July 2009

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

Legislative Action

House Passes American Clean Energy and Security Bill
By Stephen K. Cooper, CCH Washington News Bureau
The House passed the American Clean Energy and Security Bill of 2009 (HR 2454), a comprehensive energy measure designed to combat global warming by capping the amount of greenhouse gas produced by American businesses and consumers. The measure, which passed by a vote of 219 to 212 on June 26, included few tax provisions since House Ways and Means Chairman Charles B. Rangel, D-N.Y., decided against convening his committee to make changes to the bill. House Minority Leader John Boehner, R-Ohio, criticized the legislation, saying it allows the federal government to impose new regulations and programs that will drive up the costs of gasoline, food and electricity. This overly intrusive energy measure would drive millions of jobs overseas to other countries that have less strict environmental regulations, he said. Rep. Earl Blumenauer, D-Ore., a supporter of the bill said it puts a mechanism in place to rein in global warming and create capital that can be invested in renewable energy sources from the wind and sun. (FERC Opinions, Orders & Decisions, Report No. 1460, July 9, 2009)

Electric Utilities

FERC Policy Change for Electricity Sales Reasonable, DC Circuit Finds
A decision by the Federal Energy Regulatory Commission (FERC) to order two electricity wholesalers to make refunds to their customers whom they had charged market-based rates in areas where they should have charged cost-based rates was reasonable, the U.S. Court of Appeals for the District of Columbia held. Areas served by electricity wholesalers are divided into two categories: mitigated areas, where a wholesaler possesses market power, and non-mitigated areas, where the wholesaler does not. Wholesale electricity sellers are allowed to charge market-based rates in their non-mitigated areas, but must charge cost-based rates in their mitigated areas. In situations where the power is sold in one region and used in another, the dispositive factor is whether the wholesaler has market power at the point of sale, not the point of use (``sink-based''). FERC previously used the sink-based approach, but changed policy in 2006 to the point-of-sale approach. The court found that: FERC thoroughly explained in a subsequently-adopted order its reasoning; the wholesalers were not entitled to rely upon FERC's acceptance of the sink-based test until the date it adopted its new policy; and it was reasonable for FERC to adhere to its standard approach in declining to exercise its authority to waive the wholesalers' refund liability. (Westar Energy v. FERC, DCCir 2009, CCH Utilities Law Reporter ¶14,747).

Reporting Rules for New Generation Site Acquisition Strengthened
The Commission’s market-based rates rule has been strengthened by the agency with new reporting requirements for the acquisition of sites for new generation capacity development. The new requirements address wind power developers’ concerns regarding the burden of the existing requirements as well a provide FERC with the information necessary to evaluate a seller’s ability to erect barriers to market entry while preserving commercially sensitive information about future development of sites for power generating plants. Rehearing was granted to require all entities with market-based rate authorization to file a quarterly report detailing a seller’s acquisition of a site for new generation capacity development for which site control has been demonstrated in the interconnection process and for which the potential number of megawatts that are reasonably commercially feasible on the site for new generation capacity development is equal to 100 megawatts or more. This replaces the previous requirement that all such sellers report these acquisitions within 30 days. These quarterly reports must include (1) the number of sites acquired; (2) the relevant geographic market in which the sites are located; and (3) the maximum potential number of megawatts that are reasonably commercially feasible on the sites reported. This number must be justified. The information regarding the maximum potential number of megawatts for the sites may be reported on an aggregate basis for each relevant geographic market in which the site is located. (CCH FERC Statutes and Regulations Edition ¶31,291 (ip access users))

