Energy Legal Blog

Interstate Air Pollution Rule Granted Temporary Stay of Execution

In the waning days of 2008 a three-judge panel of the US appeals court ended months of uncertainty surrounding the regulation of power plant emissions of sulfur dioxide (SO2) and oxides of nitrogen (NOx) when it ruled that the EPA’s Clean Air Interstate Rule (CAIR) could remain in effect until the Agency develops a lawful alternative.  The same court last July vacated the tradable emission allowance scheme that CAIR has implemented since 2005 as "fatally flawed" because it could not assure compliance with the Clear Air Act directive that prohibits sources within one State from contributing significantly to non-attainment with national ambient air quality standards (NAAQS) in any other State.  In reliance on CAIR owners of electric generating units in 28 eastern states and the District of Columbia had spent many millions of dollars to acquire emissions allowances in compliance with CAIR requirements.

In its order on rehearing, the court made clear that it was providing only a temporary reprieve pending EPA’s development of a replacement rule that ensures compliance with the Clean Air Act.  That will be challenging.  Insofar as a system of tradable allowances is retained, what ensures that one state will not purchase sufficient allowances to authorize emissions that will contribute to another downwind state's violation of a NAAQS?  Responsibility for fashioning a replacement rule that will prevent that from happening will fall to new Obama Administration EPA Director Lisa Jackson.

How to Regulate Emissions of Greenhouse Gases?

In a policy memorandum that the Obama administration will likely revisit, current EPA administrator Stephen Johnson announced December 18 that Clean Air Act (CAA) operating permits for new or modified power generating plants need not be conditioned on the developer implementing best available control technology (BACT) to reduce plant emissions of carbon dioxide (CO2) and other greenhouse gasses that cause climate change.  The controversial memorandum responds to a November 13 decision of the US Environmental Appeals Board that validated in part the Sierra Club's objection to EPA Region 8's failure to impose greenhouse gas BACT on its issuance of an operating permit to a proposed coal-fired power station in Bonanza, Utah.  The CAA program for the prevention of significant deterioration (PSD) of air quality requires BACT in power plant operating permits for emissions of "each pollutant subject to regulation under" the CAA.  Administrator Johnson’s memorandum concludes that CO2 is not subject to regulation under the CAA and therefore does not trigger BACT under the PSD program.

The administrator's interpretation of the CAA is directly contrary to a Georgia state court ruling last June that CO2 is a pollutant subject to regulation under the CAA.  Arguably, it also cannot be squared with the ruling last April of a sharply divided (5-4) Supreme Court in Massachusetts v. EPA.  In that decision, the Court held that EPA could promulgate rules regulating vehicular emissions of CO2 as a greenhouse gas that contributes to climate change.

The policy memorandum is representative of both the Bush administration's reluctance to regulate directly emissions of greenhouse gases and its often-stated belief that the CAA is somehow an imperfect framework for addressing anthropogenic climate change.  The Obama administration has already committed to reverse course as to the former and regulate greenhouse gas emissions directly through a framework that caps tradable emission allowances.  But unresolved is whether - in addition cap and trade - to subject CO2 and other greenhouse gasses to traditional CAA technology-forcing controls such as BACT under the PSD program.   Contrary to opponents of CAA regulation of greenhouse gasses, the two approaches can co-exist synergistically.  Requiring performance technologies can advance domestic reductions in greenhouse gas emissions at their primary sources - coal-fired power plants and cars.  At the same time, cap and trade is probably the most viable international framework for industrial nations to reduce those emissions globally.

Court Rules EPA Cannot Relax Strict Controls on Hazardous Air Emissions During Start-up, Shut-down and Malfunction

In a December 19 decision of potentially broad applicability to fossil fuel-fired electric generators, a divided (2-1) panel of the US Court of Appeals for the DC Circuit ruled that the EPA violated the Clean Air Act when it adopted a final rule that would have lessened controls on emissions of hazardous air pollutants (HAP) when process or associated emission control facilities are in periods of equipment start-up, shut-down and malfunction (SSM).  Specifically, the rejected rule would have supplanted the requirement that HAP emissions be numerically limited by a strict standard based on "continuous" maximum achievable control technology (MACT) with a "general duty" to minimize emission to the greatest extent possible.  Many of the more-than-100 HAPs that are subject to MACT controls under section 112 of the Clear Air Act are by-products of fossil fuel combustion for power generation.

