2. Impacts of Modeled Provisions of the Conference Energy Bill

This analysis begins with a summary, followed by a discussion of each major provision. The impacts of provisions that affect fuel production or supply and power generation markets are discussed first, followed by provisions that affect end-use markets.

The summary of impacts described in this chapter compare the AEO2004 Reference Case to a case that contains those CEB provisions modeled in NEMS. The impact of incremental R&D investments on technological change is typically not modeled in NEMS because the relationship between any specific R&D investment and the expected technological change cannot be statistically determined. An additional case that evaluates one possible result of incremental R&D for ultra-deep offshore and unconventional resources funded by royalty payments is included as a sensitivity in the box on pages 10 and 11.

Comparison of Selected Energy Performance Indicators

The impact of the CEB provisions analyzed in this report on total primary energy consumption is small. The maximum annual difference from the Reference Case level of primary energy consumption is no more than 0.4 quadrillion British thermal units (Btu) or 0.3 percent. From 2004 through 2020, primary energy consumption is virtually identical to the Reference Case level (Table 1). After 2020, annual consumption is projected to be slightly lower than the Reference Case (by at most 0.4 quadrillion Btu).

Petroleum consumption is slightly lower, primarily due to higher prices resulting from the RFS and the ban on MTBE. Net petroleum imports are reduced by 0.3 percent in 2015 and by 1.2 percent in 2025 through a combination of increased domestic production from the ultra-deep offshore and from slightly reduced gasoline demand which results from higher gasoline prices.

Natural gas consumption is slightly lower in the period from 2009 to 2016 because the renewable and nuclear PTCs increase generation from these fuels and reduce the demand for gas during that period. Increased natural gas production from the CEB natural gas provisions (for example, the Section 29 tax provisions for unconventional gas) displaces natural gas imports and more costly domestic production. Net natural gas imports are reduced by about 0.5 quadrillion Btu in 2010. Natural gas wellhead prices are reduced slightly, resulting in slightly lower electricity prices. Coal consumption is lower at the end of the forecast period (2.5 percent in 2025) due to the PTC for nuclear and renewable technologies and the incentives to increase natural gas production.

Carbon dioxide emissions are lower in the CEB case than in the Reference Case in all years as the mix of fuels changes. In 2025 carbon dioxide emissions, are 96 million metric tons (1.2 percent) lower in the CEB case than in the Reference Case.⁵ The projected paths for some of the energy indicators identified in Table 1 tends to converge in the CEB and Reference Cases toward the end of the forecast horizon. This results because of depletion effects and the scheduled end of the CEB provisions, which are not expected to induce sufficient cost reductions to spur the additional production of alternative sources of supply beyond the timeframe of the incentives.

Natural Gas and Oil Supply Provisions

Alaska Natural Gas Pipeline Incentives

Sections 386, 1355, and 1356 provide incentives for the construction of an Alaska natural gas pipeline to supply the lower-48 States: a Federal loan guarantee for pipeline construction, a 15-percent tax credit for the construction of a high-volume gas treatment plant, and a 7-year depreciation schedule for tax purposes for high-volume natural gas pipelines. The loan guarantee shifts the risk of the pipeline loan from the lenders to the Federal government, resulting in more favorable interest rates, which ultimately result in lower required tariffs for full cost recovery. The 15-percent tax credit for gas treatment plants reduces the expected treatment charge from $0.42 per thousand cubic feet (mcf) to $0.37 per mcf (in 2002 dollars). The accelerated depreciation provision is expected to result in improved cash flow for the pipeline owners but does not appreciably alter the tariff.

The net effect of these provisions is to reduce the price necessary to trigger the construction of the pipeline by $0.15 per mcf. This provision advances the entry-into-service of the pipeline by 1 year, 2017 instead of 2018 as projected in the Reference Case.