Reliability Standards for Interchange Scheduling Updated
The approval of three updated Interchange Scheduling and Coordination (INT) reliability standards developed by the North American Electric Reliability Corporation (NERC): INT-005-3, Interchange Authority Distributes Arranged Interchange; INT-006-3, Response to Interchange Authority; and INT-008-3, Interchange Authority Distributes Status has been proposed by the Commission. The proposed INT reliability standards specify response time for entities in the Western Interconnection to review and respond to requests for interchange service. Specifically, these revisions set forth appropriate response times for all requests for on-time, emergency, and reliability adjustment interchange service. The proposed rule would benefit the reliable operation of the bulk power system by clarifying how long the relevant entities have to respond to requests for interchange service and providing entities in the Western Interconnection with sufficient time to assess and respond to requests for interchange service. NERC proposes to establish separate timing tables for the Western Interconnection and the Eastern Interconnection, including the Electric Reliability Council of Texas and Hydro-Quebec.; affirm and clarify the increase in the reliability assessment times for the Western Electricity Coordinating Council from five minutes to ten minutes for requests submitted more than 60 minutes and no less than 15 minutes prior to ramp start time; and also permit the on-time submittal of e-Tags (requests to implement a new interchange transaction as a physical energy flow). NERC also wants to specify the timing for responses to requests for the Western Interconnection and modify of INT-006-002 to clarify that the balancing authorities and transmission service providers in all Interconnections must respond to on-time requests for interchange service, as well as to requests for emergency and reliability adjustment interchange services. (Revised Mandatory Reliability Standards for Interchange Scheduling and Coordination, 127 FERC ¶61,246)

ISO-NE’s Executive Compensation Upheld
The Attorney General for the State of Connecticut (Connecticut AG) and the Connecticut Office of Consumer Counsel’s (Connecticut OCC) (together, the Connecticut Parties) requested rehearing of the Commission’s order [125 FERC ¶61,392 (ip access users)], accepting ISO New England Inc.’s (ISO-NE) tariff sheets for Recovery of 2009 Administrative Costs, was denied by the Commission. The Connecticut Parties sought rehearing regarding ISO-NE’s requested executive compensation and salary structure, employee staffing levels, depreciation rates and schedules, and external affairs activities and asked the Commission to hold a full evidentiary hearing to determine whether the proposed budget would result in unjust and unreasonable rates. The Connecticut Parties argued that the Commission erred in the order by arbitrarily, capriciously, and without substantial evidence concluding, first, that executive compensation package and salary level proposed by ISO-NE were just and reasonable and, second, that the staffing and compensation levels, depreciation and amortization schedules, and the funding for external affairs activities proposed by ISO-NE were just and reasonable. The Commission reaffirmed its finding in the order that ISO-NE had adequately supported its executive compensation package, and thus it did not set the matter for hearing. The ISO-NE provided the information in its answer necessary to allow the Commission to determine the ISO-NE’s proposed compensation package was just and reasonable. Regarding ISO-NE’s total staffing and compensation to its employees, its depreciation and amortization schedules and external affairs costs, the Commission found those were just and reasonable, and denied rehearing on those matters as well. (ISO New England Inc., 127 FERC ¶61,254)

Spindletop Regulatory Asset Costs for Production Were Reasonable
An administrative law judge (ALJ) found that excluding the costs of the Spindletop Regulatory Asset from the calculation of the Entergy Operating Companies' (EOCs) bandwidth remedy payments was unjust, unreasonable and unduly discriminatory. The Louisiana Public Service Commission (LPSC) alleged in a complaint that there were errors in the methodology used by Entergy Services, Inc. (ESI) to calculate production costs among EOCs for purposes of determining the bandwidth remedy payments and receipts to be made among the EOCs to maintain rough production cost equilibrium (RPCE) on the Entergy System (System) in accord with Opinion Nos. 480 and 480-A. [111 FERC ¶61,311 (ip access users); 113 FERC ¶61,282 (ip access users)]. The only issue remaining for the ALJ was whether excluding the costs of the Spindletop Regulatory Asset (SRA) from the calculation of the EOC production cost was unjust, unreasonable and unduly discriminatory. As a result of a ruling by the Public Utility Commission of Texas (PUCT), Texas EOCs were subject to different treatment for Credit Payments than the Louisiana EOCs. The consequence of the different treatments ordered by PUCT and LPSC was that Texas customers had already paid 100 percent of their share of capital-related costs associated with the construction of Spindletop, while Louisiana customers had only paid a portion of their share of those costs. Louisiana customers had the remainder of the 40-year amortization period ordered by LPSC to pay off the balance of their share of the SRA costs. The first question addressed by the ALJ was whether LPSC had demonstrated that the exclusion of SRA costs from EOC Production Costs included in the bandwidth remedy formula was unjust, unreasonable, and unduly discriminatory, and if so, had LPSC demonstrated that the inclusion of the costs of the SRA was just, reasonable, and not unduly discriminatory. The ALJ found that LPSC had not proven that exclusion of SRA costs from the bandwidth remedy formula was unjust, unreasonable, or unduly discriminatory, nor that their remedial proposal was just, reasonable, and not unduly discriminatory. The ALJ determined that the SRA costs were not production costs. The SRA costs were to be distinguished from the Spindletop storage facilities costs. The SRA was an accounting construct created by the LPSC, that existed solely as a deferred right to recover previously incurred costs from Louisiana retail customers. It was not a current cost of producing electricity. (Louisiana Public Service Commission v. Entergy Corp., et al., 127 FERC ¶63,021)

