Energy Legal Blog

Illinois Regulators Buck Governor and Approve Reverse Auction for Power

Following months of acrimony over power procurement and electric retail rates, the Illinois Commerce Commission (ICC) unanimously decided the state’s utilities should use a state-run reverse auction to procure power for consumers that do not choose competitive suppliers.  While the ICC agreed with state utilities Commonwealth Edison and Ameren on the benefits of this procurement method, other state officials, including Gov. Rod Blagojevich, have stridently opposed it.  But their opposition appears to have less to do with the use of an auction than the soon-to-end state-imposed retail rate freeze that has kept rates under market for several years during a transition to deregulation.   The Governor has vowed to continue his opposition.

Reverse auctions have been used successfully in New Jersey and elsewhere.  See New Wholesale Power Procurement Model Emerges: All-Source Auctions.  They entail successive rounds of offers by qualified wholesale power suppliers that drive the price of contracts lower until there is a match between the quantity needed and the supply offered.  The ICC said the auction, covering customers of ComEd and the Ameren companies, would take place in September, for deliveries commencing in January 2007.  To address concerns about market power and lack of competition, the ICC committed to create a market monitor within the agency and test auction results for prudence.  The latter would seem inconsistent with the auction mechanism, but the ICC is trying to stave off further political criticism that it is not doing enough to protect power consumers. 

The ICC concurrently denied ComEd’s request to purchase a quarter of its electricity under five-year contracts, concluding this would raise costs, and instead approved a plan under which all of the utilities will procure power up to a maximum of three years in advance.

New Rules Barring Energy Market Manipulation to Take Effect Soon

FERC has adopted final rules implementing the new sections 4A and 222 of the Natural Gas and Federal Power Acts, respectively, which were added by the Energy Policy Act of 2005 (EPAct 2005) and adopts a scheme pioneered in securities laws for combating fraud.  [Prohibition of Energy Market Manipulation, Order No. 670, (2006)]  The texts of the natural gas and power rules are the same.  See FERC Looks to Past for Future Anti-fraud Enforcement.  These final rules adopt word-for-word the rules as FERC originally proposed them last October 20, with one exception.  The prohibition against engaging in any act, practice or course of business "that operates as a fraud or deceit upon any person" was changed to bar any such act, practice or course of business "that operates a fraud or deceit upon any entity."   This change reflects the scope of the of the new law, which prohibits any entity from engaging in frauds or misrepresentations that affect wholesale energy market transactions subject to FERC's jurisdiction.  Since the relevant statutes exclude municipal power and gas companies from the definition of "person," the originally proposed rules asymmetrically would have penalized munis for their frauds but not the frauds perpetrated on them.  The final rules go into effect as soon as they are published in the Federal Register - probably some day early in February.

In its announcement of the final rules, FERC emphasized that the intent is not to punish negligent practices or corporate mismanagement.  Instead, the rules seek to punish misconduct that is intentional, knowing or reckless.  This distinguishes these anti-fraud rules from FERC's market behavioral rules, which, for the most part, prohibit certain conduct irrespective of the actor's state of mind. Under the new rules, FERC will seek sanctions whenever an entity "(1) uses a fraudulent device, scheme or artifice, or makes a material misrepresentation or a material omission as to which there is a duty [to disclose] under a tariff or FERC ruling, or engages in any act . . . that operates or would operate as a fraud or deceit upon any entity,"  (2) with an intentional, knowing or reckless state of mind, (3) in connection with a natural gas or power purchase or sale or transportation/transmission over which FERC has jurisdiction.  Notably, there is no requirement that the victim rely on the misrepresentation, fraud or deceit or that the victim damage due to the misrepresentation, fraud or deceit.   Sanctions for violations include disgorgement of profits and possible civil penalties.  See Policy Statement on Enforcement of Statutes, Orders, Rules and Regulations.
 
