Energy Legal Blog

Alliance Starts Site Selection for Zero-Emissions Coal Plant

The coal and electric utility industries in the FutureGen Alliance have started selecting a site for the state-of-the-art FutureGen project, a coal-fired, zero-emissions power plant the Alliance will build in cooperation with the U.S. Government.  If successful, the project may devise ways of harnessing abundant U.S. and world coal reserves without exacerbating the world’s increasingly worrisome dynamic of greenhouse gas emissions overheating the global climate.  

Members of the Alliance include two large U.S. utilities, American Electric Power and Southern Company, as well as BHP Billiton, the China Huaneng Group, CONSOL Energy Inc., Foundation Coal, Kennecott Energy, and Peabody Energy.  They will pay a portion of the plant's costs, while the U.S. government, acting through the DOE, will fund the balance.  The Alliance has announced it will issue a request for proposals in March 2006 for selection of the site for the project.  A draft RFP is already available.  Candidate sites will be evaluated based on technical, environmental, regulatory and financial criteria.  In addition to possessing the usual attributes that are keys to successful power plant siting, such as the availability of water, transmission, and fuel delivery, potential sites must be in an area where the geology is amenable to sequestration of carbon dioxide for permanent storage.  The Alliance expects to select a site by late 2007.  With lengthy periods expected for permitting and construction, the plant is unlikely to be operational before 2012. 

The DOE will serve as lead agency in preparing an environmental impact statement (EIS), pursuant to the National Environmental Policy Act (NEPA), to determine which of the candidate sites are acceptable from an environmental impact perspective.  Comments related to the NEPA process are due to DOE by March 20, 2006.  

CAISO Submits Long-Awaited MRTU Tariff

After seemingly endless delays, the California Independent System Operator ("CAISO") on February 9, 2006, finally submitted to FERC its long-promised market redesign and technology upgrade ("MRTU") tariff.  Originally proposed in 2002 in response to FERC findings that the California markets were dysfunctional, the CAISO undertook to redesign its markets and software.  The CAISO itself acknowledges the MRTU tariff remains incomplete; before the MRTU system can come on-line, the CAISO will have more work to do, including developing business practices and determining the appropriate methodologies for designating resources needed to meet day-ahead procurement targets, releasing post-day ahead resource adequacy capacity, and allocating CRRs to merchant transmission projects.  Comments on the tariff are due March 27, 2006, with reply comments due April 17. 

The CAISO's new tariff includes several prominent changes to its market design and market mitigation, including the implementation of a day-ahead market, an hour-ahead scheduling process, and a real-time market that uses locational marginal pricing ("LMP") and security-constrained unit commitment to dispatch resources and manage congestion.

In its filing, the CAISO extols the virtues of LMP, claiming its version of LMP is similar to the system in place in other of the country's organized markets.  The CAISO also claims it does not expect prices to rise as a result of LMP.  For the most part, MRTU will settle charges on an aggregated basis with three load aggregation points ("LAPs"), which correspond to the territories of California's three investor-owned utilities.  However, certain transactions (such as those involving pump loads, exports, metered sub-systems, existing transmission contracts, and transmission ownership rights) will be scheduled and settled on a more "granular" level – i.e., on the basis of nodes that will often be confined to an area smaller than an LAP.  MRTU will also implement congestion revenue rights ("CRRs") to help customers hedge congestion costs.  On the contentious issue of how to allocate such rights, the CAISO proposes to allocate CRRs first to California's load-serving entities ("LSEs"), who, the CAISO reasons, helped pay for the transmission system.  Any remaining CRRs will be auctioned off to all creditworthy parties.  Entities serving load outside of California may obtain CRRs by pre-paying certain wheeling charges. 

MRTU will implement a residual unit commitment ("RUC") process that should help ensure reliability by allowing the CAISO grid operator to secure on a day-ahead basis incremental capacity it forecasts it will need in real-time.  The CAISO hopes for the RUC process to work in concert with the California Public Utilities Commission's ("CPUC's") resource adequacy program.  The CAISO will also undertake to perform local capacity studies to assess the amount of capacity needed in transmission-constrained areas.  It will procure capacity to make up for any shortfalls and allocate the costs to any LSEs that fail to maintain sufficient reserves.

