‹ Analysis & Projections

Annual Energy Outlook 2014

Release Dates: April 7 - 30, 2014   |  Next Early Release Date: December 2014   |  See schedule

Efficiency from Executive Summary

With more efficient light-duty vehicles, motor gasoline consumption declines while diesel fuel use grows, even as more natural gas is used in heavy-duty vehicles


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The AEO2013 Reference case incorporates the GHG and CAFE standards for LDVs [6] through the 2025 model year. The increase in vehicle efficiency reduces LDV energy use from 16.1 quadrillion Btu in 2011 to 14.0 quadrillion Btu in 2025, predominantly motor gasoline (Figure 6). LDV energy use continues to decline through 2036, then levels off until 2039 as growth in population and vehicle miles traveled offsets more modest improvement in fuel efficiency.

Furthermore, the improved economics of natural gas as a fuel for heavy-duty vehicles result in increased use that offsets a portion of diesel fuel consumption. The use of petroleum-based diesel fuel is also reduced by growing consumption of diesel produced with gas-to-liquids (GTL) technology. Natural gas use in vehicles (including natural gas used in the production of GTL) totals 1.4 trillion cubic feet in 2040 in the Reference case, displacing 0.7 million barrels per day of other motor fuels [7]. Diesel fuel use nonetheless increases at a relatively strong rate, with freight travel demand supported by increasing industrial production.

Efficiency from Market Trends

Energy expenditures decline relative to gross domestic product and gross output


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Total U.S. energy expenditures decline relative to GDP [125] in the AEO2013 Reference case (Figure 47). The projected ratio of energy expenditures to GDP averages 6.8 percent from 2011 to 2040, which is below the historical average of 8.8 percent from 1970 to 2010.


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Figure 48 shows nominal energy expenditures relative to U.S. gross output, which roughly correspond to sales in the U.S. economy. Thus, the figure gives an approximation of total energy expenditures relative to total sales. Energy expenditures as a share of gross output show nearly the same pattern as their share of GDP, declining through 2040. The average shares of gross output relative to expenditures for total energy, petroleum, and natural gas, at 3.5 percent, 2.2 percent, and 0.4 percent, are close to their historical averages of 4.2 percent, 2.1 percent, and 0.7 percent, respectively.

In the United States, average energy use per person declines from 2011 to 2040


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Population growth affects energy use through increases in housing, commercial floorspace, transportation, and economic activity. The effects can be mitigated, however, as the structure and efficiency of the U.S. economy change. In the AEO2013 Reference case, U.S. population increases by 0.9 percent per year from 2011 to 2040; the economy, as measured by GDP, increases at an average annual rate of 2.5 percent; and total energy consumption increases by 0.3 percent per year. As a result, energy intensity, measured both as energy use per person and as energy use per dollar of GDP, declines through the projection period (Figure 52).

The decline in energy use per capita is brought about largely by gains in appliance efficiency and an increase in vehicle efficiency standards by 2025. From 1970 through 2008, energy use dipped below 320 million Btu per person for only a few years in the early 1980s. In 2011, energy use per capita was about 312 million Btu. In the Reference case, it declines to less than 270 million Btu per person in 2034—a level not seen since 1963.

After some recovery through 2020, the economy continues to shift away from manufacturing (particularly, energy-intensive industries such as iron and steel, aluminum, bulk chemicals, and refineries) toward service industries. The energy-intensive industries, which represented about 5.9 percent of total shipments in 2011, represent 4.4 percent in 2040 in the Reference case. Efficiency gains in the electric power sector also reduce overall energy intensity, as older, less efficient generators are retired as a result of slower growth in electricity demand, changing dispatch economics related to fuel prices and stricter environmental regulations.

Residential energy intensity continues to decline across a range of technology assumptions


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In the AEO2013 Reference case, the energy intensity of residential demand, defined as annual energy use per household, declines from 97.2 million Btu in 2011 to 75.5 million Btu in 2040 (Figure 55). The projected 22-percent decrease in intensity occurs along with a 32-percent increase in the number of homes. Residential energy intensity is affected by various factors—for example, population shifts to warmer and drier climates, improvements in the efficiency of building construction and equipment stock, and the attitudes and behavior of residents toward energy savings.

Three alternative cases show the effects of different technology assumptions on residential energy intensity. The 2012 Demand Technology case assumes no future improvement in efficiency for equipment or building shells beyond what is available in 2012. The High Demand Technology case assumes higher efficiency, earlier availability, lower cost, and more frequent energy-efficient purchases for some equipment. The Best Available Demand Technology case limits customer purchases of new and replacement equipment to the most efficient models available at the time of purchase—regardless of cost. This case also assumes that new homes are constructed to the most energy-efficient specifications.

From 2011 to 2040, household energy intensity declines by 31 percent in the High Demand Technology case and by 42 percent in the Best Available Demand Technology case. In the 2012 Demand Technology case, energy intensity is slightly higher than in the Reference case but still declines by 17 percent from 2011 to 2040 as a result of the replacement of pre-2012 appliance stocks with 2012 vintage equipment.

Electricity use per household declines from 2011 to 2040 in the Reference case


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Average electricity demand per household declines by 6 percent in the Reference case, from 12.3 megawatthours in 2011 to 11.5 megawatthours in 2040. As the number of households grows, however, total delivered electricity consumption in the residential sector increases by about 24 percent. Over the same period, residential use of natural gas falls by 12 percent, and use of petroleum and other liquids falls by 25 percent. Total energy demand for most electric end uses increases, even as it declines on a per-household basis. In 2040, space cooling and "other uses" consume 42 percent and 52 percent more electricity, respectively, than in 2011 and remain the largest residential uses of electricity. Electricity use for personal computers (PCs) and related equipment and for clothes washers declines.

The largest reduction in residential electricity use is for lighting (Figure 56). The Energy Independence and Security Act of 2007 (EISA2007) phases in standards that require a reduction of about 30 percent in energy use for general-service lamps between 2012 and 2014, with specific dates that vary by light level. On January 1, 2013, the requirements went into effect for 75-watt incandescent bulbs; the requirements for 100-watt incandescent bulbs went into effect a year earlier. The EISA2007 standards result in the replacement of incandescent bulbs with more efficient compact fluorescent lighting and light-emitting diode (LED) lamps.

Among electric end-use services in the residential sector, lighting demand declines at the fastest rate (1.8 percent per year) and "other uses" rise at the fastest rate (1.4 percent per year). The growth in other uses stems from the introduction of new electrical devices in households, with little coverage by efficiency standards. Electricity use for water heating also increases, but at a slower rate (0.7 percent per year) than the growth in number of households (1.0 percent per year)

Efficiency can offset increases in residential service demand


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The number of households increases by 32 percent, and total residential square footage increases by 41 percent from 2011 to 2040 in the AEO2013 Reference case. Without efficiency improvements, energy demand for uses such as heating, cooling, and lighting would increase at similar rates; however, for many end uses, delivered energy consumption increases more slowly or, in some instances, declines in the Reference case. Three alternative cases show how efficiency improvements could affect energy consumption levels (Figure 57). The High Demand Technology and Best Available Demand Technology cases assume different levels of efficiency improvement without anticipating new appliance standards. The Extended Policies case assumes the enactment of new rounds of standards, generally based on improvements seen in current ENERGY STAR equipment.

Energy consumption declines in the Reference case for two major end uses, space heating and water heating. Energy use for space cooling in the Reference case grows by 42 percent from 2011 to 2040—faster than the number of households, reflecting both population shifts and changes in the number of degree days. In the Best Available Demand Technology case, which includes greater adoption of efficient space cooling equipment, energy use for space cooling declines over the same period.

In all four cases, substantial declines in energy use for lighting reflect EISA2007 efficiency standards. For the category of miscellaneous loads—a wide range of small appliances and electronics, most of which are not currently subject to efficiency standards—delivered energy use increases at the same rate as the number of households in the Extended Policies case (32 percent from 2011 to 2040) and more rapidly than the number of households in the Reference, High Demand Technology, and Best Available Demand Technology cases because of more limited efficiency improvement.

