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On March 3, 2015, FERC approved Algonquin Gas Transmission, LLC’s (“Algonquin”) request to construct and operate its Algonquin Incremental Market Project (“AIM”) in New England.  As proposed, AIM is a 37-mile pipeline that, along with associated compression facilities, would deliver 342,000 dth/day from existing receipt points in New York to Connecticut, Massachusetts and Rhode Island.  In approving the project, FERC dismissed protesters’ environmental concerns, holding that the majority of AIM’s environmental impacts could be reduced through Algonquin’s mitigation plans.

On March 3, 2015, the Commission approved revisions to two regional Reliability Standards for the Western Electricity Coordinating Council (“WECC”) region, VAR-002-WECC-2 (Automatic Voltage Regulators) and VAR-501-WECC-2 (Power System Stabilizer), along with their associated violation severity levels, violation risk factors, and implementation plans.

On February 20, 2015, the Commission conditionally approved PJM Interconnection, L.L.C.’s (“PJM”) proposed modifications to the PJM Operating Agreement (“OA”) and the PJM Open Access Transmission Tariff (“OATT”) to allow for the planning and selection of “Multi-Driver” projects—i.e., transmission enhancements or expansions that address a combination of reliability, market efficiency, and public policy objectives—in the PJM Regional Transmission Expansion Plan (“RTEP”).  Additionally, the Commission approved an associated cost allocation method proposed by the PJM Transmission Owners for the newly adopted process.  Currently, PJM’s process selects projects based on one factor, but does not have a procedure in place for selecting projects based on a combination of factors.

On February 20, 2015, FERC rejected PJM Interconnection, L.L.C.’s (“PJM”) proposed tariff revisions to enter into out-of-market capacity contracts to address resource adequacy concerns for the 2015/2016 delivery year because the proposal was “unreasonably vague and ill-defined.”  As such, FERC denied PJM’s requested authority to compensate retiring generators to remain in-service.  FERC did, however, accept a separate but related resource adequacy waiver request that would allow PJM to retain 2,000 megawatts (“MW”) of capacity that PJM would have otherwise been required to release during the 2015/2016 delivery year.

On February 20, 2015, the U.S. Court of Appeals for the District of Columbia Circuit (“D.C. Circuit”) held that FERC had the authority to approve a cost pooling agreement among the carriers of the Trans Alaska Pipeline System (“TAPS”) that allocates certain fixed costs on the basis of each carrier’s share of combined interstate and intrastate utilization of TAPS.  In upholding this determination by FERC, the D.C. Circuit found that FERC could indirectly regulate intrastate oil prices as a result of its regulation of interstate prices.

On February 19, 2015, the Commission approved the North American Electric Reliability Corporation’s (“NERC”) proposed implementation of the Reliability Assurance Initiative (“RAI”)—an initiative aimed at creating a “Risk-Based” approach for compliance monitoring and enforcement of mandatory Reliability Standards.  Going forward, NERC believes that RAI will have Electric Reliability Organization (“ERO”) and industry resources more focused on higher-risk issues that significantly impact the reliability of the Bulk Electric System (“BES”).

On February 19, 2015, FERC directed the New York Independent System Operator, Inc. (“NYISO”) to propose new tariff provisions and a pro forma agreement for its reliability-must-run (“RMR”) service.  FERC stated that the RMR provisions are necessary because of the uncertainty and potential for reliability issues created by the lack of such RMR provisions within NYISO.

On February 19, 2014, FERC issued a Notice of Proposed Rulemaking (“NOPR”) proposing the sale of primary frequency response service at market-based rates by sellers with market-based rate authority for energy and capacity.  FERC also explained that the NOPR serves as an extension of the policy reforms set out in Order No. 784, the final rule on third-party provision of ancillary services and the accounting and financial reporting for new electric storage facilities (see July 29, 2013 edition of the WER).  In the NOPR, FERC concluded that companies that are able to pass “the existing market-based screens for sales of energy and capacity can adequately demonstrate a lack of market power for sales of primary frequency response service.” 

On February 2, 2015, the Commission directed Maxim Power Corporation, Maxim Power (USA), Inc., Maxim Power (USA) Holding Company Inc., Pawtucket Power Holding Co., LLC, Pittsfield Generating Company, LP (collectively “Maxim”), and Kyle Mitton, a Maxim executive (together “Respondents”) to show cause why they should not be found to have violated the Federal Power Act and the Commission’s regulations “through a scheme to obtain payments for reliability dispatches based on the price of expensive fuel oil when Maxim in fact burned much less costly natural gas.”  The Commission further directed the Respondents to show cause why they should not be assessed civil penalties of: (i) $50,000 (against Mr. Mitton); and (ii) $5,000,000 (against Maxim).

On February 9, 2015, FERC approved the Midcontinent Independent System Operator, Inc.’s (“MISO”) request for a temporary waiver of its $1,000/MWh energy offer price cap.  FERC’s approval will now allow generators with actual, verifiable costs above the $1,000/MWh energy offer price cap to receive make-whole payments by increasing the “No Load” component of their offer after consultation with MISO’s Independent Market Monitor (“IMM”).  The waiver of the energy offer price cap runs from December 20, 2014 to April 30, 2015.