Fuel Additives

The US Environmental Protection Agency eliminated a requirement in May that gasoline must include an oxygenate fuel additive like ethanol and ETBE made from ethanol.

The Clean Air Act — as interpreted by the Environmental Protection Agency —required until earlier this year that all fully reformulated gasoline sold in the United States must include a 2% oxygenate additive. The main additive has historically been methyl tertiary butyl ether — called “MTBE” — but refineries had been switching to ethanol and ETBE because of concerns about possible groundwater pollution caused by MTBE.

In late February, the government withdrew the oxygenate requirement altogether in California, but provided an additional 270 days of lead time before dropping it for the rest of the country.

On May 8, EPA cut short the transition period for the rest of the country.

The abrupt end of the oxygenate requirement comes amid concerns about the adequacy of ethanol supplies. Although reformulated gasoline used in air quality nonattainment areas will no longer have to comply with oxygen content requirements, it will still have to meet the other performance requirements in section 211 of the Clean Air Act. MTBE could have been used by refiners to comply with the remaining standards, but would have been gradually withdrawn from the market in response to environmental contamination problems caused by MTBE.

Where spills and leaks have occurred, it has been found that MTBE readily mixes with groundwater, resulting in potentially extensive contamination. This has led to increasing amounts of product liability litigation in which the MTBE is alleged to be a defective product for which the refiner should be held liable. The defective product claims represent a sharp departure from US environmental laws, which typically exempt manufacturers of commercial products from liability for contamination caused by their customers. Refiners have argued that the Clean Air Act’s oxygen mandate provides a legal defense to the product liability claims.

Several commentators have noted that if EPA stops requiring MTBE to be mixed with gasoline, all MTBE use will immediately cease because refiners will find MTBE too risky to use if the product is no longer mandated, and this could lead to a sudden increase in demand for ethanol beyond the available supply. They also argue that emissions of other air pollutants will also increase, because ethanol evaporates more readily than MTBE.

Ethanol use is already expected to increase in the United States due to a requirement in the Energy Policy Act last August that US motor vehicle fuel must include at least 7.5 billion gallons a year of ethanol by 2012. Some people argue that ethanol supplies will be stretched too thin to make up for the loss of MTBE in the reformulated gasoline program.

Ethanol Air Permits

The Environmental Protection Agency proposed in early March to let larger ethanol facilities be built without the need to go through a permitting process first for projects considered potential “major sources” of air pollutants.

If adopted, the proposed regulation would more than double the threshold under the Clean Air Act before a major source permit is required.

Most ethanol plants are built currently with “minor source” permits that do not typically require the application of the most advanced air emissions control technologies (known as “best available control technology”) and usually do not impose other potentially-burdensome requirements that might cut into profits. In order to stay within minor source levels, ethanol facilities must not emit more than 100 tons per year of any of several pollutants, including sulfur dioxide, nitrogen oxide, carbon monoxide and particulate matter. The 100-ton threshold applies, because such facilities are considered “chemical processing plants” under the applicable EPA regulations.

By specifying that ethanol facilities are not chemical processing plants, the EPA proposal would move them into a category with a much higher threshold for obtaining a major source permit. Ethanol plants would not be required to apply for a major source permit and incorporate best available control technology unless their emissions reach 250 tons per year of a covered pollutant. Environmental safety groups are objecting to the regulation, asserting that it would lead to higher emissions with the potential to harm communities near ethanol plants.

The proposed regulation addresses longstanding objections by ethanol producers and grain processors that emissions from ethanol facilities are very similar to, and should not be regulated differently than, grain processing and food production facilities. Grain processing and food production facilities not involving ethanol are not subject to the 100-ton limitation. For example, most of the particulate matter emissions from ethanol plants come from the handling and processing of grain, much like other types of grain handling and food processing operations. Similarly, SO₂, NO_x and carbon monoxide emissions are not the result of late stage ethanol production and the denaturing process, but instead come from fuel combustion associated with a power source at the facility. Such power sources are also used in many food processing operations.

The obligation to limit particulate matter, SO₂, NO_x, and carbon monoxide emissions can be a significant constraining factor on ethanol facility size. Although volatile organic compound emissions at ethanol facilities are higher than grain and food production facilities, they tend not to be a material constraining factor or tend to be independently regulated under other emissions programs that require strict VOC control even for facilities that do not exceed EPA major source thresholds.

