3. Energy Market Impacts of the Renewable Policy Proposal

Electricity Sector Impacts

Implementing a 25-percent RPS by 2025 has significant impacts on power sector generation by fuel, generating technology selection, and electricity prices. The power sector shifts away from its long-term reliance on coal-fired generation, toward increased reliance on nonhydropower renewable generation and incremental hydroelectric generating sources. This trend has little impact on emissions of sulfur dioxide, nitrogen oxides, and mercury. Because these three pollutants are subject to emissions caps, their levels are essentially unchanged (although the costs of compliance are lower). However, the change in fuel mix leads to somewhat lower carbon dioxide (CO2) emissions, which currently are not regulated. The higher cost of renewable generating technologies results in lower delivered prices for fossil fuels but higher electricity prices overall. Table 2 summarizes key electricity sector impacts.

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RPS Credit Prices

The RPS credit price, shown in Table 2 for 2025 and 2030, generally increases through 2025, when the maximum required share for renewable generation is initially imposed. Between 2025 and 2030, the credit price is projected to vary between 3.8 and 4.8 cents per kilowatthour. The credit price represents the incremental cost of meeting the specified renewable target. Essentially, it describes the difference between the cost of the cheapest available renewable option that satisfies the requirement and the alternative technology that would have supplied the electricity if the RPS had not been in place. Naturally, the credit price is affected by the costs and performance of the available renewable options and the alternative nonrenewable technologies. Figure 1 illustrates the RPS credit prices in the Policy Case.

Inter-sector Compliance Options

The proposed Policy analyzed in this report calls for compliance with separate renewable sales targets in the electricity and transportation sectors. The marginal cost of compliance, as reflected by the credit price for each sector, would not be expected to be the same for each sector, as each has different compliance options. Both sectors can and do use significant amounts of cellulosic biomass as part of the compliance strategy, and at times this may represent the marginal unit of supply to one or both sectors. Even so, costs may differ between the two sectors, as each has different conversion efficiencies and capital and non-feedstock operating costs.

If the proposed Policy were applied as an aggregate target for the two sectors, with credit trading allowed between the sectors (that is, 25 percent of the combined electricity and motor transportation fuels markets), the credit prices in the two sectors would converge to a common value. Currently, the electricity sector target is specified in cents per kilowatthour and the transportation sector target in dollars per gallon of ethanol. A joint target would require a common unit of comparison, as shown in Figure 2 for the Policy Case.

The higher credit price in the transportation sector indicates that an aggregate target would encourage more compliance in the electricity sector and reduced compliance in the transportation sector. More than 25 percent of the electricity generated in the electricity sector would be from renewable fuels, and less than 25 percent of the motor transportation fuels would be biofuels. The shift in the compliance burden between sectors would tend to reduce the overall cost of compliance; however, EIA is not able to determine the impact of such a scheme without specification of a mechanism for inter-sector credit trading.

Generation by Fuel

In the Reference Case, coal-fired plants continue as the primary source of electricity, increasing from about 50 percent of total supply in 2005 to 53 percent in 2025 (Table 2). Both nuclear and natural gas plants provided 19 percent of total generation in 2005. Nuclear generation is projected to increase over the subsequent 20 years but at a slower rate than total generation, and so the share of generation from nuclear plants in 2025 falls to 16 percent. Natural gas generation is projected to rise initially but then decline as natural gas prices increase. In 2025, the share of total generation from natural gas plants is projected to be about 19 percent—about the same share as in 2005. In 2030, nuclear power generation falls slightly from 2025 levels due to some age-related retirements, and its share of electricity generation falls to 15 percent. Natural gas power generation falls by about 6 percent from 2025 levels as increasing natural gas prices erode its competitiveness, and its total market share falls to about 16 percent in 2030 (Table 2).

Hydroelectric plants are the largest source of renewable generation, but production from existing facilities is not credited toward the RPS requirement. The share of hydroelectric generation declines in the Policy Case from about 6.5 percent of total supply in 2005 to 6 percent in 2025. Nonhydropower renewables remain a small source of electricity in the Reference Case, but the corresponding share of total generation doubles from 2 percent in 2005 to 4 percent in 2025. Biomass and wind plants represent the primary sources of nonhydropower renewable generation. Production from both these technologies more than triples between 2005 and 2025, although their share of total generation remains small throughout the projection.

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n general, biomass and wind electricity supplies are projected to represent the primary options for complying with the RPS. Although total wind capacity exceeds biomass capacity (Figure 3), biomass generation is considerably higher than the output from wind capacity (Figure 4) because of a higher biomass capacity factor. Dedicated biomass plants have higher utilization rates than wind plants, which are dependent on an intermittent resource. Also, biomass can be co-fired with coal in existing fossil steam units.

In the Policy Case, biomass generation in 2025 and 2030 provides about one-half of the renewable generation required by the RPS (Table 2). Considerable increases in biomass electricity generation occur in virtually every region of the United States. Wind plants account for more than 35 percent of the RPS requirement in 2025 and 2030. Most of the wind capacity additions are expected to be built in the West and Midwest. More moderate increases are projected for geothermal, municipal solid waste, and hydroelectric technologies, which together supply about 10 percent of the needed renewable generation. Little change in solar generation is expected as a result of the RPS (Table 2).

