A US appeals court reinstated limits on nitrogen oxides and sulfur dioxide emissions in late December in 28 eastern states and the District of Columbia. The limits will require power plants in the affected states to reduce NOx and SO2 emissions or buy potentially costly allowances to cover them. The limits — called the “clean air interstate rule” or “CAIR” for short — were issued in final form by the US Environmental Protection Agency in 2005. The limits take effect in two phases in 2009 and 2015 for NOx and 2010 and 2015 for SO2.
The reinstatement is temporary until EPA can come up with new rules to control both pollutants, but the court set no deadline for the agency to act. When fully implemented, EPA estimates that NOX
emissions would be reduced by 61% from 2003 levels and that SO2 emissions would be reduced by 45% from 2003 levels.
The same US appeals court that reinstated the clean air interstate rule in late December struck it down in July 2008 after concluding that there were “more than several fatal flaws in the rule.”The court issued its latest decision on December 23. The case is called State of North Carolina v. EPA. The United States already regulates SO2 and NOx through the acid rain and NOx budget trading programs.
Under the acid rain program, which was developed in 1990, the government distributes allowances to power companies to cover SO2 emissions from generating facilities and some allowances are also sold each year in public auctions.
Facilities that started operating in 1996 or later are not allocated allowances. These facilities must purchase allowances at the government auction or in the market. Each allowance represents the right to emit one ton of SO2. Companies must have allowances each year to cover their emissions. Anyone who was not given enough allowances by the government to cover his emissions must either take steps to reduce emissions or buy allowances at the government auction or in the market from other companies that reduced emissions thereby freeing up allowances for sale.
It is not clear how a revised clean air interstate rule — if EPA eventually issues one — might affect other air emissions regulatory programs and proposals that assumed that NOx and SO2 air emissions would decrease. For example, before the court’s latest decision, EPA had already announced that it was dropping an hourly air emissions test (in favor of allowing projected emissions to be averaged over an entire year) when deciding whether a “new source review” is required for major new facilities or major modifications to existing facilities.
In addition, it is unclear how NOx and SO2 credits trading markets will react to the uncertainty inherent in a revised CAIR. The risk is to companies that hold on to unused allowances expecting to find some value for them in the future and to anyone making forward purchases of allowances.
Many people expect the Obama administration to issue a plan to revise CAIR shortly after taking office. Carol Browner, the EPA administrator under President Clinton, has been put in charge of energy and climate change policy at the White House.
The Obama administration is expected to abandon an effort to reinstate limits the Bush administration proposed
on mercury emissions from power plants.
The limits — called the “clean air mercury rule” or “CAMR” for short — would have required a 70% reduction in mercury emissions by 2018. They would have set a nationwide cap on emissions of 38 tons in 2010, dropping to 15 tons in 2018.
The same US appeals court that struck down and later reinstated the clean air interstate rule set aside the mercury rule in February 2008. The Environmental Protection Agency petitioned the US Supreme Court in October to rehear the case. The Supreme Court extended the time to respond to the petition until January 21, 2009, one day after the new Obama administration takes office.
The mercury rule would have applied to coal-fired power plants that sell more than 25 megawatts of output to the electricity grid. It would have set performance standards for new plants and established a cap-and-trade program limiting mercury emissions for both new and existing coal-fired power plants.
The mercury rule has been in the courts since 1992 when the National Resources Defense Council sued the Environmental Protection Agency for not treating power plants as subject to regulation under section 112 of the Clean Air Act, the section that regulates hazardous air pollutants. Section 112 requires installation of maximum achievable control technology, or “MACT,” at all plants
subject to the section. EPA eventually issued a finding in December 2000, as President Clinton was preparing to leave office, that it was appropriate and necessary to regulate mercury from coal and oil-fired power plants as a hazardous pollutant.
Once a source category is listed under section 112, then the Environmental Protection Agency has three years to propose a hazardous pollutant standard. The Bush administration felt that regulating mercury under section 112 would cripple the coal-fired power industry. It removed coal and oil-fired power plants from the section 112 list and proposed using a cap-and-trade approach under section 111 of the Clean Air Act to regulate mercury. The environmental community views regulations adopted under section 111 as weaker than any regulation imposed under section 112.
The appeals court struck down the Bush administration’s cap-and-trade program for mercury in February because the government failed to follow the required administrative process for any delisting under section 112. The court threw out the Bush mercury rule in its entirety. It did not ask EPA to take any further action. This now leaves EPA with two options in theory. One is to try properly to delist oil- and coal-fired power plants. The other is to press forward with requiring owners of such power plants to install the maximum achievable control technology to limit emissions.
