2. Analysis of the Proposed Bills

The proposed bills were analyzed using the EIA’s National Energy Modeling System (NEMS). The reference case for the analysis was based on EIA’s Annual Energy Outlook 2004 (AEO2004) and it incorporates final regulatory action under existing laws.¹² Minor updates have been made to the reference case since the AEO2004 was prepared.¹³ It should be noted that the projections in the cases in this report are not statements of what will happen but of what might happen, given the assumptions and methodologies used. The reference case projections are business-as-usual trend forecasts, given known technology, technological and demographic trends, and current laws and regulations. EIA does not propose, advocate, or speculate on future legislative and regulatory changes. All laws are assumed to remain as currently enacted; however, the impacts of planned regulatory changes, when defined, are reflected. C onsistent with standard EIA practice requiring policy neutrality in baseline projections, it does not include pending or proposed actions, such as the maximum achievable control technology (MACT) standards for mercury emissions from power plants or actions that might be taken to comply with the revised National Ambient Air Quality Standards for ozone and fine particulates. The implementation of such actions could affect emissions, generator costs, and electricity prices during the projection period even if there is no new legislation. In addition, the potential benefits that might be associated with emissions reductions are not discussed. EIA does not have expertise in the area of health benefits that might be associated with emissions reductions.

In addition to the uncertainties inherent in the reference case projection itself, there are several important uncertainties in evaluating the bills. Of particular concern in this analysis are the cost and performance of technologies to remove mercury and the availability and cost of greenhouse gas offsets.

Analysis Cases

Table 2 describes the cases prepared for this analysis. Two cases were prepared to analyze the impacts of the Clean Air Planning Act because of uncertainty about the cost and availability of greenhouse gas offsets. The Clean Air Planning Act calls for the establishment of an independent review board to evaluate potential greenhouse offsets, but the criteria they might use are uncertain. One case, Carper Domestic, assumes that only domestic offset programs will be approved, while another, Carper International, assumes both domestic and international offsets will be available. These cases should not be seen as spanning the full range of possible outcomes, but rather representing a reasonable range of outcomes and illustrating the sensitivity of the results to the cost and availability of greenhouse gas offsets.

The cases prepared in this analysis simulate the response of the economy to changing fuel prices and demands. However, recent information suggests that natural gas intensive industries may be more sensitive to higher natural gas prices than is reflected. If these industries are truly more sensitive to natural gas prices, the costs to the power sector of complying with the three bills could be lower. Reduced industrial sector natural gas use would lower the pressure on natural gas markets, making it more economical for the electricity sector to use natural gas. However, this would lead to greater economic loss in the industrial sector.

Throughout this analysis, in order to show the full impacts of the acts, the generation and capacity data reported are for all generators, including small generators that are not covered by the emission limits. As described on page 1, the coverage of the acts does differ in some respects. The emissions data shown are for the electric power sector, which includes all generators whose primary business is to produce and sell electricity.

Generation and Fuel Use

Because of consumers’ responses to higher electricity prices, all of the bills are projected to have lower overall generation than in the reference case (Figure 5). In the Inhofe and Carper cases the change in total generation is expected to be relatively small, with the largest difference being 1 percent lower in the Carper Domestic case. However, in the Jeffords case, total electricity generation is projected to be 7.8 percent below the reference case level in 2010 and 5.2 percent below it in 2025.

All of the bills are projected to lead to lower coal generation and increased generation from natural gas, renewables, and, in the case of Jeffords, nuclear. However, the provisions of the Inhofe bill (S. 1844) are expected to lead to a relatively small shift in the fuels used to generate electricity compared to the other bills. In contrast, the provisions of the Carper and Jeffords bills are expected to lead to larger changes.

Relative to the reference case, coal generation is expected to be 1.1 and 4.9 percent lower in 2010 and 2025, respectively, in the Inhofe case (Figure 6). Conversely, natural gas generation is projected to be 0.8 and 4.9 percent higher in 2010 and 2025, respectively. Over the entire 2002 through 2025 time period natural gas use in the power sector is projected be 1.8 percent higher with the Inhofe bill than without it. For renewables, generation is projected to be 1.1 and 11.2 percent higher in 2010 and 2025, respectively, in the Inhofe case.

Primarily because of their CO₂ emission cap levels, the shifts away from coal towards natural gas and renewables are projected to be much larger under the Carper and Jeffords bills than under the Inhofe bill. In the Carper cases, coal generation in 2020 is projected to be between 12.0 and 16.9 percent below the reference case level. By 2025, this reduction is expected to grow to between 18.0 and 24.2 percent. The range of impacts seen in the Carper cases is driven by assumptions about the availability and cost of greenhouse offsets outside of the power sector. When greenhouse offsets are relatively inexpensive, as in the Carper International case, coal use is not as severely impacted. In contrast to coal, natural gas generation is projected to be from 4.4 to 6.3 and 22.4 to 22.7 percent higher in 2010 and 2025, respectively, in the Carper cases (Figure 7). Similarly, renewable generation is projected to be from 3.0 to 7.9 and 41.1 to 73.2 percent higher in 2010 and 2025, respectively, in the Carper cases (Figure 8). The role of renewables becomes increasingly important as carbon allowance prices grow. At high enough carbon allowance prices, such as in the Jeffords bill, even natural gas-fueled plants which have lower carbon emissions than coal plants, begin to become economically unattractive.