The requirement for renewable generation specified in the RPS is expected to reduce electricity production from other fuel types. Compared to the Reference Case, coal-fired generation is about 24 percent lower in 2025 and 28 percent lower in 2030 in the Policy Case. Natural-gas-fired generation is 23 percent lower in 2025 and 11 percent lower in 2030 in the Policy Case than in the Reference Case (Table 2). Similarly, nuclear generation is about 8 percent less in 2025 and 9 percent less in 2030.

Carbon Dioxide Emissions

In the Reference Case, CO2 emissions resulting from electricity generation grow from 2,375 million metric tons in 2005 to 3,046 million metric tons in 2025, an increase of almost 30 percent (Table 2). The increase in emissions results from higher fossil fuel consumption, particularly coal.

In the Policy Case, the increased penetration of renewable generating plants displaces some generation from fossil plants and slows the growth in CO2 emissions (Table 2). CO2 emissions in 2025 total about 2,425 million metric tons, which represents a reduction of about 20 percent from the Reference Case and only a slight increase from 2005 levels.

Electricity Prices

In the Reference Case, electricity prices are expected to decline from 2005 to 2015 and then increase gradually, so that the prices in 2025 and 2030 are similar to the price in 2005 (Table 2 and Figure 5). The initial decline in prices results from a corresponding decrease in fuel prices and comparatively few capacity additions (because some areas currently have a surplus of generating capacity). Between 2015 and 2025, fuel prices to electricity generators start to rise, and more new plants are required to meet projected increases in demand.

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Compared to the Reference Case, the cost of complying with the RPS in the Policy Case is projected to increase the price of electricity by about 3.3 percent and 6.2 percent in 2025 and 2030, respectively (Table 2 and Figure 5). Although the increased renewable generation resulting from the RPS displaces fossil generation and results in lower fuel prices, that decrease is more than offset by the higher cost of building and operating renewable capacity per unit of output.

The RPS could, however, result in lower electricity prices in some areas of the United States. The Western Regions have considerable renewable resources that could enable suppliers to provide renewable generation in excess of their own requirements and sell surplus credits to producers in other areas with less economical renewable options. The resulting revenue could more than offset the costs of building renewable plants in the West.

Consumers’ expenditures for electricity in the Policy Case are $9 billion higher than in the Reference Case in 2025 and $16 billion higher in 2030. The higher electricity bills are partially offset by lower consumer natural gas bills. Through 2022, however, electricity prices in the Policy Case are generally lower than in the Reference Case, because the cost of generation declines more than the cost of capital increases.

Relative to the Reference Case, end-use sector expenditures for purchased electricity rise while end-use sector expenditures for natural gas fall in the Policy Case. From 2009 through 2030, cumulative expenditures for electricity (discounted at 7 percent) are $15 billion (0.4 percent) higher and natural gas expenditures are $17 billion (1.0 percent) lower in the Policy Case than in the Reference Case.

End-Use Energy Consumption

Consumers and businesses in all sectors of the economy are projected to reduce their electricity consumption and increase their direct use of fossil fuels in response to the higher delivered electricity prices in the Policy Case. These changes reduce overall energy consumption but raise consumers’ energy bills.

Residential and Commercial Sectors

There is little change in residential and commercial energy consumption in 2025 in the Policy Case relative to the Reference Case. Lower electricity consumption is offset by increased natural gas consumption. In both sectors, total delivered energy use¹¹ in 2025 is 0.1 percent lower in the Policy Case than in the Reference Case (Figures 6 and 7). Residential electricity demand is 0.5 percent lower and commercial electricity demand is 0.3 percent lower in 2025 in the Policy Case than in the Reference Case, because electricity prices rise as suppliers pass along the costs of holding renewable credit permits and because of increased renewable fuel use. In 2030, electricity demand in the Policy Case is 1.0 percent lower in the residential sector and 1.1 percent lower in the commercial sector than projected in the Reference Case.

Increased use of renewable fuels leads to lower natural gas consumption in the electric power sector and, in turn, to lower natural gas prices in the Policy Case relative to the Reference Case. As a result, residential natural gas use is 0.2 percent higher and commercial natural gas use is 0.4 percent higher in 2025 in the Policy Case than in the Reference Case.

In the commercial sector, petroleum liquids consumption is 1.2 percent lower in 2025 in the Policy Case than in the Reference Case as a result of higher commercial distillate fuel prices. Although the price of heating oil in the Policy Case is similar to that in the Reference Case, the price of diesel fuel for commercial engines is higher than in the Reference Case, leading to lower commercial demand for petroleum.

Annual residential and commercial energy expenditures are higher with implementation of the Policy proposal. Residential energy expenditures increase by 1.5 percent ($30 per household) in 2025 in the Policy Case relative to the Reference Case due to higher electricity prices. The change in commercial energy expenditures with enactment of the Policy proposals is similar to that in the residential sector. Commercial energy expenditures are 2.3 percent higher in 2025 in the Policy Case than in the Reference Case.

