Energy Legal Blog

FERC Tweaks, Codifies Market-Based Rate Program

After prolonged deliberations on its wholesale market-based rate program, FERC issued its Final Rule on the matter June 21, 2007.  The 670-page rule will become effective sometime in late August or early September ― 60 days after its publication in the Federal Register. 

Notably, in the Final Rule:

• As proposed in last year's Notice of Proposed Rulemaking (NOPR), FERC transformed its four-prong market power analysis into a more traditional horizontal and vertical market power analysis.  The "horizontal" analysis asks whether sellers have market power in generation, while the "vertical" analysis asks whether sellers have market power in transmission or can erect other entry barriers.  FERC codified restrictions on affiliate transactions ― the former fourth prong ― and will require tariff provisions that require market-based rate sellers to abide by these regulations.
• FERC divided sellers into two categories—Category 1 sellers, who are power marketers or power producers that own or control less than 500 MW of generation in a region and are not affiliated with franchised public utilities, and Category 2 sellers, who are all other sellers.  Category 1 sellers are no longer required to file triennial market power analyses, but instead FERC will monitor their market positions through change-in-status filings and electronic quarterly reports (both of which continue to be required of all sellers).
• FERC will now review sellers' triennial market power analyses on a rotating regional basis.  To facilitate its review, FERC divided the country into six regions, and will review two regions per year according to a schedule provided in Appendix D to the Final Rule.
• FERC retained its existing indicative screens for generation market power.  The "wholesale market share screen" measures a seller's share of the relevant geographic market; the "pivotal supplier screen" determines whether a seller is pivotal in the market and unilaterally can raise prices.  If a seller fails either screen, FERC presumes market power, which the seller can either attempt to refute or acquiesce in mitigation.
• FERC rescinded the exemption for generation facilities constructed after July 9, 1996.  Generators had argued the exemption was needed to encourage construction of new generation, but FERC disagreed, finding that as time goes on, more and more generating units would be subject to the exemption, making detection of market power more difficult.
• FERC provided guidance on identifying who "controls" generation for purposes of the both generation market power analysis and the change-in-status reporting obligation.  FERC declined to adopt generic presumptions of control, but instead will stick with a fact-specific analysis.  FERC's guiding principle is that if an entity can prevent generation from reaching a market, it "controls" that generation. 
• Transmission owners (and sellers affiliated with transmission owners) can continue to show they have mitigated transmission market power by operating under an open-access transmission tariff (OATT).  Although not automatic, FERC will now consider OATT violations as grounds for revocation of the seller's market-based rate authority so long as there is a "nexus" between the tariff violation and the market-based rate authority.  FERC generally will not revoke a seller's market-based rate authority for its transmission affiliate's tariff violation. 
• The newly codified affiliate restrictions continue to prohibit power sales between a franchised public utility with captive customers and affiliated power marketers with market-based rate authority (now known as "market-regulated power sales affiliates") without prior FERC approval.  
• The Final Rule modifies and codifies the existing "code of conduct" from market-based rate tariffs.  The regulations now specifically bar utilities from using third parties to circumvent the affiliate restrictions.  In addition, FERC created a specific exception to allow utilities to share with affiliates senior officers and directors, certain legal and administrative personnel, and field and technical personnel so long as these employees do not act as "conduits" for impermissible communications. 
• A seller found to have market power in one market, requiring mitigation in that market, will be allowed to sell at market-based rates into neighboring markets so long as it commits not to sell to an affiliate and have that affiliate sell it back into the mitigated area (so-called "ricochet" transactions). 
• FERC declined suggestions that it use the cost-based rates of the WSPP Agreement to mitigate market power.  Instead FERC determined that those rates may no longer be just and reasonable and convened an investigation into the WSPP Agreement in a separate docket. 
• FERC removed restrictions and posting requirements currently imposed on third-party sales of ancillary services, in the hopes of encouraging competitive ancillary services markets.
  