The shift from coal to natural gas, renewables, and nuclear, is most pronounced in the Jeffords case. The relatively stringent emission caps, particularly the CO₂ cap, cause a large decline in coal generation. Relative to the reference case, coal generation is expected to be 35.3 and 54.7 percent lower in 2010 and 2025, respectively, in the Jeffords case. Conversely, natural gas generation is projected to be 30.5 and 8.3 percent higher in 2010 and 2025, respectively, compared to the reference case. The relatively high CO₂ allowance price in the Jeffords case causes growth in natural gas generation to slow as the electric power industry turns to renewables and new nuclear plants in the later years of the projections. Because of their long permitting and construction lead times, new nuclear plants are not expected to be able to begin contributing to reducing CO₂ emissions until 2014. Renewable generation in the Jeffords case is projected to be 133.9 and 144.1 percent higher in 2020 and 2025, respectively, than in the reference case. In the same years nuclear generation is projected to be 13.0 and 53.1 percent higher than in the reference case (Figure 9).

The change in coal production follows the decline in coal generation across the cases (Figure 10). In the Inhofe case, coal production is 10.9 and 64.9 million tons (0.9 and 4.2 percent) below the reference case level in 2010 and 2025, respectively. In the Carper cases, the reduction in coal production is much larger, ranging from 133.7 to180.5 million tons (9.7 to 13.1 percent) lower than the reference case level in 2020, and 238.4 to 302.2 million tons (15.6 to 19.7 percent) lower than the reference case level in 2025. The reduction in coal is even larger in the Jeffords case. Relative to the reference case, it is 623.4 million tons (45.4 percent) lower in 2020 and 771.6 million tons (50.4 percent) lower in 2025.

In contrast to coal, natural gas consumption increases relative to the reference case in all of the cases (Figure 11). The increase is generally stronger in the cases with a CO₂ emissions cap. However, in the Jeffords case, which has the most stringent CO₂ emissions cap, the price of natural gas together with the CO₂ allowance fee is projected to be high enough to make new renewable and nuclear technologies more attractive. As a result, growth in natural gas use slows in the later part of the projections in the Jeffords case, falling below the level expected in the Carper cases. Increased use of natural gas is very important in the early years of the Jeffords case because the alternatives are few (mainly natural gas, wind, and biomass cofiring), but in the later years, other renewables, nuclear, and fossil technologies with carbon capture and sequestration equipment are part of the generation capacity mix.

The increased use of natural gas is projected to lead to increased reliance on natural gas imports, particularly in the Carper cases (Figure 12). Relative to the reference case, in 2020, net natural gas imports are 0.1 trillion cubic feet (tcf) (1.6 percent) higher in the Inhofe case, 0.3 tcf (4.2 percent) higher in the Carper International case, 0.3 tcf (4.7 percent) higher in the Carper case, and 0.7 tcf (11.4 percent) higher in the Jeffords case. By 2025, dependence on natural gas imports is expected to be particularly strong in the Carper International case, where net imports are 0.8 tcf (10.6 percent) above the reference case. In 2025, net imports are projected to account for 24.6 percent of the total gas supply in the Carper International case. The greater imports in the Carper International case come almost entirely from increases in liquefied natural gas (LNG). In the reference case, LNG imports are projected to reach 4.5 tcf in 2025, while in the Carper International case they are expected to reach 5.1 tcf.

Generating Capacity and Pollution Control Equipment Additions

Capacity Additions

As might be expected, coal, natural gas, and renewable capacity changes in the various cases tend to parallel the generation and fuel use changes discussed previously. Under the Inhofe bill, there is a slight reduction in coal plant construction compared to the reference case (Figure 13). New coal capacity additions through 2025 amount to 92 gigawatts under the Inhofe bill compared to 108 gigawatts in the reference case. Because of the CO₂ cap used in the Carper bills, fewer new coal plants will be constructed compared to the Inhofe bill and the reference case. New coal capacity additions through 2025 range from 21 gigawatts to 35 gigawatts under the Carper bill cases.

The results are different in the Jeffords case due to the comparatively more stringent SO₂, NO_x, mercury, and CO₂ emission targets. Under the Jeffords bill, new coal plant additions are much lower while retirements are higher compared to the reference case. New coal capacity additions through 2025 amount to only 3 gigawatts under the Jeffords bill, and nearly 125 gigawatts of existing coal plants are retired. In addition, the new coal plants that are built are mostly advanced coal plants with carbon capture and sequestration equipment.

In the Carper and Jeffords bills, new renewable capacity is projected to increase significantly (Figure 14). The renewables expected to see the largest growth are biomass and wind. For example, in the Jeffords case, biomass capacity in 2025, including capacity at combined heat and power facilities, is projected to be 84 gigawatts compared to 13 gigawatts in the reference case. Similarly, wind capacity in the Jeffords case in 2025 is projected to be 94 gigawatts compared to 17 gigawatts in the reference case.

