Energy Regulation April 2008 Updates

FERC Affirms and Clarifies New Market-Based Rate Policy
FERC, acting on rehearing of its market-based rate rulemaking proceeding Order No. 697, largely affirmed its earlier rulings, including its decision to utilize a regional approach for the triennial market power analysis (separating the nation into six geographic regions); the adoption of horizontal and vertical power analyses; the use of a balancing authority area or the regional transmission organization/independent system operator market as the default relevant geographic market; and the codification of restrictions on affiliate abuse in the regulations. FERC stated that this will strengthen wholesale power markets and protect customers from exploitation in those market.

The rehearing order also clarifies the horizontal market power analysis. While FERC affirmed its continued use of historical data and a “snapshot in time” approach, it stated that it also will consider case-specific sensitivity studies that present compelling evidence that certain changes in a market should be considered as part of the market power analysis. Finally, FERC will allow mitigated sellers to demonstrate on a case-by-case basis that they do not have market power with respect to long-term contracts.

Transmission Owners Can Choose to Pay 100 Percent of Network Upgrade Costs in Midwest Independent System Operator (ISO)
FERC has denied rehearing of an order that allowed three transmission owners: International Transmission Company, Michigan Electric Transmission Company, and American Transmission Company, to pay 100 percent of network upgrade costs needed to interconnect a new generation facility to their transmission facilities. These costs can be received through transmission rates under the Midwest ISO tariff.

The Midwest ISO’s tariff generally requires the interconnection customer itself to pay 100 percent of the upgrade costs, with possible recovery of 50 percent of those costs. In this docket, FERC accepted tariff changes that also allow transmission owners to choose to pay 100 percent of the network upgrade costs, rather than the generator. Of the 100 percent paid by the transmission owners, 50 percent is eligible for recovery through tariffed regional cost-sharing measures and 50 percent can be recovered automatically through zonal transmission rates.

Several Michigan utilities, consumer groups, and the Michigan Public Service Commission requested rehearing of FERC’s order accepting these tariff changes. They argued that transmission companies have incentives to over-invest in transmission infrastructure, which subjects existing transmission customers to unnecessary rate increases. They also argued that customers will be forced to pay for network upgrades that provide no benefit if the interconnection customer decides to serve load outside the Midwest ISO region after its one-year minimum term of service is met. FERC rejected these arguments as well as the request that a cap be imposed on interconnection costs eligible for reimbursement, finding that network upgrades benefit all customers by providing a more competitive generation market.

Incentive Rate Treatment for Transmission Projects Varies in Recent Cases
In the past two months, FERC has issued a series of orders implementing Order No. 679’s policy of allowing public utilities to obtain incentive rate treatment for transmission infrastructure investments that meet certain criteria. The applicant must be able to demonstrate a nexus between the rate incentive requested and the particular risks of the project.

In a recent case applying the incentive rate policy involving a 130-mile, 500 kV transmission line (Susquehanna Line) of PPL Electric Utilities Corporation and Public Service Electric & Gas Company, FERC approved — with two partial dissents — a 1.25 percent return on equity adder, a 0.5 percent adder to each utility’s base return on equity for continued membership in PJM, full recovery of prudently incurred Construction Work in Progress (CWIP) expenses in rate base, abandonment incentives if the project does not go forward to completion, and authority to transfer certain incentives to affiliates in the future.

FERC action in other incentive rate cases:

1. On PG&E’s proposed 1,000-mile transmission project from British Columbia to northern California: To allow financing for continued studies, FERC granted the ability to recover prudently-incurred abandonment costs and pre-commercial costs, subject to a subsequent Section 205 filing as to prudence, but FERC deferred consideration of the applicant’s request for CWIP and Return on Equity (ROE) incentives due to the early stage of the project.
2. For Nevada Hydro Company’s proposed transmission line that would link San Diego Gas & Electric Company’s transmission system with Southern California Edison: FERC granted an incentive equity return “not to exceed the requested 13.5 percent” and a hypothetical 50/50 capital structure for the construction phase of the project.
3. For three transmission projects of Westar Energy, Inc.: The first was granted a 12.3 percent ROE incentive and accelerated depreciation treatment, the second had rate incentives denied because it had already been completed, and the third was denied because Westar had failed to demonstrate the required nexus. 

