Legislation and Regulations.

State Air Emission Regulations 

Several States, primarily in the Northeast, 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, North Carolina, Massachusetts, Maine, New Hampshire, New Jersey, New York, and Oregon. The regulations govern emissions of NO_x, sulfur dioxide (SO₂), carbon dioxide (CO₂), and mercury from power plants. Table 2 shows emissions of NO_x, SO₂, and CO₂ by electricity generators in the eight States and in the rest of the country. Comparable data on mercury emissions by State are not available. 

Printer Friendly Version State  SO2  NOx  CO2  Connecticut         10,814         5,100         7,827,884  Massachusetts         90,726      28,500      21,486,936  Maine           2,022         1,154         5,784,562  New Hampshire         43,946         6,826         5,556,992  New Jersey         48,268       27,581       12,440,663  New York       231,875       69,334       51,293,393  North Carolina       462,993     145,706       72,866,548  Oregon         12,280         8,840         7,607,557    Subtotal       902,925     293,039     184,864,534  Rest of country    9,287,292  4,068,670  2,240,690,001  Total  10,190,216  4,361,709  2,425,554,535  Percent of total for selected States  8.86%  6.72%  7.62%

Printer Friendly Version State  Activities  Emissions limits  Connecticut  “Abatement of Air Pollution” regulations for electric utility, industrial cogeneration, and industrial units    SO2 emissions Phase I limit by 2002  0.55 pound per million Btu input    SO2 emissions Phase II limit by 2003  0.33 pound per million Btu input    NOx limit  0.15 pound per million Btu input    Mercury limit by July 2008  90% removal (or maximum of 0.6 pound mercury emitted per trillion Btu input, equivalent to 0.005-0.007 pound mercury per gigawatthour)  Maine  “An Act to Provide Leadership in Addressing the Threat of Climate Change,” regulation for greenhouse gas emissions reduction from all sectors    Greenhouse gas emissions by 2010  At 1990 levels    Greenhouse gas emissions by 2020  10% below 1990 levels    Greenhouse gas emissions in the “long term”  75% to 80% below 2003 levels    Potential participant in Northeast CO2 cap and trade program  Massachusetts  “Emissions Standards for Power Plants,” multi-pollutant cap for existing power plants    SO2 emissions 1999: 6.7 pounds per megawatthour      SO2 cap 2004 or 2006 (depending on compliance strategy)  6.0 pounds per megawatthour    SO2 cap 2006 or 2008 (depending on compliance strategy)  3.0 pounds per megawatthour    NOx emissions 1999: 2.4 pounds per megawatthour      NOx cap 2004 or 2006 (depending on compliance strategy)  1.5 pounds per megawatthour    CO2 emissions (current): 2,200 pounds per megawatthour      CO2 cap 2006 or 2008 (depending on compliance strategy) 1,800 pounds per megawatthour  New Hampshire  “Clean Power Act” for existing fossil-fuel power plants      SO2 emissions 1999: 48,000 tons      SO2 cap 2006  7,289 tons    NOx emissions 1999: 9,000 tons      NOx cap 2006  3,644 tons    CO2 emissions 1990: 5,426 thousand tons      CO2 emissions 1999: 5,594 thousand tons      CO2 cap 2006 5,426 thousand tons  New Jersey  Greenhouse gas emissions 1990: 136 million metric tons carbon dioxide equivalent    Greenhouse gas emissions 2005  3.5% below 1990  New York  Title 6 NYCRR Parts 237 and 238 applicable to electric utilities, cogenerators, and industrial units    SO2 Phase I limit January 2005, 25% below allocation  197,046 tons    SO2 Phase II limit January 2008, 50% below allocation  131,364 tons    NOx limit beginning in October 2004  39,908 tons  North Carolina “Clean Smokestacks Act” for existing coal-fired plants only    SO2 emissions 1999: 429,000 tons      SO2 cap 2009  250,000 tons    SO2 cap 2013  130,000 tons   NOx emissions 1999: 178,000 tons      NOx cap 2009  56,000 tons  Oregon  CO2 for new or expanded power plants  675 pounds per megawatthour

Where firm compliance plans have been announced, State regulations are represented in AEO2004. For example, the SO₂ scrubbers, selective catalytic reduction (SCR), and selective non-catalytic reduction (SNCR) installations associated with the largest State program, North Carolina’s “Clean Smokestacks Initiative,” are included. As shown in Table 2, North Carolina accounts for nearly one-half of the emissions in the eight affected States. Overall, the AEO2004 forecast includes 23 gigawatts of announced SO₂ scrubbers, 41.6 gigawatts of announced SCRs, and 4.5 gigawatts of announced SNCRs (both SCRs and SNCRs are NO_x removal technologies). 

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 he 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. 

Table 3 summarizes current State regulatory initiatives on air emissions, and the following section gives brief descriptions of programs in the eight States that have enacted air emission 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 examples: California’s CO₂ pollution standards for 2009 model vehicles and those sold later; Georgia’s transportation initiative, focusing on expanding 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; Texas’s renewable portfolio standard program; and Wisconsin’s greenhouse gas emissions inventory. 

Connecticut. The Connecticut “Abatement of Air Pollution” regulation was enacted in December 2000. 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 [7]. 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 is enforced in two phases. Under Phase I, the limit for all NBP sources is 0.5 percent sulfur in fuel or 0.55 pound per million Btu of heat input by January 2002. The Phase II limit applies to all 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 by January 2003. 

