On October 16, 2020, FERC issued a number of orders at its open meeting that addressed unrelated requests for retroactive waiver of various Regional Transmission Organization and utility tariff provisions. Commissioner James Danly issued a separate statement in each proceeding. Commissioner Danly dissented from many of the orders granting waiver and concurred in the result when the orders dismissed the requests for waiver or granted waiver in certain specific circumstances. In his dissent from an order granting Sunflower Electric Power Cooperative’s (“Sunflower’s”) petition for waiver of certain Southwest Power Pool, Inc. Tariff provisions, Commissioner Danly stated his belief that FERC has no legal discretion to grant retroactive waivers unless the waivers meet certain well-defined exceptions: first, if the parties had notice that tariff provision could be waived retroactively, or second, if the tariff provision is embodied in a private contract between parties who have agreed in the contract to make the rate effective prior to filing the contract with the Commission.

On October 15, 2020, FERC issued a notice of proposed policy statement (“Proposed Policy Statement”) with proposed guidance for oil pipeline carriers to demonstrate through tariff filings or declaratory order petitions that the rates and terms in long-term contracts with affiliate shippers (“Affiliate Contracts”) are just, reasonable, and not unduly discriminatory under the Interstate Commerce Act (“ICA”).

On October 15, 2020, FERC issued a notice of proposed policy statement on state-determined carbon pricing in wholesale markets that clarified the agency’s jurisdiction over wholesale market rules incorporating state-determined carbon prices and encouraged regional market operators to consider establishing such rules. FERC is seeking comment on the type of information it should consider when reviewing any such filings. While the Commissioners agree that FERC has jurisdiction to review these issues under 205 with respect to organized markets, they have signaled a divide with respect to the best course of action for addressing carbon pricing.

PJM Interconnection, L.L.C. (“PJM”) postponed its May 2019 annual capacity auction (known as a Base Residual Auction or “BRA”) pending further FERC orders over the expansion of PJM’s Minimum Offer Price Rule (“MOPR”) to cover all resources receiving “State Subsidies.” In an October 15, 2020 order (“October 2020 Order”) addressing arguments on rehearing, PJM’s MOPR-related compliance filings, and PJM’s proposed May 2019 BRA implementation schedule, FERC largely upheld its April 16, 2020 order on rehearing (“April 2020 Order”) (see April 22, 2020 edition of the WER) of its December 19, 2019 order in which it directed PJM to apply the MOPR to all state-subsidized capacity resources (“Replacement Rate Order”) (see December 20, 2019 edition of the WER). In the October 2020 Order, FERC also largely accepted PJM’s March 2020 and June 2020 MOPR-related compliance filings; directed PJM to submit a further compliance filing on certain issues; and set aside its April 2020 Order on limited grounds.

Most notably, FERC:

  • Set aside its finding in the April 2020 Order that state default service auctions meet the definition of State Subsidy, and accepted in PJM’s proposal to exclude independently evaluated, non-discriminatory, fuel-neutral, competitive state-directed default service auctions from application of the expanded MOPR;
  • Directed PJM to submit a compliance filing:
    • proposing further revisions to the provisions governing which resources are eligible to elect the Competitive Exemption from the MOPR;
    • modifying its proposal regarding the gaming provisions that dictate under what circumstances a resource that elects the Competitive Exemption and then accepts a State Subsidy will forfeit its capacity revenue; and
    • modifying its tariff to provide 30 days for sellers to notify PJM of a material change in subsidy status unless such material change occurs within 30 days of the auction, in which case sellers will have five days to notify PJM of the change; and
  • Granted PJM’s proposed implementation schedule for the 2019 BRA and subsequent BRAs, but found that PJM could not commence the BRA schedule until FERC has issued a subsequent order on compliance filing in another case in which FERC directed PJM to adopt operating reserve demand curves and to calculate forward looking energy and ancillary service off-sets reflecting this market rule change (“Reserves Proceeding”) (see May 28, 2020 edition of the WER).

On October 15, 2020, FERC issued an order sustaining, with modifications, its previous denial of a complaint that claimed New York Independent System Operator, Inc.’s (“NYISO”) buyer-side market (“BSM”) power mitigation rules were unjust, unreasonable and unduly discriminatory. FERC upheld its previous determination that the application of BSM rules to electric storage resources (“ESRs”) does not inappropriately interfere with state policies and that the complainants failed to show that NYISO’s existing rate was unjust and unreasonable because it over-mitigates electric storage resources. FERC’s order sparked a dissent from Commissioner Glick who argued that the majority’s order was arbitrary and capricious, and that BSM power mitigation should only apply to buyers with market power.

