhance the quality, utility, and clarity of the information to be collected, and any suggested methods for minimizing the respondent’s burden, including the use of automated information techniques. 60. Please send comments concerning the collection of information and the associated burden estimates to: Office of Information and Regulatory Affairs, Office of Management and Budget, 725 17th Street NW, Washington, DC 20503, Attention: Desk Officer for the Federal Energy Regulatory Commission. Due to security concerns, comments should be sent electronically to the following PO 00000 Frm 00026 Fmt 4702 Sfmt 4702 email address: oira_submission@ omb.eop.gov. Comments submitted to OMB should refer to OMB Control No. 1902–0303, 1902–0096, or 1902–0203. 61. Please submit a copy of your comments on the information collection to the Commission via the eFiling link on the Commission’s website at https:// www.ferc.gov. If you are not able to file comments electronically, please send a copy of your comments to: Federal Energy Regulatory Commission, Secretary of the Commission, 888 First Street NE, Washington, DC 20426. Comments on the information collection that are sent to FERC should refer to Docket No. RM22–2–000. 62. Title: FERC 516H: Pro Forma Open Access Transmission Tariff, FERC 516: Electric Tariff Filings, and FERC 516A: Standardization of Small Generator Interconnection Agreements and Procedures [SGIA and SGIP]. 63. Action: Proposed revision of the information collection in accordance with RM22–2–000. 64. OMB Control No.: 1902–0303, 1902–0096, 1902–0203. 65. Respondents for This Rulemaking: Public utility transmission providers, including RTOs/ISOs. 66. Frequency of Information Collection: One-time compliance filing. 67. Necessity of Information: The proposed rule will require that transmission providers submit to the Commission a one-time compliance filing proposing tariff revisions. 68. Internal Review: The Commission has reviewed the changes and has determined that such changes are necessary. These requirements conform to the Commission’s need for efficient information collection, communication, and management within the energy industry in support of the Commission’s ensuring just and reasonable rates. The Commission has specific, objective support for the burden estimates associated with the information collection requirements. 69. Public Reporting Burden: The Commission’s estimate consists of our estimated effort related to updating the proposed revisions to the Pro Forma Open Access Transmission Tariff, and subsequent revisions to the Large Generator Interconnection Agreements and Small Generator Interconnection agreements and the effort related to submitting a one-time compliance filing. E:\FR\FM\28MRP1.SGM 28MRP1 21467 Federal Register / Vol. 89, No. 61 / Thursday, March 28, 2024 / Proposed Rules 70. The Commission estimates burden 123 and cost 124 as follows: A. Collection B. Number of respondents C. Annual number of responses per respondent I D. Total number of responses I E. Average burden hours & cost per response F. Total annual hour burdens & total annual cost (Column B × Column C) (Column D × Column E) G. Cost per respondent I (Column F ÷ Column B) FERC 516H: Pro Forma Open Access Transmission Tariff Transmission Providers (one-time compliance filing) 40 1 40 4 hrs.; $400 .......... 160 hrs.; $16,000 ....... $400 43 4 hrs.; $400 .......... 172 hrs.; $17,200 ....... 400 FERC 516: Electric Tariff Filings Transmission Providers (one-time compliance filing) 43 1 FERC 516A: Standardization of Small Generator Interconnection Agreements and Procedures Transmission Providers (one-time compliance filing) 43 1 43 4 hrs.; $400 .......... 172 hrs.; $17,200 ....... 400 Totals .................................................................. ...................... .......................... ...................... ............................... 504 hrs.; $50,400 ....... ...................... that would be impacted by this NOPR. As a result, we certify that the reforms proposed in this NOPR would not have a significant economic impact on a substantial number of small entities. VII. Regulatory Flexibility Act Certification 72. The Regulatory Flexibility Act of 1980 (RFA) 127 generally requires a description and analysis of proposed rules that will have significant economic impact on a substantial number of small entities. The Small Business Administration (SBA) sets the threshold for what constitutes a small business. Under SBA’s size standards,128 transmission providers under the category of Electric Bulk Power Transmission and Control (NAICS code 221121), have a size threshold of 950 employees (including the entity and its associates).129 73. We estimate that there are 43 transmission providers that are affected by the reforms proposed in this NOPR, based on the NERC Active Compliance Registry Matrix as of January 11, 2024.130 The Commission used a combination of sources to determine the number of employees within each entity using open-source data and information from Dunn & Bradstreet. We estimate that 6 of the 43 transmission providers, approximately 14% (rounded), are small entities. 74. We estimate that one-time costs (in Year 1) associated with the reforms proposed in this NOPR for one transmission provider (as shown in the table above) would be $400. Following Year 1, the Commission estimates no ongoing costs associated with this proposed rule. 75. According to SBA guidance, the determination of significance of impact ‘‘should be seen as relative to the size of the business, the size of the competitor’s business, and the impact the regulation has on larger competitors.’’ 131 We do not consider the estimated cost of $400 to be a significant economic impact for any of the entities 123 ‘‘Burden’’ is the total time, effort, or financial resources expended by persons to generate, maintain, retain, or disclose or provide information to or for a Federal agency. For further explanation of what is included in the estimated burden, refer to 5 CFR 1320.3. 124 Commission staff estimates that the respondents’ skill set (and wages and benefits) for Docket No. RM22–13–000 are comparable to those of Commission employees. Based on the Commission’s Fiscal Year 2024 average cost of $207,786/year (for wages plus benefits, for one fulltime employee), $100/hour is used. 125 Reguls. Implementing the Nat’l Env’t Pol’y Act, Order No. 486, 52 FR 47,897 (Dec. 17, 1987), FERC Stats. & Regs. Preambles 1986–1990 ¶ 30,783 (1987) (cross-referenced at 41 FERC ¶ 61,284). 126 18 CFR 380.4(a)(15). 127 5 U.S.C. 601–612. 128 13 CFR 121.201. 129 The RFA definition of ‘‘small entity’’ refers to the definition provided in the Small Business Act, which defines a ‘‘small business concern’’ as a business that is independently owned and operated and that is not dominant in its field of operation. The Small Business Administrations’ regulations at 13 CFR 121.201 define the threshold for a small Electric Bulk Power Transmission and Control entity (NAICS code 221121) to be 500 employees. See 5 U.S.C. 601(3) (citing to Section 3 of the Small Business Act, 15 U.S.C. 632). 130 North American Electric Reliability Corporation, NCR Active Entities List, (Jan. 12, 2024), NERC_Compliance_Registry_Matrix_ Excel.xlsx. 131 U.S. Small Business Administration, A Guide for Government Agencies How to Comply with the Regulatory Flexibility Act, 18 (Aug. 2017), https:// cdn.advocacy.sba.gov/wp-content/uploads/2019/ 06/21110349/How-to-Comply-with-the-RFA.pdf. ddrumheller on DSK120RN23PROD with PROPOSALS1 VI. Environmental Analysis 71. The Commission is required to prepare an Environmental Assessment or an Environmental Impact Statement for any action that may have a significant adverse effect on the human environment.125 We conclude that neither an Environmental Assessment nor an Environmental Impact Statement is required for this NOPR under § 380.4(a)(15) of the Commission’s regulations, which provides a categorical exemption for approval of actions under sections 205 and 206 of the FPA relating to the filing of schedules containing all rates and charges for the transmission or sale of electric energy subject to the Commission’s jurisdiction, plus the classification, practices, contracts, and regulations that affect rates, charges, classification, and services.126 VerDate Sep<11>2014 17:37 Mar 27, 2024 Jkt 262001 PO 00000 Frm 00027 Fmt 4702 Sfmt 4702 VIII. Comment Procedures 76. The Commission invites interested persons to submit comments on the matters and issues proposed in this document to be adopted, including any related matters or alternative proposals that commenters may wish to discuss. Comments are due May 28, 2024. Also, reply comments are due June 26, 2024. Comments must refer to Docket No. RM22–2–000, and must include the commenter’s name, the organization they represent, if applicable, and their address in their comments. All comments will be placed in the Commission’s public files and may be viewed, printed, or downloaded remotely as described in the Document Availability section below. Commenters on this proposal are not required to serve copies of their comments on other commenters. 77. The Commission encourages comments to be filed electronically via the eFiling link on the Commission’s website at https://www.ferc.gov. The Commission accepts most standard word processing formats. Documents created electronically using word E:\FR\FM\28MRP1.SGM 28MRP1 21468 Federal Register / Vol. 89, No. 61 / Thursday, March 28, 2024 / Proposed Rules processing software must be filed in native applications or print-to-PDF format and not in a scanned format. Commenters filing electronically do not need to make a paper filing. 78. Commenters that are not able to file comments electronically may file an original of their comment by USPS mail or by courier-or other delivery services. For submission sent via USPS only, filings should be mailed to: Federal Energy Regulatory Commission, Office of the Secretary, 888 First Street NE, Washington, DC 20426. Submission of filings other than by USPS should be delivered to: Federal Energy Regulatory Commission, 12225 Wilkins Avenue, Rockville, MD 20852. IX. Document Availability 79. In addition to publishing the full text of this document in the Federal Register, the Commission provides all interested persons an opportunity to view and/or print the contents of this document via the internet through the Commission’s Home Page (https:// www.ferc.gov). 80. From the Commission’s Home Page on the internet, this information is available on eLibrary. The full text of this document is available on eLibrary in PDF and Microsoft Word format for viewing, printing, and/or downloading. To access this document in eLibrary, type the docket number excluding the last three digits of this document in the docket number field. 81. User assistance is available for eLibrary and the Commission’s website during normal business hours from FERC Online Support at (202) 502–6652 (toll free at 1–866–208–3676) or email at ferconlinesupport@ferc.gov, or the Public Reference Room at (202) 502– 8371, TTY 202–502–8659. Email the Public Reference Room at public.referenceroom@ferc.gov. By direction of the Commission. Issued: March 21, 2024. Debbie-Anne A. Reese, Acting Secretary. Note: The following appendix will not appear in the Code of Federal Regulations. ddrumheller on DSK120RN23PROD with PROPOSALS1 Appendix A: List of Commenters A. Initial Commenters • Haley Benson • Nikhil Bhushan • Market Monitoring Unit of Southwest Power Pool, Inc. • Charles T. Gaunt • Duke Energy Corporation • Wolverine Power Supply Cooperative, Inc. • Nuclear Energy Institute • PJM Interconnection, L.L.C. • Electricity Consumers Resource Council • Southwest Power Pool, Inc. VerDate Sep<11>2014 17:37 Mar 27, 2024 Jkt 262001 • California Independent System Operator Corporation • State Agencies 1 • Electric Power Service Corporation • Renewable Generation Companies 2 • Midcontinent Independent System Operator, Inc. • Clean Energy Coalition 3 • Pine Gate Renewables, LLC • Edison Electric Institute • National Rural Electric Cooperative Association • New York Independent System Operator, Inc. • ISO New England Inc. • MISO Transmission Owners • PJM Power Providers Group • Vistra Corp. and Dynegy Marketing and Trade, LLC • National Hydropower Association • Alliant Energy Corporate Services, Inc. • Dominion Energy Services, Inc. • Los Angeles Department of Water and Power • Leeward Renewable Energy, LLC, and Union of Concerned Scientists • EDF Renewables, Inc. • Ameren Services Company • Electric Power Supply Association • Indicated Generation Owners 4 • Joint Customers 5 • PSEG • Independent Market Monitor for PJM • American Electric Power Service Corporation B. Reply Commenters • Renewable Generation Companies • Electric Power Supply Association • Clean Energy Coalition • Vistra Corp. and Dynegy Marketing and Trade, LLC • EDF Renewables, Inc. • PSEG • Ameren Services Company 1 State Agencies consist of the Connecticut Attorney General, the Connecticut Department of Energy and Environmental Protection, the Connecticut Office of Consumer Counsel, the Delaware Attorney General, the Delaware Division of the Public Advocate, the Office of the People’s Counsel for the District of Columbia, the Maine Office of the Public Advocate, the Massachusetts Attorney General, the Attorney General of the State of Michigan, the Minnesota Attorney General, the Oregon Attorney General, and the Rhode Island Attorney General. 2 Renewable Generation Companies consist of D.E. Shaw Renewable Investments, L.L.C., EDF Renewables, Inc., EDP Renewables North America LLC, Enel North America, Inc., Invenergy Renewables LLC, Lightsource Renewable Energy Operations, LLC, NextEra Energy Resources, LLC, Open Road Renewables, LLC, and RWE Renewables Americas, LLC. 3 Clean Energy Coalition consists of the Solar Energy Industries Association, the American Clean Power Association, Earthjustice, and the Natural Resources Defense Council. 4 Indicated Generation Owners consists of Ares EIF Management, LLC, Brookfield Renewable Trading and Marketing LP, Cogentrix Energy Power Management, LLC, and Eagle Creek Renewable Energy, LLC. 5 Joint Customers consist of Old Dominion Electric Cooperative, Northern Virginia Electric Cooperative, Inc., and Dominion Energy Services, Inc. PO 00000 Frm 00028 Fmt 4702 Sfmt 4702 • Joint Customers • MISO Transmission Owners • Independent Market Monitor for PJM [FR Doc. 2024–06556 Filed 3–27–24; 8:45 am] BILLING CODE 6717–01–P DEPARTMENT OF LABOR Occupational Safety and Health Administration 29 CFR Part 1910 [Docket No. OSHA–2007–0073] RIN 1218–AC91 Emergency Response Standard Occupational Safety and Health Administration (OSHA), DOL. ACTION: Notice of proposed rulemaking (NPRM); extension of comment period. AGENCY: OSHA is extending the period for submitting comments by 45 days to allow stakeholders interested in the NPRM on Emergency Response additional time to review the NPRM and collect information and data necessary for comment. DATES: The comment period for the NPRM that was published at 89 FR 7774 on February 5, 2024, is extended. Comments on any aspect of the NPRM must be submitted by June 21, 2024. ADDRESSES: Written comments: You may submit comments and attachments, identified by Docket No. OSHA–2007–0073, electronically at www.regulations.gov, which is the Federal e-Rulemaking Portal. Follow the online instructions for making electronic submissions. The Federal e-Rulemaking Portal at www.regulations.gov is the only way to submit comments on this NPRM. Instructions: All submissions must include the agency’s name and the docket number for this rulemaking (Docket No. OSHA–2007–0073). All comments, including any personal information you provide, are placed in the public docket without change and may be made available online at www.regulations.gov. Therefore, OSHA cautions commenters about submitting information they do not want made available to the public or submitting materials that contain personal information (either about themselves or others), such as Social Security Numbers and birthdates. Docket: To read or download comments or other material in the docket, go to Docket No. OSHA–2007– 0073 at www.regulations.gov. All comments and submissions are listed in the www.regulations.gov index; SUMMARY: E:\FR\FM\28MRP1.SGM 28MRP1

Agencies

[Federal Register Volume 89, Number 61 (Thursday, March 28, 2024)]
[Proposed Rules]
[Pages 21454-21468]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2024-06556]


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DEPARTMENT OF ENERGY

Federal Energy Regulatory Commission

18 CFR Part 35

[Docket No. RM22-2-000]


Compensation for Reactive Power Within the Standard Power Factor 
Range

AGENCY: Federal Energy Regulatory Commission, Department of Energy.

ACTION: Notice of proposed rulemaking.

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SUMMARY: The Federal Energy Regulatory Commission (Commission) proposes 
to revise Schedule 2 of its pro forma open-access transmission tariff 
(pro forma OATT), section 9.6.3 of its pro forma large generator 
interconnection agreement (LGIA), and section 1.8.2 of its pro forma 
small generator interconnection agreement (SGIA) to prohibit the 
inclusion in transmission rates of unjust and unreasonable charges 
related to the provision of reactive power within the standard power 
factor range by generating facilities. The Commission invites all 
interested persons to submit comments on the proposed reforms and in 
response to specific questions.

