By Roy Belden
Clear Skies Setback
Republican leaders have largely given up on trying to pass a “Clear Skies Act” in the US Senate this year after the measure failed on a tie vote to clear the Senate environment committee in March.
The “Clear Skies Act” would require reductions in three pollutants — nitrogen oxide, or NOx, sulfur dioxide, or SO2, and mercury — nationwide from power plants. The bill was controversial because Democrats also wanted reductions in carbon dioxide, which contributes to global warming, and Republicans were unwilling to go along. Republicans hold a majority on the Senate environment committee, but one Republican — Senator Lincoln Chafee (R-Rhode Island) — voted with Democrats, and the Republicans were unable to persuade at least one Democrat to break ranks and support a bill without carbon dioxide limits.
The US Environmental Protection Agency then finalized a “clean air interstate rule” that is described in a separate article in this issue of the NewsWire. This rule will achieve many of the same reductions in NOx and SO2 contemplated by the Clear Skies Act; however, the new regulation is limited in scope to 28 eastern and midwestern states. The Clear Skies Act would have applied to the entire country and a new statute would have been less susceptible to the inevitable litigation that follows any major EPA rule.
The Senate environment committee chairman — James Inhofe (R-Idaho) — said the Clear Skies Act will not be reconsidered by the committee this year. Nevertheless, several lawmakers still hold out hope that a compromise measure can be passed by the full Congress later in the year. Now that the clean air interstate rule has been finalized, there is less urgency to act, and it would be surprising if the bill receives any further serious consideration by this Congress.
Clean Air Settlements
The US Environmental Protection Agency reached noteworthy settlements with two utilities in March to resolve alleged violations of the Clean Air Act.
The utilities were accused of making major modifications to coal-fired plants in the late 1970’s through the early 1990s without getting the necessary “new source review” permits from the permitting authorities. The crux of the issue is a dispute over what constitutes a “major modification” that triggers a permit review.
The first settlement involved five power plants owned by Illinois Power and the second settlement covered four plants owned by Ohio Edison. Both Illinois Power and Ohio Edison were sued by the US government as part of a large-scale EPA enforcement initiative launched in the late 1990s. To date, the US government has entered into nine settlements to resolve issues raised in the coordinated federal enforcement initiative.
In the Illinois Power settlement, the company agreed to spend as much as $500 million by 2012 to install new pollution controls and upgrade existing pollution equipment at five coal-fired power plants. Illinois Power will install flue gas desulfurization systems on four units at the Baldwin and Havana plants over the next seven years, and NOx controls will be operated year round at these two plants. The five plants will be subject to declining systemwide NOx and SO2 emission caps, which will result in emission reductions of 15,000 tons a year of NOx and 39,000 tons a year of SO2. In addition, particulate matter controls are required to be installed or upgraded at each of the plants. The company also agreed to pay a $9 million civil penalty and to spend at least $15 million on environmental mitigation projects. Illinois Power is also required to retire 30,000 SO2 allowances under the federal acid rain program each year, and NOx allowances allocated under the NOx SIP Call rule are also reduced. The settlement resolves the US government’s pending case against Illinois Power with respect to alleged new source review permitting violations at the Baldwin station. The other four Illinois Power plants were not implicated in the original lawsuit against the company.
Ohio Edison agreed to spend approximately $1.1 billion to reduce NOx and SO2 emissions from four coal-fired plants, and it will install state-of-the-art pollution controls at all seven units at the W.H. Sammis generating station, and the plant will be subject to declining plant-wide NOx and SO2 emission caps. The two largest units at the W.H. Sammis plant will be required to install flue gas desulfurization systems and selective catalytic reduction systems by December 2011. Emissions from the W.H. Sammis plant are expected to decline by a total of 28,567 tons a year of NOx and 134,500 tons a year of SO2. An additional 49,000 tons per year of NOx and SO2 emissions reductions are expected to come from the other three plants. As part of the settlement, Ohio Edison is required to retire a certain percentage of its SO2 allowances under the federal acid rain program each year, and its NOx allowances allocations under the NOx SIP Call rule will also be limited. Ohio Edison also agreed to an $8.5 million penalty and will set aside $25 million for environmental mitigation projects. Of this amount, $14.385 million will be allocated for 20-year power purchase agreements with windpower or landfill gas projects from Connecticut, Pennsylvania, New Jersey or New York. While EPA has a long history of including environmental mitigation projects as part of its settlements, this appears to be the first settlement where renewable energy purchases were required as part of the agreement.
The settlement resolves the ongoing enforcement lawsuit against Ohio Edison. In August 2003, a federal district court in Ohio ruled that Ohio Edison violated new source review permitting requirements when it made major modifications to its W.H. Sammis station without first obtaining the requisite permits. The United States v. Ohio Edison Co. case was a major victory for EPA. New York, New Jersey and Connecticut had also filed suit separately against Ohio Edison and were parties to the settlement.
