Energy Legal Blog

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.

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.

More problematic for Entergy was its proposal to pass through to transmission customers the costs that third-party generators may charge Entergy, under existing rate schedules, for reactive power outside the deadband.  FERC initiated an investigation into that proposal and set it for hearing, declaring that it could not determine on the record before the propriety of Entergy recovering from transmission customers the utility’s payments to third-party generators for reactive power outside the deadband.  [Entergy Serivces, Inc., 113 FERC ¶ 61,040 (2005) Update]

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.

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)]

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)]

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)]