2. Energy Market Impacts of Reduction Greenhouse Gas Emissions
Greenhouse Gas Emissions and Permit Prices
This section discusses the modeling results simulating the effects of S. 280 and compares
those results to a policy-neutral reference case. The availability and cost of international
emissions offsets is a potential source of low-cost emission reductions, but also a
significant source of uncertainty. To highlight this uncertainty, the results throughout this
section frame the S. 280 Core case with two alternative cases that provide bounds on
international offset availability. The Fixed 30 Percent Offsets case assumes a sufficient
supply of international offsets is available to supplement domestic offsets such that the
30-percent limit is used in all years, while the No International case allows only domestic
offsets. Results of other sensitivity cases are also discussed to a lesser extent to illustrate
effects of other key factors. A full set of tables for all cases is available on the EIA web
site. Table 13 summarizes key results of the three main policy cases with a comparison
to the reference case.
Greenhouse Gas Emissions
Under S. 280, covered entities will reduce their GHG emissions to levels governed by the quantity of allowances issued each year, the availability and limits on offsets, and the economics of holding allowances for future use. Figure 4 compares projections of covered emissions in the reference case and the S. 280 Core case, relative to the
emissions cap. Because entities can meet up to 30 percent of the allowance obligation with offsets, the graph also depicts the projected offsets purchased, along with the covered emissions net of offsets for comparison to the cap.
As indicated in Figure 4, covered emissions net of offsets are projected to match the S. 280 cap from 2012 to 2015. Beginning in 2016, covered emissions less offsets in the S. 280 Core case are below the cap, and a bank of allowances accumulates prior to the 2020 emissions cap reduction. A second, more gradual period of allowance accumulation
starts in 2025 in advance of the cap reduction in 2030. Because the modeling horizon
ends in 2030, an allowance bank balance in 2030 was estimated that would be sufficient to cover post-2030 withdrawals. As a result, cumulative emissions net of offsets through 2030 are projected to be somewhat lower than strictly required over that period. Because of the use of offsets, actual covered emissions in the S. 280 Core case only fall slightly below their 2005 level by 2030.
The 30-percent offset limit becomes binding in the S. 280 Core case in 2020, when the reduction in the emission cap also cuts the allowable level of offsets in absolute terms. From 2020 to 2030, offsets remain at 30 percent of the allowance cap, with the absolute level of offsets dropping in 2030 when the emissions cap is reduced again.
The patterns of emissions and allowance banking depend greatly on the assumed
availability of international offsets. Projected emissions in the Fixed 30 Percent Offsets case and the No International cases are compared to those in the S. 280 Core case in Figure 5, and the patterns of allowance bank accumulation are shown in Figure 6. In the Fixed 30 Percent Offsets case, covered emissions net of offsets remain lower than the S. 280 Core case through 2019 and a large balance of allowances accumulates. The large bank build-up allows post-2020 emissions to remain correspondingly higher, and most of that bank balance is depleted over the next 11 years.
In contrast, relatively little allowance banking is undertaken in the No International case. Without international offsets, greater reductions in domestic energy-related CO2 are
needed to meet the emissions caps from 2012 to 2020. With a more significant early
investment in carbon-neutral technologies required through 2020, allowances prices rise sooner. After 2020, the emission caps can be met for a few years without driving up
allowance prices enough to induce allowance banking. Once allowance prices resume an 8-percent growth, a relatively small allowance balance begins to accrue in 2026, and by 2030 a balance builds up sufficiently high to supply the expected post-2030 withdrawals. The estimated ending balances for these three cases differ to account for the variation in allowance withdrawals in 2030.
Compliance with the S. 280 cap-and-trade program is expected to result in substantial covered emissions reductions, both from CO2 and other GHG emissions. Under the offset provisions, emission reductions from non-covered entities also occur, together with increases in biogenic carbon sequestration from domestic forestry and agriculture, and credited decreases in emissions abroad. As seen in Figure 7, emissions reductions from CO2 account for less than half of the total compliance response in the initial phase of the program, when lower cost offsets and non-CO2 abatement opportunities predominate. The CO2 share of compliance measures increases over time with more stringent reduction requirements and with greater turnover of electric power plants, energy-using equipment,
vehicles, and appliances. This growing contribution of CO2 reductions occurs in the other policy cases as well, but the degree of response and the relative share of offsets used in the compliance response differs among the cases (Figures 8 and 9).
In the Fixed 30 Percent Offsets case, the role of international offsets plays a much greater
role than in the S. 280 Core case from 2012 to 2020, and incentives to bank allowances
promote a much greater overall response over that time frame. In the No International
case, overall emission reductions are higher than in other two cases in the second phase
of the program, as are the CO2 reductions. The greater emissions reductions arise as the
allowance prices are driven higher in the No International case, and with less
accumulation of banked allowances, emissions reductions are deferred to the end of
projection horizon. Among the additional sensitivity cases examined, the compliance measures taken in the Unlimited Offset case are noteworthy (Figure 10). With no limit on offsets, a much greater use of international offsets can be used to comply after 2020 compared with the S. 280 Core case, where the offset limit is binding beginning in 2020. In 2025, the developing countries are assumed to adopt national cap-and-trade policies, and by assumption, this allows their excess CO2 reductions to enter world markets as tradable allowances, without the marketability and acceptance restrictions that arise with CDM-type reduction projects. With unlimited offsets allowed, covered entities in the United
States could then increase their use of international offsets beginning in 2025 to take
advantage of the availability of tradable allowances entering the market from developing countries. While the purchase of domestic offsets increases somewhat in the unlimited offset case compared to the S. 280 Core case, the main impact is to increase international offset purchases.
In the energy markets, the electric power sector accounts for the vast majority of the CO2 emissions reductions (Figure 11). This occurs because of fuel switching within the sector and reduced electricity consumption as consumers and business react to the higher
electricity prices and take advantage of technology rebates available from the S. 280
technology deployment programs. Since the residential and commercial sectors are not covered, direct CO2 emission in those sectors change very little. Transportation and
industrial sector CO2 emissions fall modestly in the main S. 280 cases in response to
energy price changes as well as impacts on economic activity, particularly in the
industrial output of energy-intensive manufacturing industries. These impacts will be discussed in greater detail in subsequent sections.
