Environmental update - April 2004

April 01, 2004 | By Keith Martin in Washington, DC

North Carolina

North Carolina complained to the US Environmental Protection Agency in March that power plants in 13 states that are upwind from North Carolina contribute significantly to air pollution in the state. It wants the federal government to order reductions in nitrogen oxides, or NOx, and sulfur dioxide, or SO2, emissions in 13 states that it says contribute to fine particulate matter, or PM2.5, problems in North Carolina. It is also wants action to reduce upwind contamination from Georgia, Maryland, South Carolina, Tennessee and Virginia that it says contributes to ozone or smog.

The North Carolina allegations are in a petition filed under section 126 of the Clean Air Act, which authorizes EPA to take action against specific air emission “sources” — without working directly through the states — after the agency makes a final finding that upwind emissions make it harder for a downwind state to comply with the national ambient air quality standards.

The petition alleges that the upwind contamination will affect whether the state can comply with its expected obligations under standards issued in 1997 governing 8- hour ozone and fine particulate matter ambient air quality. After lengthy legal challenges to the standards, EPA is expected to issue final designations of new ozone nonattainment areas by mid-April. According to EPA, more than 500 counties are not meeting the new 8-hour ozone air quality standard. The final designations for PM2.5 nonattainment areas are scheduled to be issued in the 2004 to 2005 period. Once the new 8-hour ozone and PM2.5 nonattainment areas are established, states will have to propose rules designed to achieve reductions in ozone precursors (that is, volatile organic compounds and NOx) and fine particulates in order to meet the standards. These new requirements, which will take effect over the period 2007 to 2021, may ultimately require upgrading or installing additional pollution control technology. North Carolina is anticipating that several of its counties will be in nonattainment with the 8-hour ozone and fine particulate matter ambient air quality standards, which will probably necessitate the imposition of costly emission reduction requirements on certain North Carolina air emission sources.

The North Carolina action is essentially a preemptive strike that is intended to keep the pressure on EPA to take additional actions to regulate NOx and SO2. The filing came shortly after EPA proposed an “interstate air quality rule” in January 2004 that focuses on reducing the interstate transport of NOx and SO2 emitted from power plants and other sources that significantly contribute to fine particulate and ozone pollution in downwind states. The proposed rule directs 29 states, including all 13 states named by North Carolina, and the District of Columbia to develop new regulations that will require major SO2 and NOx reductions in a twophase approach similar to the Bush administration’s “clear skies” legislation that is currently pending before Congress. North Carolina and possibly other states are expected to use the section 126 petition process as a forum for advocating more significant NOx and SO2 emission reductions and faster implementation timeframes than proposed in the interstate air quality rule.

The interstate air quality rule would impose a 3.9- million-ton emission cap on SO2 emissions by 2010, approximately a 58% decrease from current SO2 emission levels, and a further cut to a cap of 2.7 million tons of SO2 emissions by 2015, for a total reduction of about 70% from current SO2 levels. NOx emissions would be reduced to a cap of 1.6 million tons by 2010 under the proposed rule, with a further reduction to a cap of 1.3 million tons by 2015, for a total NOx reduction of about 65%.

Cooling Water

EPA Administrator Mike Leavitt signed a final rule in February that affects cooling water intake structures at large existing power plants. The regulations could require significant upgrades to existing cooling water intake systems, particularly at plants withdrawing water from water bodies with sensitive aquatic habitats and species.

Plants that withdraw 50 million gallons a day or more of water from rivers, streams, lakes, oceans or other waters in the US and use at least 25% of the water for cooling purposes will potentially be affected by the new requirements. EPA projects that more than 550 existing power plants will be subject to the rule, and many plants may need to make new technology-based improvements to cooling water intake structures.

The new requirements will be implemented through the existing national pollutant discharge elimination system, or NPDES, program. Plants applying for reissuance of a NPDES permit will have to submit information demonstrating how the facility intends to comply with the new requirements. The reissued NPDES permit will incorporate a new section containing the cooling water intake structure provisions. The new regulations were issued under section 316(b) of the Clean Water Act, which requires EPA to develop rules requiring that the “best technology available” be used to protect aquatic organisms from being impinged or pinned against water intake screens or other parts of the cooling water system, or drawn into the cooling water system and subjected to thermal, chemical or physical stresses. Aquatic organisms such as fish, fish larvae and eggs, crustaceans, shellfish, turtles and other forms of aquatic life are frequently killed or injured in cooling water intake structures.

The EPA rule leaves room for creative solutions that achieve an equivalent level of environmental performance to the presumptive technology requirements. For example, plants with cooling towers will be deemed to be in compliance with the section 316(b) rule, but the rule does not require that cooling towers be installed to meet the performance standards.

