Energy Update October 2011

October 2011

From the editors of Wolters Kluwer Law & Business, this update describes important developments from CCH energy publications.

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Challenge to FERC’s Market-Based Rates Fails

Challenges to FERC’s 2007 Order establishing its market-based rate policy for wholesale sales of power were rejected by the U.S. Court of Appeals for the Ninth Circuit. FERC’s rigorous screening process to detect both horizontal (energy generation) and vertical (energy transmission) market power in energy sales prior to approving market-based rates was sufficient to ensure that rates were just and reasonable, as required under the Federal Power Act, the appellate court concluded. The suit was brought by representatives of consumer groups in Montana, Colorado, and New York and the attorneys general of Connecticut, Illinois, and Rhode Island. In light of the law of the circuit, relevant precedent, and the Supreme Court’s direction, FERC’s order establishing market-based rates did not violate the Federal Power Act per se. However, the court left open the possibility of a future as-applied challenge to FERC’s Order No. 697. (Montana Consumer Counsel v. Federal Energy Regulatory Commission (9thCir), CCH Utilities Law Reporter ¶14,822)

CAISO’s 2012 Grid Management Charge Proposal Accepted
The Commission has accepted the California Independent System Operator Corporation's (CAISO) 2012 Grid Management Charge (GMC) proposal to align its cost allocation categories more closely to its nodal market. In this filing, revisions to the GMC preserve the use of a formula rate with a revenue requirement cap. The Commission accepted the GMC revisions, which will simplify its rate design and provide greater clarity and predictability for its market participants. The proposal simplifies the rate design by reducing the number of formula rate changes from seven service categories to three. These three cost categories are very similar to those already used in the rate designs of other ISOs and RTOs with nodal markets. The Commission also accepted CAISO's proposal to mitigate the impact of the systems operations charge for a limited number of generation resources that are contractually precluded from passing the GMC resources through to their energy buyers. The Commission found that this provision was delineated carefully, was of limited scope and duration, and reasonably addressed the disproportionate impact of system operations charges on certain affected resources under the revised rate design. (136 FERC ¶61,236)

FERC Acts to Support Continued Reliability of Electric Grid

The Commission has taken steps to support continued transmission system reliability by proposing revisions to eight critical infrastructure protection reliability standards that include a new method of identifying cyber assets that are critical to the nation’s bulk power grid. The proposed “Version 4” CIP standard (which includes Violation risk factors and Violation severity levels (VSLs) are an interim step, FERC said in directing the electric industry and the North American Electric Reliability Corp. (NERC) to continue developing a comprehensive approach to assure the grid can withstand a cyber security incident. NERC is the Commission-certified electric reliability organization responsible for developing and enforcing mandatory reliability standards. More specifically, the Commission proposes to adopt the Version 4 CIP reliability standards because they provide a change in three respects: (1) Version 4 will result in the identification of certain types of critical assets that may not be identified under the current approach; (2) Version 4 uses bright line criteria to identify critical assets, eliminating the use of existing entity-defined risk-based assessment methodologies that generally do not adequately identify critical assets and removing the element of discretion in identifying these assets; and (3) Version 4 provides a level of consistency and clarity regarding the identification of critical assets lacking under Version 3. (FERC Statutes and Regulations Edition ¶32,679)

Rehearing on SPP’s Distribution Losses Granted

A request for rehearing, filed by Westar Energy Inc., asking the Commission to reconsider an earlier decision [136 FERC ¶61,003] regarding Southwest Power Pool's (SPP) distribution losses has been granted by the Commission. The Commission agreed that in order for transmission owners such as Westar to recover the costs associated with providing power to wholesale customers that take delivery of power at a distribution voltage, it was necessary for SPP to include language in its Network Integration Transmission Service Agreement (NITSA) to recover distribution losses associated with the transmission of power to the delivery point. However, the loss factor found in Westar's Open Access Transmission Tariff includes both transmission and distribution losses. The NITSA also provides for delivery to points of other host transmission owners. In order to ensure that Westar collects only collects distribution losses for delivery points on Westar's system, the Commission directed SPP to include language in its NITSA specifically stating that its composite loss percentages must exclude transmission losses. (136 FERC ¶61,223)

