Seven northeastern states have taken a major step toward constructing the largest greenhouse gas emissions control program in the United States. The states entered into a memorandum of understanding in December for a new regional program to combat global warming by reducing carbon dioxide emissions from power plants. The states would establish a cap for CO2 emissions and create a program for trading CO2 offset credits to achieve compliance with emission requirements.
The memorandum of understanding caps two years of negotiations among nine northeastern states and was approved by seven states (New Jersey, New York, Delaware, Connecticut, New Hampshire, Vermont and Maine). Massachusetts and Rhode Island chose not to join the program at this time.
The new program, known as the “regional greenhouse gas initiative,” or “RGGI,” calls for a mandatory cap on CO2 emissions, coupled with a market-based trading program to reduce compliance costs. Under RGGI, regional CO2 emissions will be capped at 121.3 million tons per year beginning in 2009 through 2014. This is a level equal to 1990 emissions. A further 10% reduction is required by 2018.
The cap-and-trade program established in the memorandum of understanding sets limits on regional emissions, but allows companies to trade emissions allowances. Companies that do not have enough allowances to cover their CO2 emissions must either reduce their emissions or purchase allowances from other plant owners who are able to reduce their emissions below their prescribed caps. The RGGI agreement also provides that at least 25% of the emissions allowances will be used to benefit energy consumers. Under this mechanism, electric generators would purchase these allowances and the funds generated would be used to support energy efficiency and clean energy projects. States are free to set aside a larger portion of the allowances if they wish.
The memorandum of understanding must still be signed by each state. The participating states plan to issue a detailed set of draft model regulations for the RGGI program in early 2006 for public comment. After comments are received on the draft regulations, each state will pursue the necessary regulatory and legislative approvals necessary to adopt the program. The program is slated to begin January 1, 2009.
Announcement of the program was significantly delayed as a result of concerns raised by the states of Massachusetts and Rhode Island in the regional negotiations. Ultimately, the seven signatory states chose to go forward without those two states but included provisions in the agreement allowing Massachusetts and Rhode Island to become signatories to the memorandum of understanding at any time prior to January 1, 2008.
Power Plant Emissions
The control strategy committee of the Ozone Transport Commission proposed in late January to reduce nitrogen oxide and sulfur dioxide emissions from electric generating units to levels significantly lower than those already required by US Environmental Protection Agency regulations. The committee is composed of northeastern state environmental officials. It said that the “clean air interstate rule” that the US Environmental Protection Agency issued in 2005 to limit NOX and SO2 emissions does not provide reductions that are deep enough or rapid enough to address ozone and fine particulate problems adequately in the northeast. The committee proposes to use regional partnerships and model rules to implement a program that uses the basic structure of the federal clean air interstate rule but requires tougher emissions caps.
The Ozone Transport Commission represents 12 northeastern states and the District of Columbia. The model rule for electric generating units is one of 15 model rules under consideration by the commission to achieve compliance with the US Environmental Protection Agency’s strict new eight-hour ambient air quality standard for ozone. Officials from OTC member states have expressed concern that the new EPA clean air interstate rule, which establishes a two-phase program, will not reduce pollution sufficiently to achieve compliance with the eighthour standard by the EPA-mandated deadline of 2010. The clean air interstate rule establishes a cap-and-trade program to control power plant pollution in the eastern United States. The first phase of controls under the clean air interstate rule goes into effect in 2009 for NOX and 2010 for SO2.
Under the new OTC proposal, NOX emissions rates would be reduced to 0.12 lbs. per million British thermal units (mmBtu) in 2007 and further reduced to 0.08 lbs. per mmBtu by 2012. For SO2 the rates would be 0.24 lbs. per mmBtu in 2009 and 0.14 lbs. per mmBtu in 2012. The proposed emissions rates are significantly lower than the rates proposed in the federal clean air interstate rule, and the second phase under the OTC program begins three years earlier (in 2012) than the second phase under the federal clean air interstate rule. The committee had previously considered starting phase I in 2008, but ultimately decided to make commencement coincide with the commencement of the federal clean air interstate rule in 2009.