Ultra-Deep Gas Royalty Relief in Shallow Waters

Section 314 of the CEB authorizes the Secretary of Interior to publish a final regulation to complete the rulemaking begun by the Notice of Proposed Rulemaking entitled “Relief or Reduction in Royalty Rates—Deep Gas Provisions,” published in March 2003. The Minerals Management Service published this final rule on January 26, 2004, effective March 1, 2004. The rule grants royalty relief for natural gas production from wells drilled to 15,000 feet or deeper on leases issued before January 1, 2001, in the shallow waters (less than 200 meters) of the Gulf of Mexico. Production of gas from the completed deep well must begin before 5 years after the effective date of the final rule. The minimum volume of production with suspended royalty payments is 15 billion cubic feet for wells drilled to at least 15,000 feet and 25 billion cubic feet for wells drilled to more than 18,000 feet. In addition, unsuccessful wells drilled to a depth of at least 18,000 feet would receive a royalty credit for 5 billion cubic feet of natural gas. Section 314 further grants royalty suspension for volumes of not less than 35 billion cubic feet from ultra-deep wells on leases issued before January 1, 2001. An ultra-deep well is defined as a well drilled to at least 20,000 feet. Between 2004 and 2008, this provision increases offshore deep gas production in shallow water. However, total offshore production does not increase during this period, because lower natural gas prices relative to the Reference Case in these years slows the development of deepwater resources.

Extension and Modification of the Section 29 Tax Credit

Section 1345 of the CEB would extend and modify Section 29 of the Internal Revenue Code, established under the Windfall Profit Tax of 1980, under which tax credits were provided for producing fuel from nonconventional sources. Fuels that were eligible to receive the credit included: oil produced from shale and tar sands; gas from geopressurized brine, Devonian shale, coal seams, tight formations, and biomass; liquid, gaseous, or solid synthetic fuels produced from coal; fuel from qualified processed formations or biomass; and steam from agricultural products. For facilities producing gas from biomass or synthetic fuel from coal, the credit is available for production through 2007 from facilities placed in service before July 1, 1998. For all other sources to which Section 29 applied, the credit was available for production through 2002 for those facilities placed in service from 1980 to 1992.

In general, Section 1345 allows a credit of $3 (indexed for inflation with 2002 as the base year) per barrel (or Btu equivalent) for production from nonconventional sources for 4 years of production prior to 2010 for new wells placed in service through 2006. Fuels eligible to receive the new credit include: oil produced from shale and tar sands; gas from geopressurized brine, Devonian shale, coal seams, and tight formations; landfill gas; fuels from agricultural and animal waste; refined coal; coal-mine gas; and coke and coke gas. Production from existing oil and gas wells drilled from 1980 through 1992, previously eligible through 2002, is also eligible for the credit through 2006. For smaller landfills, there is a credit of $3 for facilities placed in service after June 30, 1998, and before January 1, 2007, and the credit is reduced to $2 for larger landfills already required to add gas collection facilities. Refined coal facilities placed in service before January 1, 2008, are also eligible for 5 years of tax credit. The credit in Section 1345 is limited to an average daily production of 200,000 cubic feet of gas (or oil equivalent) per well or facility. The credit is fully effective when the price of crude oil is $35 per barrel or less and phases out gradually as the price rises to $41 per barrel.

EIA analyzed Section 1345 with respect to gas from tight formations (tight sands), Devonian shale (gas shales), and gas from coal seams (coalbed methane). EIA allowed a credit of 53 cents per mcf ($3 per barrel Btu equivalent) for 4 years of gas production prior to 2010 for new wells placed in service through 2006. The credit was represented as an increment to the wellhead price in the first 4 years of a projected price path utilized to determine the decision whether or not to drill a well.

The increased profitability of nonconventional fuels under Section 1345 of the CEB is projected to result in significant drilling increases, higher reserve levels, and, ultimately, increased production (Table 2). Section 29 credits provide significant incentives to add new unconventional reserves through 2006 and to produce from them. Once the new facilities are added, production will continue until they are no longer economic. The need for new drilling in 2009 is diminished relative to the AEO2004 Reference Case because of the large number of wells drilled in 2006 and 2007, which continue to produce through 2010. In the CEB case, the tax credit for Section 29 wells makes more of the marginal supplies profitable to develop early and its effect is noticed in the last decade of the forecast in increased expected ultimate recovery per well (EUR) shown in Table 2. During the period for which wells are eligible for the credit, 2004 to 2006, 19 percent more nonconventional gas wells are projected to be drilled in the CEB Case than in the Reference Case. Total nonconventional reserve additions over this period are projected to be 13 percent higher in the CEB Case than in the Reference Case. With the larger reserve base, cumulative nonconventional production is projected to be 3 percent higher in the CEB Case than the Reference Case from 2004 to 2009, the period during which the credit could be claimed, for 4 consecutive years, on production from an eligible well.

