Environmental Update December 2003
By Roy Belden
The US Environmental Protection Agency is expected to propose new rules in December that would limit mercury and nickel emissions from coal- and oil-fired power plants. The rules could be costly for owners of existing plants to implement.
The US government is under a December 15 deadline to release the new proposals. The deadline is in an agreement reached in 1998 to settle a lawsuit by environmental groups. There will actually be two alternative proposals. Drafts were sent to the Office of Management and Budget in late November for internal review.
It is unusual for a government agency to release alternative proposals. There will be a period for public comment after they are released.
One of the two proposals is for a “cap and trade” rule to regulate mercury emissions from existing coal-fired power plants. There would be a 34-ton cap during first phase commencing in 2010 and a cap of 15 tons starting in 2018. EPA believes that mercury reductions would be achieved during the first phase through “co-benefit” reductions from existing and anticipated pollution controls to achieve NOx and SO2 reductions that are expected under existing law. In other words, no special effort is required to reduce mercury emissions before 2010. Mercury allowances would be issued to owners of coal-fired plants based on a unit’s share of the total heat input from existing coal units multiplied by an adjustment factor depending on the type of coal: 1 for bituminous, 1.25 for sub-bituminous, and 3 for lignite coals. Mercury is generally more difficult to remove from lignite coals than from bituminous coals.
The first proposal has an interesting legal underpinning. EPA will have to backtrack from its conclusion in December 2000 that regulation of mercury and other hazardous air pollutants from coal and oil-fired utilities is “necessary and appropriate” under the air toxics section of the Clean Air Act. The agency still believes that regulation of mercury from coal-fired plants and nickel from oil-fired plants is “appropriate,” but it does not believe that regulation under the section 112 air toxic provisions is “necessary.” Instead, it is proposing to regulate mercury and nickel from coal and oil-fired plants under the section 111 new source performance standard provisions. Section 111 of the Clean Air Act is much less prescriptive than section 112, and it allows EPA more flexibility in setting mercury and nickel emission limits. Under section 112, EPA must set emission limits at a level representing maximum achievable control technology, or “MACT.” For existing sources, the MACT level is based on the average emission limitation achieved by the best performing 12% of plants in a particular category or subcategory of sources. For new sources, the MACT level must be set at the level of control achieved by the best controlled similar source. EPA has concluded that a “cap and trade” program qualifies as a “standard of performance” under section 111.
The mercury emission limits for new sources will vary depending on the type of coal that is being burned. The EPA proposal would set the following output-based mercury standards: 6.5 x 10-6 lb/MWh for bituminous, 21 x 10-6 lb/MWh for sub-bituminous, 67 x 10-6 lb/MWh for lignite, and 0.53 x 10-6 lb/MWh for coal refuse. For integrated gasification combined-cycle, or “IGCC,” units, EPA is recommending a separate emission limit of 16 x 10-6 lb/MWh.
EPA is offering two approaches to mercury and nickel limits for comment. The second approach would set emissions limits for new sources at the same levels as in the first EPA proposal. However, the limits for existing sources would be different. They are as follows. Existing sources would have the option of complying either with an input-based pounds per trillion British thermal units or an output-based pounds per Megawatt hour standard: 2.0 lb/TBtu or 21 x 10-6 lb/MWh for bituminous, 5.8 lb/TBtu or 61 lb/MWh for sub-bituminous, 9.2 lb/TBtu or 98 lb/MWh for lignite, 0.52 lb/TBtu or 5.5 lb/MWh for coal refuse, and 15 lb/TBtu or 159 lb/MWh for IGCC units.
The proposals are sure to set off a fierce debate. They must be adopted in final form by December 15, 2004.
Rejection of the Kyoto protocol by Russia will send the international community back to the drawing board. The protocol cannot be implemented without at least one of the United States or Russia.
In early December, a senior aide to Russian President Vladimir Putin said Russia will not ratify the protocol in its current form because it places significant limitations on the economic growth of Russia. President Putin had not formally rejected the treaty when the NewsWire went to press.