DATES: Comments are due May 28, 2024. Reply comments are due June 26, 
2024.

ADDRESSES: Comments, identified by docket number, may be filed in the 
following ways. Electronic filing through https://www.ferc.gov is 
preferred.
     Electronic Filing: Documents must be filed in acceptable 
native applications and print-to-PDF, but not in scanned or picture 
format.
     For those unable to file electronically, comments may be 
filed by USPS mail or by hand (including courier) delivery.
    [cir] Mail via U.S. Postal Service Only: Addressed to: Federal 
Energy Regulatory Commission, Secretary of the Commission, 888 First 
Street NE, Washington, DC 20426.
    [cir] Hand (including courier) delivery: Deliver to: Federal Energy 
Regulatory Commission, 12225 Wilkins Avenue, Rockville, MD 20852.
    The Comment Procedures section of this document contains more 
detailed filing procedures.

FOR FURTHER INFORMATION CONTACT: 

Noah Schlosser (Technical Information), Office of Energy Market 
Regulation, 888 First Street NE, Washington, DC 20426, (202) 502-8356, 
[email protected]
Jennifer Enos (Legal Information), Office of the General Counsel, 888 
First Street NE, Washington, DC 20426, (202) 502-6247, 
[email protected]

SUPPLEMENTARY INFORMATION: 

Table of Contents

------------------------------------------------------------------------
                                                               Paragraph
                                                                 Nos.
------------------------------------------------------------------------
I. Introduction.............................................           1
II. Background..............................................          10
    A. What is reactive power?..............................          10
    B. How has reactive power been compensated?.............          12
    C. Notice of Inquiry....................................          20
III. Discussion.............................................          24
    A. Need for Reform......................................          24
    1. Compensation for Providing Reactive Power Within the           28
     Standard Power Factor Range May Be Unjust and
     Unreasonable...........................................
    2. Adverse Impacts of the Commission's Current Reactive           34
     Power Compensation Policy..............................
    B. Proposed Reform......................................          41
    1. Eliminating Separate Compensation Will Not Affect              43
     Reliability............................................
    2. Eliminating Separate Compensation Does Not Preclude            45
     Generating Facilities From Recovering Their Costs......
    C. Proposed Revisions for Eliminating Compensation for            50
     Reactive Power Supply Within the Standard Power Factor
     Range..................................................
    1. Revise Schedule 2 of the Pro Forma OATT..............          51
    2. Revise Section 9.6.3 of the Pro Forma Large Generator          52
     Interconnection Agreement..............................
    3. Revise Section 1.8.2 of the Pro Forma Small Generator          53
     Interconnection Agreement..............................
IV. Proposed Compliance Procedures..........................          54
V. Information Collection Statement.........................          57
VI. Environmental Analysis..................................          71
VII. Regulatory Flexibility Act Certification...............          72
VIII. Comment Procedures....................................          76
IX. Document Availability...................................          79
------------------------------------------------------------------------

I. Introduction

    1. The Commission is proposing to revise Schedule 2 of its pro 
forma OATT to prohibit transmission providers from including in their 
transmission rates any charges associated with the supply of reactive 
power within the standard power factor range \1\ from generating 
facilities. We further propose to remove from the pro forma LGIA and 
pro forma SGIA the requirement that a transmission provider pay an 
interconnection customer for reactive power within the standard power 
factor range if the transmission provider pays its own or affiliated 
generators for the same service. Accordingly, transmission providers 
would be required to pay an interconnection customer for reactive

[[Page 21455]]

power only when the transmission provider asks the interconnection 
customer to operate its facility outside the standard power factor 
range set forth in its interconnection agreement.
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    \1\ Operating ``inside the standard power factor range'' refers 
to a generating facility providing reactive power within the power 
factor range set forth in the generating facility's interconnection 
agreement when the unit is online and synchronized to the 
transmission system.
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    2. The Commission's policy on reactive power compensation has 
evolved since issuing Order No. 888 in 1996.\2\ In Order No. 888, the 
Commission required that reactive supply and voltage control from 
generating facilities be offered as a discrete ancillary service by 
transmission providers and, to the extent feasible, charged for on the 
basis of the amount required. The Commission explained that there are 
two ways of supplying reactive power and controlling voltage. One is to 
install facilities as part of the transmission system, the cost of 
which is part of the cost of basic transmission service. The second is 
to use generating facilities to supply reactive power and voltage 
control, which must be unbundled from basic transmission service.
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    \2\ Promoting Wholesale Competition Through Open Access Non-
Discriminatory Transmission Servs. by Pub. Utils.; Recovery of 
Stranded Costs by Pub. Utils. & Transmitting Utils., Order No. 888, 
61 FR 21540 (May 10, 1996), FERC Stats. & Regs. ] 31,036, at 31,705-
07 & n.359 (1996) (cross-referenced at 75 FERC ] 61,080), order on 
reh'g, Order No. 888-A, 62 FR 12274 (Mar. 14, 1997), FERC Stats. & 
Regs. ] 31,048 (cross-referenced at 78 FERC ] 61,220), order on 
reh'g, Order No. 888-B, 81 FERC ] 61,248 (1997), order on reh'g, 
Order No. 888-C, 82 FERC ] 61,046 (1998), aff'd in relevant part sub 
nom. Transmission Access Pol'y Study Grp. v. FERC, 225 F.3d 667 
(D.C. Cir. 2000), aff'd sub nom. N. Y. v. FERC, 535 U.S. 1 (2002).
---------------------------------------------------------------------------

    3. With respect to compensation, the Commission stated that the 
transmission provider's ``rates for ancillary services should be cost-
based.'' \3\ The Commission expected, however, that transmission 
customers would be in a position to change the amount of reactive power 
service they required. The Commission also identified the possibility 
that reactive power could potentially someday be supplied by ``a 
competitive market for such service'' if ``technology or industry 
changes'' made such a market possible.
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    \3\ Id. at 31,720.
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    4. Then, in Order No. 2003, the Commission specifically addressed 
the circumstances and manner in which a transmission provider must pay 
for reactive power, inside and outside the standard power factor range 
(sometimes referred to as the ``deadband'').\4\ In Order No. 2003, the 
Commission adopted a standard agreement for the interconnection of 
large generating facilities (the pro forma LGIA), which included the 
requirement that interconnection customers maintain a composite power 
delivery at continuous rated power output at the point of 
interconnection at a power factor within the range of 0.95 leading to 
0.95 lagging \5\ when synchronized to the transmission system, unless 
the transmission provider has established a different power factor 
range. Order No. 2003 required that a transmission provider compensate 
an interconnection customer for the provision of reactive power when 
the transmission provider requests the interconnection customer to 
operate its generating facility outside the established power factor 
range. With respect to reactive power within the established power 
factor range, the Commission initially concluded that the 
interconnection customer should not be compensated for reactive power 
when operating within the range established in the interconnection 
agreement because doing so ``is only meeting [the generating 
facility's] obligation.'' \6\ But in Order No. 2003-A, the Commission 
clarified that ``if the Transmission Provider pays its own or its 
affiliated generators for reactive power within the established range, 
it must also pay the Interconnection Customer.'' \7\ This standard is 
generally referred to as the comparability standard.
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    \4\ Standardization of Generator Interconnection Agreements & 
Procs., Order No. 2003, 68 FR 49846 (Aug. 19, 2003), 104 FERC ] 
61,103, at P 546 (2003), order on reh'g, Order No. 2003-A, 69 FR 
15932 (Mar. 26, 2004), 106 FERC ] 61,220, order on reh'g, Order No. 
2003-B, 70 FR 265 (Jan. 4, 2005), 109 FERC ] 61,287 (2004), order on 
reh'g, Order No. 2003-C, 70 FR 37661 (June 30, 2005), 111 FERC ] 
61,401 (2005), aff'd sub nom. Nat'l Ass'n of Regul. Util. Comm'rs v. 
FERC, 475 F.3d 1277 (D.C. Cir. 2007).
    \5\ A generating facility's leading reactive power indicates its 
ability to absorb reactive power and its lagging reactive power 
indicates its ability to produce reactive power.
    \6\ Order No. 2003, 104 FERC ] 61,103 at P 546 (``We agree that 
the Interconnection Customer should not be compensated for reactive 
power when operating its Generating Facility within the established 
power factor range, since it is only meeting its obligation.'').
    \7\ Order No. 2003-A, 106 FERC ] 61,220 at P 416. Section 9.6.3 
of the pro forma LGIA provided as follows:
    Transmission Provider is required to pay Interconnection 
Customer for reactive power that Interconnection Customer provides 
or absorbs from the Large Generating Facility when Transmission 
Provider requests Interconnection Customer to operate its Large 
Generating Facility outside the range specified in Article 9.6.1, 
provided that if Transmission Provider pays its own or affiliated 
generators for reactive power service within the specified range, it 
must also pay Interconnection Customer.
    Similarly, section 1.8.2 of the pro forma SGIA provided as 
follows:
    The Transmission Provider is required to pay the Interconnection 
Customer for reactive power that the Interconnection Customer 
provides or absorbs from the Small Generating Facility when the 
Transmission Provider requests the Interconnection Customer to 
operate its Small Generating Facility outside the range specified in 
article 1.8.1. In addition, if the Transmission Provider pays its 
own or affiliated generators for reactive power service within the 
specified range, it must also pay the Interconnection Customer.
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    5. In sum, ``Order Nos. 2003 and 2003-A establish a reactive power 
compensation policy that, in the first instance, treats the provision 
of reactive power inside the [standard power factor range] as an 
obligation of good utility practice rather than as a compensable 
service and permits compensation inside the [standard power factor 
range] only as a function of comparability.'' \8\ The Commission took 
this approach because, where the generating facility is operating 
within the standard power factor range, it is doing no more than 
meeting its obligation as a generator, as specified in its 
interconnection agreement, to maintain the appropriate power factor 
required to maintain voltage levels for electric power injected into 
the transmission system during normal operations.\9\ By comparison, 
reactive power provided outside of the standard power factor range is 
considered an ancillary service for transmitting power across the 
transmission system to serve load,\10\ and thus, the Commission has 
required compensation for such service.
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    \8\ Bonneville Power Admin. v. Puget Sound Energy, Inc., 120 
FERC ] 61,211 (2007) (BPA), order denying reh'g and granting 
clarification, 125 FERC ] 61,273, at P 18 (2008) (BPA Rehearing 
Order).
    \9\ See, e.g., Midcontinent Indep. Sys. Operator, Inc., 182 FERC 
] 61,033 (MISO), order on reh'g, 184 FERC ] 61,022, at P 23 (2023) 
(MISO Rehearing Order) (citing Mich. Elec. Transmission Co., 97 FERC 
] 61,187, at 61,852-53 (2001) (METC)).
    \10\ Id.
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    6. The Commission has also recognized that there is little to no 
incremental capital expenditure associated with the equipment necessary 
for the production of reactive power within the standard power factor 
range. That is because, for both synchronous and non-synchronous 
generating facilities,\11\ the same equipment is used for the 
production of real power and reactive power.\12\ In

[[Page 21456]]

addition, the Commission has noted that any purported costs associated 
with such provision of reactive power can be recovered in other ways--
such as through energy or capacity sales.\13\
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    \11\ Synchronous generating facilities (e.g., coal, gas, nuclear 
resources) produce electricity in sync with the transmission system 
at the system frequency. Non-synchronous generating facilities 
(e.g., solar, wind, battery storage resources) produce electricity 
that is initially not in sync with the transmission system and use 
inverters to convert their electrical output to synchronize with the 
transmission system. See FERC Staff Report, Payment for Reactive 
Power, Docket No. AD14-7-000, 7 (Apr. 22, 2014), https://www.ferc.gov/sites/default/files/2020-05/04-11-14-reactive-power.pdf.
    \12\ MISO Rehearing Order, 184 FERC ] 61,022 at PP 29-30 (citing 
S. Co. Servs., Inc., 80 FERC ] 61,318, at 62,091 (1997) (noting also 
that the primary function of a generating plant is to produce real 
power; thus, if costs were allocated based on the ``predominant'' 
function of the equipment, ``all of the costs of generation would 
thus be assigned to real power production and there would be no 
basis for any separate reactive power charge''); BPA, 120 FERC ] 
61,211 at P 21 (finding that the incremental cost of reactive power 
service within the standard power factor range is minimal); METC, 97 
FERC at 61,852-53 (``[R]eactive power provided, not as an ancillary 
service, but rather as a `no cost' service within reactive design 
limitations, may therefore, be provided without compensation.'').
    \13\ See, e.g., MISO Rehearing Order, 184 FERC ] 61,022 at P 42; 
BPA, 120 FERC ] 61,211 at P 21; Sw. Power Pool, Inc., 119 FERC ] 
61,199, at P 39 (2007) (stating that IPPs ``are free to negotiate 
rates that they charge their customers for real power that are 
sufficient to compensate them for any costs that they may incur in 
producing reactive power within their deadbands, just as affiliated 
generators may seek to negotiate rates that they charge their 
customers that are sufficient to compensate them for the costs of 
any reactive power that they provide within their deadbands.'').
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    7. Consistent with Order Nos. 2003 and 2003-A, multiple regional 
transmission organizations (RTO), independent system operators (ISOs), 
and non RTO/ISO transmission providers have elected not to compensate 
generating facilities for the provision of reactive power within the 
standard power factor range under Schedule 2 of the OATT.\14\ Within 
these regions, there is no evidence that this lack of compensation has 
led to an insufficient supply of reactive power or that generating 
facilities in these regions have been unable to recover any costs 
associated with the production of reactive power. Additionally, the 
experiences of these regions where reactive power within the standard 
power factor range is not separately compensated indicate that 
investors are able to, and in fact do, develop generating facilities 
that can satisfy the obligations in their interconnection agreements 
without separate reactive power compensation.
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    \14\ MISO, 182 FERC ] 61,033 at P 1.
---------------------------------------------------------------------------

    8. Based on our review of the comments submitted in response to the 
Commission's Notice of Inquiry \15\ in the instant docket, as well as 
the Commission's experience in the years since the issuance of Order 
No. 2003-A, we preliminarily find that allowing transmission providers 
to compensate generating facilities, affiliated and unaffiliated, for 
providing reactive power within the standard power factor range has 
resulted in unjust and unreasonable transmission rates. This is because 
generating facilities providing reactive power within the standard 
power factor range are only meeting their obligations under their 
interconnection agreements and in accordance with good utility 
practice, and in doing so, incur no additional costs or de minimis 
costs beyond that which they already incur to provide real power.\16\ 
Accordingly, we propose to prohibit transmission providers from 
including in their transmission rates any charges associated with the 
supply of reactive power within the standard power factor range from a 
generating facility, including those owned by the transmission owner or 
its affiliates.
---------------------------------------------------------------------------

    \15\ Reactive Power Capability Compensation, 177 FERC ] 61,118 
(2021) (NOI).
    \16\ Real power, which accomplishes useful work (e.g., runs 
motors), is typically measured in megawatts (MW).
---------------------------------------------------------------------------

