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.

DC Circuit Orders Immediate Tightening of Mercury Control Rules

On March 21, a three-judge panel of the US Court of Appeals for the District of Columbia Circuit made clear that its February 8, 2008 order mandating a return to tighter mercury control rules on coal-fired power plants must go into effect immediately.  The court's February order threw out the Bush Administration's Clean Air Mercury Rule (CAMR), which was implemented in 2005 and established a cap-and-trade program for mercury emissions from coal- and oil-fired power plants, and directed a return to the more stringent standards enacted in 2000 under the Clinton Administration.  The court's most recent ruling requires the Environmental Protection Agency (EPA) to begin implementing the tighter rules immediately, instead of allowing time for the EPA and others to request rehearing of the court's February order.

In its February order, the court rejected the EPA's CAMR standards as violating the Clean Air Act.  The CAMR standards required coal- and oil-fired plants to reduce mercury emissions by 70% by 2018, and permitted utilities to trade mercury emissions to allow them to reduce compliance costs.  The CAMR standards also reversed the 2000 mercury standards, which had required mercury emissions to be regulated under a maximum achievable control technology (MACT) standard.  The MACT standard that will now take effect again requires proposed power plants to adopt emissions controls in use at the best controlled similar pollution source, which will likely require power plants to remove an estimated 85% to 90% of the mercury from their emissions. 

The court's ruling will have an immediate impact on coal-fired plants that are currently in the planning and permitting stages, as these plants will have to revise their plans and permit applications in order to remove higher amounts of mercury.  However, the EPA and several utilities that supported it have indicated they plan to seek rehearing of the court's February order, and thus the ruling could be modified or reversed following en banc review.  In the meantime, the court's recent order requires the EPA to begin tightening its controls immediately.

Court Upholds Market Pricing and Market Behavioral Rules

In a short per curiam opinion issued June 22 in Colorado Office of Consumer Counsel v. FERC, the DC Circuit upheld FERC's provision of a targeted remedy for abuses of market-based rates and ruled that FERC was not required, as certain consumer advocates had argued, to throw out market-based pricing altogether.  In response to findings that sellers operating under market-based tariffs had engaged in "fraudulent or otherwise anticompetitive" behavior, in 2003 FERC adopted Market Behavioral Rules, but rejected arguments by several consumer groups that the only course open to FERC under the Federal Power Act was to jettison market pricing and revert to "fixed" rates for electric energy.  In its decision, the DC Circuit upheld FERC's targeted remedy and held that the agency was not required to "reopen and reevaluate all other aspects of the filed rate."

FERC Chairman Joseph Kelliher trumpeted the decision, along with the Supreme Court's earlier rejection of petitions for certiorari from the Ninth Circuit's decision in Lockyer v. FERC case, as firmly upholding FERC's market-based rate program.  According to Chairman Kelliher, the Colorado Office of Consumer Counsel decision cleared the way for FERC to "conduct effective enforcement" in wholesale power markets.

D.C. Circuit Strikes Down Rule Favorable to Waste-to-Energy Facilities

Dealing a blow to the waste-to-energy industry, a U.S. Appeals Court recently vacated a rule promulgated in 2004 by the Environmental Protection Agency (EPA) that implemented limits on emissions of hazardous air pollutants (HAP) from certain commercial and industrial boilers (the CISWI Rule). 

In 2005, a number of environmental organizations challenged the rule.  At particular issue was EPA's regulatory definition of "commercial and or industrial waste."  In short, EPA's definition limited solid waste incinerators, as a class, to those facilities (1) that operated without energy recovery or (2) whose design did not provide for energy recovery.  This interpretation effectively exempted waste-to-energy facilities from the HAP limitations contained within Section 129 of the Clean Air Act and allowed waste-to-energy facilities to be regulated by Section 112 of the Clean Air Act.  This distinction is significant because, among other things, the standards in Section 112 only apply to "major" sources of HAP emissions whereas Section 129 applies to all sources of HAP emissions. 

DC Circuit Remands ISO-NE Installed Capacity Orders to FERC

The US Court of Appeals for the DC Circuit on April 20 issued a per curiam order that sends back to FERC the issue of whether the agency has jurisdiction to authorize ISO-New England's (ISO-NE) implementation of an installed capacity requirement.  The Connecticut Attorney General Richard Blumenthal and the Connecticut Department of Public Utility Control (CDPUC) had challenged FERC's jurisdiction over the contentious installed capacity requirement, which obligates load servers to control capacity in excess of peak load.  The AG and CDPUC argued that the Federal Power Act (FPA) entrusted such power supply decisions to the states, and not the federal government, to decide such matters.  While the court did not necessarily agree with the Connecticut parties' arguments that installed capacity is really a form of generation resource adequacy that should be left to the states, it directed FERC to articulate a justification for federal jurisdiction.

The AG and CDPUC have been vehement opponents of the installed capacity proposal from the outset.  In its briefs to the court, the CDPUC attempted to downplay the relationship of installed capacity requirements to wholesale rates, indicating the connection was only "tangential[] or incidental[]."  The CDPUC sought a court order defining the scope of FERC's authority over generation resource adequacy and directing that FERC must defer to Connecticut's jurisdiction regarding the generation capacity requirements.  For its part, FERC countered that authority over generation capacity was conferred to it by the FPA's general grant of federal jurisdiction over the sale of electric energy in interstate commerce.  But that wasn't clear enough for the court, which accordingly remanded the case back to FERC.  However, the court did not go as far as the CDPUC and AG would have liked; by simply remanding to FERC for further explanation of its jurisdiction, the court gave FERC another shot to explain how and why it should regulate installed capacity, and it left for another day the merits of ISO-NE's proposal.