Summary of Natural Gas and Oil Market Impacts from CEB Provisions

The CEB provisions for natural gas supply are expected to increase domestic production from unconventional and offshore sources, thereby placing downward pressure on wellhead prices. Table 3 provides a summary of price, production, import, and consumption impacts. The effect of the Section 29 credit is felt primarily in the short term. Cumulative unconventional gas production in the CEB between 2005 through 2010 is 1.3 tcf higher than in AEO2004 and 0.68 tcf higher between 2020 and 2025. Increased unconventional production earlier drives prices below AEO2004 by as much as $0.16 per mcf in 2006 and 2007, but then prices rise to Reference Case levels in 2010. The lower natural gas wellhead prices slightly delay some of LNG projects in the Reference Case, raising the lower-48 domestic gas prices above the Reference Case in 2010. After 2010, prices in the CEB Case fall below Reference Case levels due to other provisions of the CEB which moderate gas demand for electricity generation (e.g., the renewable and nuclear PTCs). The largest price decrease from the Reference Case to the CEB Case is projected to occur in 2018 at $0.22 per mcf. In the last 5 years of the forecast, the price difference narrows as some of the provisions of the bill end and the lower prices earlier in the forecast result in lower production from sources not benefited by provisions in the bill. Higher production levels earlier in the forecast also result in lower available resources later in the forecast. By 2025, the price of natural gas in the CEB Case is $4.40 per mcf, the same as in the Reference Case.

The natural gas supply provisions of the CEB result in increased production, lower prices, and increased demand of 0.13 trillion cubic feet (tcf) by 2025. The increase in domestic production is expected to exceed the increase in demand because increased profitability expected under the CEB allows domestic production to improve its competitive position over imported sources. Net natural gas imports are lower than the Reference Case throughout the forecast period, with the greatest decrease in 2010 at almost 0.6 tcf. The majority of this difference in most of the projection period is attributable to reductions in liquefied natural gas (LNG) imports.

Renewable Fuels Standard, MTBE Ban, Oxygenate Waiver, and Ethanol and Biofuel Tax Provisions

The CEB Case includes an RFS that requires 3.1 billion gallons of renewable fuels in the transportation sector in 2005, increasing to 5.0 billion gallons by 2012. For 2013 and each year thereafter, the renewable fuels required would be proportional to the total gasoline sold in the Nation.⁶ Both ethanol and biodiesel are considered as renewable fuels, with a 1.5-gallon credit toward the RFS for every gallon of biomass ethanol produced. The use of MTBE would be prohibited nationwide starting in 2015.⁷ The CEB Case assumes that States would not seek a waiver from the U.S. Environmental Protection Agency to allow the continued use of MTBE. If economical, merchant MTBE producers are assumed to convert to iso-octane production with grant assistance up to $250 million per year between 2005 and 2012. The CEB Case also incorporates the elimination of the oxygen content requirement for reformulated gasoline starting in 2005.⁸

Currently, there is a Federal tax credit of $0.52 per gallon of ethanol blended into gasoline, which will be reduced to $0.51 per gallon for 2005 and 2006 and expire in 2007. The Federal tax credit for ethanol has been extended several times in the past, and the AEO2004 Reference Case assumes the tax credit would be extended indefinitely. The CEB extends the ethanol tax credit to December 31, 2010. Because the RFS requirements would assure the increasing use of ethanol in transportation fuels, the CEB Case assumes the ethanol tax credit would end as stated in the CEB starting in 2011. A tax credit of $0.50 per gallon of biodiesel produced from recycled oil or $1.00 per gallon of biodiesel produced from virgin oil or virgin animal fat applies to biodiesel blended with petroleum diesel. The credit is effective from December 31, 2003, through December 31, 2005.

Table 4 summarizes the major impacts of the CEB on the petroleum market.⁹ The RFS requirements would increase the ethanol consumption by 0.86 billion gallons in 2010, 1.81 billion gallons in 2015, and 1.96 billion gallons in 2025. Relative to the ethanol consumption of 2.04 billion gallons in 2002, it represents an increase in ethanol consumption of 113 percent by 2010, 173 percent by 2015, and 205 percent by 2025. Ethanol accounts for essentially all of the additional renewable transportation fuels consumption compared to the Reference Case. Biodiesel supply is not expected to be affected significantly by the RFS nor by the short-term tax incentives for biodiesel.

Net petroleum imports would be reduced by 100,000 barrels per day (0.8 percent) in 2010, 50,000 barrels per day (0.3 percent) in 2015, and 230,000 barrels per day (1.2 percent) in 2025. This is partially attributable to the increase in renewable fuels use in the transportation sector and partly due to reduced demand for gasoline as the result of higher prices. Slightly lower domestic petroleum use contributes to the reduction in petroleum imports, which are also affected by other provisions in the CEB not related to the RFS or MTBE ban.

