Energy Legal Blog

A three-judge panel of the US Court of Appeals for the Ninth Circuit in a pair of December 19 opinions — PUD v. FERC and PUC v. FERC — effectively gutted FERC’s decade-old approach to fostering robust and liquid bulk power markets, which FERC has done by granting qualified sellers blanket authorizations to make wholesales at negotiated market- (rather than cost-) based prices. Annually, tens of thousands of wholesale power transactions occur in the US pursuant to this program, but will likely now stop in western states obligated to observe the Ninth Circuit's opinions and possibly elsewhere. Supreme Court review will inevitably be sought.

The two opinions decide companion appeals from FERC decisions in 2003 that rejected complaints by electric power buyers in California, Nevada and Washington seeking relief from contracts that they entered during the 2000-01 western energy crisis. The panel held that prices set in those bilateral transactions pursuant to FERC’s market-based program enjoyed no presumption of legality. Instead, payment of those prices should be refunded to the buyers to the extent the prices exceed a “zone of reasonableness” beginning on a refund-effective date soon after the buyers filed complaints with FERC. The panel remanded the cases back to FERC for a determination of whether and by how much prices exceeded that permissible zone.

According to the panel, FERC was wrong to accord the challenged bilateral contract prices Mobile Sierra protection — named after two Supreme Court decisions from 1956 — that immunizes a contract against unilateral change by either the buyer or seller unless the price is shown to be contrary to the general public interest. The prices and contracts at issue were entitled to no such protection, the panel ruled, because they were the product of FERC’s market-based pricing program — which another Ninth Circuit panel had found deficient in the 2004 opinion in Lockyer v. FERC. And even if that were not the case, the panel held that FERC misapplied Mobile Sierra. In a novel new interpretation of the 50-year old doctrine, the panel opined that Mobile Sierra is asymmetric in that it protects wholesale buyers from unilateral seller complaints that prices are excessively low, but does not equally protect wholesale sellers from unilateral buyer complaints that prices are excessively high. In other words, Mobile Sierra accommodates buyer’s remorse, but not seller’s.

It is in the panel’s expansion of the earlier Lockyer decision that the market-pricing program is dealt what will surely be a fatal blow unless the decisions are overturned. For over a decade, FERC has authorized market-based rate schedules under the Federal Power Act allowing certain electric wholesalers to charge market-determined prices. Eligibility turned on the seller demonstrating in advance that it lacked or had mitigated market power — the ability to set prices for an appreciable period of time — in power supply, power transmission and the inputs to power supply, such as fuel supply or delivery. Once granted market pricing authority, a seller reports any change affecting its lack of market power, files quarterly reports on its market-based sales for the preceding quarter, and triennially demonstrates anew that it continues to lack market power. The Lockyer panel held that a market-based seller who aggregates sales information in its quarterly report is in violation of its market-based rate schedule, loses the protection of the filed rate doctrine for those sales and can be made to refund — even retroactively — its revenues on those sales.

The PUD/PUC panel relied on and expanded Lockyer to erode further the price certainty of market-based sales and make new and ineluctably fatal demands of FERC’s market-based pricing program. Specifically, the panel held that power wholesales pursuant to that program enjoy no Mobile Sierra price certainty following a unilateral challenge unless the contract is presented in advance to FERC and FERC has “an opportunity for [(1)] initial review of whether [the] rate is just and reasonable,” (2) determining “whether the original negotiations occurred in a functional marketplace,” and (3) “timely reconsideration of [the seller’s] market-based [pricing] authorization if market conditions change.”

From the outset of its market-pricing program, the purpose of determining the lack of market power and monitoring changes in market power going forward was and is to facilitate the tens of thousands of market-based wholesales that now occur each year in the US without requiring advance regulatory analysis and approval of specific prices and contract formation. If advance regulatory approval is to be required in order to achieve price certainty, then no purpose is served by the market power determination and monitoring. The entire exercise becomes a nullity. And, in its stead, the new panel-prescribed process becomes unworkable since the FERC does not now have ― nor ever will have ― the resources to determine individually and in advance whether the prices in tens of thousands of market-based wholesales are within a zone of reasonableness and were arrived at pursuant to negotiations in a functional marketplace. Notwithstanding disclaimers to the contrary, the panel, if not reversed, has killed market pricing and competitive wholesale power markets.

The cost of running regional transmission organizations continues to be a point of contention. FERC has agreed with New England officials representing Massachusetts, Connecticut, Maine and New Hampshire that part of ISO-New England’s proposed budget for 2007 deserves more scrutiny, and has established a paper hearing to evaluate the proposal.

In October, the ISO-NE submitted tariff sheets for recovery of an expected $114.9 million revenue requirement for 2007. For the third year in a row, challenges were levied against ISO-NE’s proposed budget. The New England officials asked FERC to hold a trial-type evidentiary hearing to determine whether the costs that ISO-NE plans to pass through to customers, were just and reasonable. In arguing that ISO-NE failed to support its budget, the regional officials pointed to FERC’s statement last year in its Final Rule on Accounting and Financial Reporting for Public Utilities and RTOs  that the changes in financial reporting implemented by that rule should improve cost recovery practices by providing greater detail concerning RTO costs. In particular, the officials challenged ISO-NE’s proposed senior staff incentive payments, depreciation and amortization expenses, non-project capital expenses, consultant and other professional service fee costs, and costs related to projected staffing increases.

The only issue set for hearing is ISO-NE’s proposed depreciation and amortization expenses. In particular, FERC ― like the New England officials ― questioned whether the “relatively short average service lives and zero net salvage values used by ISO-NE may result in excessive amounts of depreciation and amortization” for the coming year. FERC found all of the other complaints to be unfounded or not properly at issue.

