First NERC Penalty Notices Suggest Focus on Enforcement

FERC Augments, Revamps Enforcement Guidance and Procedures

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

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

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

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

FERC Mostly Affirms Market-Based Rate Program

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

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

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

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

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

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

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

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.

Standards of Conduct Proposal Retreats from Structural to Functional Separation

A recent FERC Standard of Conduct rulemaking proposal retreats from its Order 2004 expansion of the standards of conduct, expressly finding that expansion too complex and unworkable.  FERC proposes a return to its 1990s vintage functional separation model of Order 497 (natural gas) and Order 889 (electric power), eliminating both Order 2004's concept of "Energy Affiliates" and its emphasis on corporate separation.  FERC concludes that returning to mere functional separation will encourage compliance by making the rules clearer, which the agency indicates is necessary in light of the new penalty regime of the Energy Policy Act of 2005 (EPAct 2005).  Comments on the proposed rule must be filed with FERC by May 12. 

In retreating to functional (from structural) separation, the proposal rulemaking appears to validate vertically integrated utilities by conceding that Order 2004 was hindering the advantages that accrue from vertical integration.  Nevertheless, the agency seems to be adrift between acknowledgment of the planning and integration advantages of the historical utility model and distrust of the  non-competitive characteristics of that model.  

Specifically, the proposed Standard of Conduct reform would implement:  

(1)  An “independent functioning rule” that defines the two groups of employees — “transmission function" and "marketing function" — who must function independently.  This division is based on what the employees do, not where they are employed.  Employees not directly engaged in transmission or marketing -- for example attorneys, accountants, and certain supervisors -- will not have their functions constrained by the proposed rule.   

(2)  A “no-conduit rule” to ensure independent functioning by prohibiting transmission function employees from communicating non-public transmission-related information with marketing function employees.  The no-conduit rule bars both communicating and receiving non-public transmission information, and everyone, regardless of function, is prohibited from being a conduit.   

(3)  A “transparency rule” to help detect, correct, and sanction violations of the independent functioning and no-conduit rules.  Whenever information is communicated in violation of the independent functioning or no-conduit rules, then, as provided in the current rules, the transmission function employee must immediately post that information on OASIS.  In addition, any interaction of transmission and marketing function employees would have to be contemporaneously recorded (handwritten notes may suffice) and made available to FERC on request, so the agency can monitor compliance with the rules.     

Unclear from the transparency rule is whether the damage of an improper disclosure of non-public transmission information can be undone.  Penalties for violations would remain unchanged from those enacted under EPAct 2005.

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.

Southern California Edison Asks FERC to Step into Arizona Transmission Siting Dispute

In the first test of the "backstop" transmission siting authority given to FERC in the Energy Policy Act of 2005 (EPAct 2005), Southern California Edison (SCE) recently discussed with FERC staff the siting of a 230-mile, 500 kV transmission line from the Palo Verde nuclear plant near Phoenix, Arizona to Devers, California, near Palm Springs (known as the Palo Verde-Devers II Line).  SCE representatives met with FERC staffers to begin a "pre-filing" consultation process in advance of filing an application for FERC to approve the proposed siting of the line. 

California covets the line as a means to bring more power into the state, and the California Public Utilities Commission (CPUC) approved the line.  However, SCE's plans hit a obstacle at the Arizona Corporation Commission (ACC).  The ACC rejected SCE's application in May 2007, stating it refused to allow SCE to plug a "230-mile extension cord" into Arizona's generation supply.  The ACC found the line would cost Arizona ratepayers $242 million, could have detrimental environmental impacts, and would significantly reduce available generation in the state, which has a rapidly growing population. 

Arizona's rejection of the line will test the extent of FERC's authority under the national interest electric transmission corridors (NIETC) provisions of EPAct 2005.  Under these provisions, Congress gave FERC authority for the first time to approve, in certain circumstances, the siting of transmission lines in areas of congestion, designated as NIETCs by the US Department of Energy.  These circumstance include when a state public utility commission has "withheld approval for more than 1 year" after a siting application is filed.  In a controversial 2006 rulemaking decision, FERC interpreted the word "withheld" in the statute to mean "deny," indicating that FERC believes it has authority to approve siting of a transmission line even when a state has rejected the line.  This order has been appealed to the US Court of Appeals for the Fourth Circuit.

Following the meeting with SCE, FERC emphasized that no application has yet been filed.  FERC also contacted the CPUC and ACC to inform them of the meeting and seek their input as to whether FERC has authority in this case.  If SCE eventually files an application, FERC will review the records developed before the CPUC and ACC, coordinate actions required by federal law, including federal environmental review, and conduct an independent evaluation.  FERC must issue a decision within one year of the filing of the application.

FERC Takes Action to Prevent Cross-Subsidization between Affiliates

FERC continues to tweak its rules regarding mergers and acquisitions under section 203 of the Federal Power Act (FPA), issuing new regulations that impose restrictions on affiliate transactions between certain public utilities and their unregulated affiliates.  FERC explained that it intends to fill a perceived regulatory gap in its current affiliate sales rules, and stated that this final rule, combined with an order issued the same day allowing for grants of blanket authorization for a public utility to dispose of voting securities, marks the completion of the "initial implementation" of the rules governing transactions conducted under section 203. 