Supreme Court Rules that Carbon Emissions Are a Pollutant under the Clean Air Act

In a decision with potentially broad implications for the electric power industry, the Supreme Court ruled on April 2 that the Environmental Protection Agency was wrong when it declined to promulgate regulations to limit car and truck emissions of carbon as a greenhouse gas that contributes to global warming.  The case before the high court was confined to US automobile emissions; it did not directly address the far greater domestic carbon emissions from stationary, coal-fired power plants.   But the precedent established will surely fuel efforts to reduce power plant emissions either through a tax on carbon or an emissions cap-and-trade program.

In Massachusetts v. EPA (Case No. 05-1120), a harshly divided U.S. Supreme Court overturned EPA’s 2003 refusal to undertake a rulemaking to regulate carbon emissions from new motor vehicles under §202(a)(1) of the Clean Air Act.  Court patriarch, Justice Stevens (joined by Justices Kennedy, Souter, Ginsburg and Breyer) held that EPA’s denial of the petition should go back to Agency for reconsideration because EPA’s reasoning was not based on the requirements of the Clean Air Act.  The majority also rejected the government’s contention that the State of Massachusetts lacked sufficient interest (standing) to challenge EPA’s decision.  In dissent, Chief Justice Roberts (joined by Justices Scalia, Thomas and Alito), opposed what he called the majority’s  “special solicitude” to the State of Massachusetts, cautioning that the climate change grievances were tailored for redress by the Congress and the Chief Executive, not the federal courts.  Justice Scalia (joined by Chief Justice Roberts and Justices Thomas and Alito) separately dissented on the merits decision, arguing that EPA’s judgment on the petition to regulate carbon emissions was based on permissible reasons that warranted deference from the Court.

Nineteen private organizations petitioned EPA in 1999 for a rulemaking to regulate greenhouse gas emissions from new motor vehicles under §202 of the Clean Air Act.  (A dozen states (CA, CT, IL, ME, MA, NJ, NM, NY, OR, RI, VT and WA), local governments and others later joined in the petition.)  Section 202(a)(1) of the CAA requires EPA to prescribe by regulation “standards applicable to the emission of any air pollutant from . . . any class of new motor vehicles . . . which in the [EPA Administrator’s] judgment cause[s], or contribute[s] to, air pollution . . . reasonably . . . anticipated to endanger public heath or welfare.”  The CAA defines “air pollutant” to include “any air pollution agent . . . , including any physical, chemical . . . substance . . . emitted into . . . the ambient air.”

EPA denied the petition four years later because, in its view (1) the CAA does not authorize the agency to issue mandatory regulations to address global climate change, and (2) even if the agency had the authority to set greenhouse gas emission standards, it would nevertheless be unwise to do so at that time.  The U.S Court of Appeals for the District of Columbia Circuit affirmed.  Each of the three judges on the appeals panel wrote separately, but two (Randolph and Sentelle) agreed that EPA properly exercised its discretion in denying the rulemaking petition.  Judge Sentelle’s separate opinion also found that the petitioner’s failed to demonstrate standing in the case because a “particularized injury” could not be demonstrated where “global warming is harmful to humanity at large.”  

The United States Supreme Court heard oral arguments on November 29, 2006.  (In addition to EPA, respondents opposing Massachusetts and the petitioners were the Alliance of Automobile Manufacturers, National Automobile Dealers Association, Engine Manufacturers Association, Truck Manufacturers Association, CO2 Litigation Group, Utility Air Regulatory Group, and ten states (MI, AK, ID, KN, NB, ND, OH, SD, TX and UT).

Because the harm of greenhouse gasses is widespread, EPA argued it wasn’t a controversy specific enough to Massachusetts and the other petitioners to fall within the jurisdiction of the federal courts under Article III of the U.S. Constitution.  The Court majority disagreed because (i) Massachusetts held a special position and interest on behalf of its residents, (ii) the harms associated with climate change are serious and based on a strong consensus, (iii) EPA’s refusal to regulate carbon emissions from new cars, at a minimum contributes to injuries to Massachusetts’ coastal lands, and (iv) the delayed effectiveness of regulating only new motor vehicles and the concern that developing countries are poised to substantially increase greenhouse gas emissions does not excuse EPA from taking steps today to slow or reduce global warming.

The Court then reviewed the merits of EPA’s decision that it lacked authority to regulate new vehicle emissions because carbon dioxide is not an “air pollutant” under § 7602, and that, even if it possessed authority, it would decline to exercise it because regulation would conflict with other administration priorities.  The Court’s review of the merits of those decisions was narrow ¾ i.e., the Court would reverse only if its decision were found to be arbitrary, capricious, an abuse of discretion, or otherwise not in accordance with law.  Despite the narrowness of that review, the Court found that greenhouse gases fit well within the CAA’s capacious definition of “air pollutant” and that EPA’s contrary conclusion could not be squared with the statute.  The Court instructed that the law requires EPA to regulate an air pollutant if it causes or contributes to air pollution that may reasonably be anticipated to endanger public health or welfare; other policies cannot countermand that scientific judgment.

In dissent, Justice Scalia argued that the CAA says nothing at all about the reasons for which EPA may defer making a judgment on greenhouse gas emissions and that the Court should defer to EPA’s deferral.

Does this mean EPA will be forced to regulate carbon from car and truck emissions?  Not necessarily.  The question of whether is carbon is a pollutant subject to the Act is only a threshold question.  Now an analytical process begins on the road to establishing an administrative record on carbon.  Recall that the Clinton Administration in its Cannon memo argued that the Act covered carbon, but it never regulated or even proposed a carbon regulation.

If EPA did regulate car and truck emissions of carbon, would stationary source regulation be inevitable?  Stationary sources were not before the Court, and a separate administrative record would be required to establish a criteria document to regulate carbon from stationary sources.  That said, it is hard to imagine regulation of the 30 percent of US carbon emissions that come from cars and truck and ignoring the 70 percent that comes from stationary sources, primarily coal-fired electric generating stations.  Moreover, the balancing that EPA does for car and truck emissions allows for greater consideration of economic factors than does its stationary source program.