In public comments, critics of the proposed rules objected forcefully to FERC's adoption of the vilification of material omissions from securities laws.  According to these critiques, omitting material information (e.g., potential litigation exposure) in connection with securities sold to the general, non-expert public finds no parallel in wholesale power transactions in which all parties are typically large and sophisticated.  Why make these sophisticated players report all material information, much of which may be proprietary and commercially valuable, they asked.  But FERC rejected these arguments and retained the material omission proscription.  The agency clarified, however, that the final rule creates no new affirmative disclosure rule, and sanctions will be doled out only when there is an affirmative duty under a tariff or other directive to disclose the omitted information.

FERC also clarified that entities alleged to have violated the new antifraud rules will be given an opportunity to counter the allegation before charges are formally brought.   The agency deferred ruling on whether to eliminate its market behavioral rules as redundant or unnecessary in light of its implementation of the antifraud rules. 

Proposed Rule Would End PURPA “Put” in Some Power Markets

Acting on a directive from the Energy Policy Act of 2005 (EPAct 2005), FERC has proposed new regulations that automatically would relieve some utilities of their nearly 30-year old obligation to purchase qualifying facility (QF) power. [New PURPA Section 210(m) Regulations Applicable to Small Power Production and Cogeneration Facilities, 114 FERC ¶ 61,043 (2006)].  Enacted as a provision of the Public Utility Regulatory Policies Act of 1978, the purchase obligation is known as the “PURPA put” because it enabled QFs — both cogenerators and small power producers — to put their output to traditional utilities operating in the vicinity.   EPAct 2005 directed FERC to end the PURPA put in “sufficiently competitive” markets that provide QFs with the ability to deliver their generation to buyers.  To be considered by the agency, public comments on the proposed regulations must be submitted by approximately the end of February. 

FERC would end the QF-purchase mandate generically for utilities operating in the organized markets that have so-called Day 2 markets — MISO, ISO-New England, PJM, and NYISO — because they offer transparent spot markets into which all generators can sell.  Utilities operating in the CAISO or SPP, as well as utilities operating outside of organized markets will have to establish their eligibility on a case-by-case basis.  To ease this burden somewhat, FERC suggests establishing a rebuttable presumption of eligibility for utilities providing nondiscriminatory open-access transmission under an Order No. 888 tariff or a reciprocity tariff.   

In a nod to wind energy advocates and others who harbor concerns that the proposed rule would disadvantage numerous small wind facilities that do not have meaningful market access, the proposed rule seeks comment on whether certain types of QFs should be exempted from the rule and retain their ability to force a sale of their power. 

Illinois Joins States Reducing Mercury Emissions

Earlier this month, Illinois Governor Rod Blagojevich (D) announced he would mandate reductions in mercury emissions from the state's 22 coal-fired power plants by 90 percent by June 30, 2009, joining Connecticut, New Jersey, Maryland, Massachusetts, Minnesota, North Carolina and Wisconsin, in calling for mercury reductions stricter than those called for by the U.S. Environmental Protection Agency in its March 10, 2005 Clean Air Mercury Rule.  The EPA Rule calls for reductions of 47 percent by 2010 and 79 percent by 2018.  Power plants emit approximately 43 percent of mercury emissions in the United States, making power plants the leading man-made source of mercury emissions.

Lauded by environmentalists, Governor Blagojevich's proposal is the most aggressive in the nation: mercury emissions must be reduced by an average of 90 percent by June 30, 2009, and each coal-fired plant is required to reduce emissions by 75 percent by 2009 and by 90 percent by the end of 2012.  Under the Governor's plan, practices that permit plants to get around emissions controls, such as purchasing allowances or trading emissions credits with other companies or states, are prohibited.  The proposal will go before the Illinois Pollution Control Board in February, and if adopted, could become a model for other major coal-producing states considering mercury emissions reductions.  [See Maryland Governor Proposes Plan to Reduce Plant Emissions]

