Energy Legal Blog

WestConnect Utilities Experiment to Eliminate Rate Pancaking in Southwest

Eight WestConnect utilities, including Arizona Public Service Company, El Paso Electric, Nevada Power, Public Service Company of Colorado, Public Service Company of New Mexico, Southwest Transmission Cooperative, Tri-State, Tucson Electric Power, and WAPA, petitioned FERC on June 10 for guidance on a proposed two-year experimental transmission pricing initiative that would eliminate rate pancaking in the Southwest.  The proposed experiment will offer customers the option to purchase hourly non-firm point-to-point transmission service at a single regional transmission rate instead of having to pay pancaked rates under each provider’s open-access tariff.

WestConnect proposes to charge the transmission customer a single, flat rate that would be equal to the highest non-firm ceiling rate charged by a participating transmission owner.  In addition to an administrative charge for the experiment, the transmission customer would pay for scheduling and dispatch, along with reactive and voltage control.  Under the experiment, regional service would result in a lower rate than is currently available.  By charging this flat rate, WestConnect expects the reduced and simplified rates will increase transmission use.  Revenues will be distributed on a pro rata basis to each participating transmission provider. 

The WestConnect utilities have asked FERC to respond by September 15, 2008, and anticipate beginning the experimental pricing on February 1, 2009 for two years.  At the end of the two year period, WestConnect would evaluate the experiment’s effect on grid utilization and the participants’ revenues.

 

Divided Supreme Court Stirs Ashes of the 2000-01 California Energy Market Conflagration

A divided US Supreme Court in June 26 opinions argued over the meaning and existence of the eponymously named, half-century-old Mobile-Sierra doctrine.  Morgan Stanley Capital Group, Inc. v. Public Utility District No. 1 of Snohomish County ruled on consolidated buyer challenges to the prices in long-term wholesale energy contracts entered during the 2000-01 western energy market meltdown.  The buyers’ complaints were initially raised at the Federal Energy Regulatory Commission, which denied the challenges on the ground that the Federal Power Act authorized FERC to change the terms of a bilateral contract only if the contract were improperly induced (for example, through fraud or duress) or found to be contrary to public (as opposed to private) interest.  The buyers had made neither showing, FERC ruled.  On appeal, the United States Court of Appeals for the Ninth Circuit reversed on the ground that Mobile-Sierra’s presumption of lawfulness never attached to the contracts since FERC had not at the outset reviewed and found the market-based prices at issue to be just and reasonable.  Even if the presumption did attach, the Ninth Circuit held that FERC erred by holding a buyer to the same high burden of proof that a seller confronts in proving a contract violates the public interest.  According to the Ninth Circuit, a buyer challenging a wholesale power price as too high confronts a lesser burden than a seller challenging a price as too low, and need show only that a contract price exceeds a “zone of reasonableness” defined as marginal cost.

Justice Scalia’s (5-2) majority decision, with Justice Ginsburg concurring, Stevens and Souter dissenting (Chief Justice Roberts and Justice Breyer did not participate), affirmed FERC’s determination that Mobile-Sierra applies to the challenged contracts and rejected the Ninth Circuit’s interpretation of Mobile-Sierra as an “estoppel doctrine” that attaches only after a necessary threshold determination of price justness and reasonableness is made and thereafter “prevents [FERC] from modifying the rates absent serious future harm to the public interests.”  It also affirmed FERC's conclusion that its contract abrogation authority is confined to "extraordinary circumstances where the public will be severely harmed" and rejected the Ninth Circuit’s asymmetric interpretation of Mobile-Sierra as requiring only that a challenging buyer show that price exceeds a marginal-cost zone of reasonableness.  Weirdly, however, the majority went on to affirm the Ninth Circuit decision to send the buyers' complaints back to FERC on remand.  It did so for two reasons.

First, the majority erroneously conjectured that FERC “appears . . . to have looked simply to whether consumers’ rates increased immediately upon the relevant contracts’ going into effect, rather than determining whether the contracts imposed an excessive burden on consumers ‘down the line . . . .”  Not only is this factually wrong — FERC made explicit findings as to the rate effects over the life of many of the challenged contracts — it is also inconsistent with the majority’s validation of market "stabilizing force of contracts” that Mobile-Sierra enforces by "holding sophisticated parties to their bargains” over time.