Allowance Prices
Under S. 280, a market for the tradable allowances will develop, with the potential supply of allowances in any given year including those auctioned by the CCCC, as well as allowances allocated for free and those allowances held from prior years. For this
analysis, a single, annual market price for allowances is assumed, but the combination of government auctions and private trading would likely result in variations in allowance pricing. A related market for offsets is also assumed to develop for trade in emission reductions credits from non-covered entities, carbon sequestration credits, and
international allowances and credits.
The markets for the allowances and offsets will establish price signals to influence emissions-related decisions by covered and non-covered entities. Reducing emissions may require investment in more energy-efficient technology or equipment using alternative fuels, and current and expected allowance prices will affect what investments are undertaken. In a competitive allowance market, the allowance price will tend to reflect the marginal cost of reducing emissions across all covered sectors.
Allowance prices will be reflected in fossil fuel prices either directly, as in the
transportation sector where petroleum suppliers will pass on allowance costs in the prices they charge, or indirectly, as opportunity costs of using fossil fuels subject to allowance requirements. Because allowances can be sold or held for future use, covered entities
will have an incentive to reduce emissions even if they are allocated sufficient allowances to cover their annual emissions. Electricity prices will also adjust to account for
allowance costs as well as the capital and operating cost implications of various
compliance measures.
The ability to sell or hold allowances for the future is expected to promote a gradual escalation in allowance prices. Investors will tend to equate the current value of an allowance to the present discounted value of an allowance in the future. For this analysis, a real discount rate of 8 percent was assumed. As a result, allowance prices are assumed to escalate annually at a maximum rate of 8 percent. In reality, allowance prices would fluctuate around some long-term trend in reaction to imperfect information and
unanticipated events, as do prices of other commodities.
Figure 12 plots the projected allowance and offset prices in the S. 280 Core case. The
allowance and offset markets are projected to clear at the same price through 2019, a
period in which the use of offsets remains below the 30-percent limit. Beginning in
2020, when the lower emissions cap reduces the allowable level of offsets, the 30-percent
limit on offsets becomes a binding constraint. In this situation, competition to supply a
fixed quantity of offsets will tend to drive down the offset price below the domestic
allowance price.
Allowance prices in the three main policy cases are compared in Figure 13. Allowance
prices in the No International case are driven higher than in the S. 280 Core case by the
need to meet emissions goals solely from domestic sources. Allowance prices moderate
for a short period beginning in 2022 in the No International case, before resuming an 8
percent growth over the rest of projection. Lower allowance prices in the Fixed 30
Percent Offsets case reflect the optimistic supply assumptions regarding international
offsets and a greater reliance on allowance banking than in the other cases to control
compliance costs.
The projected allowance prices vary in response to several other key assumptions. Figure 14 presents estimated allowances prices in the alternative policy cases. A key assumption that determines the maximum escalation rate of allowance prices is the assumed discount rate for allowance banking. The Low Discount rate case assumes a 4-percent discount
rate, compared to the 8-percent rate in the S. 280 Core case.17 A lower discount rate
leads to higher allowance prices in the initial phase of the allowance program from
2012to 2020 than in the S. 280 Core case and lower prices after 2020. With higher
allowance prices initially, covered entities have a greater incentive to over-comply and
build up allowance deposits, then later make greater use of the banked allowance in the
second phase of the program.
Allowance prices in the Unlimited Offset case are the lowest among the cases considered. Unlike in the other cases, relatively little allowance banking is generated in the Unlimited Offset case, at least in the initial compliance phase. While allowance prices are driven up to meet the more stringent cap in 2020, allowance prices drop after 2021 as relatively cheap international offsets supply much of the compliance requirements. The allowance prices begin growing after 2025 and a substantial allowance bank balance is built up through continued rapid growth in international offsets.
Somewhat higher allowance prices are projected in the No Nuclear case compared to the S. 280 Core case. Without additional nuclear generation as an option, complying with the emissions caps requires higher allowance prices to stimulate greater use of offsets and renewable sources and adoption of carbon capture and storage technologies. Carbon reductions by sector are discussed in more detail in the sections that follow.
Primary Energy Impacts
Energy consumers are expected to face higher effective costs of using energy as a result of the bill’s allowance program. In the transportation sector, end-use consumers will face higher delivered prices of refined products, because refiners must obtain allowances for the GHG emissions associated with petroleum-based fuels sold for transportation. The cost of the allowances will be included in prices of the fuels. Covered entities in the commercial,18 industrial, and electric power sectors will implicitly face a higher cost of consuming fossil energy, because they will be required to obtain allowances for the CO2 emitted in direct fuel use. To the extent that electricity generators can pass through the opportunity cost of allowances and related incremental capital costs to their customers, electricity prices will increase in all consuming sectors. The increased energy costs, whether incorporated directly in delivered prices or reflected implicitly as the emissions related opportunity costs of consuming energy, will affect all energy sectors of the
economy. To simplify discussion of energy costs, the delivered prices of energy discussed in this chapter represent the effective delivered cost of using energy, including the direct and indirect costs of emissions allowances as applicable to a given sector.19
Table 13 presents a summary of the effects of S, 280 on energy prices and energy
consumption across the main S. 280 policy cases. By 2030, the overall mix of fuels consumed in the S. 280 Core case differs significantly from the reference case (Figure 15). Consumption of coal, liquid fuels (mainly petroleum), and natural gas all decline relative to the reference case, while the use of nuclear power and renewable energy increase. Total energy consumption in 2030 in the S. 280 Core case is 3 percent lower than the reference case in 2020 and 6 percent lower in 2030, as conservation and
improvements in energy efficiency are induced. Overall, projected liquid fuels and natural gas consumption in 2030 in the S. 280 Core case is higher than present levels, and the consumption of liquid fuels continues to grow throughout the projection.