Planned expiration of tax credits affects renewable energy use in the residential sector


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Consistent with current law, existing investment tax credits (ITCs) for residential households installing renewable energy technologies expire at the end of 2016 in the AEO2013 Reference case. The credits can offset 30 percent of installed costs for a variety of technologies, including solar photovoltaic (PV) and wind generators, ground-source heat pumps, and solar thermal water heaters. In the Reference case, expiration of the ITCs drastically slows adoption of renewable technologies. In the AEO2013 No Sunset case, the ITCs are extended through 2040, and the adoption of renewable technologies continues to rise (Figure 58).

In the Reference case, combined PV and wind capacity in the residential sector grows from 1.1 gigawatts in 2011 to 9.5 gigawatts in 2016. After 2016, expiration of the ITCs results in slower growth, with an additional 4.1 gigawatts added from 2017 through 2040. In the No Sunset case, more than 58 gigawatts of residential PV and wind capacity is added over the same period. In all cases, the majority of the added capacity is solar PV rather than wind.

Expiration of the ITCs also affects the penetration of renewable space-conditioning and water-heating equipment. With a 30-percent tax credit available, the number of ground-source heat pumps and solar water heaters grows from a combined 1.3 million units in 2011 to 2.4 million units in 2016; but after 2016 only 1.4 million additional units are added through 2040 in the Reference case. Even in the more optimistic No Sunset case, however, the two renewable technologies are adopted in only a small percentage of households—fewer than 6 percent—by 2040. In the No Sunset case, with the ITC extended, 6.4 million additional units are installed after 2016.

For commercial buildings, pace of decline in energy intensity depends on technology


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Average delivered energy consumption per square foot of commercial floorspace declines at an annual rate of 0.4 percent from 2011 to 2040 in the AEO2013 Reference case (Figure 59), while commercial floorspace grows by 1.0 percent per year. Natural gas consumption increases at about one-half the rate of delivered electricity consumption, which grows by 0.8 percent per year in the Reference case. With ongoing improvements in equipment efficiency and building shells, the growth of energy consumption declines more rapidly than commercial floorspace increases, and the average energy intensity of commercial buildings is reduced.

Three alternative technology cases show the effects of efficiency improvements on commercial energy consumption. The 2012 Demand Technology case limits equipment and building shell efficiencies in later years to those available in 2012. The High Demand Technology case assumes earlier availability, lower costs, and higher efficiencies for equipment and building shells, and a 7-percent real discount rate for energy efficiency investments. The Best Available Demand Technology case assumes more efficient building shells for new and existing buildings than in the High Demand Technology case and limits replacement of new equipment to the most efficient models available in any given year.

The intensity of commercial energy use in the Reference case declines by 10.8 percent, from 105.2 thousand Btu per square foot in 2011 to 93.8 thousand Btu per square foot in 2040. By comparison, average commercial energy intensity drops by about 8.6 percent in the 2012 Demand Technology case, to 96.1 thousand Btu per square foot in 2040, by 20.5 percent in the High Demand Technology, and by 23.9 percent in the Best Available Demand Technology case.

Greatest reduction in energy intensity is in commercial lighting


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Commercial energy intensity, defined as the ratio of energy consumption to floorspace, decreases for most electric end uses from 2011 to 2040 in the AEO2013 Reference case (Figure 60). In 2011, electricity accounted for 52.4 percent of total commercial delivered energy use. Through the projection period, electricity use for lighting declines as a portion of total energy consumption in the Reference case. Advances in solid-state lighting technologies yield lamps with higher efficacy and lower cost, as well as products that can replace, or be retrofitted into, a wide variety of fixture types. As a result, the share of purchased electricity consumption used for lighting declines from 20.8 percent in 2011 to 15.1 percent in 2040 in the Reference case.

Commercial floorspace grows by an average of 1.0 percent per year from 2011 to 2040. Federal efficiency standards, which help to foster technological improvements in end uses such as space heating and cooling, water heating, refrigeration, and lighting, act to limit growth in energy consumption to less than the growth in commercial floorspace. Increasing energy use for miscellaneous electric loads, many of which currently are not subject to federal standards, leads to a 33.9-percent increase in energy intensity from 2011 to 2040 for "other" end uses in the Reference case. Miscellaneous electric loads in the commercial sector include medical equipment and video displays, among many other devices.

Although the recent recession slowed the rate of installation of new data centers, growing demand for web-based services continues to drive growth in energy use for non-PC office equipment, which increases by an average of 1.1 percent per year from 2011 to 2040. Improvements in data center cooling and ventilation equipment, as well as increased server efficiency, continue to moderate the increase.

Efficiency gains for advanced technologies reduce commercial energy consumption growth


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In the AEO2013 Reference case, delivered energy use for core commercial end uses (space heating, space cooling, ventilation, water heating, lighting, cooking, and refrigeration) falls by an average of 0.1 percent per year from 2011 to 2040, even as commercial floorspace increases by 1 percent annually. The share of commercial delivered energy consumption accounted for by the core end uses, which have been the focus of a number of energy efficiency standards, falls from 60 percent in 2011 to 50 percent in 2040. Energy consumption for the remaining end uses grows by 1.4 percent per year, led by other uses of electricity and by non-PC office equipment, including servers.

The largest efficiency gains in the Reference case are expected for lighting as a result of updated cost projections for advanced LED technologies, especially after 2030. Significant gains also are projected for refrigeration, based on provisions in the Energy Policy Act of 2005 and EISA2007, space cooling, electric space heating, and electric water heating (Figure 61).

The Best Available Demand Technology case demonstrates significant potential for further improvements—especially in electric equipment. In this case, the core end uses account for only 43 percent of total delivered energy use in 2040, when their total delivered energy use is more than 1 quadrillion Btu lower than projected in the Reference case. More than 30 percent of the reduction in demand is attributed to lighting, followed by ventilation and space heating. Additional efficiency gains for commercial lighting arise from earlier and more widespread penetration of LED technologies. Other notable contributions result from high-efficiency versions of variable air volume ventilation systems and chillers for space cooling. Overall, delivered energy consumption in 2040 in the Best Available Demand Technology case is only 0.1 quadrillion Btu higher than in 2011, despite a 33-percent increase in commercial floorspace.

Renewable energy fuels most additions to commercial distributed generation capacity

PV and wind account for 58.7 percent of commercial distributed generation capacity in 2040 in the AEO2013 Reference case. Exponential growth of PV capacity has occurred in both new and existing construction during recent years as a result of utility incentives, new financing options, and the 30-percent federal ITC that reverts to 10 percent in 2017. In the Reference case, commercial PV capacity increases by 6.5 percent annually from 2011 to 2040. In the No Sunset case, with ITCs for all distributed generation technologies extended through 2040, PV capacity increases by an average of 7.4 percent per year.


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Small-scale wind capacity increases by 7.4 percent per year from 2011 to 2040 in the Reference case and by an even greater 12.6 percent per year from 2011 to 2040 in the No Sunset case (Figure 62). As with PV, additional federal and local incentives help to drive growth in commercial wind capacity. Wind capacity accounts for 10.7 percent of the 28.4 gigawatts of total distributed generation capacity in 2040 in the No Sunset case, and PV accounts for 55.2 percent.

Rising fuel prices offset the effects of the 10-percent ITC on nonrenewable technologies for distributed generation. In the Reference case, microturbine capacity using natural gas grows by 15.0 percent per year on average, from 83.3 megawatts in 2011 to 4.7 gigawatts in 2040; and the growth rate in the No Sunset case is only slightly higher, at 15.3 percent. The microturbine share of total DG capacity in 2040 is 18.0 percent in the No Sunset case, as compared with 21.6 percent in the Reference case, and fuel cell capacity grows at an annual rate of roughly 10.9 percent in the Reference case and 11.3 percent in the No Sunset case.