Proposals to relax required MACT controls on HAP emissions during period of SSM began in 1994 when EPA adopted an exemption that would have freed sources from strict numerical MACT standards during SSM periods so long as the source included in its Title V emissions permit an SSM plan that detailed "procedures for operating and maintaining during [SSM] periods and a program of corrective action for" fixing malfunctions.  Later in 2002, EPA ruled that the SSM plan need only exist, but need not be part of the Title V permit, which meant it could be revised by the emissions source without prior approval.  And in 2003 EPA adopted a rule to limit public access to a source's SSM plan.  Public and environmental advocates then protested, resulting in the December 19 decision that the Clean Air Act does not permit EPA to lessen Congressionally mandated "continuous" MACT emission standards for HAPs on a temporal basis during SSM periods.  Notably, the dissenting judge did not disagree with the merits of the majority's decision; rather, he objected that the public and environmental advocates' challenges wer untimely and did not properly present the issue that the majority decided.

FERC Approves First Hydrokinetic Installation at Existing Hydro Project

In a December 13 order, FERC approved a hydrokinetic generator that City of Hastings, Minnesota proposes to install by April 2009 in the Mississippi River.  Hydrokinetic projects generate electricity from waves or from the flow of water.  Hastings proposed to suspend two 35-kW hydrokinetic turbines from a floating barge in the tailrace of its existing 4.4-MW run-of-the-river dam.  The city estimates the new hydrokinetic units will generate an average of 364 MW-hours of electricity per year.  In a statement issued along with the approval, FERC Chairman Joseph T. Kelliher praised the project as a "creative solution to meeting electricity demand using renewable resources," and congratulated Hastings "for moving forward with the idea."

FERC did set forth certain conditions on its approval in order to allay environmental concerns.  The city must monitor the project for any adverse impacts on water quality, fish, or birds.  If the monitoring shows any adverse impacts on water quality or avian life, the city must modify the project's operation, including removing the turbines or barge if necessary.  The city must also develop a plan to control the spread of invasive zebra mussels during installation or operation of the project.

FERC to Be Less Generous with Incentive Rates for Transmission Projects

At a time when investment wells are bone dry and credit unavailable, FERC ironically seems to have reversed earlier policies that liberally extended economic incentives to new transmission projects under FPA section 219 and Order No. 679. In a December 4, 2008 order, FERC denied Commonwealth Edison's (ComEd) petition asking the agency to declare that 22 transmission projects are eligible for rate incentives, even though each project had been approved in the PJM Interconnection's regional transmission expansion plan (RTEP) process. The projects ranged from capacitor and transformer installations, transmission line upgrades, and circuit breaker replacements, costing approximately $215 million. Although PJM approved these projects in its 2006, 2007, and 2008 as RTEP baseline projects, FERC nevertheless rejected ComEd's petition, finding that ComEd failed to satisfy Order No. 679's "nexus" test. That test requires an applicant for incentive rates to demonstrate that its project is not routine and that the total package of incentives is needed in light of the risks and challenges faced by the project. Increasing criticism has been directed at the agency for granting incentives where no "nexus" had been demonstrated.

In its order, FERC acknowledged that rejection of ComEd's petition represented a departure from earlier orders in which FERC appeared to apply a more deferential standard to award rate incentives to projects that stakeholders of a regional transmission organization (RTO) had determined would improve grid reliability. For example, in a 2007 order involving Baltimore Gas & Electric, FERC held that "[p]rojects . . . identified as 'baseline' in the PJM RTEP process are . . . by definition, regional projects are thus, not routine." In contrast, in the December 4 Order FERC held that, "[d]espite their status as PJM RTEP baseline projects, ComEd has not demonstrated how [its] projects present risks or challenges to warrant an incentive ROE under our nexus requirement."

Imprimatur of an RTO planning processes alone will apparently no longer entitle a project to incentive returns. Now, applicants will be required to independently satisfy the "nexus test." Even though the Commission will continue to allow such projects to qualify for the rebuttable presumption under the Commission's so-called "219 test," which is a threshold determination as to whether a project ensures reliability or reduces congestion, independently supporting the nexus test will undoubtedly increase the amount of support of incentive applications going forward. Among other things, the December 4 Order could result in increased Commission scrutiny and reduced administrative certainty, even for risky projects requiring large capital outlays.