In addition to redesigning its market, the MRTU proposal adds several market power mitigation provisions, based on similar measures in PJM.  The filing includes an initial $500/MWh cap for energy bids, with a plan to raise the cap to $1000/MWh over the next two years in increments of $250/MWh.  The CAISO also proposes to implement a $250/MWh cap for ancillary services and RUC availability bids.  The MRTU proposal would also revise the vexatious must-offer obligation so that only those units whose capacity is needed to meet a utility's resource adequacy requirements would be required to offer their capacity into the CAISO's markets.

The CAISO is aiming for MRTU to become effective in November 2007.  In order for its software vendors to have sufficient time to develop appropriate software, the CAISO thus asked FERC to approve the MRTU tariff by this June, without holding any hearings or requiring any changes.

New Mexico Renewable Energy Transmission Authority Bill Dead for Now

Companion House and Senate bills to create a new quasi-agency to plan and finance interstate transmission lines did not survive a filibuster mounted by New Mexico's Republican leaders at the end of the legislative session.  Proposed by Governor Bill Richardson, the new agency would have issued state bonds to finance transmission line construction, exercised the power of eminent domain to obtain rights of way for transmission corridors, and entered into leases with utilities to operate the new transmission lines.  This transmission expansion would proceed in tandem with the goal of building more wind and solar power generation that, using the new transmission lines, could be exported to surrounding states with renewable portfolio standards, such as Arizona, California and Colorado.   

The measure's supporters justified creating the new agency on the ground that it was needed to fill the transmission void in federal programs.  In particular, they pointed to the fact that FERC's transmission pricing policy that is intended to spur transmission investments has bogged down amidst opposition from state regulators and consumer groups.  They also doubt that FERC's backstop authority to approve transmission siting will, on its own, spur new transmission construction.  They further note that DOE's new authority under the Energy Policy Act of 2005 (EPAct 2005) to help finance new transmission lines in the West and Southwest applies only to constrained areas and would not ensure that renewable energy would benefit from the new lines. 

Rule Permitting Challenges to Operational Audits Finalized

In Order No. 675, FERC finalized its revised rules on challenges to its operational audits.  Last October, FERC proposed to allow regulated companies to challenge not only financial audits, but also operational audits, [See Rulemaking to Establish Procedures for Challenging FERC Operational Audits], which include reviews of compliance with standards under the Federal Power Act, as well as audits conducted under the Natural Gas Act and the Interstate Commerce Act.  FERC proposed to allow the subject of the audit to choose whether to challenge the audit in a shortened procedure or to request a trial type hearing.  The final rule takes effect March 29, 2006.   

The final rule makes only slight changes to the initial proposal.  One adjustment permits entities subject to operational audits to change their choice of a shortened procedure to a trial-type hearing if an interested party raises a new issue during the course of the procedures.  Also, FERC clarified that the final rule will not apply to audits or compliance reviews conducted by an Electric Reliability Organization (ERO), nor to audits conducted by FERC under its ERO rules, though this latter exception may change once FERC approves an ERO, which it is expected to do later this year.  In addition, an audited entity may target its challenge to the audit finding of a violation, the remedy FERC selects, or both.  Audited companies have 30 days from when they receive notice of the audit to inform FERC as to whether they have chosen the shortened procedure or the trial-type hearing.

FERC Jettisons "Legitimate Business Purpose;" Retains Other Rules for Natural Gas & Power Wholesalers

In Order Nos. 673 and 674, FERC has eliminated from natural gas wholesaler codes of conduct and from electric power wholesaler market behavioral rules (MBRs) a controversial provision that prohibited these natural gas and power merchants "from engaging in actions that are without a legitimate business purpose and that are intended to or foreseeably could manipulate market prices, market conditions, or market rules" for natural gas, electric energy or electricity products.  Also eliminated is an MBR prohibiting collusion with others to manipulate market prices, conditions or rules.  These eliminations are effective upon publication in the Federal Register, likely to occur the last week of February or the first week of March. 