CAFE and greenhouse gas emissions standards boost light-duty vehicle fuel economy


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The 1978 introduction of corporate average fuel economy (CAFE) standards for LDVs increased their average fuel economy from 19.9 mpg in 1978 to 26.2 mpg in 1987. Despite technological improvement, fuel economy fell to between 24 and 27 mpg over the next two decades, as sales of light trucks increased from 18 percent of new LDV sales in 1980 to 55 percent in 2004 [127]. The subsequent rise in fuel prices, reduction in sales of light trucks, and more stringent CAFE standards for light-duty trucks starting in model year (MY) 2008 and for passenger cars in MY 2011, resulted in a rise in estimated LDV fuel economy to 29.0 mpg in 2011 [128].

The National Highway Traffic Safety Administration (NHTSA) and the U.S. Environmental Protection Agency have jointly announced new GHG emissions and CAFE standards for MY 2012 through MY 2025 [129], [130]], which are included in AEO2013. As a result, the fuel economy of new LDVs, measured in terms of their compliance values in CAFE testing [131], rises from 32.5 mpg in 2012 to 47.3 mpg in 2025 (Figure 71). The GHG emissions and CAFE standards are held roughly constant after 2025, but fuel economy continues to rise, to 49.0 mpg in 2040, as new fuel-saving technologies are adopted. In 2040, passenger car fuel economy averages 56.1 mpg and light-duty truck fuel economy averages 40.5 mpg.

Sales of alternative fuel, fuel flexible, and hybrid vehicles sales rise


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LDVs that use diesel, other alternative fuels, hybrid-electric, or all-electric systems play a significant role in meeting more stringent GHG emissions and CAFE standards over the projection period. Sales of such vehicles increase from 20 percent of all new LDV sales in 2011 to 49 percent in 2040 in the AEO2013 Reference case.

Micro hybrid vehicles, defined here as conventional gasoline vehicles with micro hybrid systems that manage engine operation at idle, represent 28 percent of new LDV sales in 2040, the largest share among vehicles using diesel, alternative fuels, hybrid-electric, or all-electric systems.

Flex-fuel vehicles (FFVs), which can use blends of ethanol up to 85 percent, represent the second largest share of these vehicle types in 2040, at 7 percent of all new LDV sales. Current incentives for manufacturers selling FFVs, which are available in the form of fuel economy credits earned for CAFE compliance, expire in 2019. As a result, the FFV share of LDV sales rises over the next decade and then declines.

Sales of hybrid electric and all-electric vehicles that use stored electric energy for motive power grow considerably in the Reference case (Figure 73). Gasoline- and diesel-electric hybrid vehicles account for 6 percent of total LDV sales in 2040; and plug-in hybrid and all-electric vehicles account for 3 percent of total LDV sales, or 6 percent of sales of vehicles using diesel, alternative fuels, hybrid, or all-electric systems.

The diesel vehicle share of total sales remains constant over the projection period at about 4 percent of total LDV sales. Light-duty gaseous and fuel cell vehicles account for less than 1 percent of new vehicle sales throughout the projection period because of limited fueling infrastructure and high incremental vehicle costs.

Growth in electricity use slows but still increases by 28 percent from 2011 to 2040


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The growth of electricity demand (including retail sales and direct use) has slowed in each decade since the 1950s, from a 9.8-percent annual rate of growth from 1949 to 1959 to only 0.7 percent per year in the first decade of the 21st century. In the AEO2013 Reference case, electricity demand growth remains relatively slow, as increasing demand for electricity services is offset by efficiency gains from new appliance standards and investments in energy-efficient equipment (Figure 75). Total electricity demand grows by 28 percent in the projection (0.9 percent per year), from 3,839 billion kilowatthours in 2011 to 4,930 billion kilowatthours in 2040.

Retail electricity sales grow by 24 percent (0.7 percent per year) in the Reference case, from 3,725 billion kilowatthours in 2011 to 4,608 billion kilowatthours in 2040. Residential electricity sales also grow by 24 percent, to 1,767 billion kilowatthours in 2040, spurred by population growth and continued population shifts to warmer regions with greater cooling requirements. Led by demand in the service industries, sales of electricity to the commercial sector increase by 27 percent, to 1,677 billion kilowatthours in 2040. Sales to the industrial sector grow by 17 percent, to 1,145 billion kilowatthours in 2040. Electricity sales to the transportation sector, although relatively small, triple from 6 billion kilowatthours in 2011 to 19 billion kilowatthours in 2040 with increasing sales of electric plug-in LDVs.

Electricity demand can vary with different assumptions about economic growth, electricity prices, and advances in energy-efficient technologies. In the High Economic Growth case, demand grows by 42 percent from 2011 to 2040, compared with 18 percent in the Low Economic Growth case and only 7 percent in the Best Available Technology case. Average electricity prices (in 2011 dollars) increase by 5 percent from 2011 to 2040 in the Low Economic Growth case and 13 percent in the High Economic Growth case, to 10.4 and 11.2 cents per kilowatthour, respectively, in 2040.

State renewable portfolio standards increase renewable electricity generation


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Regional growth in nonhydroelectric renewable electricity generation is based largely on three factors: availability of renewable energy resources, cost competitiveness with fossil fuel technologies, and the existence of state RPS programs that require the use of renewable generation. After a period of robust RPS enactments in several states, the past few years have been relatively quiet in terms of state program expansions.

In the AEO2013 Reference case, the highest level of nonhydroelectric renewable generation in 2040, at 104 billion kilowatthours, occurs in the WECC California (CAMX) region (Figure 84), whose area approximates the California state boundaries. (For a map of the electricity regions and a definition of the acronyms, see Appendix F.) The three largest sources of nonhydro-electric renewable generation in 2040 in that region are geothermal, solar, and wind energy. The region encompassing the Pacific Northwest has the most renewable generation in the United States when hydroelectric is included, which is the source of most of the region's renewable electricity generation.

State RPS programs heavily influence the growth of solar capacity in the eastern states. A prime example is the Reliability First Corporation/East (RFCE) region, where 7.5 billion kilowatthours of electricity is generated from solar resources in 2040, mostly from end-use capacity. The RFCE region is not known for a strong solar resource base, and the projected installations are in response to the federal tax credits, state incentives, and solar energy requirements embedded in state RPS programs. The CAMX region has the highest total for solar generation in 2040 at 36 billion kilowatthours, including 10 billion kilowatthours of generation from end-use solar capacity.

Renewable Fuel Standard and California Low Carbon Fuel Standard boost the use of new fuels


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In response to the RFS implemented nationwide and the California Low Carbon Fuel Standard (LCFS), consumption of advanced biofuels increases in the AEO2013 Reference case (Figure 101). As defined in the RFS, the advanced renewable fuels category consists of fuels that achieve a 50-percent reduction in life-cycle GHG emissions (including indirect changes in land use). The advanced fuel category includes ethanol produced from sugar cane (but not from corn starch), biodiesel, renewable diesel, and cellulosic biofuels [141]. California uses a large fraction of the total advanced renewable fuel pool in the early years of the projection.

Under the California LCFS, each fuel is considered individually according to its carbon intensity relative to the LCFS target. In general, fuels that qualify as advanced renewable fuels under the RFS have low carbon intensities for the purposes of the California LCFS, but the reverse is not always true.

Starting about 2030, production of cellulosic drop-in biofuels ramps up in California and other states. Outside California, production and consumption of cellulosic biofuels increases rapidly enough to cause a decline in California's fraction of the total advanced biofuels market. Starting in about 2035, corn ethanol with low carbon intensity begins to displace imported sugar cane ethanol in California.