At last count, 120 countries had ratified the protocol. Russian rejection of the treaty would mean it will not go into effect even in those countries. The Kyoto protocol would have required approximately a 5.2% reduction in greenhouse gas emissions over the period 2008 to 2012. The reduction would be measured against 1990 emission levels.
It is unclear whether the United Nations will try again to forge a global agreement to reduce greenhouse gas emissions, or whether the individual countries will gravitate toward regional pacts. For example, the European Union might stay the course with the greenhouse gas reduction program that it already has well underway. The United States and Australia have both rejected the Kyoto protocol.
The Kyoto protocol provides that it will take effect after it has been ratified by 55 or more countries (including both industrialized “Annex I” nations and developing “Annex II” countries) whose combined emissions levels represent at least 55% of the carbon dioxide emissions from Annex I countries in 1990. As of the end of November, 120 nations had ratified the treaty. Those 120 nations accounted for 44.2% of the 1990 carbon dioxide emissions. Russia accounts for 17.4% of the emissions and thus its ratification of the protocol would have pushed the agreement over the 55% implementation threshold.
A new air emission rule expected to be proposed by the EPA this month will require certain power plants to add or upgrade pollution controls to meet significant sulfur dioxide (or, “SO2”) and nitrogen oxide (or, “NOx”) reduction targets. EPA announced on December 4, 2003 that it will propose a new “Interstate Air Quality Rule” that is directed at reducing the interstate transport of fine particulate matter and NOx, an ozone precursor, emitted from power plants. The new rule will employ a two-phase approach that is similar to the Clear Skies Act bill currently being considered by Congress.
The press release announcing the new transport rule states that upwind sources significantly contribute to fine particulate and ozone pollution in downwind states. The rule is expected to call for a reduction in SO2 emissions from power plants by 3.7 million tons by 2010, approximately a 40% decrease from current levels, and a further cut of 2.3 million tons by 2015, for a total reduction of about 70% from current SO2 levels. The rule is expected to call for reductions in NOx emissions of 1.4 million tons by 2010, and an additional cut of 1.7 million tons by 2015, for a total NOx reduction of about 50%. EPA said that SO2 and NOx emissions will be permanently capped under the new rule and cannot increase. EPA is expected to propose a SO2 and NOx emissions trading program as part of the Interstate Air Quality Rule.
The proposed transport rule is expected to be very similar to the Bush administration’s “clear skies initiative.” It will attempt to obtain substantially the same results as the bill, but through an administrative rulemaking process. EPA affirmed its belief that the clear skies bill is the best approach to reducing multi-pollutant air emissions from power plants, but opted to exercise its existing authority to issue regulations in light of the legislation’s uncertain future.
A final rule is expected to be issued in 2005.
Two key Republican Senators introduced a bill in November that will probably serve as a vehicle for passing multi-pollutant legislation out of the Senate Environment and Public Works Committee next year. The two are James Inhofe (R-Oklahoma) and George Voinovich (R-Ohio). Inhofe is chairman of the committee.
Their revised “clear skies” bill adopts most of the Bush administration’s original clear skies initiative, but with a few important changes. The changes should make complying with the measures less expensive for power companies. The Bush Administration has greeted the Inhofe-Voinovich clear skies proposal as a welcome development.
The bill would require substantial reductions in NOx, SO2 and mercury emissions from power plants by setting nationwide emission caps in a two-phase process. These caps would decline in 2018. Both bills propose a mandatory “cap and trade” emission allocation program for the three pollutants similar to the SO2 allowance trading under the federal acid rain program. Neither bill calls for any cuts in CO2 emissions, a greenhouse gas, from power plants.
One of the most significant changes from the original Bush plan is the Inhofe-Voinovich bill would exempt qualifying cogenerators (as defined under the Public Utility Regulatory Policy Act, or “PURPA”) from mercury, NOx, and SO2 requirements in the bill. Under the original Bush plan, all power plants with a capacity of more than 25 megawatts and selling more than one-third of their power to the grid would be regulated. Under the new bill, cogenerators would be able to opt into the clear skies program. If a cogenerator opts in, then it would be able to sell its excess emission reduction credits; however, it would be required to comply with the other applicable requirements of the measure.
