Read our recent LawFlash analyzing the Federal Energy Regulatory Commission’s (FERC’s) Order No. 2222, which directs wholesale electric market operators to facilitate the participation of distributed energy resource (DER) aggregators under one or more participation models. The new rule vastly expands the opportunities for DERs, such as grid-enabled water heaters, small solar installations, and electric vehicles, to aggregate and compete alongside traditional generators for a slice of wholesale market revenues. ISOs/RTOs will have 270 days from the date the rule is published in the Federal Register to submit their compliance filings and propose implementation dates for their regions.
FERC has issued an order extending the blanket waivers of all requirements to hold meetings in person and/or to provide or obtain notarized documents in open-access transmission tariffs through January 29, 2021. The order continues the blanket waivers first issued on April 2, 2020, in response to requests from regulated entities, which were set to expire on September 1, 2020. FERC cites the coronavirus (COVID-19) national emergency proclamation issued by President Trump on March 13, 2020; the continued risk to health and safety currently presented by personal contact; and guidance from public health officials on social distancing as good cause for the waivers.
The Federal Energy Regulatory Commission (FERC) on December 19, 2019, directed PJM Interconnection to extend its minimum offer price rule (MOPR) from new natural gas–fired electric generators to also cover any generator that receives or is entitled to receive certain types of state subsidies. The rule aims at preserving competitive capacity auctions by preventing resources that receive subsidies from submitting bids that would otherwise be uneconomical—and therefore likely to “capture” a PJM capacity award based on a below-market capacity rate—if not for state support. The order means that existing or planned resources that expected to clear capacity markets with rates made economical by state subsidies will have to identify alternate strategies to generate revenue; so too will states seeking to promote the development or prevent the retirement of preferred but noncompetitive resources.
Morgan Lewis energy partner Ken Kulak takes a look at the role of regulation in defining the future of energy storage in Energy Policy Now, a podcast produced by the University of Pennsylvania Kleinman Center for Energy Policy. Ken also previews an upcoming FERC meeting during which the agency will consider plans submitted by regional transmission organizations to facilitate the participation of battery storage.
For the second time, PJM Interconnection, LLC (PJM) has suspended its 2019 Base Residual Auction (BRA) as directed by the Federal Energy Regulatory Commission (FERC). FERC found that delaying the auction until the Commission establishes a replacement rate would provide greater certainty to the market than conducting the auction under the existing rules.
PJM previously suspended the 2019 BRA when FERC granted PJM’s request to waive the auction timing requirements of its tariff to allow for a delay from May to August 2019.
Wholesale electricity sellers that are not government owned are subject to regulation by the Federal Energy Regulatory Commission. Obtaining FERC approval to sell wholesale electricity at “market-based rates” (which is nearly any sale regulated under the Federal Power Act that is not based on cost-of-service accounting) can be an intricate exercise, requiring the applicant to submit statistical horizontal market power screens. Within the FERC-regulated organized markets, the independent system operators and regional transmission organizations (ISOs/RTOs), monitoring staff and procedures, and transparent real-time and long-term demand and pricing information have led many market participants to conclude that the required market power statistical screen studies are of little value and function merely as an administrative impediment to doing business. On July 18, FERC issued a final rule, Refinements to Horizontal Market Power Analysis for Sellers in Certain Regional Transmission Organization and Independent System Operator Markets, Order No. 861, that relieves market-based rate (MBR) entities of the statistical screen requirements in some—but not all—of the ISO/RTO markets. This should streamline both the regulatory approval process for prospective MBR entities and the ongoing compliance process for MBR entities that file notices, triennial renewal applications, and similar documents with FERC.
Order No. 861 relieves MBR entities (most of which are independent generating companies and/or power marketers, and some of which are traditional franchised utilities) of the need to prepare and submit statistical screen analyses if the MBR applicant or holder is within the Northeastern and Central ISO/RTO markets—that is, ISO New England, New York ISO, PJM Interconnection, or Midcontinent Independent System Operator. In these ISO/RTOs, FERC found that the existence of both capacity and energy markets and the vigor of market monitoring and mitigation were sufficient to permit applicants to dispense with the horizontal screen studies.
When a business entity that is regulated by the Federal Energy Regulatory Commission (FERC) is closely related to another business entity, FERC takes the position that under some circumstances it may treat the two different legal entities as if they were one single entity. FERC ruled recently that it “may disregard the corporate form in the interest of public convenience, fairness, or equity” and “[t]his principle of allowing agencies to disregard corporate form is flexible and practical in nature.” As a result, a new power marketer could be barred by a Regional Transmission Organization (RTO) from participating in the market unless it paid off the debts to the RTO owed by another power marketer with the same business objectives and the same contacts and administrators as the bankrupt entity. This decision could make it difficult for public utilities to avoid the debts of their bankrupt affiliates, which could be attributed to the entire enterprise regardless of the final plan of bankruptcy, including the liquidation of the bankrupt entity.
When a debtor in bankruptcy is liquidated, or successfully emerges from bankruptcy, certain unsatisfied, unsecured pre-bankruptcy debts of that bankrupt debtor are discharged. The discharge functions as a defense by the debtor against the claims of the debtor’s creditors. Similarly, when a debtor in bankruptcy is affiliated (such as by common upstream ownership) with a non-bankrupt entity, the non-bankrupt affiliate is typically not presumed to be responsible for that bankrupt debtor’s unsatisfied obligations, unless some statutory, contractual or security arrangement makes the non-bankrupt affiliate liable for those obligations or one entity is viewed to be the “alter ego” of the other under applicable state law.