Efficiency standards shift consumption from motor gasoline to diesel fuel


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Based on NHTSA estimates, more stringent efficiency standards for LDVs will require new LDVs to average approximately 49 mpg in 2025, in addition to regulations requiring increased use of ethanol. The combination contributes to a decline in consumption of motor gasoline and an increase in consumption of diesel fuel and ethanol in the AEO2013 Reference case. Motor gasoline consumption falls despite an increase in VMT by LDVs over the projection period.

The decrease in gasoline consumption, combined with growth in diesel consumption, leads to a shift in refinery outputs and investments. Motor gasoline consumption and diesel fuel consumption trend in opposite directions in the Reference case: consumption of diesel fuel increases by approximately 0.8 million barrels per day from 2011 to 2040, while finished motor gasoline consumption falls by 1.6 million barrels per day (Figure 102). Although some smaller and less-integrated refineries begin to idle capacity as a result of higher costs, new refinery projects focus on shifting production from gasoline to distillate fuels to meet growing demand for diesel.

In the Reference case, as a result of refinery economics and slower growth in domestic demand, no new petroleum refinery capacity expansions are built during the projection period besides those already under construction. Further, approximately 200,000 barrels per day of capacity is retired, beginning in 2012. In addition to meeting domestic demand, refineries continue exporting finished products to international markets throughout the projection period. From 2014 to 2017 gross exports of finished products increase to more than 3.0 million barrels per day for the first time, and they remain near that level through 2040. Further, the United States, which became a net exporter of finished products in 2011, remains a net exporter through 2040 in the Reference case.

Efficiency from Legislation and Regulations

1. Greenhouse gas emissions and corporate average fuel economy standards for 2017 and later model year light-duty vehicles

On October 15, 2012, EPA and the National Highway Traffic Safety Administration (NHTSA) jointly issued a final rule for tailpipe emissions of carbon dioxide (CO2) and CAFE standards for light-duty vehicles, model years 2017 and beyond [16]. EPA, operating under powers granted by the Clean Air Act (CAA), issued final CO2 emissions standards for model years 2017 through 2025 for passenger cars and light-duty trucks, including medium-duty passenger vehicles. NHTSA, under powers granted by the Energy Policy and Conservation Act, as amended by the Energy Independence and Security Act, issued CAFE standards for passenger cars and light-duty trucks, including medium-duty passenger vehicles, for model years 2017 through 2025.

The new CO2 emissions and CAFE standards will first affect model year 2017 vehicles, with compliance requirements increasing in stringency each year thereafter through model year 2025. EPA has established standards that are expected to require a fleet-wide average of 163 grams CO2 per mile for light-duty vehicles in model year 2025, which is equivalent to a fleet-wide average of 54.5 miles per gallon (mpg) if reached only through fuel economy. However, the CO2 emissions standards can be met in part through reductions in air-conditioning leakage and the use of alternative refrigerants, which reduce CO2-equivalent GHG emissions but do not affect the estimation of fuel economy compliance in the test procedure.

NHTSA has established two phases of CAFE standards for passenger cars and light-duty trucks (Table 1). The first phase, covering model years 2017 through 2021, includes final standards that NHTSA estimates will result in a fleet-wide average of 40.3 mpg for light-duty vehicles in model year 2021 [17]. The second phase, covering model years 2022 through 2025, requires additional improvements leading to a fleet-wide average of 48.7 mpg for light-duty vehicles in model year 2025. Compliance with CO2 emission and CAFE standards is calculated only after final model year vehicle production, with fleet-wide light-duty vehicle standards representing averages based on the sales volume of passenger cars and light-duty trucks for a given year. Because sales volumes are not known until after the end of the model year, EPA and NHTSA estimate future fuel economy based on the projected sales volumes of passenger cars and light-duty trucks.

Figure 9. Projected average passenger car CAFE compliance targets (miles per gallon) by vehicle footprint (square feet), model years 2017-2026
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The new CO2 emissions and CAFE standards for passenger cars and light-duty trucks use an attribute-based standard that is determined by vehicle footprint—the same methodology that was used in setting the final rule for model year 2012 to 2016 light-duty vehicles. Footprint is defined as wheelbase size (the distance from the center of the front axle to the center of the rear axle), multiplied by average track width (the distance between the center lines of the tires) in square feet. The minimum requirements for CO2 emissions and CAFE are production-weighted averages based on unique vehicle footprints in a manufacturer's fleet and are calculated separately for passenger cars and light-duty trucks (Figures 9 and 10), reflecting their different design capabilities. In general, as vehicle footprint increases, compliance requirements decline to account for increased vehicle size and load-carrying capability. Each manufacturer faces a unique combination of CO2 emission and CAFE standards, depending on the number of vehicles produced and the footprints of those vehicles, separately for passenger cars and light-duty trucks.

Figure 9. Projected average passenger car CAFE compliance targets (miles per gallon) by vehicle footprint (square feet), model years 2017-2026
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For passenger cars, average fleet-wide compliance levels increase in stringency by 3.9 percent annually between model years 2017 and 2021 and by 4.7 percent annually between 2022 and 2025, based on the model year 2010 baseline fleet. In recognition of the challenge of improving the fuel economy and reducing CO2 emissions of full-size pickup trucks while maintaining towing and payload capabilities, the average annual rate of increase in the stringency of light-duty truck standards is 2.9 percent from 2017 to 2021, with smaller light-duty trucks facing higher increases and larger light-duty trucks lower increases in compliance stringency. From 2022 to 2025, the average annual increase in compliance stringency for all light-duty trucks is 4.7 percent.

The CO2 emissions and CAFE standards also include flexibility provisions for compliance by individual manufacturers, such as: (1) credit averaging, which allows credit transfers between a manufacturer's passenger car and light-duty truck fleets; (2) credit banking, which allows manufacturers to "carry forward" credits earned from exceeding the standards in earlier model years and to "carry back" credits earned in later model years to offset shortfalls in earlier model years; (3) credit trading between manufacturers who exceed their standards and those who do not; (4) air conditioning improvement credits that can be applied toward CO2 emissions standards; (5) off-cycle credits for measurable improvements in CO2 emissions and fuel economy that are not captured by the two-cycle test procedure used to measure emissions and fuel consumption; (6) CO2 emissions "compliance multipliers" for electric, plug-in hybrid electric, compressed natural gas, and fuel cell vehicles through model year 2021; and (7) incentives for the use of hybrid electric and other advanced technologies in full-size pickup trucks.

Finally, flexibility provisions do not allow domestic passenger cars to deviate significantly from annual fuel economy targets. NHTSA retains a required minimum fuel economy level for domestically produced passenger cars by manufacturer that is the higher of 27.5 miles per gallon or 92 percent of the average fuel economy projected for the combined fleet of domestic and foreign passenger cars for sale in the United States. For example, the minimum standard for passenger cars sold by a manufacturer in 2025 would be 50.9 miles per gallon, based on the estimated fleet average passenger car fuel economy for that year.

The AEO2013 Reference case includes the final CAFE standards for model years 2012 through 2016 (promulgated in March 2010) [18] and the standards for model years 2017 through 2025, with subsequent CAFE standards for years 2026-2040 vehicles calculated using 2025 levels of stringency. The AEO2013 Reference case projects fuel economy values for passenger cars, light-duty trucks, and combined light-duty vehicles that differ from NHTSA projections. This variance is the result of a different distribution of the production of passenger cars and light-duty trucks by footprint as well as a different mix between passenger cars and light-duty trucks (Table 2). CAFE standards are included by using the equations and coefficients employed by NHTSA to determine unique fuel economy requirements based on footprint, along with the ability of manufacturers to earn flexibility credits toward compliance. The AEO2013 Reference case projects sales of passenger cars and light-duty trucks by vehicle footprint with the key assumption that vehicle footprints are held constant by manufacturer in each light-duty vehicle size class.