State-by-State Potential for Demand Response Assessed
A national assessment that estimates the potential for demand response, both nationally and for each state, through 2019, has been released by the Commission. The assessment, A National Assessment of Demand Response Potential, finds the potential for peak electricity demand reductions across the country is between 38 gigawatts (GW) and 188 GW, up to 20 percent of national peak demand, depending on how extensively demand response is implemented. This can reduce the need to operate hundreds of power plants during peak times. Without any demand response, the peak demand is estimated to grow at an annual average rate of 1.7 percent, reaching 810 GW in 2009 and 950 GW by 2019. By reducing electricity consumption at peak times like hot summer afternoons, when the most expensive generators are called into service, demand response can lower the cost of producing electricity. With full participation, which posits the universal deployment of an advanced metering infrastructure and the condition that dynamic pricing were made the default tariff, the report estimates that demand response programs could reduce the projected 2019 peak load by as much as 150 GW. (CCH FERC Statutes and Regulations Edition, Report No. 509, July 2009)

Hydroelectric Power

Lift of Stay of Deadline to Begin Hydro Power Plant Construction Approved
A decision by the Federal Energy Regulatory Commission (FERC) to lift a stay of a statutory deadline for beginning construction of a hydropower plant was within FERC's discretion because FERC's findings regarding the remaining hurdles to beginning construction were sufficient to support the denial of an additional extension, according to the U.S. Court of Appeals for the District of Columbia Circuit. In 1992, FERC issued Joseph Keating a license to build a hydroelectric power plant in the Inyo National Forest in California. Keating was unable to obtain necessary approvals from the United States Forest Service or from the California State Water Resources Control Board. During this time, Keating received a number of extensions from FERC, but in 2007, FERC declined to issue another extension. FERC's conclusion that there was no reasonable basis to expect that the licensee would be able to begin construction in the foreseeable future was based on the fact that he had not yet received approval of his six-year-old water rights application, had not filed and received approval of his license amendment application, and had not filed and received Forest Service approval of his pre-construction plans. While Keating had litigated the issue with the Water Board, FERC was entitled to consider the licensee's ability to obtain water rights in the immediate future, and the court was not situated to rule on the Water Board's decision. Furthermore, the court continued, the decision to lift the stay was within FERC's discretion because the licensee was not entitled to an indefinite stay. (Keating v. FERC, DCCir 2009, CCH Utilities Law Reporter ¶14,748).

Oil

Initial Decision Issued in Third Round of Rate Challenges
In an initial decision, an administrative law judge (ALJ) settled the third generation of complaints in a series of proceedings challenging SFPP, L.P.'s (SFPP) system-wide rates on its East Line and West Line filed with the Commission. The main point of disagreement on SFPP's rates concerned the appropriate capital structure between 2000 and 2004. The ACC Shippers argued that Kinder Morgan Energy Partner's (KMEP) capital structure should be used for SFPP, and purchase accounting adjustments should be removed. The ALJ agreed in part finding that the purchase accounting adjustments should be removed from the equity component of KMEP's capital structure; however, the goodwill should remain. Additionally, the ALJ found that the appropriate cost of debt in this proceeding is KMEP's actual 2003 and 2004 costs of debt, including commercial paper that KMEP classified as long-term debt, but not including special purpose and tax-exempt bonds. SFPP met its burden of proving in the rate proceeding that its partners incur actual or potential income tax liability on their respective shares of the partnership income in order to prove its eligibility for an income tax allowance. The Indicated Shippers and ACC Shippers argued that SFPP was not entitled to an income tax allowance as a matter of law because SFPP failed to show that its partnerships incur actual or potential income tax liability. The ALJ found that SFPP complied with Commission orders in calculating its income tax allowance for 2003 and 2004, and that the KMEP incurred an actual or potential income tax liability on the SFPP income allocated to them.