    9. First, we propose to add the following sentence to the end of 
Schedule 2 of the pro forma OATT: \17\ ``However, such rates shall not 
include compensation to generating facilities for the supply of 
reactive power within the power factor range specified in its 
interconnection agreement.'' Second, we propose to remove the following 
clause from the pro forma LGIA: \18\ ``provided that if Transmission 
Provider pays its own or affiliated generators for reactive power 
service within the specified range, it must also pay Interconnection 
Customer.'' Third, we propose to remove the following sentence from the 
pro forma SGIA: \19\ ``In addition, if the Transmission Provider pays 
its own or affiliated generators for reactive power service within the 
specified range, it must also pay the Interconnection Customer.''
---------------------------------------------------------------------------

    \17\ See pro forma OATT, Schedule 2.
    \18\ See pro forma LGIA, section 9.6.3.
    \19\ See pro forma SGIA, section 1.8.2.
---------------------------------------------------------------------------

II. Background

A. What is reactive power?

    10. Almost all bulk electric power is generated, transported, and 
consumed in alternating current (AC) networks. Reactive power, which is 
measured in megavolt-amperes reactive (MVAr),\20\ is a critical 
component of operating an AC electricity system and is required to 
control system voltage within appropriate ranges for efficient and 
reliable operation of the transmission system. Reactive power supports 
the voltages that must be controlled to provide for delivery of real 
power and for system reliability. Reactive power can be produced or 
absorbed \21\ by generating facilities, power electronic equipment such 
as flexible AC transmission system devices, transmission lines and 
equipment, and load. As relevant here, generating facilities must 
either produce or absorb reactive power for the transmission system to 
maintain voltage levels required to reliably supply real power from 
generation to load.
---------------------------------------------------------------------------

    \20\ MVAr is the typical unit of measurement for reactive power.
    \21\ See supra n.5.
---------------------------------------------------------------------------

    11. The power factor is the ratio of a generating facility's real 
power to its apparent power.\22\ Power factors can range from 1.0 to 
0.0, with 1.0 representing only real power and 0.0 representing only 
reactive power. Most generating facilities have interconnection 
agreements that specify a standard power factor range within which the 
generating facility must be able to operate while producing its full 
real power capacity.
---------------------------------------------------------------------------

    \22\ Apparent power is the total power output of the system 
(both real and reactive power).
---------------------------------------------------------------------------

B. How has reactive power been compensated?

    12. As noted above, the Commission's policy on reactive power 
compensation has evolved since issuing Order No. 888, which included 
provisions regarding reactive power from generating facilities as an 
ancillary service in Schedule 2 of the pro forma OATT.\23\ As relevant 
here, in Order No. 2003, the Commission adopted a standard agreement 
for the interconnection of large generating facilities (the pro forma 
LGIA). This standard agreement included the requirement that 
interconnection customers maintain a composite power delivery at 
continuous rate of power output at the generating facility's point of 
interconnection at a power factor within the range of 0.95 leading to 
0.95 lagging when synchronized to the transmission system, unless the 
transmission provider has established a different power factor range. 
Order No. 2003 required that a transmission provider compensate an 
interconnection customer for reactive power when the transmission 
provider requests that the interconnection customer operate its 
generating facility outside the established power factor range. With 
respect to reactive power within the established power factor range, 
the Commission initially concluded that the interconnection customer 
should not be compensated for reactive power when operating within the 
range established in the interconnection agreement because doing so 
``is only meeting [the generating facility's] obligation.'' \24\ But, 
in Order No. 2003-A, the Commission clarified that ``if the 
Transmission Provider pays its own or its affiliated generators for 
reactive power within the established range, it must also pay the 
Interconnection Customer.'' \25\ Order No. 2003-A also exempted wind 
generating

[[Page 21457]]

facilities from maintaining the established power factor range.\26\
---------------------------------------------------------------------------

    \23\ Order No. 888, FERC Stats. & Regs. ] 31,036 at 31,705-07 & 
n.359.
    \24\ Order No. 2003, 104 FERC ] 61,103 at P 546.
    \25\ Order No. 2003-A, 106 FERC ] 61,220 at P 416.
    \26\ Id. P 34.
---------------------------------------------------------------------------

    13. The Commission treats the provision of reactive power within 
the standard power factor range differently from that outside the 
standard power factor range. Where reactive power is provided outside 
of the standard power factor range, it is considered ``an ancillary 
service for transmitting power across the grid to serve load.'' \27\ By 
contrast, where the generating facility is operating within the 
standard power factor range, ``it is meeting its obligation as a 
generator to maintain the appropriate power factor in order to maintain 
voltage levels for energy entering the grid during normal operations.'' 
\28\ ``Put differently, reactive support by generating facilities 
operating within the standard power factor range ensures that when 
these facilities inject real power--the product that their facilities 
exist to create and sell--onto the grid under normal conditions, they 
can do their part to maintain adequate voltages and to not threaten 
reliability.'' \29\
---------------------------------------------------------------------------

    \27\ See, e.g., METC, 97 FERC at 61,852-53 (emphasis added); 
MISO Rehearing Order, 184 FERC ] 61,022 at PP 23-24.
    \28\ METC, 97 FERC at 61,852-53; see also MISO Rehearing Order, 
184 FERC ] 61,022 at PP 23-24; BPA, 120 FERC ] 61,211 at P 19; cf. 
Dynegy Midwest Generation, Inc., 125 FERC ] 61,280, at P 16 (2008) 
(``Reactive power is a localized service that is quickly used by 
transmission system components and cannot be transported over long 
distances.'').
    \29\ MISO Rehearing Order, 184 FERC ] 61,022 at P 23.
---------------------------------------------------------------------------

    14. In Order No. 2006,\30\ the Commission adopted identical power 
factor and compensation requirements for small generating facilities 
(facilities that have a capacity of no more than 20 MW) but exempted 
small wind generating facilities from the reactive power requirement. 
Subsequently, in Order No. 827,\31\ the Commission eliminated the 
exemptions for both small and large wind generating facilities, thus 
requiring those facilities to provide reactive power. As a result, all 
newly interconnecting non-synchronous generating facilities were 
required to provide reactive power within the range of 0.95 leading to 
0.95 lagging at the high-side \32\ of the generator substation 
transformer as a condition of interconnection. With respect to 
compensation, the Commission applied the existing policies on 
compensation for reactive power as articulated in Order Nos. 2003 and 
2003-A and reflected in the pro forma LGIA and SGIA. The Commission, 
however, stated that the record did not contain a sufficient basis for 
determining a method for calculating compensation for non-synchronous 
generating facilities and therefore stated that any non-synchronous 
generating facility seeking reactive power compensation would need to 
propose a method for calculating that compensation as part of its 
filing.\33\
---------------------------------------------------------------------------

    \30\ Standardization of Small Generator Interconnection 
Agreements & Procs., Order No. 2006, 111 FERC ] 61,220, order on 
reh'g, Order No. 2006-A, 70 FR 71760 (Nov. 30, 2005), 113 FERC ] 
61,195 (2005), order granting clarification, Order No. 2006-B, 71 FR 
42587 (July 27, 2006), 116 FERC ] 61,046 (2006).
    \31\ Reactive Power Requirements for Non-Synchronous Generation, 
Order No. 827, 81 FR 40793 (June 23, 2006), 155 FERC ] 61,277, order 
on clarification and reh'g, 157 FERC ] 61,003 (2016).
    \32\ High-side refers to the side of the transformer with higher 
voltages. Generally, real power must be stepped up through a 
transformer to transmission-level voltages before being injected 
into the transmission system.
    \33\ Order No. 827, 155 FERC ] 61,277 at P 52.
---------------------------------------------------------------------------

    15. Consistent with Order Nos. 2003 and 2003-A, the Commission has 
permitted transmission providers to eliminate separate compensation for 
generating facilities providing reactive power within the standard 
power factor range.\34\ In these cases, the Commission affirmed its 
determination that the provision of reactive power within the standard 
power factor range is not compensable except as a matter of 
comparability. For example, in BPA, the Commission granted a complaint 
filed by Bonneville Power Administration (BPA) arguing that the rate 
schedules of certain independent power producers (IPP) for reactive 
power were no longer just and reasonable given BPA's decision to no 
longer pay its own or affiliated generators.\35\ The Commission found 
that ``Commission policy clearly allows BPA to discontinue paying all 
its merchants for inside the deadband reactive power service.'' \36\ 
The Commission also found that a transmission provider's decision to 
end compensation for reactive power within the standard power factor 
range did not compromise an IPP's ability to recover costs that they 
may incur in producing reactive power within such range.\37\ The 
Commission stated that such generating facilities ``may be able to 
recover such costs in other ways--such as through higher power sales 
rates of their own.'' \38\ To the extent that it could be argued that 
such recovery was not feasible for IPPs, the Commission found that such 
arguments lacked plausibility ``since the incremental cost of reactive 
power service within the deadband is minimal.'' \39\ The Commission 
explained that ``[t]he purpose for which generation assets are built 
(including reactive power capability to maintain voltage levels for 
generation entering the grid) is to make sales of real power.'' \40\
---------------------------------------------------------------------------

    \34\ See, e.g., MISO, 182 FERC ] 61,033 at PP 52-53; MISO 
Rehearing Order, 184 FERC ] 61,022 at P 26; Pub. Serv. Co. of N.M., 
178 FERC ] 61,088, at PP 29-31 (2022) (PNM); Nev. Power Co., 179 
FERC ] 61,103, at PP 20-21 (2022); BPA, 120 FERC ] 61,211 at P 20; 
E.ON U.S. LLC, 119 FERC ] 61,340, at P 15 (2007); Entergy Servs., 
Inc., 113 FERC ] 61,040, at P 38 (2005).
    \35\ BPA, 120 FERC ] 61,211 at PP 19-20; BPA Rehearing Order, 
125 FERC ] 61,273 at PP 10-11.
    \36\ BPA, 120 FERC ] 61,211 at P 20.
    \37\ Id. PP 19-22.
    \38\ Id. P 21 (citing Sw. Power Pool, Inc., 119 FERC ] 61,199 at 
P 39).
    \39\ Id.
    \40\ Id.
---------------------------------------------------------------------------

    16. The Commission made similar findings in MISO, wherein it 
accepted an FPA section 205 application by Midcontinent Independent 
System Operator, Inc. (MISO) transmission owners to end generator 
compensation for the provision of reactive power within the standard 
power factor range.\41\ In accepting MISO transmission owners' 
proposal, the Commission reiterated its longstanding policy ``that the 
provision of reactive power within the standard power factor range is, 
in the first instance, an obligation of the interconnecting generator 
and good utility practice,'' such that ``MISO transmission owners do 
not have an obligation to continue to compensate an independent 
generator for reactive power within the standard power factor range 
when its own or affiliated generators are no longer being 
compensated.'' \42\ The Commission also rejected any reliance 
arguments, reasoning in part that the provision of reactive power 
within the standard power factor range required little or no 
incremental investment.\43\ In addition, the Commission found that 
generating facilities have other opportunities, beyond Schedule 2, 
through which they have the opportunity to seek to recover

[[Page 21458]]

their costs of providing reactive power.\44\
---------------------------------------------------------------------------

    \41\ MISO, 182 FERC ] 61,033 at P 53 (``Bearing in mind that the 
provision of reactive power within the standard power factor range 
is, in the first instance, an obligation of the interconnecting 
generator and good utility practice, MISO [transmission owners] do 
not have an obligation to continue to compensate an independent 
generator for reactive power within the standard power factor range 
when its own or affiliated generators are no longer being 
compensated.'' (citation omitted)); see also PNM, 178 FERC ] 61,088 
at P 29 (accepting PNM's revisions to eliminate compensation for 
reactive service under Schedule 2 and rejecting generators' 
arguments that it is ``just and reasonable for it to be compensated 
for investments made'' to provide reactive support consistent with 
interconnection requirements even though PNM elected to no longer 
pay its own or affiliated generators for such reactive power).
    \42\ MISO, 182 FERC ] 61,033 at P 53 (finding ``those protests 
that challenge these well-established policies to be collateral 
attacks on these earlier determinations.'').
    \43\ MISO Rehearing Order, 184 FERC ] 61,022 at P 29.
    \44\ Id. P 41.
---------------------------------------------------------------------------

    17. Of the six Commission-jurisdictional RTOs/ISOs, only three 
currently compensate generating facilities for reactive power provided 
within the standard power factor range. Generating facilities in PJM 
Interconnection, L.L.C. (PJM) generally use the cost-based AEP 
Methodology to calculate cost-of-service rates for the production of 
reactive power.\45\ Because the same generation equipment contributes 
to the production of both real power and reactive power, the AEP 
Methodology attempts to functionalize each piece of equipment as 
between its contribution to real power and reactive power. Then, using 
allocators calculated based on the facility's output, the AEP 
Methodology allocates the cost of each piece of equipment based on its 
relative contribution to each function.
---------------------------------------------------------------------------

    \45\ The AEP Methodology derives its name from Opinion No. 440, 
where the Commission approved AEP's, a vertically integrated 
utility, method for calculating the costs of synchronous generation 
equipment associated with the production of reactive power. See Am. 
Elec. Power Serv. Corp., Opinion No. 440, 88 FERC ] 61,141 (1999), 
order on reh'g, 92 FERC ] 61,001 (2000). In WPS Westwood, the 
Commission recommended that all generating facilities that have 
actual cost data and support documentation use the AEP Methodology. 
See WPS Westwood Generation, LLC, 101 FERC ] 61,290, at P 14 (2002).
---------------------------------------------------------------------------

    18. Generating facilities in ISO New England Inc. (ISO-NE) and New 
York Independent System Operator, Inc. (NYISO) are compensated for 
reactive power under flat rate designs that are adjusted for 
inflation.\46\ California Independent System Operator Corporation 
(CAISO),\47\ Southwest Power Pool, Inc. (SPP),\48\ and MISO \49\ do not 
pay separately for reactive power within the standard power factor 
range.
---------------------------------------------------------------------------

    \46\ NOI, 177 FERC ] 61,118 at PP 14-16.
    \47\ CAISO never provided compensation for reactive power within 
the standard power factor range. See Cal. Indep. Sys. Operator 
Corp., 160 FERC ] 61,035, at P 7 (2017) (explaining that CAISO 
considered the possibility of compensating generating facilities for 
reactive power in its stakeholder process, but decided against it, 
reasoning that the ability to provide reactive power is part of a 
generator's fixed costs, which are recovered through power purchase 
agreements).
    \48\ Sw. Power Pool, Inc., 119 FERC ] 61,199 at P 30.
    \49\ MISO, 182 FERC ] 61,033 at PP 52-66; MISO Rehearing Order, 
184 FERC ] 61,022 at PP 23-55.
---------------------------------------------------------------------------

    19. Outside the RTOs/ISOs, transmission providers that pay for the 
provision of reactive power within the standard power factor range 
generally compensate generating facilities using the AEP Methodology to 
set reactive power compensation on an individual generating facility 
basis. Many non-RTO/ISO transmission providers do not pay separately 
for reactive power provided within the standard power factor range.\50\
---------------------------------------------------------------------------

    \50\ See, e.g., Arizona Public Service Company, FERC Electric 
Tariff Vol. No. 2, Schedule 2 (Reactive Supply and Voltage Control 
from Generation or Other Sources Service) (6.0.0) (``This service 
will be provided at no charge until APS has developed a rate that 
has been filed with the Commission and allowed to be implemented; 
however, Transmission Customers taking service at transmission 
voltage levels shall be responsible for maintaining a power factor 
of  95.0%, and Transmission Customers taking service at 
distribution voltage levels shall maintain a power factor of not 
less than 90% lagging but in no event leading, unless agreed to by 
APS.''); Public Service Company of New Mexico, PNM Open Access 
Transmission Tariff, Schedule 2 (Reactive Supply and Voltage Control 
from Generation or Other Sources Service) (2.1.0) (``As of October 
1, 2021, the Effective Date of this Schedule 2, the Transmission 
Provider is not charging for Reactive Supply and Voltage Control 
from Generation or Other Sources Service from its own resources. As 
a result, there will be no separate charge for such service.'').
---------------------------------------------------------------------------