Electricity Sector Emissions, Generation, and Prices
Implementing the proposed GHG emissions reduction program would have significant impacts on power sector CO2 emissions, generation by fuel, generating technology selection, electricity sales, and electricity prices. The power sector shifts away from its long-term reliance on coal-fired generation, towards increasing reliance on nuclear, nonhydroelectric renewable, and natural gas generation. These changes lead to lower emissions but, the increased capital expenditures for these technologies, together with higher fossil fuel prices 20, result in higher electricity prices. The magnitude of the changes in the power sector are sensitive to the GHG allowance price, with higher prices leading to larger reduction in coal use and increased use of nuclear, renewable, and, to a lesser extent, fossil technologies with carbon capture and storage (CCS) equipment.
CO2 Emissions
In the reference case, power sector CO2 emissions are projected to increase 40 percent between 2005 and 2030 as the industry increases its use of fossil fuels, particularly coal (Figure 16). In the main S. 280 cases,21 power sector CO2 emissions are expected to be 17 percent to 32 percent below the reference case level in 2020 and 37 percent to 78 percent below the reference case level in 2030. In the S. 280 Core case, CO2 emissions are forecast to decrease by 49 percent between 2005 and 2030, due to a greater reliance on nuclear and renewable generation and a less carbon-intensive fossil fuel mix.
Generation by Fuel
To reduce its CO2 emissions, the power industry, including generators in the industrial
and commercial sectors, is expected to shift away from its historical reliance on coal
generation (Figure 17). Coal generation in 2030 in the main S. 280 cases is below current
levels, ranging from 7 percent below in the Fixed 30 Percent Offsets case to 70 percent
lower in the No International case. Coal generation in the S. 280 Core case is 26 percent
below the reference case level in 2020 and 69 percent lower in 2030, a reduction of 2,295
billion kilowatthours. Relative to the 2005 level, coal generation in the S. 280 Core case
is 48 percent lower in 2030. In the reference case, coal accounts for 58 percent of total
generation in 2030, but its share falls to between 11 percent and 35 percent in the main
S. 280 cases.
The higher coal costs in the main S. 280 cases greatly influence the relative economics of new generating plants. In the reference case, 163 gigawatts of new coal capacity are projected to be added between 2005 and 2030. In the main S. 280 cases, new coal additions are between 16 and 21 gigawatts through 2030 and most of these are already under construction. In the No International case, which has the highest allowance price, 11 gigawatts of coal with carbon capture and sequestration are projected to be built, but
in the other cases, the allowance prices are not generally high enough to compensate for
the additional capital and operating expenses of this technology, and it is less competitive
against other low-carbon technologies, such as nuclear and various renewables. The
higher coal costs also affect retirement decisions across the cases. In the Fixed 30 Percent
Offsets case, most existing coal capacity remains on-line, although operating at lower
levels, but in the S. 280 Core case nearly one-third of existing coal capacity is projected
to be retired, and coal retirements in the No International case are more than one-half of
existing capacity.
In contrast to the situation for coal generation, nuclear generation is projected to increase significantly in the main S. 280 cases. In the reference case, nuclear generation is
projected to increase by 89 billion kilowatthours (11 percent) from 2005 to 2030, as
existing plants are upgraded by 3 gigawatts and 9 gigawatts of new capacity, partially
stimulated by incentives in the Energy Policy Act of 2005 (EPACT2005), are added. The 145 gigawatts of nuclear capacity added in the S. 280 Core case increases nuclear
generation to 1,909 billion kilowatthours in 2030, 120 percent above the reference case level in 2030. Across the main S. 280 cases, nuclear generation in 2030 provides from 22 percent to 42 percent of total electricity generation, much greater than the 15 percent
provided in the reference case.
Renewable generation is also expected to see significant growth in the main S. 280 cases. In the reference case, renewable generation is projected to increase by 191 billion
kilowatthours (54 percent) between 2005 and 2030. Part of this growth is stimulated by tax incentives for certain renewable technologies in EPACT2005. The renewable share of total generation in 2030 is 9 percent in the reference case, and grows to between 24
percent and 31 percent across the main S. 280 cases. Growth occurs mainly in new
biomass capacity and increased biomass co-firing in coal plants, as well as new wind capacity additions. In the reference case, biomass generation grows from 38 billion
kilowatthours in 2005 to 111 billion kilowatthours in 2020 and 131 billion kilowatthours in 2030. In the S. 280 Core case, biomass generation in 2020 is over three times that of the reference case, and by 2030 is almost 8 times greater than the reference level.
Following a similar pattern, wind generation grows from 15 billion kilowatthours in 2005 to 51 billion kilowatthours in 2020 and remains at that level through 2030 in the
reference case. In the S. 280 Core case, wind generation in 2020 is more than double that of the reference case, and by 2030 is 2.5 times greater than the reference level.
Oil and natural gas generation are also impacted by efforts to reduce power sector GHG emissions, but to lesser degrees than coal, nuclear, and renewables. Oil generation,
already a very small part of the electricity market, falls even further in the main S. 280 cases. Natural gas impacts depend on the level of the carbon allowance fee. In the Fixed 30 Percent Offsets case, natural gas generation in 2030 is 6 percent above that of the
reference case, as new natural-gas-fired combined-cycle plants replace some of the coal builds in the reference case. In the S. 280 Core and No International cases the allowance price is higher than in the Fixed 30 Percent Offsets case and even new natural-gas-fired generation is no longer attractive, and new builds are primarily nuclear or renewable
technologies. In these two cases, natural gas generation in 2030 is 12 percent to 13
percent lower than the reference case level.
Electricity Prices
The shift away from coal to increased use of nuclear and renewable fuels, together with the costs of holding emissions permits, affects electricity prices (Figure 18). In the
reference case, average delivered electricity prices fall from 8.1 cents per kilowatthour in 2005 to 7.7 cents per kilowatthour in 2015, then rise gradually as fuel prices rise,
reaching 7.9 cents per kilowatthour in 2020 and 8.0 cents per kilowatthour in 2030.
Electricity prices across the main S. 280 cases are 6 percent to 14 percent higher than the reference in 2020 and 16 percent to 25 percent higher in 2030 as the allowance prices rises throughout the forecast. Consumers’ total electricity bills in 2020 in the S280 Core case are $18 billion (5 percent) higher than in the reference case, with a range of 2
percent higher in the Fixed 30 Percent Offsets case to 8 percent higher in the No
International case. By 2030, the increase in consumer bills above the reference case
ranges from $33 billion (8 percent) to $75 billion (18 percent).
