Energy Legal Blog

No Consensus on Securing Long-term Generation Adequacy

Regional efforts to ensure long-term generation adequacy reveal a wide range of views by various interest groups who either support or to varying degrees oppose the market rules being proposed to ensure that there is sufficient generation available in all regions of the country.  A PJM effort to revise its plan is heating up, while the battle in New England continues and a new plan is approved in California.

Citing growing concerns about generation retirements and looming capacity shortages, PJM filed with FERC in late August a proposed Reliability Pricing Model (RPM).  The RTO proposes RPM as a replacement to the simpler installed capacity model it has used since starting its bid-based energy markets in 1997.  The new resource adequacy plan resembles in various ways the capacity market of the neighboring New York Independent System Operator.  The RPM includes a downward-sloping demand curve for pricing of capacity, locationally-different prices in response to shortages in constrained regions, a four-year forward capacity procurement, enhanced monitoring and mitigation for capacity markets, and various other features such as allowing demand response and new transmission to compete in capacity markets.  Numerous parties responded to the proposal with a wide range of opinions, including claims by certain utilities that RPM is not necessary because most areas within the RTO have no supply shortages, as well as general support from generator interests who claim the existing capacity rules are inadequate.  Tension between state and federal regulators was evident in the comments of the Organization of PJM States, consisting of the state utility regulators from states where PJM has a presence, which argued RPM would not accomplish its objectives and that FERC should convene a hearing on the RPM proposal.

Meanwhile, a contentious FERC proceeding to revise the resource adequacy mechanism in New England persists.  Earlier in the fall, parties in support and against ISO-New England’s locational installed capacity (LICAP) proposal presented oral arguments to the FERC Commissioners.  Previous administrative measures had included a hearing and several rounds of written arguments.  Despite this robust record, heated opposition to LICAP, primarily from Connecticut interests opposed to potential price increases caused by the locational differences in capacity pricing, has rendered FERC unwilling to approve the plan.  Instead, evoking past disasters, FERC recently warned that a California-style crisis might visit parts of New England if market rules aren’t revised to encourage more development of generation, and directed the parties to engage in settlement talks.  FERC also set a deadline of January 31, 2006 for the filing of any alternatives to the LICAP proposal.

Speaking of California, the state’s Public Utility Commission has adopted a long-anticipated resource adequacy plan for the state’s three largest investor-owned utilities, PG&E, Southern California Edison, and San Diego Gas & Electric as well as electric service providers and community choice aggregators.  As with the plans being promulgated and debated in other parts of the country, this plan is intended to encourage timely development of generation in areas where shortages might otherwise develop.  Entities covered by the plan would have to demonstrate by June 2006 that they have secured enough capacity to serve expected customer demand, plus a 15-17% reserve margin.  The contracts would have to identify the specific resources that provide capacity.  The PUC’s plan also acknowledges the need for localized electricity capacity requirements but defers implementation pending further consideration, and sets penalties that will rise to three times the monthly cost for new capacity as a sanction for a utility's failure to meet its resource adequacy obligation.  The bilateral liquidated damages contracts previously used in California to ensure resource adequacy will be gradually phased out.

No Payment Due for Reactive Power within the Deadband

In an order reinforcing its policy with regard to compensating generators for reactive power, FERC recently agreed with Entergy Services, Inc. ("Entergy") that the company is not required to pay non-affiliated generators for supplies of reactive power within their specified power factor range (the "deadband" range) so long as Entergy does not compensate its own or its affiliated generators for the same supplies.

According to its calculations, Entergy could be on the hook for millions of dollars in charges from independent power producers ("IPPs") for the provision of reactive power within the deadband range.  To avoid those charges, Entergy asked FERC in September to affirm that the utility prospectively need not pay those charges so long as it stops paying its own or affiliated generators for comparable reactive power service.  The utility argued that by providing the reactive power, IPPs are merely meeting obligations to which they are already subject under their interconnection agreements, and that they should not be compensated for a "service" that provides no grid-wide benefits.

FERC agreed, citing an earlier case in which it decided that transmission providers must compensate generators for reactive power only when directed by the transmission provider to operate outside the deadband.  In addition, FERC pointed to its Order 2003 for its specific provision that interconnecting generators should not be compensated for operating within the deadband, since they are merely meeting their obligations by doing so.  FERC also approved Entergy's associated proposal to set the charges it currently levies on its customers for its own generators' provision of reactive power at zero, thereby freeing Entergy from within-the-deadband reactive power charges from non-affiliated generators.