On October 15, 2020, FERC issued a Notice of Proposed Rulemaking (“NOPR”) to revise its regulations implementing the Public Utility Regulatory Policies Act of 1978 (“PURPA”) to permit Solid Oxide Fuel Cell systems with integrated natural gas reformation equipment to be certified as cogeneration qualifying facilities (“QFs”). FERC proposed the changes in response to what it termed the “technical evolution of cogeneration,” and in response to Bloom Energy Corporation’s (“Bloom Energy”) petitioning FERC for such revisions.

On October 6, 2020, the California Independent System Operator (“CAISO”), California Public Utilities Commission (“CPUC”), and the California Energy Commission (“CEC”) (collectively, “Joint Entities”) announced that their preliminary analysis pointed to a number of factors that caused two mid-August electricity outages in CAISO. Specifically, the group’s Preliminary Root Cause Analysis report (“Preliminary Analysis”) concluded that the outages resulted from a convergence of factors, including (i) the extreme west-wide heat storm, (ii) shortfall in system planning, and (iii) certain day-ahead energy market practices.  As directed by Governor Newsom, the Preliminary Analysis includes immediate, near, and longer-term actions that can be taken to minimize future power outages.

On October 7, 2020, FERC affirmed its prior determination that certain demand response resources participating in the New York Independent System Operator, Inc. (“NYISO”) capacity markets—termed Special Case Resources (“SCRs”)—should be subject to an offer floor, and required revenues from some retail-level demand response programs to be included in the offer floor calculations. Specifically, FERC: 1) addressed requests for rehearing of its February 2020 Order directing NYISO to apply its buyer-side mitigation (“BSM”) rules to all SCRs that participate in NYISO’s Installed Capacity (“ICAP”) market; 2) accepted NYISO’s compliance filing clarifying the offer floor price calculation for SCRs and directed NYISO to submit a further compliance filing; and 3) found, on the basis of a paper hearing established in the February 2020 Order, that payments received under the Distribution Load Relief Programs (“DLRP”) qualify for exclusion from the calculation of SCR offer floors, but that payments received under the Commercial System Distribution Load Relief Programs (“CSPRs”) do not. Commissioner Richard Glick issued a strenuous dissenting opinion to FERC’s order.

On October 7, 2020, the United States Court of Appeals for the Ninth Circuit (“Ninth Circuit”) vacated, as moot, two FERC orders asserting concurrent jurisdiction to review the disposition of certain Pacific Gas & Electric Corporation (“PG&E”) power purchase agreements (“PPAs”) that PG&E sought to reject through bankruptcy. In a brief memorandum decision, a three-judge Ninth Circuit panel explained that the orders had become moot when the bankruptcy court confirmed a reorganization plan that had PG&E assume, rather than reject, the PPAs. In the same decision, the Ninth Circuit vacated a related bankruptcy court order in which the bankruptcy court determined that FERC does not have concurrent jurisdiction with the bankruptcy courts over the rejection of such PPAs. In vacating the three orders, the Ninth Circuit expressed no opinion on the merits of the consolidated appeal, and left open the question of whether FERC and the bankruptcy courts have concurrent jurisdiction over wholesale power contracts in Chapter 11 bankruptcy proceedings.

On September 30, 2020, FERC held a technical conference focusing on how state-adopted carbon pricing intersects with a Regional Transmission Organization/Independent System Operator (“RTO/ISO”) administered market, and specifically what considerations a carbon-pricing framework may raise for FERC and/or the markets it oversees. The conference included three panels focused on: (i) the legal considerations associated with the integration of state carbon prices in FERC-regulated markets, including FERC’s statutory authority to implement carbon pricing in RTO/ISO markets and prior FERC precedent on RTO/ISO proposals to incorporate costs associated with state cap-and-trade programs, (ii) carbon pricing mechanisms, including current RTO/ISO initiatives to consider the integration of state carbon pricing actions and challenges for carbon pricing in multi-state RTO/ISO markets, and (iii) market design considerations, such as methods to reduce leakage and the potential operational impacts arising from carbon pricing. Finally, the technical conference concluded with a roundtable discussion reflecting on key issues and insights raised during the conference (see September 10, 2020 edition of the WER).