4. Maximum Achievable Control Technology for industrial boilers

Section 112 of the CAA requires the regulation of air toxics through implementation of NESHAP for industrial, commercial, and institutional boilers [31]. The final regulations are also known as "Boiler MACT," where MACT is the Maximum Achievable Control Technology. Pollutants covered by the Boiler MACT regulations include control of hazardous air pollutants (HAPs), such as hydrogen chloride, mercury (Hg), and dioxin/furan, as well as carbon monoxide (CO), and particulate matter (PM) as surrogates for other HAPs. Boilers used for generating electricity are explicitly covered by the Mercury and Air Toxics Standards, also under Section 112 of the CAA, and are specifically excluded from Boiler MACT regulations.

The Final Rule for Boiler MACT was issued in March 2011; a partial Reconsideration Rule concerning limited technical corrections to the Final Rule was issued in December 2011, but it did not replace the Final Rule. The AEO2013 Reference case assumes that the Final Rule and the partial Reconsideration Rules are in force. The finalized Boiler MACT rule was announced in December 2012, after the modeling work for AEO2013 was completed. The provisions of the finalized Boiler MACT rule are less stringent than the provisions of the Final Rule and the partial Reconsideration Rule assumed in the Reference case. For AEO2013, the upgrade costs of Boiler MACT were implemented in the Macroeconomic Activity Module (MAM). Upgrade costs used are the "nonproductive costs," which are not associated with efficiency improvements. The upgrade costs are applied as an aggregated cost across all industries. Because of this aggregation of cost and the need for consistency across industries, the cost in the MAM is manifested as a reduction in shipments in the Industrial Demand Module. There is little difference in the cost of compliance for major sources between the March 2011 Final Rule and the December 2011 Reconsideration Rule, and there is no difference for area sources.

Boiler MACT has two compliance groups with different obligations: major source [32], and area source. A site that contains one or more boilers or process heaters that have the potential to emit 10 or more tons of any one HAP per year, or 25 tons or more of a combination of HAP per year, is a major source [33]. An emissions site that is not a major source is classified as an area source[34]. The characteristics of the site determine the compliance group of the boiler. Generally, compliance measures include regular maintenance and tuneups for smaller facilities and emission limits and performance tests for larger facilities. In the Reconsideration Rule, EIA calculations based on EPA estimates revealed that there were 14,111 existing major source boilers in 2011 [35]. Of those, calculations based on EPA estimates revealed that 16 percent burn fuels that potentially may subject them to specific emissions limits and annual performance tests. The existing number of affected area source boilers in 2011 was estimated at 189,450 by EIA, using data from EPA [36].

To comply with Boiler MACT, major source boilers and process heaters whose heat input is less than 10 million Btu per hour must receive tuneups every 2 years [37]. Most existing and new major source boilers or process heaters with heat inputs 10 million Btu per hour or greater that burn coal, biomass, liquid, or "other" gas are subject to emission limits on all five of the HAP listed above [38]. Larger major source boilers with heat input of 25 million Btu per hour or greater that burn coal, biomass, or residual oil must use a continuous emission monitoring system for PM [39]. Major source boilers with heat inputs of 10 million Btu per hour or more that burn natural gas or refinery gas, as well as metal process furnaces, are not subject to specific emissions limits or performance tests [40]. Existing major source boilers must comply with the Final Rule by March 21, 2014; new major source boilers must comply by May 20, 2011, or upon startup, whichever is later [41].

Area source natural gas-fired boilers are not subject to Boiler MACT. Area source coal-fired boilers whose heat input is less than 10 million Btu per hour and biomass-fired and liquid fuel-fired boilers of any size must receive a tuneup every 2 years. Existing area source boilers with heat input of 10 million Btu per hour or greater are subject to emissions limits, must receive an initial energy assessment, and must undergo performance tests every 3 years [42]. Existing and new coal-fired boilers must meet Hg and CO limits; new coal-fired boilers must also meet limits for PM. New oil-fired and biomass-fired boilers must meet emissions limits only for PM [43]. Existing area source boilers subject to an energy assessment and emissions limits must comply by March 21, 2014.

5. State renewable energy requirements and goals: Update through 2012

To the extent possible, AEO2013 incorporates the impacts of state laws requiring the addition of renewable generation or capacity by utilities doing business in the states. Currently, 30 states and the District of Columbia have an enforceable renewable portfolio standard (RPS) or similar law (Table 3). Under such standards, each state determines its own levels of renewable generation, eligible technologies [44], and noncompliance penalties. AEO2013 includes the impacts of all RPS laws in effect at the end of 2012 (with the exception of Alaska and Hawaii, because NEMS provides electricity market projections for the contiguous lower 48 states only). However, the projections do not include policies with either voluntary goals or targets that can be substantially satisfied with nonrenewable resources. In addition, NEMS does not treat fuel-specific provisions—such as those for solar and offshore wind energy—as distinct targets. Where applicable, such distinct targets (sometimes referred to as "tiers," "set-asides," or "carve-outs") may be subsumed into the broader targets, or they may not be included in the modeling because they could be met with existing capacity and/or projected growth based on modeled economic and policy factors.

In the AEO2013 Reference case, states generally are projected to meet their ultimate RPS targets. The RPS compliance constraints in most regions are approximated, because NEMS is not a state-level model, and each state generally represents only a portion of one of the NEMS electricity regions. Compliance costs in each region are tracked, and the projection for total renewable generation is checked for consistency with any state-level cost-control provisions, such as caps on renewable credit prices, limits on state compliance funding, or impacts on consumer electricity prices. In general, EIA has confirmed the states' requirements through original documentation, although the Database of State Incentives for Renewables & Efficiency was also used to support those efforts [45].

No new RPS programs were enacted over the past year; however, some states with existing RPS programs made modifications in 2012, as discussed below. The aggregate RPS requirement for the various state programs, as modeled in AEO2013, is shown in Figure 12. In 2025 the targets account for about 10 percent of U.S. electricity sales. The requirement is derived from the legal targets and projected sales and does not account for any of the discretionary or nondiscretionary waivers or limits on compliance found in most state RPS programs.

At present, most states are meeting or exceeding their required levels of renewable generation based on qualified generation [46]. A number of factors have helped to create an environment favorable for RPS compliance, including a surge of new RPS-qualified generation capacity timed to take advantage of federal incentives that either have expired or were scheduled to expire; significant reductions in the cost of renewable technologies like wind and solar; and generally reduced growth (or, in some cases, even contraction) of electricity sales. In addition to the availability of federal tax credits, which historically have gone through a cycle of expiration and renewal, renewable energy projects were given access to other options for federal support, including cash grants (also known as Section 1603 grants) and loan guarantees. The short-term availability of federal incentives has helped to make renewable capacity attractive to investors and helped utilities meet state requirements or potential future load growth in advance (that is, build ahead of time to take advantage of the federal incentives). The attractiveness of renewable projects to investors has also been supported by declining equipment costs for wind turbines and solar photovoltaic systems, as well as by improvements in the performance of those technologies. The declines in technology cost are, in themselves, the result of a complex set of interactions of policy, market, and engineering factors. Finally, most state RPS programs have targets that are tied to retail electricity sales; and with relatively slow growth in electricity sales in most parts of the country, the renewable generation that has entered service recently has gone further toward meeting the proportionally lower targets for absolute amounts of energy (that is, for kilowatthours of energy, as opposed to energy as a percent of sales).

Total renewable generation required for combined state renewable portfolio standards and projected total achieved, 2012-2040
figure data

EIA projects that, overall, RPS-qualified generation will continue to meet or exceed aggregate targets for state RPS programs through 2040, as shown in Figure 12. Through the next decade, the surplus qualifying generation will decline gradually, as little additional qualifying capacity is added, allowing the targets to catch up with supply. By the end of the projection horizon, however, the surplus widens substantially as renewable generation technologies become increasingly competitive with conventional generation sources. It should be noted that the aggregate targets and qualifying generation shown in Figure 12 may mask significant regional variation, with some regions producing excess qualifying generation and others producing just enough to meet the requirement or even needing to import generation from adjoining regions to meet state targets. Furthermore, just because there is, in aggregate, more qualifying generation than is needed to meet the targets, this does not necessarily imply that projected generation would be the same without state RPS policies. State RPS policies may encourage investment in places where it otherwise would not occur, or would not occur in the amounts projected, even as other parts of the country see substantial growth above state targets, or even in their absence. It does, however, suggest that state RPS programs will not be the sole reason for future growth in renewable generation.

