Energy Update August 2011

August 2011

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

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FERC Transmission Planning, Cost Allocation Reforms to Benefit Consumers

The Commission has reformed its transmission planning and cost allocation requirements to benefit consumers by enhancing the grid’s ability to support wholesale power markets and ensuring transmission services are provided at just and reasonable rates. Order No. 1000 requires public utility transmission providers to align transmission planning processes and allocate costs for new transmission facilities to beneficiaries of those facilities. Specifically, each provider is required to work within its transmission planning region to create a regional transmission plan that identifies transmission facilities needed to meet reliability, economic, and public-policy requirements. Each of these plans must include fair consideration of lines proposed by nonincumbents, with cost allocation mechanisms in place to facilitate lines moving from planning to development. These changes will remove barriers to development of transmission facilities. The plan addresses consideration of transmission needs driven by public policy requirements established by state or federal laws or regulations, and coordination between pairs of neighboring transmission planning regions. The cost allocation requirements established in the rule include development of regional and interregional cost allocation methods that satisfy certain principles. Under the rule, participant-funding of new transmission facilities is permitted but cannot be used as the regional or interregional cost allocation method. ( CCH Statutes and Regulations Edition, ¶31,323)

Commission Approves Decision on Kern River Period Two Rates

An Initial Decision addressing rates on the Kern River system was affirmed in nearly all respects by the Federal Energy Regulatory Commission. When the Commission approved Kern River’s certificate in 1990 to construct its original system, the Commission approved levelized rates for three periods: Period One, the 15-year term of the firm shipper’s initial contracts, during which 70 percent of Kern Rivers’ initial investment would be recovered; Period Two, the following 10-year period until the end of Kern Rivers’ 25-year depreciable life; and Period Three, the period afterwards. Because Kern River would be allowed to recover a higher portion of its investment during Period One than under a straight-line depreciation, the Commission specified at that time that Period Two and Period Three rates would be lower than Period One rates. In 2000, Kern River entered into a settlement allowing it to lower its rates by refinancing its debts and extending the terms of its firm contracts, but still allowing Kern River to recover 70 percent of its investment by the end of the new repayment periods. All of its shippers then extended their contracts, one group by five years to expire in 2011, and another by ten years to expire in 2016. Regarding Kern River’s equity structure, the Commission said that it had consistently held that Kern River’s rates during Period Two would be designed using a 100 percent equity structure as consistent with the rate design principles of the original certificate proceedings. Each shipper will have paid by the end of its Period One contract its share of the 70 percent of Kern River’s investment capital to be recovered during that time, and delaying the implementation of the 100 percent equity structure would result in cost shifting from expansion shippers to rolled-in shippers. The Commission also agreed with the ALJ’s determination that its rates for Period Two should be designed on a 100 percent load factor.
(Kern River Gas Transmission Co., 136 FERC ¶61,045)

PJM Not Required to Pay Refunds in Line Loss Charge Proceeding

In a request for rehearing of an earlier Commission decision [ Black Oak Energy, LLC v. PJM Interconnection, LLC 131 FERC ¶61,024] which accepted a compliance filing from PJM relating to PJM's disbursement of over-collected transmission line loss charges, the Commission will not require PJM to pay refunds. Integrys, in its rehearing request, argued that the Commission erred by not addressing its protest in which it maintained that PJM should not be permitted to reclaim any of the credits paid to exporters of energy from PJM to MISO in order to pay for the refunds to Black Oak and other complainants. Integrys specifically contended that the Commission erred in failing to find that it would be unjust to require retroactively load serving entities who received distributions from the marginal line loss surpluses in the past from paying back those amounts. In a case where the company collected the proper level of revenues but it was determined later that those revenues should have been distributed differently, the Commission traditionally has declined to order refunds. The Commission reasoned that ordering refunds in such a case would be unfair because it would result in a loss of revenue from the reallocation when the utility would not have the opportunity to file a new rate case to recover those revenues. In the case at issue here, the Commission has similarly imposed a change involving the parties eligible to receive marginal line loss credits. This change does not affect the overall amount of the credit, but does provide larger amounts of credit to certain parties and lower amounts to other parties. In recognition of this fact, PJM seeks to surcharge certain parties in order to pay the refunds owed to other parties. Were the Commission to require refunds without such surcharges, PJM would suffer a loss of revenue and an under-recovery of legitimate costs. Because this case involves a change in the allocation of costs, the Commission will not require refunds. (Black Oak Energy, LLC et al. v. PJM Interconnection, 136 FERC ¶61,040)