C. Notice of Inquiry

    20. On November 18, 2021, the Commission issued an NOI \51\ in the 
instant docket seeking comment on various issues regarding reactive 
power compensation and market design as a result of the significant 
changes that have taken place in the electric industry in the last two 
decades, including changes in the generation resource mix and a general 
shift away from cost-of-service rates for generating facilities selling 
into Commission-jurisdictional markets. Generally, the Commission 
sought to ``examine whether the current regime for reactive power 
capability compensation requires revisions to ensure that payments for 
reactive power capability accurately reflect the costs associated with 
reactive power capability.'' \52\ Specifically, the Commission sought 
comment on various constructs used by transmission providers to allow 
for reactive power cost recovery, including issues related to the 
application of the AEP Methodology as well as on issues regarding 
recovery of reactive power costs through existing energy and/or 
capacity markets.
---------------------------------------------------------------------------

    \51\ NOI, 177 FERC ] 61,118.
    \52\ Id. P 19.
---------------------------------------------------------------------------

    21. The Commission received 37 initial comments and 10 reply 
comments in response to the NOI. The commenters to the NOI are listed 
and group members are identified in Appendix A. Groups representing 
transmission customers, such as Joint Customers, the Electricity 
Consumers Resource Council (ELCON), and the National Rural Electric 
Cooperative Association (NRECA), believe that the AEP Methodology 
results in unjust and unreasonable rates and recommend that the 
Commission establish a new rate methodology.\53\ In particular, Joint 
Customers argue that ``reactive capability alone should not be the 
basis for compensation.'' \54\ By contrast, resource developers, power 
generation industry groups, and commenters who support the increased 
use of renewable energy argue in favor of retaining and modifying the 
AEP Methodology to address the issues discussed in the NOI.\55\
---------------------------------------------------------------------------

    \53\ Joint Customers Initial Comments at 8-13; Joint Customers 
Reply Comments at 2-10, 12-15; ELCON Initial Comments at 5-7, NRECA 
Initial Comments at 4-5.
    \54\ Joint Customers Initial Comments at 9.
    \55\ See, e.g., EDF Renewables, Inc. (EDFR) Initial Comments at 
2-4; Edison Electric Institute (EEI) Initial Comments at 5; 
Indicated Generation Owners Initial Comments at 5-7; Nuclear Energy 
Institute (NEI) Initial Comments at 4; PJM Power Providers Initial 
Comments at 2-4; Renewable Generation Companies Initial Comments at 
6-7, 11-15; Renewable Generation Companies Reply Comments at 2-5, 
10-11; Clean Energy Coalition Initial Comments at 1-5; Electric 
Power Supply Association (EPSA) Initial Comments at 2-9; Vistra 
Corp. and Dynegy Marketing and Trade, LLC (collectively, Vistra) 
Initial Comments at 6-7; Vistra Reply Comments at 6-7; Pine Gate 
Renewables, LLC (Pine Gate) Initial Comments at 7-8.
---------------------------------------------------------------------------

    22. The Independent Market Monitor for PJM (PJM IMM) contends that 
cost-of-service compensation for the provision of reactive power within 
the standard power factor range is an ``atavistic regulatory paradigm'' 
that predates the introduction of wholesale power markets and, 
therefore, is unnecessary in light of potential compensation through 
the PJM markets.\56\ ELCON states that it supports the PJM IMM's 
position and encourages the Commission to rely on ``competitive markets 
for the procurement of essential grid services such as reactive power--
rather than reliance on traditional cost-of-service rates'' in order to 
``ensure that electricity consumers pay the lowest price possible for 
reliable service.'' \57\
---------------------------------------------------------------------------

    \56\ PJM IMM Initial Comments at 2; see also PJM IMM, Comments, 
Docket No. AD16-17-000, at 1, 6-10 (filed Aug. 1, 2016) (detailing 
the PJM IMM's view that reactive power costs can--and should--be 
recovered through PJM's capacity market instead of under a cost-of-
service paradigm); Monitoring Analytics, 2020 State of the Market 
Report for PJM, 523 (Mar. 11, 2021), https://www.monitoringanalytics.com/reports/PJM_State_of_the_Market/2020.shtml (describing the PJM IMM's position and recommended 
improvements)); PJM IMM, Brief on Exceptions, Docket No. ER17-1821-
002, at 3-16 (filed June 12, 2019) (discussing the PJM IMM's 
concerns about what it termed a ``hybrid of market-based rates and 
cost of service rates''); PJM IMM, Rehearing Request, Docket No. 
ER17-1821-005, at 3-5 (filed Apr. 30, 2021) (addressing issues 
regarding the Energy and Ancillary Services Offset (E&AS Offset) and 
a generator's proposed reactive power rates).
    \57\ ELCON Initial Comments at 4-5.
---------------------------------------------------------------------------

    23. RTOs/ISOs generally limit their comments to describing the rate 
designs in their respective regions, but PJM and CAISO did provide some 
commentary

[[Page 21459]]

on the merits. While PJM does not advocate for a particular solution in 
this proceeding, PJM highlights several issues with its current 
reactive power rate scheme.\58\ Specifically, PJM asserts that 
``enormous'' amounts of time and resources must be expended to file, 
litigate, and perform testing for each individual generating facility's 
cost-of-service rate case,\59\ which PJM notes often results in a rate 
product that is ``of exceptionally poor quality for an important 
ancillary service.'' \60\ CAISO states that despite the fact that it 
does not compensate for reactive power within the standard power factor 
range, it ``has seen no evidence to this point that resources cannot 
comply with reactive power dispatch instructions because they have 
insufficient funds for the equipment to meet the reactive power 
dispatch.'' \61\
---------------------------------------------------------------------------

    \58\ PJM Initial Comments at 1-2.
    \59\ Id. at 2-3, 5-7. PJM notes that ``many other parties beyond 
the generator are drawn into the proceeding, including PJM, FERC 
Trial Staff, zonal transmission customers, transmission owners, and/
or the Independent Market Monitor for PJM, among others. These 
parties must in turn expend time and resources of their own in 
discovery and analysis of the generator's specific cost 
characteristics and claims, in order to formulate their own position 
in the proceeding and form a basis for negotiations or litigation.''
    \60\ PJM Initial Comments at 3.
    \61\ CAISO Initial Comments at 5-6.
---------------------------------------------------------------------------

III. Discussion

A. Need for Reform

    24. Since Order No. 2003-A, the Commission has permitted 
transmission providers to compensate resources for providing reactive 
power within the standard power factor range provided that, to ensure 
comparability, the transmission provider pays both affiliated and 
unaffiliated resources. But, as explained in more detail below, 
providing reactive power within the standard power factor range is a 
``no cost'' \62\ or de minimis cost service in addition to being a 
resource's obligation under its interconnection agreement and good 
utility practice. Further, the record indicates that to the extent that 
generating facilities have any purported costs associated with 
providing reactive power within the standard power factor range, these 
costs can be recovered through energy or capacity sales and do not 
require separate compensation.
---------------------------------------------------------------------------

    \62\ METC, 97 FERC at 61,852-53.
---------------------------------------------------------------------------

    25. We thus preliminarily find that where transmission providers 
require transmission customers to pay for the provision of reactive 
power within the standard power factor range, transmission rates may be 
unjust and unreasonable, as they include costs without a sufficient 
economic basis or justification.
    26. The Commission's experience since Order No. 2003-A and the 
comments submitted into this record demonstrate that where transmission 
providers provide compensation, the costs to transmission customers 
have increased substantially without any commensurate increase in 
benefits. For example, in many regions today, resources are sited 
without regard to where there is a geographic need for reactive power, 
which is significant given that (unlike real power) reactive power 
cannot be efficiently transmitted long distances. Where such resources 
are compensated for reactive power that is not needed or necessarily 
deliverable to areas of the transmission system where reactive power 
may be needed, customers may be paying for a perceived reliability 
benefit that they are not receiving.
    27. Additionally, implementing the Commission-approved AEP 
Methodology has become increasingly administratively burdensome to 
transmission providers, transmission customers, other stakeholders, and 
the Commission due to the resource- and time-intensity involved in 
determining individualized, cost-of-service reactive power rates for 
generation facilities through hearing and settlement judge 
procedures.\63\ It also often results in inconsistent rate treatment 
across facilities.
---------------------------------------------------------------------------

    \63\ Today, most reactive power filings are made by IPPs and 
concern non-synchronous resources that produce reactive power using 
different types of equipment than that contemplated by the AEP 
Methodology. Additionally, almost all filing entities (both 
synchronous and non-synchronous) have received waivers of the 
requirement to maintain their accounts under the Uniform System of 
Accounts (USofA) rules and to file a FERC Form No. 1 when they were 
granted market-based rate authority.
---------------------------------------------------------------------------

1. Compensation for Providing Reactive Power Within the Standard Power 
Factor Range May Be Unjust and Unreasonable
    28. We preliminarily find that providing compensation for the 
provision of reactive power within the standard power factor range is 
unjust and unreasonable because the generating facility already 
provides reactive power within the standard power factor range at no 
cost or de minimis cost, because such compensation may result in undue 
compensation or other market distortions, and because providing 
reactive power within the standard power factor range is an obligation 
of the generating facility as an interconnection customer and 
consistent with good utility practice.
    29. We begin by explaining why providing reactive power within the 
standard power factor range imposes no cost or de minimis cost to 
producers. Both synchronous and non-synchronous resources provide real 
and reactive power as joint products,\64\ with joint costs.\65\ For 
synchronous generating facilities, ``the same equipment is used to 
provide real and reactive power.'' \66\ Non-synchronous generating 
facilities use a different physical process to produce reactive power, 
but ``the most critical element in VAR production, the inverter,'' \67\ 
is also necessary for non-synchronous generating facilities to produce 
real power that can be injected into AC systems.\68\ In other words, 
for both synchronous and non-synchronous generating facilities, 
``[t]here are few if any identifiable costs incurred by generators in 
order to provide reactive power'' \69\ beyond the investments in 
equipment already necessary to generate and supply real power to the 
transmission system.\70\
---------------------------------------------------------------------------

    \64\ See PSC VSMPO-Avisma Corp. v. U.S., 688 F.3d 751, 756 (Fed. 
Cir. 2012) (defining ``joint products'' as ``two dissimilar end 
products that are produced from a single production process.'').
    \65\ A joint cost is an expenditure that benefits more than one 
product, and for which it is not possible to separate the 
contribution to each product. In re Permian Basin Area Rate Cases, 
390 U.S. 747, 761 n.25 (1968) (``Joint costs `are incurred when 
products cannot be separately produced.' '' (citing M. Adelman, The 
Supply and Price of Natural Gas 25 (1962))); see also 
AccountingTools, Joint Cost (Aug. 25, 2023), https://www.accountingtools.com/articles/joint-cost.
    \66\ EEI Initial Comments at 6.
    \67\ Duke Energy Corporation Initial Comments at 4.
    \68\ See also MISO Rehearing Order, 184 FERC ] 61,022 at P 30 
(``As to non-synchronous resources, the principal piece of equipment 
required for non-synchronous resources to produce reactive power is 
the inverter, which is already necessary to convert the direct 
current produced by non-synchronous resources to alternating 
current--i.e., to supply real power that can be injected into 
alternating current power systems. On rehearing and in earlier 
protests, no party points to any other equipment costs incurred by 
non-synchronous generating facilities that are attributable to 
providing Reactive Service.'' (citations omitted)).
    \69\ PJM IMM Initial Comments at 4; see also MISO Transmission 
Owners Reply Comments at 7-8.
    \70\ See, e.g., BPA, 120 FERC ] 61,211 at P 21 (finding that the 
incremental cost of reactive power service within the deadband is 
minimal); METC, 97 FERC at 61,852-53 (``[R]eactive power provided, 
not as an ancillary service, but rather as a ``no cost'' service 
within reactive design limitations, may therefore, be provided 
without compensation.''); Ariz. Pub. Serv. Co., 94 FERC ] 61,027, at 
61,080 (2001) (rejecting generators' arguments for reactive power 
compensation for operating within standard power factor range 
because the generators failed to demonstrate that ``such a 
requirement will limit the real power output of a generating unit 
and therefore will not result in any lost opportunity costs'' or 
that operating a generating unit within the proposed standard power 
factor range will ``affect the generation output of a unit'').

---------------------------------------------------------------------------

[[Page 21460]]

    30. Moreover, because real and reactive power are provided as joint 
products with joint costs, any allocation of joint fixed costs between 
real and reactive power could be viewed as inherently arbitrary.\71\ 
When separate reactive power payments were first established, utilities 
typically provided both generation and transmission as vertically 
integrated utilities under a cost-of-service regime. In such a 
construct, the allocation of costs between generation and transmission 
facilities had little significance because it affected only the 
allocation of costs between transmission and generation rates. In other 
words, prior to the advent of IPPs (which operate only generation 
facilities), market-based rates for energy, and the development of 
RTOs/ISOs and bilateral markets, the allocation of fixed costs between 
real and reactive power did not have a major effect on the overall 
revenues of a combined vertically integrated utility.\72\ However, for 
reactive power cost recovery, the introduction of RTO/ISO markets and 
bilateral transactions in non-RTO/ISO regions has provided more 
efficient and transparent means of compensating resources than the 
cost-of-service model. For example, RTO/ISO markets provide generating 
facilities with a means to recover the costs they incur to provide 
various services, such as real power sales, that rely on the same 
equipment used for reactive power supply.\73\ Additionally, generating 
facilities in non-RTO/ISO regions (e.g., IPP) can compete in bilateral 
markets to recover their investment, production, and operating costs.
---------------------------------------------------------------------------

    \71\ See PJM IMM Initial Comments at 2 (``There is no reason to 
include complex rules that arbitrarily segregate a portion of a 
resource's capital costs as related to reactive power and that 
require recovery of that arbitrary portion through guaranteed 
revenue requirement payments based on burdensome cost of service 
rate proceedings.''); id. at 3, 5, 21, 24; In re Permian Basin Area 
Rate Cases, 390 U.S. at 804 (``There is ample support for the 
Commission's judgment that the apportionment of actual costs between 
two jointly produced commodities, only one of which is regulated by 
the Commission, is intrinsically unreliable.''); Richard A. Posner, 
Natural Monopoly and Its Regulation, 21 Stan. L. Rev. 548, 595 
(1969) (``[W]here services involve joint or common costs a rational 
allocation is impossible even in theory. How much of the cost of a 
telephone handset is assignable to local and how much to interstate 
telephone service?''); see also A.A. Poultry Farms, Inc. v. Rose 
Acre Farms, Inc., 881 F.2d 1396, 1400 (7th Cir. 1989) (``How does 
one allocate the cost of activities that have joint products? 
Agencies engaged in ratemaking struggle with these problems for 
years, even decades, without producing clear answers.'').
    \72\ See N. States Power Co., 64 FERC ] 61,324, at 63,379 (1993) 
(``In general, so long as a utility was selling generation and 
transmission services on a bundled basis (i.e., full requirements 
service), the functionalization of costs between generation and 
transmission was not critical. The historical functionalization of 
costs, or bright line approach, was administratively simple, it had 
little or no impact on the overall (i.e., bundled) rate for 
requirements service, and problems involving cross-subsidization 
between the generation and transmission functions were minimal. 
However, strict application of the traditional bright line approach 
may need to be reexamined in light of changes taking place in the 
electric industry--particularly the increase in transmission-only 
service.'').
    \73\ See, e.g., PJM IMM Initial Comments at 2 (``The current 
process is an inefficient waste of time because it relies on an 
atavistic regulatory paradigm that is not relevant in the PJM market 
framework. The AEP Method[ology] was created, before the creation of 
the PJM markets, by a regulated utility that had regulatory and 
financial reasons to want to define some generation costs as 
transmission costs.''); ELCON Initial Comments at 5 (``The AEP 
Methodology was established as a workable heuristic during a period 
in which organized markets were in their infancy and nearly all new 
resources were synchronous.'').
---------------------------------------------------------------------------