Deseret Decision Regarding CO2 Avoids the Key Question and Creates Significant Uncertainty

In a noteworthy Clean Air Act decision in the wake of Massachusetts v. EPA, 549 U.S. 497 (2007), the Environmental Appeals Board (EAB) avoided the key question of whether carbon dioxide (CO2) is currently "subject to regulation" under the Clean Air Act (Act).  In the Matter of Deseret Power Electric Cooperative, EAB App. No. PSD 07-03. (November 13, 2008).  It appears that the decision is carefully designed to leave open for the next Administration the question of whether CO2 will be regulated under a key EPA permitting program.

On the one hand, EAB sided with the Environmental Protection Agency (EPA), agreeing that EPA is not required to treat CO2 as "subject to regulation" for purposes of the Prevention of Significant Deterioration (PSD) permitting program.  On the other hand, EAB found that EPA could exercise its discretion to treat CO2 as "subject to regulation," and thus require permit limits for CO2 based on the "best available control technology" (BACT).  Under the Bush Administration, EPA has made it clear that, for both legal and policy reasons, it does not want to treat CO2 as "subject to regulation" under the Act.  The EAB found, however, that the Deseret permitting record was not adequate to support this position.  It then remanded the permit back to the Agency with instructions that will make it very hard for EPA to respond to the remand until the new Administration takes office.  In doing so, the EAB has created significant uncertainty for anyone planning to construct virtually any type of commercial building or industrial facility.

Highlights from EAB's Decision

EPA Region 8 issued a PSD permit to Deseret Power Electric Cooperative (Deseret) for a proposed waste-coal-fired electric generating unit planned at the existing Bonanza Power Plant in Utah.  Deseret's permit was subsequently challenged by the Sierra Club, which claimed that, in light of the Supreme Court's decision in Massachusetts v. EPA, the permit was invalid because it did not include a CO2 emissions limit.

In making its decision, the EAB parsed through a variety of arguments regarding textual and historical interpretations of the Act.  Sierra Club's challenge relied on sections 164 and 169 of the Act, provisions that prohibit the issuance of a PSD permit unless it includes a BACT emissions limit for "each pollutant subject to regulation under this Act." With sections 164 and 169 in mind, Sierra Club pieced together its argument using (1) the Supreme Court's ruling in Massachusetts v. EPA that CO2 is a "pollutant" as defined under the Clean Air Act; and (2) an argument that the CO2 "monitoring and reporting" requirements under section 821 of the Act constitute "regulation."  Thus, Sierra Club argued that CO2 should be considered a "pollutant" that is subject to "regulation."

On the other hand, EPA argued that "monitoring and reporting" requirements are not considered "regulation" and that deference should be given to its historical interpretations of the relevant provisions of the Act.

In the end, the EAB found no Congressional intent in the Act that would require EPA to apply BACT to "pollutants" that are merely subject to "monitoring and reporting" requirements.  The EAB also noted that in reconsidering its conclusions regarding CO2 BACT requirements, the EPA should be allowed to exercise discretion in interpreting what constitutes a "pollutant subject to regulation" under the Act.  However, because the record did not support EPA's current reasoning for failing to include a BACT limit for CO2 in the permit, the EAB remanded Deseret's permit. 

In issuing the remand, the EAB noted that EPA has discretion to interpret the term "subject to regulation under the Act," an interpretation that will determine whether BACT is required to limit CO2 emissions.  The EAB noted in the closing paragraphs of its decision that it recognized the national implications this decision may have, and called for the EPA to consider whether "an action of nationwide scope" is required to address the issue.

Initial Observations from Bracewell's Environmental Strategies Group

• The Deseret decision creates enormous uncertainty for virtually any significant building project in an area of the country in which EPA is the permitting authority.  Under the Clean Air Act, the permitting authority cannot choose to treat CO2 as subject to regulation for some types of sources and not others.  If CO2 is "subject to regulation" under the Clean Air Act, then any source that emits more than 250 tons per year of CO2 would need a PSD permit.  EPA analysis has indicated that virtually all schools, hospitals, apartment buildings and commercial buildings have CO2 emission above this threshold.
  
• Projects with a PSD permit issued after the underlying permit decision in Deseret may fare differently on appeal to the EAB because the Deseret ruling focuses somewhat myopically on the underlying permit record established by EPA.  In more recent PSD permits, EPA has included in the permitting record a much more robust explanation of its rationale for construing the existing Clean Air Act authority as not subjecting CO2 to regulation.  Since the underlying permit decision in Deseret, EPA has also stated that, before treating CO2 as subject to regulation, the Agency would need to go through notice-and-comment rulemaking.
  