If the Agency decided to regulate, does that mean a cap?  Not necessarily.  There is little agreement over how to regulate carbon just yet.  Economists uniformly favor a tax because it is more efficient and enforceable, while coal-dependent electric utilities prefer a cap-and-trade program under which they would be allocated the lion’s share of allowances.  Acid rain (sulfur dioxide) is regulated pursuant to a cap/trade program.  But the acid rain program was a legislative compromise.  Before EPA actually regulates, there would likely be a Congressional enactment - just as there was for acid rain and ozone depletion.

Does this hurt the "public nuisance" climate change cases in the Second Circuit?  Some court-watchers believe that Justice Stevens was able to entice Justice Kennedy to join the 5-Justice majority for the petitioners by slicing the standing argument narrowly.  Justice Stevens differentiates Massachusetts from other potential parties in part by noting that States should be treated with special deference.  The Chief Justice warns that the majority is using an outdated view of standing to cobble its majority.

In the Second Circuit nuisance cases, a Rule 28(j) letter was filed only two days after the Supreme Court's decision, arguing (among other things) that the standing decision does not undermine defendant's arguments in the nuisance cases because the statutory right to challenge EPA's action was "of critical importance to the standing inquiry" in order to be asserted "without meeting all the normal standards of redressability and immediacy."  The 28(j) filing also argues that the States' sovereign prerogatives to force reductions in greenhouse gases "now lodged in the Federal Government," and that "Congress has ordered EPA to protect" States from harms associated with those emissions.  And thus, that the narrow federal common law cause of action to abate nuisances is not a remedy for complex environmental issues, and cannot be expanded given Congress's authority.

FERC Issues Interim Rule for Standards of Conduct for Natural Gas

FERC has adopted in Order No. 690 an interim rule on the applicability of standards of conduct to interstate natural gas pipelines; the placeholder rule responds to a US Appeals Court decision in National Fuel Gas Supply Corp. v. FERC, 468 F.3d 831 (D.C. Cir. 2006) that FERC’s earlier Order No. 2004 unlawfully expanded the standards of conduct governing affiliate favoritism to apply beyond the marketing affiliates of a natural gas pipeline ─ that is, the court struck down application of the standards to non-marketing affiliates.  The placeholder defines "marketing" (including brokering) to mean a sale of natural gas to any person or entity by a seller that is not an interstate pipeline, except when (1) the seller is selling gas solely from its own production, (2) the seller is selling gas solely from its own gathering or processing facilities, or (3) the seller is an intrastate natural gas pipeline or a local distribution company making an on-system sale.  Although the case involved only the affiliate conduct standards as applied to a natural gas pipeline, the ruling cast in doubt the application of identical standards of conduct to the non-marketing affiliates of electric transmission providers.  In addition: 

• The interim rule allows sharing risk management employees between natural gas pipelines and their energy and marketing affiliates when the employees are engaged in transmission functions or sales or commodity functions.   
• The interim rule requires a natural gas pipeline to maintain a log of the tariff provisions that it waives, but only with respect to tariff provisions that provide for such discretionary waivers, and to provide the log to any person requesting it within 24 hours of the request. 
• Order No. 690 clarifies that FERC will treat natural gas pipeline lawyers as permissibly shared employees.  FERC's orders on Order No. 2004 had provided that while lawyers could provide legal or regulatory advice in their traditional roles without becoming transmission function employees ─ subject to the standards of conduct ─ to the extent that a lawyer engaged in transmission functions or in planning, directing, or organizing transmission functions, the lawyer was not exempt from also being a transmission function employee (and thus not permissibly shared between a natural gas transmission provider and its affiliates).   
• Order No. 690 clarifies that FERC will not require newly certificated natural gas pipelines to observe the standards of conduct until they commence transmission transactions with their marketing affiliates.  FERC's orders on Order No. 2004 had provided that newly formed transmission providers would become subject to the standards of conduct as soon as they began soliciting business or negotiating contracts. 

The interim rule retains provisions of Order No. 2004 not challenged on appeal.  Those provisions will continue to apply to natural gas transmission providers and their marketing affiliates.

Judges Bury Market Pricing and Competitive Bulk Power Markets

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

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

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

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

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

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

Court Decision Likely to Roll Back Applicability of Standards of Conduct for Both Pipeline and Utility Affiliates

A three-judge panel of the U.S. Court of Appeals for the District of Columbia Circuit in a November 17 ruling struck down a divided (2-1) FERC expansion of the applicability of Standards of Conduct that prohibit interstate natural gas pipelines and electric transmission grid owners/operators from sharing non-public pipeline or transmission- grid information with affiliates.  Before the November 2003 expansion, the Standards applied only to the marketing affiliates of the pipes and transmission systems; after, it applied to all “energy affiliates.”   Responding to natural gas pipelines’ complaints that the expanded applicability would cost the industry an estimated $240 million annually and was based on no evidence of preferential treatment of “energy affiliates,” the panel held that FERC’s “vast expan[sion] of the reach of the Standards,” based only on a theoretical possibility of affiliate favoritism, violated the Administrative Procedures Act requirement of reasoned decisionmaking.  FERC has 45 days to petition for rehearing, barring which the case will be remanded to the agency.  On remand, according to panel, FERC may (1) confine the Standards to market affiliates — those who actually buy and sell the transmission capacity of the pipes and wires, (2)  develop a factual record of abuse that would justify the expanded applicability, or (3) try to develop support for the expansion based on a “theoretical threat of abuse.”  The panel cautioned that the theoretical approach would likely fail.

As precedent, the panel decision reigns in the Standards as applied only to “energy affiliates” of natural gas pipelines, such as producers, gatherers, processors and risk managers, and not to the comparable affiliates of electric transmission system operators.  But this distinction is likely to vanish on remand since the agency prefers uniform rules for accessing natural gas pipelines and electric transmission systems to the extent possible.  Moreover, since one of the most vocal opponents of the expansion from early in its genesis, then-Commissioner Joe Kelliher, is now the FERC Chair, odds are that the agency won’t seek rehearing and, instead will retreat on remand to its original application of the Standards only to marketing affiliates of the pipes and grid operators.