FERC Scrutinizes Organized Power Markets, but Proposes No Reforms for Now

Following a series of industry conferences on wholesale electricity markets, FERC issued an advanced notice of proposed rulemaking (ANOPR) aimed at exploring means of strengthening competition in organized power markets ― markets with spot energy sales and administered by regional transmission organizations (RTOs) or independent system operators (ISOs).  Public comments on the ANOPR will be due in mid- to late-August ― 45 days following publication in the Federal Register.

FERC is not aiming for a major redesign of RTO or ISO markets, but rather is focusing on four discrete issues on which the agency seeks advice:

• the role of demand response in organized markets, including possible rule changes to increase its use in times of emergency as well as through aggregation and for (or in lieu of ) ancillary services;  
• opportunities for long-term power contracting, including having the organized market operator serve as a clearing house for information on bilateral prospective bilateral deals;
• attributes of market monitors, including independence, enforcement authority, and reporting responsibility; and
• the responsiveness of RTOs and ISOs, in particular at the board level, to customers and other stakeholders.

Each of these issues relates to recent hot topics at the agency.  Commissioner Wellinghoff has become a vocal proponent of demand response.  An increasingly acrimonious dispute between PJM management and its market monitor has drawn attention to the role of market monitors, and in particular their independence.  The perceived remoteness of ISO and RTO boards has brought some calls for allowing market participants greater access to the boards.  And both energy users and project developers at times call for greater use of long-term contracts to stabilize prices.

After reviewing public comments on these topics, FERC will decide whether to issue a notice of proposed rulemaking to propose specific changes to its regulations governing power markets.

Transmission Needed to Connect Burgeoning Renewable Generation

According to the Outlook of Renewable Energy in America report of the American Council on Renewable Energy, the United States by 2025 could have 248 GW of wind power and 100 GW of geothermal energy, in addition to 287 GW of other renewable energy, power and fuels.  "Renewable energy will not be a 'niche' source of America's energy in 2025," according to Robert Detchon, executive director of the Energy Future Coalition.  States such as Texas, Wyoming, New Mexico, and Colorado, where much of the increased wind generation is anticipated, and Nevada, California and Oregon, where much of the increased geothermal generation is anticipated, will likely require more transmission to deliver the renewable power to markets where it is needed. 

Utilities and governments in Europe, China and the United States could spend up to $150 billion on wind projects over the next five years, and the United States alone could invest $67.5 billion by 2015 to produce an anticipated total of 45,000 MW of wind capacity by that year.  According to a May survey conducted by the Geothermal Energy Association, up to 2,455 MW of new geothermal power plant capacity is currently under development in the United States, with 251 MW of capacity currently under construction.  Investment giant Merrill Lynch Commodity Partners recently closed on a $35 million deal with geothermal power developer Vulcan Power in order to finance the development of properties in California, Nevada and Oregon.  Calpine recently announced its intention to boost output at its Geysers geothermal facility in California to approximately 800 MW, and Nevada Power signed a 20-year power purchase agreement with Ormat Technologies for up to 30 MW from Ormat's proposed geothermal project development in northern Nevada. 

The world’s largest wind farm, located south of Abilene, Texas (population 115,000) already enjoyed access to sufficient transmission infrastructure necessary to bring the generation to a nearby market.  But for much future renewable energy development new transmission will be needed since renewable energy resources tend to be remote from load centers.

Several states, including Texas, California, Minnesota and Colorado are using a "zone" approach to transmission planning in order to incorporate renewable energy.  Driven by renewable portfolio standards in many states, the zone approach requires utilities to identify areas of renewable resources, plan the transmission capacity needed to reach those areas, and lobby state regulators to allow recovery of the investment in the required transmission.  Some believe that a federal initiative of this ilk would be necessary in order to tap the nation's vast renewable resources across the country.