Recent RPS modifications

A number of states modified their RPS programs in 2012, either through regulatory proceedings or through legislative action. These changes are reflected in Table 3. The changes affect some aspects of the laws and implementing regulations, but they do not have substantive effects on the representation of the RPS programs in AEO2013. Key changes include:

California

California Assembly Bill 2196, which establishes requirements for certain biomass-based generation resources, requires that biomass-derived gas be produced on site or sourced from a common carrier pipeline that operates within the state. It also sets additional requirements related to the in-service date of a common carrier source and the ability to claim certain environmental benefits from the use of such sources.

Maryland

The state enacted a series of bills that accelerate the solar-specific compliance schedule (while leaving the aggregate RPS target unchanged) and expand the tier 1 requirement category to include thermal output from certain animal waste and ground-source heat pumps.

Massachusetts

The Department of Energy Resources issued final rules regarding the use of certain biomass resources to meet the RPS standard. Biomass facilities must meet certain conditions with regard to conversion technology and feedstock sourcing to be eligible for use in meeting the standard.

New Hampshire

Senate Bill 218 allows certain thermal resources, including heat derived from qualified solar, geothermal, and biomass sources, to meet renewable energy targets. It also allows electricity produced from the cofiring of biomass in certain existing coal plants to meet the requirements. The bill also adjusts the total renewable energy target upward by 1 percentage point, to 24.8 percent by 2025.

New Jersey

Senate Bill 1925 changed the compliance schedule for the solar component of the RPS. The revised law is implemented with a solar target of 3.47 percent of sales by 2021.

Ohio

The legislature passed a set of laws that allow certain types of cogeneration facilities to qualify in meeting the RPS.

Efficiency from Issues in Focus

1. No sunset and extended policies cases

Background

The AEO2013 Reference case is best described as a current laws and regulations case because it generally assumes that existing laws and regulations remain unchanged throughout the projection period, unless the legislation establishing them sets a sunset date or specifies how they will change. The Reference case often serves as a starting point for analysis of proposed changes in legislation or regulations. While the definition of the Reference case is relatively straightforward, there may be considerable interest in a variety of alternative cases that reflect updates or extensions of current laws and regulations. Areas of particular interest include:

  • Laws or regulations that have a history of being extended beyond their legislated sunset dates. Examples include the various tax credits for renewable fuels and technologies, which have been extended with or without modifications several times since their initial implementation.
  • Laws or regulations that call for periodic updating of initial specifications. Examples include appliance efficiency standards issued by the U.S. Department of Energy (DOE) and CAFE and greenhouse gas (GHG) emissions standards for vehicles issued by the National Highway Traffic Safety Administration (NHTSA) and the U.S. Environmental Protection Agency (EPA).
  • Laws or regulations that allow or require the appropriate regulatory agency to issue new or revised regulations under certain conditions. Examples include the numerous provisions of the Clean Air Act that require EPA to issue or revise regulations if it finds that an environmental quality target is not being met.

Two alternative cases are discussed in this section to provide some insight into the sensitivity of results to scenarios in which existing tax credits or other policies do not sunset. No attempt is made to cover the full range of possible uncertainties in these areas, and readers should not view the cases discussed as EIA projections of how laws or regulations might or should be changed. The cases examined here look only at federal laws or regulations and do not examine state laws or regulations.

Analysis cases

The two cases prepared—the No Sunset case and the Extended Policies case—incorporate all the assumptions from the AEO2013 Reference case, except as identified below. Changes from the Reference case assumptions include the following.

No Sunset case

Tax credits for renewable energy sources in the utility, industrial, and buildings sectors, or for energy-efficient equipment in the buildings sector, are assumed to be extended, including the following:

  • The PTC of 2.2 cents per kilowatthour and the 30-percent investment tax credit (ITC) available for wind, geothermal, biomass, hydroelectric, and landfill gas resources, assumed in the Reference case to expire at the end of 2012 for wind and 2013 for the other eligible resources, are extended indefinitely. On January 1, 2013, Congress passed a one-year extension of the PTC for wind and modified the qualification rules for all eligible technologies; these changes are not included in the AEO2013 Reference case, which was completed in December 2012, but they are discussed in "Effects of energy provisions in the American Taxpayer Relief Act of 2012".
  • For solar power investments, a 30-percent ITC that is scheduled to revert to a 10-percent credit in 2016 is, instead, assumed to be extended indefinitely at 30 percent.
  • In the buildings sector, personal tax credits for the purchase of renewable equipment, including photovoltaics (PV), are assumed to be extended indefinitely, as opposed to ending in 2016 as prescribed by current law. The business ITCs for commercial-sector generation technologies and geothermal heat pumps are assumed to be extended indefinitely, as opposed to expiring in 2016; and the business ITC for solar systems is assumed to remain at 30 percent instead of reverting to 10 percent. On January 1, 2013, legislation was enacted to reinstate tax credits for energy-efficient homes and selected residential appliances. The tax credits that had expired on December 31, 2011, are now extended through December 31, 2013. This change is not included in the Reference case.
  • In the industrial sector, the 10-percent ITC for combined heat and power (CHP) that ends in 2016 in the AEO2013 Reference case [65] is assumed to be preserved through 2040, the end of the projection period.

Extended Policies case

The Extended Policies case includes additional updates to federal equipment efficiency standards that were not considered in the Reference case or No Sunset case. Residential and commercial end-use technologies eligible for incentives in the No Sunset case are not subject to new standards. Other than those exceptions, the Extended Policies case adopts the same assumptions as the No Sunset case, plus the following:

  • Federal equipment efficiency standards are assumed to be updated at periodic intervals, consistent with the provisions in existing law, at levels based on ENERGY STAR specifications or on the Federal Energy Management Program purchasing guidelines for federal agencies, as applicable. Standards are also introduced for products that currently are not subject to federal efficiency standards.
  • Updated federal energy codes for residential and commercial buildings increase by 30 percent in 2020 compared to the 2006 International Energy Conservation Code in the residential sector and the American Society of Heating, Refrigerating and Air-Conditioning Engineers Building Energy Code 90.1-2004 in the commercial sector. Two subsequent rounds in 2023 and 2026 each add an assumed 5-percent incremental improvement to building energy codes. The equipment standards and building codes assumed for the Extended Policies case are meant to illustrate the potential effects of those policies on energy consumption for buildings. No cost-benefit analysis or evaluation of impacts on consumer welfare was completed in developing the assumptions. Likewise, no technical feasibility analysis was conducted, although standards were not allowed to exceed the "maximum technologically feasible" levels described in DOE's technical support documents.
  • The AEO2013 Reference, No Sunset, and Extended Policies cases include both the attribute-based CAFE standards for light-duty vehicles (LDVs) in model year (MY) 2011 and the joint attribute-based CAFE and vehicle GHG emissions standards for MY 2012 to MY 2025. The Reference and No Sunset cases assume that the CAFE standards are then held constant at MY 2025 levels in subsequent model years, although the fuel economy of new LDVs continues to rise modestly over time. The Extended Policies case modifies the assumption in the Reference and No Sunset cases, assuming continued increases in CAFE standards after MY 2025. CAFE standards for new LDVs are assumed to increase by an annual average rate of 1.4 percent.
  • In the industrial sector, the ITC for CHP is extended to cover all properties with CHP, no matter what the system size (instead of being limited to properties with systems smaller than 50 megawatts as in the Reference case [66]), which may include multiple units. Also, the ITC is modified to increase the eligible CHP unit cap to 25 megawatts from 15 megawatts. These extensions are consistent with previously proposed legislation.

