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FERC is issuing two orders today dealing with transmission reforms. Here is summary of the two orders:
Order 1920 The grid rule contains these major elements:
More specifically, the rule requires each transmission operator to:
The grid rule contains these cost-allocation provisions:
The grid rule requires transmission providers to:
Order 1977 With respect to the Commission’s siting authority, the Infrastructure Investment and Jobs Act of 2021 (or “the IIJA”) clarified that the Commission may issue an interstate transmission project permit if a State has denied an application. In that process, the Commission must determine, as a precondition to a permit holder exercising eminent domain authority, that the permit holder has made “good faith efforts to engage with landowners and other stakeholders early in the applicable permitting process.” First, rule clarifies that the Commission has the authority to issue permits to construct or modify electric transmission facilities in a National Corridor if a State has denied a siting application. Second, the draft final rule codifies the Applicant Code of Conduct. Compliance with the code of conduct is one way that an applicant may demonstrate that it has made good faith efforts to engage with landowners early in the applicable permitting process. The Applicant Code of Conduct includes recordkeeping and information-sharing requirements for engagement with affected landowners, as well as general prohibitions against misconduct. Third, the rule requires applicants to develop engagement plans that describe completed and planned outreach to environmental justice communities and Indian Tribes. A Tribal Engagement Plan was added to the rule in response to comments. Applicants will provide this information as part of a Project Participation Plan, which must be filed early in the pre-filing process. The rule updates and clarifies the environmental information required for existing applicant-prepared resource reports - three new resource reports in which applicants must provide information regarding a proposed project’s impacts on air quality and environmental noise, on environmental justice communities, and on Tribal resources. As part of the new Air quality and environmental noise resource report, and consistent with the Commission’s obligations under NEPA and the Clean Air Act, the applicant must estimate emissions and noise from the proposed project and the corresponding impacts on air quality and the environment. The report must also describe any proposed mitigation measures. In addition, the rule establishes an operational noise limit for proposed substations and related facilities at nearby noise-sensitive areas, such as schools, hospitals, or residences. In the new Environmental justice resource report, the applicant must begin by using current guidance and data to identify environmental justice communities within the area of potential project impact. Once environmental justice communities have been identified, the applicant must describe the impacts of project construction, operation, and maintenance on those communities. In addition, the resource report must discuss cumulative impacts, describe any proposed mitigation measures, and describe any community input received on the proposed mitigation measures. If adopted by the Commission, the final rule will become effective 60 days after publication in the Federal Register.
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Summary:
The Federal Energy Regulatory Commission (FERC) 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 compensation of related to the provision of reactive power within the standard power factor range by generating facilities. Operating “within 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. Transmission providers would be required to pay an interconnection customer for reactive 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. Comments from interested parties are due on or about May 20, 2024. In Order No. 2003, FERC specifically addressed the circumstances and way a transmission provider must pay for reactive power, inside and outside the standard power factor range (sometimes referred to as the “deadband”). In Order No. 2003, FERC 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[1] 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, FERC 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.”[2] But in Order No. 2003-A, FERC 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.”[3] This standard is generally referred to as the comparability standard. As part of this NOPR, FERC proposes 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. In early 2023, MISO made a similar change to its reactive power compensation under Schedule 2, eliminating payments generators were receiving for the capability to provide reactive power and paying only for reactive power provided outside the deadband when called upon by MISO. SPP uses the compensation model that FERC is proposing in this NOPR. CAISO does not pay for reactive power, even when it requests a generator to provide reactive power services outside the deadband. ISO-NE and the NYISO have system-wide stated rates by which they compensate generators for reactive power. PJM is the only RTO today that compensates a generator for reactive power capability within the deadband and beyond to the generators full reactive power capability based upon its reactive power revenue requirement approved by FERC. Thus, this NOPR will greatly impact the reactive power compensation in PJM. Decision Rational: FERC 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.”[4] 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.”[5] “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.”[6] FERC also has 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. FERC 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.”[7] To the extent that it could be argued that such recovery was not feasible for IPPs, FERC has found that such arguments lacked plausibility “since the incremental cost of reactive power service within the deadband is minimal.”[8] FERC 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.”[9] By contrast, but outside the scope of this rulemaking[10], 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. 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 to comply with such an instruction, which could limit the generating facility’s opportunity to receive compensation for real power sales. In this NOPR:
FERC proposes 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, FERC proposes allowing 90 days from the date of the compliance filing for implementation of the proposed reforms to become effective. [1] 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. [2] 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.”). [3] 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. [4] See, e.g., METC, 97 FERC at 61,852-53 (emphasis added); MISO Rehearing Order, 184 FERC ¶ 61,022 at PP 23-24. [5] 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.”). [6] MISO Rehearing Order, 184 FERC ¶ 61,022 at P 23. [7] Id. P 21 (citing Sw. Power Pool, Inc., 119 FERC ¶ 61,199 at P 39). [8] Id. [9] Id. [10] I am not sure why this is outside the initial notice of inquiry on reactive power compensation. [11] 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. FERC 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. [12] 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 FERC 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. [13] Id. Summary