Order No. 707 extends the affiliate transaction restrictions already in place for entities with market-based rates and utilities requesting merger approval to franchised public utilities that have captive customers or that own or provide transmission service over jurisdictional transmission facilities.  Under the new rules, wholesale sales of power between such public utilities and power sales affiliates with market-based rate authority will require FERC approval.  In addition, such a public utility that sells non-power goods and services to an affiliate with market-based rate authority or an unregulated affiliate will be required to do so at a price that is the higher of either cost or market price.  Lastly, a public utility subject to the rules will not be permitted to purchase non-power goods or services from an affiliate at a price above market price, except that the public utility cannot receive non-power goods and services from a centralized service company above cost. 

FERC Orders Review of Sellers Using WSPP Agreement Demand Charge in Markets where They Lack Market-Based Rate Authority

Last week, following an investigation under Federal Power Act section 206, FERC issued an order finding it is unjust and unreasonable to allow power sellers to keep using the WSPP-wide "up to" demand charge as a ceiling rate in markets where the seller does not have market-based rate authority, unless the seller can justify that rate based on its own costs.  Under the WSPP Agreement, sellers may charge "up to" a cost-based ceiling rate, which consists of a seller's forecasted incremental cost plus an "up to" demand charge based on the costs of a sub-set of 18 of the original parties to the WSPP Agreement.  In its February 21 order, FERC directed sellers that wish to continue transacting under the WSPP demand charge in markets where they do not have market-based rate authority or where they are presumed to have market power to make a filing by April 21 justifying continued use of the rate.  FERC emphasized that this affects only some, and not all, sellers that use the WSPP Agreement.  In a statement issued along with the order, Chairman Joseph Kelliher stated that allowing sellers to continue to use the WSPP demand charge without justifying the rate based on their own costs would "effectively let those sellers sidestep the more rigorous market-based rate test that we have put in place in recent years."

FERC began its review of the widespread use of "up to" demand charge rates under the WSPP Agreement last year as part of its rulemaking proceeding examining sellers' market-based rate authorizations.  In Order No. 697, FERC explained that it had accepted the use of the WSPP Agreement "up to" rate as a mitigation measure by several different sellers that had failed the indicative screens for market power and were found or presumed to have market power.  FERC expressed concern that use of the WSPP rate was no longer just and reasonable for such sellers because it appeared that many sellers used the rate without showing any relationship to their actual costs.  FERC thus began the investigation into whether WSPP rates can be used by sellers that are found or presumed to have market power or that lack market-based rate authority in certain markets.

Department of Energy Pulls Plug on FutureGen Program

The Department of Energy has cancelled the FutureGen project in which the DOE and a coalition of energy industry companies would have constructed a nearly emissions-free, coal-fired generator.  The futuristic project involved carbon capture and sequestration (CCS) underground as part of an integrated gasification combined cycle 275 MW plant producing both electric power and hydrogen.  The cancellation comes as a particularly hard blow to the people in Mattoon, Illinois who had prevailed in an intense competition with other U.S. locales to host the project.   

FutureGen had been touted as a model plant for devising a way to generate power from coal, while minimizing the release of carbon dioxide into the atmosphere.  This approach to battling climate change is important to countries such as U.S., China, and India that have both vast coal reserves and great energy needs.  But the DOE cited the increased costs of the project ― recent estimates had doubled the costs to $1.8 billion ― as a key reason for pulling the plug on the nascent project.

In lieu of FutureGen, the DOE has opted for what may be a more practical approach.  Rather than sponsor one, very expensive project, the Department explained that it would invest in development and application of CCS technologies that could be applied in numerous power plants that would each be funded by its respective developers.  The DOE has issued a request for information asking for industry input on the costs and feasibility of building clean coal facilities that meet the goals of FutureGen.  Comments are due by March 3.  Following receipt of comments, the DOE plans to issue competitive solicitations for federal funding to equip IGCC plants with CCS technology.  If the technology can be implemented, it could be part of new coal plants coming on-line by approximately 2015. 

Revised Contents of Sellers' Market-Based Rate Tariffs Clarified

Federal Trade Commission Examines Green Marketing and Carbon Offset Markets

With increased concern about climate change, but limited government action, voluntary carbon markets have bloomed in recent years.  The Federal Trade Commission (FTC), which regulates advertising claims, is now taking a closer look at these new carbon offset markets to gauge how the money they attract is being invested.  The FTC held a workshop in early January and is considering revising its environmental marketing guides to address sales of carbon offsets markets as well as renewable energy credits (RECs). 

Carbon offsets are credits that correlate to quantifiable reductions in greenhouse gas credits.  Purchasers of carbon offsets can claim that their carbon-emitting activity, such as travel, is offset by unrelated beneficial measures.  Common examples include tree planting or forest preservation, as well as investment in generation of energy from low-carbon-emissions sources.  Carbon offsets are typically measured in volumes of carbon.  RECs are quantifications of energy produced with renewable means, and are measured in megawatt-hours.  Voluntary REC markets allow buyers to purchase RECs to support renewable energy development.  State renewable portfolio standards also rely on RECs to quantify utilities’ mandatory procurement of renewable energy. 