Second, the majority explained that Mobile-Sierra’s presumption that a contract is just and reasonable should not attach “if it is clear that one party to a contract engaged in such extensive unlawful market manipulation as to alter the playing field for contract negotiations” because (as in instances of fraud or duress) no contract is legally formed in the first place under such circumstances.  The Court directed FERC on remand to explain “whether it found the evidence inadequate to support the claim that respondents’ alleged unlawful activities affected the contracts at issue here.”  The referenced allegations, which are sure to be repeated, come from a 2003 FERC staff report that the agency never adopted and which has since been called into question for using allegedly falsified data.

 The majority decision is noteworthy in two additional respects.  First both the majority held and dissent agreed that the three showings that a rate violates the public interest — impairs the financial ability of a public utility to provide service, excessively burdens consumers, or is unduly discriminatory — are not exclusive.  And second, at one point the majority seems to invite a facial challenge to FERC’s market-base ratemaking —“We reiterate that we do not address the lawfulness of FERC’s market-based-rates scheme, which assuredly has its critics” — notwithstanding the recent decision of the US Court of Appeals for the DC Circuit rejecting such a challenge. 

Justice Stevens’ dissenting opinion questions whether there is a Mobile-Sierra doctrine or public interest standard independent of the Federal Power Act requirement that rates be just and reasonable and faults both the Ninth Circuit and the majority for “hobbl[ing]” FERC from different sides in making a required determination whether contracts are just and reasonable.

Wisconsin Power & Light Offers Emission-Saving Goodies to Make New Coal Plant Proposal Palatable

In an effort to counter opponents of its proposal to expand an existing coal-fired generating station by 300 MW, Wisconsin Power & Light (WP&L) has offered to take several steps to offset the increased greenhouse-gas emissions that would result from the expanded plant's operation.  In a draft environmental impact statement, the Wisconsin Public Service Commission criticized WP&L's proposed use of a circulating, fluidized bed (CFB) boiler, which results in higher CO₂ emission.  In response, rather than abandon CFB, WP&L has offered to retire the oldest coal-fired plant in its fleet, develop an additional 200 MW of wind power above the 300 MW it has already pledged to develop in the next several years, increase the amount of biomass co-firing planned for the new unit, and increase energy efficiency and conservation efforts.  WP&L's estimated cost for these proposed efforts are $500-$550 million. 

The approach taken by WP&L proved successful for another Alliant Energy Corp. subsidiary.  Interstate Power & Light offered to the Iowa Public Utility Board a package of actions, including retiring older plants, building more wind power and increasing biomass co-firing in order to win the Board’s approval of a new coal-fired plant.  More quid-pro-quos of this sort can be expected.  Even as federal greenhouse gas legislation recently failed to overcome a threatened filibuster, its eventual passage appears probable and will impact state regulatory decision making.

Michigan Legislators Consider State RPS, Rolling Back Electric Choice

The Michigan Legislature currently is considering legislation that would enact a renewable portfolio standard (RPS) and that would limit electric choice in the state.  At issue are three bills that have been passed by the state's House of Representatives and are now under Senate consideration. 

House Bills 5548 and 5549 would require the state's utilities to obtain at least 10% of their power from renewable energy resources by 2015.  These bills, however, do not currently propose to allow competitive bidding for renewable resources.  Senate Republicans have indicated they will seek to amend the legislation to require competitive bidding when the Senate takes up the measures. 

H.B. 5524 proposes to impose a 10% hard cap on participation in electric choice programs.  Opponents of the measure say it would effectively end electric choice in the state.  The state's largest utilities, Detroit Edison and Consumers Energy, have supported the bill, asserting that electric choice has limited their ability to secure financing for new power plants and to implement energy efficiency and renewable energy programs.

The Senate Energy Policy and Public Utilities Committee passed all three bills last week, by identical votes of 5-3.  The bills will now come before the full Senate, although it is unclear when they are slated to do so.