On February 15, 2024, in Docket No. EL23-101, FERC granted Mid-Atlantic Offshore Development LLC (Mid-Atlantic) (1) recovery of prudently incurred pre-commercial costs through the creation of a regulatory asset for its investment in the Mid-Atlantic Owned Facilities (“Project”) (Regulatory Asset Incentive); (2) 100% recovery of all prudently incurred transmission-related development and construction costs if the Project is canceled or abandoned, in whole or in part, as a result of factors beyond Mid-Atlantic’s control (Abandoned Plant Incentive); (3) use of a hypothetical capital structure consisting of 50% debt and 50% equity until the Project achieves commercial operation (Hypothetical Capital Structure Incentive); and (4) inclusion of a 50-basis-point incentive adder to its base return on equity (ROE) for Regional Transmission Organization (RTO) participation (RTO Participation Incentive). FERC noted that these incentives are being awarded to a project proceeding under the State Agreement Approach in the PJM Tariff and, as such, the annual transmission revenue requirement of the Project will be allocated to New Jersey load. Background Mid-Atlantic is a Delaware limited liability company that is a joint venture between EDF-RE Offshore Development, LLC (EDFR) and Shell New Energies US, LLC (Shell New Energies). Mid-Atlantic states that EDFR and Shell New Energies each own a 50% interest in MAOD. The NJ BPU selected the Mid-Atlantic Project as part of the larger Larrabee Tri-Collector Solution, which consists of the Mid-Atlantic Project plus the Jersey Central Power & Light Company (JCP&L)-owned onshore transmission delivery solutions to interconnect New Jersey offshore wind projects to onshore points of interconnection. The Mid-Atlantic Project consists of a new alternating current 230 kilovolt (kV) substation (Larrabee Collector Station) and adjacent land required for future High Voltage Direct Current converter stations, which will be constructed adjacent to JCP&L’s existing Larrabee substation located in Howell Township, New Jersey (JCP&L Larrabee Substation). The Project facilitates a single point for connecting offshore wind projects and maximizes use of available headroom at existing points of interconnection, while offering a single corridor solution preferred by the NJ BPU. Mid-Atlantic estimates its investment in the Project to be $193.5 million with an expected in-service date of December 2027. In January 2020, the State of New Jersey formally set forth its state public policy to expand the transmission system to accommodate a buildout of 7,500 MW of offshore wind generation by 2035. On November 18, 2020, NJ BPU issued an order requesting that PJM, pursuant to the State Agreement Approach, open a competitive proposal window to solicit transmission proposals to interconnect and ensure deliverability of 7,500 MW of offshore wind generation by 2035. On February 16, 2021, FERC accepted a State Agreement Approach Study Agreement (Study Agreement) between PJM and NJ BPU to effectuate NJ BPU’s formal request that PJM solicit transmission project proposals pursuant to the State Agreement Approach to integrate New Jersey’s planned offshore wind resources. The Study Agreement specifies that: (1) PJM will perform planning studies to identify system improvements to interconnect and provide for the deliverability of New Jersey’s planned offshore wind generation at specific points of interconnection to the transmission system; and (2) PJM will open a competitive proposal window to solicit transmission project proposals that provide for the deliverability of New Jersey’s planned offshore wind generation. In its order, FERC found that the Study Agreement provided transparency to stakeholders regarding the process milestones and inclusion of NJ BPU’s requested transmission in the 2020-2021 RTEP cycle. FERC also affirmed PJM’s statement that the Study Agreement does not consent to the selection of any projects or designated entities, establish any cost allocations, or grant any transmission rights. PJM opened the competitive proposal window on April 15, 2021 and received transmission project proposals until the window closed on September 17, 2021. On April 14, 2022, FERC accepted Rate Schedule No. 49, which is the State Agreement Approach Agreement between PJM and NJ BPU (PJM-NJ BPU SAA Agreement). The PJM-NJ BPU SAA Agreement establishes processes for the review and selection of specific transmission projects, which may be onshore and/or offshore facilities, to effectuate New Jersey’s public policy goals. FERC determined in the SAA Agreement Order that the PJM-NJ BPU SAA Agreement made clear that NJ BPU would be committing New Jersey customers for the cost of any SAA Projects that NJ BPU elects to sponsor. On October 26, 2022, NJ BPU issued an order on the State Agreement Approach proposals and selected 52 transmission projects. On December 2, 2022, FERC accepted a new Schedule 12-Appendix C to the PJM Tariff that includes the cost allocation method for the New Jersey State Agreement Approach projects that NJ BPU selects and agrees to sponsor to support New Jersey state law. This cost allocation method allocates the costs of such transmission projects on a load-ratio share basis to Network Customers in New Jersey and to Point-to-Point Customers with a Point of Delivery within New Jersey. In an Order dated December 29, 2023, FERC rejected Pacific Gas and Electric’s request for an RTO Participation Order. Putting this decision in context, in Order No. 679 which established transmission incentives, FERC found that “entities that have already joined, and that remain members of, an RTO, ISO, or other Commission-approved Transmission Organization, are eligible to receive” the RTO Adder incentive and have a presumption of eligibility. The Commission explained that “the basis for the incentive is a recognition of the benefits that flow from membership in such organizations and the fact continuing membership is generally voluntary.” However, FERC has taken the position that if a utility is required to be a member of an RTO-like organization, then it is not eligible for the RTO Participation Adder as it is not voluntarily a member of the RTO. Under a prior formulation in 2018 of the California statute, the Ninth Circuit Court remanded the question of PG&E’s eligibility for the RTO Adder to FERC and instructed it to inquire “whether [PG&E] could unilaterally leave [CAISO] and thus whether an incentive adder could induce it to remain.” On remand, FERC found that California law did not mandate PG&E’s participation in CAISO, and that the RTO Adder therefore induced PG&E to continue its membership. On appeal, in 2022, the Ninth Circuit upheld FERC’s interpretation of California law. However, California has since amended its public utilities code and enacted a law, effective September 6, 2022, which requires that electrical corporations such as PG&E participate in CAISO, and that they may not withdraw from CAISO without California Public Utilities Commission approval. Section 1(a)(2)(b)(1) of Assembly Bill 209 provides that “It is the intent of the Legislature to . . . reaffirm that an electrical corporation currently participating in [CAISO] is not a voluntary participant.” FERC found that, by virtue of the recently enacted California statute, PG&E is required to participate in CAISO and cannot unilaterally withdraw from CAISO. As such, PG&E’s participation in CAISO is no longer voluntary. Thus, we find that PG&E is no longer eligible for the RTO Adder.
