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Highlights from FERC’s April Open Meeting Decisions

April 22, 2015

Welcome and congratulations to Norman Bay, who took over as Chairman of FERC on April 15! Here are summaries of some of the significant orders released at the first Commission meeting he conducted as Chairman on April 16 (plus one decision issued the following day).

Coordination of the Scheduling Processes of Interstate Natural Gas Pipelines and Public Utilities (RM14-2-000). The disconnect between the electric and gas industries is becoming a problem with greater use of gas-fired power plants for electric generation. FERC has taken a number of steps to improve gas-electric coordination (see our previous blog), including this final rule on gas-electric scheduling coordination.

FERC’s final rule adopts two proposals: (1) to move the deadline for scheduling gas transportation to later in the day (so that electric utilities can finalize their schedules before gas-fired generators have to make gas purchase arrangements) and (2) to add a third intraday nomination cycle during the gas operating day (to help shippers adjust their scheduling to reflect changes in demand). However, FERC rejected the proposal to begin the natural gas operating day five hours earlier (to alleviate potential morning gas supply shortages) on the basis that there was insufficient record evidence to support that change.

Cost Recovery for Natural Gas Facilities Modernization (PL15-1-000). FERC issued a policy statement allowing interstate natural gas pipelines to recover certain pipeline infrastructure modernization expenditures. The aim is to help enhance reliability, safety and regulatory compliance (with e.g., environmental and safety standards) by incenting improvements, upgrades, and replacement of old and inefficient compressors or leak-prone pipelines.

EDF, CLF, and the Sustainable FERC Project filed comments in support of FERC’s policy statement during its proposal stage. We emphasized the need to facilitate pipeline infrastructure modernization to reduce risks to safety and adverse environmental impacts caused by preventable methane leakage.

Transmission Investment Metrics (AD15-12-000). FERC staff conducted an initial study to identify metrics that could gauge the impact of FERC policies on timely and cost-effective transmission investment. From a range of metrics, FERC staff identified six for which data appear to be available. These fit into three categories: metrics on whether adequate transmission infrastructure exists in a particular region; metrics for assessing the impact of FERC policy changes (by comparing key parameters before and after changes); and metrics designed to evaluate key goals of Order No. 1000.

Of particular importance are metrics that could help evaluate Order No. 1000 implementation. For example, a key goal of Order No. 1000 is to support competition in transmission development, and one of the proposed metrics will measure the percentage of project bids or proposals from nonincumbent transmission developers in regional transmission planning by Order 1000 planning region.

There is not yet an established timeline for this initiative, but FERC staff may introduce additional metrics and perform targeted outreach to gather more information as next steps.

FERC comment on Grand River Dam Authority MATS extension request (AD15-6-000). FERC commented on Grand River Dam Authority’s (GRDA) request to U.S. EPA seeking an administrative order to allow GRDA an additional year to comply with EPA’s Mercury and Air Toxics Standards (MATS) rule (which limits mercury, acid gases, and other toxic emissions from power plants). GRDA’s request will allow its Unit No. 1 to operate for a full extra year (beyond the one-year extension already granted under Section 112(i)(3)(B) of the Clean Air Act) even though it will not be MATS compliant. GRDA asserts that unless it is able to procure replacement capacity and associated transmission service, the loss of Unit No. 1 would result in GRDA falling below the 12 percent capacity reserve requirement stipulated in Southwest Power Pool Criteria 2.1.9.

In commenting to EPA, FERC agreed with GRDA, stating that absent a significant change in future circumstances, Unit No. 1 is needed to maintain this reserve requirement and bulk-power system reliability. This is the second such fifth-year MATS extension request submitted to EPA; the first request made by another utility was based on the same rationale – that maintaining a noncompliant unit was necessary to maintain the 12 percent reserve requirement at a particular utility.