The OTC committee also recommended adoption of a rule mandating control measures for “electric generating peaking units” — units operating less than 500 hours per year and less than 10 hours per day. The proposal would require that, by 2009, peaking units must perform at levels achievable through the use of water injection technology to control NOX emissions and must install dry-lo NOX technology by 2012.
Utility industry representatives attending the OTC committee meeting criticized the emissions control proposal as unnecessarily expensive. Representatives recommended that the OTC rely solely on the federal clean air interstate phase I program to achieve the required compliance with the 8-hour ozone standard. Areas not found in compliance in 2010 could at that time impose more stringent control requirements to achieve compliance.
Illinois Governor Rod Blagojevich is proposing to cut mercury emissions from coal-fired power plants in his state by 90% by June 30, 2009. The governor’s proposed rule would go beyond the requirements of the federal clean air mercury rule issued in March 2005. Phase I of the clean air mercury rule requires that coal-fired power plants reduce mercury emissions by 47% by 2010 and 79% by 2018. The proposed Illinois rules are more ambitious, demanding a 90% emissions reduction by June 30, 2009 and prohibiting power plants from purchasing allowances or trading emissions credits with other companies or states. Power plant operators would be required to reduce emissions by an average of 90% across their entire fleets of plants by 2009, and each plant must individually achieve at least a 75% reduction by that date. All plants will be required to achieve a 90% reduction by December 31, 2012. Phase II reductions under the federal clean air mercury rule are scheduled for 2018.
There are currently 20 coal-fired power plants in Illinois, the most of any state.
The proposed mercury rules must be submitted to the Illinois pollution control board for approval, where approval is expected, and would then have to be approved by a state legislative panel, where industry opposition is expected to be significant.
If implemented, the proposed mercury rule would put Illinois in the company of states like Connecticut, Massachusetts, Minnesota, New Jersey, North Carolina and Wisconsin that have sought more stringent and rapid reductions in mercury emissions than those required under the federal clean air mercury rule. These states argue that the federal rule does not go far enough in mandating reductions and, more importantly, that the federal government’s nationwide emissions trading program would allow local mercury hot spots to worsen.
Environmental opponents of the federal approach have long argued that mercury emissions do not disburse over as wide an area as other types of air emissions and, therefore, that it is not appropriate to allow power plants to use reduction credits from plants in different parts of the country to avoid controlling their own emissions.
The International Finance Corporation is expected to issue revised general environmental guidelines in February, a development that could have ramifications for more than just IFC-sponsored projects. Early indications are that the IFC intends to adopt a more “adaptable” approach to implementing its environmental goals. The guidelines, which have been under review since 2004, are technical reference documents that address the IFC’s expectations for industrial pollution management and environmental risk management at projects in which it invests. At present, they consist primarily of industry sector environmental guidelines that are in part III of the World Bank Group’s 1998 pollution prevention and abatement handbook, as supplemented by IFC published guidelines addressing a wide range of topics, including occupational health and safety.
The guidelines have become a global reference standard for private sector development, regardless whether the IFC or the World Bank is actually involved. They are frequently incorporated into international lending agreements by commercial banks and other financial institutions to establish baseline environmental requirements for borrowers. Since 2003, more than 30 leading private banks, accounting for about 80% of the global project finance market, have committed to follow the IFC’s social and environmental policies and environmental review procedures by adopting the “Equator principles.” In addition, 26 OECD export credit agencies have agreed to observe minimum environmental standards based on the IFC policies. Once issued, the draft IFC environmental guidelines will be available for public comment for a period of 60 days.