Energy Advisor to Coordinate State Energy Policy in Rhode Island

Rhode Island Governor Donald L. Carcieri (R) issued an executive order in mid-January creating the Office of Chief Energy Advisor to the Governor, and named Andrew Dzykewicz, Senior Project Manger at the Rhode Island Economic Development Corporation (RIEDC), to fill this new role.  Mr. Dzykewicz will be responsible for coordinating tiny Rhode Island's energy policy, and one of the first tasks assigned to the new Advisor is to oversee the enactment of a five-point energy agenda intended to assist in accessing affordable energy supplies and increasing energy conservation.

The Governor's five-point plan includes: 1) increasing natural gas supplies by offering support for regional siting of liquefied natural gas (LNG) terminals under construction in Eastern Canada, which, once up and running will increase the state's supplies and could allow Rhode Island to avoid the need for placement of LNG terminals along Narragansett Bay; 2) assisting FERC in reforming wholesale electricity pricing; 3) assisting low-income state residents to pay energy bills through a state assistance program that would supplement federal assistance; 4) completing a joint State Energy Office-RIEDC project intended to facilitate wind power development; and 5) performing a statewide audit of energy use to identify inefficiencies and to devise strategies to reduce energy consumption.

Grid West Parties, BPA Go Separate Ways

The potential for an independent transmission operator in the Pacific Northwest grew murkier in January, as the two principal factions headed in opposite directions.  On January 10, the remaining members of Grid West released a cost/benefit analysis examining the organization’s continued viability following the decision by the Bonneville Power Administration (BPA) not to participate.  The report touted decreased cost estimates, and, perhaps stating the obvious, determined that BPA's decision not to join will both create operational complexities and at the same time simplify internal procedures.  Hopes are that operations could begin in 2008.

In the meantime, several utilities that are not (or are no longer) members of Grid West announced formal plans to create an alternative to Grid West, which proposes a different path to integrated operation of the region's transmission system.  BPA, Puget Sound Energy, Seattle City Light, and the PUDs of Chelan and Grant Counties are in the process of asking other entities to become shareholders of the organization that would build upon last year's Transmission Integration Group (TIG) proposal.  See Pacific Northwest Grid Restructuring Proposal Fails.  A number of BPA's customers (primarily municipal utilities and public power agencies) that feared Grid West ceded too much control over the grid to an RTO-like organization developed TIG as the alternative to Grid West.  The as-yet-unnamed group plans to meet January 27 in Portland to determine their next step and hammer out a structure for their organization.  The group contends that its plan is intended to complement, but not compete with Grid West.  They hope some type of “seams” agreements could eventually be coordinate the portions of the regional transmission grid controlled by the two groups.

California to Spend $2.9 billion to Promote Solar Power

California is home to some of the best solar energy potential in the U.S. as well as real or threatened energy shortage problems caused by its ever-increasing population.  Putting these two factors together, the California PUC has approved a $2.9 billion incentive program intended to help install up to 3,000 MW of solar power over the next decade.  Financed through increases in gas and electric retail prices, the program will help fund solar projects for residential, public and commercial facilities.  The funds will initially be used for rebates on solar power systems, and subsequently for rebates on solar hot water and solar heating and cooling systems as well.

FERC to Mirant: Keep Power Flowing to Nation's Capital

Finding that a power-supply emergency existed in the Washington, DC area, Secretary of Energy Bodman on December 20 issued an emergency order directing Mirant to continue to operate its Potomac River, 482-MW power plant.  The plant had stopped operations to avoid violating its air quality permit.  Secretary Bodman explained that, absent the Potomac River plant, should either of Potomac Electric Power Company's (Pepco) 230-kV lines become unavailable, power supply to the Capital would be in jeopardy.

