Energy Update March 2011

March 2011

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

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Electric Market Credit Reforms Affirmed

The Commission has reaffirmed in part its determinations in Credit Reforms in Organized Wholesale Electric Markets, Order No. 741 [CCH Statutes and Regulation Edition ¶31,317], to amend its regulations to improve the management of risk and use of credit in the organized wholesale electric markets. In Order No. 741, the Commission adopted reforms to credit policies used in organized wholesale electric power markets. In the instant order, Order No. 741-A, the Commission addresses requests for rehearing of Order No. 741. The Commission grants rehearing as to its establishment of a $100 million corporate family cap on unsecured credit and extends the deadline for complying with the requirement regarding the ability to offset market obligations to September 30, 2011, with the relevant tariff revisions to take effect January 1, 2012, but denies rehearing in all other respects, including the elimination of unsecured credit for financial transmission rights markets and the ability to offset market obligations. With regard to the use of unsecured credit, the Commission is persuaded that an entity reconfiguring its corporate structure, to avoid the $50 million single-entity cap and to instead take advantage of the $100 million corporate family cap, raises a significant risk that is inconsistent with Order No. 741's intent to lower risks. This order will become effective on March 28. (CCH FERC Statutes and Regulations Edition ¶31,320) (ip access users) (IntelliConnect

Midwest ISO Creates Dispatchable Intermittent Resources

The Midwest Independent Transmission System Operator, Inc. (Midwest ISO) proposed to create a new category of resources called Dispatchable Intermittent Resources (DIR), which the Commission accepted in part and rejected in part. Under the proposal, DIR would be treated in a manner similar to Generation Resources in the Midwest ISO's real-time energy market. By allowing Intermittent Resources to register as DIR, the proposal would utilize the capability of some variable resources to respond to instructions to reduce output (e.g. via pitch control) and, thus, allow DIR to participate in the real-time security-constrained economic dispatch process. DIR offers would include Forecast Maximum Limits that would reflect the maximum megawatt level at which the resources could operate for each five-minute interval during the real-time energy market. The Commission conditionally accepted the Midwest ISO's proposal to require wind resources to register as DIR by restricting their eligibility to instead register as Intermittent Resources. However, the Commission rejected the Midwest ISO's proposal to apply the registration requirement to Intermittent Resources with non-wind fuel sources because Midwest ISO provided little or no justification for requiring the change for other Intermittent Resources that use other fuel sources. (Midwest Independent Transmission System Operator, Inc., 134 FERC ¶61,141)(ip access users)(Intelliconnect)

Assignment of Withdrawal Credits Not Allowed

In an initial decision, an administrative law judge (ALJ) found that Commonwealth Edison Company (ComEd) was not allowed to assign its credits granted under the Midwest Independent System Operator's (Midwest ISO) Withdrawal Settlement Agreement, to unaffiliated third parties. ComEd chose to withdraw from the Midwest ISO and to join the PJM Interconnection, Inc. As part of the withdrawal process from Midwest ISO, ComEd received credits against the capital cost component of future Midwest ISO administrative charges if it took transmission service from Midwest ISO. The ALJ determined that the Withdrawal Settlement Agreement did not permit ComEd to assign its withdrawal credits to unaffiliated third parties. The ALJ found that permitting departing companies to "assign" their credits to non-affiliated entities which had not prepaid their start-up capital cost obligations through the exit fee would be fundamentally inconsistent with the intent of the section, and, in fact, would provide an unjustified windfall to both the purported assignor and the purported assignee. Therefore, the assignment from ComEd to Ameren was not allowed. (Commonwealth Edison Co., et al., 134 FERC ¶63,004)(ip access users)(Intelliconnect)

Purchase of Dynergy Inc. by Icahn Approved
Icahn Partners has received permission from the Commission to acquire Dynegy Inc. and its subsidiaries (Dynegy). The facilities involved in the transaction consist of market-based rate schedules and related contracts, agreements, and interconnecting transmission facilities owned and controlled by Dynegy. Under the terms of the merger agreement, Dynegy stockholders will receive $5.50 in cash for each outstanding share of Dynegy common stock they own. The Commission approved the transaction because it found that the transaction would not have an adverse effect on vertical or horizontal competition, rates, federal or state regulation, and would not result in cross-subsidization or the pledge or encumbrance of utility assets for the benefit of an associate company. (Icahn Partners LP, et al., 134 FERC ¶61,093)(ip access users)(Intelliconnect)

Gas Company's General Rate Case Reviewed

The Commission determined issues arising from an initial decision by an administrative law judge (ALJ) concerning a general rate case filed by Portland Natural Gas Transmission System (Portland). The Commission affirmed the ALJ's findings with regard to levelized rates, two out of four cost-of-service issues, negative salvage and in part on determinations relating to depreciation. Portland operates import facilities near the United States-Canada border and pipeline facilities in the northeastern United States. Further, the Commission determined that the proxy group chosen by the ALJ was not risk appropriate for Portland. The Commission's preference is that a proxy firm's natural gas pipeline business account for at least 50 percent of its assets or operating income. The Commission substituted a company with the proper percent of assets and then approved the proxy group. (Portland Natural Gas Transmission System, Opinion No. 510 134 FERC ¶61,129)(ip access users)(Intelliconnect)