In a related development, EPA issued a notice of violation to the Big Cajun 2 power plant in Louisiana in March charging that the facility violated new source review permitting requirements by replacing boiler elements in units 1 and 2 in the late 1990s without going through the requisite review. The EPA action does not signal a new round of targeted utility enforcement actions, but confirms that the agency is continuing to pursue suspected violators of the new source review program.
Also in March, the Grand Canyon Trust and the Sierra Club entered into a settlement with the Public Service Company of New Mexico resolving a Clean Air Act citizen suit filed against the 1,600 megawatt coal-fired San Juan plant. The environmental groups alleged that the plant was exceeding its applicable emission limits. In the settlement, the Public Service Company of New Mexico agreed to spend an estimated $110 million in capital costs to install state-of-the-art pollution control technology to reduce NOx, SO2, particulate matter and mercury emissions from the plant over the next four and a half years. A portion of these costs will be used to install activated carbon injection systems to reduce mercury by as much as 80% from each of the plant’s four units.
EPA suffered another setback in its efforts to regulate regional haze when a US court of appeals in Washington invalidated an SO2 emissions trading program that five western states adopted in an effort to reduce haze-forming air emissions from power plants and certain other industrial facilities built between 1962 and 1977. The ruling closely follows the logic the same court used in 2002 to invalidate a key provision of a federal regional haze rule.
In the 2002 regional haze rule case, the court said that before the federal government can impose best available retrofit technology or BART requirements on a power plant or other industrial source, it must first find that a particular source contributes to visibility impairment in a so-called class I area, such as a national park or federal wilderness area. The court rejected an EPA plan that would have allowed states to impose BART pollution control requirements on a group of sources instead of individual sources.
Even though the EPA rule was rejected in court, states still had the option of adopting an alternative means of reducing haze-forming emissions so long as it was “better than BART.” Arizona, New Mexico, Oregon, Utah and Wyoming adopted a SO2 emissions trading program to implement the regional haze rule, which was approved by EPA. However, in determining whether the rule was better than BART, EPA used a methodology that was substantially similar to the “group BART” approach that the court rejected in 2002. The similarity brought down the regional approach, and the five states must go back to the drawing board to develop an acceptable haze rule. In the meantime, EPA is expected to propose its own rewrite soon of BART requirements for individual sources. EPA is expected to require states to identify facilities that will be subject to BART by January 2008. The required emissions reductions are anticipated to take effect in 2014, with full implementation anticipated before 2018. The new EPA rule is expected to affect a number of older power plants and industrial facilities that have not previously been required to install or upgrade pollution controls to reduce NOx, SO2, particulate matter and VOCs.
Senator James Jeffords (I-Vermont) proposed in March that utilities should supply at least 20% of their electricity from renewable sources by 2020. Jeffords would define “renewable energy” to include wind, ocean waves, biomass, solar, landfill gas, incremental hydropower and geothermal. The bill would create a national renewable portfolio standard or RPS starting with 5% in 2006 to 2009, and increasing to 10% in 2010 to 2014, 15% in 2015 to 2019, and 20% in 2020 and beyond.
The Jeffords bill would also create a federal renewable energy credit or REC program. Entities generating electricity from renewable energy sources would be able to apply to the Department of Energy for RECs based on the amount of power produced. One REC would be issued for each kilowatt hour of renewable electricity generated. The Department of Energy would also be authorized to issue three RECs for each kilowatt hour of so-called distributed generation, which is defined as reduced electricity consumption from the grid due to the use of renewable energy generated at a customer’s site.
The failure of a retail electric supplier to submit a sufficient number of RECs to cover its RPS requirements could trigger a civil penalty based on the number of RECs not submitted multiplied by the lesser of 4.5¢ or 300% of the average market value of a REC for the compliance period.
The Senate passed a similar RPS requirement in each of the past two Congresses as part of a comprehensive energy bill. An RPS requirement of 10% was dropped from the final bill in negotiations with the House in 2003 (and the energy bill was never enacted). The Senate is expected to try again as the energy bill moves through Congress this year.
In related news, Illinois Governor Rod Blagojevich announced plans in February for an RPS in Illinois. Blagojevich asked the Illinois Commerce Commission to write regulations that will require utilities in the state to supply 8% of their power from renewable sources by 2012. The regulations would also require that 75% percent of the renewable energy be generated by windpower.
The US Department of Energy released interim guidelines for the voluntary reporting of greenhouse gas emission reductions in March.
The department is required by the Energy Policy Act of 1992 to maintain a voluntary registry of greenhouse gas emission reductions that are submitted by various power generating and industrial companies. The interim guidelines make one significant change from an earlier proposal by allowing companies to register greenhouse gas emission reductions occurring outside the United States.
The guidelines create a two-tier process of reporting of emissions reductions versus the registering of emissions reductions. Companies will be able to register emissions reductions achieved after 2002 if they also provide entity-wide greenhouse gas emission inventory data. Entities registering emissions reductions would be recognized for net reductions in their entity-wide emissions.