Analysis results

The changes made to the Reference case assumptions in the No Sunset and Extended Policies cases generally lead to lower estimates for overall energy consumption, increased use of renewable fuels particularly for electricity generation and reduced energy-related carbon dioxide (CO2) emissions. Because the Extended Policies case includes most of the assumptions in the No Sunset case but adds others, the effects of the Extended Policies case tend to be greater than those in the No Sunset case—but not in all cases, as discussed below. Although these cases show lower energy prices, because the tax credits and end-use efficiency standards lead to lower energy demand and reduce the costs of renewable technologies, appliance purchase costs are also affected. In addition, the government receives lower tax revenues as consumers and businesses take advantage of the tax credits.

Energy consumption


figure data

Total energy consumption in the No Sunset case is close to the level in the Reference case (Figure 13). Improvements in energy efficiency lead to reduced consumption in this case, but somewhat lower energy prices lead to relatively higher levels of consumption, partially offsetting the impact of improved efficiency. In 2040, total energy consumption in the Extended Policies case is 3.8 percent below the Reference case projection.

Buildings energy consumption

Renewable distributed generation (DG) technologies (PV systems and small wind turbines) provide much of the buildings-related energy savings in the No Sunset case. Extended tax credits in the No Sunset case spur increased adoption of renewable DG, leading to 61 billion kilowatthours of onsite electricity generation from DG systems in 2025, compared with 28 billion kilowatthours in the Reference case. Continued availability of the tax credits results in 137 billion kilowatthours of onsite electricity generation in 2040 in the No Sunset case—more than three times the amount of onsite electricity generated in 2040 in the Reference case. Similar adoption of renewable DG occurs in the Extended Policies case. With the additional efficiency gains from assumed future standards and more stringent building codes, delivered energy consumption for buildings is 3.9 percent (0.8 quadrillion British thermal units [Btu]) lower in 2025 and 8.0 percent (1.7 quadrillion Btu) lower in 2040 in the Extended Policies case than in the Reference case. The reduction in 2040 is more than seven times as large as the 1.1-percent (0.2 quadrillion Btu) reduction in the No Sunset case.

Electricity use shows the largest reduction in the two alternative cases compared to the Reference case. Building electricity consumption is 1.3 percent and 5.8 percent lower, respectively, in the No Sunset and Extended Policies cases in 2025 and 2.1 percent and 8.7 percent lower, respectively, in 2040 than in the Reference case, as onsite generation continues to increase and updated standards affect a greater share of the equipment stock in the Extended Policies case. Space heating and cooling are affected by the assumed standards and building codes, leading to significant savings in energy consumption for heating and cooling in the Extended Policies case. In 2040, delivered energy use for space heating in buildings is 9.6 percent lower, and energy use for space cooling is 20.3 percent lower, in the Extended Policies case than in the Reference case. In addition to improved standards and codes, extended tax credits for PV prompt increased adoption, offsetting some of the costs for purchased electricity for cooling. New standards for televisions and for personal computers and related equipment in the Extended Policies case lead to savings of 28.3 percent and 31.8 percent, respectively, in residential electricity use for this equipment in 2040 relative to the Reference case. Residential and commercial natural gas use declines from 8.1 quadrillion Btu in 2011 to 7.8 quadrillion Btu in 2025 and 7.2 quadrillion Btu in 2040 in the Extended Policies case, representing a 2.2-percent reduction in 2025 and a 8.5-percent reduction in 2040 relative to the Reference case.

Industrial energy consumption

The No Sunset case modifies the Reference case assumptions by extending the existing ITC for industrial CHP through 2040. The Extended Policies case starts from the No Sunset case and expands the credit to include industrial CHP systems of all sizes and raises the maximum credit that can be claimed from 15 megawatts of installed capacity to 25 megawatts. The changes result in 1.6 gigawatts of additional industrial CHP capacity in the No Sunset case compared with the Reference case in 2025 and 3.5 gigawatts of additional capacity in 2040. From 2025 through 2040, more CHP capacity is installed in the No Sunset case than in the Extended Policy case. CHP capacity is 0.3 gigawatts higher in the No Sunset Case than in the Extended Policies Case in 2025 and 1.2 gigawatts higher in 2040. Although the Extended Policies case includes a higher tax benefit for CHP than the No Sunset case, which by itself provides greater incentive to build CHP capacity, electricity prices are lower in the Extended Policies case than in the No Sunset case starting around 2020, and the difference increases over time. Lower electricity prices, all else equal, reduce the economic attractiveness of CHP. Also, the median size of industrial CHP units size is 10 megawatts [67], and many CHP systems are well within the 50-megawatt total system size, which means that relaxing the size constraint is not as strong an incentive for investment as is allowing the current tax credit for new CHP investments to continue after 2016.

Natural gas consumption averages 9.7 quadrillion Btu per year in the industrial sector from 2011 to 2040 in the No Sunset case—about 0.1 quadrillion Btu, or 0.9 percent, above the level in the Reference case. Over the course of the projection, the difference in natural gas consumption between the No Sunset case and the Reference case is small but increases steadily. In 2025, natural gas consumption in the No Sunset case is approximately 0.1 quadrillion Btu higher than in the Reference Case, and in 2040 it is 0.2 quadrillion Btu higher. Natural gas consumption in the Extended Policies case is virtually the same as in the No Sunset case through 2030. After 2030, refinery use of natural gas stabilizes in the Extended Policies case as continued increases in CAFE standards reduce demand for petroleum products.

Transportation energy consumption

The Extended Policies case differs from the Reference and No Sunset cases in assuming that the CAFE standards recently finalized by EPA and NHTSA for MY 2017 through 2025 (which call for a 4.1-percent annual average increase in fuel economy for new LDVs) are extended through 2040 with an assumed average annual increase of 1.4 percent. Sales of vehicles that do not rely solely on a gasoline internal combustion engines for both motive and accessory power (including those that use diesel, alternative fuels, or hybrid electric systems) play a substantial role in meeting the higher fuel economy standards after 2025, growing to almost 72 percent of new LDV sales in 2040, compared with about 49 percent in the Reference case.


figure data

LDV energy consumption declines in the Reference case from 16.1 quadrillion Btu (8.7 million barrels per day) in 2011 to 14.0 quadrillion Btu (7.7 million barrels per day) in 2025 as a result of the increase in CAFE standards. Extension of the increases in CAFE standards in the Extended Policies case further reduces LDV energy consumption to 11.9 quadrillion Btu (6.5 million barrels per day) in 2040, or about 8 percent lower than in the Reference case. Petroleum and other liquid fuels consumption in the transportation sector is virtually identical through 2025 in the Reference and Extended Policies cases but declines in the Extended Policies case from 13.3 million barrels per day in 2025 to 12.3 million barrels per day in 2040, as compared with 13.0 million barrels per day in 2040 in the Reference case (Figure 14).

Renewable electricity generation

The extension of tax credits for renewables through 2040 would, over the long run, lead to more rapid growth in renewable generation than in the Reference case. When the renewable tax credits are extended without extending energy efficiency standards, as assumed in the No Sunset case, there is a significant increase in renewable generation in 2040 compared to the Reference case (Figure 15). Extending both renewable tax credits and energy efficiency standards in the Extended Policies case results in more modest growth in renewable generation, because renewable generation is a significant source of new generation to meet load growth, and enhanced energy efficiency standards tend to reduce overall electricity consumption and the need for new generation resources.


figure data

The AEO2013 Reference case does not reflect the provisions of the American Taxpayer Relief Act of 2012 (P.L. 112-240) passed on January 1, 2013 [68], which extends the PTCs for renewable generation beyond what is included in the AEO2013 Reference case. While this legislation was completed too late for inclusion in the Reference case, EIA did complete an alternative case that examined key energy-related provisions of that legislation, the most important of which is the extension of the PTC for renewable generation. A brief summary of those results is presented in the box, "Effects of energy provisions in the American Taxpayer Relief Act of 2012."