Higher electricity prices relative to natural gas prices in the Policy Case lead to 2.3 percent more commercial natural-gas-fired combined heat and power (CHP) capacity in 2025 relative to the Reference Case. In 2030, the higher relative electricity prices result in 19 percent more natural-gas-fired CHP capacity in the Policy Case compared to the Reference Case. Higher electricity prices in the Policy Case also lead to more use of PV systems in the buildings sectors. Residential and commercial PV capacity in 2030 is 9.6 percent higher in the Policy Case than in the Reference Case.

Industrial Sector

Industrial energy consumption is higher in the Policy Case due to large increases in the use of biofuels and heat co-products for ethanol production. Total delivered industrial energy consumption is 33.9 quadrillion Btu in 2030 in the Policy Case, compared with 30.3 quadrillion Btu in the Reference Case. The increase in industrial sector consumption of biofuels and natural gas in the Policy Case more than offsets a decline in coal use. In 2030, industrial consumption of biofuels and heat co-products increases from 0.8 quadrillion Btu in the Reference Case to 5.2 quadrillion Btu in the Policy Case, as a result of the increase in production of biomass-derived transportation fuels. Cellulosic ethanol production increases from 0.2 billion gallons to 31 billion gallons; the amount of corn used to produce ethanol increases by 107 percent; and biodiesel production increases from 1.6 billion gallons to 4.8 billion gallons.

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Increased ethanol production also results in a sharp increase in natural gas use for heat and power production at ethanol plants, which in 2030 increases from 0.3 quadrillion Btu in the Reference Case to 0.8 quadrillion Btu in the Policy Case. Natural-gas-fired CHP plants are also responsible for increased natural gas consumption, particularly in response to higher electricity prices after 2020. An additional 4.3 gigawatts (18 percent) of natural-gas-fired CHP capacity is added in the Policy Case. Overall, industrial natural gas consumption averages 5 to 8 percent (400 to 600 trillion Btu) higher in the Policy Case than in the Reference Case (Figure 8).

The increases in consumption of biofuels, heat co-products, and natural gas are partially offset by a drop in the use of coal to produce liquids and electricity in coal-to-liquids (CTL) plants. CTL liquids production in 2030 falls from 445 thousand barrels per day in the Reference Case to 202 thousand barrels per day in 2030 in the Policy Case. As a result, total coal use at CTL plants is reduced by 55 percent, from 112 million tons in the Reference Case to 51 million tons in the Policy Case.

The net economic impact of the Policy Case is a reduction in industrial value of shipments, by 3.3 percent in 2030 compared with the Reference Case. All industries are adversely affected to some degree. Among manufacturing industries, petroleum refining has the largest percentage decline in output (12 percent in 2030), followed by the aluminum industry (8 percent) and the steel industry (6 percent).

Transportation Sector

In the transportation sector, total energy consumption in 2025 and 2030 in the Policy Case is slightly lower than in the Reference Case (Figure 9). Total transportation energy consumption increases from 28.1 quadrillion Btu in 2005 to 36.5 quadrillion Btu in 2025 and 39.1 quadrillion Btu in 2030 in the Reference Case. Total transportation energy consumption in the Policy Case is 0.6 quadrillion Btu (1.5 percent) lower in 2025 and 1.0 quadrillion Btu (2.6 percent) lower in 2030, as a result of reductions in freight travel (due to reduced industrial output) and in fuel use for light-duty vehicle travel (associated with higher driving costs).

Ethanol and biodiesel consumption in the Policy Case represents a much larger share of highway liquid fuel use than in the Reference Case. On an energy basis, renewable fuels account for 5.0 percent and 5.6 percent of highway liquid fuel use in the Reference Case in 2025 and 2030, respectively. In the Policy Case, renewable fuels account for about 20 percent of highway liquid fuels consumption on an energy basis in 2025 and in 2030.

To facilitate compliance with the renewable fuel supply and consumption mandate, policies consistent with those outlined in S.23, the Biofuels Security Act of 2007, were adopted in this analysis. S.23 stipulates minimum requirements for the manufacture of dual-fuel capable light-duty vehicles and the installation of E85 fuel pumps by major oil companies at owned and branded stations. It requires that 100 percent of light-duty vehicles manufactured after 2016 must be dual-fuel capable and that 50 percent of owned and branded stations must install one or more pumps that dispense E85 fuel. However, two aspects of S.23 were not considered in this analysis: the requirement for specific minimum E85 sales volumes and the provisions for Corporate Average Fuel Economy credits from the manufacture and sale of dual-fuel vehicles.

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EIA data indicate that approximately 50 percent of all retail fuel sales occur through owned and branded retail outlets, which equates to a consumer fuel availability value of 25 percent.¹² Expected penetration rates of new dual-fuel vehicle sales and E85 fuel availability are illustrated in Figure 10.