ERCOT Imposes New Price Controls

The Electric Reliability Council of Texas (ERCOT) reduced its shadow price cap from $5,600 to $5,000/MWh and collared the market-clearing price for energy (MCPE) between a cap of $2,250/MWh and an floor of -$1,000/MWh. These price controls, which took effect on June 18, 2008, are designed to prevent the MCPE from rising above the current offer cap for balancing energy services of $2,250/MWh. This is the second system change implemented in June to address recent price volatility in the ERCOT market. Earlier in June, the ERCOT board adopted a protocol change designed to allow more efficient management of transmission congestion. The new limits on price volatility come in the wake of steep increases in the price for wholesale power in the Houston and South zones of the ERCOT region. The new measures come at the direction of the Public Utility Commission of Texas, which recently ordered two stakeholder committees to review the issue. The stakeholders considered the recommendation of Dan Jones of Potomac Economics (the Independent Market Monitor for ERCOT), along with two other proposals, and unanimously recommended implementation of the Potomac Economics' proposal.

San Francisco to Fund Nation's Largest Municipal Solar Program

The City and County of San Francisco Board of Supervisors on June 10, 2008, approved a program that will create a fund to provide rebates for residents and businesses that install solar power systems. Under the Solar Energy Incentive Program, the nation's largest municipal solar program, residents could receive between $3,000 and $6,000 for photovoltaic systems. Businesses could receive $1,500 per kilowatt installed, with a cap of $10,000 per building. The 10-year program will use up to $50 million from the city's energy-conservation account. The Board of Supervisors also voted to approve a complimentary one-year pilot program that would budget $1.5 million to buildings owned and operated by low-income residents and non-profit organizations.

The Solar Energy Incentive Program would supplement incentives from the federal investment tax credit and the California Solar Initiative. Creation of the program is propitious since the federal investment tax credit is set to expire at the end of this year.

Supervisor Dufty, a co-sponsor of the measure, believes that the program will provide an important opportunity to encourage the development of the solar industry in San Francisco. The incentives provided by the program will help with installation costs, which are more expensive in San Francisco than in surrounding counties. The program also seeks to help San Francisco increase its amount of solar generation. Currently, the city ranks last in the Bay Area in terms of the solar energy installed per capita, according to data compiled by the California Energy Commission and the California Public Utilities Commission.

Amaranth Court Explicates Elements of Attempted Price Manipulation under Commodity Exchange Act

In a May 21 opinion US District Court Judge Denny Chin denied defendants Amaranth Advisors' and natural gas trader Brian Hunter’s motion to dismiss the Commodity Futures Exchange Commission’s (CFTC) complaint against them alleging attempted price manipulation in violation of §13(a)(2) of the Commodity Exchange Act (CEA).  In so ruling, Judge Chin explicated the elements of attempted manipulation under the CEA — a charge that is increasingly being brought against natural gas and power traders, not only under the CEA, but also under provisions of the Natural Gas and Federal Power Acts.   

In its complaint, the CFTC alleged that the defendants attempted to manipulate the price of natural gas futures contracts traded on the New York Mercantile Exchange on February 24 and April 26, 2006 — the expiration dates for March and May futures contracts, respectively.  They did so, according to the CFTC, when Hunter instructed Amaranth traders to sell sizable long positions during the final 30 minutes (“closing range”) of the expiration date, a practice known as “marking the close.”  Defendants made these last-minute sales, the CFTC contends, to drive down the settlement price for the March and May NYMEX contracts and thereby increase Amaranth’s profits on large short positions that Amaranth concurrently held in natural gas swaps on the IntercontinentalExchange (ICE) commercial market.  ICE swaps settle at the NYMEX settlement price.  The CFTC also alleged that through the April 26 “marking the close” Amaranth also sought to counteract the price effect of a competitor’s long position in NYMEX natural gas futures contracts. 

Judge Chin denied the defendants’ motion to dismiss for failure to state a claim because the CFTC properly alleged (1) an intent to affect market prices, and (2) an overt act in furtherance of that intent.  For either attempted or completed manipulation, the intent element is the same and is typically inferred by actions or circumstances evincing a purpose to cause prices or price trends to depart from legitimate forces of supply and demand.  The CFTC properly pleaded intent through allegations that defendants Amaranth and Hunter engaged in “marking the close” sales in order to “smash” the March 2006 contracts and “experiment” with late sales to affect May prices.  The allegation that Amaranth was motivated to increase the profits on its short positions on ICE swaps, Judge Chin explained, made the inference of intent “even more plausible.”   Demonstration of fraudulent misrepresentation or an actual ability to cause an artificial price is not required, Judge Chin ruled.