Market Monitor Continues Lobbing Shells at Defensive PJM Management

The recriminations between PJM management and its market monitor have reached a crescendo.  In a June 12 multi-volume response to FERC's investigation regarding PJM Interconnection's (PJM) alleged interference of its market monitoring unit (MMU), Dr. Joseph Bowring, PJM Market Monitor, supplemented allegations made in an April 5 statement that PJM management violated the MMU’s independence and compromised other objectives of the PJM tariff.  Among the specific allegations, Dr. Bowring charges that PJM management: (1) refused to prosecute a unit's exercise of market power that resulted in costs to market participants to the tune of $20 million; (2) pressured the MMU to modify its position on mitigating market power in the new RPM capacity market; (3) authorized confidential procedures that gave PJM management preferential review authority over MMU reports effectively modifying Attachment M to PJM's tariff, which contains PJM's Market Monitoring Plan; (4) ordered the Market Monitor to remove a central conclusion from its 2005 State of the Market Report; (5) sought to change or delay the release of four MMU reports from 2004 to the present. (6) ordered the MMU in 2005 not to post minutes of a recent Market Monitoring Advisory Committee (MMAC) meeting and in 2006 ordered the MMU to remove the discussion of a recent FERC Order regarding market monitoring form the MMAC meeting agenda; (7) prevented the MMU from analyzing the BGS auction for the New Jersey Public Utilities Commission in December 2006; and (8) replaced the Market Monitor with the VP of Markets at PJM as the Chairperson of the Cost Development Task Force, a group responsible for developing, reviewing, and recommending standard procedures for calculating costs of products or services for cost-based rates analysis .

Concurrently PJM submitted its own two-volume response to the FERC, dismissing Bowring’s criticisms.  Contrary to Dr. Bowring, PJM contends that “there is no factual basis for any claim that PJM has violated its tariff."  According to PJM, no one has alleged "that the MMU was ever prevented from performing any of its tariff-defined functions or reporting to the Commission any instances of market manipulation or other inappropriate conduct in the PJM markets."  Furthermore, PJM concluded that no evidence has been presented to demonstrate "that the market monitor was prevented from bringing to the Commission's attention matters of concern regarding the markets."  

Dr. Bowring also disclosed information he claimed points to PJM management's interference with MMU staffing, including targeting specific MMU employees for PJM Markets Division openings and threatening to eliminate MMU control over its data and data management.  According to PJM, however, it has provided the MMU with all appropriate staff to "carry out its tariff-defined functions," including maintaining its reliance on contract labor and adopting an especially aggressive and enhanced retention plan to encourage current MMU employees to remain with the MMU during the review period associated with the Complaint and this investigation.  

Regulators and market participants, particularly consumer groups, remain anxious about the MMU’s independence and effectiveness pending resolution of the charges and counter charges.

Former FERC Commissioners, Public Power and Customer Groups Clash over Competitive Electricity Markets

Developments in recent weeks have added fuel to the current debate over whether competitive wholesale electric markets have produced the promised benefits to customers.  On May 31, nine FERC alumnae — Chairs James Hoecker, Elizabeth Moler, and Pat Wood, and former Commissioners Vicky Bailey, Linda Breathitt, Nora Mead Brownell, Jerry Langdon, William Massey, and Donald Santa — circulated an open letter to policymakers lauding the achievements of competitive electricity markets and cautioning against proposals to turn back the clock.  The former Commissioners acknowledged that they knew it would "take time" for the full benefits of competition to be realized, and argued this has been especially true in states that imposed transitional conditions such as rate caps and because of the lack of transmission infrastructure development.  However, there have been substantial benefits from competition, including:  increased efficiency, lower costs (as evidenced by a study showing a purported $34 billion in savings to residential customers between 1997 and 2004), increased use of demand response, the facilitation of renewable resources, technological innovation, improved reliability, and satisfied customers (citing a recent letter to FERC from several large industrial consumers praising competition).  Responding to critics of competitive markets, the former Commissioners asserted that the "good old days" of pervasive cost-based regulation were not good for consumers, but rather produced high generation costs, low generator availability, declining infrastructure investment, and a resistance to technological innovation. 