On August 31, 2023, FERC approved Missouri River Energy Services (Missouri River) request for three transmission incentives for its investment in two, high-voltage transmission line segments which are part of the Big Stone Project, a MISO Multi-Value Project that is part of the portfolio of 18 Long Range Transmission Tranche 1 Projects included in MTEP 2021. Missouri River requested (1) a hypothetical capital structure of 50% equity and 50% debt (Hypothetical Capital Structure Incentive) for its investment in the Big Stone Project; (2) inclusion of 100% of prudently incurred Construction Work in Progress (CWIP) in rate base for the Big Stone Project (CWIP Incentive); and (3) recovery of 100% of prudently incurred costs in the Big Stone Project’s transmission facilities that are abandoned for reasons beyond Missouri River’s control (Abandoned Plant Incentive).
The Big Stone Project involves the construction of two high-voltage transmission line segments. The first segment is an approximately 95-105-mile, 345 kV line from the Big Stone South Substation in South Dakota owned by Otter Tail Power Company (Otter Tail) to the Alexandria Substation in Minnesota owned by Missouri River (Big Stone South-Alexandria segment). Missouri River states that the line will be on a new right-of-way and is expected to be constructed to facilitate a potential second 345 kV circuit on the same towers. Missouri River further states that both the Big Stone South and Alexandria Substations will need to be expanded to terminate the new line. The second segment of the Big Stone Project is a 345 kV line from the Alexandria Substation to the planned new Big Oaks Substation in Minnesota (Alexandria-Monticello segment). This line will be strung largely on existing double-circuit capable towers and will also require the acquisition of some new rights-of-way as the line approaches the Big Oaks Substation near the Mississippi River. Missouri River explains that the Alexandria Substation will also have to be expanded to terminate the Alexandria-Big Oaks line segment. The Big Stone Project has an expected in-service date of June 1, 2030 with an estimated total cost of $573.5 million (in 2022 dollars), with Missouri River’s investment comprising approximately 50% at an estimated amount of $285.6 million. In addition to state and federal approvals, the Big Stone Project requires a certificate of need and route permit from the Minnesota Public Utility Commission and a facility permit from the South Dakota Public Utilities Commission. The remainder of this blog covers the hypothetical capital structure request. Missouri River sought authorization to use a hypothetical capital structure of 50% equity and 50% debt for the life of the financing of the Big Stone Project. In support, Missouri River explained that, as a municipal joint action agency, Missouri River cannot issue stock and thus cannot raise equity capital through a stock offering to finance the Big Stone Project. Missouri River therefore contended that a hypothetical capital structure is needed to provide the returns necessary to achieve the financial metrics identified in the rate policy of Missouri River’s Board of Directors and to produce a debt service coverage ratio that is consistent with maintaining Missouri River’s existing Moody’s Aa2 credit rating. Missouri River explained that, without the Hypothetical Capital Structure Incentive, the debt service coverage ratio on the Big Stone Project would be below the range expected of a Moody’s Aa2-rated joint action agency and would put substantial downward pressure on Missouri River’s current credit rating. Missouri River further explained that the Hypothetical Capital Structure Incentive provides a return to reflect the higher risk and complexities of the Big Stone Project as the projected $285.6 million investment in the Big Stone Project will be the largest transmission investment ever made by Missouri River, representing 221% of Missouri River’s projected 2023 net transmission plant of $129.5 million and 48% of its total long-term debt. Missouri River also asserted that the Big Stone Project requires multiple permits and must be coordinated with multiple owners, which creates a more complex negotiating, decision-making, and implementation process; therefore, Missouri River maintained that, without the Hypothetical Capital Structure Incentive, “it would make more sense for Missouri River to invest in other more routine projects.” Finally, Missouri River argued that granting the Hypothetical Capital Structure Incentive will further the Commission’s policy goal of promoting public and cooperative power investment in transmission and is consistent with Commission precedent. FERC granted Missouri River’s request for the Hypothetical Capital Structure, finding that Missouri River had demonstrated that the requested incentives are tailored to the risks and challenges faced by the Big Stone Project and that approval of the Hypothetical Capital Structure Incentive and CWIP Incentive will bolster Missouri River’s financial metrics, help ensure maintenance of its current credit rating, and enable its participation in the Big Stone Project. Further, FERC found that the requested hypothetical capital structure is within the range that the Commission has allowed for other entities reliant on non-equity financing. On February 28, 2023, in Docket No. ER18-99, FERC issued an order[1] addressing exceptions to an Initial Decision issued on December 6, 2021.[2] The Initial Decision concerned disputes arising from Southwest Power Pool, Inc.’s (SPP) proposal to revise its Open Access Transmission Tariff (Tariff) to include the annual transmission revenue requirement (ATRR) of transmission facilities associated with the City of Nixa, Missouri (City of Nixa), owned by GridLiance High Plains LLC (GridLiance),[3] in one of SPP’s existing transmission pricing zones, SPP Pricing Zone 10 (Zone 10), for purposes of rate recovery (Nixa Assets). In the Initial Decision, the Presiding Judge concluded that SPP’s proposal to incorporate the Nixa Assets in Zone 10 is consistent with cost causation principles and is otherwise just and reasonable. In its Order on Initial Decision, FERC affirmed the Initial Decision. On March 29, 2023, a joint request for rehearing was filed by two different intervener groups. In its Order on Rehearing issued July 5, 2023, FERC modified the discussion in the Order on Initial Decision and continued to reach the same result.