Unlike the CEA, the Natural Gas (§4A) and Federal Power (§222) Acts (as amended in 2005) make actionable only completed manipulation, but not attempted manipulation.  That is why in its administrative proceeding against Amaranth and Hunter the FERC has alleged completed manipulation, which entails a more arduous burden of proof for the plaintiff.   

First NERC Penalty Notices Suggest Focus on Enforcement

On June 4, 2008, the North American Electric Reliability Corporation made its first public announcement of its Notices of Penalty when it filed at FERC the first batch of proposed penalties for reliability standard violations.  Most Notices of Penalty filed with FERC were for a zero penalty amount, however, Baltimore Gas & Electric and MidAmerican Energy Company received penalties of $180,000 and $75,000, respectively, for violations of the Transmission Vegetation Management Standard, FAC-003-1.  Violations of the Transmission Vegetation Management Standard were one of the major causes of the 2003 Blackout and an area where Regional Entities and NERC clearly intend to keep a watchful eye to ensure companies' compliance.  Violations of reliability standards can result in penalties of up to $1 million per day per violation.

The most common violations have been violations of the sabotage reporting requirements set forth in CIP-001-1, followed by violations of other standards that address normal operations planning, maintenance of generation and transmission protection systems, and facility ratings methodology.  Many of the Notices of Penalty characterize violations as "documentation" issues because while many companies may have procedures in place, Regional Entities and NERC have found their documentation of such procedures to be lacking.  The Notices of Penalty put an emphasis on the actions taken by companies to ensure reliability going forward, including the completion of Mitigation Plans to remedy violations and prevent future violations.  The Regional Entities have discovered violations through spot checks, self certifications, self reports, and compliance audits. 

So far, NERC has made zero penalty amount determinations based on the presence of most, if not all, of the following eight factors: (1) the violation was a documentation issue, or was characterized as minor under the circumstances; (2) no system disturbance occurred as a result of the violation and the violation did not jeopardize bulk power system reliability; (3) the violation occurred prior to 1/08; (4) the violations are the first incidence of violation for the registered entity; (5) the registered entity's cooperation with the regional entity; (6) immediate action to mitigate; (7) the violation was mitigated in accordance with the mitigation plan; and (8) the registered entity's actions ensured reliability.

DOE Belatedly Files License Application with the NRC to Approve the Yucca Mountain Spent Nuclear Fuel Repository

On June 3, 2008, the U.S. Department of Energy (DOE) finally submitted its initial license application to the U.S. Nuclear Regulatory Commission (NRC) seeking construction authorization pursuant to 10 C.F.R. § 63.31 for a high-level radioactive waste repository at a geologic repository operations area at Yucca Mountain in Nye County, Nevada.

The voluminous license application comprises both General Information and a Safety Analysis Report (SAR). The General Information includes a general description of the repository and its operations and the DOE's plans for constructing and protecting the repository facilities and their contents.  The SAR is the principle technical document and discusses how the repository is considered safe and complies with the NRC's regulations.  In the SAR the DOE provides information on the repository's geology, hydrology, mineralogy and surface features and all of the structures and systems that will be constructed to receive, process and emplace spent nuclear fuel.  It also analyzes potential safety hazards and demonstrates that all of the features and structures will perform within acceptable ranges to keep the repository safe.

Congress and President Bush approved Yucca Mountain in 2002 as the site for the United States' first permanent spent nuclear fuel and high-level radioactive waste repository.  Presumptive Republican presidential candidate John McCain has expressed support for the repository at Yucca Mountain, while presumptive Democratic presidential candidate Barack Obama (together with Senate Majority Leader Harry Reid) has expressed opposition to the project. 

FERC Augments, Revamps Enforcement Guidance and Procedures

FERC has taken several steps to clarify its policies for conducting enforcement investigations, carrying out its authority to impose penalties on violators, and broadening the scope of issues to be covered by its ex parte rules and no-action letter procedures.  The additional guidance is welcome in light of the seemingly haphazard approach to enforcement that FERC has taken over the last couple of years. 