Latest Twist: Maryland Court Reinstates Commissioners

The bitter fight over the impact of electricity restructuring in Maryland saw another twist last week when Maryland’s highest court, the Court of Appeals, voided parts of a state law that would have fired all members of the state’s Public Service Commission and replaced them with new members chosen by the legislature.  The court concluded that the law violated the state’s constitution by infringing on the governor’s authority to appoint members of the PSC, which is function reserved to the executive branch of government.

The dispute grew out of anger from the public and politicians at a 72% rate hike for Baltimore Gas & Electric that was to take effect following years during which BG&E's rates had been frozen pursuant to the state’s 1999 electricity deregulation legislation.  That legislation lowered BG&E’s retail rates to a level 6.5 % below the rates that had been set for the utility back in 1993.  Having grown accustomed to service at below-market rates, consumers reacted angrily to the rate increase that was to follow when the rate freeze ended this year.  The Court of Appeals ruling, however, did not address other parts of the state law, which included phasing-in increases in BG&E's rates until they approximate market prices, and carrying forward BG&E's losses for recovery in the future.  

Replacing, Not Prolonging, Old Power Plants Is Policy of Clean Air Act, 7th Circuit Rules

In an August 17 decision, the United States Court of Appeals for the Seventh Circuit ruled that Cinergy Corp. violated the Clean Air Act by upgrading coal-fired power plants in Ohio, Indiana, and Kentucky in the late 1980s and early 1990s without installing controls to capture pollution and without updating its federal air pollution permit.  Judge Richard Posner’s decision perpetuates a deep split among federal appellate courts on how to interpret the  New Source Review (NSR) provisions of the Clean Air Act.  In particular, the Seventh Circuit's Cinergy decision conflicts with a 2005 Fourth Circuit decision that found that Duke Energy had not violated the NSR when it similarly upgraded power plants.  The U.S. Supreme Court has granted certiorari in the Duke case, and is expected to issue a decision in that case in early 2007.

NSR is a federal permitting program, enacted as part of the Clean Air Act in the late 1970s.  It requires power plants, factories, and other industrial facilities to obtain permits before constructing new facilities or adding on to existing ones.  The program is aimed at ensuring that plant additions and expansions do not degrade local air quality.  The primary issue in both the Cinergy and Duke cases involved whether particular actions by the utilities triggered the NSR requirements.  Specifically, both courts were called on to interpret the meaning of the phrase "emissions increase" for purposes of the NSR program, and to determine whether the utilities' actions can be considered "routine maintenance," which is exempt from NSR, or are "major modifications," which would require new federal permits and the installation of improved air quality controls. 

Duke and Cinergy both argued that NSR's pollution control requirements are triggered by increases in hourly emissions rates — which were virtually unchanged in both cases — and that the "routine maintenance" exemption refers to activities that are routine within the industry.  The Environmental Protection Agency ("EPA"), on the other hand, contended that NSR requirements are triggered by increases in annual emissions, and that "routine maintenance" refers to maintenance activities that are routine for a specific generating unit.  The Seventh Circuit in Cinergy sided with the EPA, reasoning that Cinergy's interpretation of the NSR provisions would give utilities an "artificial incentive" to renovate a power plant and continue using it beyond its expected lifespan, rather than replacing it with a more environmentally friendly plant.  According to Judge Posner, that incentive conflicted with the intent of the Clean Air Act.

US Appeals Court Balloons Seller Refund Exposure on California Sales during 2000-01 Energy Crisis

Nearly one year after ruling that FERC lacks jurisdiction to order governmental utilities to refund proceeds on their sales into the California Power Exchange (PX) and ISO markets during the 2000-01 energy crisis [see Court Limits FERC's Jurisdiction as Bonneville, Munis Escape Refund Liability in California Energy Crisis Case], the same panel of the US Court of Appeals for the Ninth Circuit ruled August 2 that the potential refund liability of other sellers — primarily investor-owned public utilities, independent generators and marketers — could go far beyond the parameters that FERC initially set. 

In addition to making refunds on sales into the PX and ISO single-price auction markets, the court ruled that sellers subject to FERC jurisdiction could also be required to make refunds on (1) out-of-market or OOM sales to the ISO for load balancing, (2) sales made during non-emergency hours when power supply was sufficient to meet demand,  (3)  bilateral block-forward sales to the PX, (4) exchange sales where power would be delivered to the ISO in one time period and repaid in kind plus a premium at a later time,  and (5) sleeve sales in which the seller was actually an intermediary between the PX or ISO and another seller who couldn’t or wouldn’t transact directly with the PX or ISO due credit concerns.  In each of these rulings, the court deferred to and upheld each FERC decision requiring refunds of charges in excess of a mitigated price, irrespective of how poor FERC’s reasoning or inadequate its evidence.  Conversely, the court was at pains to overturn any limitation that FERC placed on sellers’ refund liabilities (as in the case of block forward and exchange sales).  The only exception was the court’s reluctant affirmance of FERC’s decision that long-term bilateral sales to the California Department of Water Resources were not properly at issue in this case involving only sales to the PX and ISO; but even in so ruling the court hastened to add that California buyers “argue, with considerable force” that prices in those bilateral sales were unlawful and “may be the subject of other challenges.” 

Even more stunning than the panel’s single-minded drive to expand the universe of sales subject to refund was its directive to FERC that it expand the time frame of remedies by allowing California buyers to prosecute anew allegations of tariff violations for which refunds would not be confined to a period following a refund effective date no earlier than 60 days following the filing of a complaint.  FERC had confined refunds to sales occurring after October 2, 2000 — the refund effective date set when San Diego Gas & Electric’s lodged its August 2 complaint against sellers to the PX and ISO.  That limitation was wrong, according to the court, because FERC should have allowed the California complainants to seek refunds on earlier sales most, if not all, of which FERC itself had already investigated for tariff violations (including alleged violations of the ISO’s Market Monitoring and Information Protocols) and in many instances entered into settlements requiring the sellers to disgorge revenues back to California.  Although far from a paragon of clarity, the panel’s decision seems to direct FERC to permit the California complainants to seek further refunds on top of those FERC already exacted on some of the same sales to the PX and ISO.