Other recent challenges to ISO-NE budgets have not succeeded. Last year, FERC rejected challenges to rate recovery of certain lobbying costs, and in 2005 FERC justified the increase in ISO-NE’s administrative costs based on additional duties taken on by the RTO. As seen again here, FERC’s concern for accurate RTO budgeting does not necessarily translate into reduced rates for RTO services.

Brazos Electric Cooperative (Brazos) applied to FERC in October and again in November for the interconnection of a new 70-mile, 345 kV transmission line that would connect generation in Oklahoma with load in Texas.  The proposed line would be built in conjunction with Brazos’s plans to construct a new 750 MW coal-fired generating unit near the Western Farmers Electric Cooperative‘s (WFEC) existing Hugo generating facility in Hugo, Oklahoma.  Brazos, an electric coop located in 68 counties across north Texas, and WFEC, which has service areas throughout Oklahoma, will jointly own the new Hugo unit.  In order for Brazos to bring this power from Hugo to the Electric Reliability Council of Texas (ERCOT), Brazos is planning to build the new DC intertie between ERCOT and the Southwest Power Pool (SPP), which will have an approximate capacity of 375 MW.  Accordingly, Brazos has asked FERC to order TXU Electric Delivery (TXU) to allow it to interconnect with TXU’s system at the Valley South substation in north Texas.  Brazos also asked FERC to require TXU and CenterPoint Energy Houston Electric to offer transmission service for power flows over the new line into or out of ERCOT.  Brazos has asked FERC to issue a decision on its application by January 31, 2007.

The proposed DC intertie would be the third such interconnection between ERCOT and SPP.  In its application, Brazos took pains to emphasize that its proposed interconnection would maintain the fiction that ERCOT is outside of the interstate grid and not subject to most forms of FERC regulation.  To that end, Brazos specified that the intertie and the generating unit’s switching station would be engineered such that the generating facility could generate only into either ERCOT or SPP, but not both at once.

California ISO president and CEO Yakout Mansour indicated this past Tuesday that the CAISO would likely delay further the implementation of its new Market Redesign and Technology Upgrade (MRTU) tariff until January 31, 2008.  Mansour attributed the need for further delay to the large number of changes FERC ordered the CAISO to make in FERC's September 21 order conditionally approving the tariff, including FERC's requirement that the CAISO certify 60 days before implementation that the MRTU software works as promised.  During FERC proceedings on MRTU, numerous market participants and stakeholders expressed doubts that the CAISO would meet its November 2007 start date, even though it has been four years since the CAISO initially proposed to redesign its market in 2002 on the heels the western energy crisis.  The CAISO Board will convene December 19 to decide on a “firm” implementation date.

Disputes in the Midwest over allocating transmission costs date back to at least the mid 1980s, when competing interests fought over AEP's transmission equalization agreements and the transmission costs associated with the Rockport plant.  Recently FERC resolved for now another of those disputes, by accepting Midwest ISO's proposed allocation of the costs of new transmission infrastructure. 

Midwest ISO proposed to allocate the cost of: (1) lower voltage lines subregionally to all transmission customers in the designated pricing zones affected by the transmission project, and (2)  Extra High Voltage (EHV) ― 345 kV up to 765 kV ― 80% subregionally (like lower voltage facilities) and 20% systemwide on a load-ratio share basis (i.e., a postage-stamp basis).  FERC accepted this allocation on the ground that the EHV lines are the superhighways of the Midwest transmission grid. 

Midwest ISO is the third RTO for which FERC has engaged transmission cost allocation issues.  The others are New England and Southwest Power Pool.  FERC accepted a different approach for each.  Given that FERC has been flexible in allowing different approaches, future RTOs will be free to seek their own solutions to these often divisive issues. 

FERC also accepted Midwest ISO’s proposal for generation interconnection cost allocation, which makes generators responsible for 50% of the transmission upgrade costs if the generation output is committed to network customers or designated as a network resource.  Otherwise, the generator is responsible for 100% of the costs of transmission upgrades required for interconnection.  While FERC rejected arguments that this approach would “chill” generation investment, FERC still directed Midwest ISO to file, within 12 months, an informational report on its experience under this cost recovery methodology.  More to come on this front, as the issue is reopened with more data next year. 

Texas moved closer to developing the additional transmission needed to deliver wind power to loads when the Electric Reliability Council of Texas (ERCOT) issued a report identifying geographic areas that the Public Utility Commission (PUCT) could designate as competitive renewable energy zones (CREZ) under Texas law.  After the CREZ are established, the law then requires construction of the necessary transmission facilities between the CREZ and urban areas.   

Texas currently has more installed wind generation, 2508 MW, than any other state, and this number is expected to rise to approximately 4850 MW by the end of 2007.  However, as in many other parts of the country, the areas where wind power has the greatest potential are far from energy-thirsty population centers.  Texas legislation enacted in 2005 is intended to facilitate the development of needed transmission infrastructure to support future wind power development.  To that end, ERCOT’s analysis concludes that most wind farms would likely be located in the Gulf Coast region, the Panhandle, central-western Texas (along the Abilene-Odessa corridor), and in the McCamey region in west Texas.  Each area has different strengths and weaknesses regarding expected production and transmission costs, capacity characteristics, and daily and seasonable variability of winds.  The report states that several new high-voltage 345-kV transmission lines and associated grid upgrades would be needed to support expected wind farm development.

The PUCT is expected to make CREZ determinations in early 2007.  Any designations will be based on a wide range of factors, including costs of transmission construction and ancillary services, wind energy strength and benefits, and the financial support for proposed projects.