Adrienne Thompson

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As part of the ongoing legal fallout from the 2000-2001 California energy crisis, on January 9, 2017, FERC issued an order clarifying that, for purposes of that proceeding, “pricing umbrella” evidence is relevant only for contextual purposes and cannot serve as a basis for finding refund liability. In this order, FERC clarified that “pricing umbrella” evidence may be introduced solely for the purposes of providing context for FERC’s consideration, and that such evidence should not constitute the basis for finding refund liability.

On January 4, 2017, FERC issued an order conditionally accepting certain Open Access Transmission Tariff (“Tariff”) revisions submitted by the Southwest Power Pool, Inc. (“SPP”) in November 2016. The proposed Tariff revisions amend Attachment AE of the SPP Tariff, including the sections governing the Auction Revenue Right (“ARR”) Allocation and Transmission Congestion Right (“TCR”) Offer and Bid submittal processes in SPP’s Integrated Marketplace.

On December 6, 2016, FERC issued an order partially denying and partially granting a complaint brought by a coalition of transmission customers (“Coalition”) of the Midcontinent Independent System Operator, Inc. (“MISO”). The Coalition argued that MISO misapplied portions of its open access transmission tariff (“OATT” or “Tariff”) regarding the 2016/2017 planning year resource auction. Although the Commission rejected the Coalition’s argument that MISO utilized an unjust and unreasonable methodology for calculating Sub-Regional Export and Import constraints for the 2016/2017 auction, FERC found that prospective application of those methodologies was no longer just and reasonable, and directed MISO to modify its Tariff accordingly.

On November 30, 2016, FERC issued an order accepting tariff revisions filed by Public Service Company of Colorado (“PSCo”) regarding penalty charges for energy imbalance and generator imbalance services under Schedules 4 and 9 of PSCo’s open access transmission tariff (“OATT”). FERC found the revisions, which PSCo filed to address the influx of variable wind generation on its system, to provide incentives for accurate scheduling from transmission customers.

On November 17, 2016, FERC issued Order No. 831, revising its regulations regarding incremental energy offer caps imposed by Regional Transmission Organizations (“RTOs”) and Independent System Operators (“ISOs”). As a result, RTOs and ISOs will be required to cap each resource’s “incremental energy offer”—the portion of an energy resource’s supply market offer that can vary depending on output or demand levels—at the higher of $1,000/megawatt-hour (“MWh”) or that resource’s verified actual or expected cost-based incremental energy offer. RTOs and ISOs must also cap verified cost-based incremental energy offers at $2,000/MWh when calculating locational marginal prices (“LMP”). According to FERC, Order No. 831 will reduce the likelihood that offer caps will suppress LMPs below the marginal cost of production, as well as ensure fair compensation for generators and more efficient resource dispatching from grid operators.

On November 4, 2016, FERC issued an order denying a complaint filed by HORUS Central Valley Solar 1, LLC and HORUS Central Valley Solar 2, LLC (jointly, “HORUS”) against the California Independent System Operator Corporation (“CAISO”). In the complaint, HORUS requested that the Commission prevent CAISO from imposing interconnection procedures and study requirements in addition to those already imposed on HORUS by the Western Area Power Administration (“WAPA”). In denying the complaint, FERC reaffirmed its existing policy that generators must obtain transmission service at or beyond the point where facility ownership changes, as well as beyond the interconnection point with the wider integrated grid. Because HORUS sought to connect to WAPA-owned interconnection facilities, and those facilities in turn interconnected with CAISO, HORUS was required to comply with both WAPA’s and CAISO’s interconnection procedures.

On November 4, 2016, FERC issued an order denying a complaint filed by HORUS Central Valley Solar 1, LLC and HORUS Central Valley Solar 2, LLC (jointly, “HORUS”) against the California Independent System Operator Corporation (“CAISO”). In the complaint, HORUS requested that the Commission prevent CAISO from imposing interconnection procedures and study requirements in addition to those already imposed on HORUS by the Western Area Power Administration (“WAPA”). In denying the complaint, FERC reaffirmed its existing policy that generators must obtain transmission service at or beyond the point where facility ownership changes, as well as beyond the interconnection point with the wider integrated grid. Because HORUS sought to connect to WAPA-owned interconnection facilities, and those facilities in turn interconnected with CAISO, HORUS was required to comply with both WAPA’s and CAISO’s interconnection procedures.

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 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 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.