The different regulatory regimes in the various regions of the country do affect the electricity prices in the main S. 280 cases, due to the initial allocation of allowances. It is assumed that 70 percent of allowances are allocated to the covered sectors in 2012, but this share is reduced over time to just 10 percent allocated in 2030. In regulated regions, it is assumed that the value of allowances will be passed on to consumers, so the price increases are not as great, relative to unregulated regions, where the value of allowances is assumed to accrue to stockholders. However, as more allowances are auctioned off throughout the forecast, the regulated regions see more significant price increases as well.
End-Use Energy Consumption
In response to higher delivered fossil fuel and electricity prices in the main S. 280 cases, consumers and businesses in all sectors of the economy are projected to reduce their energy consumption and, where possible, shift their consumption away from fossil fuels. These changes reduce overall energy consumption, but raise consumers’ energy bills.
Residential and Commercial
Higher electricity prices under the proposed GHG cap and trade program, combined with greater adoption of more efficient technologies, reduce the use of electricity in the residential and commercial sectors. Residential electricity use is between 5 percent and 6 percent lower in 2020 and between 10 percent and 11 percent lower in 2030 in the main
S. 280 cases than in the reference case (Figure 19). Residential total delivered energy
use22 in the main S. 280 cases is lower by a smaller amount, 3 percent in 2020 and 6
percent in 2030. The changes in the commercial sector mirror those of the residential
sector. When compared to the reference case, electricity use in the main S. 280 cases
shows the largest change, ranging from 3 percent to 4 percent lower in 2020 and between 7 percent and 8 percent lower in 2030. Relative to the reference case, overall delivered energy consumption in the main S. 280 cases is 2 percent lower in 2020 and from 3
percent to 4 percent lower in 2030 (Figure 20). In both sectors, the consumption of fuels other than electricity change very little because emissions associated with their use are
not covered by the program.
With the exception of electricity, the price of fuels to residential and commercial consumers falls in the main S. 280 cases, relative to the reference case because these consumers do not have to submit allowances for their emissions. In the No International case, electricity prices in the residential sector are 12 percent higher in 2020 and 22 percent higher in 2030, relative to the reference case. Natural gas prices, on the other hand, are 2 percent lower in 2020 and 3 percent lower in 2030, when compared to the reference case. In 2020, overall residential energy expenditures range from 1 percent ($18 per household) lower in the Fixed 30 Percent Offsets case to 2 percent ($36 per household) higher in the No International case, relative to the reference case. However, by 2030 the rising allowance prices in the main S. 280 cases leads to higher residential energy costs in all of the cases. In 2030, residential energy expenditures in the main S. 280 cases, range from 1 percent ($26 per household) higher in the Fixed 30 Percent Offsets case to 4 percent ($78 per household) higher in the No International case.
The price changes in the main S. 280 cases in the commercial sector are similar to those found in the residential sector, but the range is wider. Relative to the reference case,
electricity prices to the commercial sector in the main S. 280 cases are projected to be between 7 percent and 15 percent higher in 2020 and between 17 percent and 25 percent higher in 2030. Natural gas prices to the commercial sector, on the other hand, are
between 1 percent and 3 percent lower in 2020 and between 1 percent and 4 percent
lower in 2030 in the main S. 280 cases, when compared to the reference case. The
change in relative prices brings about an increase in investment in natural-gas-fired
combined heat and power plants (CHP) in the commercial sector. Natural-gas-fired CHP capacity is between 3 percent and 16 percent higher in 2020 and between 31 percent and 267 percent higher in 2030, as relative prices for on-site generation of electricity become increasingly favorable in the main S. 280 cases.23
The use of renewable energy sources in the end-use sectors is expected to increase in the main S. 280 cases relative to the reference case. In the residential sector, the market share of ground-source (geothermal) heat pumps more than quadruples by 2030, reaching 3 percent of the residential heating market in the S. 280 Core case, much larger than the 0.6 percent share reached in the reference case. Commercial sector photovoltaic (PV) system capacity is 211 percent to 276 percent higher by 2030 in the main S. 280 cases while residential rooftop PV units are 42 percent to 94 percent higher, further reducing the need for grid-supplied electricity in both sectors.
Industrial
As in the buildings sector, higher energy prices caused by the GHG reduction program lead industrial consumers to reduce their energy use, particularly their use of coal. In the main S. 280 cases, total industrial sector energy consumption in 2020 is projected to be 0.5 quadrillion to 0.8 quadrillion Btu (2 percent to 3 percent) lower than in the reference
case. By 2030 the difference grows to 1.6 quadrillion to 2.2 quadrillion Btu (5 percent to
7 percent) lower.24 The vast majority of this difference is seen in industrial coal
consumption which is 11 percent to 16 percent lower in 2020 and 38 percent to 41
percent lower in 2030 in the main S. 280 cases than in the reference case (Figure 21).
Purchased electricity is also noticeably lower in the main S. 280 cases because industrial
consumers increase their use of self-generation. The increased use of natural gas for self
generation nearly offsets the reduction in natural gas consumption for other uses. As a
result, there is little change in total industrial sector natural gas use in the main S. 280
cases.
The change in energy consumption varies noticeably by case across industries in the industrial sector. Coal use declines sharply in refining due to the elimination of coal-to-liquids in the GHG constrained cases. By contrast, coal use is projected to grow rapidly in the reference case in the later years of the projection when coal-to-liquids plants are introduced. In the reference case, 434 thousand barrels per day of liquids are produced from coal in 2030. In the main S. 280 cases, none is produced. Since agriculture and construction are not required to purchase GHG permits, they incur lower energy prices and increase energy consumption slightly in the S. 280 cases.