The final rule will require all large existing power plants meeting the water withdrawal thresholds to meet certain performance standards. Under the technology performance standards, impingement mortality must decline by 80 to 95% and, depending on the location of the facility, the amount of water withdrawn and energy generation, entrainment must decline by 60 to 90%. Plants generally may choose one of three options to comply. Under the first option, the plant may demonstrate that the cooling water intake structure meets specified technology performance standards that are based on a closed-cycle recirculating cooling system (that is, a wet cooling tower). Under the second option, the plant may install new equipment and take operational or restoration measures to meet the technology performance standards. An example of an operational measure is a screen with a fish return system. Examples of restoration measures are restocking affected fish or creating alternative habitats for them. Under the third compliance option, a plant could make a site-specific determination of what is the best technology available. The conclusion may differ from EPA’s if compliance costs are significantly greater than those considered by EPA. In addition, facilities may substitute restoration and other conservation measures to maintain fish and aquatic life in place of , or in addition to, technology measures. However, this “restoration alternative” will probably be subject to further EPA rulemaking.

The final rule is the second in a series of three rules intended to establish new cooling water intake structure requirements. The first rule addressed new facilities and was issued in December 2001. The third rule is expected in November 2004 and will apply to power plants and other industrial sources using smaller amounts of cooling water.

In related news, a US appeals court largely upheld the section 316(b) rule for new facilities that was issued in December 2001. The court rejected arguments from environmental groups that Congress intended dry cooling systems — such as dry cooling towers that use minimal water — to be the “best available technology.” However, the court agreed with the environmentalists that using restoration measures as an alternative to complying with the performance standards is inconsistent with the Clean Water Act. EPA’s “restoration alternative” was sent back to the agency for further rulemaking. A similar provision allowing for the use of voluntary restoration measures in the new second-phase rule will probably have to be revised to comply with the court decision. The court released its decision in February.

Mercury

EPA received a barrage of negative comments at the three public hearings held at the end of February on a proposed “utility mercury reductions rule” that would regulate mercury and nickel emissions from existing and new coaland oil-fired power plants. At hearings in Chicago, Philadelphia and Research Triangle Park, North Carolina, numerous environmental and public interest groups, local and state agency air division officials and various politicians urged that the proposed rule be rewritten.

The major criticisms are that the “cap and trade” option under the proposed rule is not authorized by the Clean Air Act, the mercury reduction targets are not sufficiently stringent enough, the compliance deadline for achieving the emission reductions is too far off, and the proposal should regulate more air toxics than just mercury and nickel. EPA heard more of the same criticisms in letters earlier this month from 45 US Senators and 10 state attorneys general.

The proposed utility mercury reduction rule became a lighting rod for dissent when the government failed, as expected, to take a traditional “command and control” approach to regulating air toxic emissions from power plants under section 112 of the Clean Air Act. The agency was expected to propose a “maximum achievable control technology,” or MACT, standard that would require compliance by December 2007. Instead, EPA proposed two alternative approaches for reducing mercury emissions from coal-fired plants and nickel emissions from oil-fired plants. It will choose one of the approaches by the end of this year.

One of the alternatives is a traditional MACT standard. The other approach is a “cap and trade” program. The MACT alternative uses a command-and-control approach that would apply to both new and existing coal-fired power plants. For existing plants, the MACT level is set at the average emission limitation achieved by the best performing 12% of plants in a particular category or subcategory of sources. For new plants, the MACT level must be set by law at the level of control achieved by the best controlled similar source. Under the “cap and trade” approach, EPA would implement a nationwide cap on mercury emissions. Coal-fired plants subject to the rule would be required to hold sufficient allowances to cover their annual mercury emissions. Each allowance would authorize the emission of one ounce of mercury. EPA is strongly leaning toward adopting a “cap and trade” program that it believes will achieve steeper reductions in a more cost-effective manner. According to EPA, emissions from coal-fired power plants would be reduced by 30% by 2007 under the MACT approach and by 70% by 2018 under the “cap and trade” option. Environmental groups are seeking at least a 90% reduction in mercury from coal-fired power plants.

Both EPA alternative proposals would apply to coalfired power plants with a capacity of more than 25 megawatts that produce their entire output for sale and to cogeneration facilities that put more than one-third of capacity and more than 25 megawatts on a utility grid for sale. Given the uncertainties surrounding the technologies that will be available to achieve mandated mercury emission reductions, both EPA proposed mercury reduction rules include different emission standards depending on whether a plant burns bituminous, sub-bituminous, lignite or coal refuse. In the MACT standard approach, EPA proposes emission limitations for new and existing power plants based on five subcategories, including the four different fuel types and a separate standard for integrated gasification combined-cycle or IGCC units. EPA projects that mercury emissions would be reduced from 49 tons to 34 tons through implementation of the proposed mercury MACT standards.

Under the “cap and trade” alternative, EPA is proposing a 34-ton mercury emission cap for the first phase, which commences in 2010 and a 15-ton cap for the second phase, which starts in 2018. Mercury allowances would be issued to coal-fired plants based on a unit’s share of the total heat input from existing coal units, multiplied by an adjustment factor that depends on the type of coal. The adjustment factors are 1.0 for bituminous, 1.25 for subbituminous and 3.0 for lignite coals. Under the “cap and trade” approach, EPA would set mercury MACT standards for new coal-fired plants at substantially the same levels as the mercury MACT emission limits proposed in the command-and-control approach.