Although the Policy Case requires the installation of E85 fueling infrastructure to begin by 2008 and reach the maximum share by 2017, the projections indicate that E85 will not become a cost-competitive alternative to gasoline until 2015. As a result, the projections indicate that the E85 infrastructure requirements considered in the analysis could be delayed by as much as 7 years.

The cost of installing E85 retailing infrastructure and the associated impact on fuel cost and fuel retailer profitability were not considered in this study. An EIA analysis of the incremental cost associated with retrofitting an existing gasoline station to dispense E85 indicates that the costs could vary widely, depending on the scale of the retrofit and the annual volume of E85 dispensed.¹³ At 40 thousand gallons per year, the estimated incremental charge required to recover the cost over 15 years ranges from 8 cents per gallon for a minimal retrofit (tank cleaning and nozzle, hose, and filter replacement) to 29 cents per gallon for the replacement of the existing underground tank and dispenser with E85 compatible equipment. As annual E85 pump volumes approach 50 percent of equivalent unleaded gasoline pump volumes (about 160,000 gallons per year), the incremental costs decrease significantly and could vary from 2 cents per gallon to 7 cents per gallon depending on the scale of the retrofit. The incremental costs per gallon are 2 to 3 times higher if the cost recovery period is reduced to 5 years. These estimates do not account for any gains or losses in revenues that may result from replacing an unleaded gasoline dispenser with an E85 dispenser. In the initial years of operation, fuel-related revenues are likely to be lower if an existing gasoline tank and dispenser are replaced with E85 equipment.

The incremental cost of adding an E85 dispenser at a new retail fuel facility is negligible in comparison with the cost of adding a new gasoline dispenser. If the conversion to E85 from an existing gasoline dispenser is made during the regularly scheduled cycle for gasoline tank and equipment maintenance and cleaning, the incremental cost of conversion to the E85 fuel dispensing capability ranges between a few percent and 50 percent of the cost for a conversion done outside the normal maintenance cycle.

Also not addressed in this study are the costs and implications associated with developing an ethanol distribution network capable of moving in excess of 60 billion gallons of ethanol annually. The distribution costs represented here reflect an infrastructure designed to accommodate volumes expected under typical business-as-usual projections, which are significantly lower than the volumes addressed in this study. Distribution of ethanol in all cases is accomplished via truck, rail, and barge shipments, with costs varying by mode of travel and intra- or interregional considerations.

Depending on the mode of travel and distance shipped, ethanol distribution costs vary from 3.5 cents per gallon to 14.0 cents per gallon, excluding any additional costs that may be incurred due to additional infrastructure development requirements, congestion, new distribution patterns, or legal issues related to an expanded ethanol distribution network. Also not considered are any distribution cost savings that could result from the installation of dedicated ethanol pipelines.

Fuel Prices and Expenditures

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The 25-percent RFS policy raises consumer prices for gasoline and diesel in 2025 by about 13 percent and 22 percent, respectively (Table 3). After 2025, the RFS percent ceases to change, reducing the upward pressure on gasoline and diesel prices. In 2030, gasoline and diesel prices in the Policy Case are about 11 percent and 17 percent higher, respectively, than in the Reference Case.

Unlike gasoline and diesel fuel prices, E85 prices in the Policy Case fall, because revenues from RFS credits reduce the price of ethanol production. E85 prices in the Policy Case are about 15 percent lower than those in the Reference Case in 2025 and 2030, despite the increased cost of ethanol production in the Policy Case.

Transportation energy expenditures in the Policy Case are about $68 billion (12 percent) higher in 2025 and $50 billion (7.7 percent) higher in 2030 than in the Reference Case. Cumulative undiscounted consumer expenditures for transportation energy between 2009 and 2025 are about $266 billion higher in the Policy Case than in the Reference Case.

End-Use Carbon Dioxide Emissions

In the Reference Case, total end-use CO2 emissions increase from 5,945 million metric tons CO2 equivalent in 2005 to 7,381 million metric tons in 2025 and 7,914 million metric tons in 2030 (Table 4). In the Policy Case, CO2 emissions from the end-use sectors are significantly lower, because the average carbon intensity of the fuels used is lower. In 2025, total end-use CO2 emissions are 13 percent (972 million metric tons) lower in the Policy Case than in the Reference Case, and in 2030 they are 14 percent (1,138 million metric tons) lower.

In the Reference Case, the transportation sector accounts for 33.8 percent of total CO2 emissions in 2025, followed by the industrial sector (25.6 percent), residential sector (20.7 percent), and commercial sector (19.8 percent). CO2 emissions from the electric power sector are assigned to each sector according to its share of electricity sales. Compared with the Reference Case, the reductions in CO2 emissions in 2025 in the Policy Case are proportional to the change in energy consumption in the transportation sector. The transportation sector reductions account for 34 percent (329 million metric tons) of the total CO2 reduction of 972 million metric tons in 2025 (Figure 11).