Projected energy prices increase primarily due to the GHG fee that results from the
emissions cap and trade program. The price increases are generally in line with the
carbon content of various fuels. Consequently, coal prices increase more rapidly tha n do other industrial energy prices. In 2020, industrial coal prices are 59 percent to 126
percent higher in the main S. 280 cases than in the reference case. By 2030, industr ial coal price increases ranged from 119 percent to 217 percent higher in the main S. 280 cases than in the reference case. In comparison, in 2020 industrial natural gas prices ar e 11 percent to 23 percent higher than the reference case. By 2030, industrial natural prices ranged between 24 percent and 41 percent higher than in the reference case.
Industrial sector energy expenditures increase sharply as a result of the higher energy prices. In the reference case, industrial sector energy expenditures in 2020 are projecte d to be $195 billion (2005 dollars). In the main S. 280 cases, energy expenditures increase by $13 billion to $26 billion (7 percent to 14 percent). In 2030, industrial energy
expenditures in the main S. 280 cases increase by $32 billion to $50 billion (14 percent to 22 percent) compared to the reference case.
Industrial combustion-related CO2 emissions in the reference case grow from 1,682 million metric tons in 2005 to 1,810 million metric tons in 2020 and 2,021 million metric tons in 2030. In the main S. 280 cases, industrial sector CO2 emissions are 133 million metric tons to 263 million metric tons lower (7 percent to 15 percent) in 2020 and 390 million metric tons to 744 million metric tons lower (19 percent to 37 percent) in 2030.
In dustrial output is reduced significantly across all affected sectors (agriculture and
construction are not covered sectors for this analysis). The coal mining industry and
energy-intensive manufacturing industries are the most adversely affected subsectors
(Figure 22):
- In 2020, total industrial output is $49 billion to $137 billion (2000 dollars)25 (1 percent to 2 percent) lower in the main S. 280 cases than in the reference case. In 2030, industrial output is $161 billion to $321 billion lower (2 percent to 3 percent) than in the reference case.
- The coal mining industry experiences the most severe fall in output, ranging from 17
percent to 32 percent lower than the reference case in 2020 and from 40 percent to 74
percent lower in 2030.
- Among the manufacturing industries in 2020, the aluminum industry’s output has the
largest reductions, 5 percent to 12 percent in 2020 and 13 percent to 22 percent in
2030, compared to the reference case.
- Output of the steel industry is 3 percent to 7 percent lower than in the reference case in 2020 and 6 to 13 percent lower in 2030.
- Glass, cement, and bulk chemicals experience output reductions of between 4 percent and 10 percent in the main S. 280 cases in 2030.
Higher energy prices and reduced output have impacts on industrial employment (Figure
23). The employment impacts parallel the output impacts discussed above. The coal
industry experiences the sharpest fall in employment followed by energy-intensive
manufacturing industries. In the main S. 280 cases, total industrial employment is 105
thousand to 293 thousand lower (1 percent) in 2020 and 250 thousand to 529 thousand
lower (1 percent to 2 percent) in 2030 than in the reference case (Figure 23). While the
largest percentage fall among the manufacturing sectors occurs in the energy-intensive
industries (cement, glass, steel, and aluminum), the largest reductions in the number of
employees are in the transportation equipment (37 thousand to 70 thousand), machinery
(29 thousand to 69 thousand), and fabricated metals (21 thousand to 56 thousand)
industries.
Potential impacts on carbon-intensive industries: cement and lime production
A program to reduce GHG emissions would have the largest impacts on industries whose production processes are most carbon intensive—industries like the cement industry. The U.S. cement industry produced a record 99.3 million metric tons of cement and imported a record 30.4 million metric tons in 2005.26 The share of U.S. cement consumption met by imports grew to 23 percent in 2005, continuing a trend of increasing imports that has been apparent for at least 10 years. Canada accounted for 16 percent of U.S. cement imports in 2005, while China accounted for 14 percent.
The cement industry is one of the largest producers of process-related CO2 emissions due to the baking of limestone to produce clinker, an intermediate product in cement production. Production of 1 metric ton of cement produces approximately 0.5 metric tons of CO2.27 In 2005, the U.S. cement industry produced an estimated 46 million metric
tons of CO2, 62 percent of total industrial process emissions of CO2.28 In addition, the cement industry’s combustion-related CO2 emissions are estimated to be 40 million
metric tons in 2005, making the total CO2 emissions of the industry nearly 90 million metric tons.
If the U.S. cement industry is required to reduce CO2 emissions but other countries are not, it is probable that the upward trend in cement imports will rise faster. There are few options for the cement industry to reduce process-related emissions. One option, however, is to increase the amount of blended cement production. For example, clinker can be combined with fly ash to produce blended cements. This option is already used extensively for some purposes, e.g., highway construction in California.29
In the main S. 280 cases, U.S. clinker production in 2020 is projected to fall 4 percent to 7 percent, relative to the base case, due to a combination of increased production of
blended cements and increased imports of finished cement. Reference case process
related CO2 emissions and combustion-related emissions30 are projected to be 52 million metric tons and 42 million metric tons, respectively, in 2020. In the main S. 280 cases, in 2020, process-related CO2 emissions are reduced by 2 million metric tons to 4 million
metric tons, and combustion-related CO2 emissions are reduced by 3 million metric tons to 6 million metric tons (Figure 24). In 2030, reference case process-related CO2
emissions are projected to be 57 million metric tons and combustion-related CO2
emissions are projected to be 44 million metric tons. In the main S. 280 cases, U.S.
clinker production in 2030 is 10 percent to 13 percent lower than in the reference case
while process-related CO2 emissions are 5 million metric tons to 7 million metric tons
lower (10 percent to 13 percent) and combustion-related CO2 emissions are 7 to 13
million metric tons lower (17 percent to 30 percent). The fall in cement industry CO2
emissions is due to the combined effects of increased blending and imports, increased
energy efficiency, and reduced industry output.
The lime production industry is the second largest producer of process-related CO2
emissions. In a process similar to cement clinker production, limestone is heated in a kiln to drive off the carbon to create lime. While there are energy efficiency improvements that could be undertaken in the lime production process, lime production inherently produces carbon dioxide. In 2005, the lime production industry’s process-related CO2 emissions were 15.7 million metric tons of CO2, second only to the cement industry. 31 Lime is used in many manufacturing industries as well as in construction and a variety of environmental-related uses, such as flue-gas desulfurization.32 While the lime
manufacturing industry does not presently encounter appreciable import competition, the advent of a GHG fees will have an adverse impact on the manufacturing industries that use lime in their production processes. As a result, process-related CO2 emissions from lime manufacturing in 2030 are projected to fall by 1 million metric tons (4 percent) to 21.9 million metric tons in the S. 280 Core case.
