Several States have recently enacted air emission regulations that will affect the electricity generation sector. The regulations are intended to improve air quality in the States and assist them in complying with the revised 1997 National Ambient Air Quality Standards (NAAQS) for ground-level ozone and fine particulates. The affected States include Connecticut, Massachusetts, Maine, Missouri, New Hampshire, New Jersey, New York, North Carolina, Oregon, Texas, and Washington. The regulations govern emissions of NO_x, SO₂, CO₂, and mercury from power plants. 

Where firm compliance plans have been announced, State regulations are represented in AEO2005. For example, installations of SO₂ scrubbers and selective catalytic reduction (SCR) and selective noncatalytic reduction (SNCR) NO_x removal technologies associated with the largest State program, North Carolina’s “Clean Smokestacks Initiative,” are included. Overall, the AEO2005 forecast includes 22 gigawatts of announced SO₂ scrubbers, 27 gigawatts of announced SCRs, and 3 gigawatts of announced SNCRs. 

In addition to the existing regulations, Governor George Pataki of New York has announced proposed greenhouse gas reduction targets for the State of New York and has invited nine other States (Connecticut, Delaware, Maryland, Maine, New Hampshire, New Jersey, Pennsylvania, Rhode Island, and Vermont) to participate in a future “Northeast CO₂ cap and trade” program. The program requires only CO₂ trading among power plants but would also allow trading of other emissions allowances among power plants burning coal, natural gas, or oil. The first Commissioner-level meeting was held in September 2003, and a final agreement is expected to be in place by April 2005. Maryland and Pennsylvania are participating in discussions but have not committed to participation in the program. 

Table 8 summarizes current State regulatory initiatives on air emissions, and the following section gives brief descriptions of programs in the States that have enacted air emissions regulations more stringent than Federal regulations. State-level initiatives to limit greenhouse gas emissions without directly regulating the electricity generation sector, which are not discussed here, include the following: California law A.B. 1493, enacted in July 2002, which sets CO₂ pollution standards for 2009 model vehicles and those sold later (see “Legislation and Regulations,”page 27); Georgia’s transportation initiative, which is focused on expanding the use of mass transit and other transportation sector measures; Minnesota’s Releaf Program, which encourages tree planting as a way to reduce atmospheric CO₂ levels; Nebraska’s carbon sequestration advisory committee, which proposes to sequester carbon through agricultural reform practices; North Carolina’s program to develop new technologies for solid waste management practices that reduce emissions; RPS programs being adopted by several States (see discussion of State renewable energy requirements and goals, above); and Wisconsin’s greenhouse gas emissions inventory. 

Connecticut. The Connecticut “Abatement of Air Pollution” regulation was enacted in December 2000, and revisions are being made on an ongoing basis. It limits SO₂ and NO_x emissions from all NO_x budget program (NBP) sources that are more than 15 megawatts or require fuel input greater than 250 million Btu per hour [20]. The regulation applies to the electricity generation sector, the cogeneration sector, and industrial units. The NO_x limit is 0.15 pound per million Btu of heat input. The SO₂ limit applies to NBP sources that are also Acid Rain Program sources, and the limit is 0.3 percent sulfur in fuel and 0.33 pound per million Btu. Modifications are being made to the current NBP rules to provide incentives in the form of allowances for renewable energy and energy efficiency programs [21]. 

In May 2003, the Connecticut General Assembly passed legislation (Connecticut Public Act 02-64) requiring coal-fired power plants to remove 90 percent of the mercury from smokestack emissions (or a maximum of 0.6 pound of mercury emitted per trillion Btu input, which is equivalent to 0.005 to 0.007 pound per gigawatthour) by July 2008. The legislature has recommended that the State Department of Environmental Protection consider stricter limits by July 2012 [22]. 

In addition, Connecticut enacted a law in June 2004 called “An Act Concerning Climate Change,” Public Act No. 04-252. The goal of the legislation is to reduce emissions of greenhouse gases from sources in Connecticut to 1990 levels by 2010 and to 10 percent below 1990 levels by 2020, and it establishes a process to determine reduction goals beyond 2020. The Act covers electricity generators, fleet vehicles, industrial facilities, and commercial establishments; however, there are no enforcement procedures in the law. There is a requirement for the Governor’s Steering Committee on Climate Change to develop a Climate Action Plan by January 2005, and for the Commissioner of Environmental Protection to establish a regional greenhouse gas registry that will collect emissions data. 

