1. Background and Summary of the Bills

On March 19, 2004, Senator James M. Inhofe requested the Energy Information Administration (EIA) to undertake analysis of S.843, the Clean Air Planning Act of 2003, introduced by Senator Thomas Carper; S.366, the Clean Power Act of 2003, introduced by Senator James Jeffords; and S.1844, the Clear Skies Act of 2003, introduced by Senator James M. Inhofe. This Service Report responds to his request.

Bill Summary

These bills require reductions in the emissions of sulfur dioxide (SO₂), nitrogen oxides (NO_x), and mercury (Hg) from electricity generating plants.² In addition, the Clean Air Planning Act and the Clean Power Act also call for reductions in power sector emissions of carbon dioxide (CO₂). The emissions caps and reduction timetables differ, but the bills generally call for cap-and-trade emission reduction programs (Table 1 and Figures 1 through 4) covering most electricity-generating facilities.

All three bills cover emissions from larger generators that generate power for sale. This includes central station generators and generators at customer sites that sell power they do not use for their own needs. The exact provisions in each of the acts do differ in some respects. The Clear Skies and Clean Air Planning Acts cover generating facilities 25 megawatts and larger, while the Clean Power Act covers facilities 15 megawatts and larger. The Clear Skies and Clean Air Planning Acts do not cover combined heat and power facilities (often referred to as cogeneration facilities) unless they meet the size requirement and they provide more than one-third of their potential output to any utility power distribution company for sale. The Clean Power Act covers combined heat and power facilities as long as they meet the size requirement and produce any power for sale. In all three acts, facilities that do not generate any power for sale are not covered.

Neither the Clear Skies nor the Clean Air Planning Act places any requirements on the emissions of facilities that are not directly covered by their emission targets. However, while the Clean Power Act does not explicitly cover generating facilities smaller than 15 megawatts that sell power, it does require that the cap on the emissions from larger facilities be adjusted to account for their emissions. Specifically, beginning in 2009, the emissions caps on larger facilities must be reduced by the emissions from smaller facilities from the second preceding year. In other words, the 2009 emissions caps for covered larger facilities are reduced by the 2007 emissions from smaller facilities. In this analysis, the CO₂ emissions caps in the Clean Power Act are adjusted to account for estimated emissions by small generators in the end-use sectors that sell power to the grid. The emissions from small generators in the power sector are directly included in the emissions cap, but these generators are not required to pay for CO₂ allowances.

To put the emission targets in perspective, the Clear Skies Act calls for reducing SO₂ emissions by 72 percent from the 2001 emission level, while the Clean Air Planning and Clean Power Acts call for a 79-percent reduction. For NO_x, Clear Skies calls for a 62-percent reduction from the 2001 emission level while the Clean Air Planning Act calls for a 64-percent reduction and the Clean Power Act calls for a 68-percent reduction. For Hg, Clear Skies calls for a 69-percent reduction from the 2001 level while the Clean Air Planning Act calls for an 80-percent reduction, and the Clean Power Act calls for a 90-percent reduction.³ The emission targets in the bill may not be achieved by the target dates because of allowance banking and, in the case of the Clear Skies Act, the safety valve limitations on allowance prices.

The Clean Air Planning Act calls for reducing CO₂ emissions from electricity generating plants in 2009 to the level projected in EIA’s reference case for 2005⁴ and further reducing them to the actual 2001 level by 2013. Relative to EIA’s projected CO₂ emissions from electricity generators in the reference case, the 2013 target in the Clean Air Planning Act would require a 25-percent reduction in 2020 and a 32-percent reduction in 2025⁵. However, the Clean Air Planning Act allows generators to comply with the CO₂ target using allowances from other domestic or international greenhouse gas trading programs or by investing in projects that reduce greenhouse gas emissions or increase sequestration. The Clean Power Act calls for reducing CO₂ emissions from electricity generating plants in 2009 to 1990 levels, approximately 39 percent below the projected level in 2020 and 43 percent below the projected level in 2025. There are no carbon emission reductions under the Clear Skies Act.

