Reliability

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On March 29, 2018, FERC issued an order accepting proposed modifications to the methodology used to evaluate the availability of resource adequacy (“RA”) resources and resulting charges and payments under the Resource Adequacy Availability Incentive Mechanism (“RAAIM”) administered by the California Independent Operator Corporation (“CAISO”).  In the order, FERC agreed that CAISO’s proposal addressed identified problems such as overweighting certain types of resource adequacy capacity and discouraging parties from providing other types of capacity.

 On March 29, 2018, FERC issued an order granting a limited tariff waiver request by the California Independent System Operator Corporation (“CAISO”) relating to participation requirements for certain demand response resources in the California Public Utilities Commission’s (“CPUC”) Demand Response Auction Mechanism (“DRAM”) with delivery obligations between April-October in 2018 and 2019.  The waiver, which was necessitated by recent changes in CAISO’s resource adequacy program, will allow CPUC-identified DRAM resources to meet their contractual and regulatory obligations.  In granting the waiver, however, FERC stated that DRAM contracts executed after the date of the order and that do not conform with current CAISO requirements should not be eligible for the waiver.

On March 9, 2018, a divided FERC approved the Competitive Auctions with Sponsored Policy Resources (“CASPR”) proposal submitted by the ISO New England Inc. (“ISO-NE”). Developed through an extensive stakeholder process that began in 2016, CASPR was promoted by ISO-NE as a mechanism to integrate out-of-market state resource policies that might otherwise suppress capacity market prices in ISO-NE’s capacity market. A divided FERC approved the proposal as a just and reasonable accommodation of state policies, with Commissioner Powelson dissenting, arguing that the proposal dilutes market signals and “threatens the viability” of ISO-NE’s capacity market. Commissioners LaFleur and Glick concurred with the outcome, but criticized the order’s guidance on adapting markets to state energy policies, and reliance on minimum offer pricing rules (“MOPRs”) as the “standard solution” to achieve that end.

On February 23, 2018, FERC approved PJM Interconnection, L.L.C.’s (“PJM”) changes to its tariff and Reliability Assurance Agreement (“RAA”) to revise Reliability Pricing Model (“RPM”) capacity market rules in order to accommodate greater participation from seasonal resources.  Specifically, FERC approved changes related to: (1) resource aggregation for submitting combined capacity market sell offers; (2) granting winter-period interconnection rights; and (3) demand response resource measurement and verification for seasonal resources.  However, FERC separately responded to complaints that the RPM does not adequately accommodate seasonal resources by directing FERC staff to establish a technical conference to explore whether further changes are needed to permit seasonal resource participation.

In dual orders issued on February 28, 2018, FERC affirmed that the current resource adequacy requirements of the Midcontinent Independent System Operator, Inc. (“MISO”) remain just and reasonable, and simultaneously rejected an earlier MISO filing that would have imposed additional resource adequacy program changes.  The rejection of MISO’s earlier filing came after the United States Court of Appeals for the D.C. Circuit (“D.C. Circuit”) granted FERC a voluntary remand to reconsider its previous conditional acceptance in light of NRG Power Marketing, LLC. v. FERC (“NRG”).

On February 28, 2018, FERC accepted ISO New England Inc.’s (“ISO-NE”) and the New England Power Pool Participants Committee’s (“NEPOOL”) tariff revisions to replace the capacity market’s existing bilateral contracting mechanism with a new mechanism, the Annual Reconfiguration Transaction (“ART”).  According to ISO-NE, the ART provides an alternative method to achieve the equivalent of a Capacity Supply Obligation (“CSO”) Bilateral while also accounting for a resource’s impact on reliability. 

On February 15, 2018, FERC issued a notice that staff will hold a technical conference on April 10-11, 2018 to discuss the participation of distributed energy resources (“DER”) in markets operated by Regional Transmission Organizations and Independent System Operators.  As FERC stated in the notice, the two-day conference will host…

In response to concerns regarding the changing nature of the nation’s energy supply portfolio and the emergence of promising energy storage technologies, the Commission in recent years issued several notices of inquiry, notices of proposed rulemaking, and policy statements regarding various energy storage and ancillary service supply issues.  Additionally, the Commission considered but ultimately declined to pursue the Department of Energy-initiated rulemaking on grid resiliency and reliability.  On February 15, 2018, however, the Commission took concrete action by issuing a pair of Final Rules, addressing (i) storage participation in regional markets; and (ii) the provision of primary frequency response, a critical grid support service.

On January 18, 2018, FERC took steps to develop supply chain risk management Reliability Standards and to approve several new Emergency Preparedness and Operations (“EOP”) Reliability Standards.  First, FERC issued a Notice of Proposed Rulemaking (“NOPR”) proposing to direct the North American Electric Reliability Corporation (“NERC”) to develop supply chain risk management requirements under the Critical Infrastructure Protection (“CIP”) Reliability Standards.  Second, in a separate order, FERC approved several new EOP Reliability Standards aimed at addressing emergency event reporting, roles and responsibilities during system restoration via blackstart resources, system restoration plans and coordination, and the loss of control center functionality. 

On January 18, 2018, FERC approved California Independent System Operator Corporation’s (“CAISO”) changes to its resource adequacy program to, among other things, (1) allow capacity located in a local capacity area, but procured as system capacity, to provide system substitution capacity during forced outages and (2) cap a load serving entity’s (“LSE”) monthly local capacity requirement at its monthly system capacity requirement.