FERC’s new Revised Policy Statement on Enforcement supersedes its 2005 Policy Statement on Enforcement.  The Revised Policy Statement affirms FERC's existing enforcement policies and explains the usual steps involved in FERC's conduct of audits and enforcement investigations.  It describes the types of matters that FERC has recently determined do not merit investigation or that have not resulted in findings of a violation or sanction.  It lists several actions that entities can take to develop strong compliance programs, and offers suggestions for making effective self-reports.  Finally, it augments the current list of factors that FERC will consider when determining the seriousness of an offense:

• What, if any, harm was there to the efficient and transparent functioning of the market?
• What are the earnings, revenues and market share of the part of the company that is under investigation?
• What penalty amount best deters improper conduct, while not excessively discouraging beneficial market participation?
• What was the motivation of those accused of the improper conduct?
• Was the integrity of the regulatory process impaired:
• Was there a risk of serious harm, even if the actual harm was slight of non-existent? 

FERC also issued a Notice of Proposed Rulemaking (NOPR) to clarify its regulations governing ex parte contacts (Rule 2201) and separation of functions (Rule 2202) in the context of non-public investigations.  Rule 2202 prohibits FERC staff that act as litigators in an adjudicated proceeding from advising as to the outcome or decision in that proceeding.  The NOPR proposes that this separation begin at the point when FERC issues a show-cause order in a proceeding or initiates a civil action under Part 1b of FERC's regulations.  The NOPR also proposes to apply FERC's ex parte rules during investigations conducted under Part 1b, where they do not currently apply.   

Finally, FERC issued an Interpretive Order modifying its no-action letter process and reviewing other mechanisms for obtaining compliance guidance.  The no-action letter process is currently limited to issues relating to the Standards of Conduct for transmission providers, Affiliate Restrictions for electric sellers, Code of Conduct for natural gas sellers, and FERC's Market Behavior Rules and Market Manipulation Rules.  FERC has expanded the scope to include any issue that falls within its jurisdiction, except for issues arising under Part 1 of the Federal Power Act (FPA), sections 215 and 216 of the FPA (regarding NERC and National Interest Electric Transmission Corridors), sections 3, 7 and 15 of the Natural Gas Act, and section 311 of the Natural Gas Policy Act.

FERC Mostly Affirms Market-Based Rate Program

On April 21, FERC issued an order generally affirming its market-based rate program, promulgated last June in Order No. 697.  FERC left many of its prior determinations in place, including much of the analysis sellers must provide in order to receive or maintain authority to sell electric energy, capacity, and/or ancillary services at market-based rates. 

In particular, FERC affirmed its decision to combine its prior four-pronged analysis into an evaluation of horizontal and vertical market power.  FERC will continue its approach of using "indicative" screens to determine both a seller's wholesale market share and whether the seller is a "pivotal" supplier within the relevant geographic market.  If a seller fails to pass either of these screens, FERC will presume the seller has market power within that market and require the seller to either (a) refute that it has market power or (b) adopt mitigated (i.e., cost-based) rates for that market.  FERC also affirmed its decision to remove questions about the relationship between market-based rate sellers and their affiliated franchised public utilities from the market-based rate review program, and instead to codify those requirements in FERC's regulations as ongoing obligations that sellers must continue to meet.

FERC did offer certain clarifications or revise certain of its prior determinations on rehearing.  One of FERC's major changes was to allow a seller that has been presumed to have market power in the short-term to continue to show that it does not have market power, and thus may continue to charge market-based rates, with respect to its long-term contracts.  To do so, a seller is required to show that the buyer has other viable alternatives to purchasing power under the contract.  Additionally, with respect to FERC's affiliate restrictions, FERC granted rehearing on its adoption of a prohibition on two-way information sharing between market-based rate sellers and affiliated franchised public utilities with captive customers, determining instead that to adopt a one-way prohibition, i.e., the utility may not provide information to the market-based rate seller.  A few FERC's other notable clarifications included:

• FERC clarified that sellers may make use of ISO/RTO mitigation and/or market monitoring in order to show they do not possess market power and that such mitigation and monitoring will be presumed to be sufficient to address market power concerns, although other parties may present evidence otherwise. 

• FERC made certain clarifying changes with respect to the horizontal market power analysis, which examines whether a seller has generation market power in generation.  In particular, FERC clarified the data that it will rely upon in this analysis.  FERC generally affirmed its decision to rely solely on historical data to determine whether a seller has market power.  However, FERC conceded that it will consider, on a case-by-case basis, "clear and compelling evidence" that certain changes in relevant geographic markets should be taken into account.  Additionally, FERC also provided several clarifications to the transmission import studies that sellers must provide to account for uncommitted generation capacity in their relevant markets.