FERC Seeks Comments for Competition Task Force

Acting on behalf of a multi-federal-agency Electric Energy Market Task Force, FERC published on October 13 a notice asking questions intended to assess the competitiveness of the nation’s wholesale and retail electric power markets.  The Domenici-Barton Energy Policy Act of 2005 (EPAct 2005) established the Task Force  — comprising the Antitrust Division of Justice, FERC, the Federal Trade Commission, the Department of Energy, and the Rural Utility Service of Agriculture — and charged it with studying and analyzing “competition in electric power markets.”   Leading the Task Force, FERC subtly converts the statutory charge into one of studying and analyzing the “critical elements” needed to achieve competitive and robust wholesale and retail markets.  Public responses to FERC’s questions and other topics pertaining to electric power markets must be submitted to the agency by November 11.

FERC’s questions not surprisingly focus on contentious topics that have come before federal and state regulators with increasing regularity in recent years.  The questions divide between wholesale and retail markets, but also often probe how wholesale and retail markets interact under competition.  Noteworthy areas of inquiry into wholesale markets include questions on the existence and consequences of RTOs and organized short-term (day- and hour-ahead) markets.  How do they affect costs and prices?  How do such markets affect bid/ask spreads and what are the directions of those spreads (narrowing or expanding)?  Can demand resources be offered and, if so, on what terms?  The Task Force also appears keen on learning about the extent of trading in futures and forward contracting generally.

Reflecting FERC’s apprehensions about the recent trend toward consolidating the ownership of generation, particularly into the ratebase of traditional franchise utilities, the October 13 notice poses a number of questions about the ownership of generation assets and whether available generation is keeping apace with demand.  How much non-utility generation is leaving the competitive sector and being converted into part of traditional utility ratebase?  The Task Force also wants to know what barriers stand in the way of developing new generation, including financing and economical interconnection.  And reflecting the contentious battles over locational generation capacity requirements in relation to demand in New England and the PJM Interconnection, FERC asks how generation adequacy is being achieved, which implicitly invites views on the relationship between fixed capacity obligations of load servers, on the one hand, and access to robust markets in generating reserves, on the other hand.

A series of questions posed in the October 13 notice betray concern over the direction of retail competition and consumer choice programs.  How, the Task Force asks, should the effectiveness of these programs be measured?  Are consumers well informed of their supply options?  Are supplier options sufficiently robust and are adequate supplies available to last-resort providers?  A particularly noteworthy line of questions asks not only whether consumers can participate in the supply side of the market through demand response, but whether they are empowered to do so effectively through access to time-of day and seasonally differentiated rates and metering.

When the public comments are in, it will be interesting to see the extent to which opponents of competition in electric power markets use the occasion of the October 13 questions to highlight perceived failings of competitive markets or to defend recent consolidations of generation back into traditional utility ratebase.

FERC Reconsiders Who Pays RTO Expansion Costs

In the midst of growing concerns among states and utilities about the costs of joining RTOs, FERC has agreed to take a second look at an order allocating several utilities' costs of joining the PJM Interconnection.  On October 17 FERC announced that it would reconsider its May 2005 holding that the costs associated with integrating American Electric Power (AEP), Commonwealth Edison, and Dayton Power & Light Company into PJM should be recovered from the three companies' customers, rather than all PJM customers collectively.  Citing the need for regulatory consistency with other cases in which a utility becomes a new member of an existing Regional Transmission Organizations (RTO), as well as serious policy concerns raised by the companies and the Public Utility Commission of Ohio (PUCO) who had requested rehearing of the prior order, FERC agreed that imposing the costs of joining an RTO solely on the customers of a new member could have the unintended effect of discouraging utilities from joining an RTO.  This outcome would stand in direct contravention to FERC's long-pursued goal of encouraging RTO membership.  FERC also evinced sensitivity to PUCO's assertion that, had it known that the Ohio customers of AEP and Dayton would bear the full cost of their joining PJM, it might not have approved the move of the two utilities to PJM.

In its October 17 order, FERC also encouraged the parties to settle the issue of how AEP, Commonwealth (an Illinois utility), and Dayton would recover the non-capital expenses incurred by PJM in integrating the companies into its interconnection.  These costs totaled $31.6 million and went to reimburse PJM for the costs of developing systems and infrastructure to support their integration.  FERC promised to hold a trial-type evidentiary hearing on the issue if a settlement is not forthcoming.  [American Electric Power Service Corporation on Behalf of Appalachian Power Company, et al., 113 FERC ¶ 61,050 (2005)]

FERC Explains Its Policy on New Penalty Authority

The Domenici-Barton Energy Policy Act of 2005 (EPAct 2005) expanded and increased administrative, civil and criminal penalties for violations of the Natural Gas (NGA), Natural Gas Policy, Federal Power (FPA), and Interstate Commerce Acts, including new NGA 4A and FPA 222 on market manipulation.  See Congress Passes New Energy Bill.  In an October 20 Policy Statement on Enforcement (PSE), the FERC notifies the industry how the agency proposes to dole out these penalties to malefactors.  The central admonition of the PSE to the power industry is:  Get thee a comprehensive compliance program and your punishments for errant infractions will be small and few; without such a program, they will be severe and many.  FERC joins other federal law enforcement agencies in further admonishing energy business organizations that willing and timely cooperation in investigations of their agents will lessen the likelihood of sanctions against the company itself, but failure to cooperate could result in penalties against the company as well as its agents.  The seriousness of a violation will also influence the punishment.  To be considered, public comments on the proposed rule must by submitted to FERC by November 23, 2005.