Background: SPP uses a zonal rate design, pursuant to which its footprint is separated into several transmission pricing zones for purposes of establishing transmission service rates. The Tariff specifies a zonal ATRR for each pricing zone that is based on the sum of the ATRRs for each transmission owner in the zone. The charges for Network Integration Transmission Service (network service) in a pricing zone are calculated by multiplying a customer’s percentage share of total load in the zone (i.e., its load ratio share) by the zonal ATRR. When a new transmission owner is added to an existing pricing zone, the ATRR for its transmission facilities in the zone and any associated load not already included in the zonal load are added to the existing zone’s zonal ATRR and total load. In 2017, SPP instituted a new Transmission Owner Zonal Placement Process (Zonal Placement Process) to review and determine zonal placement for existing transmission facilities that new SPP transmission-owning members propose to include under the SPP Tariff. A group of SPP transmission owners challenged the SPP Zonal Placement Process, arguing that allocating the costs of a new SPP member’s transmission facilities to existing customers of a zone results in an unjust and unreasonable cost shift between new and existing transmission customers.[4] Although FERC denied the complaint,[5] it also stated that parties may challenge the placement of a new transmission owner’s facilities in a transmission pricing zone.[6] The Nixa Assets consist of approximately 10 miles of transmission lines and related facilities interconnected to Southwestern Power Administration (Southwestern) in Zone 10 and to City Utilities of Springfield, Missouri (City Utilities) in SPP Pricing Zone 3 (Zone 3).[7] On October 18, 2017, SPP submitted proposed Tariff revisions to add an ATRR and a formula rate template and implementation protocols for the Nixa Assets. SPP explained that it had used its Zonal Placement Process to place the facilities in Zone 10. On March 15, 2018, FERC set the Tariff revisions for hearing and settlement judge procedures.[8] After a settlement was unsuccessfully put forth to FERC, in late 2021, the Presiding Judge issued the Initial Decision, which addressed three general issues: (1) whether, and to what extent, the placement of the Nixa Assets in Zone 10 involves a cost shift; (2) whether benefits accrue to Zone 10 customers as a result of placing the Nixa Assets in Zone 10; and (3) whether the benefits justify the cost shift. The Presiding Judge determined that SPP’s proposal to incorporate the Nixa Assets in Zone 10 is consistent with cost causation principles and is otherwise just and reasonable.[9] Specifically, the Presiding Judge found that: (1) the placement of the Nixa Assets in Zone 10 will result in a $1.8 million cost shift to Zone 10 customers; (2) the Nixa Assets accrue substantial, specific, but unquantifiable benefits (i.e., integration benefits, reliability enhancements, and support for power transfers) to Zone 10 customers; and (3) those benefits justify the cost shift involved in the placement of the Nixa Assets in Zone 10. In its Order on the Initial Decision, FERC affirmed the findings that SPP’s proposal to include the ATRR for the Nixa Assets in Zone 10 is just and reasonable and consistent with the cost causation principle and, accordingly, accepted SPP’s proposed Tariff revisions. As to the amount of the cost shift, FERC determined that the Presiding Judge properly balanced competing evidence to reach the finding that the cost shift at issue in this proceeding should be calculated as GridLiance’s proposed ATRR for the Nixa Assets, which is $1.8 million. In doing so, FERC rejected arguments that the proper amount of the cost shift should be measured by the amount or percentage of the Gridliance ATRR for the Nixa Assets that will be paid by non-City of Nixa customers rather than the full amount of the GridLiance ATRR. FERC explained that “the City of Nixa is already a Zone 10 customer and the Commission’s evaluation of the cost shift to Zone 10 customers can and should incorporate costs paid by the City of Nixa as well as other customers in that zone.” FERC also affirmed the Presiding Judge’s finding that the Nixa Assets provide benefits that accrue to Zone 10 customers, concluding that the record supports the finding that the Nixa Assets provide integration, reliability, and power transfer benefits to Zone 10 customers. Responding to “the main argument raised on exceptions” that the benefits that the Nixa Assets provide allegedly accrue mostly, if not entirely, to the City of Nixa rather than other Zone 10 customers, FERC found that the Presiding Judge properly evaluated the benefits of the Nixa Assets to all Zone 10 customers—including the City of Nixa—rather than restricting his findings to non-City of Nixa customers. In doing so, FERC explained that “under SPP’s zonal rate design, all customers in a pricing zone pay a rate based on the ATRRs associated with all transmission facilities in that zone, regardless of which facilities may have previously been used to provide service to a specific customer prior to the customer or the Transmission Owner joining the [Regional Transmission Organization (RTO)].” FERC also affirmed the Presiding Judge’s finding that the benefits to Zone 10 customers from the Nixa Assets are roughly commensurate with their costs, and therefore SPP’s proposal to include the Nixa Assets in Zone 10 was just and reasonable. FERC found that arguments that it should treat the “roughly commensurate” standard as requiring that any costs of a facility should be distributed “roughly proportionate” to the usage of that specific facility were “contrary to Commission precedent and inconsistent with how costs are allocated within SPP.” Finally, FERC affirmed the Presiding Judge’s dismissal of the alternative rate proposals made by intervenors since, having affirmed the Presiding Judge’s finding that SPP’s proposal is just and reasonable, it “need not consider whether the proposal is more or less reasonable than other alternatives.” Arguments on Rehearing: Intervener arguments centered around their claim that a cost shift associated with a zonal placement decision under SPP’s Tariff cannot be just and reasonable unless each customer (or group of customers) that will bear some portion of the costs of those assets (or group of assets) is deriving a benefit from those specific assets that is “roughly proportionate” to those costs. The interveners sought to apply an asset-level, beneficiary-pays rough proportionality requirement. FERC disagreed with this view as it does not square with the existing zonal rate construct under the SPP Tariff. Under that construction, a transmission customer taking network service shall pay a monthly demand charge for the SPP Pricing Zone where the load is located (Load Ratio Share). As evident in this formula/calculation, SPP’s zonal rate construct does not attempt to measure each transmission customer’s benefit from each transmission asset included in the zonal ATRR. Nor does it charge each customer transmission costs on an asset-by-asset basis. Instead, under that zonal construct, the costs and benefits associated with network service in a zone are assessed on an aggregate level, with each customer paying for transmission service based on its load ratio share, which reflects its total use of the aggregate assets in the zone. Even if a customer does not benefit from a particular transmission asset in a manner roughly commensurate