Primary Energy Impacts

Increasing the use of renewable fuels in the electricity and motor fuels sectors would lead to higher overall primary fuel use, because additional energy would be needed to produce ethanol and because of the accounting conventions used to estimate the primary resources consumed in renewable electricity generation. For example, for wind, geothermal, and solar electricity generation, primary energy use is calculated by multiplying the renewable electricity generated by an assumed standard heat rate of 10,200 Btu per kilowatthour to derive a fossil-fuel equivalent. In these cases the measure can be somewhat misleading, because increased use of primary energy is often considered a negative attribute of policy. A more meaningful measure is total consumption of nonrenewable primary energy from coal, oil, and nuclear fuels.

In the Policy Case for this analysis, total primary energy consumption from nonrenewable sources is 5.3 percent lower in 2020, 7.7 percent lower in 2025, and 8.6 percent lower in 2030 than in the Reference Case (Figure 12).

The 25-percent RPS policy leads to lower coal and, to a lesser extent, natural gas and nuclear fuel use in 2025 as generation from nonrenewable fuels is displaced by generation from renewable fuels. In the Policy Case, coal use is 3.1 quadrillion Btu (11 percent) lower in 2020, 6.1 quadrillion Btu (20 percent) lower in 2025, and 7.8 quadrillion Btu (23 percent) lower in 2030 than in the Reference Case. The change in natural gas and nuclear use is smaller than 10 percent in all years.

The percentage of nonrenewable fuel use declines in the Policy Case with the increasing RPS and RFS percentages but not as quickly as the RPS and RFS requirements rise. In the electricity generation sector, new renewable capacity displaces more efficient coal and natural gas capacity that would have been built in the Reference Case. Because the newer capacity would have been more efficient and would have been run at higher utilization rates than the older coal and natural gas units, the RPS actually increases the amounts of coal and natural gas consumed per kilowatthour of electricity generated.

Nonrenewable liquid fuel use is also significantly lower in the Policy Case, because it is displaced by increased ethanol use in gasoline blending and E85 and increased biodiesel use in diesel fuel, including ethanol and biodiesel blends. Overall, nonrenewable liquid fuel use is 2.3 quadrillion Btu (5 percent) lower in 2020, 5.3 quadrillion Btu (11 percent) lower in 2025, and 6.0 quadrillion Btu (12 percent) lower in 2030 in the Policy Case than in the Reference Case.

In contrast, because of the increased production and use of E85 and biodiesel in the Policy Case, the amounts of biofuels used to produce heat and co-products and other renewable fuels are all significantly higher than in the Reference Case. In combination, the use of these fuels in the Policy Case is more than double that in the Reference Case in 2020 and approaches 3.5 times the Reference Case level in 2025 and 2030.

Fuel Supply Impacts

Petroleum and Renewable Fuels Impacts

The provisions of the proposed RFS require that gasoline and diesel producers must either blend and sell an increasing percentage of renewable fuels or purchase enough credits to cover their sales of gasoline and diesel fuels. For the Reference Case, this implies a need for approximately of 34 billion gallons of renewable fuel in 2020, increasing to 66 billion gallons in 2025.¹⁴ For 2026 and each year thereafter, the renewable fuels requirement would be proportional to 25 percent of total gasoline and diesel sales, including ethanol and biodiesel blends, in that year. In 2030, the Policy Case would require approximately 70 billion gallons of biofuels to be consumed in the motor transport market.

Under the RFS proposal, suppliers of gasoline, diesel, E85, and diesel blends would be obligated to hold one biofuel credit for every 4 gallons of motor fuel sold (e.g., gasoline, E10, E85, biodiesel blends, and diesel). For this study, ethanol and biodiesel are considered to be the only renewable fuels qualified to fulfill the RFS requirement. In contrast to the existing RFS, no additional credit is assigned to either fuel, depending on its feedstock or technology.

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Given the magnitude of the RFS requirement, gasoline blends containing up to 10 percent ethanol (E10) would not be sufficient to ensure compliance. Most gasoline-powered vehicles currently manufactured are warranted to operate on gasoline blends with ethanol content up to 10 percent. The use of FFVs, which can operate on much higher concentrations of ethanol—currently, up to 85 percent (E85)—would be required.¹⁵ In 2025, the market share of E85 in the gasoline pool is projected to increase from less than 1 percent in the Reference Case to almost 30 percent in the Policy Case (Figure 13).

Many new light-duty vehicles powered by diesel fuel are warranted for up to 5 percent biodiesel. The reluctance of engine manufacturers to warranty higher blends stems from concerns about the wide range of product quality currently on the market. A campaign to improve the quality of the product significantly is assumed to mitigate such concerns to the point where the number of manufacturers willing to warrant certified B20 blends (a mixture of petroleum diesel and 20 percent biodiesel) will be sufficient to absorb the volumes of biodiesel available.¹⁶

Tables 5 and 6 and Figure 14 summarize the major impacts of the proposed RFS on the downstream market for liquid motor fuels. Relative to the Reference Case, the RFS requirement is projected to increase the consumption of renewable fuels by 21 billion gallons in 2020 and 50 billion gallons in 2025 in the Policy Case. The increase in biofuel consumption increases the cost of gasoline in the Policy Case by 10 cents per gallon in 2020 and by 28 cents per gallon in 2025 (2005 dollars). For diesel fuel, the cost increases are 15 cents per gallon in 2020 and 49 cents per gallon in 2025. The comparatively higher impact on diesel prices results in part from the lower average renewable content of diesel fuel.¹⁷ Each gallon of renewable fuel blended into a product lowers the number of credits needed and the price. As a result, diesel bears more of the cost of RFS compliance than motor gasoline on a per-gallon basis.