• FERC clarified that sellers are not required to report on firm transmission rights or congestion contracts (collectively, FTRs) as part of their analyses of their vertical market power, which examines whether a seller has market power with respect to transmission or can erect other barriers to entry.

• FERC codified definitions of "affiliate" and "captive customers" in its regulations, and clarified that the affiliate restrictions in its regulations generally supersede prior "codes of conduct."

Bonneville Holding Transmission Open Season to Speed Interconnections

Transmission providers and customers alike are increasingly complaining about the lengthy queues for interconnecting to the transmission grid.  Scores of generator projects sign up for interconnection service, which is then delayed for years while the transmission provider conducts an array of studies.  To clear backlog on its transmission network, the Bonneville Power Administration is conducting a Network Open Season for transmission service that asks customers to commit to the transmission service they are seeking. 

At present BPA’s transmission queue includes requests by 25 customers for approximately 180 applications for transmission service totaling about 8,500 MW of new capacity, but BPA states that many of these service requests are speculative.  Under its new procedure, BPA will give all customers applying for transmission service by May 15, 2008, a precedent service agreement.  If a customer signs the binding agreement and remits the required financial security by June 16, 2008, BPA commits to providing the service, so long as it can provide the service at its rolled-in rate and complete its environmental study obligations.  BPA also will assume the study costs itself and arrange financing for any required transmission facilities, instead of requiring customers to front these costs.  However, if a customer declines the offer, BPA will withdraw its service requests from the transmission request queue, while allowing the customer to participate in future Network Open Seasons.

In December 2007, the Federal Energy Regulatory Commission held a technical conference focusing on transmission queue logjams.  The interconnection queue process is governed by Order No. 2003, which standardized the agreements and procedures related to the interconnection of large generating facilities based on a first-come, first-served process.  However, the surge of new generation projects, including many based on wind and other forms of renewable energy, have led to long interconnection queues that transmission providers are now debating how to expedite. 

ERCOT Identifies Scenarios for Texas Wind Transmission

Texas Senate Bill 20 (2005) directed the Public Utility Commission of Texas (PUCT), in consultation with the Electric Reliability Council of Texas (ERCOT) and the Southwest Power Pool (SPP), to designate Competitive Renewable Energy Zones (CREZ) and develop transmission plans for areas in Texas with significant renewable resource potential and developer commitment to facilitate new electricity generation from renewable resources.  In July 2007 the PUCT designated five CREZs in West Texas and the Texas Panhandle.  In early April ERCOT filed its transmission study, which provides transmission plans and cost estimates for the four scenarios that the PUCT designated.  The study presents optimized transmission plans for developing between 12,000 MW and 24,000 MW of wind generation in the CREZs.

ERCOT applied three overarching criteria to its evaluation of the study scenarios: 1) system reliability, 2) sufficient transfer capability, and 3) benefit and cost-effectiveness for consumers.  ERCOT made a significant effort to evaluate the engineering feasibility of the interconnections and circuits that it proposed.  Consistent with the PUCT's directive, ERCOT also endeavored to design the transmission plans for each scenario to be staged and expandable to bring more wind generation on-line over time.

For Scenario 1, ERCOT designed two transmission proposals for 12,053 MW of wind generation.  Plan A has an estimated cost of $2.95 billion, excluding collection costs, and Plan B, which is a more scalable transmission proposal, has an estimated cost of $3.78 billion.  ERCOT recommended Plan B, since it provides for more cost-effective expansion in the future.

For Scenario 2, ERCOT's estimated cost of the transmission proposal for 18,456 MW of wind generation is $4.93 billion, excluding collection costs.

For Scenario 3, ERCOT's estimated cost of the transmission proposal for 24,859 MW of wind generation is $6.38 billion, excluding collection costs.

For Scenario 4, ERCOT's estimated cost of the transmission proposal for 24,419 MW of wind generation is $5.75 billion, excluding collection costs.
 

Too Much Adieu about Mobile-Sierra?