The concern related to carbon offsets and RECs is whether the funds from voluntary sales are being used in legitimate or constructive ways.  Concerns have been voiced over issues such as whether eligible projects might oversell credits, or, even if not, whether the money paid goes to existing projects or projects that would have happened anyway.  For example, if an existing, operating windfarm that was built without any sales of RECs or carbon offsets subsequently obtains additional funds from such sales, there is arguably no additional environmental benefit obtained from these REC or carbon offset sales.

The FTC is inviting comments on carbon offset guidelines until January 25 and on environmental marketing guidelines until February 11, and will subsequently decide how and if to revise the marketing guides. 

Final Skirmishes in Enron Contract Wars Draw to Close

Resolving the last remaining claims against Enron stemming from the 2000-2001 California energy crisis, over the past week, FERC approved two settlements involving Enron:  one with the Port of Seattle, Washington (Port), and the other with Public Utility District No. 1 of Snohomish County, Washington (Snohomish).  The Port receives a $500,000 unsecured claim against Enron in its bankruptcy proceeding, while the Snohomish will pay Enron $18 million out of the $180 million that Snohomish allegedly owes Enron in termination fees arising from Snohomish's cancellation of contracts it entered into with Enron during 2001.  FERC's approval of these settlements puts an end to rancorous litigation between the parties and dismisses Enron from the various California refund proceedings.

The Enron-Port settlement continued the debate among the current Commissioners with respect to the Mobile-Sierra "public interest" standard of review for contract modifications.  Commissioners Kelly and Wellinghoff each filed separate opinions to the order approving that settlement, expressing disagreement with FERC's approval of the public interest standard.  Both Commissioners have consistently criticized FERC orders approving the inclusion of the public interest standard in settlement agreements, arguing that the Commission should not bind itself to the that standard, which allows unilateral changes to an agreement only if required by the greater "public interest" ― a singularly demanding burden of proof.  Instead, Commissioners Kelly and Wellinghoff have argued, FERC should approve modifications to settlement agreements so long as they are "just and reasonable," which is considered a less rigorous analysis and makes it easier for agreements to be modified in the future.

In two recent decisions currently before the Supreme Court (the so-called Long-Term Contracts decisions), the US Court of Appeals for the Ninth Circuit questioned whether the public interest standard applies where a buyer challenges a contract price as being too high.

FERC Tweaks Open-Access Reforms in Order No. 890-A

In late December FERC issued Order No. 890-A, clarifying and modifying the reforms it made in Order No. 890 to open-access transmission requirements originally established by Order Nos. 888 and 889 and revising the associated pro forma open access transmission tariff. 

In the primary clarifications and modifications, FERC:

• affirmed a tiered approach to calculating energy and generator imbalance charges, while revising the calculation itself:  imbalance charges should be based on the last 10 MW dispatched by the transmission provider for any purpose, rather than the last 10 MW dispatched to serve native load;
• affirmed lifting the price cap on reassignments of transmission capacity for all transmission customers through October 2010 (though the price cap lift may be extended based on a required FERC staff report due in May 2010);
• clarified that the control area of an off-system resource must be identified before it can qualify as a "network" resource, but deferred revising the minimum lead time for undesigating network resources; and
• clarified posting requirements related to processing of service requests and the time frame for implementation of transmission rollover rights reforms. 

As with Order No. 890, transmission providers must submit compliance filings to incorporate the modifications contained in Order No. 890-A—within 60 days of the order's publication in the Federal Register for non-RTO/ISO transmission providers whose facilities are not within an RTO/ISO footprint, and within 90 days for RTO/ISO transmission providers.

FERC Rules to Promote Transparency in Natural Gas Markets

On December 21 the FERC adopted a Final Rule that establishes an annual reporting requirement designed, as Chairman Kelliher said, "to boost our efforts to carry out Congress’ mandate [in the Energy Policy Act of 2005] to protect consumers by protecting the integrity of the markets for physical [natural] gas."

The final rule directs buyers and sellers of more than 2.2 million MMBtus of physical natural gas annually to file information pertaining to the size of physical natural gas markets, the relative importance of indexed and fixed price transactions, and the identity of major traders.   Specifically, Form No. 552 filings will report on the total volume of sales and purchases, the volumes of transactions that were priced at fixed prices, and the volumes of transactions that were reportable to price index publishers.  In addition, affected buyers and sellers must indicate whether sales of natural gas are transacted under a blanket sales certificate.  Form No. 552 must be filed by May 1 of each year, starting in 2009 for transactions delivered in the previous year.

Simultaneously, FERC issued a Notice of Proposed Rulemaking (NOPR) in which it proposes "to require both interstate and certain major non-interstate natural gas pipelines to post capacity, daily scheduled flow information and daily actual flow information" in order to achieve price transparency in natural gas sale and transportation markets.  Chairman Kelliher stated, however, that "the new proposed rule has a narrower application on major non-interstate pipelines [because it would] limit the reporting requirement to major non-interstate pipelines with significant gas flows that do not fall entirely upstream of a processing plant or deliver gas almost exclusively to retail consumers."  Commissioner Spitzer invited comments as to "whether the posting requirements for both interstate and non-major interstate pipelines should be similar" and "how the posting requirements should apply to storage facilities."   Comments on the NOPR are due in mid March.