Higher relative prices in the Policy Case contribute to a reduction in transportation fuel use. In the Policy Case, liquid motor fuels consumption is approximately 480 trillion Btu (about 1.5 percent) lower than in the Reference Case in 2025 and about 940 trillion Btu (about 2.5 percent) lower in 2030.¹⁸ The combination of displacing petroleum volumes with renewable fuels and lowering consumer demand for petroleum products reduces the consumption of imported crude oil and petroleum products by approximately 0.8 million barrels per day in 2020, 2.1 million barrels per day in 2025, and 2.4 million barrels per day in 2030. Domestic crude oil production is minimally affected in the Policy Case, but refinery gain is reduced due to reduced refining activity an dnatural gas liquids production falls with the reduction in natural gas production resulting primarily from the RPS. The import share of liquid fuel consumption, including ethanol imports, declines from about 60 percent in the Reference Case to about 51 percent in the Policy Case in 2025.

Despite the drop in fuel use, consumer expenditures on liquid transportation fuels increase in the Policy Case by $28 billion in 2020, $69 billion in 2025, and $51 billion (2005 dollars) in 2030 compared with the Reference Case.

The RFS credit price is $2.18 in 2025 and $2.02 per gallon in 2030 in the Policy Case.

Ethanol Imports

The United States recently passed Brazil to become the world’s largest producer of fuel ethanol. In the past, Brazil has emphasized ethanol production from sugar cane for domestic use. More recently, representatives of the Brazilian government have expressed interest in exporting more ethanol, with the United States considered as an important potential market.¹⁹

Brazil currently cultivates sugar cane on about 6 million hectares of land (1 hectare = 2.47 acres). About half of the cane is used to produce ethanol, and the other half is used to produce sugar for food use. Brazil’s ethanol production in 2004 was 4.1 billion gallons, and its total exports were 635 million gallons, including 112 million gallons exported to the
United States.

Brazil has vast potential to increase ethanol production and exports. One recent study indicated that as much as 90 million more hectares of underutilized agricultural land is available.²⁰ However, the investments needed to increase production capacity to 54 billion gallons in 25 years may be substantial.²¹

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Very high levels of biofuel consumption would be needed to meet the requirement of the proposed RFS policy (Figure 15), and it is possible that higher levels of ethanol imports could be a cost-effective way to meet part of the requirement. Currently, ethanol imported directly from Brazil is subject to a tariff of 54 cents (nominal) per gallon. The tariff on ethanol imports is scheduled to expire in 2010, and imports are projected to rise to 3.3 billion gallons of ethanol in the Reference Case in 2025 from approximately 0.11 billion gallons in 2005. In the Policy Case, ethanol imports total 7.7 billion gallons in 2025, or 4.5 billion gallons more than in the Reference Case (Table 6).

Cellulosic Ethanol

No commercial plant using cellulosic feedstock to produce ethanol is in existence today. IOGEN, a Canadian biotechnology firm, estimates that the cost of such a plant would be approximately $6 per gallon of capacity annually (2005 dollars) for a plant producing 50 million gallons per year.²² EIA estimates for its AEO2007 reference case, and those used in this study, are based on the IOGEN estimate.

As in AEO2007, the capital costs in this analysis are adjusted for technological optimism (early estimates of construction costs for first-of-a-kind plants tend to be optimistic) and learning-by-doing (construction costs decline with manufacturing experience) in a manner consistent with the treatment of other emerging technologies within NEMS.²³ Once the first few plants are built, with Federal incentives in this case, learning-by-doing reduces costs as experience increases.²⁴

Learning-by-doing assumes that production costs fall as manufacturing experience with the technology increases. The rate of learning, however, depends on the newness and maturity of the component parts that make up the technology—the more mature the component parts, the slower the learning rate.

For cellulosic ethanol, this study assumes that two-thirds of the capital costs would be represented by mature technologies or materials, such as the power plant; only elements such as the pre-treatment and hydrolization/fermentation units are subject to very rapid learning. After the addition of 200 units (equivalent to 10 billion gallons per year capacity), the capital cost in the EIA approach is approximately 83 percent of the base cost in 2012, and 66 percent of the estimated first-of-a-kind cost. The cumulative effect of applying EIA’s methodology results in an nth-of-a-kind plant cost for cellulosic ethanol of $5.14 per gallon per year.