• In general, states that have their own EPA-approved permitting programs could take the position that they can interpret the term "subject to regulation" under the Clean Air Act to include CO2.  Some of these states (e.g., Connecticut, Maine, New York, California, Rhode Island and Vermont) sided with Deseret's opponents and argued that CO2 is already subject to regulation under the Clean Air Act.  It will be interesting to see whether these states now begin to require PSD permits for all sources that emit more than 250 tons per year of CO2, including schools, hospitals and apartment buildings.

Recent FERC Enforcement Efforts Reported

FERC's Office of Enforcement on November 6 released its "2008 Report on Enforcement," an annual report detailing FERC's enforcement program during the preceding fiscal year ending September 30.  This report provides a statistical analysis of FERC's enforcement activities, including receipts of company self-reports and investigations opened by FERC staff.  In a statement issued concurrently with this year's report, FERC Chairman Joseph Kelliher emphasized that the focus of FERC's enforcement program is on compliance, and the report is aimed at providing energy market participants with information to help them comply with applicable laws and regulations.

This year's report showed a significant jump in enforcement activity in 2008, with self-reports of violations more than doubling since 2007 (from 31 in 2007 to 68 in 2008), and with Office of Enforcement staff opening a significantly higher number of non-public investigations in 2008 than in 2007.  The Staff entered into seven settlement agreements in 2008, which totaled more than $20 million in civil penalties.  On an encouraging note — a note consistent with FERC assurances that it looks favorably upon self-auditors and self-reporters — the report showed that approximately 75% of the self-reports made in 2006 and 2007 were closed without any formal action or penalty assessment. 

Better Markets Through Demand Response, Forward Contracting and Accountability

FERC issued a final rule October 17 to strengthen competition in organized wholesale electric markets.  The rule (generally consistent with the proposed rule FERC issued last February) seeks to improve wholesale markets by establishing a more forceful role for demand response and long-term contracts in organized markets, strengthening market monitoring, and improving the responsiveness of regional transmission organizations' (RTO) and independent system operators' (ISO) to their customers. 

• As to demand response, FERC directs each RTO/ISO to:  accept bids for ancillary services from demand response resources; eliminate charges to buyers for voluntarily reducing demand during emergencies; permit market participants to aggregate retail demand responses (unless otherwise prohibited by state law); and allow market prices to reflect more accurately the value of energy during shortages, by adopting scarcity pricing to allow prices to rise during times of shortages and encourage an increase in supply.  FERC also requires the RTOs/ISOs to assess and report on any remaining barriers to comparable treatment of demand response resources.  Commissioner Suedeen Kelly dissented from the Commission's scarcity pricing decision, arguing her belief that before allowing scarcity pricing, FERC should ensure that the necessary generation and demand response infrastructure are in place to give consumers the ability to respond to higher prices.

• Because long-term contracts help market participants hedge against potential volatility in market prices and can help improve price stability, FERC urges more long-term contracting in organized markets.  Finding there is no fundamental barrier to long-term contracts in organized markets, FERC sought to improve transparency in such contracting by requiring RTOs/ISOs to dedicate a portion of their websites to a transparent exchange of long-term sale offers and buy bids.

• To enhance the effectiveness of RTO/ISO market monitoring, the rule addresses  the independence and functioning of RTO/ISO market monitoring units and information sharing.  In apparent response to some of the difficulties faced by the PJM Interconnection and its market monitor last year, the final rule requires that market monitors report directly to RTO/ISO boards, as opposed to management.  FERC also broadened market monitors' reporting duties by clarifying that market monitors must refer to FERC any instances of misconduct by the RTO or ISO, as well as by market participants, and by expanding market monitors' referral obligations to include perceived market design flaws.

• Finally, FERC sought to improve RTO/ISO responsiveness by requiring that they provide customers and other stakeholders with some form of direct access to their boards.  FERC emphasized the importance of RTO/ISO boards being willingness to directly receive concerns and recommendations from customers and other stakeholders, and to consider fully and take action in response to such concerns and recommendations.

These reforms come on the heels of a report by the Government Accountability Office (GAO), issued last month, that questioned how well FERC has quantified the benefits of RTOs to electric consumers.  Although not a direct response to the GAO report, the new rule appears aimed at some of the problems that have typically been identified with organized markets. 