    31. We recognize that the production of reactive power within the 
standard power factor range can result in certain incremental variable 
costs such as fuel, maintenance, and potentially other costs. That 
said, the Commission has repeatedly found,\74\ and commenters agree, 
that ``[v]ariable costs of generating reactive power are de minimis.'' 
\75\ Indeed, as SPP notes, variable costs ``are generally limited to 
changes in losses within the generating facility which are part of the 
overall efficiency of the resource and, as such, are typically captured 
in the resource offers.'' \76\ Similarly, Joint Customers state that, 
in CAISO, SPP, and other regions that do not separately compensate for 
reactive power within the standard power factor range, ``perhaps 
generators are adequately recovering their costs through some other 
means.'' \77\
---------------------------------------------------------------------------

    \74\ MISO Rehearing Order, 184 FERC ] 61,022 at PP 29-31 
(finding that providing reactive service requires ``little or no 
incremental investment'' by both synchronous and non-synchronous 
resources); PJM Interconnection, L.L.C., 151 FERC ] 61,097, at PP 7, 
28 (2015) (finding that non-synchronous generating facilities are 
comparable to traditional synchronous generating facilities, in that 
there are for both types of generating facilities very little if any 
incremental costs incurred to provide reactive power); Panda 
Stonewall, LLC, 176 FERC ] 61,072, at P 6 n.9 (2021) (stating that 
Panda Stonewall's annual revenue requirement of $2,051,894 reflected 
a heating losses component of $10,018). We note that the heating 
losses component reflects the incremental cost of providing reactive 
power.
    \75\ SPP Initial Comments at 2; see also PJM IMM Initial 
Comments at 4.
    \76\ SPP Initial Comments at 2-3.
    \77\ Joint Customers Initial Comments at 9; see also PJM IMM 
Initial Comments at 1-4; CAISO Initial Comments at 3-4; Dominion 
Initial Comments at 12; MISO, 182 FERC ] 61,033 at P 58 (``[J]ust as 
the MISO [transmission owners'] generators may try to recover their 
lost revenue through higher power sales rates, so too may 
independent power producers try to recover their lost revenue 
through their own higher power sales rates.''); BPA, 120 FERC ] 
61,211 at P 21; Sw. Power Pool, Inc., 119 FERC ] 61,199 at P 39 
(stating that IPPs ``are free to negotiate rates that they charge 
their customers for real power that are sufficient to compensate 
them for any costs that they may incur in producing reactive power 
within their deadbands, just as affiliated generators may seek to 
negotiate rates that they charge their customers that are sufficient 
to compensate them for the costs of any reactive power that they 
provide within their deadbands.'').
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    32. By contrast, but outside the scope of this rulemaking, the 
production of reactive power outside of the standard power factor 
range, for which transmission providers are required to provide 
compensation, may result in increased costs, including opportunity 
costs to the generating facility.\78\ As such, if the transmission 
provider requires a generating facility to provide reactive power 
outside of the standard power factor range, the generating facility may 
have to ``reduce its MW output in order to comply with such an 
instruction[,]'' which could limit the generating facility's 
opportunity to receive compensation for real power sales.\79\
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    \78\ See, e.g., SPP Initial Comments at 2 (``SPP's current 
Schedule 2 rate per MVArh was calculated to represent the cost of 
reactive power production from recently constructed generators so as 
to reflect the upper end of such costs. This rate is applied to 
compensate qualifying generators located throughout the SPP region 
that provide reactive power support outside a power factor dead 
band.'' (emphasis added) (citations omitted)).
    \79\ CAISO Initial Comments at 4.
---------------------------------------------------------------------------

    33. Lastly, consistent with Order No. 2003 and multiple subsequent 
Commission orders since then, generating facilities must produce 
reactive power in order to be allowed to interconnect to the 
transmission system, and the industry has recognized that regulating 
voltage among interconnected generating facilities is a necessary 
component of good utility practice in an interconnected transmission 
system. For example, CAISO states that ``[t]he rationale for the 
CAISO's existing approach to reactive power compensation is that the 
reactive power ranges called for in each interconnection agreement 
represent a reasonable range of what a generator is expected to provide 
the CAISO without additional compensation in accordance with good 
utility practice and as a condition of being part of the CAISO markets 
and CAISO grid.'' \80\ The Commission, therefore, has required 
generating facilities to provide reactive power within the standard 
power factor range under their interconnection agreements and good 
utility practice.\81\

[[Page 21461]]

Thus, the obligation for generating facilities to provide reactive 
power within the standard power factor range pursuant to their 
interconnection agreements is separate from any compensation for 
reactive power. In turn, because providing reactive power within the 
standard power factor range is already obligated (a no cost or de 
minimis cost service), compensating for providing such reactive power 
could result in undue compensation to generating facilities \82\ at the 
expense of transmission customers.
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    \80\ CAISO Initial Comments at 3.
    \81\ See, e.g., MISO, 182 FERC ] 61,033 at P 53 (``Bearing in 
mind that the provision of reactive power within the standard power 
factor range is, in the first instance, an obligation of the 
interconnecting generator and good utility practice, MISO 
[transmission owners] do not have an obligation to continue to 
compensate an independent generator for reactive power within the 
standard power factor range when its own or affiliated generators 
are no longer being compensated.'' (citations omitted)); id. P 54 
(``We find unpersuasive protesters arguments that it is not just and 
reasonable to eliminate compensation for Reactive Service within the 
standard power factor range because generators have come to rely on 
the compensation for Reactive Service in order for the generators to 
remain financially viable. The Commission has previously rejected 
such arguments, finding that all newly interconnecting generators 
are required to provide reactive power within the power factor range 
of 0.95 leading to 0.95 lagging as a condition of interconnection.'' 
(citations omitted)); PNM, 178 FERC ] 61,088 at P 29 (rejecting 
generator's arguments that it is ``just and reasonable for it to be 
compensated for investments made'' to provide reactive support 
consistent with interconnection requirements even though 
transmission provider elected to no longer pay its own or affiliate 
generators for such reactive power); Nev. Power Co., 179 FERC ] 
61,103 at P 22 (finding that the generating companies' argument, 
``that it is not just and reasonable to eliminate their compensation 
for reactive service because they made investments in their 
generating facilities based on the expectation that they would 
receive compensation for reactive service,'' unpersuasive because 
all newly interconnecting generators are required to provide 
reactive power within the standard power factor range as a condition 
of interconnection); Order No. 2003, 104 FERC ] 61,103 at P 546.
    \82\ See Belmont Mun. Light Dep't v. FERC, 38 F.4th 173, 179, 
186 (D.C. Cir. 2022) (finding that the Commission's approval of a 
portion of ISO-NE's Inventoried Energy Program ``was not reasoned 
decision making'' and ``thwart[ed] the [Commission's] own 
`longstanding policy that rate incentives must be prospective and 
that there must be a connection between the incentive and the 
conduct meant to be induced' '' because it would compensate market 
participants for conduct they already engage in as part of standard 
business operations). Compensating for reactive power that is 
already required for interconnection purposes could create a 
``windfall'' as suggested by the D.C. Circuit in Belmont. Id. at 186 
(citing San Diego Gas & Elec. Co. v. FERC, 913 F.3d 127, 137 (D.C. 
Cir. 2019)). But see Order No. 2003-C, 111 FERC ] 61,401 at P 42 
(finding that because providing reactive power within the 
established range is an ``important service,'' payment for such 
service does not constitute a ``windfall.'').
---------------------------------------------------------------------------

2. Adverse Impacts of the Commission's Current Reactive Power 
Compensation Policy
    34. In the years since the issuance of Order No. 2003-A, numerous 
issues have arisen in regions that provide compensation to generators 
for the provision of reactive power within the standard power factor 
range.
    35. First, compensation for reactive power within the standard 
power factor range is not tied to whether there is a particular 
geographic need for reactive power. As noted above, reactive power 
cannot be transferred over long distances across the transmission 
system and, as a result, the reliability benefits of a generating 
facility's reactive power depend, in part, on its location.\83\ But, 
compensation in a region for reactive power within the standard power 
factor range does not vary based on location, meaning that some 
generating facilities are compensated for reactive power that is not 
needed at the generating facilities' location on the transmission 
system. As the MISO transmission owners argue, ``[t]he current 
framework is . . . unjust and unreasonable because resources are being 
paid for reactive power capability in geographic areas where not all of 
the available reactive power is necessary. There are service areas with 
concentrations of generation but very little load, creating an 
exporting region where load pays for reactive capability that is 
unneeded.'' \84\ Joint Customers add that, with the vastly increased 
amount of generation and increase in the number of generators seeking 
reactive compensation, the Commission ``should reconsider whether 
unbounded payment for reactive power capability is appropriate, or, to 
the contrary, whether transmission customers are paying for capability 
for which they do not receive commensurate benefits.'' \85\ It appears 
that under the current framework, generating facilities are eligible to 
receive cost-based reactive power payments that do not reflect the 
reliability benefits of the reactive power at each facility's location 
(i.e., the extent to which the generating facility supports the voltage 
of the transmission system), and that the reliability benefit may be 
zero for certain generating facilities.
---------------------------------------------------------------------------

    \83\ FERC Staff Report, Payment for Reactive Power, Docket No. 
AD14-7-000, 5 (Apr. 22, 2014), https://www.ferc.gov/sites/default/files/2020-05/04-11-14-reactive-power.pdf.
    \84\ MISO Transmission Owners Initial Comments at 7-8; see also 
Joint Customers Initial Comments at 8-9; Alliant Initial Comments at 
4; NYISO, Reliability and Market Considerations for a Grid in 
Transition, at 105 (2019), https://www.nyiso.com/documents/20142/2224547/Reliability-and-Market-Considerations-for-a-Grid-in-Transition-20191220%20Final.pdf/61a69b2e-0ca3-f18c-cc39-88a793469d50 
(``Moreover, because voltage support needs are local, the NYISO will 
need voltage support within specific narrow regions, not necessarily 
at the locations at which resources able to provide reactive power 
without incurring substantial commitment costs may be located.'').
    \85\ Joint Customers Initial Comments at 8-9.
---------------------------------------------------------------------------

    36. Second, many commenters explain that in regions that allow 
generating facilities to file individualized cost-of-service reactive 
power rates, the process for determining those rates has proven to be 
resource-intensive, time-intensive, and administratively burdensome for 
ratepayers, transmission providers, and market participants.\86\ 
Moreover, commenters explain that in addition to being burdensome, the 
resulting black box settlements produce a ``rate product'' that is ``of 
exceptionally poor quality for an important ancillary service.'' \87\
---------------------------------------------------------------------------

    \86\ Id. at 4-5, 12-13 (``[T]he case-by-case approach to 
reactive capability rates based on the AEP methodology makes it very 
difficult for proceedings to be resolved in an efficient manner.''); 
PJM IMM Initial Comments at 2, 4 (noting that ``[a]pplying cost of 
service rules is costly and burdensome and unnecessary'' and 
asserting that ``[r]emoving cost of service rules would avoid the 
significant waste of resources incurred to develop unneeded cost of 
service rates''); PJM Initial Comments at 10 (``[T]he current 
construct for reactive power capability compensation in PJM imposes 
a significant administrative burden on PJM and its resource owners, 
both in terms of settlements and testing.''); Dominion Initial 
Comments at 2-3 (noting that settlement proceedings are time 
consuming and not transparent); see also Clean Energy Coalition 
Reply Comments at 5; ELCON Initial Comments at 6-7; Renewable 
Generation Reply Comments at 25; EDFR Initial Comments at 4-5; Pine 
Gate Renewables Initial Comments at 6-7; PJM Power Providers Group 
Initial Comments at 4-5; American Electric Power Service Corporation 
Initial Comments at 2-3; EPSA Initial Comments at 2; Nuclear Energy 
Institute Initial Comments at 6-7; PJM IMM Initial Comments at 2 
(``Most reactive proceedings for generators in PJM are resolved in 
black box settlements that fail to address the merits of the cost 
support provided, result from an unsupported split the difference 
approach, and that, not surprisingly, produce a wide, unreasonable 
and discriminatory disparity among the rates per paid per MW-
year.'').
    \87\ PJM Initial Comments at 3; see also PJM IMM Initial 
Comments at 2.
---------------------------------------------------------------------------

    37. As noted in the NOI, most of the filings at the Commission 
seeking to establish rates for reactive power compensation are made by 
generating facilities (both synchronous and non-synchronous) that have 
received waivers of the Commission's requirement to maintain their 
accounts under the USofA rules and to file FERC Form No. 1.\88\ Due, in 
part, to the lack

[[Page 21462]]

of availability of this cost-of-service information, many of these 
filings are set for hearing and settlement judge procedures.\89\ Many 
commenters, including Joint Customers, note that these settlement 
proceedings ``require a significant expenditure of resources that 
include legal and technical consultants,'' and while many of the cases 
settle on a ``black box'' basis, ``significant effort is undertaken by 
the Joint Customers [and other participants] in order to obtain 
information necessary to perform an AEP-like calculation and develop 
settlement proposals.'' \90\ The PJM IMM notes that, in its experience, 
``[m]ost reactive proceedings for generators in PJM are resolved in 
black box settlements that fail to address the merits of the cost 
support provided, result from an unsupported split the difference 
approach, and that, not surprisingly, produce a wide, unreasonable and 
discriminatory disparity among the rates paid per MW-year.'' \91\ Joint 
Customers also note that the time-consuming process for resolving 
individual reactive service rate proceedings may leave customers 
without adequate refund protection.\92\
---------------------------------------------------------------------------