EPA has not developed a federal mercury MACT. In 2004, it proposed MACT for coal-fired power plants at a level of 2 lb/TBtu (bituminous fired) and 5.8 lb/TBtu (subituminous fired). For comparison, Virginia issued a permit to construct a coal-fired power plant in June 2008 that included a mercury limit of 0.09 lb/TBtu. Environmentalists are challenging the Virginia permit limit as too generous.
A federal district ruled in early December that Duke Energy must do a MACT analysis for the Cliffside power plant that the company has under construction in North Carolina. Duke is appealing. The case is Southern Environmental Law Center, et al. v. Duke Energy Carolinas.
Duke received an air emissions permit from the North Carolina Department of Environmental and Natural Resources in January 2008 to construct a new coal-fired power plant. Construction began shortly after the permit was issued (on January 30, 2008 according to Duke, but on February 9, 2008 according to environmentalists).
The clean air mercury rule was struck down by a court on February 8, 2008. Environmental groups challenged the Duke permit, arguing that because there was no clean air mercury rule when construction of the plant got underway, the plant should have been considered on the section 112 list of plants that can only be built if they install maximum achievable control technology to reduce mercury emissions.
The federal district court that heard the case declined to stop construction. However, it ordered Duke to submit a full mercury-control assessment to state environmental regulators. Previously, Duke had agreed to provide a MACTlike assessment on a voluntary basis, but resisted a formal MACT determination with public review.
North Carolina has no blanket policy of reviewing new coal-fired power plants for MACT controls. Duke asked the state to make such a determination in its case soon after the federal district court ruling. The state environmental department issued a “notice of intent to disapprove” Duke’s request on December 17.
Duke also applied to modify its air emissions permits with respect to hazardous air pollutants. Under the modification, the Cliffside plant would be considered a minor air emissions source emitting less than 10 tons per year for any single hazardous air pollutant and less than 25 tons per year for any combination of such pollutants. The environmental groups who challenged the original permit are skeptical that the facility could be considered a minor source. Written comments regarding the modification are due on January 22.
The lesson from the Duke case is that air emissions permits to construct coal-fired power plants that do not reflect MACT for mercury may be challenged.The Natural Resources Defense Council said in a press release last February 28 that the ruling may affect coal-fired plants in 13 states.
Greenhouse Gas Regulation
The Environmental Protection Agency issued a memo in mid-December rejecting a finding by a permit appeals board that it should have considered whether to require a developer who plans to build a power plant in Utah that will burn waste coal as fuel to install best achievable control technology to control carbon dioxide emissions. The Environmental Appeals Board made the finding in
The power project is one being constructed by Deseret Power near Bonanza, Utah. An EPA regional office issued a so-called PSD permit allowing the developer to start construction. PSD stands for “prevention of significant deterioration.” A PSD permit is the kind of permit issued to developers with projects that are considered major stationary sources in attainment areas.
The EPA regional office issued the PSD permit in August 2007.The Sierra Club then challenged the permit, in part, based on the failure by the EPA regional office to consider whether to
impose BACT for CO2 emissions.The Sierra Club argued that the US Supreme Court decision in the case Massachusetts v. EPA that greenhouse gases are pollutants requires EPA to take
action to control CO2 emissions.The Clean Air Act prohibits construction of major new emitting facilities (or major modifications to existing facilities) unless the owners install best achievable control technology for each “pollutant subject to regulation.”The EPA regional office that issued the permit argued that while companies are required to monitor and report CO2 emissions, they are only required to install best achievable control technology to control “pollutants subject to regulation,”which, in its view, means only those pollutants that are regulated currently.The federal government has not issued any limits yet on CO2 emissions.
The Environmental Appeals Board said the following when it sent the permit back to the EPA regional office:
In remanding this permit to the Region for reconsideration of its conclusions regarding the application of BACT to limit CO2 emissions, the Board recognizes that this is an issue of national scope that has implications far beyond this individual permit proceeding, The Board suggests that the Region consider whether interested persons, as well as the Agency, would be better served by the Agency addressing the interpretation of the phrase “subject to regulation under this Act” in the context of an action of nationwide scope rather than through this specific permitting proceeding.
The EPA administrator released a memo on December 18, 2008 rejecting the appeals board finding. The memo said the government is not required to consider CO2 emissions when issuing air emissions permits under the PSD program. Environmentalists fear that this interpretation, if allowed to stand, will lead to a rush to permit new coal-fired power plants without consideration of CO2
emissions before the new administration takes office. Thus, it seems clear that any new air emissions permit issued under the PSD program without CO2 controls will draw legal challenges.
The International Finance Corporation is expected to publish final environmental, health and safety guidelines for thermal power plants financed by the IFC — an arm of the World Bank — early in 2009. The public comment period ended on May 11. No major changes are expected from the guidelines the IFC proposed earlier. The guidelines apply to power plants with a total heat
input capacity of greater than 50 megawatts and that use gas, liquid and solid fuels or biomass for fuel. The guidelines describe issues associated with the environment (air emissions, aquatic habitat alteration, effluents, wastes, hazardous materials and oil and noise) and provide recommendations to reduce environmental impacts associated with these facilities.