A widely quoted National Energy Renewable Laboratory (NREL) study by Aden et al.²⁵ details an engineering study that estimates a capital cost of $3.39 per gallon per year.²⁶ There are several important differences between the NREL and EIA estimates. First, the NREL study is an engineering analysis of an nth-of-a-kind plant, which assumes that several technological and engineering hurdles will be overcome, whereas EIA’s estimate is for a first-of-a-kind commercial plant. Second, the NREL study assumes a slightly larger plant (69.3 million gallons per year versus 50 million gallons per year). The economies of scale make the NREL study plant slightly less expensive. Finally, the total project economics in the NREL study were chosen to match the Department of Energy’s target selling price of $1.07 per gallon (2000 dollars) to be achieved by 2010. Basing the future price on a research and development target raises the issue of uncertainty: investments in research and development cannot, statistically speaking, assure a successful outcome within a specific time frame.

EIA’s nth-of-a-kind plant cost estimate for cellulosic ethanol of $5.14 per gallon per year is 51 percent higher than the NREL estimate for a similar but not necessarily identical plant. The EIA and NREL estimates of nth-of-a-kind capital costs illustrate the range of costs that may be realized, while the application of learning to the plant components illustrates the extent to which costs could decline if the technology merely evolved without further technological breakthroughs. Such breakthroughs could reduce the “footprint” of the plant and lead to much greater cost reductions than currently projected by EIA. Such breakthroughs are not predictable, however, and assuming that they will occur would indicate a higher degree of technological progress than has been observed for other technologies.²⁷

Agriculture Market Impacts

Dramatic increases in domestic production of corn ethanol would be needed to meet the renewable fuels requirement in the Policy Case. Corn ethanol production reaches 25 billion gallons in 2025 in the Policy Case, and U.S. corn production is projected to be insufficient to meet the total demand for corn at such high levels of ethanol production.

Historically, the United States has been a large exporter of corn, and in the absence of new policy it is projected to continue exporting corn. But assuming that corn and cellulose would be the only sources of ethanol, the United States would be required to import corn or corn products to meet demand in the Policy Case. For example, U.S. corn exports total 2.7 billion bushels in 2025 in the Reference Case, whereas corn imports total 1.9 billion bushels in 2025 in the Policy Case (Table 6).

It is likely, however, that U.S. agriculture and biofuels markets would adjust to higher corn prices in ways that would eliminate the need for corn imports. For instance, feedstocks previously regarded as uneconomical might be used to produce ethanol or biodiesel (in the United States or elsewhere) to meet the requirement. Furthermore, the projections assume that corn yields would continue to increase at historical rates, from 151 bushels per acre in 2006 to 183 bushels per acre in 2025. Genetic improvements to corn plants, however, may allow quicker yield growth or higher sugar/starch content. Any of these developments, which may be triggered by the relatively higher price of corn, would lessen the need for corn imports in the Policy Case. Alternatively, any corn imports could be in the form of a wide range of finished and intermediate products that contain corn.

EIA models domestic ethanol production from corn and cellulosic biomass and Brazilian ethanol production from sugar cane. It is possible that very high corn prices could cause U.S. ethanol producers to turn to other starchy or sugary crops that EIA has not modeled, such as sugar cane, higher-starch corn, sorghum, wheat, barley, sugar beets, potatoes, or cassava. Ethanol producers might also choose corn wet-mill technology over corn dry-mill technology to produce ethanol. Wet mills produce corn oil, corn gluten meal, and corn gluten feed as co-products. The output of these products per bushel of corn is more valuable than DDGS from a dry mill, but wet mills require higher capital expenditures.

New corn ethanol plants are assumed to be the dry-mill type, producing DDGS as a coproduct. DDGS can be used as an animal feed supplement, but there are limits on its use, depending on the type of animal. At current levels of corn ethanol production, DDGS is assumed to sell for the price of corn on a weight basis. This analysis assumes that the DDGS value starts to fall in relation to corn at a production level of 18 billion gallons. If the value of DDGS falls sufficiently, it is assumed that the DDGS would be burned for process energy at the ethanol plant. In 2025, 78 million tons of DDGS is projected to be produced in the Policy Case, with 15 million tons used for process energy.

There are many uncertainties about the agriculture market impacts of high levels of biofuels demand. The corn price in 2025 is projected to rise from $3.00 per bushel (2005 dollars) in the Reference Case to $6.50 per bushel in the Policy Case (Table 6). The higher corn prices would cause prices for other commodities to rise, and the increases would be reflected in food prices. In the short term, higher food prices would impose hardships on developing nations. In the longer term, however, farmers in the developing world could benefit from the increased demand for agricultural products, which would lead to more investment and more farm employment. Some investments could enable current subsistence farmers to market their surplus output.

EIA models domestic biodiesel production from soybean, cottonseed, canola (edible rapeseed), sunflower oils, yellow grease, and animal fats. European biodiesel producers prefer industrial rapeseed oil for raw material, because it yields biodiesel with better cetane and cold flow properties than soybean oil biodiesel. Industrial rapeseed is not edible, however, which limits it potential market and marketability by farmers. U.S. farmers want as many markets for their crop as possible to enhance profits at minimum risk, and they tend to resist cultivation of crops specialized to one use. Farmers like the fact that conventional corn and soybeans can be sold for food or industrial use.

