Energy Update June 2011

June 2011

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

If you have any comments or suggestions concerning the information provided or the format used, we'd like to hear from you. Please send your comments to pamela.maloney@wolterskluwer

Offshore Transmission Highway Incentives Approved
Atlantic Grid Operations A-E LLC’s (AWC Companies) request for approval of incentive rate treatment and approval of a return on equity for their investments in the Atlantic Wind Connection project was granted in part and denied in part by the Commission. The AWC Companies requested: return on equity (ROE) adders totaling 300 basis points, an incentive-based ROE of 13.58 percent (inclusive of the 300 basis point ROE adders), regulatory asset accounting treatment, 100 percent of construction work in progress (CWIP), abandoned plant recovery, a hypothetical capital structure based on 60 percent equity and 40 percent debt, and approval for the use of a formula rate structure. However, the AWC Companies did not provide the Commission with the necessary support to determine whether the project ensured reliability or reduced the price of delivered power by reducing congestion. The Commission granted the requested 50 basis point RTO adder, provided that: (1) the project was included in the PJM RTEP; (2) AWC Companies take all the necessary steps to turn over operational control of the project to PJM; and (3) AWC Companies become participating transmission owners. Further, the Commission granted the requested 50 basis point adder for Transco status and use of advanced technologies. The Commission also granted 100 basis point adders for the risks and relative complexity of the project, for CWIP, and abandoned plant recovery. AWC Companies were granted an up-front incentive ROE based on AWC Companies’ analysis and the right to establish the initial regulatory asset. (Atlantic Grid Operations A, LLC, et al., 135 FERC ¶61,144 (ip access users) (Intelliconnect))

Comment on Transmission Incentives Program Sought
Comments on the Commission's electric transmission incentives program are being sought by the agency. In the Energy Policy Act of 2005, Congress directed FERC to provide incentive rates to encourage development of transmission infrastructure. In July 2006, the Commission issued Order No. 679 [CCH FERC Statutes and Regulations Edition ¶31,222 (ip access users) (Intelliconnect)] identifying specific incentives available to qualifying applicants, including return on equity adders, recovery of 100 percent of prudently incurred abandoned plant costs, inclusion in rate base of 100 percent of prudently incurred construction work in progress, recovery of pre-commercial operations costs, hypothetical capital structures and accelerated depreciation.
To date, the vast majority of applications for transmission incentives filed with the Commission have focused on the enlargement of facilities, including construction of new transmission facilities. Few applications have focused on the improvement, maintenance, and operations of transmission facilities or on increasing their capacity or efficiency.

Since Order No. 679 was issued, FERC has received more than 75 applications for transmission incentives associated with more than an estimated $50 billion in proposed investments, from a variety of transmission developers. Given the significant changes in the electric industry and FERC’s experience in applying Order No. 679, FERC was seeking comment regarding the scope and implementation of its incentives program.

This Notice of Inquiry focuses on several topics related to FERC’s implementation of its transmission incentives program, such as: (1) What factors should the Commission consider in evaluating an application for incentives; (2) What obstacles are faced by transmission developers and what incentives are best suited to addressing those obstacles; (3) How should the Commission consider changes in cost estimates; (4) How have the incentives granted to transmission projects affected consumer rates and services; and (5) What other factors should the Commission consider in implementing the law?

Comments, referencing RM11-26-000, are due July 26, and should be sent to: Federal Energy Regulatory Commission, Secretary of the Commission, 888 First Street, NE., Washington, DC 20426. E-mail comments to: http://www.ferc.gov. (CCH FERC Statutes and Regulation Edition ¶35,572 (ip access users) (Intelliconnect)

