Miles Kiger

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In orders issued on January 25 and 28, 2019, FERC concluded that the Commission and the bankruptcy courts have concurrent jurisdiction to review and address the disposition of FERC-jurisdictional contracts sought to be rejected through bankruptcy and, therefore, a party to a FERC-jurisdictional wholesale power agreement must first obtain approval from both FERC and the bankruptcy court to modify the filed rate and reject the filed wholesale power contract, respectively.  FERC made its determination in response to two separate petitions (“Petitions”) filed by NextEra Energy, Inc. and NextEra Energy Partners, L.P. (collectively, “NextEra”) and Exelon Corporation (“Exelon”), individually, against Pacific Gas and Electric Company (“PG&E”).  In those Petitions, NextEra and Exelon asked FERC to clarify its authority regarding the prospect of PG&E seeking to reject or amend FERC-jurisdictional wholesale power agreements in its anticipated bankruptcy proceeding.  On January 29, 2019, PG&E submitted its anticipated bankruptcy filing in the U.S. Bankruptcy Court for the Northern District of California.   

On January 17, 2019, FERC denied North Carolina Electric Membership Corporation’s (“NCEMC”) Formal Challenge and Complaint against Duke Energy Progress, LLC’s (“DEP”) transmission formula rate and Joint Open Access Transmission Tariff (“Joint OATT”) for failing to reflect in its wholesale transmission rates reductions related to federal, and North Carolina state, corporate income tax changes.  For various reasons discussed below, FERC denied NCEMC’s Complaint because it found that DEP had correctly applied its historical test year formula rate methodology.

On January 8, 2019, FERC approved revisions to the PJM Interconnection, L.L.C. (“PJM”) Tariff and Operating Agreement regarding the use of transmission constraint penalty factors in its market operations.  PJM’s filing responds to new market transparency requirements set out in Order No. 844, the result of FERC’s rulemaking addressing uplift cost allocation and transparency in Regional Transmission Organizations (“RTOs”) and Independent System Operators (“ISOs”).  In accepting PJM’s proposed revisions, FERC found the revisions would provide transparency regarding PJM’s transmission constraint penalty factor procedures and also produce more transparent and appropriate pricing and investment signals that correspond to an underlying transmission constraint.

On December 20, 2018, FERC proposed to revise the horizontal market power analysis required for electric power sellers seeking to obtain or retain market-based rate authority in certain organized wholesale power markets (“NOPR”).  Specifically, FERC proposed to relieve electric power sellers of the obligation to submit indicative screens when seeking to obtain or retain market-based rate authority in any Regional Transmission Organization (“RTO”)/Independent System Operator (“ISO”) market with FERC-approved RTO/ISO monitoring and mitigation, thus easing the regulatory burden for certain market-based rate sellers.  However, FERC proposed to continue to require market-based rate sellers in an RTO/ISO to submit indicative screens for authorization to make capacity sales at market-based rates in any RTO/ISO market that lacks an RTO/ISO-administered capacity market subject to FERC-approved RTO/ISO monitoring and mitigation.

On November 19, 2018, FERC accepted ISO New England Inc.’s (“ISO-NE”) request to terminate the capacity supply obligation (“CSO”) of the Clear River Unit 1 natural gas-fired generator (“Clear River”) for the 2021–2022 Capacity Commitment Period. In doing so, FERC found that ISO-NE had the right under its Tariff to terminate Clear River’s CSO because Clear River’s project sponsor, Invenergy Energy Management LLC (“Invenergy”), had covered Clear River’s CSO for two consecutive Capacity Commitment Periods. In the same order, FERC denied Invenergy’s request for waiver of certain provisions of ISO-NE’s Tariff related to the termination of Clear River’s CSO.

On October 15, 2018, FERC issued two orders involving rate of return on equity (“ROE”): the first was an order directing parties in two proceedings involving the base ROE of the transmission owning members of the Midcontinent Independent System Operator, Inc. (“MISO”) to submit briefs concerning a proposed change in FERC’s approach to determining the base ROE of public utilities previously outlined in Martha Coakley v. Bangor Hydro-Elec. Co. (“Coakley Briefing Order”) (see October 25, 2018 edition of the WER); the second was an order providing guidance regarding the effect of the Coakley Briefing Order on pending proceedings involving base ROE issues that have been set for hearing and settlement judge procedures.

On November 5, 2018, FERC granted in part and denied in part a rehearing request (“Rehearing Order”) filed by Ameren Services Company (“Ameren Services”), on behalf of its affiliate Ameren Transmission Company of Illinois (together with Ameren Services, “Ameren”) of a FERC order (“February 13 Order”) denying Ameren’s request pursuant to Order No. 679 for a 100 basis point incentive rate of return on equity (“ROE Incentive”) for the Illinois Rivers and Mark Twain components (“Components”) of the Grand Rivers Project (“Project”).  In the February 13 Order, FERC denied Ameren’s requested ROE Incentive for the Components, largely because of construction progress made to date on the Illinois Rivers component.  In the Rehearing Order, FERC granted rehearing in part with respect to the Mark Twain component because that component is not substantially complete and, because based on its own merits, the Mark Twain component continues to face risks and challenges that warrant an ROE Incentive.  FERC denied rehearing with respect to the Illinois River component, however, upon finding that given the substantial completion of the Illinois Rivers component and limited remaining risks and challenges Ameren faces with respect to that component, Ameren’s requested ROE Incentive for Illinois River failed to meet the nexus test.

On October 31, 2018, FERC accepted revisions to the Midcontinent Independent System Operator, Inc.’s (“MISO”) Open Access Transmission, Energy and Operating Reserve Markets Tariff (“Tariff”) to enhance the locational aspects of its resource adequacy construct (“Filing”).  In March of 2018 (“March 2018 Filing”), MISO had proposed a similar filing, which FERC rejected, without prejudice, on August 2, 2018.  There, FERC found two elements of the March 2018 Filing to be unjust and unreasonable, but FERC provided MISO with guidance with respect to any future filing.  With the exception of those two elements, MISO stated that its Filing contains the same proposal and justification for the proposal as in its March 2018 Filing.

On October 22, 2018, FERC Commissioner Kevin McIntyre announced in a letter to President Donald Trump that he would step down from his role as Chairman and would continue his work as Commissioner.  In addition, President Trump announced on October 24, 2018 that current FERC Commissioner and former Chairman Neil Chatterjee would replace Commissioner McIntyre as FERC Chairman.

On October 12, 2018, FERC rejected without prejudice a proposal submitted by Midcontinent Independent System Operator, Inc. (“MISO”) and a group of MISO Transmission Owners (“MISO TOs”) (together, “Filing Parties”) to add a new Schedule 50 to MISO’s Open Access Transmission, Energy and Operating Reserve Markets Tariff (“Tariff”) that would enable MISO TOs to recover reasonable expenses, including overhead costs, associated with operation, maintenance, and repair of a transmission owner’s interconnection facilities (“TOIF”).  FERC rejected the proposal without prejudice because it relied on estimated construction costs of the TOIF without the requirement to support the reasonableness of such estimated costs.