Fate of Ocean Power Projects Requires FERC and Interior Cooperation

Jurisdictional jockeying between FERC and the Department of Interior threatens development of Outer Continental Shelf (OCS) ocean power projects. The issue calls out for agency cooperation and possibly an interagency agreement similar to that between FERC and the U.S. Forest Service for licensing and permitting hydroelectric projects on Forest Service lands. Absent such cooperation, the matter will have to be resolved by the courts.

The dispute flared most recently when Pacific Gas & Electric Co. asked FERC to issue preliminary permits for two sites located partially in state waters and partially on the OCS. PG&E contemplates placing between 8 and 200 wave energy conversion devices in water with depths of 60 to 600 feet and delivering the energy from the two projects via underwater cables connected to the PG&E transmission grid. The two projects would each generate about 40 MW. FERC considers them hydroelectric projects because they generate electricity through ocean waves.

While Interior does not contest FERC's jurisdiction over such projects in state waters, it contends that FERC has no authority over the OCS sites. Interior argues that "navigable waters" (the touchstone for FERC jurisdiction) does not include waters beyond the 3 mile boundary of the U.S. territorial waters. Interior’s position derives from the definition of navigable waters in a number of statutes, including the Clean Water Act and the Rivers and Harbors Act of 1899. Rejecting this argument, FERC says the Federal Power Act (FPA) definition of navigable waters is broader and extends to "bodies of water over which Congress has jurisdiction" under the commerce clause, including OCS waters. FERC also asserts authority under the FPA to issue licenses for projects located on "lands and other interests in lands owned" by the U.S., again including the OCS.

By empowering Interior to lease the OCS for non-oil and gas energy sources, the Energy Policy Act of 2005 (EPAct 2005), according to Interior, made Interior the lead agency for OCS wave energy projects. Not so, says FERC, asserting EPAct 2005 limited Interior's authority to OCS activities not otherwise authorized by "other applicable law" and that hydro licensing is otherwise authorized by the FPA. No end to the debate is in sight.

Employee Function Replaces Corporate Separation as Cornerstone of FERC's New Standards of Conduct

The Federal Energy Regulatory Commission adopted revised Standards of Conduct (Standards of Conduct) for Transmission Providers ― both natural gas pipelines and electric transmission systems ― in its October 16 Order No. 717.  The single largest change from earlier SC is replacement of corporate separation requirement adopted in 2003 with an “employee functional approach” that dates back to the original 1988 natural gas Standards of Conduct and the 1996 electric transmission Standards of Conduct.  Order No. 717 will take effect 30 days after publication in the Federal Register, likely sometime in late November.

In order to prevent preferential access to natural gas pipelines and electric transmission systems, the Standards of Conduct originally separated employees engaged in transmission from others engaged in natural gas or electricity marketing and required them to operate independently of each other.  In response to the unbundling of gas sales and transportation and the proliferation of electric power marketers, FERC in 2003 changed the Standards of Conduct to require a corporate separation of transmission employees not only from those in marketing, but also from employees broadly and ambiguously characterized as "energy affiliates."  The found these changes difficult to implement and an obstacle to both competitive procurement and integrated resource planning.  The natural gas industry sought judicial review, and a court invalidated the 2003 Standards of Conduct revisions on "energy affiliates" as to the natural gas industry.  Order No. 717 responds to the natural gas and power industries' complaints and the court's decision by jettisoning the "energy affiliate" concept and reverting to separation of employees by transmission and marketing function and no longer requiring corporate separation.

In regard to merchant employees, FERC clarified that designation comprises only employees involved in natural gas or electricity sales.  The Standards of Conduct do not apply to purchases and should therefore have not adverse effect on competitive procurement.  And as to transmission employees, the Standards of Conduct apply only to employees involved in the day-to-day operation of pipelines or electric transmission systems; they do not apply to planning activities and therefore should not be a limitation on integrated resource planning, which has a long history in the electric power industry.

In addition to the adoption of the employee functional approach and the elimination of the concept of “energy affiliates,” Order No. 717 also made a variety of other clarifications to its Standards of Conduct regulations in response to industry comments.  FERC’s hope is that the narrowing of the scope of its Standards of Conduct regulations will facilitate compliance.  For that reason, the new Standards of Conduct is likely to take center stage in future FERC enforcement actions.