The participants in this proceeding agreed that actual 2003 and 2004 volumes for SFPP's East and West Lines should be used for determining just and reasonable rates. The just and reasonable rates determined in the proceedings depend upon the final determinations on income tax allowance, allowed return, and operation and maintenance expenses set forth in the ALJ's decision. The airline companies involved in these proceedings were entitled to reparations stemming from overpayments of the West Line, while Chevron, ConocoPhillip and the Indicated Shippers were entitled to reparations based on overpayments of rates on both lines, according to the ALJ. Reparations are permitted when the justness and reasonableness of existing rates is successfully challenged for shippers that have filed complaints against a specific rate. The reparations were to be calculated as the difference between the indexed just and reasonable rates and the rates that the shippers actually paid, multiplied by actual throughput, plus interest. (Chevron Products Co., et al. v. SFPP, LP, et al., 127 FERC ¶63,024)

Safety and Environmental Management Rule Proposed
Minerals Management Service (MMS) proposed a rule to require operators to develop and implement a Safety and Environmental Management System (SEMS) to address oil and gas operations in the Outer Continental Shelf (OCS). The system would consist of four elements: Hazards Analyses, Management of Change, Operating Procedures, and Mechanical Integrity.The Hazards Analyses would require that a hazards analysis (facility level) be conducted for all facilities. The Management of Change element would require lessees/operators to document and analyze all proposed facility changes to determine possible adverse safety and environmental impacts, with the exception of replacement in kind. The Operating Procedures element would require OCS oil and gas operators' management officials to include requirements for written facility operating procedures designed to enhance efficient, safe, and environmentally sound operations. The Mechanical Integrity element would require that procedures were in place to ensure that equipment was designed, fabricated, installed, tested, inspected, monitored, and maintained in a manner consistent with appropriate service requirements, manufacturer's recommendations, and industry standards to promote safe and environmentally sound operations in the OCS.The MMS believed that requiring operators to implement a Safety and Environmental Management System would reduce the risk and number of accidents, injuries, and spills during OCS activities. The proposed rule explains who must have a program, what the criteria for the program are, and what the record keeping and documentation requirements will be. For more information see the full text of the proposed rule in CCH Energy Management ¶9252.

Nuclear Power

NRC: Apparent Decommissioning Shortfalls Exist
Eighteen nuclear power plants have been asked by the Nuclear Regulatory Commission to clarify how their owners will address the recent economic downturn’s effects on funding to decommission their reactors in the future. Nuclear power plant operators are required to set aside funds during a reactor’s operating life to ensure the reactor site will be properly cleaned up once the reactor is permanently shut down. Although this is not currently a safety issue, the NRC’s review of the latest reports on decommissioning funding assurance suggests several plants must adjust their funding plans to guarantee that they are setting aside the appropriate amount of money. (CCH Nuclear Regulation Reporter, Report No. 1419, June 30, 2009)

Higher NRC Licensing/Inspection Fees Approved
Generally higher licensing, inspection and annual fees for applicants and licensees have been approved by the Nuclear Regulatory Commission for 2009. NRC is required to recover almost all of its budget authority (90 percent this year)·minus the amounts appropriated from the Nuclear Waste Fund for high-level waste activities. The total amount to be recovered for fiscal year 2009--$870.6 million--is approximately $91.5 million more than last year. The professional hourly rate charged by the agency for licensing and inspection services has been increased to $257. This represents a 7.5 percent raise from the 2008 hourly rate of $238 per hour. The increase is primarily due to the higher 2009 budget supporting increased regulatory and infrastructure workload for reactor license renewals, and applications from new uranium recovery and enrichment facilities. Under the new annual fee structure, most power reactor licensees will have to pay $4,625,000 in annual fees for 2009, up from last year's $4,167,000. Test and research reactors licensees will be required to pay an annual fee of $87,600, which is significantly higher than the 2008 amount of $76,500. High-enriched uranium fuel facility licensees will be assessed $4,691,000 instead of last year's total of $3,007,000, while low-enriched uranium fuel fabrication facility licensees, who manufacture fuel for nuclear power plants, will pay $1,649,000 for 2009, rather than last year's figure of $899,000. (CCH Nuclear Regulation Reporter, Report No. 1419, June 30, 2009)