The "legitimate business purpose" requirement, which had been challenged in court as unlawfully vague, is replaced by an anti-fraud rule that FERC recently adopted to implement 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 adopt a scheme pioneered in securities laws for combating fraud.  [Prohibition of Energy Market Manipulation, Order No. 670, (2006)]  The new rule makes it unlawful for any "entity, directly or indirectly (1) to use or employ any device, scheme, or artifice to defraud, (2) to make any untrue statement of material fact or to omit to state a material fact" needed to make a statement "not misleading, or (3) to engage in any act, practice, or course of business that operates . . . a fraud or deceit . . . in connection with purchase or sale of" natural gas or electricity or the purchase or sale of transmission or transportation subject to FERC's jurisdiction.   

In addition to mooting the pending legal challenge, replacing the "legitimate business purpose" requirement with the new anti-fraud rule is significant in two other important respects.  First, since it is based on longstanding anti-fraud rules under the Securities Exchange Act, the new anti-fraud rule not only articulates a clearer standard, but it is also informed by a body of decisional precedents that illustrate and clarify how it should be applied.  Second, it replaces culpability based on "intended to or foreseeably could manipulate" with culpability based on scienter ― a showing of intent to defraud or deceive.  This should prevent a natural gas or electric power wholesaler from being prosecuted for actions that are simply short-sighted. 

Will Capacity Settlement Tear NEPOOL Apart?

After a pile-on of pleadings, a hearing, months of settlement talks, most parties have agreed on a settlement regarding ISO-New England's controversial locational installed capacity model (LICAP).  While Connecticut led the opposition to LICAP, now it's Maine that fiercely opposes the settlement and has threatened to withdraw from NEPOOL to spare its citizens what it considers excessive costs under the settlement.  

Development of capacity markets has led to tension between regions and market participants based on perceptions of capacity gluts or shortages, prices being too low or high, the level of the reserve margin to be procured, the creation of distinct capacity regions, and other issues.  [See No Consensus on Securing Long-term Generation Adequacy.]  There appears to be a growing awareness that capacity development and procurement must take into account the deliverability of energy from a capacity resource.  This in turn would provide for higher capacity payments to generators in constrained areas.  Connecticut authorities balked at this outcome and instead steadfastly insisted that the rest of New England subsidize supplying it with imported energy.

The current settlement agreement has yet to be filed at FERC.  Its outlines include dropping LICAP in place of a forward procurement market that would be implemented through competitive auctions.  During a transitional period of several years, generators would receive capacity payments to help cover their costs.  Overall, this plan is to cost consumers less, but some state officials remain unhappy, particularly those in Maine.  Its industrial customers already feel the brunt of higher energy costs, and fear greater price increases.  Withdrawal from NEPOOL may be an option: the Maine legislature's Utilities and Energy Committee has even held hearings on a bill that would allow the state's regulators to order utilities to leave the power pool.  A major energy marketer testified in opposition to the bill, urging lawmakers to not cast the blame for high energy prices on ISO-NE, which administers the energy markets and transmission in the NEPOOL region.  Other concerns include numerous administrative, operating, legal and market issues that would require resolution were Maine utilities to withdraw.    

Meanwhile, on the federal front, a FERC judge who shepherded the settlement has scheduled meetings with the parties to try to resolve these differences before ISO-NE files a revised capacity plan at FERC.  [FERC Docket ER03-563]

FERC Issues First No-Action Letter

On January 31, 2006, FERC issued the first of its new "no-action letters" to Cinergy Corp.  FERC announced it would begin issuing no action letters to entities requesting them in an interpretive order last November.  [See With Heightened Enforcement Threatened Against Objectionable Natural Gas & Power Transactions, FERC to Offer Industry Guidance in the Form of 'No-Action' Letters.]  Given FERC's new enforcement authority and its increased emphasis on enforcement, FERC borrowed a page from the Securities and Exchange Commission and Commodities Futures Trading Commission and adopted a no-action letter process.  No-action letters allow industry participants to request FERC's enforcement Staff for assurance that a particular action will not result in an enforcement action.  The process also allows Staff to give companies "informal, advance" advice on their activities.

In its December request, Cinergy asked FERC to issue a no-action letter in response to its proposal for two of its affiliated utilities, Cincinnati Gas & Electric ("CG&E") and Union Light, Heat & Power Company ("ULH&P"), to share certain employees and jointly purchase non-power goods and services.  CG&E is in the process of transferring certain generating facilities to ULH&P, and Cinergy requested that the two companies be allowed to share employees at certain of the units and make certain joint purchases without violating FERC's Code of Conduct.  FERC Staff agreed, assuring Cinergy it would not implement an enforcement action based on these actions.  The letter gave FERC an opportunity to shed some light on how Staff intends to respond to these requests.  It also illustrated a quick response time, with Staff issuing the no-action letter about a month after Cinergy's request.  This should give industry participants some hope that FERC is committed to the no-action letter process and intends to turn such requests around in a timely fashion.