Circumscribed Clean Water Act Protections Unlikely to Affect Hydroelectric Regulation

In companion cases, Rapanos v. US and Carabell v. US, a divided Supreme Court cabined Clean Water Act (CWA) jurisdiction, holding that the Act's protections for navigable waters do not extend to four Michigan wetlands lying near ditches or man-made drains that eventually empty into traditional navigable waters.  The CWA prohibits dumping dredged or fill material into “navigable waters” without a permit and defines “navigable waters” as “the waters of the United States, including the territorial seas,”  The Corps of Engineers' regulations implementing this prohibition broadly read "navigable waters" to comprise" tributaries” of such waters, and wetlands “adjacent” to such waters and tributaries.  The Supreme Court held that this construction went too far.  Four justices concluded that waters of the United States include only relatively permanent bodies of water, not intermittent or ephemeral channels.  Justice Kennedy (often the Court's swing vote) concurred, concluding that a water or wetland would be jurisdictional if it possesses a “significant nexus” to navigable waters.  In his view, when the Corps seeks to regulate wetlands based on adjacency to non-navigable tributaries, it must establish this significant nexus on a case-by-case basis. 

Regardless of its impact on the CWA jurisdiction, the Court's ruling is unlikely to alter FERC's interpretation of its mandatory hydroelectric licensing jurisdiction.  In most cases, conventional hydroelectric projects will involve more typical streams, not ditches, man-made drains or other "adjacent" water bodies.  Moreover, in non-conventional cases, such as pumped storage projects using ground water or intermittent streams, FERC has adopted a view that cabins its mandatory hydroelectric licensing jurisdiction consistent with Justice's Kennedy's nexus analysis. 

Court Confirms Hydro Licensees Must Certify for Water Discharges

A unanimous Supreme Court in S.D. Warren Co. v. Maine Board of Environmental Protection upheld the requirement that hydro licensees must certify under § 401of the Clean Water Act (CWA).  CWA § 401 requires a water quality certificate for any activity that would cause a "discharge" into navigable waters.  Warren (the license applicant) argued that § 401 certificates were not required for its multiple hydro projects because the projects only take water from a lake, run the water through a turbine and then return it to the lake.  In Warren's view, this did not amount to a "discharge."  Warren based its position on the high court's interpretation of CWA § 402 in South Fla Water Management Dist. v. Miccosukee Tribe.  CWA § 402 established the National Pollution Discharge Elimination System and requires a permit for the "discharge of any pollutant."  Miccosukee held that pumping water from one part of a water body to another is not a discharge of a pollutant under § 402, and Warren sought to extend that reasoning to § 401.  The Supreme Court rejected Warren’s attempted extension.  According to the court, § 402 and § 401 are not interchangeable and § 402's term "discharge of a pollutant" is narrower than § 401's term "discharge." 

This is fairly settled § 401/hydro licensing law.  Although § 401 does not define "discharge," and although the precise question raised by Warren had not yet been addressed, FERC, EPA, and the various state Water Quality Certification Entities have all long considered releases from hydro dams as discharges implicating § 401.  In fact, FERC will not issue a hydro license without a § 401 certificate or waiver.  By holding that Miccosukee does not limit the scope of § 401, the Supreme Court provided greater clarity on these issues.

Ohio Court Rejects FirstEnergy's Rate Program

In what could be a boost for electric choice in Ohio, on May 3, the Ohio Supreme Court ruled that the Ohio Public Utilities Commission (OPUC) had violated the state's energy choice law by approving FirstEnergy's rate stabilization plan, which would have stabilized rates until 2008.  The FirstEnergy rate plan failed to provide customers with any competitive alternatives.

Rejecting FirstEnergy’s and OPUC’s contention that the state's electric market is not yet fully developed enough for any choice to be meaningful.  To the contrary, in order to comply with the 1999 law, the court ruled that OPUC and FirstEnergy must provide customers with a choice or at least some level of customer participation.  The choice requirement does not necessarily translate into a mandatory competitive-bidding process, the court instructed.  But alternatives to a competitive-bidding mechanism must provide customers with options similar to competitive bidding. 

Cases involving similar rate stabilization plans for several other Ohio utilities are also currently pending before the Supreme Court.  In light of the FirstEnergy ruling, it appears unlikely that these other utilities' plans will survive the court's scrutiny.

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. 

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.

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) ]

FERC Approves Enron-California Settlement

FERC approved a $1.5 billion settlement between Enron and the plaintiff group known as the California parties, as well as the attorneys general of Oregon and Washington, and FERC staff.  The settlement resolves claims and matters arising from transactions in the western energy markets from January 16, 1997, through June 25, 2003.   

The settlement includes an $875 million unsecured claim against Enron in the bankruptcy proceeding, a $600 million civil penalty in favor of the California, Oregon and Washington attorneys general, and cash or cash equivalence of $47.4 million.  Ominously for others who did business with the disgraced energy giant, the settlement also requires Enron to cooperate with the settling parties in their claims against other entities related to events in the Western energy market.  

The settlement has also been approved by the California Public Utilities Commission and the United States Bankruptcy Court for the Southern District of New York, which is adjudicating Enron's bankruptcy.  FERC's order noted that the value and timing of the settlement's $875 million unsecured claim in the bankruptcy proceeding is uncertain due to the ongoing bankruptcy litigation.  

FERC Chairman Joseph Kelliher called the Enron settlement a turning point in the agency's efforts to bring closure to the 2000-2001 Western energy crisis.  He also attributed the settlement to FERC's "strong enforcement posture."  Combined with the Chairman's recent statements in support of FERC's Office of Market Oversight and Investigations, its seems clear that the agency intends to emphasize its market oversight and enforcement roles.