Transportation
Similar to the other demand sectors, the transportation sector also reduces energy consumption under the GHG cap and trade proposal (Figure 25). Relative to the reference case, reductions in transportation energy demand in the main S. 280 cases are projected to range between 1 percent and 2 percent in 2020 and 3 percent and 5 percent in 2030, with the greatest reductions occurring in the No International case. Because the
GHG cap and trade proposal does not directly impact the transportation sector, reductions in energy demand are driven by consumers’ response to higher fuel prices, reductions in in dustrial output, and reductions in coal shipments.
The higher fuel prices projected in the main S. 280 cases stimulate consumer demand for more efficient vehicles. However, the fuel price increases are not large enough to create dramatic shifts in consumer behavior. Relative to the reference case, the price of motor gasoline in the main S. 280 cases increases from 6 percent to 12 percent ($0.11 and $0.23 per gallon, respectively) in 2020 and from 11 percent to 19 percent ($0.25 and $0.41 per gallon, respectively) in 2030. In 2030, the consumer response to higher fuel prices driv es a market shift in new vehicle sales from light trucks to cars in the S. 280 cases. In the
reference case, 2030 car sales account for 44 percent of new light-duty vehicle sales. In the main S.280 cases, the percent of new vehicles sold in 2030 that are cars increases to between 47 percent and 49 percent. In addition to the shift in vehicle sales, increased
sales of hybrid and diesel vehicles, as well as other advanced technologies, results in an overall improvement in new light-duty vehicle fuel economy rangi ng between 2 percent (0 .6 miles per gallon) to 3 percent (1.0 miles per gallon) by 2030.
Lower transportation energy consumption also results from reduced travel in response t o higher fuel prices. In 2020, the reduction in light-duty vehicle miles traveled from the reference case ranges between 29 billion miles (1 percent) to 54 billion miles (2 percent) in the main S. 280 cases. By 2030, the reduction in light duty vehicle travel increases to between 72 billion miles (2 percent) and 114 billion miles (3 percent). Reductions in
freight truck travel are very similar, on a percentage basis, to those projected for light duty vehicles and are due to lower industrial output.
Though energy use by railroads accounts for only a small part of overall transportation energy use, projected growth in railroad shipments is expected to be significantly
impacted by large reductions in the projected growth of coal demand in the main S. 280 cases. Relative to the reference case, 2020 rail ton-miles traveled in the main S. 280 cases are between 154 billion ton-miles (8 percent) and 293 billion ton-miles (15 percent) lower. With a growing reduction over time in coal use relative to the reference case, reductions in rail ton-miles in the main S. 280 cases in 2030 range from 470 billion tonmiles (19 percent) to 884 billion ton-miles (36 percent).
Fuel Supply
Coal
Relative to the reference case, total U.S. coal production in 2020 is projected to be
between 18 percent (235 million tons) and 33 percent (429 million tons) lower in the
main S. 280 cases (Figure 26). By 2030, the gap between the reference and the main
S. 280 cases becomes even larger, with total coal production in these cases projected to
be between 41 percent (697 million tons) and 78 percent (1,313 million tons) less than in
the reference case. Moreover, in 2030, total coal production in these cases is projected to
be between 12 percent (135 million tons) and 66 percent (750 million tons) less than
production in 2005.
The caps on greenhouse gas emissions have a disproportionately larger impact on coal production west of the Mississippi River. This is primarily because this region supplies most of the growing demand for coal projected in the reference case for the electricity
sector and for coal-to-liquids (CTL). In addition, eastern coal mines are the primary
source of supply for the industrial sectors and for export, and the demand for coal in these markets is less affected by constraints on greenhouse gas emissions than is the demand for coal in the electric power sector and for the production of coal-based synthetic
liquids. None of the 15 coal-to-liquids plants built in the reference case are projected to come on line in the main S. 280 cases. In the reference case, coal consumption at CTL plants reaches 109 million tons in 2030.
Reduced demand for coal in the main S. 280 cases is primarily attributable to the allowance cost, which effectively raises the delivered price of coal. In the electricity sector, the delivered price of coal in 2030 in the main S. 280 cases is between 162 percent ($2.75 per million Btu) and 291 percent ($4.93 per million Btu) higher than the price of $1.70 per million Btu projected in the reference case.
Natural Gas
In contrast to coal, the impact on natural gas markets is more modest. S. 280 results in
higher delivered natural gas prices to the industrial and electric power sectors, because of
the costs associated with GHG emissions allowances. The average delivered end-use
natural gas price in 2030 is projected to be between 11 and 18 percent higher than in the
reference case in the main S. 280 cases. In contrast, 2030 wellhead natural gas prices,
which do not include the cost of allowances, are projected to be between 8 to 34 cents per
thousand cubic feet lower (1 to 6 percent) in the S. 280 cases, because the higher
delivered cost of natural gas reduces gas demand, which in turn, reduces wellhead natural
gas prices.
Delivered natural gas prices to residential and commercial consumers are lower in the
S. 280 cases, because these sectors are not covered by the bill’s allowance provisions.
However, these lower natural gas prices do not result in higher residential natural gas
consumption because S. 280 allowance auction revenues are assumed to be deployed by
the CCCC to reduce the cost of energy-efficient appliances by providing rebates for such
appliances. These rebates significantly reduce the cost of energy-efficient appliances,
thereby causing a higher penetration rate of these appliances in the S.280 policy cases
relative to the reference case. Consequently, the CCCC rebate program is projected to
reduce residential natural gas consumption, even though the S. 280 policy results in
slightly lower residential natural gas prices, which would otherwise encourage a higher
consumption of natural gas.