Even though most ethanol facilities are constructed in rural areas where air quality already complies with national ambient air quality standards, environmental groups and some state environmental officials are opposed to the proposed rule out of concern for damage to air quality, particularly in national parks and, in the case of state officials, out of concern for the potential to limit the state’s ability to attract other industries if too much of the state’s capacity to absorb new air pollutants is consumed by ethanol plants.

Greenhouse Gas

According to a World Bank report released in early May, the global carbon emissions trading market saw explosive growth in 2005 to an estimated level of more than $8.2 billion. This represents an increase of more than 10 times the value of global carbon trading activity in 2004. Not surprisingly, most of the increase was fueled by the emissions trading scheme that took effect in the European Union in 2005.

The report, entitled State of the Carbon Market 2006, also covers the first quarter of 2006, in which an estimated $6.6 billion of carbon transactions also occurred. According to the report, almost 330 million tons of carbon dioxide equivalents were traded internationally in 2005 and another 209 million tons were traded in the first three months of this year. By comparison only slightly more than 16 million metric tons were traded in 2004. Of the 330 million tons, approximately 322 were traded under the European trading scheme. The next closest jurisdiction was Australia, where the New South Wales greenhouse gas abatement scheme logged transactions totaling 6.11 million tons of carbon dioxide equivalent during the 2005 and another 5.5 during the first quarter of 2006. Trading within the Chicago Climate Exchange, which is a voluntary US market for carbon emissions trading, actually declined from 2.4 million to 1.45 million tons in 2005, but the exchange almost matched its 2005 total with 1.25 million tons carbon dioxide equivalent in trades in 2006.

Although most of the market value is tied to trading in the European Union, a majority of the greenhouse gases traded come from developing countries. Projects from developing countries and economies in transition totaled 364 million tons of carbon dioxide equivalent of the 524 tons that were traded during the period covered in the report.

As the report’s main author, Karan Capoor of the World Bank, points out,“[T]he data makes it clear that carbon is now a financial commodity, complete with a price and with factors that will affect that price.”

Although a robust carbon trading market has developed in Europe, the price of carbon allowances in the European market fell after news from several European Union member countries that their 2005 emissions were below quota, a fact which could reduce demand for allowances in the future. Phase I of the European trading scheme, which took effect last year and ends after 2007, applies to carbon dioxide emissions from more than 12,000 European facilities, including power plants, refineries, ferrous metals and mineral operations and pulp and paperboard activities. Individual EU member countries allocate allowances to the covered plants based on operating expectations. Each plant must hold one allowance for each ton of carbon dioxide it emits in a year. The lower-thanexpected carbon dioxide emission rates means that there will be less demand on the whole for allowances to cover allowance shortfalls.

The Chicago Climate Exchange announced in early May that one of its members executed the first trade of greenhouse gas allowances between trading systems in Europe and North America. In the transaction, Baxter Healthcare Corp. transferred 100 metric tons of carbon allowances from its operations in Ireland to an account with the Chicago Climate Exchange. The allowances, which were issued under the European trading scheme, will be used by Baxter to comply with its voluntary commitment at the Chicago exchange to reduce greenhouse gas emissions. Chicago exchange members agree voluntarily to make a 4% reduction in their greenhouse gas emissions by 2006 and a 6% reduction by 2010. The Chicago exchange launched continuous electronic trading of all six Kyoto greenhouse gases on December 12, 2003. Member companies agree to achieve the reductions from a baseline established from their operations in the period 1998 to 2001.

Plant Modifications

A US appeals court in Washington set aside an EPA regulation in March that was supposed to clarify when a company making changes at an existing facility must get prior approval under the Clean Air Act. The regulation — known as the equipment replacement provision — allows more expensive repairs and maintenance of existing facilities without having to install state-of-the-art emissions controls.

Under the Clean Air Act, owners of existing plants must comply with “new source review” requirements, including installation of modern emissions controls, if they make changes at their facilities that go beyond “routine repair and maintenance.” 

What qualified as routine repair and maintenance in the past had been the subject of litigation during the Clinton administration, which took the position that many aging power plants had improperly avoided expensive new emissions controls and even shutdown while making extensive repairs or even improvements to their equipment.