Wind Projects Exempt from MISO’s Revised Queue Requirements

Edison Mission Energy was exempt from the M3 milestone and other queue reforms of MISO's Open Access Transmission, Energy and Operating Reserve Market Tariff. As part of the tariff's generator interconnection procedures, (GIP) the M3 milestone makes certain demands on interconnection customers, including
security reasonably acceptable to MISO for the greater of the cost of the Network Upgrades or Interconnection Facilities. The Commission, however, found that the M3 milestone and other queue reform procedures did not apply to the Edison Wind Projects because they fell into the first category of the GIP which applied to interconnection requests for which a Facilities Study Agreement already had been executed at the time the revised GIP became effective. These interconnection requests were exempt from revised GIP provisions.

The Edison Wind Projects entered into Facilities Study Agreements with MISO nearly one year before the effective date of the revised GIP. The Queue Reform Order established that interconnection projects such as Edison would only be subject to the new rules governing suspension which do not include the M3 milestone and the other queue reform procedures Edison objected to. The Commission, therefore, directed MISO to reinstate the queue position of any interconnection customer meeting the criteria of the first category of the GIP exemption that have been withdrawn from the MISO queue for failure to meet the M3 milestone and/or to execute a Facilities Study Agreement.. (Edison Mission Energy v. MISO, 136 FERC ¶61,035)

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)

Costs of Reloading SNF Casks Deferred, Not Avoided

The government's proposed offset or reduction in damages due Entergy Nuclear for spent nuclear fuel (SNF) cask loading costs has been denied by the U.S. Court of Federal Claims because these costs have not been avoided, as the government claims, due to its failure to take possession of the SNF starting on January 31, 1998, but have only been deferred. In granting partial summary judgment to Entergy, the court found that the utility has incurred costs for procuring additional SNF storage capacity as the result of the government’s partial default in taking possession of the utility's SNF. It is not possible to ascertain the method the Department of Energy will ultimately use for accepting the SNF and, as a result, the government impermissibly sought to offset Entergy's claim based on speculation as to future events. The government's expert had no basis other than speculation for his belief that, when DOE picks up Entergy's SNF, it will utilize casks compatible with the canisters in which Entergy has stored its SNF at its independent spent fuel storage facility. If DOE does not use compatible casks, Entergy will need to incur the costs of loading its Holtec canisters and reloading its SNF into DOE's chosen cask when the removal actually begins. (Entergy Nuclear Fitzpatrick, LLC ¶20,712)

Comment Sought on Proposed Revisions to LLRW Policy Statement
The Commission is seeking public comment on proposed revisions to its policy statement on volume reduction of low-level radioactive waste (LLRW). The proposed revisions recognize progress licensees have made in reducing the volume of LLRW generated during operations since the current policy statement was issued in 1981. The revised statement would continue to urge licensees to minimize the volume of waste they produce, because such a focus will extend the operational lifetime of the existing commercial low-level disposal sites and reduce the number of waste shipments. The revised policy statement, however, would also recognize that volume reduction is only one aspect of an effective program for managing radioactive waste. According to the draft policy statement, licensees should consider all means available to manage waste in a manner that is secure, and protects public health and safety. Such means include waste minimization; short-term storage and decay; long-term storage; use of the alternative disposal provision in NRC regulations at 10 CFR 20.2002; use of waste processing technologies; and use of licensed disposal facilities. About 96 percent of all LLRW is generated by nuclear power plants. The remainder is generated by fuel cycle facilities such as uranium enrichment plants, and materials licensees such as hospitals, research institutes and universities. (CCH Nuclear Regulation Reporter No. 1471, August 23, 2011)