The emissions caps on the power sector also have impacts on power plant additions in the commercial and industrial sectors, including refineries, particularly in the Jeffords case. Since many combined heat and power plants in these sectors are smaller than 15 megawatts and may not sell any power to others, they are not directly covered by the bill. As a result, the higher purchased electricity prices that occur in the Jeffords case provide these facilities with an incentive to build new small electricity facilities and combined heat and power facilities to meet their own needs. In the Jeffords case, 31 additional gigawatts of these end-use facilities are projected to be added, and 6 additional gigawatts of distributed generation facilities are added in the power generation sector. Being able to avoid the costs of CO₂ allowances will make small self-generation facilities increasingly attractive. Because these facilities tend to be less efficient than the larger new facilities, their increased development could raise the costs of complying with the bill. Essentially, for every relatively inefficient small generator built and operated, a larger generator will have to take action to offset its emissions. The relatively high CO₂ allowance fee in the Jeffords case is also projected to stimulate the addition of new nuclear capacity. Between 2014 and 2025, 58 gigawatts of new nuclear capacity are projected to be added in the Jeffords case, increasing total U.S. nuclear capacity by about 60 percent.¹⁴

Pollution Control Equipment

While generating capacity investment decisions are not expected to change significantly in the Inhofe bill, power companies are projected to make significant investments in pollution control equipment to meet the NO_x, SO₂, and mercury caps in all three bills. For NO_x control, they are expected to turn mainly to selective catalytic control (SCR) systems. Under the Inhofe bill, power companies are expected to add 160 gigawatts of SCR capacity by 2025 (Figure 15). SCR additions are expected to be slightly higher under the Carper bill because SCRs also help to reduce mercury emissions for some plants and coal types. With a slightly lower NO_x emissions cap than under Inhofe, the amount of capacity expected to add SCRs in the Carper cases is similar though slightly higher than in the Inhofe case. Between the Carper domestic and international cases, the amount of capacity projected to add SCRs ranges from 159 gigawatts to 165 gigawatts by 2025.

Among these three bills, Jeffords has the lowest NO_x emission limit and that limit has to be achieved at the earliest time. In addition, as discussed in the background section, the Jeffords bill has a birthday provision that requires all plants to add the best available control technology by 2014 or 40 years of age, whichever comes later. This essentially means that to continue operating beyond their 40 th birthday, all plants must add the best available emission controls. As a result, under the Jeffords bill, power companies are projected to add about 206 gigawatts of SCR capacity by 2025, which is significantly more than in the other cases.

Under the Inhofe bill, power companies are projected to add 123 gigawatts of SO₂ scrubber capacity by 2025 (Figure 16). With approximately 90 gigawatts of SO₂ scrubbers on existing plants today, this means that approximately two-thirds of existing coal capacity will have SO₂ scrubbers by 2025.¹⁵ Those existing plants not adding SO₂ scrubbers are expected to turn to low-sulfur coal to reduce their emissions.

In comparison to the Inhofe bill, the tighter SO₂ emissions cap leads to greater additions of SO₂ scrubbers under the Carper bill cases. In these cases, the amount of capacity adding SO₂ scrubbers is projected to range from 146 gigawatts to 150 gigawatts. The Jeffords bill has the same SO₂ emission cap as the Carper bill, although in the Jeffords bill the cap takes effect earlier than in the Carper bill. By 2025, the amount of SO₂ scrubber additions under the Jeffords bill (130 gigawatts) is similar to that required under the Carper bill. The amount of capacity adding scrubbers is highest in the Carper International case because it has tighter SO₂ and mercury emission limits than the Inhofe bill and the availability of low-cost greenhouse gas offsets means that more coal plants keep operating than in the Carper Domestic or Jeffords cases.

To meet the mercury emissions cap, power plants are expected to partially rely on mercury reductions that come from equipment primarily designed to remove NO_x, SO₂, and particulates¹⁶ and partially on the use of activated carbon injection (ACI) systems designed to specifically remove mercury. ACI can be used with existing particulate control devices (such as electrostatic precipitators or fabric filters) or with a supplemental fabric filter specifically designed to remove mercury. The ACI fabric filter systems are more expensive but are also more effective when a higher percentage of mercury must be removed. Under the Inhofe bill, the mercury removal requirement can be achieved without the need for ACI fabric filters (Figure 17). However, under the Carper bill, the requirement is that all coal plants have to remove at least 70 percent of mercury in the coal that they use and there is a tighter mercury cap. In the Carper case, ACI fabric filter systems are expected to be the key compliance strategy for reducing mercury emissions. By 2025, between 139 gigawatts and 142 gigawatts of capacity are projected to be retrofitted with ACI fabric filter systems in the Carper cases.

To comply with the generator specific mercury emission requirement in the Jeffords bill, most generators would have to remove over 90 percent of the mercury in the coal they use. For example, the average coal used today contains about 7.3 pounds of mercury per trillion Btu. For a plant that consumes 10,000 Btu of coal per kilowatthour of electricity produced, just over 33 grams of mercury would be produced for each 1,000 megawatthours of electricity generated. Thus, meeting the 2.48 gram per 1,000 megawatthour standard would, on average, require a 93-percent reduction from the level of mercury in the coal. With currently available technologies, it is not known whether this level of removal is achievable for all plant and coal types. This is particularly true for plants using subbituminous and lignite coals. Technologies for removing SO₂ and NO_x are not as successful at removing mercury from these lower rank coals and mercury specific control technologies that can achieve greater than 90-percent removal have not been demonstrated.

The technologies normally represented for mercury removal assume that most plants can only achieve a maximum 90-percent removal. Only plants with full fabric filter systems for particulate control and scrubbers for SO₂ control are assumed to achieve mercury removal levels in excess of 90 percent. To represent the Jeffords bill, it was assumed that plants with cold- or hot-side electrostatic precipitators for particulate control could replace them with full fabric filter systems to achieve 95-percent mercury removal. However, the cost of these retrofits is expected to be high because the existing particulate control systems will have to be removed and significant plant modifications may be needed. To represent these costs, it was assumed that retrofitting full fabric filter systems would cost twice as much as a similar system on a new plant, or approximately $125 per kilowatt. In the Jeffords case nearly 147 gigawatts of coal capacity is projected to be retrofitted with full fabric systems while 60 gigawatts are retrofitted with supplemental fabric filter systems with activated carbon injection to meet the generator specific mercury emission limits.