Maine. Maine enacted a climate change statute— “An Act to Provide Leadership in Addressing the Threat of Climate Change” (Public Law 2003, Chapter 237, H.P. 622, L.D. 845)—in June 2003 [23]. The statute requires the establishment of a greenhouse gas emissions inventory for State-owned facilities and State-funded programs and calls for a plan to reduce emissions to 1990 levels by 2010. It specifies that carbon emission reduction agreements must be signed with at least 50 businesses and nonprofit organizations by January 2006, and that Maine must participate in a regional greenhouse gas registry. The goals of the statute are a reduction of greenhouse gases to 1990 levels by January 2010, a reduction to 10 percent below 1990 levels by 2020, and a reduction to 75 and 80 percent below 2003 levels “in the long term.” It authorizes the Department of Environmental Protection to submit to the Legislature a State climate action plan to meet the goals of the statute [24]. 

Massachusetts. The Massachusetts Department of Environmental Protection air pollution control regulations (310 CMR 7.29, “Emissions Standards for Power Plants”), approved in May 2001 [25], apply to six existing older power plants in Massachusetts. There are two options for utilities to comply with the regulations: either “repower” (defined as replacing existing boilers with new ones that meet the environmental standards, switching fuel to low-sulfur coal, or switching from coal to natural gas); or choose a standard path that includes installing low-NO_x burners, installing SO₂ scrubbers, and installing SCR or SNCR equipment. 

The rule offers an incentive for a fuel shift by delaying the compliance deadline to October 2008 for any facility choosing to repower. Plants using other techniques, such as pollution control equipment, must comply by October 2006. The SO₂ standard is 6.0 pounds per megawatthour by October 2004 (standard) or October 2006 (repowering) and 3.0 pounds per megawatthour by October 2006 (standard) or October 2008 (repowering). The NO_x standard is 1.5 pounds per megawatthour by October 2004 (standard) or October 2006 (repowering). The SO₂ and NO_x regulations are considered by the State to be more stringent than CAAA90 would imply. Most of the facilities are choosing the repowering mode rather than the standard mode of compliance. Compliance plans have been submitted for the six power stations affected: Brayton Point, Salem Harbor, Somerset, Mount Tom, Canal, and Mystic stations [26]. 

The CO₂ standard annual facility cap is based on 3 years of data as of October 2004 (standard) or October 2006 (repowering) and an annual facility rate of 1,800 pounds CO₂ per megawatthour as of October 2006 (standard) or October 2008 (repowering) [27]. Credits for off-site reductions of CO₂ emissions can be obtained through carbon sequestration or renewable energy projects. The Massachusetts Department of Environmental Protection is developing regulations that would determine what projects could qualify as reductions. Greenhouse gas banking and trading regulations are also being developed. Plants that fail to achieve the reductions may purchase emissions credits. 

The State of Massachusetts published final mercury emissions regulations in June 2004 that apply to the State’s four largest existing coal-fired power plants (Brayton Point, Mount Tom, Salem Harbor, and Somerset Station) [28]. The regulations require compliance with at least one of the following standards: reduce mercury emissions by 85 percent from 2004 levels by January 2008 or a facility average mercury emissions rate of 0.0075 pound per gigawatthour or less. The affected facilities must reduce their mercury emissions by 95 percent from 2004 levels by October 2012, or achieve a facility average mercury emissions rate of 0.0025 pound per gigawatthour or less. The Massachusetts mercury emissions regulations are more stringent than EPA’s proposed mercury emissions regulations as of January 2004 (69 CFR 4651). 

Missouri. The Missouri NO_x rule, “Emission Limitation and Emissions Trading of Oxides of Nitrogen” (Rule 10 CSR 10-6.350) applies to fossil-fueled capacity larger than 25 megawatts. The emissions cap is based on a unit’s heat input. Power plants had to be in compliance by May 2004. Allowances can be banked, with some restrictions, and some exchange of allowances is allowed [29]. The seasonal NO_x limits (from May to September of each year) vary by county and generally range from 0.18 to 0.35 pound per million Btu. 