Unlike the residential and commercial sectors, the industrial and electric power sectors face higher delivered natural gas prices. The impact on natural gas consumption in these sectors varies considerably, based on whether there are cheaper alternative fuel sources which can be deployed and/or the degree to which energy efficiency improvements are employed to reduce the overall cost of using fossil fuels. Although the delivered cost of natural gas is projected to increase substantially in the main S. 280 cases, there are few lower cost substitutes for natural gas in the industrial sector. Much of the natural gas
consumed in the industrial sector is used for chemical and refining feedstocks and for
direct-heat applications where the avoidance of product contamination is critical.
In contrast, natural gas consumption in the electric power sector is projected to be
between 0.3 to 1.0 trillion cubic feet (4 to 15 percent) lower in the in the main S. 280
cases in 2020, than in the reference case. By 2030 this difference grows to between 0.5 and 1.7 trillion cubic feet (8 and 29 percent).
Overall natural gas consumption in the main S. 280 cases is between 0.6 and 1.3 trillion cubic feet (2 and 5 percent) lower in 2020, than in the reference case. By 2030 this difference grows to between 0.7 and 2.0 trillion cubic feet (3 and 8 percent).
Liquid Fuels and Other Petroleum Products
Similar to the situation for natural gas, the consumption of liquid fuels and other
petroleum products is somewhat lower in the main S. 280 cases than it is in the reference
case, as consumers respond to the higher delivered product prices that result from cost of
allowances under S. 280. Liquid fuels consumption in 2020 ranges from 0.5 to 0.8
million barrels per day (2 to 3 percent) lower in the main S. 280 cases. By 2030 the
difference grows to between 1.0 and 1.6 million barrels per day (4 and 6 percent).
However, domestic crude oil production is relatively unaffected because the world crude
oil prices are assumed to be unchanged. The reduction in petroleum supply comes from
reductions in imports and reductions in domestic CTL production. In the main S. 280
cases, CTL production is no longer economical, removing 70 thousand barrels per day, or
1 percent, of distillate production relative to the reference case in 2020. By 2030, the
change is 0.4 million barrels per day, or 7 percent. The cost of allowances increases the
cost of using coal, making CTL production much less competitive with imported and
domestic oil.
Economic Impacts
Implementing a GHG emissions cap and trade program to reduce GHG emissions will have impacts on the economy through multiple mechanisms. First, efforts to reduce GHG emissions and the requirement to hold permits for all remaining GHG emissions will raise energy prices, particularly those for fossil fuels. Second, the auctioning of permits will generate revenues for the government, which, through various government programs, will be spent by businesses and consumers to reduce their emissions or help ameliorate the impacts associated with higher energy prices.
The variation in aggregate GDP impacts among the main S. 280 cases can be traced
primarily to the different energy price impacts in each case. The changes in energy prices are the dominate factor affecting the economy under S. 280. For example, in the S. 280 Core case, higher energy prices between 2010 and 2030 contribute to cumulative GDP
losses of $577 billion (discounted present value)33. Revenue recycling alone increases
cumulative GDP by $126 billion, and buying international offsets alone causes a
cumulative GDP loss of $83 billion, for an aggregate net cumulative GDP loss of $533
billion, or 0.22 percent.
Permit Revenues
Projected revenues generated from the allowance program are a function of the market price of the allowances and the number of allowances made available. The value of allowances allocated for free can be considered a revenue transfer in the sense that recipients will accrue revenue from the resale of these allowances or avoid costs by holding the allowances for their own use. For simplicity in the following discussion, allowances allocated for free by the Federal government are treated as a revenue
transfers. All other permits are auctioned and the revenue flows to the CCCC for
disbursement. Table 14 describes the allocation of GHG permits and the associated revenue in the S. 280 Core case. Each of the main S. 280 cases incorporates the
distribution of allowances shown in Table 14.
Figure 27 shows the amount of allowance revenue generated annually in the S. 280 Core case and the shares allocated to each of the programs. By 2029 the total revenue rises to $287 billion, but then falls to $233 billion in 2030 when the emissions cap is lowered, reducing the overall number of allowances allocated and auctioned.
Over time, the largest components of total permit revenue consist of the no-cost
allocation of permits to business, followed closely by the distribution of CCCC funds to
businesses to spur technology deployment. In 2012, the total flow of funds to business
makes up nearly 85 percent of the total amount of allowance related revenues. While the
no-cost-allocation share declines over time, the amount going to CCCC, and therefore, to
technology deployment for business grows. By 2030, business still receives over 50
percent of the total amount of GHG permit-related revenue. Moving out in time, funding
for other CCCC Programs becomes a growing proportion of the total revenue collected.
Consumers receive funds designated for transition and mitigation as well as 10 percent of
the technology deployment funds. The CCCC also funds specific fish and wildlife
projects and numerous other programs that are treated as increased government
expenditures.
Figure 28 shows a comparison of the total value of allowances in the main S. 280 cases. In the No International case, total annual GHG permit-related revenue peaks at $348
billion in 2029, while in the Fixed 30 Percent Offsets case these revenues rise to just
under $200 billion in 2029. The cumulative 2012 through 2030 GHG permit related
revenue in the main S. 280 cases ranges from 1.9 to 3.9 trillion nominal dollars ($1.2 to $2.6 discounted).
The High Auction Case
S. 280 does not specify the share of allowances to be allocated for free or the share to be auctioned off by the CCCC. Senate staff specified that EIA should assume that the
auction share would start at 30 percent in 2012 and grow to 90 percent in 2030.
However, they also requested a sensitivity case, in which the auction share started at 70 percent in 2012 and ramped up linearly to 90 percent in 2030—the same final target as in the main S. 280 cases. In the High Auction case, the difference in the amount of revenue recycled was relatively small, since allowance prices are fairly low in the early years when the auction share was increased. Figure 29 shows the difference in total revenues by destination between the High Auction case and the S. 280 Core case. Relative to the overall policy these changes are fairly small, and the impact on the economy is further muted because there is really little difference economic difference between giving
allowances directly to business or auctioning off allowances and giving the revenue to business to support technology deployment programs. As a result, the change in real GDP in the S. 280 Core and High Auction cases are nearly identical (Figure 30).
