FERC June Open Meeting Decisions of Interest

Jun 23, 2015 by Eric DeBellis, NRDC Legal Intern

ISO New England, Inc., Docket No. ER15-1137-000

FERC accepted ISO New England’s filing of its ninth forward capacity auction results. In approving the filing, FERC rejected Utility Workers Union’s objection to New England ISO’s results.

As it did in response to the previous year’s auction results, Utility Workers Union alleged Energy Capital Partners inflated the future capacity price for the Southern Massachusetts and Rhode Island zone by unlawful market manipulation. The union argued that New England ISO’s tariff allows for the retirement of a resource only if it has been shown to be uneconomic to run on a stand-alone basis. Utility Workers Union alleged that Energy Capital Partners retired the economically viable Brayton Point Power Station to remove its capacity from the auction and thereby increase profits from the firm’s other assets. According to Utility Workers Union’s interpretation, withholding economically viable capacity from the auction violated the tariff and constituted unlawful price manipulation for profit. FERC rejected this interpretation, finding the Energy Capital Partners properly retired the Brayton Point Power Station and thus not only could, but had to, withhold its capacity from the auction.

Riggs v. Rhode Island PUC, Docket No. EL15-61-000

FERC denied a petition seeking a PURPA enforcement action against the Rhode Island Public Utilities Commission. The petitioner, a retired Navy pilot, alleged that approval of a power purchase agreement between Deepwater Wind Block Island and Narragansett Electric (d/b/a National Grid) violated PURPA, the Federal Power Act, and the Supremacy Clause. In 2009, the Rhode Island General Assembly passed an act enabling the purchasing power agreement. To encourage renewable energy development, the legislation provided for Deepwater potentially to recover more than avoided costs. In his complaint, Mr. Riggs argued that the agreement’s terms infringed on federal jurisdiction by subsidizing a wholesale generator’s rates. FERC found no grounds to commence an enforcement action, leaving the petitioner to decide whether to file the claim in court himself.

This is not the first time Ben Riggs has petitioned FERC unsuccessfully for an enforcement action regarding Deepwater’s wind power development efforts in Rhode Island. In 2012, Riggs petitioned FERC to challenge the Rhode Island PUC’s renewable energy incentives. FERC denied that petition as well.

Consolidated Edison Co. of New York v. PJM Interconnection, LLC, Docket No. EL15-18-000 et al.

FERC denied Con Ed’s challenge under Federal Power Act section 206 to PJM’s cost allocation for two transmission projects in New Jersey. PJM calculated half of each party’s share of costs under a load-ratio share and the other half by the solution-based distribution factor (DFAX) method. By this method, PJM allocated $629 million of the Bergen-Linden Corridor Project’s costs to Con Edison and $52 million to public Service Electric & Gas Co. (PSEG). Con Edison objected to this cost allocation, arguing that the Bergen-Linden Corridor Project primarily would benefit PSEG and its customers, making Con Ed’s much larger cost allocation inconsistent with “beneficiary pays” principles. Con Ed and Linden also challenged the cost allocation of the Sewaren Project, for which PJM assigned all costs to Con Edison and Linden and none to PSEG.

Con Ed’s argument centered on the tariff’s “objectively unreasonable” clause, which Con Ed argued required PJM to use an alternative method to allocate costs if the solution-based DFAX method allocated the project’s costs in a manner not commensurate with its benefits. PJM disagreed, interpreting the provision to allow PJM to use an alternative formula only when the model estimated electric flows that were objectively unreasonable according to engineering principles. FERC sided with PJM, finding that the “objectively unreasonable” clause called for consideration of engineering principles, not “beneficiary pays” principles. Without the necessary engineering findings, the filed rates doctrine bound PJM to apply the FERC-approved formula.

Delta-Montrose Electric Association, Docket No. EL15-43-000

FERC found it had jurisdiction to invalidate terms of a power purchase agreement that conflicted with PURPA. Tri-State Generation and Transmission Association—a non-profit cooperative owned by a network of forty-four small electric cooperatives—successfully argued that it is exempt from FERC regulation under the Federal Power Act (FPA). However, FERC found that Tri-State’s contract with one of its member cooperatives was subject to PURPA regardless because the member cooperative itself was a public utility and could not contract away its PURPA obligations.

In 2001, Tri-State entered into a wholesale electric service contract with rural electric cooperative Delta-Montrose Electric Association, agreeing to provide Delta-Montrose with at least 95 percent of its capacity and energy needs through 2040. The contract allowed Delta-Montrose to provide the rest of its needs from generation it owns and controls, but it did not address whether Delta-Montrose could purchase power from third parties. The dispute at issue arose after Delta-Montrose received a request to purchase power from a hydroelectric project, which would bring total purchases from third parties above 5 percent of need.