They are important because they establish benchmarks that commercial banks also tend to follow. They supplement guidelines that the IFC issued earlier for wind farms and geothermal projects.
The US Supreme Court heard arguments in three consolidated cases in early December on whether the government is allowed under the Clean Water Act to compare costs to benefits when determining the best technology available to control water pollution associated with existing cooling water intake structures.
Many of the questions asked by the Supreme Court justices focused on how such cost comparisons can be made — for example, what is the value of a fish? The decision has potentially huge economic consequences for so-called “one-pass” facilities that withdraw water for cooling purposes and discharge it directly back into a body of water without any recirculation. An example
of a one-pass facility is an older power plant without a closed-cycle system, like a cooling tower, to recirculate water it uses for cooling. A decision that cost-benefit comparisons are not allowed could require costly upgrades to existing power plants. Estimates of the total cost run as high as $585 million.
The consolidated cases are Entergy Corp. v. Riverkeeper, PSEG Fossil v. Riverkeeper and Utility Water Act Group v. Riverkeeper.
Existing cooling water intake structures are regulated under section 316 of the Clean Water Act. That section requires “effluent limitations that will assure protection and propagation of balanced, indigenous population of shellfish, fish, and wildlife.” Current EPA regulations require facilities with existing cooling intake structures to use best technology available or its equivalent to reduce any adverse environmental impacts.
A federal appeals court ordered EPA in January 2007 to reconsider several provisions of its existing regulations on cooling water intake structures at existing facilities in a case called Riverkeeper, Inc. v. EPA. The Riverkeeper court found that EPA improperly rejected selection of closed-cycle cooling as the best technology available, in part because the court could not determine whether EPA had properly weighed cooling tower costs and benefits when drafting the regulations. In essence, this means that future regulations could require existing facilities install cooling towers or achieve an equivalent reduced level of environmental impact.
A decision by the Supreme Court is anticipated in the spring of 2009.
Carbon Capture and Storage
The Environmental Protection Agency is moving to adopt regulations for carbon sequestration under ground. The comment period for these proposed rules for underground storage of carbon on a long-term basis closed in December. The government currently regulates five classes of injection wells (including several subtypes of wells within these classes). Government standards for the various wells vary according to the type of material injected and the depth of injection under ground. For example, hazardous substance injection is falls under class I. Carbon sequestration falls under a new class of underground injection control wells called class VI.
EPA proposed rules for carbon sequestration in July 2008. Its proposed rules include requirements for well location, construction, testing, monitoring and closure. Critics charge that EPA did not provide useful guidance with respect to liability under the Resource Conservation and Recovery Act (RCRA) or the Comprehensive Environmental Response, Compensation, and Liability Act (CERCLA). RCRA applies to hazardous waste from generation to disposal. It is unclear whether hazardous waste will be generated from operation of these proposed wells. According to the
proposal, EPA cannot provide a blanket determination that impurities in the carbon dioxide injection stream are considered hazardous. CERCLA provides a mechanism for the government and private parties to recover the costs of environmental cleanup of hazardous substances. Although CO2 itself is not considered a hazardous substance (or waste), impurities in the CO2 may be
hazardous. The amounts of any impurities in the CO2 will be dictated by factors such as fuel source composition (for example, coal type) and pollutant removal technologies. Although the proposed rules note that the injection of hazardous substances would be regulated under existing class I regulations (as opposed to class VI regulations), EPA did not address whether liability under CERCLA would be created by disposing of a hazardous substance (in the form of CO2 with impurities). Its proposal notes that the CO2 stream may … react with groundwater to produce listed
hazardous substances such as sulfuric acid. Thus, whether or not there is a ‘‘hazardous substance’’ that may result in CERCLA liability from a sequestration facility depends entirely on the make-up of the specific CO2 stream and of the environmental media (e.g., soil, groundwater) in which it is stored. CERCLA exempts from liability certain ‘‘federally permitted releases’’ including releases in
compliance with a [disposal] permit under the [Safe Water Drinking Act].
EPA acknowledged that hazardous substances may be created as a result of the injection process, but failed to address the ramifications of these hazardous substances. If hazardous substances and waste are generated as a result of CO2 injection, then RCRA and CERCLA may be triggered. Until these issues are addressed, investors may be hesitant to fund sequestration projects considering the unknowns associated with RCRA or CERCLA liability and the potential new avenues for citizens to challenge carbon sequestration facilities (citizen suits under RCRA for imminent and substantial harms). The comment period closed on December 24.