Critics of current electricity markets answered the former Commissioners in a letter released on June 12, 2007.  The American Public Power Association (APPA) and the Electricity Consumers Resource Council (ELCON) purport to refute many of the former Commissioners’ claims.  They argue that "competition is in the eye of the beholder," and that just because they oppose the version of competition adopted by FERC and endorsed by the former Commissioners (presumably, a model centered around regional transmission organizations and organized spot markets) does not mean they oppose competition generally.  The problem, APPA and ELCON assert, is how competition has been implemented.  APPA and ELCON question the motives of the former Commissioners, many of whom APPA and ELCON contend work and schill for the "haves" in the electric industry, and criticize them for blaming high retail costs on misguided state regulators.  APPA and ELCON also question the study showing that consumers have saved $34 billion under competitive markets.  They also do not accept the common explanation that high electric costs have resulted entirely from higher natural gas and fuel costs, and argue that "satisfied" customers are few and far between.

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

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

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

Oregon's RPS Will Apply Broadly but with Large Gaps

Oregon became the last state along the west coast of the continental U.S. to enact a renewable portfolio standard (RPS) law.  It will require all retail providers in the state to obtain a certain percentage of their energy from renewable sources – up to 25% for the largest utilities – but the law also has numerous exceptions for cost and other factors. 

Under the RPS, utilities with at least 3% of Oregon's total retail electric sales must procure 5% of their energy from renewable resources by 2011, followed by 15% by 2015, 20% by 2020, and 25% by 2025.  Smaller utilities (1½ to 3% of all sales) must achieve 10% renewable energy procurement by 2025, with no interim targets.  The smallest utilities (less than 1½% of all sales) would need to procure only 5% of their power from renewables by 2025, with no interim targets.  Retail marketers would abide by the procurement levels of the utilities in the ESS' individual customer areas.  The law does not make clear whether existing renewable energy purchases count towards RPS compliance.

For sales under the RPS, generators that became operational on or after January 1, 1995 are eligible if they use hydropower (outside certain protected areas), wind, solar, wave, tidal, ocean thermal, geothermal, or a wide range of biomass except for trash or wood that is treated with chemical preservatives.  Older generators are eligible to the extent of capacity or efficiency upgrades or if they have been certified as low-impact hydro facilities.  Any renewable energy sold by the Bonneville Power Administration also qualifies under the law.  Eligible generators must be located in the U.S. portion of the Western Electricity Coordinating Council (WECC), but generators in the Canadian or Mexican portion of WECC can sell unbundled renewable energy credits (REC).

There are a number of exceptions in the law.  A utility is excused from the RPS to the extent that its compliance would cause it to:  spend more than 4% of its revenue requirement, as determined by the Oregon PUC on complying with the RPS; displace a consumer-owned utility's purchases of firm Federal Base System preference power rights from BPA; force a utility to purchase power beyond its needs in a given year; cause displacement of a utility's use of a non-fossil fueled resource; displace low-price hydropower from power contracts with Mid-Columbia River dams until those contracts could not be renewed or replaced.  In addition, a utility can make alternative compliance payments instead of procuring renewable energy.

The relative complexity, delayed implementation and numerous exceptions in the Oregon law may support arguments in favor of a national RPS with uniform standards rather than a patchwork of state laws that may fragment the renewable energy market.

Failing Commitment to Report Code of Conduct Infractions Lands Cleco $2 Million Penalty

On June 12 FERC again flexed its EPAct 2005 civil penalty authority muscle.  FERC's Office of Enforcement had alleged that Cleco violated its Code of Conduct and a 2003 settlement in which Cleco agreed to a stricter, more consolidated code of conduct requiring the independent operation of its unregulated affiliated power marketers and generation assets.  The June 12 Stipulation and Consent Agreement (Settlement) recapped specific allegations of Code violations from the summer of 2003 to winter 2005.  In addition, the Settlement accuses Cleco of failing to report those violations to the Office of Enforcement, even though Cleco did submit a self-report of possible violations after investigations had been initiated.  As a part of the Settlement, Cleco neither admitted nor denied that its conduct violated the 2003 settlement or its Code of Conduct.