The guidelines do not create a transferable credit program. In the preamble to the rule, the energy department suggested that registering greenhouse gas reductions would serve as a building block for recognizing such reductions in any future climate change program adopted by the United States; however, the agency acknowledges that it does not have the legal authority to create a transferable credit program that would be binding in any future mandatory climate change program.
The guidelines also explain how to measure or estimate greenhouse gas emissions. There is a 60-day public comment period ending on May 23, 2005. The guidelines will take effect on September 20, 2005. Companies will continue to have the flexibility to report greenhouse gas reductions on a plant-specific or project-related basis. Third-party or independent verification of emissions reductions is “strongly encouraged,” but is not required. While companies are under no obligation to comply with the guidelines, companies may get a public relations benefit by participating.
The US Environmental Protection Agency held the annual acid rain program SO2 allowance auction in late March. The agency offered 125,000 vintage 2005 SO2 allowances and another 125,000 allowances for the 2012 seven-year advance market. The auction prices for 2005 SO2 allowance were more than 250% higher than prices paid for 2004 SO2 allowances in last year’s auction. The average auction price of a 2005 allowance was $702.51 compared to an average auction price of $272.82 for a 2004 allowance last year. The spot market price of SO2 allowances traded by private brokerage firms has been steadily increasing over the past year, and this dramatic price increase appears to be largely driven by the new clean air interstate rule that EPA issued in March.
Local environmental groups filed a lawsuit in mid-March challenging the air permit issued for the proposed 1,500-megawatt coal-fired Thoroughbred generating station in Kentucky. The citizen suit alleges that the US Environmental Protection Agency failed to consult with the US Fish and Wildlife Service under section 7 of the Endangered Species Act before deciding whether to object to the dual pre-construction and air operating permit issued by the Kentucky Environment and Public Protection Cabinet. The environmental groups charge that emissions from the plant will adversely affect several endangered species. The complaint could set a new precedent for raising Endangered Species Act issues as a way to challenge air operating permits.
The US Environmental Appeals Board rejected a pre-construction air permit issued by the Illinois Environmental Protection Agency for the 1,500 megawatt coal-fired Prairie State generating station at the request of the Sierra Club and various public interest groups. The board concluded that the Illinois EPA violated applicable federal procedures when it issued the air permit. The board told the Illinois agency it had to consider comments submitted by interested parties before deciding whether to reissue the permit.
The US Environmental Protection Agency issued two orders in March directing the Illinois Environmental Protection Agency to rewrite portions of air operating permits that were issued to two coal-fired power plants in Illinois. EPA said that the air permits included a number of deficiencies, including the lack of sufficient monitoring to demonstrate compliance with certain emission limits, and several permit conditions contained language that was not practically enforceable.
EPA said in March that the draft environmental impact statement prepared for the Cape Wind windpower project in Nantucket Sound off the coast of Massachusetts was inadequate because the report failed adequately to analyze the potential environmental impacts from the project. The agency reaffirmed its strong support for renewable energy such as wind, but said the draft impact statement should have done a better job of evaluating the potential impact of the project on aquatic habitat, threatened and endangered species, eelgrass and migratory birds. EPA also commented that the Army Corps of Engineers — which wrote the report — failed to address why a smaller scale project, such as a 25% to 75% smaller than proposed, was not considered. The ball is now in the Army Corps court to decide whether to go ahead anyway with a section 10 permit authorizing construction of the project.
EPA issued two proposed rules in the Federal Register in February that establish revised “new source performance standards ”for various boilers and combustion turbines. The first rule would establish NOx, SO2, and particulate matter or PM new source emission limits for large utility steam generating units constructed, modified or reconstructed after February 28, 2005 and PM new source emission limits for large and small industrial-commercial-institutional steam generating units constructed, modified or reconstructed after the same date. The second rule proposes new NOx and SO2 emission limits for stationary combustion gas-and oil-fired turbines constructed, modified or reconstructed after February 18, 2005. The new source performance standards program applies technology-based standards as a backstop to emission limits adopted in the pre-construction permitting process. The new rule for large utility steam generating units would limit NOx emissions to one pound per megawatt hour on a gross energy output basis, SO2 emissions to two pounds per megawatt hour on a gross energy output basis, and PM emissions to 0.015 pounds per million Btu heat input. For large and small industrial-commercial-institutional steam generating units, the PM new source emission limit would be set at 0.03 pounds per million Btu heat input. The proposed NOx new source standard for stationary combustion turbines would be set at one pound per megawatt hour for gas-fired turbines under 30 megawatts and 0.39 pounds per megawatt hour for over 30 megawatts. The SO2 limit for all gas- and oil-fired turbines would be set at 0.58 pounds per megawatt hour. EPA is accepting comments on the first proposed rule until April 29, 2005. The comment period on the second proposed rule expires on April 19, 2005.
— contributed by Roy Belden in New York