Senate Joins House in Passing Measures to Expand CFTC Authority over Energy Markets

The U.S. Senate reauthorized the Commodity Exchange Act (CEA) in a farm bill, strengthening the Commodity Futures Trading Commission's (CFTC) authority over energy (and other commodity) trading platforms such as the Intercontinental Exchange (ICE) that are currently "exempt commercial markets."  This closes the so-called "Enron loophole" that allows these exchanges to avoid federal regulation of their trading activities.  

In language very similar to a CEA reauthorization that the House Agriculture Committee also passed last week, the Senate amendment to the CEA would require electronic exchanges to monitor trading for manipulative trading behavior and price distortions, limit position sizes to prevent excessive speculation, and reduce the holdings of traders who have violated position limits.  Exchanges would be required to collect data on trading activity, report large traders to the CFTC, and publish daily price and trading volume data.  These requirements would apply only to futures and financials contracts that offer a "price discovery function" for energy commodities.  The CFTC is directed to review all currently exempt contracts to determine which ones affect market prices and, for that reason, should be brought within the expanded purview of the CEA, with the main target being ICE's financial Henry Hub swap.

The main distinction between the House and Senate measures is that the Senate amendment permits an electronic trading platform to determine whether a previously unregulated product serves a price discovery function, while the House measure includes no such provision.  The House measure could be attached to that body’s farm bill. 

Expanded CFTC oversight of commercial futures and financials markets enjoys broad bipartisan support.  The CFTC itself now supports the measure after abandoning its resistance to calls for expanded oversight.  If the expanded authority is enacted — which now appears likely — that authority would validate the CFTC's evaluation the actions of energy markets and traders, including ICE as well as Amaranth Advisors.

Competing FERC and CFTC Jurisdictional Claims Are Court Bound

FERC in a November 30 order refused to reconsider its July 26 decision to impose $291 million in civil penalties against Amaranth Advisors (Amaranth) for gaming the natural gas futures market and manipulating the price of natural gas.  FERC upheld its own jurisdiction to impose penalties on Amaranth, rejecting the Commodities Futures Trading Commission's (CFTC) insistence that it alone has jurisdiction over manipulation of gas futures contracts.  FERC found instead that "the language and statutory purpose of Section 315 of the Energy Policy Act of 2005" (EPAct 2005) gave FERC "broad authority to sanction manipulative conduct by any entity 'in connection with' the purchase, sale or transport of natural gas within its jurisdiction." 

In the earlier July order, FERC had directed Amaranth to show cause why it had not violated the Natural Gas Act and FERC's anti-market manipulation rules, and proposed a $291 million civil penalty for allegedly manipulating the gas futures market by selling New York Mercantile Exchange (NYMEX) futures contracts just before they expired.  In an August request for rehearing, Amaranth argued that FERC did not have jurisdiction to impose the proposed civil penalties, and that the CFTC had exclusive enforcement authority for manipulation of gas futures markets.  The case has set up a turf war between FERC's expanded enforcement authority under EPAct 2005 and the CFTC's traditional regulation of commodities markets, and led the CFTC to argue that it has exclusive jurisdiction over this case.  Amaranth may now appeal FERC's orders to a US Court of Appeals, which may ultimately delineate the boundaries of FERC's expanded enforcement authority in relation to the CFTC's authority over commodity futures markets. 

Also in the November 30 order, FERC gave Amaranth 14 days to responds to the original show-cause order.

FERC, Industry Exchange Views on Enforcement

Two years after Congress granted FERC enhanced enforcement authority in the Energy Policy Act of 2005 and FERC issued its Policy Statement on Enforcement, and following the first year in which FERC has acted on this authority, FERC this month held a technical conference to discuss how it is implementing its new authority.  The conference revealed a gap between how FERC understands and is implementing its enforcement authority and an industry that is uncertain what is expected of it and fearful of the penalties it could unwittingly incur.  

In anticipation of the conference, a coalition of seven trade groups representing the electric and natural gas industries submitted a white paper highlighting concerns with FERC's implementation of its enforcement authority.  The coalition urged FERC to ensure that penalties fit the infraction.  It also warned FERC not to enforce against legitimate market behavior. 

In a statement issued prior to the conference, FERC Chairman Kelliher responded to the white paper and tried to clarify FERC's approach to implementation of its enforcement authority, disclosing that FERC intended to focus on punishing violations that cause the most serious harm or entail great risk of serious harm, violations of core regulatory requirements, and companies with weak compliance programs.  He cited FERC staff's report tallying the 64 enforcement investigations conducted in the last two years to argue that FERC has exercised this authority fairly, pointing out that of those, 47 concluded with no sanctions imposed and the remainder resulted in 13 settlements involving civil penalties and two show-cause orders.  Kelliher touted the value of self-reporting, and clarified that FERC will consider both actual and potential harm as the most important factor when determining a penalty. 