Bankruptcy Court Cedes to FERC Resolution of Terminated Enron Contract

A New York bankruptcy judge has become the first to implement a provision of the Energy Policy Act of 2005 (EPAct 2005) that prohibits bankruptcy judges from deciding disputes over the fees associated with termination of pre-June 20, 2001, power supply contracts where the seller has been found to have manipulated the market and had its FERC market-pricing authority revoked.  In EPAct 2005 Congress granted to FERC exclusive jurisdiction to decide whether such sellers should be permitted to collect termination fees from their former buyers.  Although this provision of the statute does not mention Enron by name, it nevertheless squarely targets the disgraced energy trading giant.  Enron declared bankruptcy on December 2, 2001, inducing many of its buyers to terminate.  In order to benefit from this provision of the statute, a buyer's objection to payment of a termination fee must be pending and not subject to the final order of any court.

The specific dispute before the bankruptcy judge stemmed from a contract entered into in August 2000, which called for Enron to supply power to Luzenac America Inc.'s talc processing facilities in Montana.  After Enron filed for bankruptcy, its trustee sued Luzenac in the U.S. bankruptcy court for the southern district of New York for contract termination fees.  That suit is still pending.  Based on the EPAct provision, Luzenac petitioned FERC in October to review Enron's claim for termination fees.  In response, Enron asked the bankruptcy court to prevent Luzenac from pursuing its FERC petition.  Judge Arthur Gonzalez, however, denied Enron's motion, and agreed that, as a consequence of EPAct 2005, FERC has exclusive jurisdiction to resolve the dispute.  The judge's ruling will pave the way for other former Enron buyers to petition FERC to relieve them of Enron termination charges, which FERC is expected to do.

Court Affirms Pro-Shipper, Competitive Rules on Use of Natural Gas Pipelines

After having sent FERC back to the drawing board to rethink its rules on a firm shipper’s right of first refusal to extend a capacity reservation on an interstate natural gas pipeline beyond its initial term and to segment a firm reservation into forward and backhauls, a U.S. Appeals court on October 28 vindicated the agency’s resolution of both issues. 

Specifically, in connection with the right of first refusal that existing firm shippers enjoy under FERC’s open-access rules, the court held that FERC was justified in eliminating its cap on the number of years that an existing firm shipper must commit to in order to match the firm service request of a competing shipper and trigger the existing shipper’s right of first refusal.  Previously, FERC had proposed to cap the term that the existing firm shipper match at 20 years and then 5 years, but the court found no reasoned basis for either cap.  Now, for a shipper to take advantage of the right of its right of first refusal to extend firm service beyond the term of its reservation, it will have to match a competing purchaser’s term, without limitation on the term, and price (as before, up to a maximum rate).  According to both FERC and the court agreeing with the agency, a term cap was not needed to prevent a pipeline from exercising market power since five other constraints on pipeline operations already cabined the potential exercise of market power against existing shippers:  (1) cost of service rates; (2) the requirement that a pipelines sell all of its capacity; (3) shipper access to FERC complaint procedures; (4) a shippers’ ability to release for third-party sales capacity that it reserved but didn’t need; and (5) the non-discriminatory access rules of the standard pipeline tariff.

On the backhaul issue, the court rejected interstate pipeline objections to FERC’s proposal to permit firm shippers to divide their capacity reservations within a transportation zone into forward hauls, backhauls, or combined forward hauls and backhauls. The pipelines contended that allowing such flexible uses of firm reservations effectively amended the contracts between the firm shippers and the pipelines; FERC and the court ruled that it did not.  Allowing backhauls within a zone of firm reservation and giving that haul a firm, yet secondary priority to firm (but superior to interruptible) was service that the firm shipper had paid for and was not a new service requiring contract amendment. 

The two shipping rules affirmed by the court laudably promote competition, without compromising consumer protections.  On the right of first refusal issue, requiring incumbent shippers to match fully the offers of competing shippers is fair and forces shippers to value competitively scarce resources.  And on the backhaul issue, allowing shipper flexible use of capacity it has already paid for, irrespective of direction of flow, simply prevents interstate pipelines from proliferating services and charges.   [American Gas Association v. FERC (DC Cir. No. 04-1094] 

Entergy Rebuilding from Hurricane Damage Entails Numerous Options and Actions

The damages to large portions of Entergy’s transmission system by Hurricanes Katrina and Rita included thousands of miles of downed transmission lines and extensive damage from flooding.  The response to date has included numerous actions and proposals by the utility and governmental entities.

Within weeks of Hurricane Katrina’s landfall, which led to flooding of vast areas of the city, Entergy New Orleans filed for Chapter 11 bankruptcy protection to further insulate its finances from those of other Entergy subsidiaries and to help manage the extensive losses caused by the hurricane.  

In Washington, Entergy vice president Curt Hébert advocated at a Congressional hearing for federal financial aid for Entergy New Orleans in order to prevent already over-burdened city residents from alone shouldering the high price of reconstructing the utility's shattered network.  The former FERC Chairman argued by analogy to the financial relief the government gave to airlines following their loss of business after the terrorist attacks on September 11, 2001. 

Department of Energy Secretary Samuel Bodman invoked his authority under the FPA to order CenterPoint Energy in Texas to temporarily restore power to Entergy Gulf States and thereby provide power to the latter's customers while it repairs its broken infrastructure. 

Most recently two municipal utilities in Louisiana and Mississippi that receive transmission service from Entergy offered to help fund reconstruction of Entergy’s system in exchange for shared ownership interests in portions of the transmission network.  There is no indication yet whether Entergy is interested in such an offer.