SPP Requires Wind Generation Curtailment
Wind-powered generating facilities within the Southwest Power Pool, Inc. (SPP) must be capable of reducing generation output in increments of no more than 50 MW in five minute intervals, when required to protect the reliability of the transmission system under a proposal approved by the Commission. SPP stated that the proposed amendment to its tariff was needed to protect the reliability of its transmission system. According to SPP, wind facilities were only able to respond to curtailment requests by opening their plant interconnection breaker, thereby reducing output to zero. SPP was concerned that the abrupt cessation in output, when only a reduction in output was necessary, could cause excessive curtailments that could adversely affect the reliability of the transmission system. The effects of over-curtailments would likely worsen because of the expected addition of 4,500 MW in wind-powered resources that were scheduled to interconnect to the SPP transmission system in the coming years. The Commission found that the proposed amendment was a just and reasonable and was not an unduly discriminatory approach to ensure the continued reliability of SPP’s transmission system. Further, requiring new wind resources to be capable of incrementally reducing their output should alleviate potentially harmful reliability conditions. Also, the 50 MW curtailment increment was just and reasonable because it provided SPP and/or the transmission owner the operational flexibility to request partial reductions in output, the Commission found. (Southwest Power Pool, Inc., 135 FERC ¶61,148 (ip access users) (Intelliconnect))

Policy on Reassigned Transmission Capacity Prices Upheld
In a rehearing/clarification request involving Order No. 739 [132 FERC ¶61,238 (ip access users) (Intelliconnect)], Powerex Corporation and other transmission customers within the Bonneville Power Administration’s service area requested that certain rate schedules which have allowed these customers to make reassignments of electric transmission capacity to non-jurisdictional transmission providers (such as Bonneville) via bilateral sales at negotiated rates remain operative. The request was denied by the Commission, which earlier declined to clarify that the existing stand-alone rate schedules that allow reassignments above the price cap would remain operative because those rate schedules were outside the scope of this proceeding and it was unclear at the time whether Bonneville would reimpose the price cap (which had previously been lifted). The Commission suggested that entities could file, in separate proceedings, revised rate schedules allowing them to continue reselling transmission capacity above a price cap if such a price cap were imposed by a non-jurisdiction entity. The Commission continues to believe that the issues raised with respect to Bonneville are better resolved in individual proceedings rather than as part of a generic rulemaking. (Promoting a Competitive Market for Capacity Reassignment, 135 FERC ¶61,137 (ip access users) (Intelliconnect))

PG&E Interconnection Procedures Updated
Pacific Gas and Electric Company’s (PG&E) proposed revisions to its wholesale distribution tariff (WDT) to combine its small generator interconnection procedures (SGIP) and large generator interconnection procedures (LGIP) into a new set of generator interconnection procedures (GIP), was approved by the Commission .PG&E proposed to offer a combined cluster study process as the default study option for large and small generator interconnection requests. PG&E stated that it would perform one cluster study per year, but would provide two opportunities, or “cluster windows,” for customers to submit cluster study applications and hold scoping meetings. As an alternative to the cluster study process, PG&E proposed establishing a new independent study process that would allow qualifying generators to be studied at any time during the year, outside of the cluster study process, using a modified and shortened version of the current SGIP serial study process. PG&E’s revised GIP satisfied the “consistent with or superior to” standard, thus, the Commission accepted the proposed tariff revisions. PG&E’s proposal struck an appropriate balance between preserving the interests of small and large generator interconnection customers while ensuring that other viable options were available to process interconnection requests as quickly as possible, the Commission found. Further, PG&E’s proposal would increase the efficiency of the interconnection process while maintaining grid reliability for both distribution and transmission. (Pacific Gas and Electric Co., 135 FERC ¶61,094 (ip access users) (Intelliconnect))