    \88\ The Commission's accounting and reporting requirements are 
particularly important to the evaluation and monitoring of cost-
based rates. See, e.g., Alcoa Power Generating Inc., 172 FERC ] 
61,052, at P 29 (2020); Third-Party Provision of Ancillary Servs.; 
Acct. & Fin. Reporting for New Elec. Storage Technologies, Order No. 
784, 78 FR 46178 (July 30, 2013), 144 FERC ] 61,056 (2013) 
(accounting and reporting requirements ``support the rate oversight 
needs of both this Commission and State Commissions'' and are 
``important in developing and monitoring rates, making policy 
decisions, compliance and enforcement initiatives, and informing the 
Commission and the public about the activities of entities that are 
subject to these accounting and reporting requirements.''); Carville 
Energy LLC, 104 FERC ] 61,252, at 61,833 n.13 (2003) (``For example, 
non-exempt public utilities keep financial records, required by this 
Commission, which, among other things, are designed to aid in the 
development of the cost-based rates.'' (emphasis added)).
    \89\ Indeed, as the Commission has explained, Parts 41, 101, and 
141 of its regulations are critical to its statutory obligation 
under sections 205 and 206 of the FPA to ensure that rates are just, 
reasonable, and not unduly discriminatory or preferential. See PSEG 
Fossil, LLC, 97 FERC ] 61,211, at 61,920-21 (2001) (PSEG), reh'g 
denied, 98 FERC ] 61,169 (2002). Moreover, the Commission has stated 
that customers subject to cost-based rates have a right to cost data 
so that they may evaluate the ongoing reasonableness of their rates. 
See also PSEG, 97 FERC at 61,920-21.
    \90\ Joint Customers Initial Comments at 5. When the cases do 
not settle, Joint Customers note that even more resources must be 
expended to litigate the individual revenue requirement proposal. 
For example, Joint Customers note that the Panda Stonewall 
proceeding lasted four years from the effective date of Panda's 
reactive service rate to the Commission's order establishing the 
just and reasonable rate. Id. (citing Panda Stonewall, LLC, Opinion 
No. 574, 174 FERC ] 61,266, reh'g denied, 175 FERC ] 62,132 (2023)). 
During this time, Joint Customers note that they and others paid the 
approximately $6.2 million annual revenue requirement filed by 
Panda. Joint Customers state that the Commission's Order on Initial 
Decision established an approximately $2 million annual revenue 
requirement. Joint Customers note that this difference resulted in 
``approximately $17 million in overcollection and delayed refunds 
due to customers.'' Id.
    \91\ PJM IMM Initial Comments at 2. Many other commenters 
express concern over the lack of transparency associated with how 
these rates are calculated. See, e.g., American Electric Power 
Service Corporation Initial Comments at 2; Renewable Generation 
Companies Initial Comments at 22-23; ELCON Initial Comments at 6-7; 
Joint Customers Initial Comments at 6; PJM Initial Comments at 3-4, 
11; Nuclear Energy Institute Initial Comments at 6-7; PSE&G Initial 
Comments at 10.
    \92\ See, e.g., Joint Customers Initial Comments at 13, 26; see 
also id. at 28-29 (``The 15-month statutory limitation on refunds 
[in FPA section 206 proceedings] creates an incentive for the 
applicant to delay the proceeding in order to profit from their 
delay by running out the clock to enter a period where the applicant 
continues to collect the rate as filed (likely to later be 
determined unjust and unreasonable) without any ongoing refund 
obligation. While the statute provides for further refunds upon a 
showing of dilatory behavior by the applicant, it would be difficult 
to demonstrate such dilatory behavior when the delay in resolution 
is due to settlement proceedings, or the procedural schedule in a 
litigated proceeding. Therefore, customers are left in the position 
of either foregoing or prematurely ending settlement discussions in 
order to try to achieve a litigated outcome within the 15-month 
refund period.'').
---------------------------------------------------------------------------

    38. Third, the process for testing and verification under the AEP 
Methodology is unduly burdensome. Under that process, resources must 
coordinate with the transmission provider to test and verify capability 
to produce reactive power under certain conditions, which often 
requires multiple tests over a series of months and that yields 
inconsistent results across resources. PJM notes that this has caused a 
``significant influx of resources that are not [otherwise] required to 
test under PJM Manual 14-D . . . seeking to test solely for purposes of 
filing and/or litigating reactive power capability cases.'' \93\ PJM 
notes that ``under the current regulatory structure, rather than PJM 
spending time and resources testing units based on PJM's operational 
needs as the Transmission Provider, PJM is now often spending time and 
resources testing units based on the resource owner's need to file and 
litigate its individual cost-of-service rate case.'' \94\
---------------------------------------------------------------------------

    \93\ PJM Initial Comments at 6-7.
    \94\ Id. at 7 (emphasis in original); see also Vistra Reply 
Comments at 8 (``The time and resources that PJM must expend to 
conduct testing for the purposes of supporting individual rate cases 
is an anathema to the core purpose of the tests, which is system 
reliability.'').
---------------------------------------------------------------------------

    39. Fourth, as discussed above, in regions where resources recover 
their costs by participating in organized competitive wholesale 
markets, providing separate compensation for the provision of reactive 
power within the standard power factor range risks overcompensation and 
market distortion in ways that did not exist prior to the existence of 
organized markets.\95\ As noted above, the AEP Methodology originated 
in an era of vertically integrated utilities, when most utilities 
(including AEP) filed FERC Form No. 1s, used the USofA to classify 
their costs, and recovered those costs entirely through cost-based 
rates.\96\ It was thus intended to be a cost-of-service allocation 
method for assigning joint costs between the generation and 
transmission functions, but, as the PJM IMM argues, ``[t]he false 
precision of the AEP Method is entirely based on arbitrary 
assumptions.'' \97\ The PJM IMM argues that even proponents of the AEP 
Methodology do not claim that the methodology's goal is to recover only 
the specific costs associated with the production of reactive power, 
which the PJM IMM claims is not possible in most cases. The PJM IMM 
further argues that the AEP Methodology was not intended to define such 
costs. The imprecision associated with the AEP Methodology was less 
problematic when the total amount that a utility recovered was largely 
unchanged by the allocation of fixed costs between a generation and 
transmission function. But, as commenters point out, today most 
generating facilities recover their costs through competitive markets 
in both RTO/ISO and non-RTO/ISO regions. The AEP Methodology's 
imprecision therefore becomes more significant because it can lead to 
arbitrary increases in the utility's total recovery when cost-based 
reactive power payments are added to any market recoveries.\98\ That is 
especially true when markets fail to account for separate, cost-based 
reactive power revenues by using standard rate making techniques (i.e., 
revenue crediting).\99\ For example, in PJM, the

[[Page 21463]]

capacity market rules currently account for reactive power payments to 
resources by assuming average reactive power compensation of $2,546 per 
MW-year.\100\ But reactive power revenue requirements in PJM, many of 
which result from ``black-box'' settlements, range from roughly $1,000 
per MW-year to $13,000 per MW-year.\101\ As the PJM IMM explains, this 
wide range of actual compensation, which is both above and below the 
amount of assumed reactive power compensation in the capacity market 
rules, can lead to market distortions.\102\
---------------------------------------------------------------------------

    \95\ See ELCON Initial Comments at 5; PJM IMM Initial Comments 
at 22-23.
    \96\ See, e.g., Joint Customers Reply Comments at 6-7; ELCON 
Initial Comments at 5.
    \97\ PJM IMM Initial Comments at 5. As a point of comparison, 
black start compensation also requires some cost allocation of joint 
costs, but this is arguably distinct from allocation for reactive 
power because incremental costs incurred to provide black start 
service can be separately identified (e.g., unlike most generators, 
which require power from the transmission system during start-up, 
black start-capable generators may have small, on-site diesel 
generation units, or equivalent equipment, to independently support 
their station power needs and other electricity-using activities 
during start-up). See, e.g., PJM Interconnection, L.L.C., Intra-PJM 
Tariffs, OATT Schedule 6A (12.2.0). Payment is not related only to 
identifiable costs. Such black start resources will also generally 
have a different interconnection arrangement which allows for black 
start service. The determination of whether a particular unit is a 
black start unit is ultimately defined in the applicable tariff and 
relates to capability rather than the presence of specific 
equipment.
    \98\ PJM IMM Initial Comments at 9-10; PJM IMM Reply Comments at 
4 (``[T]he AEP Method allocates a portion (X percent) of the cost of 
the plant to MVAR production and the balance (1-X percent) to MW 
production. In a pure cost of service world, the allocators add to 
100% and there can be no over recovery, regardless of the value of 
X. But that is not true when the units operate in a competitive 
wholesale power market.'').
    \99\ See PJM IMM Reply Comments at 3 (``The Commission has 
recognized the relevance of the issue associated with a `resource 
receiving cost-based rate recovery while concurrently receiving 
compensation for market-based rate services involves potential 
double recovery of costs borne by the relevant cost-based 
ratepayers.' '' (quoting Utilization of Elec. Storage Res. for 
Multiple Servs. When Receiving Cost-Based Rate Recovery, 158 FERC ] 
61,051, at P 15 (2017)); ELCON Initial Comments at 5 (``[R]ecouping 
costs through organized markets while separately recouping the same 
costs through a cost-of-service rate--would result in double 
recovery, imposing additional and unnecessary costs on 
consumers.'').
    \100\ See PJM Interconnection, L.L.C., 182 FERC ] 61,073, at P 
135 (2023).
    \101\ PJM IMM Initial Comments at 21-22; see also PJM Initial 
Comments at 4 (``There is a wide range of revenue requirements that 
may ultimately be agreed to by the parties to a given proceeding, 
and the willingness of parties to agree or not agree to a particular 
number may be influenced by factors completely exogenous to the 
actual cost and service characteristics of the unit (e.g.[,] the 
legal fees associated with continuing the litigation).'').
    \102\ PJM IMM Initial Comments at 21-22 (``For example, a 
marginal resource with reactive revenue of $5,000 per MW-year 
reflected in their net ACR offer would suppress the capacity market 
clearing price. Conversely, a marginal resource with a reactive 
revenue of $1,000 per MW-year reflected in their net ACR offer would 
inflate the capacity market clearing price.'').
---------------------------------------------------------------------------

    40. The challenges experienced under the Commission's current 
reactive power compensation policy are exacerbated by the increasing 
volume of filings for reactive power compensation. Since Order No. 
2003-A, and particularly in recent years, the number of reactive power 
filings has significantly increased.\103\ In turn, the amount of 
reactive power compensation paid to generating facilities by 
transmission providers and collected from transmission customers has 
likewise increased.\104\ We are concerned that transmission customers 
may not be receiving a roughly commensurate increase in reliability 
benefit.\105\
---------------------------------------------------------------------------

    \103\ See, e.g., Joint Customers Initial Comments at 4-5 (``In 
PJM's Dominion zone, there has been a significant increase in the 
number of reactive revenue requirements filings as well as a drastic 
increase in the proposed revenue requirements for Reactive 
Service.''); Vistra Initial Comments at 10 (noting the ``sheer 
volume of reactive power hearing and settlement proceedings in 
recent years''); PJM IMM Initial Comments at 13 (explaining that as 
of February 2022, there were ``over two dozen active proceedings'' 
and that since 2016, there have been ``more than 100'' reactive 
power proceedings).
    \104\ For example, as of December 2023, the total RTO-wide 
reactive power compensation paid to generating facilities in PJM was 
approximately $384 million. See PJM, Reactive Supply and Voltage 
Control Revenue Requirements 2023, https://www.pjm.com/markets-and-operations/billing-settlements-and-credit.aspx (cell D296 in the 
.xls file for December 2023).
    \105\ See also Joint Customers Initial Comments at 8-9 (citing 
Ill. Com. Comm'n v. FERC, 576 F.3d 470, 477 (2009)); Alliant Initial 
Comments at 5; MISO Transmission Owners Reply Comments at 10; Joint 
Customer Reply Comments at 5-6.
---------------------------------------------------------------------------

B. Proposed Reform

    41. Having preliminarily found that allowing transmission providers 
to include charges associated with the supply of reactive power within 
the standard power factor range from generating facilities results in 
transmission rates that may be unjust and unreasonable, we propose, 
pursuant to FPA section 206,\106\ that a just and reasonable 
replacement rate is to prohibit transmission providers from including 
in their transmission rates any charges associated with the supply of 
reactive power within the standard power factor range from a generating 
facility.
---------------------------------------------------------------------------

    \106\ 16 U.S.C. 824e.
---------------------------------------------------------------------------

    42. Eliminating such charges ensures that transmission customers do 
not pay transmission rates that include costs without an economic basis 
or justification. Moreover, eliminating compensation is consistent with 
the Commission's original statement in Order No. 2003 (as modified in 
Order No. 2003-A) and in subsequent cases on the non-compensability of 
providing reactive power within the standard power factor range. 
Eliminating compensation also addresses the undue discrimination 
concerns articulated by the Commission in Order No. 2003-A regarding 
the disparate treatment of affiliated and non-affiliated generating 
facilities, which led to the Commission's comparability policy. By 
requiring the same approach to compensation for all generating 
facilities, which necessarily includes both affiliates and non-
affiliates, we address the potential for undue discrimination by the 
transmission provider by providing that comparability would no longer 
be a justification for payment. To the extent that there are 
incremental costs to provide reactive power within a generating 
facility's standard power factor range, we see no reason why such costs 
should not be reflected through energy or capacity offers made in 
organized and bilateral markets.\107\
---------------------------------------------------------------------------

    \107\ See, e.g., SPP Initial Comments at 2-3 (``Variable costs 
of generating reactive power are de minimis and are generally 
limited to changes in losses within the generating facility which 
are part of the overall efficiency of the resource and, as such, are 
typically captured in the resource offers submitted to the SPP 
Integrated Marketplace.''); PJM IMM Initial Comments at 2-3 
(``Payments based on cost of service approaches result in 
distortionary impacts on PJM markets. Elimination of the reactive 
revenue requirement and the recognition that capital costs are not 
distinguishable by function would increase prices in the capacity 
market. . . . The simplest way to address this distortion would be 
to recognize that all capacity costs are recoverable in the PJM 
markets.'').
---------------------------------------------------------------------------

1. Eliminating Separate Compensation Will Not Affect Reliability
    43. We preliminarily find that prohibiting transmission providers 
from including in their transmission rates any charges associated with 
the supply of reactive power within the standard power factor range 
from a generating facility is just and reasonable because compensation 
for providing reactive power within the standard power factor range is 
unnecessary to maintain reliability.\108\ Several commenters argue that 
separate reactive power compensation is necessary to maintain 
reliability. For example, Vistra, among others, argues that separate 
compensation for reactive power is necessary because without it, 
regions seeing increasing shares of non-synchronous generating 
facilities in their generation mixes may not have sufficient reactive 
power.\109\ We preliminarily disagree with this argument because we 
preliminarily find that requiring transmission providers to continue 
paying for reactive power already required by a generating facility's 
interconnection agreement is not necessary to ensure that generating 
facilities provide reactive power when required.\110\ As explained in 
MISO, new

[[Page 21464]]

and existing generating facilities will still be required to provide 
reactive power within the standard power factor range as a condition of 
obtaining and maintaining interconnection.\111\ Additionally, as CAISO 
notes, its current approach to not compensate for reactive power 
provided within the standard power factor range has not resulted in 
major issues of concern with the level of reactive power.\112\
---------------------------------------------------------------------------

    \108\ See CAISO Initial Comments at 5-6; Joint Customers Reply 
Comments at 5-6 (``Despite unsubstantiated claims to the contrary, 
there has been no demonstration that there is any dearth of reactive 
power sufficient to maintain reliability in regions where reactive 
compensation is not based on the AEP methodology.''); MISO Initial 
Comments at 6 (explaining that the ``method of compensation is 
incidental to reliability'' because generating facilities' 
obligation to provide reactive power within the standard power 
factor range ``ensures that reactive power will be provided to 
support the Transmission System.'').
    \109\ Vistra Comments at 4 (citing NYISO, Reliability and Market 
Considerations for a Grid in Transition, 25-26, 104-06 (2019), 
https://www.nyiso.com/documents/20142/2224547/Reliability-and-Market-Considerations-for-a-Grid-in-Transition-20191220%20Final.pdf/61a69b2e-0ca3-f18c-cc39-88a793469d50 and CAISO, Reactive Power 
Requirements--Automatic Voltage Regulator Systems, Docket No. ER17-
490-000 (filed Dec. 5, 2016)). But see Joint Customers Reply 
Comments at 6 (urging ``the Commission to maintain a focus on 
reliability as the basis for compensating for Reactive Service, but 
also to be wary of attempts by others to use `reliability' to 
justify over-compensation for Reactive Service or to preserve 
outdated methodologies.'').
    \110\ See Essential Reliability Servs. & the Evolving Bulk-Power 
Frequency Response, Order No. 842, 83 FR 639 (Mar. 6, 2018), 162 
FERC ] 61,128, at P 121, order on reh'g and clarification, 164 FERC 
] 61,135 (2018) (``While the Commission has approved specific 
compensation for discrete services that require substantial 
identifiable costs, such as for frequency regulation and operating 
reserves, the Commission has not required specific compensation for 
all reliability-related costs. We agree with those commenters who 
observe that minimal reliability-related costs such as those 
incurred to provide primary frequency response, are reasonably 
considered to be part of the general cost of doing business, and are 
not specifically compensated.'').
    \111\ MISO, 182 FERC ] 61,033 at P 55.
    \112\ CAISO Initial Comments at 5.
---------------------------------------------------------------------------