FERC discloses in the PSE that for all violations of the statutes the agency administers or regulations implementing those statutes, FERC will require the violator to disgorge any resulting unjust and unreasonable profits, to the extent they can be determined or reasonably estimated.  Beyond disgorgement, the scope and severity of administrative sanctions and civil or criminal liability will turn on the existence of a comprehensive compliance program, cooperation in any investigations, and the severity of the offense.   Following the example of the Securities and Exchange Commission and Commodity Futures Trading Commission, FERC declines to adopt any specific schedule of penalty severity.  Using its new EPAct 2005 authorities, in addition to administrative sanctions ― disgorgement of unjust profits and conditioning or suspending market-pricing authority and (blanket) certificates ― FERC can pursue civil penalties of up to a maximum of $10,000 to $1 million for violations of any provision of the NGA, NGPA or Part II of the FPA, and refer criminal violations to the Justice Department for prosecutions up to $1 million and five years incarceration for statutory violations and $25,000 per day for regulatory violations.

Given the greatly expanded range of penalties, it becomes imperative that energy companies understand what FERC means by a comprehensive compliance program, investigatory cooperation, and the seriousness of an offense because these are the factors that will mitigate punishments under the PSE.   In order for a compliance program to be deemed comprehensive and worthy of penalty mitigation, FERC will require that it address all legal and regulatory obligations, be memorialized in a widely disseminated document, supported by senior management (for example in compensation decisions and disciplinary actions), updated periodically in training programs, and intermittently audited.

For purposes of assessing whether an energy company is cooperating in its investigations, FERC will look to a wide array of factors that largely track Justice's so-called Thompson memorandum on the Principles of Federal Prosecution of Business Organizations.  In addition to stopping quickly any violation that comes to light, the company will be expected to produce internal records, investigations or audits, encourage all employees to cooperate in FERC's investigation, provide FERC access to employees with knowledge of the investigation, identify culpable employees, and audit the consequences (i.e., revenues and profits that flowed from the violation).  The PSE does not expressly instruct that an energy company will be required to waive attorney-client privilege in order to be deemed cooperative, but it implies as much.

In gauging the seriousness of an offense, FERC explains that it will consider whether there was loss of life or endangerment, damage to property or the environment, harm to energy markets, the cost, the wrongdoer's gains, whether the wrongdoer acted willfully, whether senior management was involved, and whether repeat offenses are involved.  [Enforcement of Statutes, Orders, Rules and Regulations, 113 FERC ¶ 61,068 (2005)]

FERC Looks to Past for Future Anti-fraud Enforcement

In the Domenici-Barton Energy Policy Act of 2005 (EPAct 2005), Congress looked to the antifraud provisions of the Securities Exchange Act of 1934 ('34 Act) in adding new section 4A of the Natural Gas Act (NGA) and new section 222 to the Federal Power Act (FPA), which makes it unlawful for any entity (including municipal and cooperative utilities) to employ any "manipulative or deceptive device or contrivance (as those terms are used in section 10(b) of the [Exchange] Act . . .) in contravention of such rules and regulations as [FERC] may prescribe" to protect ratepayers in connection with the purchase or sale of natural gas, electric energy or the transportation or transmission of either.  Section 10(b) of the Exchange Act similarly prohibits the use of any manipulative or deceptive device or contrivance in connection with the purchase or sale of securities registered on a national exchange; case law spanning 70 years broadly defines what is manipulative or deceptive.  Not surprisingly, in an October 20 notice of proposed rulemaking, FERC proposes to implement new NGA 4A and FPA 222 through new rules modeled on the Securities and Exchange Commission's (SEC) Rule 10b-5 for implementing the section 10(b) of the '34 Act.  To be considered, public comments on the proposed rule must by submitted to FERC by November 23, 2005.

The proposed new rule tracks nearly word-for-word the text of the SEC Rule 10b-5.  In so doing, it proscribes both acts of commission and omission, and, consistent with the directives of EPAct 2005, it is not limited to natural gas companies or public utilities, but rather extends to government utilities, coops, and other market participants who traditionally have fallen outside of federal regulation.  Specifically, the proposed rule, like Rule 10b-5, makes it unlawful for any "entity, directly or indirectly (1) to use or employ any device, scheme, or artifice to defraud, (2) to make any untrue statement of material fact or to omit to state a material fact" needed to make a statement "not misleading, or (3) to engage in any act, practice, or course of business that operates . . . a fraud or deceit . . . in connection with purchase or sale of" natural gas or electricity or the purchase or sale of transmission or transportation subject to FERC's jurisdiction.