The Inhofe-Voinovich bill would also make available a pool of mercury, NOx and SO2 allowances for new units. Instead of allocating 100% of the available allowances under the program, the new source set aside would hold back a number of allowances in reserve for new projects. The bill would create a 7% pool for SO2 allowances and a 5% pool for NOx and mercury allowances. Similar to the existing acid rain program, one NOx allowance or one SO2 allowance would be required for each ton of NOx or SO2 emitted, respectively. A mercury allowance would be required to generate one ounce of mercury. The creation of a new source allowance set aside is intended to encourage the development of new, cleaner generating facilities.
One other significant change from the Bush plan is the bill would increase the mercury emissions cap to be achieved by 2010 from 26 tons under the Bush plan to 34 tons. The 34-ton mercury cap is reportedly the level of mercury emission reductions that can be achieved through “co-benefit” reductions in NOx and SO2 emissions that would be required by 2010. This suggests that many regulated coal-fired plants would be able to avoid installing costly mercury control technologies until the second phase of the clear skies measure kicks in. The first phase of mercury reductions would have to be reached by 2010 and the second phase — reducing mercury to 15 tons — would not be required until 2018.
It is not clear the Inhofe-Voinovich bill will be able to make it out of committee. It remains controversial. Even if it does, it is doubtful that Congress will be willing to tackle such a politically charged issue during an election year.
In related news, the US Senate rejected a bill in late October that would have required electric generating facilities and other manufacturing plants to cut back their greenhouse gas emissions to 2000 levels by 2010.The vote for the bill was 43-55.
The US Department of Energy proposed changes in November for voluntary reporting of greenhouse gas emission reductions.
The department maintains a voluntary registry of greenhouse gas emission reductions that are submitted by various power generating and industrial companies. Since participation is not mandatory, the registry is primarily used as a tracking device to record voluntary efforts by companies to reduce greenhouse gases.
The proposed new reporting guidelines create a two-tier process of reporting of emissions reductions versus the registering of emissions reductions. Companies will continue to have flexibility in reporting greenhouse gas reductions on a plant-specific or project-related basis. The revised guidelines are also designed to encourage companies to register entity-wide data and demonstrate entity-wide reductions. The proposed guidelines provide that entities that are able to meet additional requirements established by DOE to register emission reductions achieved after 2002 would receive special recognition under the guidelines. In addition, third-party or independent verification of emissions reductions is “strongly encouraged,” but is not required. While under no regulatory obligation to comply with the guidelines, participating companies may be able to derive important public relations benefits.
DOE will hold a public workshop on the proposed guidelines on January 14, 2004 in Washington, D.C., and will accept comments on the proposed guidelines until the end of January 2004.
In related news, the Chicago Climate Exchange (known as the “CCX”) recently held its first auction of CO2 emission allowances. The CCX has more than 20 members, including Amtrak, DuPont Co., American Electric Power, Motorola Inc., Ford Motor Co. and International Paper Co. Each member has voluntarily committed to reduce its greenhouse gas emissions by 4% in 2006 from baseline emission levels calculated based on CO2 from 1998 to 2001.
The first auction was of 100,000 metric tons of 2003 vintage CO2 allowances and 25,000 metric tons of 2005 vintage CO2 allowances. The average successful bid was $0.98 per metric ton CO2 for 2003 allowances and $0.84 per metric ton CO2 for 2005 allowances.
The Federal Energy Regulatory Commission announced in early October that a power purchase agreement between a “qualifying facility” and a utility will not convey to the utility any renewable energy certificates that belong to the QF unless the contract specifically says that it does. Renewable energy certificates — called “RECs”— are a mechanism for selling the “environmental attributes” of power generated from renewable energy services such as wind, solar, biomass, and landfill gas power plants. FERC’s ruling could mean increased costs for utilities in states where a renewable portfolio standard requires utilities to purchase a certain percentage of their power from renewable energy sources.