Court Limits FERC's Jurisdiction as Bonneville, Munis Escape Refund Liability in California Energy Crisis Case

On September 6, 2005, the U.S. Court of Appeals for the Ninth Circuit issued an order excusing the Bonneville Power Administration ("Bonneville") and other governmental entities and "non-public utilities" from any potential refund liability in the California refund proceedings.  The court found that FERC did not have authority under the Federal Power Act ("FPA") to order these entities to pay refunds.  The main question for the court was whether FERC's refund authority is based upon the identities of the sellers (i.e., public versus non-public utilities) or the nature of the transactions (i.e., FERC's broad regulatory authority over the sale of electric energy for resale in interstate commerce).  The court decided that the sellers' identities was the paramount consideration, and since these sellers were not "public utilities" as defined by the FPA, FERC's refund authority did not extend to their wholesale electric energy sales.  Dismissed from the proceeding, and thus escaping any future refund liability, were Bonneville, along with various California cities, counties, irrigation districts, and state entities. 

The case involved the petition for review by several governmental entities and other sellers that did not fit into the FPA's definition of "public utility" (i.e., the "non-public utilities") of various FERC orders that purported to impose refund liability on all entities selling power into California markets during the 2000-2001 energy crisis.  In these orders, FERC reasoned that its broad authority over the wholesale sales of electricity in interstate commerce gave it the authority to require all sellers to pay refunds, while at the same time admitting that it did not have direct authority over governmental entities and non-public utilities.  The Ninth Circuit disagreed and found that since governmental and municipal utilities are not "public utilities" under the FPA, FERC's refund authority did not reach them.  The court cited the FPA's express exemption for U.S. federal, state, and municipal governmental entities and the statute's general definition of public utilities.  If FERC had jurisdiction over governmental entities merely by reason of its authority over wholesale energy sales, the court reasoned, these provisions would have been superfluous.  The court refused to read these provisions out of the statute and held that FERC had acted improperly in ordering these entities to pay refunds.  The court also cited previous FERC precedent, which held that Congress had explicitly exempted governmental entities from FERC's authority to set just and reasonable rates.  Although the court noted that the energy crisis was an extraordinary circumstance, it did not permit FERC to ignore its own precedent.

While the decision's immediate impact will be to excuse Bonneville and other municipal utilities from refunds relating to California sales, the decision's overall impact will likely extend past California.  Complainants in the Pacific Northwest proceedings (Port of Seattle v. FERC, Docket No. 03-74193) have argued that FERC's authority to order refunds does extend to governmental entities like Bonneville.  The Ninth Circuit's decision here, however, appears to have settled the question that FERC does not have jurisdiction over these entities, apparently precluding any arguments to the contrary in the Pacific Northwest appeal.  [Bonnevill Power Administration v. Federal Energy Regulatory Commission, Ninth Cir. 02-70262 (September 6, 2005) FERC Docket No. EL00-95, et al.] [UPDATE]

Court Vacates Erratic FERC Orders on Congestion Pricing

A federal appeals court recently reversed a FERC order on pricing arrangements in a congested area of ISO-NE region because of the agency’s failure to respond to reasonable objections to its mercurial policies on pricing. The opinion demonstrates that the agency’s abrupt policy changes will not withstand appellate scrutiny where FERC fails to resolve reasonable objections by appellants.

FERC's order concerned the ongoing attempts to devise an appropriate mechanism for compensating generators in a congested area of southwest Connecticut in which there is a risk of generator market power. As evidenced by FERC’s recent decision to delay implementation of a contentious locational installed capacity requirement in New England, the agency has yet to settle on a long-term, commonly accepted mechanism. The order on appeal involved two previous attempts to come up with a pricing scheme.

In 2002, FERC addressed NEPOOL’s proposal to create a standard market design in New England, and as part of that market design, approved the use of Reliability-Must-Run ("RMR") agreements that provide for monthly payments of costs and a return to generators that run seldom but are needed for reliability. Not long afterwards, however, when two generators, including an affiliate of PPL, sought approval of RMR agreements with the system operator, FERC reversed course and devised a new compensation scheme, although it signaled that RMR agreements could serve as a last-resort compensation mechanism. The new methodology was termed Peaking Unit Safe Harbor ("PUSH") bidding, and was intended to give a generator that ran seldom a bid price based on the sum of its units’ variable-cost and fixed-cost components.

The PPL affiliate appealed FERC’s order to the D.C. Circuit, where the agency has met with not infrequent reversals in recent years. The gas-fired generator challenged FERC’s assumption that the PUSH methodology would provide it with adequate compensation, as this would occur only if the generator operated as frequently from one year to the next, which was unlikely given rising gas prices and the availability of non-gas generators. The generator further pointed out that FERC relied on an incorrect assumption about whether PUSH-eligible units could set the locational marginal price (LMP). In addition, the generator argued that it met the last-resort standard FERC has established for RMR eligibility. The Court agreed with the PPL affiliate that FERC failed to respond directly to any of these objections. That failure, the court ruled, demonstrated a lack of reasoned decisionmaking and rendered the orders arbitrary and capricious. [PPL Wallingford Energy, LLC v. Federal Energy Regulatory Commission, 419 3d 1194 (D.C. Cir.) (2005)]

California Supreme Court Puts Re-Regulation Proposition Back on the Ballot

Controversial Proposition 80, which seeks to re-regulate California's electricity market, should be put to a vote in the upcoming November 8 elections, according to the Golden State’s highest court. The court's decision overturns a July 22 ruling of a lower court that would have kept Proposition 80 off of the ballot. The lower court ruled that Proposition 80 was unconstitutional on its face because it would expand the authority of the California Public Utilities Commission ("CPUC") to regulate the energy industry, a role that the court found to be reserved for the California Legislature under a constitutional provision giving the Legislature "plenary" authority over the CPUC. Not so, said the state's Supreme Court in a unanimous decision. Instead, the court held that Proposition 80 was not clearly unconstitutional and thus, the issue should be left up to the voters. However, the court managed to hedge its bets somewhat by saying that it could revisit the issue if voters approve the measure.