FERC emphasizes in the rulemaking that the virtue of parroting SEC Rule 10b-5 is the wealth of case law on the books interpreting the key words and concepts of what is made unlawful.  Rule 10b-5 does so primarily in the context in which an officer, director, or person with a fiduciary relation to a company buys or sells its securities based on material, non-public information ― i.e., insider trading.  It has also been used in cases where a company issues misleading information or keeps quiet when it has a duty to disclose.  Most other applications are unique to the securities business.  In the rulemaking, FERC further notes that the antifraud provision of the Commodity Exchange Act, section 4b, parallels section 10(b) of the '34 Act and new NGA 4A and FPA 22, and that precedents under the Commodity Exchange Act will also be available to help interpret the proposed new natural gas and electric power rules.

Rule 10b-5 under the '34 Act is no stranger to the energy business, however.  The 24-year sentence of Jamie Otis of Dynegy was based in part on 10b-5 violations in connection with hiding a $300 million loan.  The plea bargain of Enron's Andrew Fastow and the upcoming prosecutions of Enron's Ken Lay and Jeff Skilling will play out in part under 10b-5.

Because of the securities and commodities case law that will be available to help interpret FERC's proposed new rules implementing NGA 4A and FPA 222, the industry stands to confront more stationary goal posts than it has under FERC's current Market Behavior Rule (MBR) 2, which, among other things, prohibits transactions "lacking a legitimate business purpose and that are intended to or foreseeably could manipulate market prices . . . conditions . . . or rules . . . ."  In the rulemaking FERC assures the industry that will not seek duplicative sanctions under the proposed new rules and MBR 2 for the same conduct or transaction.  And FERC asks whether MBR 2 should be revised or repealed if the proposed new rules base on SEC Rule 10b-5 are adopted.  [Prohibition of Energy Market Manipulation, 113 FERC ¶ 61,067 (2005)]

We Gotta Get Out of this Place: LG&E and KU Ask to Leave MISO

Unimpressed with the touted benefits of RTO membership, LG&E Energy has petitioned FERC to allows its operating utilities Louisville Gas & Electric and Kentucky Utilities to withdraw from the Midwest Independent System Operator (MISO).  LG&E Energy instead wants Tennessee Valley Authority to serve as the utilities’ reliability coordinator and the Southwest Power Pool as administrator of their tariffs.  In a particularly stinging rebuke, LG&E Energy claims that even with separate entities administering reliability and  the tariff, the arrangement would be superior to the one with MISO.   The utilities want their withdrawal to take effect by the summer of 2006.

The two utilities were anchor members of MISO, but have been looking to bolt for some time.  In 2003, the Kentucky Public Service Commission had ordered the utilities to perform cost-benefit studies on MISO membership.  A study by an outside consultant had concluded that costs outweighed benefits.  Predictably, MISO disagreed, citing a litany of benefits such as reliability and consistent regulatory control.  Reports suggest that the utilities’ decision to leave was heavily influenced by the significant costs incurred by MISO as it devised and then operated its Day 2 market, which includes LMP-based energy markets.  The utilities will seek a simpler regime for their control areas, based on the independent coordinator of transmission (ICT) model pioneered by Entergy.  The MISO is on record stating it will not seek to block the utilities’ withdrawal, but the amount of an exit fee remains to be quantified.   

DOE Increases Reporting Requirements in Effort to Increase Response to Natural Gas Supply Needs

In an effort to improve the country's ability to respond to future energy-related supply problems and to keep the general public informed on the current state of natural gas trading, the Department of Energy's Office of Fossil Energy ("OFE") has added a new monthly reporting requirement to existing and future Orders authorizing the import and export of natural gas and liquefied natural gas ("LNG").   The first monthly report, for the reporting period November 1, 2005, through November 30, 2005, must be filed no later than December 30, 2005, and can be filed electronically through OFE's website - www.fe.doe.gov.

OFE regulates natural gas imports and exports pursuant to section 3 of the Natural Gas Act.  Before the new rule, OFE collected information about natural gas and LNG import and export activities on a quarterly basis.  In accordance with the Department of Energy's Natural Gas Data Collection Initiative to improve the way the Department gathers and disseminates information about the use and origin of natural gas supplies in the U.S., OFE has expanded its collection activities.  The monthly reports must include information pertaining to the country of origin of an import or country of destination for an export, the points of entry and/or exit, and the total volume at each point of entry and/or exit for the month.

Proposed Rules Will Cabin the Future Role of Qualifying Facilities

In its latest effort to implement the mandates of the Energy Policy Act of 2005 (EPAct 2005), FERC has proposed to amend several of its regulations concerning qualifying cogeneration and small power production facilities (QF).  The proposed changes would tighten the criteria used to evaluate the eligibility of cogenerators for QF designation, discontinue restrictions on QF ownership, and eliminate some exemptions that QFs have enjoyed from regulatory requirements.  To be considered by the agency, public comments on the proposed rulemaking must be received 21 days after publication in the Federal Register, likely sometime in mid-November. 