FERC's website offers more information on how to request no-action letters.

Retail Competition Reported to Benefit Texans

The Public Utilities Commission of Texas (PUCT) released a report on February 2, 2006, detailing to the state legislature the benefits of retail competition in the state.  The Texas House of Representatives asked the PUCT in December 2005 for an "apples to apples" comparison of what prices are now, given retail competition, and what they would have been under regulation.  The PUCT concluded that rates are substantially lower four years after switching to a competitive retail market.  Specifically, the PUCT estimated that customers in the Houston and Dallas areas would have saved $1450 and $800 respectively by switching annually to the lowest cost provider.  The report also emphasized other benefits of competition, including a variety of service and pricing options and mechanisms for encouraging renewable and efficient energy. 

The Texas House had also asked about the impact of the sale of Texas Genco, first in 2004 from CenterPoint Energy to a consortium of new owners for $3.65 billion and again in 2005 to NRG Energy for $8.3 billion.  Despite this dramatic increase in value in a relatively short period of time, the PUCT found the sales would not negatively affect Texas electricity markets or Texas retail rates because NRG did not own any other generating assets in ERCOT and therefore lacked market power and the ability to elevate market prices.  Finally, the PUCT report responded to consumer advocate claims that retail competition has resulted in higher prices as opposed to several selected cooperative and municipal utilities' prices.  The report argued it was inapt to compare utilities that had adopted retail competition with those that had not, pointing out that many utilities had started out with different rates and that the Senate bill deregulating rates had included a rate freeze that prevented many regulated investor-owned utilities from changing their rates.

Rule Narrows Universe of Qualifying Facilities, Widens Ownership

In a final rule issued February 2, FERC largely adopted its earlier proposed rulemaking implementing the Energy Policy Act of 2005’s (EPAct 2005) significant scaling back of the 1978 qualifying facility (QF) program of the Public Utility Regulatory Policy Act (PURPA).  As reported in an earlier entry, [Long-Term Transmission Rights Proposed for Organized Markets] FERC already has adopted a rule implementing EPAct 2005’s biggest change to the nearly 30-year-old QF program — prospectively terminating in organized electricity markets the mandatory purchase or "PURPA Put," which empowered qualifying cogenerators and small power producers to force traditional electric utilities to buy their electrical output at attractive, avoided-cost prices.  The February 2 rule further tightens the eligibility requirements for future cogenerator QFs, reduces the benefits accessible to QFs, and eliminates the prohibition against an electric utility owning more than 50 percent of existing and future QFs.

In addition to the now largely defunct PURPA Put, an important benefit of being a QF has been exemption from various state and federal regulatory laws.  For new (but not existing) QF contracts, the new rule eliminates one of the most valuable exemptions that removed QFs from price regulation under the statutory just and reasonable requirement of the Federal Power Act.  Going forward, QF contracts for cogeneration and small power production facilities of greater than 20 megawatts will be subject to price regulation, albeit probably pursuant to market-based rate schedules.   QFs retain their exemption of regulation as electric utilities under the new Public Utility Holding Company Act of 2005, but will be subject to the new market transparency and anti-fraud provisions that EPAct 2005 added to the Federal Power Act.

In order to qualify as a QF, PURPA required that the thermal energy that a cogenerator produces in tandem with electricity be "useful."  FERC implemented that requirement by simply presuming that the thermal output of a cogenerator was useful and making that presumption irrebuttable.  Much  to the consternation of utilities forced to by cogenerated electricity, this irrebuttable presumption, on occasion, countenanced thermal applications that were plainly not useful, such as distilling water only to dispose of the distilled water.  Responding to complaints that these thermal applications were a "sham," Congress directed in EPAct 2005 that FERC change its QF eligibility rules to require that a cogenerator’s thermal energy output be "productive and beneficial" and that its electrical, chemical and thermal output be used "fundamentally" for "industrial, commercial or institutional purposes" and not "fundamentally" to make electricity sales to an electric utility.   The February 2 rule adopts this language verbatim and requires and will require that an applicant for status as a cogenerator QF prove both that its thermal energy is productive and beneficial and that all of its ouput is fundamentally for purposes other than making electricity sales to an electric utility.  