Non-public, preliminary investigations of Cleco began in November 2005 when the Office of Enforcement reviewed the utility's October 2005 Quarterly Compliance Report as a requirement of the 2003 settlement with FERC.  The Office of Enforcement concluded that Cleco violated the independent functioning requirement in the Code of Conduct, which requires that, except in emergencies, employees involved in transmission must function independently of the power supply employees.  The Office of Enforcement concluded that: (1) operational employees impermissibly engaged in restructuring activities for Cleco's exempt wholesale generators; (2) employees conducted activities that were beyond the scope of permissible shared accounting support duties; (3) six Technical Services Department Planning Group employees performed generation outage planning, coordinating, and scheduling activities for affiliates; (4) certain employees were given access to non-public market information; (5) a non-public monthly risk report was circulated to affiliated companies' Chief Operating Officer(s); and (6) daily status reports were distributed to affiliates that contained non-public information. 

In addition to the $2 million penalty, Cleco is now subject to another compliance plan that requires semi-annual reports to the Office of Enforcement and a 12-month independent audit.  Both semi-annual report and the audit reports must identify all shared employees, report whether any provisions of the Code of Conduct were violated, and identify each instance where non-public information was shared with affiliates.  

Although Cleco self-reported some of the violations at a later date and has taken steps to prevent recurrence of similar violations, it was Cleco's violation of the earlier 2003 settlement agreement that peeved the regulator.  FERC Chair Kelliher admonished that the $2 million penalty would serve as "a reminder that the Commission will not tolerate such actions."  He went on to say that the Commission will "use [its] civil penalty authority to establish a culture of compliance."  The Commission acknowledged that Cleco's actions did not create undue discrimination, result in preference, or cause harm to third party competitors or customers.

Arizona Regulators Reject Cross-Border Transmission Line

The Arizona Corporation Commission (ACC) recently rejected an application by Southern California Edison Company (SCE) to construct a new transmission line from Devers, California to Palo Verde, Arizona.  The proposed Devers-Palo Verde No. 2 line ― a 230-mile, 1200 MW line estimated to cost approximately $600 million ― had already won approval of the California Public Utilities Commission (CPUC).  According to the CPUC, the line would serve as an important means of reducing the substantial congestion in southern California by expanding the transmission capacity into the area and allowing California utilities to import significant amounts of power from Arizona.  The ACC, on the other hand, dismissed the project as essentially allowing California to plug a "230-mile extension cord" into its generation supply, something the ACC found untenable at a time when Arizona's own population is growing rapidly. 

With both SCE and the CPUC considering appeals, the ACC's decision potentially sets up a fight under provisions of the Energy Policy Act of 2005 that allow FERC to site transmission facilities in certain Department of Energy (DOE)-designated National Interest Electric Transmission (NIET) Corridors for which state regulators have "withheld" approval for more than a year.  In a rulemaking issued late last year, FERC interpreted the word "withheld" in the statute to also mean "denied," thus potentially allowing transmission developers to bypass recalcitrant state regulators in favor of federal regulators.  In May, DOE proposed to designate an area encompassing the Devers-Palo Verde No. 2 line as a NIET corridor.

FERC to Investigate Claims of PJM Management Interference in Market Monitoring

Progress Energy Plan Will Encourage Conservation, Delay Plant Construction

Confronted with burgeoning demand, Progress Energy Carolinas (Progress) has set a goal of reducing demand by 2,000 MW through demand-side management efforts and energy efficiency programs.  The announcement comes less than a month after Duke Energy (Duke) filed a request with the North Carolina Utilities Commission (NCUC) to compensate the company for investments in energy efficiency and new technologies to meet its own growing demand. 

Progress has not yet proposed a similar compensation plan to the NCUC.  Its plan, however, seeks to double the approximately 1,000 MW being saved with programs currently in effect.  With these savings, Progress commits to postpone any plans for new coal plants, and delay consideration of a new nuclear reactor for two years while it evaluates the effectiveness of its stepped-up conservation efforts.  These efforts include the conversion of Progress' own buildings, plants and distribution and transmission systems to new, more efficient technologies, partnering with commercial, industrial and government consumers, including the military — a significant Progress customer — to help these consumers reduce their demand, and offering new energy efficiency programs to residential customers, including installation of latest-generation programmable thermostats, and increased residential HVAC maintenance.