To ensure that cogeneration QFs' thermal output is used in a "productive and beneficial manner," FERC proposes to discontinue its essentially irrebuttable "presumptively useful" standard normally applied to its evaluations of cogenerators seeking QF status.  This presumption allowed "sham" QF designations where there was no real use for a facility's thermal output.  The presumption of usefulness would now be rebuttable, with FERC considering the uses a cogeneration facility makes of its thermal output.  FERC also must now ensure that the electrical, thermal, chemical and mechanical output of a new cogeneration facility is used fundamentally for industrial, commercial, or institutional purposes and is not intended for sale to an electric utility (rendering the facility a so-called "PURPA machine").  FERC proposes to require applicants for QF status to explain how the cogeneration facility meets this requirement, and review those explanations on a case-by-case basis.  FERC would also require applicants for new QF certification to describe how they are progressing in the development of efficient electrical energy generating technology, and seeks comment on its proposal to require new coal-burning cogeneration facilities to meet an efficiency standard similar to that applied to natural gas and oil-burning cogeneration facilities.  In light of these changes, FERC asks whether self-certification procedures should continue to be available to new applicants for QF status.

FERC also proposes to implement EPAct 2005's elimination of the existing restriction that a traditional public utility not own more than 50 percent of a QF.  That restriction is what invited new entry and competition into power generation in the 1980s and 1990s.  Removal of the ownership restriction will allow traditional utilities to own majority interests in a QF.

Historically, FERC has exempted most QFs from Sections 203, 205, 206, 208, 301 and 304 of the Federal Power Act (FPA).  Based on the elimination of the QF ownership restriction, as well as its reasoning that these exemptions are no longer necessary to encourage the development of cogeneration and small power production facilities, and that their continuation would remove many sales of generation from any regulatory oversight at all, FERC asks for comment whether these exemptions should be continued or eliminated.  FERC proposes to retain the exemptions only for smaller QFs and asks whether QFs that are independent of traditional utilities, transmission providers, and other power producers should continue to enjoy some or all of the existing exemptions.  QFs would not, however, be exempt from the new provisions that EPAct 2005 added to the FPA, such as the prohibitions against misreporting price and transmission-availability information, and market manipulation.

If adopted, these proposed changes to FERC's regulations, in combination with EPAct 2005's elimination of the PURPA mandate requiring traditional public utilities to purchase QF power at avoided-cost prices (which FERC proposes to address in another forthcoming rulemaking) would result in a more-limited future role for QFs.  [Revised Regluations Governing Small Power Production and Cogeneration Facilities, 113 FERC ¶ 61,020 (2005) NEW MATTER]

FERC Shoots Down First Public Utility to Seek Waiver of QF Purchase Requirement

On the same day that it proposed a rulemaking implementing many provisions of the Energy Policy Act of 2005 (EPAct 2005) regarding qualifying small power production and cogeneration facilities (QFs), FERC shot down the first request of a traditional public utility under EPAct 2005 for exemption from the requirement that it purchase the output of a QF at an avoided-cost price.

Alliant Energy was the first of several utilities to request FERC to waive its power purchase requirements with respect to QFs within the service territories of two of its operating utilities [See Alliant Becomes First to Try for EPAct Waiver, 9/22/2005], based on EPAct 2005's elimination of that requirement in certain cases.  This week FERC denied the request, without prejudice, on procedural grounds.  FERC did not engage Alliant's contention that proximity to markets administered by the Midwest Independent System Operator provides a "competitive market" for QFs, the existence of which is a prerequisite under EPAct 2005 for exemption from the mandatory purchase requirement.  Instead, FERC pointed to Alliant's failure to meet EPAct 2005's requirement that an applicant for exemption provide "sufficient notice to potentially affected qualifying … facilities."  According to FERC, mere publication of the notice of the application for waiver of the mandatory purchase requirement in the Federal Register did not satisfy the "sufficient notice" requirement.  FERC clarified that any entity seeking relief from this power purchase requirement must identify to FERC any QFs that would be affected, including both existing QFs and QFs under development.  FERC plans to establish a rulemaking in the near future to address the statutory elimination of the power purchase obligation contained in the EPAct.  [Alliant Energy Corporate Services, Inc., 113 FERC ¶ 61,024 (2005) UPDATE]

Energy Department Auditors Fault FERC Cybersecurity

The Energy Department’s Inspector General (IG) has issued a report concluding that while FERC’s cybersecurity program continues to improve, flaws remain in its unclassified cybersecurity program.  The IG’s evaluation, required by the Federal Information Management Security Act, states that, despite some recent improvements, FERC’s cybersecurity includes various weaknesses:

• Inadequate password management caused insufficient controls over access to some systems.
• Some software with known security flaws was not replaced, and some users were provided access at higher levels than their duties required.  
• Not all cybersecurity weaknesses were tracked to their causes and resolved.