To date, 13 states have enacted some form of RPS and at least five other states are considering RPS-style legislation. For example, Texas requires each electric utility to obtain 1.65% of its power from renewable fuels by 2003, 2.15% by 2005, 2.75% by 2007, and 3% by 2009.
The issue is whether utilities that buy electricity from an independent generator also get the RECs associated with that electricity. If not, utilities in certain states will have to develop their own renewable generation projects to satisfy the RPS requirements or pay for RECs on the open market. The price of RECs ranges from approximately 1/2¢ to 2¢ per kilowatt hour, depending on the state.
The FERC ruling came in a case filed by several waste-to-energy plants who petitioned the commission for a determination that the QF power purchase agreements did not convey legal title to RECs. The utilities argued that since they are required under PURPA to buy power generated by QFs using renewable fuels, the environmental benefits associated with the electricity should also belong to the utilities. The QFs countered that most power purchase agreements do not inherently transfer RECs to utilities because the compensation paid to a QFs is based on a utility’s avoided cost, which does not reflect the environmental costs of generating power.
Even though FERC ruled in favor of the petitioners, its order left the door open for individual states to determine that the sale of QF-generated power automatically transfers ownership of state-created RECs to a purchasing utility. It is unclear whether utilities will now seek legislative changes directly to the particular state RPS programs.
New Source Review
In late October, 14 states and 29 local jurisdictions filed a lawsuit challenging new rules issued by the US Environmental Protection Agency that draw a bright-line test for determining when replacing equipment at a power plant or other industrial facility requires an air permit. Included as plaintiffs in the suit are California, New York, Illinois, Washington, DC and most of the northeastern and mid-Atlantic states.
The new rule at the heart of the controversy was issued to settle conflicting EPA guidance and interpretations of the scope of the “routine maintenance, repair, and replacement” exemption. Under this exemption, a power plant owner does not need to apply for a modification of its existing “New Source Review,” or “NSR,” air permit if it replacing equipment at the plant in the course of routine maintenance, repair or replacement. If the replacement does not fit within this definition, a modified NSR permit must generally be obtained unless another exclusion applies. EPA’s new rule creates a safe harbor for equipment replacement at a power plant or other industrial facility where three prerequisites are satisfied. First, the owner must be replacing an existing component of a process unit with identical components or components that serve the same purpose. Second, the fixed capital cost of the replaced component and any other costs associated with the replacement activity must not exceed 20% of the current replacement value of the process unit. Third, the equipment replacement must not alter the basic design of the process unit or cause the unit to exceed any emission limitations.
The petitioners allege that EPA’s new rule, which was issued on October 27, 2003, violates the plain language of the Clean Air Act, is contrary to Congressional intent, and constitutes a radical departure from 25 years of prior agency and judicial interpretations regarding the applicability of the “routine maintenance, repair, and replacement” exemption. But the rule is not without supporters: a group of nine states, led by Virginia, as well as several industry trade associations have intervened in the case in support of the rule on behalf of EPA. The supporters assert that the new rule provides much needed clarity on the scope of the exemption and will help achieve energy efficiency and reliability objectives. A decision in the case is not expected until late 2004 or early 2005.
The rule is the second set of EPA reforms to the NSR program. The first rule was issued on December 31, 2002, and it revised the way industrial facilities calculate emission increases under the NSR program. It also incorporated other revisions to the NSR applicability provisions. The December 31, 2002 rule is currently being challenged by substantially the same coalition of states, local governments and environmental groups.
In a related development, EPA’s assistant administrator for enforcement and compliance assurance announced that the agency will review on a “case-by-case basis” the ongoing investigations into more than 50 coal-fired power plants for alleged past violations associated with failing to obtain NSR permit modifications for certain equipment repair and replacement activities. EPA announced that it will review the cases under the new “routine maintenance, repair, and replacement” rule that was issued on October 27, 2003. The agency’s decision to consider past actions of the utilities under the new “routine maintenance, repair, and replacement” rule is surprising in the wake of EPA’s initial pronouncements that the past actions would continue to be pursued under the prior agency guidance. EPA clarified that it has not made a formal decision to drop all of the pending utility enforcement lawsuits that are based on the prior EPA guidance; however, it appears likely that only a handful of the more egregious cases will continue to be pursued by the agency.