Certificate of Public Convenience and Necessity Not Transferrable

A Federal Energy Regulatory Commission (FERC) order, authorizing a company to site, construct, and operate a liquefied natural gas (LNG) import terminal in Oregon, and issuing a certificate of Public Convenience and Necessity (CPCN) to a second company to construct and operate a natural gas pipeline to connect the terminal to the Pacific Northwest's existing natural gas pipeline network, was vacated and the petition for review was mooted by the US Court of Appeals for the Ninth Circuit. Since issuing the order, both the companies had filed petitions in bankruptcy for Chapter 7 liquidation. While FERC could authorize a permittee to transfer a permit to a new project proponent, the CPCN was not transferable. Once the company was liquidated, it would no longer exist and, thus, would not be able to renew its efforts to obtain Washington's certification under the Clean Water Act or Oregon's concurrence in the proponents' federal consistency determination under the Coastal Zone Management Act, or proceed with the pipeline project in any other manner. Because the pipeline and the terminal essentially constituted a single project that would go forward together, or not at all, the future of the project was in doubt, the court noted. Thus, the possibility that the project authorized by FERC could be revived to threaten the interests of the petitioners was too remote and speculative a consideration to save the case from mootness. (State of Oregon, et al. v. Federal Energy Regulatory Commission (9th Cir.), CCH Utilities Law Reporter ¶14,805)

Precedent Mandates Acceptance of Increased Rates
In an initial decision, an administrative law judge found that SFPP, LP (SFPP) failed to meet its burden of proof in the majority of the components in the calculation of its cost of service based rates in order to increase the costs and associated transportation rates of the East Line portion of the SFPP pipeline. However, previous Commission decisions barred finding against SFPP. The ALJ did order modifications to the income tax allowance and certain costs that flowed from those calculations in SFPP's rates. While Navajo Refining Company and Western Refining Company (N/W) submitted significant evidence proving that empirical evidence indicated that the cost of equity capital of the corporation was 2.38 percent lower than the cost of equity capital, the ALJ found that Commission policy prevented a ruling in its favor. As a result, N/W's request to reduce the stipulated real and nominal return on equities (ROEs) by 2.38 percent was denied. The ALJ found that Commission policy did not permit adjustments to the ROEs. (SFPP, LP, 134 FERC ¶63,013)(ip access users)(Intelliconnect)

Income Tax Allowance Authority Altered

The Commission generally affirmed an administrative law judge's (ALJ) decision regarding the reasonableness of rates that SFPP, LP (SFPP) filed to increase its West Line rates. The Commission agreed with the ALJ's decisions regarding good-will, the allocation of costs among SFPP's affiliates and between SFPP's jurisdictional and non-jurisdictional services, and most capital structure, cost of capital and income tax allowance issues. However, the Commission modified the ALJ's decisions regarding throughput, purchase accounting adjustments, the allocation of litigation costs, and some rate base and secondary cost of service issues. Most importantly, the Commission concluded that BP West Coast was not the controlling authority on the issue of whether SFPP was entitled by law to an income tax allowance. Rather, ExxonMobil [CCH Utilities Law Reporter ¶16,659], which upheld the Income Tax Policy Statement [111 FERC ¶61,139 (ip access users)(Intelliconnect)], was the prevailing authority on the issue. ExxonMobil upheld Commission determinations that (1) the income tax liability of the partners for the partnership income is properly attributed to a regulated partnership; and (2) attributing that tax liability to the partnership does not result in phantom taxes if the partners have an actual or potential income tax liability. Therefore, SFPP should be afforded an income tax allowance on all of its partnership interest to the extent that the owners of those interests had an actual or potential income tax liability during the periods at issue. Thus, the pipeline company, a limited partnership, was entitled to an income tax allowance based upon established legal precedent. (SFPP, LP, Opinion No. 511, 134 FERC ¶61,121)(ip access users)(Intelliconnect)

Exchange Agreement Not Subject to Commission Jurisdiction

ConocoPhillips Company's (ConocoPhillips) complaint against Enterprise TE Products Pipeline Company LLC (Enterprise TEPPCO) alleging Enterprise TEPPCO unlawfully refused to provide transportation of propane from the ConocoPhillips refinery in Trainer, Pennsylvania (Trainer), was dismissed by the Commission. The Commission found that the exchange agreement showed that it was a contract between ConocoPhillips and Enterprise TEPPCO for trading of propane at different locations without the need for physical transportation that was typical in the oil industry. The Commission did not find that it was credible for ConocoPhillips to claim the propane exchange constituted jurisdictional transportation without pointing to any such indicia in the agreement, while the other part of the contract concerning butane transportation specifically referred to transportation pursuant to Enterprise TEPPCO's tariff. Therefore, because the Exchange Agreement was not jurisdictional, and ConocoPhillips did not make a valid request for transportation which was unreasonably denied, there was no basis under which the Commission could grant relief. (ConocoPhillips Co. v. Enterprise TE Products Pipeline Co. LLC, 134 FERC ¶61,174)(ip access users)(Intelliconnect)