The IFC issued draft policies on social and environmental sustainability and on disclosure of information last September. The draft policies were intended to better define the roles and responsibilities of IFC and its clients in the hope of increasing accountability and at the same time increasing transparency. The sustainability policy includes a performance standard for pollution prevention and abatement that is expressly based on technical and financial feasibility and cost-effectiveness. Mohave Shutdown Southern California Edison has shut down its 1,580 megawatt Mohave generating station in order to avoid violating a court-ordered deadline to install pollution control equipment.
The coal-fired Mohave plant, which is located about 100 miles south of Las Vegas, has been the subject of litigation with environmental groups that claim sulfur dioxide emissions from the plant caused a deterioration in visibility at the Grand Canyon. The litigation produced a 1999 consent decree under which SCE is required to upgrade emission control equipment or close the plant by January 1, 2006. The emission controls contemplated by the consent decree include a sulfur dioxide scrubber and a fabric filter “baghouse” in which SCE was expected to invest $300 million.
According to a December 29 filing with the California public utilities commission, SCE’s decision not to invest $300 million in the pollution control equipment resulted from its inability to secure sufficient water to maintain plant operations. The plant uses water to turn coal into slurry. The water used to make the slurry comes from the Navajo aquifer in Arizona, which the tribe asserts is being depleted and is too valuable for this use. Negotiations to get water from an alternative aquifer, also on tribal land, are ongoing, but SCE told the public utilities commission that the process could take up to four years to complete. SCE wants an extension of time to comply with the emission control requirements of the 1999 consent decree. Environmental groups oppose granting any extension.
Renewables in Gasoline
In January, the EPA ordered refiners, importers and blenders of gasoline to ensure that “the percentage of renewable fuel in gasoline sold or dispensed to consumers in the United States, on a volume basis, shall be 2.78% for calendar year 2006.” This 2.78% minimum is the “default” percentage set by the new Energy Policy Act enacted last August.
The Energy Policy Act requires the use of ethanol and biodiesel in gasoline production, at levels starting at four billion gallons in 2006 and increasing to 7.5 billion gallons in 2012. Under the act, the EPA is required to establish an annual minimum percentage of renewable fuel that must be used in gasoline production. In order to ensure that the 2006 program was implemented in a timely fashion, the act established an initial default percentage of 2.78% to be used by EPA initially. The agency said that it intends in future years to adopt individual renewable fuels caps when it develops the necessary credit trading program for renewable fuels.
The 2.78% renewables standard should be easily met in 2006 by the petroleum fuels industry as a whole, primarily through the use of ethanol. Anticipated US gasoline sales of about 141.6 billion gallons will account for almost four billion gallons of ethanol — up from the 3.574 billion gallons of ethanol consumed in 2004, according to the Renewable Fuels Association. Biodiesel, on the other hand, cannot be blended with gasoline, but can be blended with diesel.
In future years, refiners and blenders that use more than the required percentages of renewable fuels in their products will receive credits that can be used in other refining or blending operations or by other refiners and blenders. Because the trading program has not yet been developed by EPA, no such credits will be generated in 2006.
New Source Review Case
A Federal district court dismissed a suit against the Tennessee Valley Authority in mid-January for alleged violations of the Clean Air Act at its Colbert plant in Alabama.
The case was brought by the National Parks Conservation Association in 2001, alleging that TVA violated Clean Air Act new source review requirements by making modifications to its Colbert plant that increased emissions without obtaining a new or modified air permit, which permit would have required the installation of advanced pollution control equipment. TVA took the position that the modifications qualified as “routine repair and maintenance” that are exempted from new source review under EPA regulations.
In a 2005 ruling, the court interpreted “routine maintenance” in a light favorable to TVA. The court decided that the term refers to projects that are routine within the industry, even if they are carried out once at each individual plant. In November, the court also granted TVA’s motion to dismiss the new source review claims, holding that the modifications had occurred more than five years before the lawsuit commenced and that, therefore, the claims were barred by the five-year statute of limitations period. The court ruled against the citizens’ group’s argument that the violations were continuous or ongoing because the resulting pollution continued to be emitted. The decision to dismiss the case may now be appealed by the citizens’ group.