Air Quality

State Multi-Pollutant Strategies

April 2004

As the Congress continues to debate different legislative proposals to control emissions of nitrogen oxides (NOx), sulfur dioxide (SO₂), mercury (Hg) and, in some cases, carbon dioxide (CO₂), states have taken the lead in formulating multi-pollutant strategies through legislation or executive agency rules. Three states--Massachusetts, New Hampshire and North Carolina--illustrate recent efforts to control multiple pollutants. Another state--Florida--is considering legislation that will act to curb emissions of NOx, SO₂ and particulates from fossil fuel fired generating units.

Massachusetts

Massachusetts was the first state to apply a multi-pollutant strategy to control air emissions from old high-polluting power plants. On May 11, 2001, the Massachusetts Department of Environmental Protection issued final regulations to control the emission of “criteria” pollutants--NOx, SO₂ and mercury (those traditionally regulated under the Clean Air Act--in addition to CO₂, a greenhouse gas that contributes to climate change.

The regulations--310 CMR 7.29 Emissions Standards for Power Plants--apply to fossil fuel fired power plants that emitted more than 500 tons of SO₂ and 500 tons of NOx during any of calendar years 1997, 1998 or 1999, and that were permitted prior to August 7, 1977. Control of emissions is accomplished by establishing output based emission rates for NOx and SO₂, and establishing a cap on CO₂ and mercury emissions from affected facilities. Six facilities are affected by these regulations.

By October 1, 2004, the six facilities must begin to comply with the following emission limits for NOx--not to exceed 1.5 pounds per megawatt hour (lbs/MWh) over any 12-month period--and for SO₂--not to exceed 6.0 lbs/MWh over any 12-month period. By October 1, 2006, the regulated facilities must comply with these stricter emission limits for NO_x--not to exceed 3.0 lbs/MWh over any one month--and for SO₂--not to exceed 3.0 lbs/MWh over any 12-month period and 6.0 lbs/MWh over any one month.

Emissions standards for mercury and CO₂ were not immediately set. The Department of Environmental Protection was instructed to complete an evaluation of the technological and economic feasibility of controlling and eliminating emissions of mercury from fossil fuel fired power plants by December 1, 2002. Within six months of completing the evaluation, the Department must propose emission standards for mercury that facilities must comply with by October 1, 2006. On December 10, 2002, the Massachusetts Executive Office of Environmental Affairs issued a press release with the findings of the feasibility study stating that it is feasible to remove a significant amount of mercury emissions from the state’s oldest power plants. Using data from power plant smokestack tests and other research, the office determined that the removal of 90 percent or more of mercury in flue gas is both technologically and economically feasible. The draft mercury regulations for power plants were issued in October 2003 calling for two faces of mercury reductions. The first attainment level is a facility average total mercury removal efficiency of at least 85 percent, or a facility average total mercury emissions rate of .0075 lbs/GWh by October 1, 2006. The second attainment level is a facility average total mercury removal efficiency of at least 95 percent, or a facility average total mercury emissions rate of .0025 lbs/GWh by October 1, 2012.

The six regulated facilities are required to demonstrate to the Department of Environmental Protection by January 30 of each year that CO₂ emissions in the previous year did not exceed historical actual emissions. The facilities are also required to ensure that the average emission rate of CO₂ does not exceed 1,800 lbs/MWh. There are a number of ways that a facility may demonstrate compliance, including using offsite reductions or carbon sequestration, provided the department certifies that the reductions are “real, surplus, verifiable, permanent and enforceable.” The state’s CO₂ controls are the first imposed on existing power plants by any state.

New Hampshire

During the 2002 session, the New Hampshire Legislature passed, and the governor signed, HB 284 (Chapter 130) establishing caps for emissions of NOx, SO₂, mercury and CO₂ by the state’s three existing fossil fuel burning power plants. The legislation--N.H. Rev. Stat. §§ 125-O:1 - 125-O:10 Multiple Pollutant Reduction Program--was the result of negotiations between Public Service of New Hampshire (PSNH), several New Hampshire environmental organizations, state legislators, state energy and environmental officials and the governor’s office.

The corresponding executive agency rules--N.H. Code Admin. R. Ann. Env. A2900 (2003)--became effective on May 13, 2003 and place a cap on emissions from the state’s three fossil fuel burning power plants. The caps are annual and “output based,” encouraging more efficient generation than the traditional “input based” regulations. The program authorizes the banking and trading of emissions reductions in order to achieve compliance for emissions of NOx, SO₂and CO₂.