The CEB Case projects an increase of 0.3 cents per gallon in the average gasoline price and an increase of 0.4 cents per gallon in the average RFG price compared to the Reference Case in 2010. These estimated price increases result mainly from the RFS which would require additional renewable fuels in the gasoline pool (essentially more ethanol blended into conventional gasoline). Because ethanol would incur a vapor pressure penalty of roughly 1 pound per square inch (psi), it would cost slightly more to produce the gasoline blendstock for ethanol blending in order to maintain limits on volatile organic compound (VOC) emissions.

By 2015, the CEB Case projects an increase of 3.0 cents per gallon in the average gasoline price and 8.1 cents per gallon in the average RFG price, relative to the Reference Case. Included in this price is the elimination of the ethanol tax credit in 2011 which is expected to increase the gasoline price by the amount of ethanol blended, about 1.2 cents per gallon for all gasoline (including conventional gasoline and RFG) and 2.7 cents per gallon for all RFG.¹⁰ The remaining cost increases result from the phase-out of MTBE use by 2015. Because of the MTBE ban, cost increases of about 1.8 cents per gallon for all gasoline and 5.4 cents per gallon for average RFG in 2015 are expected. The volume loss of 11 percent for RFG due to the MTBE ban would favor the blending of ethanol in most RFG areas to make up the loss of volume and octane. Because of the vapor pressure penalty from blending ethanol and much stricter vapor pressure specifications for the RFG, it would be harder and more costly to provide RFG blendstock for ethanol blending. Thus, the MTBE ban has a greater price impact than the effect of the RFS.

Electric Power Provisions

The key CEB provisions analyzed affecting electricity include:

• a 3-year extension of the PTC for qualified renewables,
• a clean coal technology ITC for 6 gigawatts of new capacity, and
• a PTC for 6 gigawatts of new advanced nuclear capacity.

Renewables

The CEB contains numerous provisions relating to renewable energy, especially with respect to renewable energy used for electric power production. The 1.8-cent-per-kilowatthour, 10-year payment period PTC for wind and “closed-loop”¹¹ biomass plants expired on December 31, 2003. The CEB would extend eligibility to plants coming online from January 1, 2004, to December 31, 2006. It also expands the program to include renewable electricity generated from geothermal, solar, “open-loop” biomass¹², municipal solid waste, and landfill gas resources. Some of the newly eligible technologies would only be able to claim two-thirds of the value of the PTC for wind and closed-loop biomass, that is, 1.2 cents, and each of these program additions are limited to a 5-year payment period. Since the CEB specifies no earliest in-service date for plants utilizing open-loop biomass fuel, existing plants that co-fire with biomass fuel can claim the credit.

The PTC extension and expansion does support significant growth in generation from wind and biomass co-firing (Table 5). By 2010, generation from wind with the PTC extension is more than double the generation in the Reference Case. However, much of the additional construction of wind capacity is due to the accelerated construction of units that would have occurred later in the Reference Case. By 2025, the level of renewable generation with the PTC extension is only 14 percent above the Reference Case.

By allowing existing plants to claim the PTC for burning “open-loop” biomass, significant co-firing in existing coal facilities is induced. Some coal facilities are able to quickly modify operations, while others may take a couple of years to make the small capital investments (about $200 per kilowatthour) necessary to take advantage of this provision. At the peak PTC-eligibility year of 2008, there are 85 billion kilowatthours of biomass generation in co-fired facilities, compared to only 9 billion kilowatthours in the same year for the Reference Case. However, once the 5-year payment period for the credit has ended, it is no longer economical to utilize most of the incremental biomass fuel. With minimal investment cost to recover, co-firing operations are greatly reduced, although they remain somewhat higher than in the Reference Case throughout the projection period.

Coal

Section 1351 of the CEB provides a 17.5-percent ITC for new coal-fired generating units employing advanced clean coal technologies, such as advanced pulverized coal, fluidized bed, or IGCC. The tax credit applies to facilities placed in service before January 1, 2017, and is limited to 6 gigawatts. The 6-gigawatt cap is to be divided evenly between advanced IGCC plants and advanced pulverized coal plants. To qualify as an advanced clean coal technology, a plant must meet a minimum technology-specific energy conversion efficiency and carbon dioxide emission rate.