According to the report, FERC overlooked the problems because its officials had failed to complete compliance evaluations required by general federal requirements and agency-specific rules.  These failures, the IG explained, led to a risk of disruption of operations, modification or destruction of sensitive data or programs, or theft or improper disclosure of confidential business information.  For security reasons, the report did not identify specific vulnerabilities, but stated that many of them had already been redressed.  FERC’s information technology budget in Fiscal Year 2005 was $27 million, of which approximately three percent was spent on cybersecurity measures. 

FERC, CFTC to Coordinate Requests and Share of Proprietary Information

In response to a directive in the recent Energy Policy Act of 2005 (EPAct 2005), on October 12 FERC and the Commodity Futures Trading Commission (CFTC) announced that the agencies' respective Chairs, Joseph T. Kelliher and Reuben Jeffery III, had entered into a memorandum of understanding (MOU) on the sharing of information and providing confidential treatment for proprietary energy trading data.  While the MOU makes clear that any sharing of information between the two agencies will not constitute a waiver of confidentiality, the MOU should lead to an increased flow of information between the two agencies, who frequently conduct investigations, and oversight and enforcement activities concerning many of the same energy markets and their participants.  Both agencies pursued investigations, often duplicative, into allegations of false reporting of natural gas and power wholesale prices to index publishers in 2000 and 2001.

In EPAct 2005 Congress instructed the two agencies to come to an understanding within six months in order to better ensure that their information requests to markets are "properly coordinated to minimize duplicative information requests" and "to address the treatment of proprietary trading information."  FERC was quick to point out that the agencies had completed the MOU four months ahead of schedule, before the winter heating season, when energy prices are typically stressed  and may require additional FERC and CFTC vigilance.  CFTC Chairman Jeffery expressed the belief that the MOU would lead to a "more effective and efficient working relationship with FERC" as both agencies actively work to assure price integrity in the natural gas and other energy markets.

The MOU lays out procedures the FERC and CFTC will use in obtaining industry information, providing that the CFTC will turn over to FERC any futures and options trading data or other market information that FERC requests, and conversely requiring FERC to turn over any information it has that the CFTC requests.  However, the MOU requires that both agencies must keep any data surrendered to the other confidential and non-public pursuant to their respective regulations.  In addition, FERC and the CFTC may only disclose information obtained from the other in certain circumstances.  FERC may disclose information received from the CFTC only in certain administrative or enforcement proceedings, and the CFTC may disclose FERC-obtained information only in actions or proceedings to which either CFTC or the United States is a party.

The MOU is likely to lead to heightened cooperation between FERC and the CFTC.  The two agencies agreed to coordinate their third-party notice requirements and to communicate with each other in order to avoid duplicative discovery where possible.  Importantly, the agencies also agreed to coordinate their oversight, investigative, and enforcement activities on a regular basis.  To facilitate this coordination, each agency's oversight and enforcement staff are authorized to share information concerning their ongoing investigations and oversight and enforcement proceedings. 

The MOU also addressed the treatment of proprietary information, and each agency agreed it would obtain the other's prior written permission before releasing such information.  FERC and the CFTC also agreed to notify each other whenever they received demands or requests to disclose information provided by the other, such as Freedom of Information Act requests, subpoenas, court orders, or informal requests.  However, under the MOU, the agencies are not required to keep aggregate data or data derived from proprietary information confidential. 

Updates to FERC's Merger and Acquisition Rules in the Works

In one of its latest move to implement the EPAct of 2005, FERC, on October 3, 2005, issued a notice of proposed rulemaking (NOPR) that proposes amendments to its merger policy regulations, in accordance with the EPAct amendments to section 203 of the Federal Power Act.  To be considered by the agency, public comments on the NOPR are due November 7, 2005.

Section 203 is the provision that requires FERC's authorization for certain mergers, acquisitions, and dispositions of jurisdictional assets.  Currently, FERC focuses on three major factors when analyzing whether a proposed transaction is consistent with the public interest, as required by section 203: the effect on competition; the effect on rates; and the effect on regulation.  The amended section 203 language adds a new factor to FERC's review process, requiring that FERC find that a transaction will not result in cross-subsidization, such as where a regulated utility subsidizes a non-utility associate company at ratepayer expense.  FERC seeks comment on what evidence parties should be required to submit to support their positions here.