Following the Secretary, in a January 9 order FERC ordered PJM Interconnection L.L.C. (PJM) and Pepco to devise a long-term plan to maintain adequate reliability in the Washington, D.C. region, as well as an interim plan to provide adequate reliability pending implementation of a long-term plan.   Due to the fact that PJM's and Pepco's current transmission system has been shown to have a high probability of violating the NERC and PJM reliability standards, FERC directed PJM and Pepco jointly to develop a comprehensive long-term plan to address operation, planning and construction of needed transmission facilities for the region.  PJM and Pepco must file the comprehensive plan with FERC by February 8 and must also jointly submit progress reports to FERC on a monthly basis until the plan has been fully implemented.  Immediately after the issuance of FERC's order, Pepco announced that it already has a plan in the works to build new transmission lines in the area. See Mirant Plant Showdown Prompts Efforts to Expand Transmission in D.C.

Additionally, Pepco recently announced that it would be repairing one of its 230-kV lines sometime this month.  The Department of Energy declined to grant a Virginia Department of Environmental Quality (VDEQ) request to order Pepco to postpone its transmission line repairs until Mirant could put the proper air pollution controls in place at the plant, stating instead through its spokesman that it will address VDEQ's request in a future order.   [District of Columbia Pub. Serv. Comm'n, 114 FERC ¶ 61,017 (2006)]

FERC Approves Increase in CAISO Bid Cap, Examines West-Wide Cap in 206 Proceeding

The California ISO and FERC recently addressed the long-simmering issue of the appropriate level of the CAISO's offer caps.  Those caps are controversial since they are lower than in other parts of the country.  For that reason, many argue that these caps are a barrier to new investment  in much-needed power in the state. 

On January 13 FERC approved the CAISO's request to increase the soft offer cap in its real-time market to $400/MWh, up from a $250/MWh, but rejected its request to transition to a hard bid cap.  A soft cap is the amount above which a seller must justify its prices to FERC; a hard cap would create a non-negotiable cap on prices.  FERC ordered that the soft cap remain in place until the CAISO can implement its market redesign and technology upgrade (the so-called MRTU process), which is scheduled to occur in 2007.  FERC also responded to concerns raised by western market participants that raising the offer cap in the CAISO alone, while the rest of the west maintains a lower $250 cap, could create significant problems for the west in attracting imbalance energy, particularly if fuel costs increase.  FERC instituted an investigation into whether it should raise the real-time spot market offer caps across the WECC to $400/MWh. [California Independent System Operator 114 FERC ¶ 61,026 (2006)]

Calpine & California Halt FERC Litigation, but MISO Threatens to Dump Calpine

Calpine Corp. and California January 12 jointly asked FERC and the agency agreed to suspend proceedings on California' complaint against Calpine.    This followed the decision by the U.S. District Court for the Southern District of New York to take jurisdiction over the dispute, which has been brewing in the bankruptcy court for some time.  The district court scheduled a hearing in late January to determine whether to allow bankrupt Calpine to reject the contracts. 

The move by the district court to take jurisdiction may signal its agreement with FERC's interim guidance offered in a January 3 order in which FERC concluded that it lacked the jurisdiction to order a supplier in bankruptcy to continue selling power pursuant to a power supply contract.  The agency went on to opine that district courts should analyze such contracts to determine whether rejection of such contracts would be in the "public interest" and offered "interim guidance" on when continued performance under the contracts would satisfy that standard.

On a related note, the Midwest Independent Transmission System Operator (MISO) asked the bankruptcy court to reconsider a December 21 decision that would allow Calpine to participate in its market while providing only minimal credit and collateral assurances.  The bankruptcy court's December 21 interim order would permit Calpine to submit a deposit equal to two weeks of utility service.  MISO argued this amount is inadequate and unfairly shifts the risk of a possible default on other MISO participants.  According to MISO, this risk is substantial in light of Calpine's recent trading practices, which consist of buying and selling in the day-ahead and real-time energy markets and involve substantially greater risks.  This could also result in MISO having to extend millions of dollars in unsecured credit to Calpine, a result it argued is illegal under both the bankruptcy code and the Federal Power Act.  If the bankruptcy court chooses not to increase the amount of required collateral, MISO argued it has the absolute right to terminate service to Calpine.  [See FERC Purports to Advise Bankruptcy Court on Debtor Contract Rejection]