The ITC for advanced IGCC units is expected to increase this capacity by about 22 gigawatts above the Reference Case level. While the ITC is only available to the first 3 gigawatts of IGCC capacity, it causes plants to be built earlier than otherwise expected, making the technology more competitive in later years of the projections. An ITC is also specified for 3 gigawatts of advanced pulverized coal capacity, but more than 3 gigawatts are expected without the ITC, so the CEB does not cause more advanced pulverized coal capacity to be built. Overall, the total pulverized coal capacity is actually lower in the CEB case because the combination of lower natural gas prices that make natural gas capacity more economical and the tax credits that bring on more nuclear and renewable capacity dampen the additions of new pulverized coal capacity.

Nuclear

Section 1310 of the CEB adds Section 45L to U.S. Code Title 26, Section 45, which provides a 1.8-cent-per-kilowatthour tax credit (unadjusted for inflation) for production from advanced nuclear facilities for the first 8 years of their operation. To receive the credit, new facilities must be built before January 1, 2021. The total amount of the credit is limited to $125 million annually per 1 gigawatt of new capacity, and the total amount of new capacity that can receive the credit is 6 gigawatts. The CEB is projected to lead to the addition of 6 gigawatts of advanced nuclear capacity through 2025. However, no additional nuclear capacity beyond the 6 gigawatts eligible for the tax incentive is expected.

Summary of Electric Sector Impacts

Taken together, the CEB tax credit provisions affecting renewables, nuclear, and coal generation result in slightly lower electricity prices and a slight shift in the mix of capacity added to meet the demand for electricity through 2025 (Tables 5 and 6). The change in electricity prices is driven by lower fuel prices, while the CEB tax incentives drive the capacity mix changes. In 2025, electricity sales in the CEB case are 9 billion kilowatthours lower than in the Reference Case even though electricity prices are slightly lower. This is primarily due to the torchiere efficiency standard, which is expected to reduce electricity demand by 8 billion kilowatthours in the residential sector.

End-Use Demand Provisions

Residential Sector

Of all the provisions in the CEB for the residential sector that meet the criteria for inclusion in the modeling analysis, only the torchiere lighting standard has a direct and measurable effect on residential energy demand. The standard, effective January 1, 2005, limits the output of torchiere lights to 190 watts per bulb. Today, torchiere bulbs in the 300-watt range are common in the marketplace, allowing room for future energy savings. In 2010, the torchiere standard is projected to save 5 billion kilowatthours (2 percent of residential lighting demand), increasing to 8 billion kilowatthours by 2025 (3 percent of lighting demand).

The remaining residential sector provisions in the CEB that could be analyzed have little or no effect on energy demand. Increases in funding for weatherization programs and tax credits for existing homes are projected to reduce heating and cooling requirements by less than one-tenth of one percent. The tax credits for solar, wind, and fuel cell equipment are not sizable enough to bring about any additional purchases of these relatively expensive products. As a result, the tax credit would be given to purchasers of this equipment who would be expected to purchase it without the tax credit, without encouraging additional expansion of the market. The tax credit for new homes spurs the construction of an additional 107 thousand homes that meet or exceed the Energy Star requirement. This represents a 16-percent increase over the number of homes built to these specifications in the Reference Case and about 2 percent of the homes built in the 2004 to 2006 time period.

Residential consumers are also affected by CEB provisions directed towards energy suppliers that lower the energy prices, partially offsetting the energy demand reductions in the CEB Case, relative to the Reference Case. Table 7 confirms the reduction in energy consumption, prices, and expenditures in the CEB Case, relative to the Reference Case.

Commercial Sector

Section 133 of the CEB provides specific conservation standards for illuminated exit signs and low voltage dry-type transformers manufactured on or after January 1, 2005. The provision requires exit signs to meet Version 2.0 Energy Star performance requirements, power usage of 5 watts or less with size and luminance levels also specified. Low voltage dry-type transformers must meet the Class I Efficiency Levels specified by the National Electrical Manufacturers Association. The provision also requires traffic signal modules manufactured on or after January 1, 2006, to meet Energy Star performance requirements. To estimate the impacts of these standards, electricity use reductions relative to reference case assumptions were estimated and included in the CEB Case. The standards are projected to reduce commercial delivered electricity demand in the “Other Uses” category by 8 trillion Btu or 2 billion kilowatthours in 2010, 15 trillion Btu in 2015, and 18 trillion Btu (over 5 billion kilowatthours) annually in 2025 as the existing equipment stock is replaced and the effects of the standards are realized. However, reduced electricity prices due to other provisions of the CEB result in slightly higher projected commercial electricity use in the CEB Case than in the Reference Case.