Electricity Prices, Consumer Electricity, Natural Gas Expenditures, and Industry Resource Costs

Meeting the emissions caps in the Inhofe, Carper, and Jeffords bills is projected to lead to higher electricity prices and industry resource costs. These changes are driven by the increased reliance on higher-cost generating options and the addition of emissions control equipment to reduce NO_x, SO₂, Hg, and CO₂ emissions. The largest price increases are projected in the cases with the more stringent CO₂ emissions caps. In the Inhofe case, electricity prices are projected to be 2.6 and 3.2 percent above the reference case levels in 2010 and 2025, respectively (Figure 18). In the Carper cases, electricity prices are projected to be between 3.0 and 3.6 percent above the reference case level in 2010 and between 4.3 and 7.8 percent above the reference case level in 2025. Of the two Carper cases, the Carper Domestic case is projected to show the larger price increase because only domestic greenhouse gas offsets are assumed to be allowed. The electricity price increases in the Carper cases are dampened by the output-based scheme used to allocate emission allowances. This allocation approach leads to higher overall compliance costs but lower electricity price impacts.

The largest electricity price increases are expected in the Jeffords case. The near-term timing and stringency of the emission caps, combined with the relatively strict facility specific requirements for mercury control and the birthday provision, are the factors driving the large price increases. Electricity prices, in the Jeffords case, are projected to be 47.2 and 26.5 percent above the reference case levels in 2010 and 2025, respectively. The price impact is largest in the near-term, because meeting the 2009 CO₂ cap requires a rapid industry transformation from coal to natural gas and renewables. Over time, other generating options such as new nuclear, dedicated biomass gasification, and fossil plants with sequestration equipment become available. In addition, as these new technologies penetrate the market their costs are expected to decline, reducing the impact on electricity prices compared to that of 2009.

The changes in consumer expenditures on electricity tend to follow the electricity price changes (Figure 19). However, on a percentage basis, the increases in expenditures are smaller than the electricity price changes because consumers reduce their electricity consumption. In the Inhofe case, electricity use is generally within 1 percent of the reference case level, while it is between 1 and 2 percent below the reference case level in the Carper cases, and 7 to 8 percent below the reference case level in the Jeffords case. Relative to the reference case, the Nation’s electricity bill is projected to be $5.9 billion (2002 dollars) (2.2 percent) higher in the Inhofe case in 2010 and $8.0 billion (2.2 percent) higher in 2025. This compares to between $6.8 billion (2.5 percent) and $8.1 billion (3.1 percent) higher in 2010 and between $11.3 billion (3.1 percent) and $21.1 billion (5.7 percent) higher in 2025 in the Carper cases. In the Jeffords case, the Nation’s electricity bill is projected to be $97.7 billion (35.2 percent) higher than in the reference case in 2010 and $60.0 billion (15.9 percent) higher in 2025.

The average annual household electricity bill is projected to be $19 and $23 higher in 2010 and 2025, respectively, in the Inhofe case. The average annual household electricity bill is projected to be between $21 and $24 in 2010 and $29 and $57 in 2025 in the Carper cases. The average annual household electricity bill in the Jeffords case is projected to be $305 and $177 higher in 2010 and 2025, respectively.

Consumers are also projected to spend more on natural gas as electricity producers drive up the price of gas by increasing their natural gas consumption (Figure 20). Relative to the reference case, the Nation’s nonelectricity sector natural gas bill is projected to be $0.8 billion (2002 dollars) higher in the Inhofe case in 2020. This compares to between $2.1 billion and $2.9 billion higher in the Carper cases and $23.5 billion higher in the Jeffords case. While the impact will vary from region to region, when averaged over the 63 percent of households using natural gas, the annual household natural gas bill in 2020 is projected to be $4 higher in the Inhofe case, $6 to $9 higher in the Carper cases, and $15 higher in the Jeffords case. In the Jeffords case where the greatest impact on gas markets occurs in 2009, the average household increase in natural gas is $52 ($83 when just the households using natural gas are included). The relatively large increase in the Jeffords case is due to the stringency of the emissions caps, particularly the CO₂ emissions cap, and the exemption for small generators that do not have to hold allowances. With a projected CO₂ allowance fee of over $27 per metric ton CO₂ ($100 per metric ton carbon equivalent), small generators are expected to become increasingly economical.

The change in electric industry expenditures, referred to as resource costs, also tend to follow the change in electricity prices (Figure 21). To comply with the bills, the industry is projected to spend more on fuel, new plants, emissions control equipment, and supplies such as activated carbon. Over the 2005 through 2025 period, industry resource costs are projected to be 1.3 percent ($19 billion) higher in the Inhofe case, 2.9 percent ($42 billion) to 4.5 percent ($65 billion) higher in the Carper cases and 19.4 percent ($279 billion) higher in the Jeffords case.¹⁷

Emissions and Allowance Prices

The emissions data shown in this section are for the electric power sector, which includes all generators whose primary business is to produce and sell electricity. Emissions from industrial and commercial facilities that primarily produce power for their own use are not included.