FERC Makes Good on Rate Incentive Promises to Transmission Developers

At its November 15 meeting, FERC announced three decisions awarding several incentive mechanisms to transmission developers.  The orders were issued in response to requests from Southern California Edison Company (SCE), Baltimore Gas & Electric Company (BG&E), and Pepco Holdings, Inc. (PHI), and were among the first substantive decisions since FERC's transmission incentive rulemaking order earlier this year, Order No. 679.  To transmission developers who can show their projects would ensure reliability or reduce transmission congestion that decision, Order No. 679 proposed to provide increased transmission rate incentives, such as higher Returns on Equity (ROE), adders to the rate basis, and inclusion of 100% of Construction Work in Progress (CWIP) and abandoned facilities in rate base.  The transmission developers, in order to qualify, must demonstrate a "nexus" between the incentives sought and the investment being made, i.e., the applicant must show that the incentives are rationally related to the investments being proposed.

Two of the instant orders provided incentives for companies seeking to construct new facilities in the transmission-constrained Southern California and Mid-Atlantic regions.  SCE is building several projects in Southern California:  the Devers-Palo Verde II Project, which consists of two transmission lines; the Rancho Vista Project, which includes a new 500 kV substation; and the Tehachapi Project, which consists of over 200 miles of transmission lines and three new substations and will be used to bring renewable energy (predominantly wind) onto SCE's transmission system.  In its order, FERC found that SCE had satisfied the "nexus" standard of Order No. 679.  The agency went on to allow a 125-basis point ROE incentive for the Devers-Palo Verde II and Tehachapi Projects, and a 75-basis point ROE incentive for the Rancho Vista Project.

Similarly, BG&E is constructing two baseline transmission projects in Maryland.  While FERC granted BG&E's request for a total of 150-basis point adders (for membership in the PJM Interconnection and for constructing baseline transmission), FERC denied BG&E's request to include 100 percent of its CWIP in rate base.  FERC also established a technical conference to determine whether BG&E's projects satisfied Order No. 679's "nexus" test.

In FERC's third order, it granted a request from PHI, on behalf of its transmission-owning public utility affiliates, Atlantic City Electric Company, Delmarva Power and Light, and Potomac Electric Power Company, for a 50-basis point adder to its authorized ROE for continued membership in PJM.  The adder moves PHI's overall ROE up closer to ROEs granted for PJM transmission facilities placed in service since 2006.  FERC explained that granting PHI's request furthered the Energy Policy Act of 2005 directive that FERC encourage utilities to join RTOs and ISOs.

EPA Rulemaking Will Provide Guidelines for Underground CO2 Storage

The Environmental Protection Agency has announced it is preparing a rulemaking to develop guidelines for permanent underground storage of carbon dioxide.  Underground sequestration of carbon may be a valuable tool for combating climate change, as it complements usage of fossil fuels such as coal that are widely available but also relatively high in carbon content.  The potential success of carbon sequestration and storage, however, depends on resolution of numerous technological challenges, including means for separating out the carbon from fossil fuels and transporting it to and storing it in secure underground locations.

The EPA will evaluate the potential impact of underground carbon storage on health, safety and the environment, including underground sources of drinking water.  The agency stated that rules are needed to determine what parties have responsibility and liability for storage of carbon dioxide.  The EPA’s timeline is unlikely to provide much near-term guidance, as its proposed rules would appear in mid-2008 and final rules not until 2010 or later.  The proposed rules will not address the high-profile issue of who would get credit for any reductions in carbon emissions related to reduced emissions or underground storage of CO2. 

Energy Expands Loan Guarantee Program, Picks 16 Pre-Applications for Further Analysis

FERC, NERC Flesh Out ERO Operations, Penalties, Disclosures & Budgets

Five months after FERC authorized mandatory Reliability Standards to go into effect last June, it  is now sorting out to whom the Standards apply.  It is also slogging through issues of organization and management of NERC as the Electric Reliability Organization (ERO).   

Application of Reliability Standards 

Among the issues being debated are when a participant on the electric power grid sufficiently impacts grid operations to require registration with a Regional Entity and to what extent pure power marketers should be subject to Reliability Standards.

On October 18, 2007, FERC remanded to NERC its determinations that the Florida Reliability Coordinating Council properly included Mosaic Fertilizer, LLC and City of Tampa, Florida on its compliance registry.  Mosaic and Tampa appealed their registration to NERC and then to FERC.  FERC determined that NERC did not adequately show that the either was properly registered and, in any event, failed to respond adequately to arguments against registration. 

Penalties, Budget & Business Plan

The back-and-forth between FERC and NERC to define the ERO continues.  FERC issued an order October 18 directing NERC to clarify that the maximum penalty that it or a Regional Entity could impose for violation of a Reliability Standard is $1 million per violation, per day, consistent with the Federal Power Act, and to clarify how it would address specific situations that do not fit the one-violation, one-day fact pattern.  FERC generally accepted NERC's compliance filing on these issues, and directed small follow-up clarifications to the proposed sanctions language.  Alternative situations will be handled as follows:  repeated violations during a single day may result in a $1 million penalty  for each violation; NERC will amend Reliability Standards requirements measured as an average over time to specify the minimum period in which a violation could occur and how to determine when a violation arises; and for requirements of Reliability Standards that involve discrete events that are measured only periodically or are reported by exception, a violation arises when that event occurs and continues until it is cured.