Boucher-Dingell Bill Would Have FERC Run Cap-and-Trade Carbon Market

If the "discussion draft" carbon cap-and-trade bill recently released by Congressmen John Dingell (D-MI) and Rick Boucher (D-VA) becomes law, then FERC would run the carbon market. Within FERC, the bill would create a new Office of Carbon Market Oversight possessing jurisdiction over brokers, dealers and certain others involved in carbon trading. The draft bill would amend the Federal Power Act to add provisions empowering FERC to regulate carbon markets. Noteworthy provisions of the bill include:

· Jurisdiction: FERC would obtain jurisdiction over both domestic and foreign transactions involving instruments — defined as emission allowances, offset credits, and instruments whose values derive from the prices of allowances or credits — not otherwise regulated by the Securities and Exchange Commission.  Brokers and dealers, as well as entities seeking to serve as Carbon Clearing Organizations (CCO), would need to register with FERC. The Environmental Protection Agency (EPA) would have the authority to manage certain carbon off-set programs, as well as establish industry-specific emission standards for sources that emit less than 25,000 tons of CO2 per year.

· Cap: The bill would cover approximately 88 percent of sources of U.S. greenhouse gas emissions. It would require these sources to be responsible for reducing "covered emissions" to six percent below 2005 levels by 2020, 40 percent below 2005 levels by 2040, and 80 percent below 2005 levels by 2050.

· Market Monitoring: FERC would monitor price and market manipulation of regulated instruments, and would be charged with promulgating regulations to prevent excessive speculation in regulated instrument trading. 

· Penalties: FERC would be authorized to assess civil penalties of $1 million per violation of the cap-and-trade law or up to three times the monetary gain obtained as a result of the violation.  FERC would also be the ultimate arbiter of decisions to suspend or expel certain participants in carbon trading activity. 

· Preemption: The bill would explicitly preempt state and local initiatives to regulate GHG, such as the Regional Greenhouse Gas Initiate (RGGI) that is implementing a mandatory carbon dioxide cap-and-trade program in the Northeast and Mid-Atlantic states.

One might fairly ask what expertise or special competence FERC brings to running a carbon market. Only some of the emission sources are energy utilities that FERC historically has regulated. Why not instead the EPA, with its expertise in administering the Clean Air Act? Alternatively, in recognition that carbon allowances may need to trade internationally, comparable to currency, why not the Department of the Treasury? Some suggest that the answer is politics. By selecting FERC, representatives Dingell and Boucher appear to take jurisdiction over the program away from the Senate Committee on the Environment and Public Works, chaired by Sen. Barbara Boxer (D-CA), and transfer it to the Senate Committee on Energy and Natural Resources, chaired by Sen. Jeff Bingaman. Sen. Bingaman is on record favoring less aggressive carbon controls less than Sen. Boxer, a position more in sync with the Boucher-Dingell discussion draft.

Congressmen Dingell and Boucher have stressed that their "discussion draft" is aptly named; it is a draft only, and it is meant to stimulate discussion.  Indeed, the bill contains blanks on some fundamental elements.  For example, it proposes—and asks for comment—on four different mechanisms for allocating emissions allowances, running the gamut from free allocations to auctions. 

FERC Issues Policy Statement on Compliance

The Federal Energy Regulatory Commission (FERC) revised its Policy Statement on Compliance October 16.  The revision posits four factors FERC will take into account when considering whether to reduce or eliminate civil penalties for violations: (1) The role of senior management in fostering compliance; (2) Effective preventative measures to ensure compliance; (3) Prompt detection, cessation, and reporting of violations; and (4) Remediation efforts. 

FERC adopted a "compliance credit" approach resembling that of the Securities Exchange Commission and the Federal Sentencing Guidelines.  Where a violation is not serious (does not involve significant harm or damage to the integrity of FERC's regulatory program), and the company has all 4 elements of vigorous compliance in place, FERC may then reduce a company's penalty to zero.

Energy Beneficiaries of Economic Stimulus Package

The Energy Improvement and Extension Act of 2008 embedded in the economic stimulus legislation (H.R. 1424) that President Bush signed into law on October 3, 2008, provides nearly $17 billion in various tax credits to promote clean power generation technologies, alternative fuels, renewable energy and energy efficiency.

Renewable Energy Initiatives

While the 2008 Act provides notable incentives for investments in several emerging technologies such as hydrokinetics, fuel cells, geothermal and open-loop biomass facilities, solar and wind emerged as the biggest winners. For commercial-scale wind power producers, the Act provides a brief, although relatively costly, extension of the production tax credit as well as a variety of incentives for microturbines and residential-scale wind projects. For the solar industry, the Act extends the existing 30 percent investment tax credit for solar energy facilities and, perhaps most notably, eliminates the cap on the existing 30 percent tax credit for investments in residential solar.