All of the bills rely primarily on emissions cap-and-trade programs to meet their specified emission targets (except for mercury under the Clean Power Act). Under a cap-and-trade program, each power plant must annually submit an allowance for each unit (i.e., tons, metric tons, pounds, or ounces) of emissions. Market forces will determine allowance prices, and each covered entity is free to determine its optimal compliance strategy. They can choose to reduce their emissions or purchase allowances from others who have reduced their emissions below the level of allowances they hold. They can also choose to over-comply in an earlier year and to use those allowances in a future period, i.e., bank allowances. Besides differences in the timing and stringency of the emissions caps, there are several important features in each bill. These include:

Excess emissions penalties and allowance price safety valves

The Clear Skies Act sets excess emissions penalty for NO_x at $2,000 per ton. For SO₂, the penalty before 2008 is $2,000 per ton of SO₂ if offsets are made and payments are received within 30 days. If offsets are not made or payments are not received within 30 days, then the penalty is $4,000 per ton of SO₂. After 2007, the penalty for SO₂ is set to the annual average price of SO₂ allowances. These penalty values, originally established in 1990 dollars in the Clean Air Act Amendments of 1990, are adjusted for inflation. For mercury, the penalty is set to the annual average price of mercury allowances. Facilities with excess emissions are required to pay the penalties and reduce their future emissions to cover their excess emissions. That is, facility owners cannot just pay the penalty and not reduce their emissions.

In addition, the Clear Skies Act establishes an allowance price safety valve for each type of emission. Facilities can purchase allowances from the government at these safety valve prices if they are not available in the market at lower prices. The safety valve puts a limit on the respective allowance prices and, if utilized, will cause the emission targets to be exceeded.⁶ Under Clear Skies the safety valve values are: $2,000 per ton for SO₂, $4,000 per ton for NO_x, and $2,187.50 per ounce ($35,000 per pound) for mercury. These values are to be adjusted for inflation beginning with the year the act is passed.

The Clean Air Planning Act does not specify safety valves, but imposes excess emissions penalties amounting to: $2,000 (in year 1990 dollars) per ton for SO₂, $5,000 per ton for NO_x, $10,000 per pound for mercury, and $100 per ton for CO₂ (penalty fees are to be adjusted for inflation). In addition, excess emissions must be made up in the following year or within a period of time prescribed by the Administrator of the Environmental Protection Agency (EPA).

The Clean Power Act does not specify safety valves, but imposes excess emissions penalties for SO₂, NO_x, and CO₂, amounting to three times the excess emissions in tons multiplied by the average annual market price for the appropriate allowances. For mercury, the excess emissions penalty amounts to three times the excess emissions in grams multiplied by the average cost of mercury controls.

Facility-specific mercury limits

The Clean Air Planning Act requires that all coal facilities either remove a minimum percentage (50 percent between 2009 and 2012, and 70 percent in 2013 and later) of the mercury in the coal used as fuel or that each facility meet an output-based rate to be set by the EPA Administrator. The efforts taken to comply with the requirement to remove a certain percentage of the mercury in the coal reduce the additional efforts needed to meet the overall emissions cap. This will lead to lower allowance prices but higher industry cost than would occur with only a cap-and-trade program.

The Clean Power Act sets a facility specific mercury emissions limit of 2.48 grams per 1,000 megawatthours. This is an emissions limit, not an allocation of allowances, and it may not be banked or traded.

“Birthday Provisions”

Both the Clean Air Planning and Clean Power Acts include provisions triggered when plants reach a specified age, referred to as “birthday provisions.” Beginning in 2020, the Clean Air Planning Act requires that plants that began construction before August 17, 1971, must emit no more than 4.5 pounds per megawatthour of SO₂ and 2.5 pounds per megawatthour of NO_x.

The Clean Power Act requires that all plants have the best available control technology (BACT) beginning in 2014 or when they reach 40 years of age, whichever comes later.