New York Independent System Operator, Inc. (ER13-102-005, ER13-102-006). FERC denied requests for rehearing of the Commission’s second compliance order on NYISO’s Order No. 1000 regional compliance. FERC accepted NYISO’s third compliance filing in part subject to another compliance filing. In particular, FERC found that NYISO’s revisions comply with FERC’s directive to clarify how NYISO will review the Transmission Owners’ local transmission plans to determine whether alternative transmission solutions might meet the system needs more efficiently or cost-effectively than solutions in the local plans.

Southwest Power Pool (ER13-366-004 et al.). FERC conditionally accepted Southwest Power Pool, Inc.’s tariff revisions responding to FERC’s October 16, 2014, second Order No. 1000 compliance order, subject to another compliance filing within 30 days (to clarify provisions related to rights-of-ways). FERC also denied LS Power Transmission, LLC and LSP Transmission Holdings, LLC’s request for rehearing of this order.

Virginia Electric and Power Company (QM15-1-000). FERC denied Virginia Electric and Power’s application to be relieved of its requirement under PURPA to enter into new obligations to purchase electric energy with respect to nine qualifying facilities owned by Community Energy Solar, LLC. FERC explained that rather than new obligations, there were already legally enforceable obligations in place that require Virginia Electric and Power to purchase electric energy from the nine facilities at issue.

Astoria Generating Co. v. New York Independent System Operator, Inc. (EL11-42-001 et al.). FERC denied rehearing and granted clarification, in part, of its June 22, 2012 order on a complaint filed by Astoria Generating Company, NRG Companies, and TC Ravenswood against NYISO, alleging that NYISO improperly implemented its buyer-side market mitigation provisions in the New York City installed capacity market. This order confirmed understandings of NYISO with respect to mitigation exemption testing and offer floor determinations, and clarifies the June 22, 2012 order with respect to: the inflation rate to use in applying the exemption test; NYISO’s evaluation of contracts to determine whether a cost is appropriate to use in determining a project’s Unit Net Cost of New Entry; and eligibility for retesting for market mitigation exemption. FERC also accepted tariff changes intended to increase transparency of NYISO’s market mitigation exemption process. It required NYISO to make a further compliance filing to modify its proposed tariff revisions related to the inflation component used for Unit Net Cost of New Entry.

Astoria Generating Co. L.P. and TC Ravenswood, LLC v. New York Independent System Operator, Inc. (EL11-50-001). FERC largely denied rehearing of a September 10, 2012 order on a complaint filed by Astoria Generating Company and TC Ravenswood against NYISO. The complaint alleged that NYISO improperly implemented its buyer-side market mitigation provisions in the New York City installed capacity market. The order mostly denied rehearing but grants rehearing of the earlier finding that NYISO erred in its Unit Net Cost of New Entry calculation. FERC also clarified when NYISO may use appropriate proxy data.

 New England Power Co. (ER15-418-001). FERC rejected New England Power’s section 205 filing revising its return on equity provision for integrated facilities service, finding that the revision would allow earning a total ROE on certain assets exceeding the zone of reasonableness.

Last, FERC issued an important decision the day after the FERC open meeting:

ISO New England Inc., New England Power Pool Participants Committee (ER14-2407-004). FERC had accepted ISO New England’s proposed tariff revisions intended to aid ISO-NE maintain reliability during winter 2014-2015 (2014-2015 Winter Reliability Program). FERC also required ISO-NE to initiate a stakeholder process to develop a proposal to address reliability concerns for the 2015-2016 winter and future winters as necessary. The New England Power Generators Association, Inc. requested that FERC clarify that ISO-NE is required to implement a market-based winter reliability solution in time for the 2015-2016 winter. FERC granted clarification and ISO-NE sought rehearing.

In this order, FERC granted ISO-NE’s rehearing request to allow the possibility that ISO-NE may file additional out-of-market winter reliability programs until its two-settlement capacity market design becomes effective in 2018. However, the Commission expects ISO-NE to abide by its commitment to work with stakeholders to expand any future out-of-market winter reliability program to include “all resources that can supply the region with fuel assurance,” such as nuclear, coal, and hydro resources.