New Hampshire. New Hampshire has enacted legislation—the “Clean Power Act” (House Bill 284)—to reduce emissions of SO₂, NO_x, CO₂, and mercury from existing fossil-fuel-burning steam-electric power plants. Governor Jeanne Shaheen signed the Act into law in May 2002, and implementing regulations have been finalized [30]. The legislation applies to the State’s three existing fossil-fuel power plants only and does not apply to new capacity. The plants must either reduce emissions, purchase emissions credits from plants outside New Hampshire that have achieved such reductions, or use some combination of these strategies. Compliance plans submitted to the New Hampshire Department of Environmental Services are under review. 

One of the affected plants is Schiller, a 150-megawatt coal-burning power plant made up of three 50-megawatt units. Part of the compliance action, the “Northern Wood Power Project,” is the conversion of one of Schiller’s 50-megawatt units from coal to a fluidized-bed combustor that will burn biomass. The converted power plant will burn wood chips, sawmill residue, and other woody material. The action is, in part, a result of the Massachusetts RPS program, under which plants in States neighboring Massachusetts can convert from coal to biomass and qualify for the program. Thus, Schiller’s conversion from coal to biomass counts toward meeting both the Massachusetts RPS and the New Hampshire multi-pollutant requirements. The conversion, which is expected to cost $70 million (about $1,500 per kilowatt), is planned for completion by the end of 2005. 

The SO₂ annual cap under New Hampshire’s Clean Power Act is 7,289 short tons by 2006, which amounts to a 75-percent reduction from Phase II Acid Rain legislation requirements and an 85-percent reduction from 1999 emission levels. The NO_x annual cap is 3,644 short tons by 2006, which amounts to a 60-percent reduction from 1999 emission levels. The CO₂ annual cap is 5,425,866 short tons by 2006, which amounts to a 3-percent reduction from 1999 levels. 

New Jersey. New Jersey’s goal is to reduce State-wide emissions of greenhouse gases from all sectors by 3.5 percent from 1990 levels by 2005. “Covenants” have been signed, pledging organizations to reduce their greenhouse gas emissions in accordance with the State goal [31]. 

New York. New York’s “Acid Deposition Reduction Budget Trading Programs”—Title 6 NYCRR Parts 237 and 238—were approved by the State Environmental Board in March 2003 and became effective in May 2003 [32], but implementation of the rule has been delayed by a court order. The NO_x regulations apply to electricity generators of 25 megawatts or greater, and the SO₂ regulations apply to all CAAA90 Title IV sources, including electric utilities and other sources of SO₂ and NO_x, such as cogenerators and industrial facilities. NO_x emissions were limited to 39,908 short tons beginning in October 2004. This is a non-ozone season cap (October 1 to April 31), based on the same rate (0.15 pound per million Btu) as the NO_x cap in the current State emissions regulation. SO₂ emissions are limited in two phases: Phase I, beginning in January 2005, limits SO₂ to 25 percent below Title IV allocations (197,046 short tons); Phase II, beginning in January 2008, increases the limit to 50 percent below Title IV allocations (131,364 short tons) [33]. A governor’s task force was established in June 2001 to recommend greenhouse gas limits. 

North Carolina. The General Assembly of North Carolina has passed the “Clean Smokestacks Act”— officially called the “Air Quality/Electric Utilities Act” (S.B. 1078)—which requires emissions reductions from 14 existing coal-fired power plants in the State. It was signed into law in June 2002. Under the Act, North Carolina power companies must reduce NO_x emissions from 178,000 short tons in 1999 to 56,000 short tons by 2009 and SO₂ emissions from 429,000 short tons in 1999 to 250,000 short tons by 2009 and 130,000 short tons by 2013. Progress Energy Carolinas, Inc., and Duke Power have submitted compliance plans to the North Carolina Department of Environment and Natural Resources and the North Carolina Utilities Commission. The utilities will comply with the Act by installing scrubbers and SNCR technology at their plants. Duke Power and Progress Energy have reported compliance costs for SO₂ and NO_x control, with SNCR costs ranging from $4.93 to $63.70 per kilowatt and scrubber costs ranging from $113 to $414 per kilowatt [34]. 