In May 2003, the Connecticut State legislature passed legislation requiring coal-fired power plants to remove 90 percent of their mercury (or a maximum of 0.6 pound 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 [8]. 

Connecticut is developing a climate change action plan that is designed to help meet the New England Governors/Eastern Canadian Provinces goal for CO₂ reduction (stabilization of greenhouse gas emissions at 1990 levels by 2010, and a 10-percent reduction from 1990 levels by 2020). The State is also a potential participant in the Northeast CO₂ cap and trade program. Modifications are being made to the current NBP rules to provide incentives in the form of allowances for renewable energy and energy efficiency programs [9]. 

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 May 2003. 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. The statute 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 between 75 and 80 percent below 2003 levels “in the long term.” It authorizes the Department of Environmental Quality to adopt a State climate action plan by July 2004 to meet the goals of the statute [10]. 

Massachusetts. The Massachusetts Department of Environmental Protection air pollution control regulations (310 CMR 7.29, “Emissions Standards for Power Plants”) [11] apply to existing power plants in Massachusetts. They would affect six older power plants. 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 the Clean Air Act Amendments of 1990 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 [12]. 

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). 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 governor of Massachusetts has sent a letter expressing interest in working with New York State to develop a cap and trade program for CO₂ emission reductions from power plants [13]. Data collection and feasibility assessment on mercury control are ongoing. Draft mercury regulations have been publicly released and are going through a comment period before consideration by the State legislature [14]. 

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 [15]. 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 other 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 (DES) are under review. 

The SO₂ annual cap is 7,289 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 (see Table 3). The NO_x annual cap is 3,644 tons by 2006, which amounts to a 60-percent reduction from 1999 emission levels. The CO₂ annual cap is 5,425,866 tons by 2006, which amounts to a 3-percent reduction from 1999 levels. The Governor of New Hampshire has sent a letter expressing interest in working with New York State to develop a cap and trade program for reducing CO₂ emissions from power plants. 

The mercury cap is to be determined after the U.S. Environmental Protection Agency (EPA) establishes a Maximum Achievable Control Technology (MACT) standard for mercury control, but no later than March 31, 2004. Emissions allowances from Federal or regional trading and banking programs can be used to comply with the State cap. For CO₂ and mercury, early reductions can be banked for future use. NO_x allowances can be pooled but cannot be applied to emissions between May and September. SO₂ allowances obtained under the Federal acid rain program can be used against the cap. The statute includes incentives for investment in energy efficiency, new renewable energy projects, conservation, and load management. It does not apply to utilities that have installed “qualifying repowering technology” or replacement units meeting certain pollution control criteria [16]. 

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 [17]. In January 2002, the U.S. Department of Justice, the U.S. EPA, and the State of New Jersey obtained a Clean Air Act Consent Decree involving Public Service Enterprise Group Fossil, LLC (PSEG). In addition to a $1.4 million monetary penalty to be paid to the Federal Government [18], the settlement commits PSEG to reduce SO₂, NO_x, and particulate matter emissions on all its coal-fired units, to retire SO₂ and NO_x allowances, and to undertake other environmental projects. This is a part of the Prevention of Significant Deterioration/New Source Review (PSD/NSR) enforcement effort. The Governor of New Jersey has also sent a letter expressing interest in working with New York to develop a cap and trade program for CO₂ emission reductions from power plants. 

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 [19]. The NO_x regulations apply to electricity generators of 25 megawatts or greater, and the SO₂ regulations apply to all Title IV sources under the Clean Air Act [20], including electric utilities and other sources of SO₂ and NO_x, such as cogenerators and industrial facilities. NO_x emissions are limited to 39,908 tons beginning in October 2004. SO₂ emissions are limited in two phases: Phase I, beginning in January 2005, limits SO₂ emissions to 25 percent below Title IV allocations (197,046 tons), and Phase II, beginning in January 2008, increases the limits to 50 percent below Title IV allocations (131,364 tons) [21]. A governor’s task force was established in June 2001 to recommend greenhouse gas limits. Further details on the recommendations of the Task Force are provided below. 

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 coal-fired power plants in the State. Under the Act, North Carolina utilities must reduce NO_x emissions from 245,000 tons in 1998 to 56,000 tons by 2009 and SO₂ emissions from 489,000 tons in 1998 to 250,000 tons by 2009 and 130,000 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. 

The Act requires the Department of Environment and Natural Resources to evaluate issues related to the control of mercury and CO₂ emissions and recommend the development of standards and plans to control them. In 2003, the Department of Air Quality has prepared a report on mercury [22] and CO₂ reductions for the State [23]. This is the first of three sets of reports submitted to the Environmental Management Commission and the Environmental Review Commission. The subsequent reports are due in September 2004 and September 2005. The objective of the 2003 report is to provide a 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. A proposed workshop being planned for spring 2004 will form the basis for the September 2004 report. 

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 emission 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 8 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. Duke Power and Progress Energy have reported compliance costs for SO₂ and NO_x control. For the North Carolina utilities, SNCR costs range from $4.93 to $63.70 per kilowatt, and scrubber costs range from $113 to $414 per kilowatt [24]. 

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 [25]. For baseload natural gas plants and non-baseload plants, the standard is CO₂ emission rates of 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. 

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 locations 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) [26]. This equates to an offset cost of 0.88 mills per kilowatthour [27].

.

Notes and Sources

Released: January 2004