Delta-Montrose petitioned FERC to declare that Tri-State was too large to qualify for an exemption from FPA ratemaking requirements. Delta-Montrose argued this would place Tri-State—and therefore Tri-State’s purchase power agreement with Delta-Montrose—under FERC’s jurisdiction. Federal Power Act Section 201(f) exempts any “electric cooperative that receives financing [from the Rural Utility Service] under the Rural Electrification Act of 1936 or that sells less than 4 [million MWh] of electric power per year.” Delta-Montrose argued Tri-State no longer qualified for this exemption because it recently retired its entire Rural Utility Service debt and it owned and operated interstate transmission facilities that together sold over 18 million MWh of wholesale power annually.

FERC rejected Delta-Montrose’s characterization of Tri-State as one large utility. Instead, FERC treated Tri-State as an extension of the several small utilities that collectively owned it. Each of the small cooperatives that owned Tri-State qualified for the exemption, so Tri-State was not one large, non-exempt utility but rather a group of small, exempt utilities. FERC’s finding that Tri-State is exempt from FPA ratemaking requirements, though, did not defeat Delta-Montrose’s PURPA claim.

FERC found that, despite Tri-State’s exemption from the FPA, the other party to the power purchase agreement—Delta-Montrose—was itself a public utility under PURPA. Therefore, FERC found that PURPA section 210 required Delta-Montrose, as a public utility, to purchase available power from any qualifying facility. PURPA preempts the terms of a purchase power agreement. As a result, Delta-Montrose must purchase available power and capacity from Pencheron’s hydro units (at negotiated rates), regardless of the terms of its contract with Tri-State.

PáTu Wind Farm, LCC v. Portland General Electric Co., Docket Nos. EL15-6-001 and QF06-17-003

FERC denied rehearing of a January 22, 2015 order requiring public utility Portland General Electric Co. to buy the entire net output of PáTu, a small Oregon wind farm according to the terms of the Oregon Public Utilities Commission’s standard contract under PURPA (Standard Contract). In its January 22 order, FERC found that Portland General could not avoid its obligation under PURPA to purchase all of PáTu’s net output by conditioning its purchase on scheduling requirements with which PáTu could not reasonably comply. FERC ordered Portland General to accept PáTu’s entire net output delivered to Portland General and to do so at avoided cost rates.

After the January 22 order, Portland General informed PáTu that the utility would purchase the wind farm’s entire net output delivered according to an hourly schedule. The parties sought a rehearing to clarify whether Portland General may refuse to purchase power that is not delivered according to an hourly schedule.

In its denial of rehearing, FERC clarified that Portland General could not impose an hourly rate schedule on PáTu because the wind farm could not reasonably predetermine its hourly output. To adhere to hourly scheduling, a generator must be able to state its output ahead of time with more assurance than is possible for variable resources. Thus, FERC found that conditioning power purchases under the Standard Contract on hourly scheduling imposed an unreasonable barrier to wind farms like PáTu. Accordingly, FERC struck down this requirement, ordering Portland General to allow PáTu to schedule rates on a dynamic (real-time) basis.

Notice of Proposed Rulemaking: Transmission Operations Reliability Standards and Interconnection Reliability Operations and Coordination Reliability Standards, Docket No. RM15-16-000

FERC proposes to adopt several revisions by NERC to electric reliability standards under Federal Power Act section 215. FERC would replace the eight current transmission operations (TOP) Reliability Standards with three standards as well as adjust IRO Reliability Standards and multiple definitions of terms.

The TOP standards would govern transmission operators’ authority to prevent and respond to outages, revise operations planning provisions and establish data collection, retention, and distribution requirements for transmission operators and balancing authorities.

The IRO standards would revise reliability coordinators’ responsibilities within their respective regions, establish standards for real-time data monitoring and analysis capabilities, establish requirements for reliability coordinators to conduct next-day analyses and real-time operating conditions assessments, establish means to provide reliability coordinators with data necessary to help prevent instability, uncontrolled separation, or cascading outages, set rules for the harmonization of reliability coordinators’ respective roles in interconnected operations and introduce a new Reliability Standard intended to facilitate planned outage coordination across planning time horizons.

In its notice of proposed rulemaking (NOPR),  FERC solicited comments on four topics in particular: (1) possible inconsistencies in identifying interconnection reliability operating limits (IROLs); (2) monitoring of non-bulk electric system facilities; (3) removing of the load-serving entity as an applicable entity for proposed Reliability Standard TOP-001-3 (transmission operations); and (4) data exchange capabilities.

In support of its revisions, NERC asserted that the proposed Reliability Standards would improve operation within system operating limits, outage coordination, situational awareness, clarity of definitions of terms, and requirements for operational reliability data. FERC emphasized throughout the NOPR that the new standards and definitions would simplify, and therefore encourage compliance by transmission operators.

Comments on the proposal are due to FERC 60 days after publication in the Federal Register.

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