Sulfur Dioxide

As might be expected, the respective allowance prices are projected to increase as the emissions caps are tightened. For example, under the Inhofe bill, national SO₂ emissions are projected to decline from approximately 10.2 million tons in 2002 to 3.6 million tons in 2025 (Figure 22). Note that because of emission banking, SO₂ emissions are not expected to reach the 3-million-ton target specified for 2018. This target is not even reached by 2025. SO₂ allowance prices under the Inhofe bill are projected to be $605 per ton in 2010 and $1,414 per ton in 2025 (Figure 23). The pattern of SO₂ emissions and allowance prices is similar in the Carper cases, though projected allowance prices are higher due to the lower emissions limits. National SO₂ emissions are projected to decline from approximately 10.2 million tons in 2002 to 2.9 million tons in 2025 in the Carper Domestic case and 2.8 million tons in the Carper International case. There are slight differences between the Carper Domestic and Carper International cases, and these reflect differences in emissions banking patterns in the two cases. Also, as is projected to occur under the Inhofe bill, because of emission banking, SO₂ emissions are not expected to reach the 2.25-million-ton target specified for 2016. This target is, again, not achieved by 2025. SO₂ allowance prices in the Carper Domestic and International cases are projected to range from $898 per ton to $906 per ton in 2010 and from $1,792 per ton to $2,064 per ton in 2025. In the long run, SO₂ allowance prices tend to be lower in the Carper Domestic case than in the Carper International case because higher CO₂ allowance prices lead to lower coal use. This is much higher than the comparable allowance prices under the Inhofe bill.

The Jeffords bill is somewhat different from the other bills in that the SO₂ emission cap has to be achieved in 2009 compared to 2016 in the Carper bill and 2018 in the Inhofe bill. In addition, the Jeffords bill has a provision which requires that all plants have to install the best available control technology beginning in 2014 or when they reach 40 years of age, whichever comes later (this is known as the “birthday provision”). Since a reduction of coal use to meet a CO₂ cap would also reduce SO₂ emissions, there are significant synergies between the CO₂ cap and the SO₂ cap in the Jeffords bill. The CO₂ cap under the Jeffords bill is earlier and more stringent than the Carper bill cap. The combined effect of power companies reducing their use of coal to comply with the CO₂ cap and the impact of the birthday provision in the Jeffords bill is that plants over-comply with respect to meeting their SO₂ emissions cap. Under the Jeffords bill, national SO₂ emissions are projected to decline from approximately 10.2 million tons in 2002 to 1.18 million tons in 2025, which is significantly under the emission cap of 2.25 million tons. Because of the CO₂ cap and the birthday provision in the Jeffords bill, SO₂ allowance prices rise to $373 per ton in 2010 and then decline to zero by 2014.

Nitrogen Oxides

In the Inhofe and Carper domestic and international cases, NO_x emissions are projected to fall from 4.4 million tons in 2002 to about 1.7 to 1.8 million tons by 2025. Both bills meet or are very close to meeting their NO_x emission targets within the required timetables. Unlike for SO₂, because the first and second phase targets are so close, there is not expected to be significant NOx allowance banking during the first reduction phases, so the second phase targets are achieved as scheduled. NO_x allowance prices under the Inhofe bill are projected to be higher in the Eastern United States than in the West (Figures 24 and 25). Generally, eastern region NO_x allowance prices under the Inhofe bill are expected to be in the $2,040 per ton to $2,776 per ton range across all years. In contrast, western region allowance prices under the Inhofe bill are expected to be in the $1,124 to $1,715 per ton range. NO_x allowance prices in the West are lower because the western region NO_x emissions cap does not require plants to reduce their emission rates as much as in the East.

The Carper bill does not differentiate between emission caps in the East and West. The Nation as a whole has to meet the same overall cap regardless of the location of the power plants. Therefore there is no difference in NO_x allowance prices between the East and West under the Carper bill. In 2025, NO_x allowance prices in the Carper Domestic and International cases range from $1,792 to $1,857 per ton. The Carper International case results in higher NO_x allowance prices because of synergies between the CO₂ cap and the NO_x cap since a reduction of coal use to meet a CO₂ cap would also reduce NO_x emissions. Under the Carper International case, power companies are able to purchase greenhouse gas emission offsets from the international and domestic market at lower costs compared to the domestic only offset market in the Carper Domestic case. The availability of international offsets allows more of their existing coal capacity to continue operating while still meeting the CO₂ cap. However, the higher coal capacity results in higher allowance prices for NO_x emissions.

Under the Jeffords bill, the final NO_x emission cap has to be achieved earlier, in 2009 compared to 2013 in the Carper bill and 2018 in the Inhofe bill. The combined effect of power companies reducing their use of coal to comply with the CO₂ cap and the impact of the birthday provision is that plants over-comply with respect to meeting their NO_x emissions cap. Under the Jeffords bill, national NO_x emissions are projected to decline from approximately 4.4 million tons in 2002 to 0.61 million tons in 2025, which is significantly under the emission cap of 1.51 million tons. Because of the CO₂ cap and the birthday provision in the Jeffords bill, NO_x allowance prices rise to $2,042 per ton in 2009 and then decline to zero almost immediately thereafter.

Mercury

Mercury emissions are projected to be below the reference case level under the Inhofe bill (Figure 26). In the reference case, mercury emissions are expected to increase to approximately 55 tons in 2025 as existing coal plants are used more intensively and new coal plants are added. Under the Inhofe bill, 2025 mercury emissions are projected to be only 29 tons because of the combined effect of equipment added to reduce NO_x, SO₂, and mercury. However, mercury emissions are not projected to reach the 2010 or 2018 cap levels because of the early credit program and the mercury safety valve. In 2010 under the Inhofe bill, mercury emissions are expected to be 40 tons (versus a cap of 34 tons), while in 2025 emissions are 29 tons (versus a cap of 15 tons). Mercury emissions are projected to exceed the 34-ton cap in 2010 because of the use of early credits power companies accumulate (bank) prior to the start of the program. In the longer term, mercury emissions are projected to exceed the 15-ton cap that begins in 2018 because of the $35,000-per-pound safety valve on mercury allowance prices (Figure 27).