Extension and Expansion of PTC — Section 45 of the Tax Code allows a production tax credit (PTC) for "qualified facilities" that generate electricity from "qualified energy resources." The 2008 Act expanded the definition of "qualified energy resources" to include "marine and hydrokinetic renewable energy." As a result, energy derived from marine resources such as waves, tides, and temperature differentials are now eligible for the PTC. The Act also expands the definition of "open-loop biomass facility," "trash combustion facility," and the definition of "non-hydroelectric dam."

The 2008 Act extends the PTC for commercial wind by one year for facilities placed in service by January 1, 2010. The Act also extends the PTC for other types of qualified facilities such as biomass, geothermal, solar, small irrigation and landfill gas, for two years, to January 1, 2011 and for marine and hydrokinetic energy facilities until 2012.

Long-Term Extension of Energy Property Tax Credit — Section 48 of the Tax Code provides tax credits (in addition to the PTC) for investments in energy property. The 2008 Act expands the scope of qualified energy property, removed or raised the caps on this tax credit, and extended the sunset for the credit in certain instances. Specifically, the Act extends through 2016 the 30 percent tax credit for investments in solar energy property and fuel cell property and the 10 percent tax credit for commercial microturbines. The Act amends the definition of energy property to provide a new 10 percent investment tax credit for combined heat and power sources and geothermal equipment that uses ground water for heating or cooling purposes. The Act also increases the tax credit available for investments in qualified fuel cells from $500 to $1,500 per half KW.

Long-Term Extension and Modification of the Residential Energy-Efficient Property Tax Credit — Section 25D of the Tax Code allows for a 30 percent credit for investments in residential solar and fuel cell properties. The 2008 Act extends through 2016 the credit available for solar property and adds residential small wind and geothermal heat pumps as qualifying property. Significantly, the Act eliminates the $2,000 cap on the 30 percent tax credit available for solar facilities; the credit can now be applied to the total cost of photovoltaic solar facilities.

For other facilities, the following caps continue to limit the available tax credits:

· $2,000 for solar water heating;

· $500 for each half KW of capacity of qualified fuel cell property;

· $500 for each half KW of capacity of wind turbines for which qualified small wind energy property expenditures are made (up to $4,000); and

· $2,000 for any qualified geothermal heat pump property.

Energy Conservation and Efficiency Initiatives

The 2008 Act offers states and municipalities, homeowners, contractors, as well as the commercial and manufacturing sectors financing and tax credit incentives for improving energy efficiency. Although the Act did not pick one industrial sector or clean technology as a clear winner, certain sectors faired better than others.

Among the biggest beneficiaries are producers of energy-efficient appliances (e.g., stoves and water heaters) as well as producers of smart meters and smart grid systems. For example, the Act extends until 2009 existing tax credits for homeowner investments in energy-efficient appliances and extended until 2013 the existing tax credit for the costs of energy-efficient property installed in commercial buildings. The combined value of these tax credits is nearly $2 billion. The Act also:

· Creates a new category of bonds to finance State and local initiatives to reduce greenhouse gas emissions;

· Extends the credit contractors receive for building new homes that achieve 30 to 50 percent reduction in cooling and heating energy consumption relative to comparable homes;

· Modifies and extends the tax credit manufacturers receive for producing energy-efficient appliances such as dishwashers, washing machines, and refrigerators;

· Accelerates depreciation (10 years) for utility investments in smart meters and smart grid systems; and

· Extends and modifies the qualified green building and sustainable design project bond.

 

Coal Projects and Coal Gasification Investment Credits

The 2008 Act provides new tax credits in section 48A of the Code for qualifying advanced coal electricity projects and in section 48B of the Code for qualifying coal gasification projects that demonstrate the greatest potential for carbon capture and sequestration. Credits are to be awarded through an application process, with priority given to projects demonstrating the greatest CO2 sequestration. To be considered qualifying, an advanced coal electricity project must capture at least 65percent of the facility's CO2 emissions and a coal gasification project must capture and sequester at least 75 percent of the CO2 emissions.

Carbon Dioxide and Sequestration Tax Credit

New Section 45Q to the Tax Code provides tax credits for qualifying CO2 sequestration facilities. The Act provides a $20 credit per ton of CO2 captured and transported from an industrial source for permanent storage in a geologic formation and a limited $10 credit per ton for CO2 captured and transported from industrial sources for use in enhanced oil recovery. Qualifying facilities must capture at least 500,000 metric tons of CO2 per year.