Although the Bush administration has continued to prosecute cases initiated by its predecessor, it has generally not brought new ones and has tried to broaden the routine repair exemption. In October 2003, it proposed rules that would allow existing plants to replace components with identical or functionally-equivalent components as long as they do not exceed 20% of the replacement value of the unit as a whole and do not change its basic design parameters.

The US appeals court in Washington said in March that the Bush proposal violates section 111(a)(4) of the Clean Air Act. The court said Congress broadly intended that “any physical change” that results in an emissions increase should be subject to new source review permitting. Therefore, the Environmental Protection Agency did not have authority to limit this to “physical changes that are costly or major,” nor did EPA have the power to allow changes that increase emissions by more than a de minimis amount.

There are recent signs that EPA may be ramping up enforcement against possible new source review violations. The agency sent information demand letters under section 114 of the Clean Air Act to power companies in Phoenix, Arizona, Topeka, Kansas and LaCrosse, Wisconsin on April 26 seeking information about possible modifications to power plants that were made without first getting proper permits. EPA has not indicated that it intends to reembrace the Clinton approach to new source review enforcement, but it may have little choice in light of the appeals court decision.

Mercury Emissions

Minnesota Governor Tim Pawlenty signed legislation in early May requiring the three largest coal-fired power plants in the state to cut their mercury emissions by 90% by 2014.

The new law forces Xcel Energy to install mercury controls at its Oak Park Heights and Becker, Minnesota power plants and requires Minnesota Power to install controls at its Cohasset power plant. The controls will be phased in to avoid shutting down all three plants simultaneously, with some controls to be in place by 2010. When implemented, the emissions of mercury at the three plants will be reduced by a total of 1,200 pounds per year, or one-third of the total mercury emissions in the state. The utilities will have the ability to use expedited rate recovery for the cost of the installations.

Because the precise technology for achieving these reductions is uncertain, the law also allows for time extensions, if needed, and it gives Minnesota regulators the authority to reduce the 90% goal after reviewing and approving mercury reduction plans from the facilities. In North Carolina, the Department of Environment and Natural Resources issued a proposed mercury reduction regulation for new and existing power plants in May. The regulations would adopt many of the same requirements that are in the “clean air mercury rule” that the federal government proposed in March 2005, but the state will also go beyond the federal requirements to impose additional controls on particular facilities and more stringent rules in general. The proposed regulation would require a 60% reduction in mercury emissions by 2013.

Owners of new units have been given several options, including reducing emissions by 90% and requiring emissions sources to offset their emissions with reduction credits obtained from other sources. The rules could affect possibly 20 power plants in North Carolina. Public hearings on the new regulations will held in June.

The Pennsylvania Department of Environmental Protection will propose soon a 90% reduction in mercury emissions from coal-fired power plants in that state by 2015. The rule would also bar such power plants from trading any mercury emissions allowances that their control efforts might otherwise generate under the federal clean air mercury rule. Instead, each of the power plants would have to meet a strict facility-wide mercury emissions cap.

Opponents of the expected new Pennsylvania regulation assert that it would lead to premature retirement of more than 20% of the state’s coal generating capacity and would force power companies to spend more than $1 billion on new pollution controls without any clear benefit to Pennsylvania residents. A bill has been introduced in the Pennsylvania general assembly that would bar the state environmental department from adopting the expected rule.

Environmental groups have criticized the federal clean air mercury rule. They argue that power plants can use allowances purchased from other locations instead of controlling their own mercury emissions, thereby creating mercury hot spots even if overall mercury emissions are reduced nationwide. A May 15, 2006 report issued by the EPA inspector general criticized the EPA approach on the same grounds, asserting that recent studies undermined EPA’s position that hot spots would not be created. The inspector general said the studies show high levels of mercury deposition from coalburning facilities and suggested the agency develop a plan for monitoring the effects of its clean air mercury rule. The federal clean air mercury rule is supposed to reduce mercury emissions from coal-fired power plants in two phases. In phase I, mercury emissions would be reduced approximately 21% by “co-benefit” reductions resulting from emissions controls that need to be put in place to control SO₂ and NO_x emissions under another EPA program. In phase II starting in 2018, additional mercury controls will be required, leading to reductions of 70% from current emissions levels. Several states and environmental organizations are challenging the federal rule in court, asserting that it will not be effective and that tighter controls are necessary.