with its load ratio share, this does not demonstrate that the customer is not overall receiving roughly commensurate benefits from the transmission assets within the zone as compared to the zonal rates it is paying under SPP’s Tariff. The interveners also attempted to align their proposed proportionality requirement with SPP’s zonal rate construct by arguing that RTO zones will be ordinarily configured to allocate the costs of transmission facilities to the customers for whom they were constructed. FERC agreed that, in a typical case, it expects that a transmission asset should be included in the same zone as the customers for whom they were constructed and continue to serve. But this principle does not establish that zones generally, or SPP Pricing Zones in particular, have been or must be constructed to ensure that each customer benefits from each asset in the zone in rough proportion to the costs it pays for that specific asset, or that new assets that may be included in a zone must meet such a requirement. FERC asserted that the facts of this case are as follows: including the Nixa Assets in Zone 10 will result in a $1.8 million increase in the zonal ATRR, a portion of which will be borne by the City of Nixa based on its load ratio share under SPP’s existing Tariff. Under these circumstances, considering the cost shift in terms of the $1.8 million ATRR of the Nixa Assets ensures that FERC does not take an incomplete view of the impacts of placing the Nixa Assets in Zone 10 by focusing only on how including the assets in Zone 10 impacts the non-City of Nixa customers. Considering the full picture of the costs and benefits of the Nixa Assets to all Zone 10 customers is also consistent with SPP’s zonal rate construct, which does not evaluate the costs and benefits of transmission assets in a zone at the level of how individual customers use each of those assets, as explained above. [1] Sw. Power Pool, Inc., 182 FERC ¶ 61,141 (2023) (Order on Initial Decision). [2] Sw. Power Pool, Inc., 177 FERC ¶ 63,021 (2021) (Initial Decision). [3] GridLiance was formerly known as South Central MCN LLC. [4] Indicated SPP Transmission Owners v. Sw. Power Pool, Inc., 162 FERC ¶ 61,213 (ITOs Complaint Order), reh’g denied, 165 FERC ¶ 61,005 (2018) (ITOs Complaint Rehearing Order). [5] Order on Initial Decision, 182 FERC ¶ 61,141 at P 4 (summarizing the basis for the Commission’s denial of the complaint in the ITOs Complaint Order and ITOs Complaint Rehearing Order). [6] ITOs Complaint Order, 162 FERC ¶ 61,213 at P 74. [7] GridLiance acquired the Nixa Assets from the City of Nixa on April 1, 2018. Missouri Joint Municipal Electric Utility Commission then acquired the Nixa Assets from GridLiance on May 19, 2022. See Sw. Power Pool, 179 FERC ¶ 61,134, at P 1, 4 (2022). [8] Sw. Power Pool, Inc., 162 FERC ¶ 61,215 (Hearing Order), order on reh’g and clarification, 164 FERC ¶ 61,120 (2018) (Rehearing Order). [9] Initial Decision, 177 FERC ¶ 63,021 at PP 2, 188, 206. This summary concerns the Order Addressing Arguments Raised on Rehearing regarding reactive power compensation in MISO (Rehearing Order).
Background: On November 30, 2022, in Docket No. ER23-523, MISO, on behalf of the MISO Transmission Owners (MISO TO),[1] submitted proposed revisions to Schedule 2, Reactive Supply and Voltage Control from Generation or Other Sources Service of OATT. The MISO TOs proposed to eliminate all charges under Schedule 2 for the provision of reactive power within the standard power factor range for the MISO TOs’ own and affiliated generation resources.[2] Based on the Commission’s “comparability standard,” MISO TOs stated that their proposal also terminates the obligation under Schedule 2 to pay unaffiliated generation resources in MISO for reactive power within the standard power factor range. In its Reactive Power Order, FERC accepted the MISO TOs’ proposed Schedule 2 revisions, effective December 1, 2022. This means that the $220 million being paid in MISO to generators for the provision of reactive power ended December 1, 2022. Several parties requested rehearing. On July 12, 2023, FERC issued its Order on Rehearing (Rehearing Order - 184 FERC ¶ 61,022), modifying the discussion in the Reactive Power Order and continuing to reach the same conclusion. Here are the items FERC discussed in its Rehearing Order: Comparability Standard: FERC restated that electric power consists of two components: real power, which is “the power that does real work—and thus the power that sellers are looking to sell and that buyers are looking to buy;” and reactive power, which is necessary to maintain adequate voltages so that real power can be transmitted.[3] The provision of reactive power by generating facilities involves two different concepts. Where reactive power is provided outside of the standard power factor range, it is “an ancillary service for transmitting power across the grid to serve load.”[4] 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.”[5] 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 not to threaten reliability. FERC’s longstanding policy is “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 TOs 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. Order No. 2003 reflects the distinction between these two different reactive power concepts. When the transmission provider asks the interconnecting generator to operate its facility outside the established power factor range, the transmission provider is required to pay the interconnecting generator for the provision of such reactive power. By contrast, compensation for reactive power when the generating facility is operating within the established power factor range is not required. The sole exception FERC identified was that “if the Transmission Provider pays its own or its affiliated generators for reactive power within the established range, it must also pay the Interconnection Customer.” This is referred to as the comparability standard. In the Reactive Power Order, the Commission accepted MISO TOs’ proposal to eliminate all charges under Schedule 2 for the provision of Reactive Service. The effect of this order was not to “categorically prohibit new generation resources from seeking to recover the costs of their investment in reactive power capability.” Rather, this order eliminated only Schedule 2’s mandated, separate stream of compensation for the capability of providing Reactive Service, which had been required in MISO consistent with the comparability standard. This result is not unusual and is in fact already the case in other large RTOs or ISOs: for example, Southwest Power Pool, Inc. has eliminated compensation within the power factor range, and CAISO never provided such stand-alone compensation for Reactive Service. In its Rehearing Order, FERC stated that for synchronous resources, there is little or no incremental capital expenditure associated with the equipment necessary to produce reactive power because the same equipment is used to produce real power. FERC went on to state that its conclusion that the same equipment used for Reactive Service is also necessary to produce real power is also supported by application of the AEP cost allocation methodology that apportions costs for synchronous generating plants. 