NRC Continues To Review Japanese Nuclear Events
The Commission will launch a two-pronged review of U.S. nuclear power plant safety in the aftermath of the March 11 earthquake and tsunami and the resulting crisis at a Japanese nuclear power plant . The task force will conduct both short- and long-term analysis of the lessons that can be learned from the situation in Japan, and the results of their work will be made public. The Commission set a schedule for the task force to provide formal updates on the short-term effort in 30, 60 and 90 days. The staff reiterated their conclusions that the United States and its territories will avoid any harmful radiation levels as a result of the ongoing events at the Fukushima Daiichi plant damaged by the quake and subsequent tsunami. NRC inspectors who are posted at every U.S. nuclear power plant will also support the task force's short-term effort, supplemented as necessary by experts from the agency's regional and headquarters offices. "This work will help determine if any additional NRC responses, such as Orders requiring immediate action by U.S. plants, are called for, prior to completing an in-depth investigation of the information from events in Japan," said NRC Executive Director for Operations Bill Borchardt. ( CCH Nuclear Regulation Reports No. 1461, March 29, 2011)

Lower NRC Inspection and Licensing Fees Proposed for 2011
Generally lower licensing, inspection and annual fees for applicants and licensees have been proposed by the Commission for 2011. 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 2011--$915.3 million--is approximately one percent ($0.4 million) less than last year. The NRC is proposing to change the FY 2011 hourly rate to $273. This increase in hourly rate is primarily due to a slight increase in the agency fee-based budget that will be recovered by fewer direct full time equivilents (FTEs) and higher authorized budgeted resources. In FY 2011, the NRC revised its budget structure. The annual fees for power reactors and uranium recovery facilities have decreased while fees for spent fuel storage facilities, non-power reactors, fuel facilities, most materials users and Department of Energy's (DOE) uranium recovery and transportation increased. Under the new rate structure, most power reactor licensees would have to pay $4,669,000 in annual fees for 2011, down from last year's $4,719,000. Test and research reactors licensees would be required to pay an annual fee of $86,100, up from last year's amount of $81,800. High-enriched uranium fuel facility licensees would be assessed $6,078,000 instead of last year's total of $5,442,000, while low-enriched uranium fuel fabrication facility licensees, who manufacture fuel for nuclear power plants, would pay $2,287,000 for 2011, rather than last year's figure of $2,048,000. Annual fees for broad scope medical licensees and radiographers would also change during 2011, to $45,100 and $25,700, as opposed to $45,000 and $22,700, respectively, in 2010. (CCH Nuclear Regulation Reporter ¶4210a)

Judge Orders Action on Deepwater Leases

The Department of the Interior (DOI) and the Bureau of Ocean Energy Management, Regulation and Enforcement (BOEMRE) were ordered to act on five deepwater drilling permits by a U.S. District Court judge in Louisiana. An oil drilling company's request for an injunction to prevent the enforcement of the DOI's blanket moratorium on deepwater drilling in the Gulf of Mexico with regard to five deepwater drilling permits previously had been denied. The government had imposed the moratorium following BP's Deepwater Horizon incident and had not acted on any permits in ten months. The oil company once again requested an injunction following government lifting the moratorium and there still being no action on the permits. The court noted that the Outer Continental Shelf Lands Act (OCSLA) establishes a non-discriminatory duty on the part of the DOI to act, favorably or unfavorably, on drilling permit applications. Once the Secretary of the Interior exercises that discretion, the government is under a duty to act by either granting or denying a permit within a reasonable time. The court found that because the government had a non-discretionary duty to act on the applications and because it was beyond quarrel that the government had failed to act, the government's action on permit applications was judicially reviewable. However, the OCSLA is silent as to the length of time required for permit applications to process. The court noted that the Outer Continental Shelf Lands Act (OCSLA) establishes a non-discriminatory duty on the part of the DOI to act, favorably or unfavorably, on drilling permit applications. Once the Secretary of the Interior exercises that discretion, the government is under a duty to act by either granting or denying a permit within a reasonable time. The court found that because the government had a non-discretionary duty to act on the applications and because it was beyond quarrel that the government had failed to act, the government's action on permit applications was judicially reviewable. However, the OCSLA is silent as to the length of time required for permit applications to process. (Ensco Offshore Co., et al. v. Kenneth Lee "Ken" Salazar, et al. (EDLa) CCH Energy Management ¶9628)