    44. We seek comment on the reliability impact of prohibiting 
transmission providers from including in their transmission rates any 
charges associated with the supply of reactive power within the 
standard power factor range from a generating facility in regions where 
generating facilities currently receive such compensation.
2. Eliminating Separate Compensation Does Not Preclude Generating 
Facilities From Recovering Their Costs
    45. We preliminarily find that separate compensation for providing 
reactive power within the standard power factor range is not necessary 
for resources to be able to recover their costs. Some commenters argue 
that cost-of-service payment for reactive power is important for 
obtaining financing. Although the prospect of receiving separate, fixed 
reactive power payments may be beneficial for developing certain 
generating facilities, resource developers continue to develop new 
generating facilities in regions without such payments.\113\ 
Furthermore, the basis for these payments has always been 
comparability. Therefore, these arguments do not demonstrate why 
allowing for separate reactive power payments at the transmission 
provider's discretion is just and reasonable.
---------------------------------------------------------------------------

    \113\ For example, as of February 21, 2024, there were 453 total 
generating facilities in the CAISO interconnection queue, 440 of 
which were non-synchronous generating facilities. This corresponds 
to 122,885 MW of capacity, 120,043 MW of which comes from the non-
synchronous generating facilities in the queue. See CAISO, Formatted 
Generator Interconnection Queue Report, https://rimspub.caiso.com/rimsui/logon.do (last visited Feb. 21, 2024). Similarly, as of 
February 21, 2024, there were 947 total generating facilities in the 
SPP interconnection queue, 770 of which were non-synchronous 
generating facilities. This corresponds to 175,243 MW of capacity, 
141,879 MW of which comes from the non-synchronous generating 
facilities in the queue. See SPP, Generator Interconnection Active 
Requests, https://opsportal.spp.org/Studies/GIActive (last visited 
Feb. 21, 2024).
---------------------------------------------------------------------------

    46. Instead, in the context of RTO/ISO markets, we preliminarily 
find that it is both more efficient and less administratively 
burdensome for generating facilities to recover any identified reactive 
power costs, to the extent they exist, through energy and capacity 
sales,\114\ since competition between generating facilities may 
incentivize efficiency.\115\ Another benefit of any such market-based 
compensation in RTOs/ISOs is that any costs of providing reactive power 
within the standard power factor range would be more transparent to 
market participants because they would be included in RTO/ISO energy 
and/or capacity prices as opposed to generating facility-specific out-
of-market cost-of-service agreements.
---------------------------------------------------------------------------

    \114\ See MISO Rehearing Order, 184 FERC ] 61,022 at P 42 
(dismissing Vistra's claim that they would be unable to recover any 
costs attributable to providing reactive service through mechanisms 
other that Schedule 2, such as in energy offers and capacity offers. 
The Commission noted that ``[a]s to capacity offers, among the 
`going forward' costs that can be recovered are `mandatory capital 
expenditures necessary to comply with federal . . . reliability 
requirements,' which would appear to include any (hypothetical) 
capital investments and expenditures associated with Reactive 
Service. As to energy offers, Vistra does not explain the basis for 
its assertion that the Tariff bars including any incremental costs 
associated with Reactive Service (e.g., fuel costs, short-term 
variable operations and maintenance) in such offers.'').
    \115\ For example, in PJM, capital costs are included in the Net 
Cost of New Entry (Net CONE) parameter of the Variable Resource 
Requirement (VRR) curve in the capacity market and the Net CONE 
parameter directly affects clearing prices by affecting both the 
maximum capacity price and the location of the downward sloping part 
of the VRR. As a result, if the Commission were to eliminate 
reactive power compensation within the standard power factor range, 
the only change that would be required would be to exclude the 
reactive power revenues from the Net CONE parameter and to exclude 
any reactive power revenues from the energy and ancillary services 
offset from the offer caps for resources that provide reactive 
power. See PJM IMM Initial Comments at 21-22, 25.
---------------------------------------------------------------------------

    47. The Commission has repeatedly rejected arguments that 
generating facilities need separate reactive power payments ``since the 
incremental cost of reactive power service within the deadband is 
minimal.'' \116\ Therefore, consistent with those findings, for IPPs 
operating in non-RTO regions, we preliminarily find that cessation of 
payments for reactive power within the standard power factor range set 
forth in the Commission's pro forma LGIA and SGIA does not compromise 
an IPP's ability to recover costs that it may incur in producing 
reactive power within such range because generating facilities have the 
opportunity to recover such costs in other ways, ``such as through 
higher power sales rates of their own.'' \117\
---------------------------------------------------------------------------

    \116\ BPA, 120 FERC ] 61,211 at P 21 (citing Sw. Power Pool, 
Inc., 119 FERC ] 61,199 at P 39).
    \117\ Id.
---------------------------------------------------------------------------

    48. Both experience in CAISO, SPP, MISO and certain non-RTO regions 
where generating facilities do not receive compensation for the 
provision of reactive power within the standard power factor 
range,\118\ and the evidence in the record to date supports these 
findings. Specifically, experience and evidence demonstrate that: (1) 
eliminating compensation has not led to an insufficient supply of 
reactive power in those regions; and that (2) generating facilities in 
these regions have been able to recover any purported costs associated 
with the production of reactive power. For example, CAISO notes that it 
``has seen no evidence to this point that resources cannot comply with 
reactive power dispatch instructions because they have insufficient 
funds for the equipment to meet the reactive power dispatch.'' \119\ As 
Leeward Renewable Energy, LLC, and Union of Concerned Scientists (LRE/
UCS) notes, ``the lack of separate reactive power compensation in CAISO 
or SPP means that all costs have to be recovered through the applicable 
PPA, which also means that those PPA prices are higher, all other 
variables being equal, than they would otherwise be.'' \120\
---------------------------------------------------------------------------

    \118\ See Cal. Indep. Sys. Operator Corp., 160 FERC ] 61,035 at 
P 19. In 2017, the Commission considered the CAISO's approach and 
found ``a separate payment for the provision of reactive power 
capability inside the standard power factor range is not required, 
and we see no reason to require a separate cost recovery mechanism 
for reactive power capability based on the record here.'' The 
Commission later affirmed this approach when it was proposed by 
different transmission providers. See PNM, 178 FERC ] 61,088 at P 29 
(``Consistent with Commission precedent, a transmission provider may 
decide to eliminate compensation for having the capability of 
providing reactive service within the standard power factor 
range.''); MISO, 182 FERC ] 61,033 at P 55 (``As stated by MISO 
[transmission owners] and supporting commenters, new and existing 
generators in MISO will still be required to provide reactive power 
within the standard power factor range as a condition of obtaining 
and maintaining an interconnection. MISO [transmission owners] do 
not propose to change MISO's ability to manually redispatch 
individual generators for voltage control and generators will 
continue to be compensated under a separate Tariff mechanism if MISO 
directs a generation resource to provide reactive power outside of 
the standard power factor range.'' (citations omitted)); see also 
Order No. 842, 162 FERC ] 61,128 at P 120 (explaining that ``there 
are interconnection requirements for generating facilities in which 
the recovery of capital costs and operating expenses are not 
necessarily ensured.'').
    \119\ CAISO Initial Comments at 5-6.
    \120\ LRE/UCS Initial Comments at 16.

---------------------------------------------------------------------------

[[Page 21465]]

    49. The record from the Notice of Inquiry contains comments arguing 
that removal of all reactive power compensation under the standard 
power factor range without a transition period or other similar 
mechanism has the potential to disrupt business and investment 
decisions for generating entities in certain markets in the near 
term.\121\ We seek comment on whether and, if so, how the elimination 
of separate reactive power payments will affect generating facilities' 
ability to recover their costs in the markets that currently provide 
reactive power compensation within the standard power factor range. We 
also seek comment on whether, and if so how, eliminating separate 
reactive power compensation within the standard power factor range may 
affect investment decisions to build, or finish building, generation 
facilities, and whether, and if so how, the elimination could otherwise 
affect generators' business decisions in those markets.
---------------------------------------------------------------------------

    \121\ See, e.g., EDF Renewables Initial Comments at 11-12 
(``Since independent power producers . . . rely on project financing 
to finance their project development, predictability of the revenue 
stream is very important to this industry segment.); Joint Customers 
Reply Comments at 17 (noting that ``resource developers or owners 
may have made the decision to invest in resources under the 
Commission's currently approved methods for determining reactive 
compensation,'' while also cautioning against allowing unjust 
reactive power rates to ``remain effective indefinitely.''); Duke 
Energy Comments at 4 (``Developers have . . . obtained financing 
based on [the AEP] methodology being in place.'').
---------------------------------------------------------------------------

C. Proposed Revisions for Eliminating Compensation for Reactive Power 
Supply Within the Standard Power Factor Range

    50. To effectuate the changes discussed herein, we propose three 
revisions discussed further below. Our preliminary findings and these 
proposed revisions are consistent with the Commission's previous 
initial statements in Order No. 2003 (which was subsequently revised in 
Order No. 2003-A) and in subsequent cases on the non-compensability of 
providing reactive power within the standard power factor range. They 
also address the undue discrimination concerns articulated by the 
Commission in Order No. 2003-A, which led to the Commission's 
comparability policy.\122\ By requiring the same approach to 
compensation for all resources, which necessarily includes both 
affiliates and non-affiliates, there is no potential for undue 
discrimination by the transmission provider and comparability would no 
longer be a justification for payment.
---------------------------------------------------------------------------

    \122\ See supra notes 7-9 and associated text.
---------------------------------------------------------------------------

1. Revise Schedule 2 of the Pro Forma OATT
    51. We propose to revise Schedule 2 of the pro forma OATT to add 
the following sentence at the end of Schedule 2: ``However, such rates 
shall not include any charges associated with the compensation to a 
generating facility for the supply of reactive power within the power 
factor range specified in its interconnection agreement.'' This 
proposed revision would prohibit separate compensation for the 
provision of reactive power within the standard power factor range 
specified in an interconnection agreement.
2. Revise Section 9.6.3 of the Pro Forma Large Generator 
Interconnection Agreement
    52. We propose to revise section 9.6.3 of the pro forma LGIA to 
remove the proviso: ``provided that if Transmission Provider pays its 
own or affiliated generators for reactive power service within the 
specified range, it must also pay Interconnection Customer.'' 
Accordingly, under our proposal here, section 9.6.3 of the pro forma 
LGIA would read as follows: ``Payment for Reactive Power. Transmission 
Provider is required to pay Interconnection Customer for reactive power 
that Interconnection Customer provides or absorbs from the Large 
Generating Facility when Transmission Provider requests Interconnection 
Customer to operate its Large Generating Facility outside the range 
specified in Article 9.6.1. Payments shall be pursuant to Article 11.6 
or such other agreement to which the Parties have otherwise agreed.'' 
Along with the other proposed revisions, this proposed revision would 
prohibit a transmission provider from including in its transmission 
rates any charges associated with the supply of reactive power within 
the specified power factor range from a generating facility. 
Accordingly, transmission providers would be required to pay an 
interconnection customer for reactive power only when the transmission 
provider requests the interconnection customer to operate its facility 
outside the power factor range set forth in its interconnection 
agreement.
3. Revise Section 1.8.2 of the Pro Forma Small Generator 
Interconnection Agreement
    53. We propose to revise section 1.8.2 of the pro forma SGIA to 
remove the following sentence: ``In addition, if the Transmission 
Provider pays its own or affiliated generators for reactive power 
service within the specified range, it must also pay the 
Interconnection Customer.'' Accordingly, under our proposal here, 
section 1.8.2 of the pro forma SGIA would read as follows: ``The 
Transmission Provider is required to pay the Interconnection Customer 
for reactive power that the Interconnection Customer provides or 
absorbs from the Small Generating Facility when the Transmission 
Provider requests the Interconnection Customer to operate its Small 
Generating Facility outside the range specified in article 1.8.1.'' 
Along with the other proposed revisions, this proposed revision would 
prohibit a transmission provider from including in its transmission 
rates any charges associated with the supply of reactive power within 
the specified power factor range from a generating facility. 
Accordingly, as above, transmission providers would be required to pay 
an interconnection customer for reactive power only when the 
transmission provider requests the interconnection customer to operate 
its facility outside the power factor range set forth in its 
interconnection agreement.

IV. Proposed Compliance Procedures

    54. We propose to require each transmission provider to submit a 
compliance filing within 60 days of the effective date of the final 
rule in this proceeding revising its OATT, pro forma LGIA, and pro 
forma SGIA, as necessary, to comply with the requirements set forth in 
any final rule issued in this proceeding. In addition, we propose to 
allow 90 days from the date of the compliance filing for implementation 
of the proposed reforms to become effective.
    55. To the extent that any transmission provider believes that it 
already complies with the reforms adopted in any final rule in this 
proceeding, the transmission provider would be required to demonstrate 
how it complies in the compliance filing required 60 days after the 
effective date of any final rule in this proceeding. In reviewing 
compliance filings, the Commission will apply the ``consistent with or 
superior to'' standard to deviations from the adopted pro forma 
language proposed by non-RTO/ISO transmission providers. In evaluating 
compliance filings made by RTOs/ISOs, the Commission will apply the 
``consistent with or superior to'' standard to deviations from the 
adopted pro forma Schedule 2 and the ``independent entity variation 
standard'' to deviations from the pro forma LGIA and pro forma SGIA.
    56. We seek comment on whether the proposed compliance and

[[Page 21466]]

implementation timeline would allow sufficient time for changes to be 
implemented in response to a final rule or whether a limited transition 
period (beyond the 90-day implementation period proposed in this NOPR) 
may be necessary. Specifically, we seek comment on the following 
questions:
     Is a transition period necessary? Please provide 
discussion supporting any opinion.
     What factors, if any, such as potential business or 
investment impacts, should be considered in determining whether any 
transition period is appropriate, how any transition period for 
reactive power compensation may be structured to minimize impacts, and 
for what duration any transition period should last? Absent a 
transition period, would the final rule disrupt business and investment 
decisions or not? If so, what transition mechanisms other than delaying 
the implementation date of the final rule would minimize such 
disruptions and be just and reasonable?
     For regions that have an established capacity market, 
should transmission providers be allowed to make the implementation 
date of their compliance filing align with the region's capacity market 
timelines in order to allow costs associated with reactive power 
production, if any, to be incorporated into capacity market bids? Would 
a different transition mechanism, if any, be necessary for regions 
without a capacity market? Would it be unduly discriminatory or 
preferential to set different implementation dates for the final rule 
in different markets and regions?
     If the Commission allows existing generation resources 
that have previously received compensation for reactive power supply to 
continue to receive compensation for a limited period while prohibiting 
new generation resources from receiving reactive power compensation, 
how should it determine eligibility for continued compensation in a 
manner that is just and reasonable and not unduly discriminatory or 
preferential?