Under the Carper bill, the pattern of mercury emissions is similar to that of the Inhofe bill, though lower because of the tighter mercury emissions cap and the lack of a mercury allowance safety valve. Mercury emissions are projected to be 10 tons in 2025, much lower than the 55 tons projected in the reference case. The co-benefits of NO_x and SO₂ reduction, the addition of mercury reduction equipment, and reduced coal use are the key drivers in lower mercury emissions. Under the Carper bill, the requirement that all plants remove a minimum of 70 percent of the mercury in the coal also contributes to the reduced mercury emissions. The mercury cap is 10 tons by 2013, which is achieved in both the domestic and international cases of the Carper bill¹⁸. In the Carper cases, mercury allowance prices in 2025 are projected to be between $55,000-per-pound and $69,000-per-pound. These allowances prices would be higher without the plant-specific mercury reduction requirements. This compares to the $35,000-per-pound allowance price in 2025 under the Inhofe bill, due to the limit imposed by the safety valve.

The Jeffords bill 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 does not allow for banking or trading of allowances. The emission limit in the Jeffords bill is set to achieve an overall mercury emissions cap of 5 tons by 2009, much earlier than the final caps in the Carper and Inhofe bills, which take effect in 2013 and 2018, respectively. However, because coal use is projected to fall because of the CO₂ emissions cap, the mercury emissions are expected to be 3.7 tons in 2025, 1.3 tons under the 5-ton emissions target. This is partially achieved through the co-benefits associated with the installation of NO_x and SO₂ control equipment. However, the primary strategy is expected to be the addition of fabric filters and activated carbon injection systems to reduce mercury.

Carbon Dioxide

Under the reference case assumptions, CO₂ emissions from the generation sector in 2025 are projected to be 3,271 million metric tons (892 million metric tons carbon equivalent). There are no CO₂ caps under the Inhofe bill; however, because of NO_x, SO₂, and mercury caps, there is a slight shift from coal to natural gas. This shift results in a decline in CO₂ emissions in the Inhofe bill compared to the reference case. In 2025, CO₂ emissions under the Inhofe bill are projected to be 3,164 million metric tons (863 million metric tons carbon equivalent), about 3 percent below the reference case level.

The Carper bill requires a reduction in CO₂ emissions to 2,244 million metric tons (612 million metric tons of carbon equivalent) by 2013. Although the Carper cases have lower CO₂ emissions than under the Inhofe bill, neither the Carper Domestic or International cases achieve this target because of the use of greenhouse gas offsets. The projected change in CO₂ emissions in the Carper Domestic and International cases depends on the availability and cost of offsets (Figure 28). In the Carper Domestic case, generation companies are projected to rely primarily on offsets available in the domestic U.S. market. In the Carper International case, a greater amount of offsets are available at a lower cost from the international offset market. Therefore, in the Carper Domestic case the CO₂ emissions in 2025 are projected to be 2,721 million metric tons (742 million metric tons carbon equivalent). In the Carper International case, generation companies rely more on international offsets rather than direct emission reductions to meet the CO₂ cap. Therefore the CO₂ emissions are projected to be higher, 2,904 million metric tons (792 million metric tons carbon equivalent) in 2025.

CO₂ allowance prices are projected to vary significantly across the Carper cases (Figure 29). In 2010, CO₂ allowance prices are projected to range from $1 to $6 per metric ton ($5 to $22 per metric ton carbon equivalent), while in 2025 the range widens to between $7 to $17 per metric ton ($27 and $61 per metric ton carbon equivalent). The increase over time is driven by the growing demand for electricity and resulting need for greater emissions reductions from the reference case level.

The Jeffords bill calls for a reduction to 1,863 million metric tons of CO₂ (508 million metric tons carbon equivalent) by 2009 (which is approximately the 1990 level of CO₂ emissions from the electricity sector) and it does not allow for emissions offsets.

However, because the emissions of small generators, including those in the residential, commercial, and industrial sectors, must be offset by emissions reductions in larger, covered generators the cap is projected to decline slightly over time. Electricity sector CO₂ emissions in the Jeffords bill are projected be 1,808 million metric tons (493 million metric tons carbon equivalent) in 2010 and 1,732 million metric tons (472 million metric tons carbon equivalent) in 2025. Because it is only 5 years away, meeting the 2009 cap is expected to be particularly challenging because the near-term options for lower emission technologies are limited to the increased use of natural gas or renewables such as wind and biomass cofiring. As a result, CO₂ allowance prices in 2009 are projected to be quite high, over $58 per metric ton of CO₂ ($212 per metric ton carbon equivalent). Over the longer term, they are projected to be lower, generally ranging between $29 and $42 per metric ton CO₂ ($108 and $155 per metric ton carbon equivalent). Over time, other generating options such as new nuclear, dedicated biomass gasification, and fossil plants with sequestration equipment become available and the carbon allowance price declines.