EPAct 2005 also amends section 203 to include an increase in the value threshold from $50,000 to $10 million for certain transactions subject to section 203, and an extension of FERC's review to include transactions involving the transfer of electric generation facilities and the transfer of public utility holding companies.  With regard to the "value" threshold, FERC seeks comment on whether the "market value" is an appropriate benchmark for determining whether asset transfers or the sale of transmission facilities or existing generation facilities trigger the jurisdictional value threshold; for wholesale contracts, FERC proposes to define "value" based on total expected contract revenues over the remaining life of a contract.

EPAct 2005 also adds a requirement that FERC adopt an expedited review procedure for certain classes of transactions.  In its NOPR, FERC proposes that the following transactions generally receive expedited review: a disposition of only transmission facilities; certain transfers involving generation facilities that do not require an Appendix A analysis under FERC's Merger Policy Statement; internal corporate reorganizations that do not present cross-subsidization issues; and the acquisition of a foreign utility company by a holding company with no captive customers in the U.S.  It is intended that the new rules will take effect on February 8, 2006.  [Tansactions Subject to FPA Section 203, 113 FERC ¶ 61,006 (2005)]

Pennsylvania Lacks Competition in Retail Natural Gas Supply Market

In a recent report released to the Governor and to the state General Assembly, the Pennsylvania Public Utility Commission ("PAPUC") concluded that competition in the Pennsylvania retail natural gas supply market simply does not exist.  This, of course, is not good news for ratepayers who are watching prices skyrocket due to increased demand worldwide as well as the effects of recent hurricanes on transportation and distribution lines in the South.  As a result of its findings, the PAPUC has determined that it will convene natural gas industry stakeholders to examine ways to increase competition and develop recommendations for changes to market structure and operation.

Pursuant to the 1999 Natural Gas Choice and Competition Law, the PAPUC was required to investigate the level of competition five years after the law had gone into effect.  The purpose of the law was to create opportunities for customers to purchase gas from independent suppliers. However, the PAPUC found that it is difficult for suppliers to enter the retail natural gas market in Pennsylvania because of differing security requirements and varying penalties that are not assessed in a cost-based manner by the natural gas distribution companies.  Additionally, the PAPUC found that the marketplace currently lacks accurate and timely price signals.   Although the report was supported by all five Commissioners, Commissioner Bill Shane expressed concern that a new stakeholder process would be a "futile exercise."

Wyoming Finances Power Line Project to Improve Transmission and Reliability

Using bonds issued through the state's mineral trust fund, the Wyoming Infrastructure Authority ("WIA") recently financed its first power line project, the Basin Electric Power Cooperative's 130-mile $50 million 230-kilovolt transmission line to be located in northeastern Wyoming.  The Basin Electric project — the first step in WIA's forecasted 500 miles of needed transmission — is expected to deliver power within the state and facilitate exports to neighboring California, Colorado and Utah.  The circuit on the Basin Electric project is anticipated close by the end of 2008.

The WIA's charter tasks the authority with conceiving, funding, constructing, maintaining and operating electric transmission line projects using up to $1 billion in state-backed bonds.  It is intended that the new transmission lines will provide export market access for the substantial bituminous coal deposits in the state's Powder River Basin as well as up to 8,000 megawatts of wind generation proposed for development in the Cowboy State.

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.

AES Corp.'s Proposed Boston Harbor LNG Project Meets with Tentative Approval

After rejecting two similar projects in or near their state, Rhode Island officials made clear in recent weeks that AES Corp.'s latest proposal to build a new liquefied natural gas ("LNG") facility on an island in Boston Harbor met with their approval.  Reportedly, AES Corp. is considering leasing Outer Brewster Island, a state-owned island eight miles from the Boston shoreline, in the hopes of building a new LNG facility there.

Rhode Island's support of an Outer Brewster Island facility stands in sharp contrast to its vehement opposition to two other projects in the area, the Weavers Cove project, planned for Fall River, Massachusetts, and a proposed terminal expansion by KeySpan Corp. in Providence, Rhode Island.  On September 20, 2005, Rhode Island Attorney General Patrick Lynch sent a letter to President Bush calling the proposal more sensible than Weavers Cove or the KeySpan expansion and calling on the President to urge FERC to stop considering these proposals.  Rhode Islanders feared that these two projects would pose serious security risks to the area because they were either too close to large population centers or would require LNG tankers to navigate the narrow Narraganset Bay.  AES Corp.'s proposal, on the other hand, is two miles from the nearest population center (in Hull, Massachusetts) and ten miles from downtown Boston.  Moreover, tankers could sail directly to Outer Brewster Island without having to enter narrow waterways.

Despite smooth sailing with Rhode Island, the AES project remains in its infancy and could yet be scuttled by opposition in Massachusetts.

FERC Pursues Unique Remedies for MidAmerican's Open-Access Transgressions

Not only did FERC affirm its staff's findings that in recent years MidAmerican Energy Co. persistently had violated core provisions of its open-access transmission tariff, but in a September 29 order FERC pursued unique remedies against MidAmerican ― remedies that underscore the premium that FERC places on improvements to the transmission grid.  The violations were documented in an audit, from January 1, 2002, through April 30, 2004, of MidAmerican's compliance with its open-access transmission tariff provisions relating to interconnection and transmission services, Standards of Conduct, OASIS system, and the electronic posting requirements of Order No. 2004.