In response to FERC's request that NERC describe how it will process requests for information, NERC clarified that the requestor must explain the need for the information and how it will be used.  NERC clarified that requests would be met so long as they were not frivolous, too-broad or unreasonable, and that the requestor's description of the anticipated use of the information would not limit the use of the information once disclosed.  FERC accepted these clarifications.  NERC also proposed to include a new section 1600 in its rules of procedure, to establish a process for NERC or Regional Entities to issue requests for data or information needed to fulfill their obligations.  

Also on October 18, 2007, FERC accepted NERC's proposed budget and business plan for 2008, including the budgets and business plans for each of the eight regional entities and the Western Interconnection Regional Advisory Body.  FERC noted that it plans to compare proposed budgets to actual expenditures, and will require NERC to provide a true-up for itself and each Regional Entity by April 1 of each year.  FERC also directed several compliance filings with regard to the Regional Entities' proposed budgets and business plans, focusing especially on inconsistencies between the Regional Entities' income statements and their business plans, and on its concern about the adequacy of separation and independence of the SPP Regional Entity from the SPP RTO.

FERC Extends Financial Houses’ Leave to Acquire Utility Securities

The role of financial institutions in energy markets is steadily increasing.  In furtherance of this trend, FERC recently granted blanket authorizations to three financial and investment companies allowing them to acquire securities of electric utility companies in the course of their business, without needing advance FERC approval under the Federal Power Act (FPA) for each transaction.

As part of the Energy Policy Act of 2005, Congress amended the FPA to require prior FERC approval for holding companies to acquire securities with a value of over $10 million of utilities or holding companies owning utilities.  Financial institutions have since sought and received from FERC waivers to allow them or their affiliates to acquire these securities in amounts exceeding $10 million without advance FERC approval, provided the acquisition is in their ordinary course of their business, which includes taking security for a loan, in connection with their asset management business, or as part of their routine activities as a broker, dealer, and trader. 

In 2006, FERC granted these blanket approvals for only one-year terms.  But having grown more comfortable with these arrangements, FERC now granted blanket approvals for a three-year term.  The authorization granted two of the companies, The Goldman Sachs Group, Inc. and Morgan Stanley, were renewals for these longer terms, while the third, Legg Mason, Inc., received an initial three-year authorization.  The conditions FERC imposed on each company include not exercising control over public utilities whose securities they acquire and compliance with reporting requirements.

Demand Response Developments: Promotion and Quantification

Utilities and their regulators are increasingly taking steps to foster reductions in electricity demand — whether through improved efficiency in applications or demand management — based on a combination of economic, reliability, and, increasingly, environmental reasons.

FERC's recent creation of an Energy Innovations Sector (EIS) within the newly renamed Office of Energy Market Regulation (OMER) (formerly the Office of Energy Markets and Reliability) is intended to highlight and respond to the growing complexity and potential of demand response in U.S. electric power markets.   The EIS will focus on five areas—demand response, renewables, distributed generation, global warming and advanced technologies—and will be tasked with performing independent assessments of developments in each of these areas as well as serving as an in-house technical advisor on issues regarding the integration of these resources into FERC's traditional concerns of wholesale markets, reliability, transmission planning and resource adequacy. 

Regional collaborative efforts to encourage demand response are also gaining traction in the form of the Pacific Northwest Demand Response Project and the Midwest Demand Response Initiative in the last year.  In addition, the California Independent System Operator (CAISO) plans to open a demand response laboratory this month in an effort to educate consumers on the potential for and importance of demand response.  The lab will feature exhibits and information on the latest demand response technologies, ranging from thermostats that respond to FM radio signals to adjust air conditioning and other residential applications to an automated direct response programs for commercial and industrial clients.  The latter allows utilities and other demand response aggregators to bid in MW blocks of demand reduction at certain prices and allocate the revenue as they wish.  Increasing numbers of utilities are using programs such as these to meet supply.  Finally, the addition of third-party demand response providers to the mix further expands the range of demand response options. 

FERC's Assessments of Demand Response and Advance Metering, issued in August 2006 and again in September 2007, demonstrate, according to FERC Commissioner Wellinghoff, that implementation of demand response programs has shifted from a question of "whether" to a question of "how."  FERC plans to issue another report in 2008 and follow up every two years thereafter, with information updates in the intervening years. 

Other nationwide efforts are also underway to quantify and verify demand response resources.  Quantification can prove difficult since reliability-based demand response resources, such as direct curtailments or interruptible services, are easier to track than are economically induced resources that depend on variable levels of customer participation.  Both NERC and NAESB have undertaken efforts to calculate demand response potential in the U.S.  Also, the US Demand Response Coordinating Committee (DRCC), a group composed of utilities and other energy companies, is working to develop methods for verifying the contribution of demand response resources.