FERC Allows Master Limited Partnerships in Gas and Oil Pipeline Rate of Return Proxy Groups
Spurred by a 2007 D.C. Circuit decision, FERC has issued a Policy Statement, which holds that Master Limited Partnerships (MLP) should be included in the return on equity proxy group for gas and oil pipelines. Under the Discounted Gas Flow (DCF) methodology that FERC has employed since the 1980s, the return on equity allowed for interstate pipelines has been based largely on the returns earned on investments in companies with corresponding risks as the pipeline. In recent years, however, as mergers have reduced the number of publicly traded corporations with natural gas pipeline operations, fewer corporations have satisfied FERC’s standards for inclusion in the pipeline proxy groups. At the same time, there has been a trend towards MLPs owning natural gas pipelines. FERC thus determined to include MLPs in the proxy group used for determining the return on equity for gas and oil pipelines. FERC also found that there should be no cap on the level of distributions included in the DCF methodology.

MLPs generally distribute most of their available cash to their general and limited partners in the form of quarterly distributions that include net income plus depreciation and amortization minus the capital investments of the partnership. In contrast to a corporation’s dividends, an MLP’s cash distributions generally exceed its report earnings and the returns for MLPs generally equal the cost of the capital plus some additional return for the existing unit holders. By including MLPs in the proxy group used to determine the return on equity component of rates, FERC’s Policy Statement appears likely to increase the return allowances for FERC-jurisdictional interstate gas and oil pipelines. 

U.S. Supreme Court to Review EPA’s Cooling Water Intake Structure Rules: Estimated $66 Billion in Power Plant Costs at Issue
The U.S. Supreme Court agreed on April 14, 2008 to consider a case that should resolve whether the U.S. Environmental Protection Agency (EPA) can conduct cost/benefit analysis when determining the “best technology available for minimizing adverse environmental impacts” from cooling water intake structures at power plants. Utilities have estimated that as much as $66 billion is at issue in the case.

The Court granted and consolidated petitions from Entergy Corp., PSEG Nuclear LLC, and the Utility Water Act Group (Nos. 07-588, 07-589, and 07-597) to review this one issue raised by the Second Circuit’s decision in Riverkeeper Inc. v. EPA, 475 F.3d 83 (2d Cir. 2007), commonly referred to as the Riverkeeper II case.

Section 316(b) of the Clean Water Act (CWA) requires large power plants to install the “best technology available” (BTA) to protect fish, shellfish, and other aquatic organisms from harm caused by cooling water intake structures. On its face, Section 316(b) does not specify what factors should be considered when selecting the BTA for a specific cooling water intake structure. But the statute includes cross-references to CWA Sections 301 (Effluent Limitations) and 306 (National Standards of Performance), which both include cost as an appropriate consideration.

EPA has adopted three sets of rules (each a rulemaking “phase”) governing the selection of BTA for cooling water intake structures under CWA Section 316(b). The Phase I rules govern cooling water intake structures at new facilities; the Phase II rules cover cooling water intake structures at existing facilities; and the Phase III rules apply to intake structures at new offshore oil and gas extraction facilities. An environmental group headed by Robert Kennedy Jr., called Riverkeeper, Inc., has lead challenges to all three rulemaking phases.

In Riverkeeper II — the case the Supreme Court just agreed to review — the Second Circuit remanded to the EPA portions of its Phase II rules related to existing facilities (rules the EPA subsequently suspended) and found that the EPA should not conduct cost-benefit analysis when determining the best available cooling water intake technology. Instead, the Second Circuit found that cost can be considered under Section 316(b) only in determining whether the industry as a whole can reasonably bear the costs of a certain technology and in choosing one technology over another when both technologies achieve essentially the same results. The Second Circuit based this finding on its previous 2004 decision in Riverkeeper I, which addressed the Phase I rules for new facilities, and on an interpretation of the cost consideration conducted pursuant to CWA Sections 301 and 306.