Impacts on Energy and Aggregate Prices
Rising energy costs influence the aggregate economy through higher energy expenditures and through higher prices for other goods and services where energy is an input cost. Figure 31 shows the percentage changes in the consumer price index (CPI) for energy and the All-Urban CPI, a measure of aggregate consumer prices in the economy, in the main S. 280 cases. The CPI for energy, a summary measure of energy prices facing households at the retail level, increases by approximately 16 percent above the reference case level by 2030 in the S. 280 Core case. Ultimately the consumer sees higher prices directly through final prices paid for energy related goods and services, and higher prices for other goods and services rise as a result of higher energy price changes and changes in interest rates. Differences in the consumer price impact on the economy in the main S. 280 cases can be traced to the different energy price paths in each of the cases.
Real GDP and Consumption Impacts34
The higher delivered energy prices lower real output for the economy. They reduce energy consumption but also indirectly reduce real consumer spending for other goods and services due to lower purchasing power. The lower aggregate demand for goods and services results in lower real GDP relative to the reference case (Figure 32). Real GDP in 2030 is between 0.3 percent and 0.5 percent lower in 2030 in the main S. 280 cases than in the reference case. Total discounted GDP over the 2009 to 2030 time period is $533 billion (0.22 percent) lower in the S. 280 Core case and ranges from $471 billion (0.19
percent) lower in the Fixed 30 Percent Offsets case to $572 billion (0.23 percent) lower in the No International case. Projected GDP impacts generally increase over time, as the cap-and-trade program requires larger changes in the energy system.
While real GDP is a measure of what the economy produces, the composition of GDP may change considerably between the major components—consumption, investment,
government, and net exports. The bottom line for the consumer is how many goods and services can they purchase—the consumption component of GDP. Figure 33 shows two measures of consumption impacts: the cumulative discounted loss in consumption over the 2009 to 2030 period and the percentage change in consumption compared to the
reference case. The cumulative losses of consumption are $487 billion (0.28 percent) in S. 280 Core case and $538 billion (0.31 percent) and $433 billion (0.25 percent) in the No International and Fixed 30 Percent Offsets cases, respectively. Consumption impacts, like GDP impacts, generally grow over time.
Industrial Output
As energy prices increase, the energy-intensive sectors, including food, paper, bulk chemicals, petroleum refining, glass, cement, steel and aluminum, show greater losses compared to the rest of the industrial sectors, falling 3.5 percent below the reference case level by 2030 in the S. 280 Core case. The left side of Figure 34 depicts impacts by industry in the S. 280 Core case while the right side shows the change in total industrial output in the main S. 280 cases. The industrial sector (all non-service industries) is down
2.5 percent relative to baseline, as higher inflation and lower demand impact industrial activity. The right side of Figure 34 shows industrial sector impacts across the main S. 280 cases with the change in 2030 varying from 1.7 percent to 3.4 percent below the reference case level.
Uncertainty and Limitations
All long-term projections engender considerable uncertainty. It is particularly difficult to
foresee how existing technologies might evolve or what new technologies might emerge
as market conditions change, particularly when those changes are fairly dramatic. Under
S. 280, this analysis finds energy providers, particularly electricity producers, will
increasingly rely on technologies that play a relatively small role today or have not been
built in the United States in many years. Sensitivity analyses suggest that the economic
impacts can change significantly under alternative assumptions regarding the cost and
availability of new technologies. In addition, the cost and availability of offsets outside
of the energy sector, both domestically and internationally, is a significant area of
uncertainty.
This analysis suggests that increasing the use of nuclear and renewable power is an
economical compliance strategy, with nuclear generating capacity more than doubling
over the next 25 years. However, concerns about siting, waste disposal, and project risk
could deter nuclear development. The No Nuclear case holds nuclear capacity to the
reference case level, driving allowance prices 6 percent higher than those in the S280
Core case by 2030. Similarly, there are questions about the potential development of a
large scale bio-power industry. For example, the analysis does not assume enactment of
a significant new mandate for the use of biofuels in the transportation sector, which
would tend to reduce the availability of biomass for electricity generation. The costs of
integrating large quantities of wind into the power grid are another issue. If nuclear and
renewable generation cannot grow rapidly, the deployment of CCS technology would be
more likely. However, the industry would again be relying on a technology about which
there is considerable uncertainty.
The effects uncertainty regarding the potential role of international offsets is illustrated by the range of allowance prices, an indicator of marginal compliance costs, across cases with different assumptions about offset availability. Relative to the S.280 Core case, allowance prices in 2030 are 20 percent higher in the No International case and 35 percent lower in the Fixed 30 Percent Offsets case.
The analysis of S. 280 is subject to a number of additional limitations that deserve emphasis. S. 280 calls for a reduction in the emission caps in 2030 and 2050, but the modeled time horizon in this study extends through 2030. While EIA has attempted to take into account investor behavior anticipating the post-2030 regulations, such as advanced allowance banking, the economic implications of S.280 on the economy after 2030 have not been evaluated. Our analysis suggests that large reductions in carbon dioxide emissions in the electric power sector will be necessary to achieve the emissions caps through 2030. Meeting the 2050 caps would likely require a nearly carbon-free
electric power supply and a substitution of petroleum-based fuels in transportation, a potentially costly transition from current trends.
The reference case used as the baseline for this analysis is only one of many possible
paths representing future economic and energy markets trends under current laws and
policies. The Annual Energy Outlook 2007 presents a range of cases reflecting
alternative growth and price paths. All else equal, higher growth in the U.S. economy
raises baseline emissions and increases the total amount of reductions required to comply
with a cap linked to historical emissions, while lower growth has the opposite effect.
Assuming fixed emissions objectives for other countries, higher growth abroad would
increase their internal requirement for emissions reductions and reduce the availability of
international offsets to U.S. entities covered under S.280, while lower growth has the
opposite effect. A baseline with higher conventional energy prices tends to increase both
energy efficiency and the penetration of alternative energy sources, reducing the burden
of compliance with a cap linked to historical emissions, while lower prices have the
opposite effect.
Energy Market Impacts of Reduction Greenhouse Gas Emissions 
Notes
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