Drafted and sponsored by consumer group The Utility Reform Network ("TURN"), Proposition 80 would effectively re-regulate the California electricity market. In addition to expanding the CPUC's regulatory authority, the measure would roll back one of the few remaining central provisions of the state's 1996 deregulation law, direct access, and would prohibit large consumers not already doing so from purchasing their electricity from independent power marketers rather than from the state's investor-owned utilities. Proposition 80 would also mandate cost-of-service regulation for all of the state's retail energy-service providers. In the wake of the Supreme Court's decision, TURN has been proclaiming victory. However, the measure's opponents, including the Independent Energy Producers Association and Californians for Reliable Electricity, have pointed out that the Supreme Court could still strike the provision down as unconstitutional if it passes. [Case No. 05-169] [NEW MATTER]

Supreme Court Decision Backs FCC Ruling Deregulating Broadband Cable Modem Providers that Bundle Telecommunication with Internet Access

In a decision noteworthy for its implicit encouragement of bundling traditional utility network service with competitive goods and services, contrary to the regulatory course charted in recent years for pipelines, local telephone exchanges and electric transmission grids, a divided (6-3) U.S. Supreme Court recently affirmed a Federal Communications Commission (FCC) declaratory rule that exempts from common-carrier regulation providers of broadband cable modem service because of the bundling of the telecommunications component of that service with internet applications.  The majority decision in what will likely become known as the Brand X case (after an internet service provider (ISP) that supported common carrier regulation and opposed the FCC rule) dismissed with virtually no analysis the objection that the FCC rule allows broadband cable providers, such as Comcast, to deny common-carriage access to competing ISPs, while at the same time the FCC takes precisely the opposite approach in its regulation of the other principal media for accessing the internet, dial-up access and Digital Subscriber Line (DSL) service, both of which are required to provide nondiscriminatory common carriage.

While the majority decision in large part turned on an evolving and mushy area of the law concerning the extent to which federal courts must defer to the expertise and judgment of a regulatory agency such as the FCC, the ultimate question boiled down to this:  Does a broadband cable provider offer telecommunications service to the public for a fee?  If so, then the provider, like providers of dial-up and DSL, is subject to mandatory regulation as a common carrier and must provide nondiscriminatory access to competing ISPs.  Conversely, if the broadband cable modem provider is deemed not to offer telecommunications service, then it is an information service provider, like an ISP that does not own wires or cables, and escapes common carrier regulation.  Because of the nature of the broadband cable providers' service, which does not offer telecommunications on a stand-alone basis, but instead only uses telecommunications to provide end users with a package of internet applications, the FCC ruled and the Supreme Court affirmed that broadband cable providers do not "offer" telecommunications.  Paraphrasing the majority, evidently incredulous dissenters countered:

[F]or the inputs of a finished service to qualify as the objects of an “offer” . . . , it is perhaps a sufficient, but surely not a necessary, condition that the seller offer separately “each discrete input that is necessary to providing . . . a finished service . . . .”  The pet store may have a policy of selling puppies only with leashes, but any customer will say that it does offer puppies — because a leashed puppy is still a puppy, even though it is not offered on a “stand-alone” basis.

It remains to be seen whether this decision of the high court will have any carryover influence in other network industries with natural monopoly characteristics, such as pipelines, local exchange telecommunications and electric transmission systems.  The direction of these industries has been just the opposite.  In recent years, they have been unbundled from sales of natural gas or oil, long distance and wireless service, and electric energy, respectively, and required to provide competing sellers nondiscriminatory access to their networks and common carriage.   It would be a stunning volte-face if these industries could escape this obligation simply by adopting a policy of bundling network access with other services or products and not offering it on a stand-alone basis.  [National Cable & Telecommunications Association, et al., v. Brand X Internet Services, et al., 545 U.S.--, 162 L. Ed. 2d 820 (June 27, 2005)] [NEW MATTER]

North Carolina’s Highest Court Validates Local Regulator’s Assertion of Veto Over Proposed Wholesale Power Contracts

The North Carolina Supreme Court ruled July 1 that the North Carolina Utilities Commission ("NCUC") can exercise veto power over certain wholesale power contracts — contracts that would confer on wholesale customers a higher priority than accorded to a Tar Hill State utility’s retail native-load customers.  In so ruling, the court rejected the argument that FERC's exclusive jurisdiction over wholesale sales preempted the state commission’s assertion of this veto power.
 
The case arose out of a 1998 plan by Carolina Power & Light (since renamed Progress Energy Carolinas) to build two plants to meet its incremental need for power and to provide wholesale power to customers in the Carolinas.  The NCUC approved the plan, but then in an order approving the merger between Carolina Power & Light and Florida Progress, the NCUC imposed the condition that the NCUC be given a 20-day advance notice to review and possibly reject any proposed power wholesale sales that would provide the buyer with priority equal to native-load priority to ensure the deals would not affect retail customers.  A N.C. Appeals Court found that FERC’s Federal Power Act jurisdiction preempted NCUC's advance-notice condition.  The July 1 Supreme Court decision reversed, however.  It did so based on the dubious proposition that NCUC review was not preempted because it sought to review the contracts before they were filed with FERC and before FERC took any action on them.  Moreover, the NCUC was not seeking to set wholesale rates, inquire into the prudence of proposed contracts, or overrule a FERC action.  According to the court Congress intended states to oversee matters of local concern, such as generating facilities and local supply adequacy and reliability issues, just the type of matters that NCUC's proposed review would take into consideration.

The issue of federal vs. state jurisdiction over wholesale power contracts that impact resource adequacy issues has recently been on the forefront of electric power news, with tensions between federal and state regulators running high, and the decision comes just as FERC and state commissioners are attempting to establish an informal joint working group to discuss resource procurement and adequacy issues.  The impact of the N.C. high court’s decision on this debate remains to be seen.  Investor-owned utilities and competitive power suppliers argue that the decision can and should be overturned by the federal courts.