Importantly, FERC clarified that residential uses are subsumed within permissible "institutional" purposes, and rejected the demand of the Edison Electric Institute that formal economic and financial reports support any finding that thermal energy is productive and beneficial.   Also importantly, FERC instructed that thermal uses that were irrebuttably presumed useful under the old rule will be presumed rebuttably to be productive and beneficial under the new rule.  And once certified as a QF cogenerator, the owner will not lose that status even if the economics of its thermal energy output later reverse.  Cogenerators with 5 megawatts or less are also rebuttably presumed productive and beneficial.

 With regard to the new fundamental-use requirement, the February 2 rule adopts a straightforward safe harbor:  If 50 percent of the aggregated annual energy output of a facility is used industrially, commercially or institutionally and not sold to an electric utility, then the fundamental-use requirement will be presumed irrebuttably to be satisfied.   And again, cogenerators with less than 5megawatts or less are rebuttably presumed to satisfy this new requirement.

Pre-existing efficiency standards for oil- and gas-fired cogenerators are unchanged in the new rule, and FERC rejected demands that it establish efficiency standards for coal-fired cogenerators.  Also retained is the existing practice by which both cogenerator and small power QFs can self-certify and self-recertify.  The only difference is that such self-certifications will be publicly noticed in the federal register and can be challenged by the public or by FERC on it own initiative.

DOE Congestion Study to Identify National Interest Electric Transmission Corridors

In response to a Energy Policy Act of 2005 (EPAct 2005) directive that the Department of Energy (DOE) report on electric transmission congestion nationwide (congestion study), DOE has issued a Notice of Inquiry (NOI) seeking advise on how to proceed.  So begins a process with the hoped-for result of catalyzing the construction of transmission facilities in areas desperately in need of enhanced transfer capability.  Public comments in response to the NOI are due March 6, 2006. 

The congestion study will inventory geographic areas where significant congestion exists.  DOE will publish the congestion study by August 8, 2006, and seek further public comment at that time.  As the follow-up report may include designations of geographic areas with transmission capacity constraints or congestion adversely affecting consumers as "national interest electric transmission corridors" (NIETCs) [See Congress Enacts Energy Bill and Energy Policy Act of 2005 Hands FERC a Long To-Do List], comments on the study may propose potential NIETCs.  DOE will then evaluate those potential NIETCs based on certain criteria, some of which DOE has identified and offered for comment, including whether there is a "clear need" to remedy reliability problems, and whether NIETC designation would enhance U.S. energy independence.   

Designation as a NIETC will open the door for FERC to issue permits for construction of electric transmission facilities in the NIETC.  Prerequisite to issuing such a permit, FERC must determine that a proposed transmission project will serve the public interest and that the state where it would be located cannot or will not issue a permit.  The next milestone in this process will be selection of the criteria used to evaluate NIETC nominations – the result of which will affect both the scope and success of the NIETC initiative.

FERC Rule Allows Regional Entities to Propose and Enforce Reliability Standards

FERC has satisfied another major mandate of the Energy Policy Act of 2005 by issuing final rules that pave the way for certification of an Electric Reliability Organization ("ERO") as well as the establishment of mandatory electric reliability standards.  Notably the rule condones more regional flexibility than FERC originally envisioned [See Rules Concerning Certification of the Electric Reliability Organization; and Procedures for the Establishment, Approval, and Enforcement of Electric Reliability Standards]; Regional Entities are allowed both to propose reliability standards and to enforce (under ERO and FERC supervision) those standards that are adopted.  The rule, styled Order No. 672, establishes: 

• Credentials required of an ERO;
• Procedures for the ERO to propose new or modified reliability standards for FERC review (FERC will evaluate the standards on whether they are just, reasonable, not unduly discriminatory or preferential, and in the public interest);
• Funding of the ERO;
• Directions for enforcing adopted reliability standards;
• ERO authority to delegate to a Regional Entity the authority to propose and enforce reliability standards;
• An ERO and Regional Entity audit programs to ensure compliance with the reliability standards;
• Periodic ERO reports assessing the reliability and adequacy of the bulk power system; and
• Procedures for establishing regional advisory bodies. 