Allowance programs

The Clear Skies Act generally allocates NO_x, SO₂, and Hg allowances to existing units based on historical heat input. This is often referred to as “grandfathering” since the allocation is based on historical fuel use. The baseline period for calculating heat input is the highest 3 years of fuel use for each facility between 1998 and 2002.

For SO₂, the Clean Air Planning Act also allocates allowances using a grandfathering approach, while for NO_x, mercury, and CO₂ allowances are allocated on an output basis (i.e., pounds per megawatthour of electricity produced) that is continually updated based on the most recent 3 years of each facility’s generation. Essentially this is a rolling 3-year generation performance standard (GPS) for NO_x, mercury, and CO₂. Under this bill, allowances are also allocated to new units until they have operated for 3 years and become part of the regular GPS program.⁷

The GPS programs in the Clean Air Planning Act will impact the cost and price impacts of meeting the emission targets. In general, a dynamic GPS, which is updated continuously as each facility’s generation changes, provides an incentive to facilities to increase their output so that they receive more allowances in the future. This “output subsidy” lowers the electricity price impacts of reducing emissions, but increases the cost impacts.⁸ As one expert said, “output based rebating sacrifices some of the efficiencies of market-based environmental policies. Allocating by market share essentially provides a subsidy to output, which creates a bias away from output substitution and toward emissions rate reduction. The result is a higher marginal cost of control, a lower equilibrium output price, and a greater cost of achieving any given level of emissions reduction, compared to an efficient policy. The size of the welfare loss from this distortion depends on how much emissions reduction would normally be performed by output substitution.”⁹ In layman’s terms, this means, if facilities are given allowances based on their output (generation), they will tend to produce more than they otherwise would have.

The output subsidy associated with a GPS derives from its impact on covered generators’ operating costs. For example, a typical coal plant produces approximately 0.25 metric tons of carbon per megawatthour. As a result, a $100 carbon fee would raise its operating cost by $25 per megawatthour. However, under a GPS, the plant will be allocated some allowances for each megawatthour it generates. If it is assumed that the GPS is 0.15 metric tons of carbon per megawatthour, calculated by dividing the CO₂ emissions cap by the generation of all covered plants, the impact on the coal plant’s operating costs of a $100 carbon fee is only $10 per megawatthour ((0.25 – 0.15) X $100). If this plant were setting the market-clearing price of electricity, consumers would face a smaller price increase under the GPS, $10 per megawatthour rather than $25 per megawatthour, and have less incentive to reduce their use of electricity. This would lead to greater generation (output) from the power sector under a GPS allocation program, than under a grandfathering allowance program.

The Clean Air Planning Act establishes an independent review board to certify projects outside of the U.S. power sector as eligible for additional CO₂ allowances. It also allows the use of allowances from recognized international CO₂ trading programs. Electricity facilities are able to use these allowances from certified projects as well as allowances from other U.S. or recognized international CO₂ trading programs (all referred to as offsets in this report) to meet their CO₂ targets rather than directly reducing their own emissions. In addition to existing fossil generators, new fossil fuel and renewable units receive CO₂ allowances.¹⁰

To analyze the availability and cost of greenhouse gas offsets, this analysis incorporates a set of curves representing the potential for other greenhouse reductions and sequestration. These curves, referred to as marginal abatement curves (MACs), were obtained from EPA’s Office of Air and Radiation. Essentially, MACs are simplified, reduced-form representations of emissions compliance potential as a function of a single variable, the allowance price. Because there is great uncertainty in developing these MACs, a range of results is provided based on alternative assumptions.¹¹

Under the Clean Power Act, most allowances are to be allocated to households served by electricity. Other entities receiving allowances include dislocated workers, makers of electricity intensive products, and investors in renewable energy, energy efficiency, cleaner energy, and biological sequestration. In addition, owners or operators of electricity generators receive a declining share of the allowances allocated. The share starts at 10 percent in 2009 and falls to 1 percent in 2018. For this analysis, it is assumed that consumers receive a lump sum payment equal to the allowance revenue each year.

Notes and Sources