FERC Relicensing Decision Was Ripe for Review
The Federal Energy Regulatory Commission’s (FERC) contention that a power company’s petition for review was not ripe because in accordance with its policy it had not been able to act on the company’s application for licensure in view of an on-going North Carolina Department of Environment and Natural Resources administrative review, was incorrect the U.S. Court of Appeals for the District of Columbia Circuit. As part of the relicensing procedure, the company was seeking a state water quality approval for an existing hydroelectric project. The state issued a certification one day before the end of the one–year period, which required that the company undertake various improvements, control and monitoring measures related to water quality, and a surety bond in the amount of $240 million. The court found that the company correctly maintained that the purpose of the waiver provision was to prevent a state from indefinitely delaying a federal licensing proceeding by failing to issue a timely water quality certification. FERC’s interpretation of the CWA to allow licensing once a certification had been “obtained” even if the certification was not by its terms immediately “effective,” was consistent with the plain text and statutory purpose of the provision. Therefore, under the CWA the state, acting through its Division of Water Quality, timely issued a water quality certification that complied with the CWA. Thus, the court held there was no waiver by the state. (Alcoa Power Generating Inc. v. Federal Energy Regulatory Commission, et al., CCH Utilities Law Reports ¶14,811)

Gulf Coast Exports of LNG Approved by DOE
The U.S. Department of Energy has issued a conditional authorization approving an application to export liquefied natural gas (LNG) from the Sabine Pass LNG Terminal in Louisiana, paving the way for thousands of new construction and domestic natural gas production jobs in Louisiana, Texas, and several other states. Subject to final environmental and regulatory approval, Sabine Pass Liquefaction, LLC will retrofit an existing LNG import terminal in Louisiana so that it can also be used for exports. This is the first long-term authorization to export natural gas from the lower 48 states as LNG to all U.S. trading partners. In August 2010, Sabine Pass Liquefaction, LLC filed a two-part application requesting authority to export up to 803 billion cubic feet per year of domestically produced natural gas as LNG for a period of 20 years. On September 10, 2010, the Department approved these exports to 15 countries with which the U.S. already has a Free Trade Agreement covering natural gas. The Department is extending this authorization to include all other countries except those that lack the ability to receive imports or those with which trade is prohibited by U.S. law or policy. In issuing a conditional authorization for exports to non-free trade agreement countries, the Department considers a number of factors, including the impact of exports on domestic supply. In the event the Department receives subsequent applications for LNG export, it will closely examine the cumulative impacts of additional exports on the domestic market. (CCH Statutes and Regulations Edition, No. 531, June 20, 2011)

Review of Oil Pricing Index Denied
Requests for rehearing filed by Valero Marketing and Supply (Valero), Air Transport Association of America (ATA), and Tesoro Refining and Market Company and Sinclair Oil Transportation (Sinclair/Tesoro) questioning the “rate base screening” methodology and other issues was denied by the Commission. Valero and ATA claimed that the Commission erred by rejecting the “rate base screening” methodology proposed by Valero’s expert. Valero and ATA failed to undermine the conclusions of the 2010 Index Order [133 FERC ¶61,228] that the rate base screening methodology selectively emphasized one factor which could cause a substantial change in pipeline costs per barrel-mile while ignoring other factors. The 2010 Index Order fully described the steps necessary to perform the rate base screening methodology. The Commission properly construed the proposed rate base screening methodology as emphasizing one potential cause for cost changes while ignoring others.

Valero and ATA also claimed that the rate base screening methodology was analogous to other data set trimming methods used by the Commission in the past. However, the comparison was inapposite. First, although the Kahn Methodology removed from the data set those pipelines that reported erroneous or incomplete data, erroneous or incomplete data differed from the accurately reported actual costs Valero and ATA sought to remove using the rate base screening methodology. Second, regarding the examples of the TAPS pipelines, those pipelines were easily identifiable and were not subject to the index adjustment due to the provisions of the EPAct. Third, Valero and ATA’s analogy to the Ultra Low Sulfur Diesel surcharge also was misplaced.. (Five Year Review of Oil Pricing Index, 135 FERC ¶61,172) (ip access users) (Intelliconnect)