The plants were part of a large-scale enforcement initiative launched in the late 1990’s that culminated in a number of lawsuits against many of the major utilities with older coal-fired plants. Several of the utilities are engaged in ongoing litigation with EPA and the Department of Justice and a few of the utility enforcement cases have been settled. Utilities that settled are now reportedly pressing EPA to reevaluate the settlements in light of the new “routine maintenance, repair, and replacement” rule.
In October, the Senate Environment and Public Works Committee approved a bill that would require tighter security at power plants and other facilities that use or manufacture potentially dangerous chemicals in the US. Compliance with the measure could be costly, particularly for plants located near population centers.
Under the bill, the Department of Homeland Security would take the lead in developing a list of “high priority” chemical sources based on a number of security-related factors, including the quantity of substances of concern at the site, the likelihood that the plant may be a target of terrorism, and the cost and feasibility of implementing enhanced security measures. The “high priority” plants would be required to prepare vulnerability assessments and develop site security plans. The bill also contains a toxic use reduction provision that would require the facilities to identify potentially safer chemical alternatives; however, the bill does not require the companies to use the safer alternatives.
The detailed vulnerability assessments and site security plans could lead to capital intensive upgrades to enhance plant security. The measure would apply to “chemical sources” that are required to complete a risk management plan in accordance with section 112(r) of the Clean Air Act. Section 112(r) applies to accidental releases of hazardous chemicals. Many power plants that store anhydrous ammonia in large amounts for use in selective catalytic reduction systems are typically subject to the 112(r) requirements.
The bill closely tracks legislative language proposed by the Bush Administration and introduced by Senator James Inhofe (R-Oklahoma), the committee chairman, earlier this year. The measure should come up for a vote in the full Senate in early 2004.
California Governor Arnold Schwarzenegger has issued an executive order suspending all proposed state regulations for 180 days and ordering a review of all regulations adopted, amended or repealed since January 9, 1999. The order requires all state agencies to submit a report to the governor’s office on such adopted, amended or repealed regulations within 90 days.
Several members of the “green power market development group” announced the largest single purchase of renewable energy credits to date. The group purchased approximately 36 megawatts of RECs generated from renewable energy sources such as wind, biomass, and landfill gas. The World Resources Institute said that the purchase means that 450 million pounds of CO2 will be avoided because renewable sources will displace power plants using coal, oil, or gas. Members of the green market power development group include Alcoa Inc., DuPont, Delphi Corp., Dow Chemical Company, General Motors, IBM, Pitney Bowes and Staples.
The state of Washington released a draft of a proposed rule that would require new power plants over 350 megawatts to mitigate 20% of their projected CO2 emissions. Under the draft proposed rule, plants could mitigate CO2 emissions in any of three ways. They could pay a set fee per ton of CO2 emissions, purchase forest land to offset emissions, or undertake efficiency projects. The draft proposed rule is part of an effort to standardize rules for siting new generation in Washington.
EPA is reportedly evaluating the widespread use of AP-42 emission factors by state permitting agencies to establish air permit emission limits. The AP-42 emission factors are based on industry averages, and originally were developed as a tool for preparing state-wide emission inventories and not as a source-specific method for projecting an individual source’s emissions. The regulated community has criticized emission factors as being inaccurate and overestimating projected emissions. EPA may require states to use actual monitoring data and other methods to establish air permit limits instead of using AP-42 emission factors.
EPA recently released a proposed rule providing a conditional exclusion for regulating certain solvent-contaminated disposable industrial wipes as hazardous waste. To qualify for the exclusion, the industrial wipes must generally not contain free liquids, must be stored in leak-free containers, and must be combusted. Certain lightly contaminated industrial wipes — those containing not more than 5 grams of solvent— may be disposed in a regulated municipal or other non-hazardous landfill, provided that the solvents do not qualify as one of 11 listed solvents that are ineligible for landfill disposal under the proposed rule. Comments on the proposed rule must be submitted to EPA by February 18, 2004.