Because the Supreme Court’s review of this issue also may include an examination of CWA Sections 301 and 306, along with 316(b), the Supreme Court’s decision likely will have broad implications. The oral arguments in this case will occur in the next Supreme Court term, which starts in early October, so a decision is unlikely until winter/spring 2009.

Inquiry Into FERC Annual Regulatory Charges Methodology
On April 17, 2008, FERC issued a Notice of Inquiry (NOI) to determine whether its method of assessing its annual regulatory charges on public utilities is fair, or whether an alternative method should be utilized to allocate regulatory costs. The alternative methods include levying the charge only on wholesale transmission volumes, establishing new charges on wholesale power sales and other license fees, accounting for regional differences in market structure, or using factors such as peak load or transmission investment.

FERC requested comment on (1) whether the current electric annual charges assessment methodology remains fair and equitable for recovering FERC’s electric regulatory programs costs, (2) what alternative electric annual charges assessment methodology is fair and equitable if the current methodology no longer meets that standard, and (3) what entities would be assessed electric annual charges and how such an alternative methodology should work under a proposed alternative method. Comments on FERC’s proposal are due 30 days from the NOI’s publication in the Federal Register.

FERC Adopts Policy on NERC Penalty Notices for Reliability Standard Violations
Last week FERC adopted a policy for its review of notices of penalties filed by the North American Electric Reliability Corporation (NERC). When a user, owner, or operator of the bulk power system violates a Reliability Standard, NERC or the Regional Entity may impose a penalty on the guilty party. Order No. 672 required NERC or the Regional Entities to file a notice of the penalty that it imposed with FERC. In its order addressed last week, FERC proposed to adopt six modified reliability standards from NERC, relating to interchange scheduling and coordination and transmission loading relief procedures.

Under its new policy, FERC stated it does not anticipate reviewing every penalty notice of uncontested penalties filed by the NERC on the ground that such review would be inconsistent with the enforcement discretion of NERC and the Regional Entities. Nevertheless, FERC indicated that it may review notices of penalty even if the registered entity subject to the notice does not file for review. In these cases, FERC will weigh the seriousness of the violation when deciding whether to review penalty amounts. FERC emphasized that it encourages the Regional Entities and NERC to enter into settlements, and that it normally will allow NERC and Regional Entity settlements to become effective.

FERC Approves Acquisition of Puget Energy by Macquarie
As part of a trend in recent years of increased foreign ownership of utility assets in the United States, FERC issued an order on April 17, 2008 that approved the acquisition of Puget Energy, Inc. (Puget) by an Australian-Canadian investment group headed by Macquarie Group Limited (Macquarie), which had previously acquired Duquesne Light in 2007. Among the investors is British Columbia Investment Management Corporation (British Columbia), an entity established under provincial legislation to provide funds management services to publicly administered trust funds.

Findings and Conditions. FERC determined that there was no negative effect on competition because of the distance of any of the other Macquarie-related utility assets from Puget and because the electric utility-owning crown corporations of British Columbia were determined not to be under common control. The applicants committed not to seek recovery of any acquisition premium or transaction costs. FERC found that the applicants were entitled to safe-harbor status for cross-subsidization purposes to the extent that the Washington Commission accepts certain conditions that the applicants have offered, which include the provision of a non-consolidation opinion as to the utility assets and liabilities of Puget being bankruptcy-remote from the parent as well as commitments to maintain separate books and records, not to pledge utility assets without state approval, and to hold state ratepayers harmless from business and financial risks of the parent and other affiliates.

Future Transfers. The applicants also received a pre-authorization for future transfers of some of the Macquarie-owned interests to other Macquarie-managed funds or affiliates as well as to third-party investors to the extent they were not engaged primarily in energy-related businesses, would not hold more than 20 percent voting interest in Puget, and, when combined with the interests of any other affiliate, would not own five percent or more interest in any public utility owning generation or engaging in jurisdictional facilities within the Northwest Power Pool region.

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