Initiatives Provide Transmission for Renewable Power

The California Energy Commission has initiated a Renewable Energy Transmission Initiative (RETI) to identify transmission projects needed to help the state meet its renewable energy development goals.  In a process similar to that already adopted in Texas, the RETI process entails identifying Competitive Renewable Energy Zones (CREZs) from which renewable energy could be brought to California consumers.  Not surprisingly for the power-importing state, CREZs could be outside as well as inside California, although designation of external CREZs to serve California may not be well received in neighboring states.

The RETI process should complement the California Independent System Operator’s (CAISO) development of transmission financing rules.  The CAISO’s FERC-approved trunkline proposal provides for sharing of costs between interconnecting renewable generators, together with subsidies from other transmission customers.  The CAISO is now working on a tariff proposal for the inelegantly named “Location Constrained Resource Interconnection” rules, and is expected to submit the proposal to FERC by the end of October. 

On the national stage, Senator Harry Reid, the Majority Leader from Nevada, has introduced a bill to promote renewable energy development.  The bill, S.2076, would require establishment of renewable energy zones and direct federal power administrations to identify the transmission needed to access renewable energy in the zones.  The prospects of the bill becoming law are uncertain.  At minimum, however, the bill signals increased awareness by senior policymakers of the need to foster transmission development to connect the nation’s vast renewable energy potential with the load centers in need of energy. 

Supreme Court to Hear Long-Term Power Contract Cases

The U.S. Supreme Court granted certiorari to review two Ninth Circuit decisions involving long-term contracts that were entered into during the 2000-2001 California energy crisis.  In a pair of decisions issued last December, Public Utility District No. 1 of Snohomish County, WA v. FERC and California Public Utilities Commission v. FERC, the Ninth Circuit held that the long-standing Mobile-Sierra doctrine and its "public interest" standard did not protect contracts from unilateral modification when they were entered in a dysfunctional market that caused prices to exceed a "zone of reasonableness."  The Ninth Circuit held that FERC should have reviewed the circumstances under which the contracts were entered, and possibly set those contracts aside if it found the prices to be unreasonable. 

Several groups of sellers sought Supreme Court review of the Snohomish and CPUC decisions to determine whether the Ninth Circuit's formulation of the Mobile-Sierra doctrine was appropriate.  Many argued the Ninth Circuit's view would upend contract certainty in electric markets, thereby inhibiting investment, if contracts could later be revised because of changes in the market, buyer's remorse, or other circumstances outside of a seller's immediate control.  Interestingly, FERC itself had asked the Supreme Court not to hear the cases, arguing that because these cases arose out of the "highly unusual context" of the 2000-2001 energy crisis they provided a "poor vehicle" for the Court to evaluate the proper application of the Mobile-Sierra doctrine to a complaint that rates were too high.

A seven-justice panel of the Supreme Court disagreed and granted certiorari in response to petitions filed by Morgan Stanley Capital Group and Calpine Corp. of the Snohomish decision.  (Chief Justice Roberts and Justice Breyer have recused themselves from the case, without explanation.)  The Court has not yet indicated whether it will grant certiorari petitions for the CPUC decision as well or will simply apply its decision in the Morgan Stanley and Calpine petitions to the CPUC case.  Briefs are due in November and December, and oral argument will likely be scheduled for sometime in the first quarter of 2008.

Commodity Futures Trading Commission Echoes Arguments of Alleged Manipulators of the Gas Futures Market

House Passes Energy Bill with 15% RPS Requirement, Other Clean Energy Initiatives; House and Senate Must Now Reconcile Vastly Different Legislation

On the heels of a Senate bill passed in June, the House of Representatives on August 4 passed a comprehensive energy bill by a vote of 241 to 172.  The House bill is drastically different from the Senate's energy legislation, and it appears the House and Senate face an arduous conference to reconcile the two versions, which contain drastically different approaches to energy policy.

In summary, the House bill:

• Incorporates a 15% renewable portfolio standard (RPS), requiring utilities to produce at least 15% of their electricity through the use of renewable energy resources (e.g., wind or solar power) by 2020;
• Sets a goal of eliminating greenhouse gas emissions by federal agencies by 2050;
• Establishes new efficiency standards for appliances, lighting and buildings, while promoting new technologies for transmitting and delivering energy to create a "smart grid;"
• Authorizes billions of dollars for research into sustainable energy sources and alternative fuels, including research into carbon dioxide sequestration efforts;
• Resolves the sticky issue of numerous "faulty" leases in the Gulf of Mexico that arose when the Department of the Interior erroneously executed leases with several oil and gas companies that provided the companies with excessive royalties, by requiring the oil and gas companies to either renegotiate the leases or pay a conservation fee before bidding on future leases; and
• Promotes international energy-efficiency standards and U.S. involvement in other international partnerships to address energy issues and climate change.

The House also passed a companion package of changes to the tax code, by a vote of 221-189.  The tax bill offers various incentives to encourage the use and production of renewable energy and energy conservation, including new tax credit bonds to encourage energy efficiency in residential property and more production of clean energy, and $3.6 billion in bonds for state and local governments to fund energy conservation efforts.  The bill pays for these tax incentives by repealing approximately $16 billion worth of tax breaks for oil and gas companies.