Regional Emissions

NEMS reports regional results for the electric power sector based on reliability council regions and sub-regions (Figure 30). Under the Inhofe bill, NO_x, SO₂, and mercury emissions are projected to fall in all regions of the country, but the largest changes are in regions where coal supplies a large share of the generation (Figures 31, 32, and 33). Large, heavily coal-dependant regions such as ECAR and SERC are projected to show the largest reductions in NO_x and SO₂ emissions under the Inhofe bill. Despite the fact that there is no CO₂ cap in the Inhofe bill there is a slight reduction in CO₂ emissions due to the indirect effect of the NO_x, SO₂, and mercury caps. The combined effect of these caps creates a slight shift away from coal to natural gas and renewables for the power industry, which leads to reduced CO₂ emissions.

In the Carper and Jeffords cases, NO_x, SO₂, and CO₂ emissions are also projected to fall in most of the regions of the country. Because of the tighter emissions caps and earlier reduction schedule, the regional emissions in 2025 are lower than under the Inhofe bill. As under the Inhofe bill, the largest changes are in regions where coal supplies a large share of the generation, specifically ECAR and SERC.

Economic and Employment Impacts

The imposition of emission limits on the generation sector affects the whole U.S. economy through higher delivered energy prices. As energy prices increase, the cost of production rises, especially for energy-intensive goods, placing upward pressure on the prices of intermediate and final goods and services. Investment and consumer spending decisions will be affected. At the same time, the Federal Reserve Board may seek to balance the adverse effects of higher energy prices by making adjustments to the Federal Funds rate. The adjustments would be designed to moderate the possible impacts on both inflation and unemployment, and to return the economy toward its long-run growth path.

The way that emissions revenue is distributed also has an impact on the economy. The Inhofe and Carper bills allocate allowances to the generation sector either through grandfathering or on an output basis. The effect on energy prices is relatively small because the costs for the generation sector as a whole are relatively small. In the Jeffords case, emissions revenue is collected and distributed according to an allocation scheme. Most of it is given to households consuming electricity; a smaller portion is allocated to renewable generating units, efficiency projects, cleaner energy sources, and to sequestration. Between 2009 and 2018 a declining share is put aside for transition assistance to dislocated workers, hard hit communities and makers of electricity intensive products. Energy prices are expected to rise sharply because of the more stringent CO₂ emissions cap, and the impacts on the economy are more widespread.

Because of the size of the U.S. economy, nearly $10 trillion dollars in 2002, a relatively small decline in economic growth over time can lead to large dollar costs that are a small percent of total Gross Domestic Product (GDP). For example, a 0.1 percent loss in economic output in a $10 trillion economy amounts to a $10 billion loss in a single year. For this reason, it is probably best to focus on the percentage changes in economic output rather than the estimated dollar impacts. Readers should keep the size of the U.S. economy in mind when reviewing the estimated economic costs of the bills. Similarly, the reader should be aware that total U.S. non-farm employment currently exceeds 130 million people. As with economic output, a relatively small percentage loss in employment of 0.1 percent would amount to a loss in employment of 130 thousand.

In the Jeffords case, the wholesale price index for all fuel and power is projected to rise by 48 percent above the reference case in 2009. The price hike slows as the economy adjusts to the new emissions caps and the redistribution of revenue. By 2025, the wholesale price index is expected to be 18 percent above the reference case. Higher energy prices affect all industrial sectors. The industry-wide wholesale price index is projected to be 9 percent above the reference case in 2009, and to be gradually reduced to 4 percent above the reference case by 2025. On an even broader level, the effect on the Consumer Price Index (CPI) is much less acute, varying from 2.5 percent above the reference case in 2013 down to 1.3 percent above the reference case by 2025.

Higher energy prices impact the production of goods and services and consumer spending. The lump-sum transfer of revenue to consumers alleviates some of the burden of the price increases, but overall consumer spending will still be impacted. In the Jeffords case, consumer spending is expected to be reduced by 1.4 percent from the reference case in 2010, while investment is reduced by 4 percent because of the increase in production costs. The economy as a whole, as measured by the real GDP, is projected to fall by 1.5 percent from the reference case in 2010. After 2010, higher energy costs will shift production toward less energy-intensive sectors and more energy-efficient processing and will encourage energy conservation. Energy prices, producer prices, and sales prices begin to stabilize, and consumption and investment begin to recover. As the economy moves toward the long-run equilibrium path, real GDP is projected to be about 0.1 percent lower than the reference case level from 2017 onwards.

Under the Carper Domestic case, the wholesale price index for all fuel and power is projected to rise by less than 5 percent above the reference case throughout the implementation period. The impact on the CPI is less than 0.3 percent per year, and the impact on real GDP is less than -0.1 percent per year in general, with a maximum impact of -0.11 percent in 2014. The economic impact of the Carper International case is very similar to the Carper Domestic case.

The wholesale price index for all fuel and power in the Inhofe bill rises by less than 2 percent above the reference case throughout the implementation period. The impact on the CPI is less than 0.2 percent per year, and the impact on real GDP is less than -0.06 percent per year.