As expected, the North American Electric Reliability Council will soon apply to FERC to be designated as the ERO.  The application must be delivered to FERC by April 3, 2006.  FERC noted in the Final Rule that it plans to provide adequate time for industry participants to transition from the current regime of voluntary reliability standards to the new ERO world of mandatory and enforceable reliability standards.  [Rules Concerning Certification of the Electric Reliability Organization; and Procedures for the Establishment, Approval, and Enforcement of Electric Reliability Standards, 114 FERC ¶ 61,104 (2006)]

Long-Term Transmission Rights Proposed for Organized Markets

Responding to yet another directive of the Energy Policy Act of 2005 (EPAct 2005), FERC has proposed a new rule requiring transmission organizations with organized electricity markets to make available to load servers long-term firm transmission rights (FTRs) that satisfy certain guidelines.  FTRs have been valuable tools for all participants in organized power markets, particularly those that use locational marginal pricing.  In light of a Congressional mandate that favors load servers, it remains to be seen how FERC will accommodate the needs of non-load servers, such as independent generators or marketers, to hedge against the costs of transmission congestion.  Comments on the proposed rule are due March 13 and reply comments on March 27.

To date most of the FTR instruments available for hedging congestion risks have been no longer than one-year in duration.  Certain load servers and other parties had complained that the lack of long-term FTRs in organized electric markets precluded hedging the financial risks created by transmission congestion.  In EPAct 2005, Congress responded to these complaints by ordering FERC to allow load servers to "secure [FTRs] (or equivalent tradable or financial rights) on a long term basis for long term power supply arrangements . . . ."  Congress directed FERC to make these longer-term FTRs available within one year of EPAct 2005's passage.

In response, FERC has initiated a rulemaking that would require transmission organizations with organized electric markets ― currently, NYISO, ISO-NE, PJM, MISO and CAISO ― either to propose tariff changes giving load-servers these FTRs or explain how they already makes such rights available.  FERC proposes eight guidelines for designing and administering long-term FTRs.  Specifically, FTRs should

·         be point-to-point with a specific source, sink and MW-size;

·         hedge against locational-marginal pricing congestion charges, and remain unmodified during their term;

·         be allocated to those who pay for upgrades that create them;

·         be long enough to hedge long-term power supply arrangements made or planned to satisfy a retail service obligation;

·         afford a priority to load servers with long-term power supply arrangements to meet a retail service obligation;

·         be re-assignable to another entity that succeeds to a retail service obligation;

·         not require participation in an auction for their initial allocation; and

·         be allocated initially in a manner that minimizes economic distortions between those who receive and those who do not receive the FTRs. 

The affected organized markets will have to submit their responses to FERC no later than six months after the rule is finalized. [Long-Term Firm Transmission Rights in Organized Electricity Markets, 114 FERC ¶ 61,097 (2006)]

Consumers Energy Green Power Surcharge Suffers Setback

A Michigan Court of Appeals has denied Consumers Energy the ability to impose a surcharge on all of its customers to finance green power projects to which only some customers had subscribed.  Last May the Michigan Public Service Commission (PSC) authorized the surcharge of 5 cents per meter, which would amount to approximately $1 million annually.  Consumers Energy had been using the revenues from the surcharge to fund its expanded renewable energy program, under which about 850 customers had enrolled, agreeing to pay approximately 10% more for green power than they would otherwise be invoiced by the power company.  Michigan's attorney general appealed the PSC's authorization, arguing that the PSC lacked the right to authorize Consumers Energy to force all of its customers to pay a premium for green energy when only some had agreed to do so. 

Re-Regulation Moves Forward Quietly

In the midst of a rushed close to Congress, a morass of media coverage concerning the war in Iraq, exploding lobbying scandals in D.C., and the coming holiday season, on December 14th the House of Representatives quietly passed a bill that may substantially impact energy markets.  The legislation, H.R. 4473, is usually described as legislation to reauthorize the Commodity Future Trading Commission (CFTC), but in reality it represents much more than an extension of the status quo.