There are several notable absences in the House's bill.  For instance, the bill does not revoke or condition the backup transmission siting authority given to FERC in 2005's Energy Policy Act in so-called "national interest electric transmission corridors," a provision that has raised significant concern in states with controversial transmission projects, like New York and Virginia. Similarly, the House bill does not set new corporate average fuel economy (CAFE) standards for cars and trucks, nor does it provide any support for coal-to-liquid production, both of which were contained in the Senate's energy bill.

It may prove a substantial battle to reconcile the House's and Senate's legislation.  While both bills included some of the same provisions, including requirements for research and development of carbon sequestration, biomass resources, and cellulosic ethanol and biodiesel, the two versions appear to be quite far apart on several major policy issues.  Key differences include:

• the House's inclusion of an RPS, which the Senate bill did not contain;
• the House bill's expanded energy efficiency provisions, which are more expansive than the Senate's version, which only included new standards for appliances and lighting;
• the House tax bill's rescission of approximately $16 billion in tax breaks for oil and gas companies, which the Senate bill does not contain;
• the Senate's inclusion of increased CAFE standards, requiring 35 mpg by 2020 for cars, SUVs, and small trucks, which the House bill omitted;
• the Senate bill's ethanol mandates, which require that the use of ethanol increase by sevenfold by 2022 and that 85% of cars manufactured by 2015 be capable of running on E-85 fuel (a blend of 85% ethanol and 15% gasoline); the House's bill did not contain such ethanol provisions; and
• the Senate bill's provision making it unlawful to charge an "unconscionably excessive price for oil products, including gasoline, which the House bill does not include.

The House and Senate will likely convene a conference committee this fall to attempt to iron out these differences.  Even if able to come to a compromise, White House approval is not assured.  Shortly after the passage of the House bill, the White House indicated its opposition to many of the bill's major provisions, stating that it would not "deliver American consumers or businesses more energy security, but rather would lead to less domestic oil and gas production, higher energy costs, and higher taxes." 

States Pursue Cleaner, Sustainable Energy, but not Too Quickly

While climate change legislative proposals and potential energy legislation continue  to muddle in the halls of Congress, individual states keep on creating their own requirements for checking green-house gas emissions and requiring greater use of renewable energy within their borders.  Whether this will lead to a mosaic of disparate standards and obligations or eventual standardization across state lines remains to be seen.

Despite relatively limited renewable energy production potential and a sharply growing population in Florida, Governor Charlie Crist (R) recently issued several executive orders intended to reduce greenhouse gas emissions and increase renewable energy use.  The orders direct the state’s public service commission to initiate a rulemaking intended to achieve a renewable portfolio standard (RPS) of 20%; call for capping utility greenhouse gas emissions at their 2000 level by 2017, reducing them to their 1990 level by 2025, and to 20% of their 1990 level by 2050; and implement other measures such as new interconnection standards, net metering, and requiring state agencies to take additional energy efficiency measures.

Hawaii already has an RPS, and its legislature recently added climate change legislation.  Its objective is to reduce the level of greenhouse gas emissions in the state to 1990 levels by 2020.  New Jersey – a densely populous state with limited renewable energy production – also added climate change legislation to its existing RPS requirements.  Under the new law, greenhouse gas emissions would be reduced approximately 15% below 1990 levels by 2020 and 80 percent by 2050. 

California and Washington already have both an RPS and climate change legislation.  While the mandates of all these states vary, they all push far into the future – 2050 – the most severe level of cuts, a move that may be reflect the technological challenges, but also resonates like a promise to start a diet tomorrow, or later. 

House Weighs Federal "Smart Grid" and Other Efficiency Enhancements

Among energy initiatives that Congress is considering this summer, one would highlight smart grid technology on the national stage.  In hopes of not only making the U.S. grid more reliable and efficient, but also more secure and independent—often-used phrases in Congressional energy circles—the Energy and Commerce Committee approved one measure that would establish a federal Grid Modernization Commission to implement smart grid technologies. 

The proposed nine-member Commission would monitor smart grid developments, develop common standards and protocols for smart grid technologies, identify barriers to implementation and propose solutions, coordinate federal and state agencies to implement smart grid efforts, and report to Congress biennially on the progress made in modernizing the electric grid system. 

The measure would also create a federal matching grant program, funded with $250 million for 2008 and $500 million for each of the years 2009-2012, to reimburse one quarter of the costs of certain smart grid investments.  The measure would amend section 111(d) of the Public Utility Regulatory Policies Act of 1978 to require states to consider regulatory standards that would allow utilities to include smart grid investments in rates, "decouple" utility profits from the volume of electricity sold, and require utilities to make time-sensitive supply, cost, price, and other information available to consumers to inform their use of smart grid technologies and demand response. 

Finally, the measure also would amend the National Energy Conservation Policy Act to require federal agencies to reduce their peak electricity consumption by 2 percent each year for 10 years, or make that percentage available as demand response, and report to Congress on the results.  The Grid Modernization Commission would also be tasked with developing a national action plan to achieve demand response poten