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. Reliance: Numerous parties assert that independent power producers have come to rely on Schedule 2 compensation and argue that FERC erred in accepting MISO TOs’ proposal. At the outset, FERC again noted that its acceptance of MISO TOs’ proposal considering the comparability standard was an application of the Commission’s long-standing policy in Order Nos. 2003 and 2003-A, consistent with its numerous subsequent decisions. The parties on rehearing are, in effect, urging that generators’ unilateral business decisions to treat Schedule 2 compensation as irrevocable should amount to a new exception—in addition to the comparability standard—to Order No. 2003’s determination that compensation for Reactive Service should not be provided. FERC rejected that argument in the Reactive Power Order and sustained that determination on rehearing. Reliability: FERC disagreed that it failed to adequately consider the effects of eliminating Schedule 2 compensation on grid reliability. The Reactive Power Order considered the potential reliability impacts of MISO TOs’ proposal, and FERC sustained its conclusions for the reasons articulated therein. Moreover, arguments that accepting MISO TOs’ proposal erodes the incentive to invest in reactive power capability are unpersuasive. Under Order Nos. 2003 and 2003-A, reactive power capability within the standard power factor range (i.e., Reactive Service) is and remains mandatory for generator interconnection, without incentives. The financial and other incentives for generators to invest in equipment to ensure reliability by providing reactive power outside of the standard power factor range are unaltered by and, in fact, not at issue in MISO TOs’ proposal. Retail Rates: Certain parties argue, primarily relying on Conway, that the possibility that generation owned or controlled by MISO TOs might recover the costs of reactive power capability from retail customers requires that independent power producers must also be compensated for such costs in their wholesale rates. But this amounts to a generic argument that Schedule 2 compensation for Reactive Service is required not just when the transmission owner “pays its own or its affiliated generators for reactive power within the established range” but also when the transmission owner can recover its costs through its bundled retail rates. Neither Order Nos. 2003 and 2003-A, nor any of the Commission’s prior decisions, have ever suggested this requirement. Arguments that Schedule 2 compensation is required unless transmission owners disclaimed the opportunity to recover Reactive Service costs in their retail rates were brought as challenges to Order No. 2003 and are not now properly before FERC. FERC concluded that the possibility of compensation through retail rates did not give rise to a comparability issue or dictate that the Commission requires compensation under Schedule 2. FERC further noted that Conway concerned allegations of actual anticompetitive behavior, namely that a public utility engaged in the sale of energy at both retail and wholesale sought to raise its wholesale rates in a way that would squeeze its customers, who competed with it in the retail market, out of that retail market. The U.S. Supreme Court held that FERC has jurisdiction to consider the interplay between retail and wholesale rates in assessing a proposal to change a wholesale rate. Here, by contrast, there are no allegations of anticompetitive behavior parallel to those in Conway, and—as noted in the Reactive Power Order—FERC concluded that the comparability principle is satisfied by the fact that Schedule 2 compensation is being terminated for all generation, notwithstanding that the particular alternative avenues available to seek to recover Reactive Service costs may differ between transmission owners and independent power producers. Filing Rights and Procedures: Some interveners argued that MISO TOs’ proposal failed to follow the appropriate procedures under Appendix K of the MISO TO Agreement in that the filing was not supported by the required majority vote nor was it the result of the required stakeholder process. FERC found these arguments unpersuasive as there no requirement that the filing be supported by a public vote of eligible MISO TOs, under which the identity of those voting and how they voted must be disclosed, and FERC had no reason to doubt MISO TOs’ statement as to the outcome of the vote. In the Reactive Power Order, FERC also rejected arguments that MISO TOs lacked authority to file their proposal under FPA section 205 because MISO TOs only have unilateral filing rights as to their own generators. FERC explained it had previously found, and the D.C. Circuit in Dynegy affirmed, that pursuant to the settlement adopting section 9.6.3 of the MISO pro forma GIA, “transmission owners and the Midwest ISO share the same section 205 filing right, which is the right to submit filings under FPA section 205 to govern the rates, terms, and conditions applicable to the provision of ancillary services.” FERC further concluded—consistent with the reasoning in the Reactive Power Order—that arguments asserting that accepting MISO TOs’ proposal undermines generators’ FPA section 205 filing rights reflect a misunderstanding of how compensation is provided for reactive service in MISO. Specifically, whatever rights interconnection customers (including independent power producers) may have to compensation for Reactive Service must be consistent with the terms of their GIAs. Section 9.6.3 of the MISO pro forma GIA provides that such payments shall be “pursuant to any tariff or rate schedule filed by Transmission Provider and approved by the FERC.” Thus, generators who have GIAs with this or a similar provision have agreed to make their compensation for reactive power contingent on the contents of Schedule 2, which MISO (and MISO TOs through Appendix K) have the right to revise through an FPA section 205 filing. Prior to FERC’s acceptance of MISO TOs’ proposal, Schedule 2 provided that the amount of such compensation for Reactive Service was determined by reference to generators’ annual reactive power revenue requirements. MISO TOs’ proposal altered Schedule 2—and only Schedule 2—to provide that “there will be no separate charge to compensate any generation resource for reactive service within the standard power factor range.” In other words, MISO TOs’ proposal did not adjust, overturn, or reduce to zero any generator’s annual revenue requirement for reactive power, but rather revised the Tariff such that those revenue requirements are no longer cross-referenced as the basis for determining the amount of compensation for Reactive Service. Constitutional Arguments: In the Reactive Power Order, the Commission rejected arguments that MISO TOs’ proposal violates the Takings Clause and Due Process Clause of the Fifth Amendment to the United States Constitution. The obligation to provide Reactive Service exists independent of, and was not altered by, MISO TOs’ proposal: it was stated in Order No. 2003 and applies to individual generators through their GIAs. MISO TOs proposed only to change the compensation for Reactive Service, eliminating a stream of revenue under Schedule 2. FERC thus concluded that arguments that the obligation to provide Reactive Service is unconstitutional are impermissible collateral attacks on our prior determinations. Generators do not have a property interest in continued Reactive Service compensation under the Tariff nor did MISO TOs’ proposal unconstitutionally deprive generators of that putative property interest under the Takings Clause or Due Process Clause of the Fifth Amendment. Dissent: In the Rehearing Order, Commissioner Danly reiterated his dissention. In his dissention to the Reactive Power Order, he stated that, notwithstanding