Challenge to Lease Sale Allowed
The Bureau of Ocean Energy Management, Regulation, and Enforcement's (BOEMRE) motion to dismiss Defenders of Wildlife's (Defenders) claim, filed in the wake of the Deepwater Horizon oil spill, was dismissed by a federal district court in Alabama because, with one exception, the claims under the National Environmental Policy Act (EPA), the Administrative Procedures Act (APA), and the Endangered Species Act (ESA) were not moot and were ripe for review. Foe example, defenders' claimed that BOEMRE violated National Environmental Policy Act (EPA) and the Administrative Procedures Act (APA) by continuing to rely on the conclusions of an April 2007 Environmental Impact Statement (EIS) governing 11 lease sales, in particular Lease Sale 213, in the Gulf of Mexico even though key conclusions of the Multi-Sale EIS were demonstrably invalid after the Deepwater Horizon oil spill. BOEMRE argued that the claim was moot because BOEMRE was, in fact, preparing a supplemental EIS. BOEMRE had published a notice in the Federal Register that it was preparing a supplemental EIS and it would supplement the Environmental Assessments for Lease Sales 206 and 213. However, because the claim had a Lease Sale 213 component that BOEMRE's motion to dismiss did not address, BOEMRE failed to demonstrate that portion of the claim was moot. Further, while some issues were not ripe, Lease Sale 213, which the complaint was limited to, was ripe for review. (CCH Energy Management ¶9634)

Higher NRC Licensing and Inspection Fees for 2011 Established
Generally higher licensing, inspection and annual fees for applicants and licensees have been established by the Nuclear Regulatory Commission for 2011. The total amount to be recovered for fiscal year 2011--$915.8 million--is approximately one percent ($3.6 million) more than last year. The professional hourly rate charged by the agency for licensing and inspection services will be increased to $273, up from the 2010 hourly rate of $259 per hour. This increase in the hourly rate is primarily due to a slight increase in the agency fee-based budget that will be recovered by fewer direct full time equivalents (FTEs). Instead of billing a licensee when the inspection is completed, NRC bills the licensee for any inspection cost incurred during the quarter even if the inspection is ongoing. Under the new rate structure, most power reactor licensees will have to pay $4,673,000 for 2011, down slightly from last year's $4,784,000. Test and research reactors licensees will be required to pay an annual fee of $86,300, higher than the 2010 amount of $81,700. High-enriched uranium fuel facility licensees will be assessed $6,085,000 instead of last year's total of $5,439,000, while low-enriched uranium fuel fabrication facility licensees, who manufacture fuel for nuclear power plants, will pay $2,290,000 rather than last last year's figure $2,047,000. Annual fees for broad scope medical licensees and radiographers will also change during 2011, to $45,400 and $25,700 as compared to $45,100 and $28,200, respectively, in 2010.NRC estimates that the 2010 annual fees will be paid by 104 nuclear power plant licensees, 4 non-power reactors, 19 spent fuel storage/reactor-in-decommissioning facilities, 12 fuel cycle facilities, 10 uranium recovery facilities and approximately 3,150 material licensees. (CCH Nuclear Regulation Reporter, No. 1467, June 28, 2011 )

Stricter Environmental Protection Rules Issued
The Commission has issued stricter environmental protection requirements designed to prevent future “legacy sites” with insufficient funds for decommissioning by requiring licensees to minimize the introduction of residual radioactivity at their sites during operations. A legacy site is a facility with an owner who cannot complete complex decommissioning work for technical or financial reasons. The rule requires owners licensed by the NRC to keep survey records of residual radioactivity, including in the subsurface soil and groundwater, with records important for decommissioning. Facilities that process large quantities of radioactive material, especially in liquid form, have the potential for significant environmental contamination due to the scale of their operations. Over time, leaks from these facilities can lead to significant radioactive contamination of the subsurface soil and groundwater, even though the radiation doses from these releases are well below annual regulatory limits for public and occupational exposure .In addition, the high costs of disposing of radioactive material offsite may lead licensees to store more waste onsite, increasing the potential for subsurface radioactive contamination and significantly higher decommissioning costs. The final rule also requires more detailed reporting by licensees. The new regulations will take effect December 17, 2012. (CCH Nuclear Regulation Reporter No. 1467, June 28, 2011 )