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Donald J. Trump (R) was elected 45th President of the United States yesterday, a development that will likely change the way energy companies interact with regulators and the federal government. Without addressing the political issues associated with the race itself, we provide the following initial thoughts on practical issues regarding FERC associated with a shift in political party control of the Executive Branch, an event that has not affected Washington, D.C. since late 2008/early 2009.

Specifically, FERC currently has three sitting Commissioners, all Democrats. Mr. Trump’s election will permit his administration to dramatically change the make-up of the Commission. He may be able to appoint as many as four new Commissioners in 2017, and will almost certainly appoint a new Chair upon his inauguration. Notably, given the timing of the confirmation process for new FERC Commissioners, the current sitting Commissioners could be in control of FERC through at least April of 2017 assuming none of them resign in the interim. We explain below how these FERC changes will happen and provide a general sense of the timeline for new Commissioners and new leadership to be installed.

On November 1, 2016, FERC dismissed a complaint filed by the Vote Solar Initiative and the Montana Environmental Information Center (collectively, “Vote Solar”) against the Montana Public Service Commission (“Montana Commission”) alleging that the Montana Commission violated section 210 of the Public Utilities Regulatory Policies Act of 1978 (“PURPA”) by suspending NorthWestern Energy’s (“NorthWestern”) obligation to adhere to a standard rate for solar qualifying facilities (“QFs”) with a nameplate capacity between 100 kW and 3 MW. FERC dismissed the complaint on the grounds that: (i) it does not have jurisdiction to order the Montana Commission to take or not take particular actions; and (ii) Vote Solar is neither a QF nor an electric utility, and therefore is not permitted to file a petition for enforcement pursuant to section 210 of PURPA.

On November 1, 2016, FERC rejected arguments raised by numerous intervenors (“Environmental Intervenors”) that FERC had too narrowly defined its jurisdiction over Trans-Pecos Pipeline, LLC’s (“Trans-Pecos”) Presidio Border Crossing Project (the “Project”) and interconnecting intrastate pipeline (the “Trans-Pecos Pipeline”), which resulted in an abbreviated environmental review that failed to comply with the National Environmental Policy Act of 1969 (“NEPA”). In doing so, FERC found that the Trans-Pecos Pipeline will be an intrastate pipeline receiving natural gas produced solely in Texas, and thus environmental review of the construction and operation of the pipeline is not subject to FERC’s Natural Gas Act (“NGA”) Section 7 jurisdiction.

On October 31, 2016, FERC approved PJM Interconnection, L.L.C.’s (“PJM”) proposed revisions to Schedule 1 of the PJM Amended and Restated Operating Agreement (“Operating Agreement”) and the parallel provisions of Attachment K-Appendix of the PJM Open Access Transmission Tariff (“Tariff”). The approved revisions modify PJM’s compensation procedures for load reductions during emergency conditions.

On October 28, 2016, FERC issued an order that both partially accepted compliance filings and also denied rehearing requests from PJM Interconnection, LLC (“PJM”), Midcontinent Independent System Operator, Inc. (“MISO”) and MISO Transmission Owners regarding Order No. 1000 interregional compliance filings. Of particular concern for the Commission was the parties’ MISO-PJM Joint Operating Agreement (“MISO-PJM JOA”), and whether it failed to satisfy certain required Interregional Cost Allocation Principles. This is the third such order to address the parties’ compliance with the interregional transmission coordination and cost allocation requirements of Order No. 1000.

On October 25, 2016, FERC held that a pipeline providing interstate service pursuant to Natural Gas Policy Act (“NGPA”) Section 311 may not give preferential curtailment priority to preexisting, intrastate customers unless their intrastate transportation service agreements expressly provide for a higher curtailment priority above the pipeline’s other firm services. In doing so, FERC clarified that it is not enough that a preexisting intrastate service agreement has “different” curtailment provisions than the pipeline’s Statement of Operating Conditions (“SOC”) used to provide interstate service pursuant to NGPA Section 311.

On October 25, 2016, the United States Court of Appeals for the District of Columbia Circuit (“D.C. Circuit”) ruled that two Notices issued by the FERC Secretary as the result of a deadlock between the then-four sitting FERC Commissioners over whether to approve or set for hearing the rates established by ISO-New England, Inc.’s (“ISO-NE”) eighth Forward-Capacity Auction (“FCA 8”) were unreviewable. Specifically, the court concluded that: (i) the Notices did not constitute reviewable “agency action” as contemplated by the Federal Power Act (“FPA”), because, according to the court, the FPA requires a “majority” vote of the Commissioners in order for FERC to act institutionally; and (ii) the Notices were not reviewable under the Administrative Procedure Act (“APA”) by virtue of an unlawful “failure to act,” because the FPA does not mandatorily obligate FERC to either set disputed rates for hearing, or to affirmatively prevent any unjust and unreasonable rates from going into effect.

On October 26, 2016, FERC denied a rehearing request from San Diego Gas & Electric Company (“SDG&E”), Pacific Gas and Electric Company, and Southern California Edison Company following a March 2, 2016 order wherein FERC allowed only a 50 percent cost recovery in the event that SDG&E’s South Orange County Reliability Enhancement (“SOCRE”) transmission project is abandoned or canceled. As the Commission reiterated, utilities are generally allowed 100 percent cost recovery for abandoned or canceled projects only after a project is found eligible for “Abandonment Incentives,” whereas only 50 percent cost recovery is typically allowed for costs incurred before such determination. Thus, because SDG&E was not granted the Abandonment Incentive until FERC issued its March 2 order, FERC denied SDG&E’s request for an Abandonment Incentive for 100 percent of the prudently incurred costs prior to March 2, 2016. In reaching this conclusion, the Commission noted, “it would be reasonable to infer” that utilities are required to request eligibility for Abandonment Incentives before incurring significant expenditures on a transmission project.

On October 18, 2016, FERC accepted proposed changes to ISO New England Inc’s (“ISO-NE”) Transmission, Markets and Services Tariff (“Tariff”) intended to enhance liquidity in ISO-NE’s Forward Capacity Market (“FCM”). According to ISO-NE’s proposal, the changes – proposed jointly by ISO-NE and the New England Power Pool Participants Committee – will give qualified resources additional opportunities to provide capacity to the New England region.

On October 20, 2016, FERC issued an order that, among other things, rejected a refund report filed by the California Independent System Operator Corporation (“CAISO”). In so doing, FERC reiterated its discretionary authority to order refunds as well as its general policy to not exercise this discretion in situations involving cost allocation and rate design.