Section 205 of the CEB establishes a photovoltaic energy commercialization program, including the installation of at least 150 megawatts cumulative capacity in public buildings from 2004 through 2008. The provision authorizes $50 million per year for the 5-year program, about one-third of the funds needed to install the full 150 megawatts specified in the bill. To estimate the impact of the provision, extra “program-driven” commercial photovoltaic capacity was added over the 5-year program equal to about 50 megawatts, the capacity consistent with the authorized funding. The additional photovoltaic capacity installed for this provision is projected to generate about 110 million kilowatthours of electricity annually post-2007. Using the current Federal Energy Management Program discount rate, the investment results in a levelized generation price of more than 16 cents per kilowatthour, not including operating and maintenance costs.

Section 1303 provides a 20-percent business ITC for fuel cell systems up to a maximum of $500 per 0.5 kilowatt of capacity. Qualifying equipment must have electrical capacity of at least 0.5 kilowatts and be placed in service from 2004 through 2006. Fuel cell adoption is limited because current system costs are more than $5,000 per kilowatt and the timeframe of the credit is short. Very few additional sales of fuel cells would be purchased as a result of the tax credit.

Supply-driven energy price effects for commercial consumers, similar to those projected for the residential sector, also occur. Composite energy prices and expenditures are projected to be one percent lower in 2025 (Table 8).

Industrial Sector

Section 1306 of the CEB expands the current 10-percent business ITC for solar power generation equipment to include combined heat and power (CHP) systems. Qualifying equipment must have electrical capacity of not more than 15 megawatts or mechanical energy no greater than 2,000 horsepower. Qualifying equipment must produce at least 20 percent of its useful output as thermal energy and at least 20 percent as electricity. Such equipment must also have a system efficiency of at least 60 percent. The credit would be effective from 2004 through 2006. The tax credit creates an incentive to increase CHP capacity, but that incentive is diminished by the relatively small size limit for qualifying facilities and the short timeframe of the credit.

To estimate the impact of the CHP ITC, the initial cost of industrial CHP plants was reduced by 10 percent during the 2004 through 2006 period. The tax credit was factored into the cash flow calculations for commercial CHP plants. The tax credit is projected to increase CHP capacity additions by 98 megawatts, 51 percent higher than additions of 15-megawatt or smaller CHP systems in the Reference Case. However, the total qualifying capacity added from 2004 through 2006 is projected to be 290 megawatts. Consequently, about 66 percent of the tax credits would be given to purchasers of CHP who would have purchased the equipment without the tax credit.

The overall impact of the CEB on the industrial sector is summarized in Table 9. Generally, the CEB reduces energy prices and energy expenditures slightly compared with the Reference Case (0.7 percent less for both). However, the positive impact of the CHP tax credit is offset by slightly lower average energy prices in the later years of the forecast mainly due to the natural gas provisions, resulting in a slight reduction in end-use CHP capacity in 2025 compared with the Reference Case (0.8 percent).

Transportation

Section 1318 provides tax credits for the purchase of lean-burn technology, hybrid, electric, and fuel cell vehicles. The value of the credit is based on vehicle type (hybrid, fuel cell, etc.), vehicle size (gross vehicle weight rating), efficiency improvement compared to a 2002 model year vehicle, and life-time fuel savings. On average, EIA assumes for the CEB Case that a hybrid vehicle will receive a $1,600 tax credit, fuel cell and electric vehicles will receive a $9,000 tax credit, and lean-burn technology vehicles will receive a $400 tax credit. Tax credits available for hybrid vehicles are limited to 80,000 vehicles per manufacturer.

As a result of the tax credits electric vehicle sales increased by 460 vehicles, from a cumulative total of 60,914 vehicles to 61,374 vehicles, during the period between 2004 and 2012. There are no significant impacts on the sales of hybrid or fuel cell vehicles. This is due primarily to sales requirements for these vehicles mandated under the zero-emission vehicle program, which increases the sales of hybrid, electric, and fuel cell vehicles beyond the market penetration that would be expected without the mandate.

Because the tax credits have no significant impact on the sales of advanced technology, light-duty vehicles, projections of energy use and fuel expenditures show little change between the Reference and CEB Cases (Table 10). Energy use in the CEB Case is slightly lower (0.5 percent by 2025) compared to the Reference Case, but because fuel prices are higher (1.9 percent by 2025) throughout the projection period due to the RFS and MTBE ban, light-duty vehicle fuel expenditures increase by 1.4 percent by 2025.

Tables 1-10

Notes and Sources

Special Topic