Did a panel of the US Court of Appeals for the District of Columbia Circuit bid adieu to the half century-old Mobile Sierra doctrine on contract stability when it otherwise affirmed the Federal Energy Regulatory Commission's approval of a multi-party settlement that phases in a Forward Capacity Market in New England?  Notwithstanding alarms to the contrary, it did not.   The panel in Maine Public Utilities Comm'n v. FERC ruled that the challenges of non-settling parties to prices set in the new Forward Capacity Market are to be judged under the statutory just and reasonable standard of review, and not the deferential standard applied under Mobile Sierra when a party to a contract (or its privies) unilaterally seeks to change the terms of its agreement.  That ruling does not show the Supreme Court's Mobile Sierra doctrine the door.

In companion cases, United Gas Pipe Line Co. v. Mobile Gas Serv. Corp and Fed. Power Comm'n v. Sierra Pacific Power Co., the Supreme Court in 1956 held that the terms of a valid, bilaterally negotiated wholesale energy contract are presumptively just and reasonable under the Federal Power and Natural Gas Acts, and that FERC has authority under those statutes to set aside such contracts only in extraordinary circumstances of unequivocal public interest.  Showing only that the contract had become unprofitable to one of the parties was not enough to allow that party unilaterally to change the contract.

Consistent with the Supreme Court's ruling, the Maine PUC panel affirmed a settlement provision that rates set in the Forward Capacity Market could be presumptively just and reasonable as to parties consenting to the settlement agreement, which parties thereafter could not set aside those rates except on a showing of unequivocal public necessity.  FERC erred, however, and the panel reversed when FERC extended that proposition to the eight (of over 150) parties who did not join but rather "vociferously" opposed the settlement.  In other words, the panel ruled that parties to a wholesale energy contract or settlement agreement who become unhappy with their bargain could be made subject to the higher burden of proof imposed by the deferential Mobile Sierra doctrine, but not non-parties.  This is not a rejection of Mobile Sierra.  Rather, the panel's language strongly reaffirms the doctrine's deference to all contracts and forcefully restates the heavy burden imposed on any party seeking to change its contract.

This reaffirmation is significant and timely, since the Supreme Court recently heard argument and will soon decide whether to reverse a ruling of the full US Court of Appeals for the Ninth Circuit that would eviscerate the Mobile Sierra doctrine.  The Ninth Circuit held that the doctrine applies only insofar as the contract was entered into in a market determined to be workably competitive at the time, FERC reviewed and approved the contract, and that the challenge came from a purchaser but not a seller.  The Maine PUC decision now joins the robust body of Mobile Sierra case law that requires reversal of the Ninth Circuit.

FERC Blesses Midwest ISO Plan for Resource Adequacy

The Federal Energy Regulatory Commission has conditionally accepted a Midwest Independent Transmission System Operator (Midwest ISO) plan for ensuring long-term resource adequacy in the RTO’s 15-state territory.  Most other RTOs and ISOs have spent years grappling with how to ensure sufficient capacity is available to meet peak demand, and contentious FERC proceedings have led to different market models in NYISO, PJM, and ISO-NE.  FERC directed MISO to develop its own resource adequacy plan after having operated for years without one.   The first planning year under the resource adequac plan will start June 2009.

MISO’s responsibilities under the new plan will include determining capacity obligations, monitoring compliance, and assessing penalties to deficient load servers.  Unlike the PJM, ISO-NE, and NYISO models, the MISO plan does not entail a centralized capacity market, but does require any load server in the Midwest ISO region to maintain access to sufficient planning resources, whether generation or demand response.  

The MISO will set a Planning Reserve Margin for each load server, based on analysis that take into account factors such as generator forced outage rates, generator planned outages, forecast performance of demand resources, and transmission congestion.  The MISO will then require each load-server to demonstrate that it has sufficient resources to meet the forecast requirements plus the applicable Planning Reserve Margin.  FERC directed the MISO to provide more information on how it will establish a Planning Reserve Margin.  However, the state regulators may supersede the MISO's Planning Reserve Margin with a higher or lower Planning Reserve Margin if they choose.  Resource adequacy is a sensitive jurisdictional issue for federal regulators as it overlaps state jurisdiction over retail service.  In recognition of this, FERC acknowledged the contributions of the Organization of Midwest ISO States, which represents regulators from the 15 states in the Midwest ISO footprint.