The proposed RFS policy probably would result in added incentives for farmers to grow specialized biofuels crops beyond those incorporated in current modeling structures. It is possible that U.S. agriculture in the future will be better optimized for biofuels production. Finally, EIA also does not model biodiesel production from algae or jatrohpa, both of which promise higher yields of oil per acre of land than soybeans.

Meeting the requirements of the proposed Policy could be more costly than indicated in this analysis if other nations also increased their requirements for renewable motor fuels. Japan, for example, recently mandated ethanol-blended gasoline, and the European Union has set a target of 5.75 percent biofuels in fuels for light-duty vehicles. The proposed Policy would also be affected by the choices of other nations that produce and export biofuels. Brazil, the largest exporter of ethanol, and Indonesia and Malaysia, major exporters of palm oil that can be used to make biodiesel, might choose to use more of their production domestically to displace fossil fuels.

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Natural Gas Supply

In the Policy Case, natural gas consumption declines in the electric power sector as natural gas generation is displaced by renewable energy sources (Table 7). In the industrial sector, natural gas consumption increases in the Policy Case, as more natural gas is used in the production of corn-based ethanol. Natural gas consumed in petroleum refining is included in the industrial natural gas consumption figures shown in Table 7.

The increase in natural gas consumption for corn-based ethanol production in the Policy Case partially offsets the decline in natural gas consumption for electric power generation. As a result, total natural gas consumption and supply are projected to be only slightly (0.5 trillion cubic feet) lower in the Policy Case than in the Reference Case (Tables 7 and 8).

Coal Supply

Total coal production in the Policy Case is projected to be 23 percent (340 million tons) lower in 2025 and 25 percent (426 million tons) lower in 2030 than in the Reference Case (Figure 16). The impacts fall more heavily on coal production west of the Mississippi River, which meets most of the incremental demand for coal in the Reference Case. While the RFS also affects coal markets to some extent, the RPS for the electricity sector is the dominant influence that drives the shift away from coal in the Policy Case.

The displacement of coal-fired electricity generation by renewable generation accounts for most of the reduction in coal consumption in the Policy Case relative to the Reference Case, and much of the remaining decline is attributable to decreased production of coal-based synthetic liquids. In 2025, coal-fired generation is 691 billion kilowatthours lower in the Policy Case than in the Reference Case, equal to 73 percent of the increase in renewable generation in 2025. In 2030, the decline in coal-fired generation in the Policy Case is even larger, amounting to 938 billion kilowatthours—equal to 93 percent of the increase in renewable generation in 2030 (see Table 2).

Reduced output of coal-based synthetic liquids in the Policy Case results from lower demand for diesel and other petroleum products and a lower selling price for the excess electricity generated at CTL plants. Relative to the Reference Case, coal consumption at CTL plants in the Policy Case is 50 million tons lower in 2025 and 61 million tons lower in 2030.

Economic Impacts

In the Policy Case, higher energy and food prices are projected to reduce economic activity (Table 9). Achieving 25-percent penetration of renewable fuels in both electricity generation and motor transportation leads to higher energy prices as consumers substitute more expensive renewable fuels for less expensive fossil fuels. Higher renewable fuel demand, in turn, increases the cost of key inputs and results in higher electricity and transportation prices.

Impacts on Energy and Aggregate Prices

Consumer energy prices in the Policy Case rise steadily for the first 10 years of the projection, to 13.0 percent above prices in the Reference Case—roughly one-quarter of the increase in overall consumer prices. The peak consumer price inflation occurs in 2025, when the renewable standards are met, then starts to subside. The inflation rate (year-to-year change in consumer prices) reaches 12.7 percent for consumer energy prices and 3.0 percent for overall consumer prices in 2025. As energy prices begin to recede, overall consumer prices stabilize to approximately 3.0 percent above Reference Case levels. Wholesale prices show similar patterns: peaking in 2025, then starting to stabilize at higher levels after 2025 (Figure 17).

GDP and Consumption Impacts

In general, higher delivered energy prices relative to a baseline reduce real output for the economy, energy consumption, and, indirectly, real consumer spending for other goods and services due to lower purchasing power. In the Policy Case, higher energy prices result in lower aggregate demand for goods and services and lower real GDP relative to the Reference Case (Figure 18). In the Policy Case, total discounted GDP losses,²⁸ over the 2009 to 2030 time period are $296 billion (-0.12 percent) relative to the Reference Case. After energy prices peak in 2025, both real GDP and consumption begin to return to baseline levels.

Real GDP is a measure of what the economy produces; however, consumers ultimately are interested in their purchases of goods and services, or “consumption.” GDP and consumption impacts of a proposed policy can differ if the policy leads to changes in the level and shares of the GDP: consumption, investment, government expenditures, and net exports. In the Policy Case, cumulative discounted consumption losses relative to the Reference Case are $149 billion (-0.09 percent). Consumption impacts, like GDP impacts, generally grow over time; however, as energy price increases subside, consumption begins to return to the respective reference cases. On an undiscounted basis, GDP and consumption losses are much larger²⁹ (Figure 18).

Industry and Employment Impacts

Notes