H.R. 4473 includes a number of measures that should be controversial.  The language of the legislation would broaden the CFTC’s authority to supervise natural gas trades, enhance its responsibilities to investigate potential fraud or price manipulation, and could expand the CFTC's authority to conduct surveillance over all futures contracts.  These details have led many experts to criticize the legislation.  Federal Reserve Chairman Alan Greenspan, CFTC Commissioner Sharon Brown-Hruska, and a variety of trade associations representing commodity traders all have expressed serious concerns about the language of the bill.

Given this opposition, one would think that there must have been a significant political coalition formed to pass H.R. 4473 in the House.  That is not the case.  H.R. 4473 was sponsored by one member of the House, Robert Goodlatte (R-VA), had no cosponsors, was not the subject of any committee hearings or reports, and was passed on the floor of the House by voice vote on December 14th.  The process used to pass the bill, referred to as passing a bill "on suspension," guarantees that no legislators are individually accountable for legislation because there is no recorded vote.

Unless constituents and industry leaders force Congress to change their approach towards energy issues, it may be the case that re-regulation of energy markets occurs with a whimper, rather than a bang.  Whether one supports or opposes deregulation of energy markets, it is fair to demand that Congress confront the issue in a transparent and accountable manner.

What the Regulator Giveth, Only the Regulator May Taketh Away

A federal judge ruled January 27 that FERC has exclusive jurisdiction over power supply contracts between Calpine Corp. and several California utilities.  Because they are underwater, these contracts have been tied up in Calpine's bankruptcy.  Although an immediate victory for the California utilities, by reinforcing the primacy of regulatory jurisdiction properly granted by the legislature, the court’s decision should also buttress supplier contracts that California utilities and the state have sought to abrogate in recent years, including large multi-year purchases that California Department of Water Resources (CDWR) made at the end of the 2000-2001 western energy crisis.

Following an order of  a Fifth Circuit US Court  of Appeals decision (Mirant v. Potomac Electric Power Co.), FERC found on January 3 that it did not have jurisdiction under the Federal Power Act to order a party in bankruptcy to continue performing under a power supply contract.  See FERC Purports to Advise Bankruptcy Court on Debtor Contract Rejection.  But Judge Richard Casey, of the U.S. District Court for the Southern District of New York, rejected Mirant and FERC’s reliance on it.  He held that FERC cannot cede its authority to the courts.  According to Judge Casey, the bankruptcy court cannot exercise its authority to interfere with the jurisdiction of a federal agency acting within its properly delegated regulatory capacity, and nothing in the Bankruptcy Code prohibits FERC from exercising its jurisdiction over the contracts.  Thus, Calpine cannot achieve in bankruptcy court what it could not otherwise achieve without FERC approval:  "ceas[ing] performance under the rates, terms, and conditions of filed rate wholesale energy contracts in the hopes of getting a better deal."  Judge Casey added, "what FERC giveth, only FERC may taketh away."  The court also vacated a temporary restraining order that prohibited FERC from ordering Calpine to continue performance of the contracts.

The decision is a victory — at least for now — for the California utilities who sought to have the Calpine contracts affirmed and had looked to FERC to decide the issue.   But what goes around, comes around.  This decision should also become authority for rejecting the California utilities’ and the state’s ongoing efforts to get out of the power supply contracts that the state, through CDWR, entered in 2000 and 2001.

State Ballot Initiative to Boost Renewable Energy in Washington

Renewable energy advocates hope to enact a renewable portfolio standard (RPS) for Washington State.  The vehicle will be a ballot initiative as early as November 2006.  A coalition dedicated to this purpose launched a campaign to collect by June 30, 2006, the 300,000 signatures necessary for a plebiscite on adopting an RPS. 

The proposed law would require Washington's utilities by 2020 to procure 15% of their power from renewable energy sources such as wind energy, and to take steps to increase energy efficiency.  At present, approximately 1% of the state's energy is produced by renewable energy other than hydropower, which supplies the state with a significant portion of its energy.  It is not clear how the initiative would account for any new hydropower generators.  For example, would it differentiate between impoundment and run-of-river?  Demonstrating the increasingly wide range of benefits touted from renewable energy, the coalition cites in support of an RPS renewable energy's health and environmental benefits, its increased cost-competitiveness, and the creation of local jobs and landowner revenues.