the increased rates and the administrative burden of the present compensation approach, FERC cannot simply accept the MISO TOs’ proposal unless they meet their section 205 burden that the proposed rate—in this case, the elimination of reactive power compensation—is just and reasonable based on substantial evidence in the record. He went on to state that the MISO TOs did not offer any evidence of the effects of eliminating the $220 million annual reactive power revenue requirement from the MISO tariff, and what is clear on the record is that separate reactive power compensation has been available in MISO for several years, and parties have taken this into account in their financings, bilateral contracting, power purchase agreements, and other arrangements. [1] MISO TOs include: Ameren Services Company, as agent for Union Electric Company, Ameren Illinois Company, and Ameren Transmission Company of Illinois; Arkansas Electric Cooperative Corporation; City Water, Light & Power (Springfield, IL); Cooperative Energy; Dairyland Power Cooperative; East Texas Electric Cooperative; Entergy Arkansas, LLC; Entergy Louisiana, LLC; Entergy Mississippi, LLC; Entergy Texas, Inc.; Great River Energy; Indianapolis Power & Light Company; Lafayette Utilities System; MidAmerican Energy Company; Minnesota Power (and its subsidiary Superior Water, L&P); Missouri River Energy Services; Montana-Dakota Utilities Co.; Northern States Power Company, a Minnesota corporation, and Northern States Power Company, a Wisconsin corporation, subsidiaries of Xcel Energy Inc.; Northwestern Wisconsin Electric Company; Otter Tail Power Company; Prairie Power, Inc.; Southern Indiana Gas & Electric Company; and Southern Minnesota Municipal Power Agency. [2] The phrase “standard power factor range” refers to the power factor range required for interconnection and set forth in the interconnecting generator’s generator interconnection agreement (GIA). MISO’s pro forma GIA prescribes a power factor range of 0.95 leading to 0.95 lagging.” [3] Sw. Power Pool, Inc., 119 FERC ¶ 61,199 at P 28 (SPP), order on reh’g, 121 FERC ¶ 61,196, at PP 16-22 (2007) (SPP Order on Rehearing); see also Bonneville, 120 FERC ¶ 61,211 at P 21 (“The purpose for which generation assets are built (including reactive power capability to maintain voltage levels for generation entering the grid) is to make sales of real power.”). [4] Mich. Elec. Transmission Co., 97 FERC ¶ 61,187, at 61,852-53 (2001) (emphasis added). [5] Id. at 61,853 (emphasis added); SPP, 119 FERC ¶ 61,199 at P 29; 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.”). In Docket No. ER22-2968, on September 30, 2022, as supplemented on February 14, 2023, SPP submitted proposed revisions to Attachment V (Generator Interconnection Procedures (GIP)) of its OATT to implement a new pro forma Facilities Service Agreement (FSA). In SPP, an interconnection customer is responsible for 100% of the costs of network upgrades needed to accommodate its interconnection request. Article 11.4 in SPP’s pro forma GIA provides two options for funding the costs of network upgrades for generator interconnection. Under the first option, the interconnection customer pays for the network upgrade costs upfront during construction (Generator Upfront Funding). Under the second option, the transmission owner can unilaterally elect to provide the upfront funding for the capital cost of the network upgrades (Transmission Owner Initial Funding). SPP’s OATT did not contain provisions pertaining to how an interconnection customer would reimburse the transmission owner under the second option.
In the pro forma FSA, SPP proposed that the interconnection customer reimburse the transmission owner for a return on and of the capital costs of the network upgrades and system protection facilities needed for the interconnection customer’s interconnection service. Specifically, SPP proposes a default 20-year term over which the interconnection customer reimburses the transmission owner through a monthly network upgrade charge. The network upgrade charge is calculated using a formula rate that is based on the FSA’s term and the transmission owner’s Attachment H formula rate using data from the previous calendar year. Additionally, the pro forma FSA requires that the interconnection customer post security in the amount of the initial capital cost, which may be reduced pro rata over the FSA’s term. SPP stated that it also proposed revisions to its GIP and its pro forma GIA to effectuate certain provisions related to the pro forma FSA and the transmission owner’s election of Transmission Owner Initial Funding. FERC found that the nonbinding notice by the transmission owner indicating it intends to fund network upgrades could lead to greater uncertainty for interconnection customers as the transmission owner could later change its election which could cause risk and uncertainty and delays for interconnection customers and could lead to late-stage withdrawals and attendant delays in administering the generator interconnection queue. SPP contended that its filing and nonbinding transmission owner elections is substantially similar to generator interconnection procedures the Commission has accepted in MISO. FERC disagreed, as MISO proposed, and FERC accepted, revisions to its tariff to add deadlines by which transmission owners must make both non-binding and binding elections of Transmission Owner Initial Funding prior to the start of the GIA negotiation phase. The SPP proposal included only the non-binding indication provision during the first phase of SPP’s DISIS process. FERC rejected the SPP OATT changes. Therefore, though the SPP OATT provides for transmission owner funding of network upgrades, it still lacks provisions pertaining to how an interconnection customer would reimburse the transmission owner. In an Order on Rehearing in Docket No. EL22-34, FERC continued to find that the Ohio Office of Consumer Council (OCC) demonstrated that the Ohio Power and AEP Ohio Transmission (AEP) rates were unjust and unreasonable since FERC specifically granted them an RTO Adder under section 219, and their continued participation in a Transmission Organization is not voluntary and the RTO Adder should be removed from their rates. By contrast, OCC did not meet its burden to show that Duke and ATSI rates charged to Ohio customers were unjust and unreasonable as FERC had not specifically granted them an RTO Adder under section 219 and their rates, inclusive of any RTO Adder, were instead parts of comprehensive settlements. While OCC is correct that an applicant may make a section 205 filing in order to recover an RTO Adder in its rates, it does not follow that the Commission, in approving comprehensive settlement packages, specifically authorized RTO Adders in the section 205 proceedings that resulted in ATSI and Duke’s rates. Rather, in ATSI’s and Duke’s proceedings, even if the statements in the settlements indicated that the parties agreed to include an RTO Adder, FERC only approved comprehensive settlement packages without specifically approving the RTO Adder under section 219. FERC does not know the precise trade-offs and concessions made by the parties to those proceedings. Even if the settlements included an amount reflecting an RTO Adder, that does not explain how that RTO Adder came to be included in the settlement agreements and what trade-offs led to that outcome. It is FERC’s position not to revisit individual elements in a settlement unless it is shown that they make the overall rate unjust and unreasonable.