Figure 34 shows the projected total GDP in the alternative cases. The differences are small when compared to total GDP. Since the impacts on the economy vary from year to year, a consistent way of comparing the impact across cases is to compute the percentage change in cumulative real GDP from 2009 through 2025. Figure 35 shows the percentage change in the cumulative sum and the present value of real GDP, using a real discount rate of 7 percent. The percentage change in these two values is estimated to fall between -0.4 percent and -0.5 percent of the economy’s aggregate output between 2009 and 2025. In dollar terms the cumulative change in real GDP in the Jeffords bill is projected to be -$947 billion and the present value loss, -$527 billion. These figures compare to a cumulative sum for total GDP of $255 trillion and a present value sum of $107 trillion. In the Carper International case, the percentage change is projected to fall between -0.05 and -0.06 percent of aggregate output. In dollar terms, this amounts to a change in cumulative real GDP of -$135 billion, with a present value change of -$60 billion. In the Carper Domestic case, the percentage change is projected to be -0.05 percent of aggregate output, with the dollar change in cumulative real GDP being -$134 billion, and the present value change is -$58 billion. The percent change in aggregate output in the Inhofe cases is projected to be -0.03 percent, while the cumulative change in real GDP is -$73 billion and the present value change is -$36 billion.

The loss in economic output has an impact on employment. Figure 36 shows the average annual loss in jobs between 2009 and 2025. Total nonfarm employment is projected to be reduced by an annual average 272 thousand (0.17 percent) in the Jeffords bill, by 46 thousand (0.03 percent) in the Carper International case, by 43 thousand (0.03 percent) in the Carper Domestic case, and by 22 thousand (0.01 percent) in the Inhofe bill. For the manufacturing sector, the projected losses are 154 thousand (1.0 percent), 23 thousand (0.14 percent), 15 thousand (0.1 percent), and 8 thousand (0.05 percent), respectively.

Employment is expected to be particularly impacted in the coal industry. Between 1978 and 2002, the number of workers employed at U.S. coal mines fell by 4.8 percent per year, declining from 246,000 to 75,000. The decrease primarily reflected strong growth in labor productivity, which increased at an annual rate of 5.8 percent over the same period. An additional factor contributing to the employment decline was the increased output from large surface mines in the Powder River Basin (Wyoming and Montana), which require much less labor per ton of output than mines located in the Interior and Appalachian regions.

In the reference case, productivity improvements are assumed to continue in most regions of the country, but at a considerably slower pace. Different rates of improvement are assumed by region and by mine type, surface and underground. On a national basis, coal mining labor productivity in the reference case increases at an average rate of 1.3 percent per year over the forecast horizon.

In the reference case, the expectation that the rate of productivity improvements will slow over the forecast horizon combined with projections of continuing increases in coal production lead to a relatively stable outlook for U.S. coal mine employment. In this case, coal industry employment is projected to remain near current levels of 75,000 through 2020, increasing slightly thereafter to 78,000 by 2025 as increases in production outpace expected improvements in productivity (Figure 37).

In both the Carper and Jeffords cases, lower levels of coal production relative to the reference case result in lower coal industry employment. In the Carper Domestic case, coal mine employment is projected to decline by 0.6 percent per year, falling from 75,000 in 2002 to 66,000 by 2025. Due to the increased availability of greenhouse gas offsets in the Carper International case, a slightly smaller decline in employment is projected in this case than in the Carper Domestic case, where a larger falloff in coal production is projected. In the Jeffords case, a considerably more restrictive cap on CO₂ emissions, relative to the Carper cases, results in higher greenhouse gas emission allowance prices, and, subsequently, lower levels of coal production and employment. In this case, coal mine employment is projected to decline by 2.5 percent per year, falling from 75,000 in 2002 to 43,000 by 2025. Relative to the reference case, U.S. coal mine employment in 2025 is projected to be reduced by 12,000 in the Carper Domestic case, by 10,000 in the Carper International case, and by 36,000 in the Jeffords case. In the Inhofe case, U.S. coal mine employment is projected to be only slightly lower than projected in the reference case.

Oil and gas extraction jobs generally track the number of oil and gas wells drilled. With the exception of the Jeffords case, domestic crude oil and natural gas production and drilling closely track the pattern and levels in the reference case. As a result, the difference in employment in the oil and gas extraction industry for the Carper and Inhofe cases ranges from 2,900 additional to 2,700 fewer jobs than the reference case in any year. Cumulatively from 2003 through 2025, the number of oil and gas extraction job-years is higher than in the reference case by 7,000 job-years (0.09 percent) in the Inhofe case; 16,000 job-years (0.2 percent) in the Carper International case; 21,000 job-years (0.3 percent) in the Carper Domestic case; and 80,000 job-years (1.0 percent) in the Jeffords case.

In the Jeffords case, from 2009 through 2015, oil and gas wells, and therefore jobs, are notably higher than in the reference case in response to a relatively short surge in prices. The increase is greatest in 2010 at 30,000 jobs. The increased drilling activity allows for notably higher production levels in the 2011 to 2018 time frame. However, by 2017 and through the end of the forecast period, the number of oil and gas extraction jobs in the Jeffords case is lower than the reference case by at most 12,000 jobs due to alternative generation technologies, including renewables and nuclear, competing with natural gas for the generation market.

Though difficult to quantify, increased employment in the renewable fuels industry is expected to occur in response to policies to reduce power sector emissions of NO_x, SO₂, Hg, and, particularly, CO₂. In the Inhofe case, the change would likely be small because the increase in renewable generation relative to the reference case is not large. In the Carper and Jeffords cases the impacts would be larger. However, most renewables, including geothermal, hydroelectric, landfill gas, solar, and wind for example, are not supported by continuous renewable energy extraction industries which tend to be labor intensive. Only biomass involves notable labor in energy production, such as for energy crops or for separating, preparing, and transporting various agricultural and forest wastes. Also, employment declines at retiring coal plants will be at least partially offset by growing employment at the natural gas, renewable and, in the Jeffords case, nuclear plants that are added.

Notes and Sources