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On November 19, 2015, FERC issued an order granting rehearing of its prior June 30, 2015 order accepting and suspending tariff records, subject to refund, filed by Alliance Pipeline L.P. (“Alliance”). In the prior order, FERC had set for hearing, among other issues, Alliance’s proposal to eliminate Authorized Overrun Service (“AOS service”) from its Rate Schedule FT-1. In the rehearing order, FERC held that Alliance could not eliminate AOS service from its Rate Schedule FT-1, because it had entered into negotiated agreements that set specific, negotiated rates for AOS service, and hence removal of AOS service from its tariff would violate these negotiated transportation service agreements without justification. FERC held that the Memphis Clause in each of the negotiated transportation service agreements would permit Alliance to modify tariff provisions of general applicability to all shippers where the Commission determined such modification to be just and reasonable, but did not support modifying, without some further justification, rates or services specifically negotiated over and agreed upon in the negotiated transportation service agreements. On the other hand, FERC directed Alliance to eliminate from the GT&C section of its tariff provisions providing that AOS service would have priority over IT service. FERC held that these provisions were both (1) contrary to its policy that overrun service and IT service should have equal priority and (2) not the subject of specific negotiation and agreement in the negotiated transportation service agreements.

On November 24, 2015, the Commission accepted and suspended proposed amendments to PJM Interconnection L.L.C.’s (“PJM”) Open Access Transmission Tariff (“OATT”) that allocated cost responsibility for two transmission upgrades: the Bergen-Linden Corridor Project, and the Artificial Island Project. In suspending the proposed amendments, the Commission ordered staff to convene a technical conference on whether the use of the solution-based distribution factor (“DFAX”) cost allocation methodology results in rates that are just and reasonable when applied to transmission enhancements and expansions that address reliability violations that are not related to flow on the planned transmission facility, as approved by the Commission in Schedule 12 of the PJM OATT for assigning the costs of transmission upgrades.

On November 17, 2015, the Federal Energy Regulatory Commission (“Commission”) terminated the proceeding in which it was considering a proposed reporting requirement that would have required quarterly reporting of every natural gas transaction within the Commission’s Natural Gas Act jurisdiction that entails physical delivery for the next day or for the next month.  The Commission decided to terminate based on its determination that the proposed reporting requirement is not necessary at this time.

On November 20, 2015, the Commission amended its regulations to permit the sale of primary frequency response service at market-based rates by sellers with market-based rate authority for sales of energy and capacity.  As defined by the Commission, “primary frequency response service” is “a resource standing by to provide autonomous, pre-programmed changes in output to rapidly arrest large changes in frequency until dispatched resources can take over.”  The Commission clarified that sellers can provide primary frequency response service “irrespective of what specific equipment they may choose to use to make such sales.”

On November 19, 2015, FERC issued an order confirming that certain qualifying facilities (“QFs”) under the Public Utility Regulatory Policies Act of 1978 (“PURPA”) with market-based rate (“MBR”) authority, generator interconnection facilities, or other jurisdictional assets are exempt from section 203(a)(1) of the Federal Power Act (“FPA”), which requires public utilities to receive Commission authorization before acquiring or disposing of certain jurisdictional facilities.

On November 10, 2015, the Federal Energy Regulatory Commission (“FERC”) granted a motion for a technical conference and request to postpone the comment deadline (“Motion”) that was filed in response to the Notice of Proposed Rulemaking for the Collection of Connected Entity Data from Regional Transmission Organization and Independent System Operators (“NOPR”) that the FERC issued on September 17, 2015 (see September 21, 2015 edition of the WER). The FERC directed staff to convene a technical conference on December 8, 2015 and postponed the due date for comments on the NOPR until January 22, 2016.

On November 5, 2015, NERC reported to the NERC Board of Trustees (“NERC Board”) that it had been unable to identify groups of similarly-situated Transmission Owners (“TOs”), Transmission Operators (“TOPs”), Generator Owners (“GOs”), or Generator Operators (GOPs”), that should automatically qualify for a reduced set of compliance obligations through a “sub-set” list of Reliability Standards, as part of Phase II of NERC’s Risk-Based Registration (“RBR”) initiative. The NERC Board accepted the report, and endorsed a recommendation from NERC that such “sub-set” lists be granted by the NERC-led review panel to individual entities on a case-by-case basis, rather than as a class, at least for the time being.

On November 4, 2015, FERC issued an order conditionally accepting the North American Electric Reliability Corporation’s (“NERC”) compliance filings articulating its Reliability Assurance Initiative (“RAI”) concepts and programs, and providing details on NERC’s oversight and evaluation of the RAI program (“November Order”).  FERC’s acceptance is conditioned upon NERC providing additional information in its annual report on RAI and making an additional compliance filing to modify its Rules of Procedure within 120 days of the November Order.

On November 4, 2015, the California Independent System Operator Corporation (“CAISO”) Board of Governors unanimously approved certain design changes to the western Energy Imbalance Market (“EIM”). These changes and enhancements are part of CAISO’s “year 1 phase 2 enhancements” – including items and issues that the CAISO originally determined would benefit from having six months of operational experience under the EIM to inform their resolution, as well as certain items that were deferred from phase 1 to allow for additional stakeholder input.

On November 2, 2015, the Commission conditionally approved revised Regional Delegation Agreements (“RDAs”) between the North American Electric Reliability Corporation (“NERC”) and the eight NERC Regional Entities. The RDAs are the agreements through which NERC delegates to the Regional Entities its legal authority under Section 215 of the Federal Power Act to propose and enforce mandatory Reliability Standards.