V. Information Collection Statement

    57. The Office of Management and Budget's (OMB) regulations require 
approval of certain information collection requirements imposed by 
agency rules. Upon approval of a collection(s) of information, OMB will 
assign an OMB control number and an expiration date. Respondents 
subject to the filing requirements of a rule will not be penalized for 
failing to respond to these collections of information unless the 
collections of information display a valid OMB control number.
    58. This notice of proposed rulemaking proposes to amend the 
Commission's regulations pursuant to section 206 of the Federal Power 
Act, to eliminate compensation to generating facilities for the 
provision of reactive power within the standard power factor range set 
forth in each generating facility's individual interconnection 
agreement. To accomplish this, the Commission proposes to require each 
transmission provider to amend the standard large interconnection 
agreement and the standard small generator interconnection agreement in 
its open access transmission tariff to implement the reforms proposed 
in this NOPR. Such filings should be made under Part 35 of the 
Commission's regulations. Subsequently, the proposed rule would revise 
the following currently approved information collections: FERC 516H 
(OMB control. No. 1902-0303): Pro Forma Open Access Transmission 
Tariff, FERC 516 (OMB control No. 1902-0096): Electric Tariff Filings, 
and FERC 516A (OMB control No. 1902-0203): Standardization of Small 
Generator Interconnection Agreements and Procedures [SGIA and SGIP].
    59. The Commission is submitting these reporting requirements to 
OMB for its review and approval under section 3507(d) of the Paperwork 
Reduction Act. Comments are solicited on whether the information will 
have practical utility, the accuracy of provided burden estimates, ways 
to enhance the quality, utility, and clarity of the information to be 
collected, and any suggested methods for minimizing the respondent's 
burden, including the use of automated information techniques.
    60. Please send comments concerning the collection of information 
and the associated burden estimates to: Office of Information and 
Regulatory Affairs, Office of Management and Budget, 725 17th Street 
NW, Washington, DC 20503, Attention: Desk Officer for the Federal 
Energy Regulatory Commission. Due to security concerns, comments should 
be sent electronically to the following email address: 
[email protected]. Comments submitted to OMB should refer to 
OMB Control No. 1902-0303, 1902-0096, or 1902-0203.
    61. Please submit a copy of your comments on the information 
collection to the Commission via the eFiling link on the Commission's 
website at https://www.ferc.gov. If you are not able to file comments 
electronically, please send a copy of your comments to: Federal Energy 
Regulatory Commission, Secretary of the Commission, 888 First Street 
NE, Washington, DC 20426. Comments on the information collection that 
are sent to FERC should refer to Docket No. RM22-2-000.
    62. Title: FERC 516H: Pro Forma Open Access Transmission Tariff, 
FERC 516: Electric Tariff Filings, and FERC 516A: Standardization of 
Small Generator Interconnection Agreements and Procedures [SGIA and 
SGIP].
    63. Action: Proposed revision of the information collection in 
accordance with RM22-2-000.
    64. OMB Control No.: 1902-0303, 1902-0096, 1902-0203.
    65. Respondents for This Rulemaking: Public utility transmission 
providers, including RTOs/ISOs.
    66. Frequency of Information Collection: One-time compliance 
filing.
    67. Necessity of Information: The proposed rule will require that 
transmission providers submit to the Commission a one-time compliance 
filing proposing tariff revisions.
    68. Internal Review: The Commission has reviewed the changes and 
has determined that such changes are necessary. These requirements 
conform to the Commission's need for efficient information collection, 
communication, and management within the energy industry in support of 
the Commission's ensuring just and reasonable rates. The Commission has 
specific, objective support for the burden estimates associated with 
the information collection requirements.
    69. Public Reporting Burden: The Commission's estimate consists of 
our estimated effort related to updating the proposed revisions to the 
Pro Forma Open Access Transmission Tariff, and subsequent revisions to 
the Large Generator Interconnection Agreements and Small Generator 
Interconnection agreements and the effort related to submitting a one-
time compliance filing.

[[Page 21467]]

    70. The Commission estimates burden \123\ and cost \124\ as 
follows:
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    \123\ ``Burden'' is the total time, effort, or financial 
resources expended by persons to generate, maintain, retain, or 
disclose or provide information to or for a Federal agency. For 
further explanation of what is included in the estimated burden, 
refer to 5 CFR 1320.3.
    \124\ Commission staff estimates that the respondents' skill set 
(and wages and benefits) for Docket No. RM22-13-000 are comparable 
to those of Commission employees. Based on the Commission's Fiscal 
Year 2024 average cost of $207,786/year (for wages plus benefits, 
for one full-time employee), $100/hour is used.

--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                     C. Annual
                                    B. Number of     number of       D. Total     E. Average burden hours &   F. Total annual hour burdens   G. Cost per
          A. Collection             respondents    responses per     number of        cost per response           & total annual cost        respondent
                                                     respondent      responses
                                                                    (Column B x                              (Column D x..................   (Column F /
                                                                      Column C)                              Column E)....................     Column B)
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                  FERC 516H: Pro Forma Open Access Transmission Tariff
--------------------------------------------------------------------------------------------------------------------------------------------------------
Transmission Providers (one-time              40                1            40  4 hrs.; $400..............  160 hrs.; $16,000............          $400
 compliance filing).
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                            FERC 516: Electric Tariff Filings
--------------------------------------------------------------------------------------------------------------------------------------------------------
Transmission Providers (one-time              43                1            43  4 hrs.; $400..............  172 hrs.; $17,200............           400
 compliance filing).
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                 FERC 516A: Standardization of Small Generator Interconnection Agreements and Procedures
--------------------------------------------------------------------------------------------------------------------------------------------------------
Transmission Providers (one-time              43                1            43  4 hrs.; $400..............  172 hrs.; $17,200............           400
 compliance filing).
                                   ---------------------------------------------------------------------------------------------------------------------
    Totals........................  ............  ...............  ............  ..........................  504 hrs.; $50,400............  ............
--------------------------------------------------------------------------------------------------------------------------------------------------------

VI. Environmental Analysis

    71. The Commission is required to prepare an Environmental 
Assessment or an Environmental Impact Statement for any action that may 
have a significant adverse effect on the human environment.\125\ We 
conclude that neither an Environmental Assessment nor an Environmental 
Impact Statement is required for this NOPR under Sec.  380.4(a)(15) of 
the Commission's regulations, which provides a categorical exemption 
for approval of actions under sections 205 and 206 of the FPA relating 
to the filing of schedules containing all rates and charges for the 
transmission or sale of electric energy subject to the Commission's 
jurisdiction, plus the classification, practices, contracts, and 
regulations that affect rates, charges, classification, and 
services.\126\
---------------------------------------------------------------------------

    \125\ Reguls. Implementing the Nat'l Env't Pol'y Act, Order No. 
486, 52 FR 47,897 (Dec. 17, 1987), FERC Stats. & Regs. Preambles 
1986-1990 ] 30,783 (1987) (cross-referenced at 41 FERC ] 61,284).
    \126\ 18 CFR 380.4(a)(15).
---------------------------------------------------------------------------

VII. Regulatory Flexibility Act Certification

    72. The Regulatory Flexibility Act of 1980 (RFA) \127\ generally 
requires a description and analysis of proposed rules that will have 
significant economic impact on a substantial number of small entities. 
The Small Business Administration (SBA) sets the threshold for what 
constitutes a small business. Under SBA's size standards,\128\ 
transmission providers under the category of Electric Bulk Power 
Transmission and Control (NAICS code 221121), have a size threshold of 
950 employees (including the entity and its associates).\129\
---------------------------------------------------------------------------

    \127\ 5 U.S.C. 601-612.
    \128\ 13 CFR 121.201.
    \129\ The RFA definition of ``small entity'' refers to the 
definition provided in the Small Business Act, which defines a 
``small business concern'' as a business that is independently owned 
and operated and that is not dominant in its field of operation. The 
Small Business Administrations' regulations at 13 CFR 121.201 define 
the threshold for a small Electric Bulk Power Transmission and 
Control entity (NAICS code 221121) to be 500 employees. See 5 U.S.C. 
601(3) (citing to Section 3 of the Small Business Act, 15 U.S.C. 
632).
---------------------------------------------------------------------------

    73. We estimate that there are 43 transmission providers that are 
affected by the reforms proposed in this NOPR, based on the NERC Active 
Compliance Registry Matrix as of January 11, 2024.\130\ The Commission 
used a combination of sources to determine the number of employees 
within each entity using open-source data and information from Dunn & 
Bradstreet. We estimate that 6 of the 43 transmission providers, 
approximately 14% (rounded), are small entities.
---------------------------------------------------------------------------

    \130\ North American Electric Reliability Corporation, NCR 
Active Entities List, (Jan. 12, 2024), 
NERC_Compliance_Registry_Matrix_Excel.xlsx.
---------------------------------------------------------------------------

    74. We estimate that one-time costs (in Year 1) associated with the 
reforms proposed in this NOPR for one transmission provider (as shown 
in the table above) would be $400. Following Year 1, the Commission 
estimates no ongoing costs associated with this proposed rule.
    75. According to SBA guidance, the determination of significance of 
impact ``should be seen as relative to the size of the business, the 
size of the competitor's business, and the impact the regulation has on 
larger competitors.'' \131\ We do not consider the estimated cost of 
$400 to be a significant economic impact for any of the entities that 
would be impacted by this NOPR. As a result, we certify that the 
reforms proposed in this NOPR would not have a significant economic 
impact on a substantial number of small entities.
---------------------------------------------------------------------------

    \131\ U.S. Small Business Administration, A Guide for Government 
Agencies How to Comply with the Regulatory Flexibility Act, 18 (Aug. 
2017), https://cdn.advocacy.sba.gov/wp-content/uploads/2019/06/21110349/How-to-Comply-with-the-RFA.pdf.
---------------------------------------------------------------------------

VIII. Comment Procedures

    76. The Commission invites interested persons to submit comments on 
the matters and issues proposed in this document to be adopted, 
including any related matters or alternative proposals that commenters 
may wish to discuss. Comments are due May 28, 2024. Also, reply 
comments are due June 26, 2024. Comments must refer to Docket No. RM22-
2-000, and must include the commenter's name, the organization they 
represent, if applicable, and their address in their comments. All 
comments will be placed in the Commission's public files and may be 
viewed, printed, or downloaded remotely as described in the Document 
Availability section below. Commenters on this proposal are not 
required to serve copies of their comments on other commenters.
    77. The Commission encourages comments to be filed electronically 
via the eFiling link on the Commission's website at https://www.ferc.gov. The Commission accepts most standard word processing 
formats. Documents created electronically using word

[[Page 21468]]

processing software must be filed in native applications or print-to-
PDF format and not in a scanned format. Commenters filing 
electronically do not need to make a paper filing.
    78. Commenters that are not able to file comments electronically 
may file an original of their comment by USPS mail or by courier-or 
other delivery services. For submission sent via USPS only, filings 
should be mailed to: Federal Energy Regulatory Commission, Office of 
the Secretary, 888 First Street NE, Washington, DC 20426. Submission of 
filings other than by USPS should be delivered to: Federal Energy 
Regulatory Commission, 12225 Wilkins Avenue, Rockville, MD 20852.

IX. Document Availability

    79. In addition to publishing the full text of this document in the 
Federal Register, the Commission provides all interested persons an 
opportunity to view and/or print the contents of this document via the 
internet through the Commission's Home Page (https://www.ferc.gov).
    80. From the Commission's Home Page on the internet, this 
information is available on eLibrary. The full text of this document is 
available on eLibrary in PDF and Microsoft Word format for viewing, 
printing, and/or downloading. To access this document in eLibrary, type 
the docket number excluding the last three digits of this document in 
the docket number field.
    81. User assistance is available for eLibrary and the Commission's 
website during normal business hours from FERC Online Support at (202) 
502-6652 (toll free at 1-866-208-3676) or email at 
[email protected], or the Public Reference Room at (202) 502-
8371, TTY 202-502-8659. Email the Public Reference Room at 
[email protected].

    By direction of the Commission.

    Issued: March 21, 2024.
Debbie-Anne A. Reese,
Acting Secretary.

    Note: The following appendix will not appear in the Code of 
Federal Regulations.

Appendix A: List of Commenters

A. Initial Commenters

 Haley Benson
 Nikhil Bhushan
 Market Monitoring Unit of Southwest Power Pool, Inc.
 Charles T. Gaunt
 Duke Energy Corporation
 Wolverine Power Supply Cooperative, Inc.
 Nuclear Energy Institute
 PJM Interconnection, L.L.C.
 Electricity Consumers Resource Council
 Southwest Power Pool, Inc.
 California Independent System Operator Corporation
 State Agencies \1\
---------------------------------------------------------------------------

    \1\ State Agencies consist of the Connecticut Attorney General, 
the Connecticut Department of Energy and Environmental Protection, 
the Connecticut Office of Consumer Counsel, the Delaware Attorney 
General, the Delaware Division of the Public Advocate, the Office of 
the People's Counsel for the District of Columbia, the Maine Office 
of the Public Advocate, the Massachusetts Attorney General, the 
Attorney General of the State of Michigan, the Minnesota Attorney 
General, the Oregon Attorney General, and the Rhode Island Attorney 
General.
---------------------------------------------------------------------------

 Electric Power Service Corporation
 Renewable Generation Companies \2\
---------------------------------------------------------------------------

    \2\ Renewable Generation Companies consist of D.E. Shaw 
Renewable Investments, L.L.C., EDF Renewables, Inc., EDP Renewables 
North America LLC, Enel North America, Inc., Invenergy Renewables 
LLC, Lightsource Renewable Energy Operations, LLC, NextEra Energy 
Resources, LLC, Open Road Renewables, LLC, and RWE Renewables 
Americas, LLC.
---------------------------------------------------------------------------

 Midcontinent Independent System Operator, Inc.
 Clean Energy Coalition \3\
---------------------------------------------------------------------------

    \3\ Clean Energy Coalition consists of the Solar Energy 
Industries Association, the American Clean Power Association, 
Earthjustice, and the Natural Resources Defense Council.
---------------------------------------------------------------------------

 Pine Gate Renewables, LLC
 Edison Electric Institute
 National Rural Electric Cooperative Association
 New York Independent System Operator, Inc.
 ISO New England Inc.
 MISO Transmission Owners
 PJM Power Providers Group
 Vistra Corp. and Dynegy Marketing and Trade, LLC
 National Hydropower Association
 Alliant Energy Corporate Services, Inc.
 Dominion Energy Services, Inc.
 Los Angeles Department of Water and Power
 Leeward Renewable Energy, LLC, and Union of Concerned 
Scientists
 EDF Renewables, Inc.
 Ameren Services Company
 Electric Power Supply Association
 Indicated Generation Owners \4\
---------------------------------------------------------------------------

    \4\ Indicated Generation Owners consists of Ares EIF Management, 
LLC, Brookfield Renewable Trading and Marketing LP, Cogentrix Energy 
Power Management, LLC, and Eagle Creek Renewable Energy, LLC.
---------------------------------------------------------------------------

 Joint Customers \5\
---------------------------------------------------------------------------

    \5\ Joint Customers consist of Old Dominion Electric 
Cooperative, Northern Virginia Electric Cooperative, Inc., and 
Dominion Energy Services, Inc.
---------------------------------------------------------------------------

 PSEG
 Independent Market Monitor for PJM
 American Electric Power Service Corporation

B. Reply Commenters

 Renewable Generation Companies
 Electric Power Supply Association
 Clean Energy Coalition
 Vistra Corp. and Dynegy Marketing and Trade, LLC
 EDF Renewables, Inc.
 PSEG
 Ameren Services Company
 Joint Customers
 MISO Transmission Owners
 Independent Market Monitor for PJM

[FR Doc. 2024-06556 Filed 3-27-24; 8:45 am]
BILLING CODE 6717-01-P
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