FERC found in the Rehearing Order that it had not err, as stated by AEP, by declining to address preemption arguments and whether the voluntariness requirement is consistent with the plain text of section 219. FERC previously addressed those issues in the RTO Adder Order and in the Dayton Orders. In summary, FERC has eliminated the RTO Adder for Dayton Power and Light, Duke and ATSI for their Ohio transmission services. Commissioner Danly continues to dissent as the Federal Power Act does not limit incentives to those utilities that voluntarily join a transmission organization, though he did concur with the decision not to reduce the rates of ATSI and Duke. On November 30, 2022, in Docket No. ER23-523, the Midcontinent Independent System Operator, Inc. (MISO), on behalf of the MISO Transmission Owners (MISO TO),[1] submitted proposed revisions to Schedule 2, Reactive Supply and Voltage Control from Generation or Other Sources Service of its Open Access Transmission, Energy and Operating Reserve Markets Tariff (Tariff). The MISO TOs proposed to eliminate all charges under Schedule 2 for the provision of reactive power within the standard power factor range (Reactive Service) from MISO TOs’ own and affiliated generation resources.[2] Based on the Commission’s “comparability standard,” MISO TOs stated that their proposal also terminates the obligation under Schedule 2 to pay unaffiliated generation resources in MISO for reactive power within the standard power factor range. FERC accepted MISO TOs’ proposed Schedule 2 revisions, effective December 1, 2022. This means that the $220 million being paid in MISO to generators for the provision of reactive power ends December 1, 2022.
Many comments were filed in this docket, particularly from generators opposing the elimination of reactive power compensation. Notwithstanding, FERC found that the revisions are just and reasonable and not unduly discriminatory or preferential. As FERC articulated in Order No. 2003, “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.” In Order No. 2003-A, FERC clarified, however, 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.” Consistent with Order No. 2003 and 2003-A, where a transmission provider does not separately compensate its own or affiliated generators for reactive power service within the standard power factor range, it is not required to separately compensate non-affiliated generators for reactive power service within the standard power factor range. Comparability entitles a generator to compensation for providing reactive power within the standard power factor range “if, and only if, the [t]ransmission [p]rovider pays its own or affiliated generators for reactive power within the [standard power factor range].” FERC found that MISO TOs’ proposed Schedule 2 revisions to eliminate compensation for its own and affiliated generation resources and unaffiliated generation resources and the associated charges to transmission customers is permitted under, and consistent with, Order Nos. 2003 and 2003-A. Additionally, FERC stated that Order Nos. 2003 and 2003-A do not mandate that once a transmission provider compensates its own or affiliated generators, it may never discontinue such compensation and must, as a result, always compensate unaffiliated generators. Rather, FERC precedent allows transmission providers to eliminate compensation for reactive power within the standard power factor range for all generators, regardless of whether the generator is owned by or otherwise affiliated with a transmission owner or is independent. FERC found protests that challenge these well-established policies to be collateral attacks on these earlier determinations. Commissioner Danly dissented, stating that, notwithstanding the increased rates and the administrative burden of the present compensation approach, FERC cannot simply accept the MISO TOs’ proposal unless they meet their section 205 burden that the proposed rate—in this case, the elimination of reactive power compensation—is just and reasonable based on substantial evidence in the record. He went on to state that the MISO TOs did not offer any evidence of the effects of eliminating the $220 million annual reactive power revenue requirement from the MISO tariff, and what is clear on the record is that separate reactive power compensation has been available in MISO for several years, and parties have taken this into account in their financings, bilateral contracting, power purchase agreements, and other arrangements. Commissioner Clements stated in a concurring statement that she encourages stakeholders in MISO to consider more effective alternatives to cost-based reactive power compensation as services should be appropriately compensated for the benefits they provide, and reactive power plays an important reliability function. She remains open to the possibilities of other reactive power compensation options, such as market solutions or compensation models that are based on the performance of the generators in providing reactive power when called upon, or that incentivize reactive power generation to be located where additional reactive supply is most needed from a reliability perspective. [1] MISO TOs include: Ameren Services Company, as agent for Union Electric Company, Ameren Illinois Company, and Ameren Transmission Company of Illinois; Arkansas Electric Cooperative Corporation; City Water, Light & Power (Springfield, IL); Cooperative Energy; Dairyland Power Cooperative; East Texas Electric Cooperative; Entergy Arkansas, LLC; Entergy Louisiana, LLC; Entergy Mississippi, LLC; Entergy Texas, Inc.; Great River Energy; Indianapolis Power & Light Company; Lafayette Utilities System; MidAmerican Energy Company; Minnesota Power (and its subsidiary Superior Water, L&P); Missouri River Energy Services; Montana-Dakota Utilities Co.; Northern States Power Company, a Minnesota corporation, and Northern States Power Company, a Wisconsin corporation, subsidiaries of Xcel Energy Inc.; Northwestern Wisconsin Electric Company; Otter Tail Power Company; Prairie Power, Inc.; Southern Indiana Gas & Electric Company; and Southern Minnesota Municipal Power Agency. [2] The phrase “standard power factor range” refers to the power factor range required for interconnection and set forth in the interconnecting generator’s generator interconnection agreement (GIA). MISO’s pro forma GIA prescribes a power factor range of 0.95 leading to 0.95 lagging. This range is also sometimes referred to as the “deadband.” |
Dr. Paul DumaisCEO of Dumais Consulting with expertise in FERC regulatory matters, including transmission formula rates, reactive power and more. Archives
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