Under the statute, SO₂emissions must be reduced 75 percent from current levels, and emissions of NOx must be reduced 70 percent from current levels, by the end of 2006; CO₂ emissions must be reduced to 1990 levels by 2010. The specific statewide annual emissions caps are 7,289 tons for SO₂, 3,644 tons for NOx, and 5,425,866 tons for CO₂. A cap was not placed on mercury emissions, but one will be recommended to the legislature by the Department of Environmental Services by early 2004. The schedule for the determination of a mercury cap takes into account a specific assessment of mercury emissions from the three facilities and the results of federal mercury limits that should be proposed by the U.S. Environmental Protection Agency in late 2003.

The legislation included some innovative incentives to encourage PSNH to comply with the emissions caps in ways that will most benefit the state. Specifically:

Voluntary expenditures by PSNH for energy efficiency, renewable energy and conservation programs can be converted into allowances to aid in compliance with the caps.
If PSNH reduces its direct emissions below a three-year moving average, it can receive credit for those reductions the following year.
If PSNH acquires pollution allowances from other states directly upwind from New Hampshire, it will get a premium over allowances acquired from more remote states.

North Carolina

The 2002 session saw another successful collaboration between stakeholders when the North Carolina Legislature passed, and the governor signed, SB 1078 (Session Law 2002-4). The Clean Smokestacks Act is the result of consensus reached among the electric utilities, the environmental community, the business and manufacturing sector, the public health sector and consumers on a multi-pollutant strategy to clean up North Carolina’s air.

The two pollutants specifically regulated under the act are NOx and SO₂ emissions from large-scale coal fired generating units owned or operated by investor owned public utilities in the state.

The legislation establishes caps designed to reduce emissions of each pollutant by roughly two-thirds over a 10-year period. Those plants that collectively emitted more than 75,000 tons of NOx in 2000 are required to reduce their annual emissions to no more than 35,000 tons beginning January 1, 2007, and to no more than 31,000 tons two years later. Those plants that emitted less than 75,000 tons of NOx are required to reduce annual emissions to a maximum of 25,000 tons beginning January 1, 2007.

Those plants that collectively emitted more than 225,000 tons of SO₂ in 2000 are required to reduce annual emissions to no more than 150,000 tons beginning January 1, 2009, and to a maximum of 80,000 tons by January 1, 2013. For those plants that emitted less than 225,000 tons of SO₂, the limits are 100,000 tons and 50,000 tons per year by the same respective dates.

To pay for the emission reductions, the act allows the utilities to accelerate the recovery of their compliance costs through the electricity rate base (the legislation freezes the rates--which were anticipated to go down--for five years). The legislation also authorizes the governor to enter into annual agreements with the power companies to voluntarily transfer to the state pollution allowances that they would earn from complying with the law (because North Carolina’s caps are stricter than current federal limits, the utilities would receive federal pollution allowances that could be sold to power plants in upwind states). These allowances are held in trust for the citizens of the state and cannot be transferred without legislative approval (the governor and utilities signed contracts to this effect the day after the bill was signed). By retiring the allowances, the act ensures that emission reductions made in North Carolina do not come back in the form of pollution from other states.

Florida

Both the Florida House and Senate are considering bills that would regulate emissions of NOx, SO₂ and particulates from coal-fired, oil- and gas-fired and oil-fired electric generating units. The “Air Quality Improvement Act”--House bill 1631 and Senate bill 2798--is pending in the Florida Legislature. The bill was reported favorably by the Senate Natural Resources Committee and the House Energy Committee.

The following are the emission reductions that would be required of investor owned public utilities that own or operate coal-fired electric generating units for which the 2002 collective emissions of NOx was between 32 and 36,000 tons and the collective emissions of SO₂ was between 96 and 100, 000 tons. Collective emissions of NOx may not exceed 17,000 tons, while the collective emissions of SO₂ may not exceed more than 50,000 tons. These reductions will be required as of 2010.

There are additional emission reductions that would be required of investor owned public utilities that own or operate residual oil and natural gas-fired or residual oil-fired generating units for which the 2002 collective emissions of NOx exceeded 11,000 tons and the collective emissions of particulates exceeded 7,000 tons. Collective emissions of NOx may not exceed an annual weighted average of .26 pounds of NOx per million BTUs of fuel consumed, while the collective emissions of particulates may not exceed an annual weighted average of .030 pounds per million BTUs of fuel consumed. These reductions will be required as of 2010 and 2012 respectively.

The utilities will be required to submit a compliance plan to the Department of Environmental Protection (DEP) not later than August 1 of the year the act becomes effective. Once a compliance plan is submitted, the DEP will have 30 days to certify that the plan is capable of achieving the emissions limitations required. A public utility subject to the air emission limitations of the act may petition the DEP for approval to recover costs and expenses associated with achieving compliance with the act. The petition must be filed on or before September 1 of the year prior to which requested cost recovery is to begin.

Comparison of State Multi-Pollutant Strategies

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