The Act requires the Department of Environment and Natural Resources to evaluate issues related to the control of mercury and CO₂ emissions and recommends the development of standards and plans to control them. In 2003, the Department of Air Quality prepared reports on mercury [35] and CO₂ [36] emissions reductions for the State, in the first of three sets of reports to be submitted to the Environmental Management Commission and the Environmental Review Commission. The objective of the 2003 report was to provide general background on the topic of climate change and to define the scope of efforts needed to meet the legislative requirements. The 2004 and 2005 reports will build on this background, report on any developments in the Federal Government, and recommend courses of action that may follow [37]. 

The Act also requires North Carolina to persuade other States and power companies to reduce their emissions to similar levels and on similar timetables. The Act specifically mentions that discussions should be held with the Tennessee Valley Authority (TVA) to determine its emissions reduction policies. A meeting was held between the Department of Environment and Natural Resources/Department of Air Quality and TVA in August 2002 to discuss actions planned by TVA that would be comparable to the Clean Smokestacks Act. TVA presented its plans to add scrubbers to five additional power plants, primarily in the eastern portion of the TVA system, beginning with its Paradise plant in 2006. TVA plans to complete installation of the new scrubbers by 2010. TVA also plans to install the first eight SCR systems for NO_x control and to have 25 boiler units controlled by 2005, which will reduce NO_x emissions during the ozone season by 75 percent. 

Oregon. Oregon has established its first formal State standards for CO₂ emissions from new electricity generating plants. The standards apply to power plants and non-generating facilities that emit CO₂. The Oregon Energy Facility Siting Council originally adopted the rules pursuant to House Bill 3283, which was passed by the Oregon legislature in June 1997, and has subsequently updated the rules, most recently in April 2002 [38]. For baseload natural gas plants and non-baseload plants, the standard CO₂ emission rate is 675 pounds per megawatthour, 17 percent below the rate for the most efficient natural-gas-fired plants currently in operation in the United States. The Council has not set CO₂ emission standards for baseload power plants using other fossil fuels. As of 2002, about 90 percent of Oregon’s electricity was from hydroelectricity and natural gas and about 8 percent was from coal [39]. 

The Council’s definition of a natural-gas-fired facility allows up to 10 percent of the expected annual energy to be provided by an alternative fuel, most likely distillate fuel. Proposed facilities may meet the requirement through cogeneration, using new technologies, or purchasing CO₂ offsets from carbon mitigation projects. It is possible to offset all excess CO₂ emissions through cogeneration offsets alone, and there are no limitations on the geographic location or types of CO₂ offset projects. The Council has set a monetary value that the generators may pay to buy offsets ($0.85 per short ton CO₂, equivalent to $3.12 per ton carbon, set in September 2001) [40]. This equates to an offset cost of 0.88 mill per kilowatthour [41]. 

Texas. Texas Senate Bill 7 (S.B. 7) imposes NO_x and SO₂ caps for grandfathered fossil fuel power plants [42]. The SO₂ annual cap is 595,000 short tons (East: 532,000, West: 63,000, and El Paso: 0 short tons). The NO_x annual cap is 302,000 short tons (East: 256,000, West: 44,000, and El Paso: 2,000 short tons), both of which had to have been achieved by May 2003. The State-wide caps have been met. 

Washington. Washington’s House Bill 3141, signed into law in May 2004, requires 20 percent of their CO₂ emissions from new power plants to be offset. Plant owners can either directly or indirectly invest in CO₂ mitigation projects, such as forest preservation or the conversion of buses from diesel to natural gas. Power plant CO₂ emissions must be reduced by 20 percent over a 30-year period. CO₂ emissions can be offset by payments to an independent qualified organization, by direct purchase of permanent carbon credits, or by direct investment in CO₂ mitigation projects. The rate of payment to third parties is fixed at $1.60 per metric ton CO₂ [43]. The Washington State Energy Facility Site Evaluation Council may adjust the rate every 2 years, but any decrease or increase may not exceed 50 percent of the current rate.

Notes and Sources

Contact: Robert Smith
Phone: 202-586-9413
E-mail: robert.smith@eia.doe.gov