MISO Tariff Waiver Request Denied

A request for a tariff waiver, filed by Midwest Independent Transmission System Operator, Inc. (MISO) was denied by the Commission. MISO sought waiver of its Open Access Transmission, Energy and Operating Reserve Markets Tariff (Tariff) regarding the planning and cost allocation of network upgrades, in order to establish a transition for the integration of Entergy Corporation and its operating companies into MISO as new transmission-owning members. MISO stated that, during the transition period, the cost of network upgrades located entirely within either its current footprint (the Northern Planning Region) or Entergy (the Southern Planning Region) will be allocated only within each respective planning region.. If their systems are not comparable in those respects, and this issue is not addressed, MISO contends that subsidization could occur between the Northern and Southern Planning Regions. The Commission found the requested waiver of certain sections of the MISO tariff was an inappropriate vehicle for implementing the transition period that MISO seeks for Entergy. It also found that MISO's proposal would alter the existing cost allocation methodology for the existing MISO footprint and apply a new cost allocation methodology to Entergy during the proposed transition period. As a result, MISO's proposal would affect the rates and charges for jurisdictional service significantly. Such changes should not be effectuated by a waiver of the tariff but should be submitted via a properly supported filing with tariff sheets setting forth the cost allocation provisions that would apply to the Northern and Southern Planning Regions during the transition period. Finally, the requested waiver does not satisfy the Commission's requirements for waiver of tariff provisions. MISO's proposed waiver is not limited in scope and lacks specificity. (136 FERC ¶61,212)

NRC Extends Construction Permit for Bellefonte, Unit 1

The Commission has extended the construction permit for Tennessee Valley Authority’s (TVA) unfinished Unit 1 reactor at the Bellefonte site near Scottsboro, Alabama. The permit extension request, which would have expired on October 1, is now valid until October 1, 2020. After withdrawing both Bellefonte permits in 2006, TVA determined in August 2008 that completing the Bellefonte reactors could be viable and requested that the NRC reinstate the permits. The NRC reinstated the permits in March 2009, returning the plant to “terminated” status under the Commission Policy Statement on Deferred Plants. In January 2010 the NRC placed the plant in “deferred” status. TVA must re-establish control over the plant’s physical condition and records regarding the quality of Units 1 and 2 before the NRC will authorize a return to active construction. This approach provides assurance to the public that the NRC will thoroughly scrutinize the plant and that any issues identified will be addressed before TVA can move forward. The agency granted construction permits for Bellefonte’s two pressurized-water reactors in 1974. By 1988, when TVA deferred completion of the plant, Unit 1 was approximately 88 percent complete, and Unit 2 was approximately 58 percent complete. When TVA submits its request to return to active construction it must provide the current state of construction and work remaining. There is no nuclear fuel on the site. The Bellefonte site is located on approximately 1,600 acres adjacent to the Tennessee River in northern Alabama. Bellefonte Unit 2’s construction permit expires October 1, 2014. (CCH Nuclear Regulation Reports No. 1474, October 11, 2011)

Indirect Overhead Costs Includable in Damages for DOE’s Failure to Take SNF
Indirect overhead costs incurred by Southern California Edison Company (SCE) were properly included in the damages awarded the utility as the result of the Department of Energy's failure to take possession of SCE's spent nuclear fuel by January 31, 1998, the date specified in the contract signed by the two parties, the U.S. Court of Appeals for the Federal Circuit ruled in affirming the trial court's decision. The agency had a clear contractual obligation to live up to its part of the bargain and could not claim that its failure to do so was unavoidable on the grounds that it had not yet prepared a permanent repository or that it had no authority to provide interim storage. As a result of DOE's failure, SCE had to construct dry storage facilities, known as a Independent Spent fuel Storage Installation (ISFSI) to house its SNF and sought damages for, among other things, the overhead costs allocated to the ISFSI project. The costs were separated into three categories (Common Allocation, Corporate Administrative and General, and internal Market Mechanism. These included items such as plant security, emergency response systems, and lease payments. Although the U.S. argued that many of the costs would have been incurred regardless of DOE's delay, the utility demonstrated that it had incurred substantial and foreseeable costs in mitigating DOE's acknowledged, impending breach of its contractual obligations and that the delay was a substantial causal factor in its expenditure decisions. The trial court also found no evidence of concern with the reliability or accuracy of the accounting methods used, which were based on a percentage basis. (SCE v. U.S., CCH Nuclear Regulation Reporter ¶20,714)