Plug-in Electric Vehicle and Bike Credit

The Act offers a new tax credit in section 30D of the Code ranging from $2,500 to $7,500 for the purchase of the first 250,000 plug-in electric vehicles. It also proposes a refueling property credit for alternative fuel vehicles and adds electricity to the type of fuel qualifying for the credit. New section 30C of the Tax Code grants a 30 percent credit for the cost of refueling property placed into service during the year up to $30,000 for properties subject to depreciation and $1,000 otherwise.

Commuting by bike is also encouraged. The 2008 Act allows employers to provide fringe benefits of up to $20 a month to employees who bike to work. Bicycle commuters may spend the benefits on maintaining, repairing or buying bicycles.

Alternative Fuels Credit

The alternative fuels tax credit under section 6426 of the Tax Code is extended through December 31, 2009, for all fuels except hydrogen. Alternative fuels are considered compressed or liquefied gas derived from biomass; liquefied petroleum gas; compressed or liquefied natural gas; liquefied hydrogen; liquid fuel derived from coal and liquid hydrocarbons derived from biomass.

GAO Report Urges FERC to Be More Specific on Costs, Benefits of RTO Membership

The Government Accountability Office (GAO) issued a report to Congress on September 26 urging FERC to take additional steps to analyze the benefits and performance of the Regional Transmission Organizations (RTOs) that manage regional transmission grids.  FERC's development of RTOs has been controversial from the beginning, with many arguing that they ultimately increase electricity prices.  Highlighting this debate, the GAO stated:  "Many agree that RTOs have improved the management of the transmission grid and improved generator access to it; however, there is no consensus about whether RTO markets provide benefits to consumers or how they have influenced consumer electricity prices. . . ."  The GAO specifically criticized FERC's failure to develop standardized measures to track RTO grid operator performance, finding that this failure bred uncertainty about the benefits of RTO membership and led to missed opportunities for FERC to direct improvements in RTOs' operations and markets.

In its analysis, the GAO discussed several areas in which it found FERC's oversight of RTOs to be lacking and offered recommendations.  Specifically, the GAO concluded that FERC does not adequately review RTO financial reports and budgets.  To remedy this, the GAO urged FERC to develop a consistent approach for reviewing RTO budgets, including routine assessments of the accuracy, completeness, and reasonableness of the financial reports that RTOs submit to FERC. 

The GAO also determined that FERC has failed to undertake a comprehensive review of broader RTO performance and benefits, and that this failure resulted in missed opportunities for developing new market rules and improvements in RTO operations.  The GAO suggested FERC work with RTOs, stakeholders, and other interested parties to develop measures to track grid operations and markets.  FERC should also submit an annual report to Congress describing its review and identifying any changes that should be made to address performance concerns.

In response to the report, FERC Chairman Joseph Kelliher generally agreed with many of the GAO's recommendation, in particular, that FERC should increase its review of RTO performance and costs.  Chairman Kelliher noted that FERC Staff is evaluating possible approaches for implementing the GAO's recommendations and that FERC plans to perform periodic audits of financial information in RTOs' financial reporting forms (FERC Form No. 1).  Chairman Kelliher did push back on the GAO's assessment that RTOs stand in a "position of greater public trust" than other public utilities, stating there is no policy reason to view RTOs differently than public utilities. 

Demand “Very Strong” in Nation's First Carbon Allowance Auction

Despite the market turmoil and liquidity concerns on Wall Street in recent weeks, the nation's first government-run auction of carbon dioxide emissions allowances met with "very strong demand," according to the coalition of ten states, the Regional Greenhouse Gas Initiate (RGGI), that is implementing a mandatory carbon dioxide cap-and-trade program in the Northeast and Mid-Atlantic United States. The next auction will take place on December 17, 2008.

On September 29, 2008, RGGI announced that its first carbon allowance auction had generated approximately $38 million in revenues for six of the ten RGGI states that participated in the auction—Connecticut, Maine, Maryland, Massachusetts, Rhode Island, and Vermont. RGGI reported that the 59 participants represented diverse interests from across financial, energy, and environmental sectors. Demand was so strong that participants sought to purchase nearly four times the number of allowances available for sale at the auction. The price of allowances reflected this demand, with the 12,565,387 available allowances selling at a market clearing price of $3.07 per allowance. This figure is reported to be approximately 65 percent above RGGI's predetermined minimum floor price of $1.86, or 80 percent of the modeled 2009 allowance price.