FERC Purports to Advise Bankruptcy Court on Debtor Contract Rejection

In the latest chapter in an ongoing jurisdictional struggle between FERC and U.S. bankruptcy courts, on January 3, FERC issued an order providing some interim guidance as to which power supply contracts companies filing for bankruptcy protection must continue to honor.  The proceeding involves Calpine Corporation, which filed for bankruptcy under Chapter 11 on December 21, 2005 in the Southern District of New York.  Just before Calpine's filing, on December 19, the California Electricity Oversight Board, California Attorney General Bill Lockyer, and the California Department of Water Resources (DWR) (collectively, California petitioners) petitioned FERC, asking the Commission to direct Calpine to continue to supply power under an existing contract.  In its bankruptcy petition, however, Calpine requested that the bankruptcy court dissolve the power supply contract at issue, explaining that providing power under its contracts at below-market rates was exacerbating its insolvency.

In its January 3 order, FERC ruled that it could not order Calpine to continue selling power to California under the contract since the bankruptcy court had already issued a temporary restraining order prohibiting FERC from doing so.  FERC went on to offer some guidance on the circumstances in which companies declaring bankruptcy must continue to perform under power supply agreements.  Both the California petitioners and FERC invoked a June 2003 order, Blumenthal v. NRG Power Marketing, Inc., in which FERC held that a bankruptcy court may not reject a FERC-jurisdictional contract without the seller first obtaining FERC's permission to terminate that contract.  Following FERC's NRG order, however, a U.S. Appeals Court reached the opposite conclusion in Mirant Corp. v. Potomac Electric Power Co. (In re Mirant).  In Mirant, the Fifth Circuit held that the Federal Power Act does not prevent a debtor from rejecting a FERC-jurisdictional contract, even though the rejection may indirectly impact filed rates.  In the January 3 order, FERC stated that it intends to follow the authority of the Mirant decision, thus tying the agency's hands to prevent rejection of an executory power sales contract.  In a further discussion of dubious authority, FERC cautioned that a bankruptcy court may not reject such a contract without carefully scrutinizing the impact upon the "public interest," including whether rejecting the contract would disrupt power supplies. 

FERC then asked parties for comments on whether the rejection of the Calpine/DWR contract would result in such a disruption.  In doing so, FERC emphasized it was not attempting to supplant the bankruptcy court's role in determining whether to permit Calpine to reject its DWR contract at issue.  Rather, FERC ventured that the court would "welcome" FERC's input and participation in the process.  By soliciting party comments, FERC claimed on to be building a record to inform its later advice the bankruptcy court.  FERC directed the California petitioners to amend their petition within 15 days of the order to take into account Mirant, and then directed interested parties to intervene and comment within 15 days following the filing of the amended petition.  [California Electricity Oversight Board, et al., v. Calpine Energy Services, L.P., et al., 114 FERC ¶ 61,003 (2006) ]

Order No. 669 Puts Flesh on FERC's Expanded Merger Review

FERC has issued new rules implementing its revised authority to review mergers and acquisitions.  The Energy Policy Act of 2005 (EPAct 2005) raised the transaction value that triggers FERC review from $50,000 to $10 million.  At the same time, the new law extended FERC's authority to more types of transactions, such as transactions involving generation facilities and certain public utility holding company transactions.  In addition, EPAct 2005 extends FERC's review authority to purchases of jurisdictional facilities, whereas previously it reached only sales.  EPAct 2005 required FERC to adopt by rule procedures to consider expeditiously applications for Section 203 approval.  FERC's rule, contained in Order No. 669, fulfills this statutory mandate. 