In its audit, FERC staff found three major open-access fouls: (1) MidAmerican permitted its wholesale merchant function to use network transmission service to import power to make possible off-system (i.e., non-network) sales;  (2) MidAmerican provided transmission services to its wholesale merchant function that were not clearly available to unaffiliated entities; and (3) MidAmerican did not require its wholesale merchant function to comply with certain tariff provisions concerning the designation of network resources.  In contrition, MidAmerican acceded to FERC's demand that it build $9.2 million in unplanned transmission system upgrades and accelerate $14.7 million in planned transmission improvements.  [MidAmerican Energy Company, 112 FERC ¶ 61,346 (2005)]

FERC Staff Clears Powerex of Alleged Manipulative Bidding

FERC took the unusual step on September 26 of releasing publicly a staff report on a confidential investigation of bidding behavior by importers at the interties into the California Independent System Operator ("CAISO") control area.  The report cleared Powerex, the power marketing affiliate of BC Hydro, of any wrongdoing and found that the problems with bidding at the CAISO's interties were a product of the CAISO's tariff and not any impropriety.  In releasing the Staff report, FERC said it hoped to clear up confusion regarding its Market Behavior Rule 2, which prohibits market manipulation, by providing an illustration of a wholesaler pursuing "legitimate business interests." FERC also hoped to grant some closure to the contentious CAISO intertie bidding issue, which the CAISO made public at a board meeting in March.

The investigation was initiated when the CAISO asked FERC staff to investigate potential manipulative bidding at its interties.  The CAISO alleged that from the implementation of its Phase 1B market redesign on October 1, 2004, through early March 2005, importers (and in particular, Powerex) were submitting offsetting incremental and decremental bids solely for the purpose of triggering and collecting "uplift" payments, although they were not actually delivering any net energy into the CAISO.  Under the CAISO tariff, uplift payments that were made to importers represent the difference between the CAISO's market clearing price and an importer's bid price.  These payments are awarded to importers to encourage competitive bidding at the CAISO interties.  The CAISO claimed that these uplift costs totaled approximately $18.5 million for this six month period and alleged that Powerex and other importers were manipulating its supplemental energy markets.

During its investigation, FERC staff examined whether Powerex had violated Market Behavior Rule 2 and CAISO Tariff Enforcement Provision 7.1, both of which prohibit actions or transactions that do not have a legitimate business purpose and are intended to or foreseeably could manipulate electricity market prices, conditions, or rules.  The staff investigators concluded that Powerex had not engaged in any wrongful behavior and had made its bids for the "legitimate business purpose of maximizing its physical energy purchases and sales in the CAISO" because its transactions had economic substance within the meaning of Market Behavior Rule 2.  Powerex could not have reasonably foreseen that its bidding behavior would result in high uplift payments, the investigators explained.  Moreover, they also reported that the CAISO had exaggerated its total uplift payments during the relevant period, finding only $4.6 million in uplift payments during the period under investigation.  Those payments were caused not by errant market participant behavior but due to the CAISO's rules then in place.  Transactions undertaken in contemplation of FERC-approved rules and regulations or at the direction of an ISO or Regional Transmission Organization do not violate Market Behavior Rule 2, the staff investigators explained.  In April the CAISO amended its tariff to decrease the amount of uplift payments that it will make.  [Intertie Bidding in the California Indpendent System Operator's Supplemental Energy Market, 112 FERC ¶ 61,333 (2005)]

AWEA and NERC Settle Reliability Dispute

The American Wind Energy Association ("AWEA") and the North American Electric Reliability Council ("NERC") asked FERC to accept their settlement on technical standards regarding wind generator interconnections, avoiding the public battle over reliability that was threatened when NERC complained that standards FERC previously proposed posed an “unacceptable risk to the reliability of the bulk electric system.”

In response to a 2004 petition for rulemaking from AWEA, FERC had adopted a rule allowing asynchronous generators such as wind plants to disconnect from the grid when voltage at the point of interconnection drops below 15%.  In a rehearing request last July, NERC argued that these low-voltage ridethrough standards fell short of NERC requirements.  Later discussions between NERC and AWEA led to the settlement, which proposes that, following a transition period, wind generators be able to remain on-line even if the voltage levels fall to 0%.  The transition period would give wind generators sufficient time to adopt technology to meet the stricter low-voltage ridethrough standards.  Individual transmission providers would, as before, be able to request deviations from these standards.

In light of the attention industry and government officials are giving to grid reliability, resolution of this dispute represents a step towards potentially greater integration of wind power in the nation’s electric power grid.