On March 16, 2004, EPA published a supplemental proposal with specific provisions of a model “cap-andtrade” rule that states may adopt. The proposal spells out applicability requirements, allowance allocation formulas, emission banking, and compliance and enforcement mechanisms. The proposal also includes a “backstop” price of $2,187 per ounce of mercury that would cap the price of a mercury allowance under the trading program. EPA held a hearing on the supplemental proposal at the end of March in Denver.

Given the criticism, EPA has agreed to extend the public comment period on the rule from March 30 to April 30. EPA Administrator Mike Leavitt has also directed agency personnel to consider whether earlier cost estimates take into account the possibility that mercury control technology costs may decline over time.

Under a court-approved settlement, EPA must issue a final rule by December 15, 2004. The costs to comply with the new rule are expected to be substantial. Like many environmental regulations, the parameters of the final rule will probably be settled in court.

NOx Emissions

EPA issued a”Phase II” supplement to its rule requiring most states east of the Mississippi River to adopt state implementation plan, or “SIP,” rules requiring reductions of nitrogen oxides or NOx. The “NOx SIP call rule” was originally issued in October 1998, and the Phase II supplement responds to a court decision that struck down portions of the original rule. The original rule has already required a number of affected power plants owners to decide whether to install pollution control equipment, such as selective catalytic reduction systems, shut down particular units, or embark on a program to purchase sufficient NOx allowances. The Phase II rules will have similar effects on power plants in Georgia and Missouri that are now subject to the NOx SIP call rule.

The initial rule required 22 states east of the Mississippi River plus the District of Columbia to take steps to reduce NOx to a specified level for each affected state by 2007. A federal appeals court largely upheld the NOx SIP call rule in March 2000. However, the court disagreed with extending the rule to three states — Georgia, Missouri, and Wisconsin — on grounds that there was too little evidence indicating that NOx emissions from these states contribute to ozone nonattainment in downwind states. The court sent this issue and two other key issues back to EPA for further proceedings.

In response to the court’s ruling, EPA proceeded to regulate power plants and other large stationary sources within the remaining 19 states and the District of Columbia. Sources in these states are required to comply with the new NOx SIP call standards by May 31, 2004. The NOx SIP call standards apply during the summer ozone season that runs from May 1 through September 30.

The Phase II rule largely completes the agency’s response to the court’s decision. In the Phase II rule, EPA has concluded that power plants and other large industrial combustion sources in Wisconsin and portions of Alabama, Georgia, Michigan and Missouri that are classified as the “fine grid” modeling areas will be excluded from the NOx SIP call. Georgia and Missouri will be required to submit to EPA their state regulations implementing the NOx SIP call requirements by April 1, 2005 for approval. These two states will have to comply with the NOx SIP call rule by May 1, 2007.

Under the Phase II rule, EPA also set standards for natural gas-fired stationary internal combustion engines and diesel and dual-fuel combustion engines, and it revised the definition of “electric generating units” to exclude certain cogeneration units from the NOx SIP call rule.

Brief Updates

American Electric Power and Cinergy announced plans in February to report on the potential financial burden of implementing future greenhouse gas emission reduction requirements. The reports are expected to be released to shareholders by September.

The state of Washington adopted a new law at the end of March requiring new power plants to offset 20% of the CO2 they emit through mitigation projects. Companies can either finance mitigation projects on their own or pay a fee of $1.60 per ton of CO2.

The US Senate defeated a proposal by Senator Frank Lautenberg (D–New Jersey) in March to reinstate a “Superfund tax” on chemical and petroleum companies that was used to finance the a federal Superfund trust fund for cleanups undertaken by the federal government. The vote was 43 to 53. Reinstatement of the Superfund tax is opposed by the Bush administration.

EPA increased its maximum penalties for civil violations of environmental laws in March by 17.3% to account for inflation increases since 1997. For example, the maximum penalty for most Clean Air Act violations has increased from $27,500 to $32,500 a day per violation.

The European parliament recently approved the first “polluter pays” liability law. The environmental liability plan is now cleared for final approval by the Council of Ministers, which is expected in the next few weeks. Once approved by the Council of Ministers, the European Union countries will have three years to implement the measure, which will penalize companies that cause environmental damage by releasing heavy metals or producing dangerous chemicals.

More than 125 environmental and public interest organizations petitioned the US Environmental Protection Agency in February to ask that the agency take steps to regulate the disposal of coal combustion waste in mines, quarries and surface impoundments. EPA is reportedly working on draft nonhazardous waste regulations that will establish standards for disposing of coal ash and other coal combustion wastes in landfills and surface impoundments.

Finally, EPA took action in late March to remove four subcategories of combustion sources from the list of sources of hazardous air pollutants, or “HAPs.” These sources include new lean premix gas-fired turbines, diffusion flame gas-fired turbines, emergency stationary combustion turbines, and stationary combustion turbines operated on the North Slope of Alaska. EPA is also proposing to exempt these types of combustion turbines from the new HAP emission standard for stationary combustion turbines that was published in the Federal Register on March 5.