The new rule grants numerous blanket authorizations for mergers, including acquisitions of foreign utility companies, intra-company cash management and financing, acquisitions of local distribution companies or other retail facilities (traditionally subject to state commission oversight), and acquisitions of nonvoting stock and voting stock up to 9.9% of a company.  FERC declined, however, to grant a blanket authorization for holding company acquisitions of qualifying facilities under PURPA or exempt wholesale generators under PUHCA.   

While EPAct 2005 specified a $10 million minimum for triggering FERC review, the new law did not prescribe how to value a transaction.  Though FERC and industry participants agreed that market value should be the standard, they differed over how to apply this standard.  For example, there were divergent views on how to determine market value in transactions between affiliates or where assets are sold in a bundle without the value of FERC-jurisdictional assets being determined separately.  The final rule provides a rebuttable presumption that market value equals the transaction price.  For facilities transactions between affiliated companies, value equals original cost depreciated, or original book cost, whichever is appropriate.  For transactions involving contracts between affiliated companies, value means the total expected nominal contract revenues over the remaining life of the contract.  FERC also provided a formula for determining the value of securities transactions between affiliated companies where the securities are not widely traded. 

EPAct 2005 requires  FERC to complete its review of proposed transactions within 180 days, or the application will be considered granted.  FERC's rule provides for expedited review for certain categories of proposed transactions, including dispositions of transmission facilities, especially those that remain under the functional control of an RTO or ISO when the transaction is completed, as well as acquisitions of foreign utilities companies by holding companies with no captive U.S. customers.   

FERC plans to hold a technical conference within one year of February 8, the effective date, to see how the new regulations are working and to evaluate issues raised by the repeal of PUHCA.  [Transactions Subject to FPA Section 203, 113 FERC ¶ 61,315 (2005) (Order 669)]

IRS Initiates Renewables Subsidy Program for Non-Profit Utilities

Implementing a new renewable energy incentive from the Energy Policy Act of 2005 (2005 EPAct), the Internal Revenue Service (IRS) has issued a notice soliciting participation in a tax credit bond program that will allow units of government, municipal utilities, rural electric cooperatives, and Tribal governments to finance, through bonds, capital expenditures for certain renewable resource facilities.    

Previously, production tax credits (PTCs) for renewable energy production have been made available only to tax-paying entities such as corporations.  In the 2005 EPAct, however, Congress created a mechanism, equivalent to the PTCs, for non-profit utilities.  The initiative would allow qualifying entities to issue "Clean Renewable Energy Bonds" (CREBs) to finance projects that would qualify for PTCs were they sponsored by private entities.  CREBs do not pay interest; instead bondholders will receive tax credits.  The 2005 EPAct designated up to $800 million for the CREB program, of which no more than $500 million may be allocated to governmental entities such as public power systems.  All CREBs must be issued during 2006 and 2007.  In early 2006, the IRS, together with the Treasury Department, plans to issue temporary rules for the CREB program.  Initially, the IRS plans to allow CREBs on a project-by-project basis to "qualified projects" that apply to the IRS by April 26, 2006, and meet all the requirements contained in the IRS notice.   

The IRS notice solicits applications for allocations of the bonds and provides initial guidance on required criteria for eligibility for the program.  Applicants for CREBs must show that the project to be financed is one of the "qualified projects" eligible for funding: a wind facility, a closed- or open-loop biomass facility, a geothermal or solar energy facility, a small irrigation power facility, a landfill gas facility, a trash-combustion facility, a refined coal production facility, or a qualified hydropower facility.  Applicants must also describe the project's financing plan and specify the dollar amount of the CREB funding requested.  CREBs will be allocated starting with the smallest dollar amount requested and increasing until the limit of $800 million is reached.  The IRS notice also provides guidance on the methodology the Treasury Department will use to allocate the funds, set the credit rate, and determine maximum term and information reporting requirements applicable to CREBs.