Effects of energy provisions in the American Taxpayer Relief Act of 2012

On January 1, 2013, Congress passed the American Taxpayer Relief Act of 2012 (ATRA). The law, among other things, extended several provisions for tax credits to the energy sector. Although the law was passed too late to be incorporated in the Annual Energy Outlook 2013 (AEO2013) Reference case, a special case was prepared to analyze some of its key provisions, including the extension of tax credits for utility-scale renewables, residential energy efficiency improvements, and biofuels [69]. The analysis found that the most significant impact on energy markets came from extending the production tax credits (PTCs) for utility-scale wind, and from changing the PTC qualification criteria from being in service on December 31, 2013, to being under construction by December 31, 2013, for all eligible utility-scale technologies. Although there is some uncertainty about what criteria will be used to define "under construction," this analysis assumes that the effective length of the extension is equal to the typical project development time for a qualifying project. For wind, the effective extension is 3 years.


figure data

Compared with the AEO2013 Reference case, ATRA increases renewable generation, primarily from wind (Figure 16). Renewable generation in 2040 is about 2 percent higher in the ATRA case than in the Reference case, with the greatest growth occurring in the near term. In 2016, renewable generation in the ATRA case exceeds that in the Reference case by nearly 9 percent. Almost all the increase comes from wind generation, which in 2016 is about 34 percent higher in the ATRA case than in the Reference case. In 2040, however, wind generation is only 17 percent higher than projected in the Reference case. These results indicate that, while the short-term extension does result in additional wind generation capacity, some builds that otherwise would occur later in the projection period are moved up in time to take advantage of the extended tax credit. The increase in wind generation partially displaces other forms of generation in the Reference case, both renewable and nonrenewable—particularly solar, biomass, coal, and natural gas.

ATRA does not have significant effects on electricity or delivered natural gas prices and generally does not result in a difference of more than 1 percent either above or below Reference case prices. In the longer term (beyond 2020), electricity and natural gas prices generally both are slightly lower in the ATRA case, as increased wind capacity reduces variable fuel costs in the power sector and reduces the demand for natural gas.

Other ATRA provisions analyzed had minimal impact on all energy measures, primarily limited to short-term reductions in renewable fuel prices and a one-year window for residential customers to get tax credits for certain efficiency expenditures. Provisions of the act not addressed in this analysis are likely to have only modest impacts because of their limited scale, scope, and timing.

In the No Sunset and Extended Policies cases, renewable generation more than doubles from 2011 to 2040, as compared with a 64-percent increase in the Reference case. In 2040, the share of total electricity generation accounted for by renewables is between 22 and 23 percent in both the No Sunset and Extended Policies cases, as compared with 16 percent in the Reference case.

Construction of wind-generation units slows considerably in the Reference case from recent construction rates, following the assumed expiration of the tax credit for wind power in 2012. The combination of slow growth in electricity demand, little impact from state-level renewable generation requirements, and low prices for competing fuels like natural gas keeps growth relatively low until around 2025, when load growth finally catches up with installed capacity, and natural gas prices increase to a level at which wind is a cost-competitive option in some regions. Extending the PTC for wind spurs a brief surge in near-term development by 2014, but the factors that limit development through 2025 in the Reference case still largely apply, and growth from 2015 to about 2025 is slow, in spite of the availability of tax credits during the 10-year period. When the market picks up again after 2025, availability of the tax credits spurs additional wind development over Reference case levels. Wind generation in the No Sunset case is about 27 percent higher than in the Reference case in 2025 and 86 percent higher in 2040.

In the near term, the continuation of tax credits for solar generation results in a continuation of recent growth trends for this resource. The solar tax credits are assumed to expire in 2016 in the Reference case, after which the growth of solar generation slows significantly. Eventually, economic conditions become favorable for utility-scale solar without the federal tax credits, and the growth rate picks up substantially after 2025. With the extension of the ITC, growth continues throughout the projection period. Solar generation in the No Sunset case in 2040 is more than 30 times the 2011 level and more than twice the level in 2040 in the Reference case.

The impacts of the tax credit extensions on geothermal and biomass generation are mixed. Although the tax credits do apply to both geothermal and biomass resources, the structure of the tax credits, along with other market dynamics, makes wind and solar projects relatively more attractive. Over most of the projection period, geothermal and biomass generation are lower with the tax credits available than in the Reference case. In 2040, generation from both resources in the No Sunset and Extended Policies cases is less than 10 percent below the Reference case levels. However, generation growth lags significantly through 2020 with the tax credit extensions, and generation in 2020 from both resources is about 20 percent lower in the No Sunset and Extended Policy cases than in the Reference case.


figure data

After 2025, renewable generation in the No Sunset and Extended Policies cases starts to increase more rapidly than in the Reference case. As a result, generation from nuclear and fossil fuels is below Reference case levels. Natural gas represents the largest source of displaced generation. In 2040, electricity generation from natural gas is 13 percent lower in the No Sunset case and 16 percent lower in the Extended Policies case than in the Reference case (Figure 17).

Energy-related CO2 emissions

In the No Sunset and Extended Policies cases, lower overall fossil energy use leads to lower levels of energy-related CO2 emissions than in the Reference case. In the Extended Policies case, the emissions reduction is larger than in the No Sunset case. From 2011 to 2040, energy-related CO2 emissions are reduced by a cumulative total of 4.6 billion metric tons (a 2.8-percent reduction over the period) in the Extended Policies case relative to the Reference case projection, as compared with 1.7 billion metric tons (a 1.0-percent reduction over the period) in the No Sunset case (Figure 18). The increase in fuel economy standards assumed for new LDVs in the Extended Policies case is responsible for 11.4 percent of the total cumulative reduction in CO2 emissions from 2011 to 2040 in comparison with the Reference case. The balance of the reduction in CO2 emissions is a result of greater improvement in appliance efficiencies and increased penetration of renewable electricity generation.


figure data

Most of the emissions reductions in the No Sunset case result from increases in renewable electricity generation. Consistent with current EIA conventions and EPA practice, emissions associated with the combustion of biomass for electricity generation are not counted, because they are assumed to be balanced by carbon absorption when the plant feedstock is grown. Relatively small incremental reductions in emissions are attributable to renewables in the Extended Policies case, mainly because electricity demand is lower than in the Reference case, reducing the consumption of all fuels used for generation, including biomass.

In both the No Sunset and Extended Policies cases, water heating, space cooling, and space heating together account for most of the emissions reductions from Reference case levels in the buildings sector. In the industrial sector, the Extended Policies case projects reduced emissions as a result of decreases in electricity purchases and petroleum use.

Energy prices and tax credit payments


figure data

With lower levels of fossil energy use and more consumption of renewable fuels stimulated by tax credits in the No Sunset and Extended Policies cases, energy prices are lower than in the Reference case. In 2040, average delivered natural gas prices (2011 dollars) are $0.29 per million Btu (2.7 percent) and $0.59 per million Btu (5.4 percent) lower in the No Sunset and Extended Policies cases, respectively, than in the Reference case (Figure 19), and electricity prices are 3.9 percent and 6.3 percent lower than in the Reference case (Figure 20).


figure data

The reductions in energy consumption and CO2 emissions in the Extended Policies case are accompanied by higher equipment costs for consumers and revenue reductions for the U.S. government. From 2013 to 2040, residential and commercial consumers spend, on average, an additional $20 billion per year (2011 dollars) for newly purchased end-use equipment, DG systems, and residential building shell improvements in the Extended Policies case as compared with the Reference case. On the other hand, residential and commercial customers save an average of $30 billion per year on energy purchases.

Tax credits paid to consumers in the buildings sector (or, from the government's perspective, reduced revenue) in the No Sunset case average $4 billion (2011 dollars) more per year than in the Reference case, which assumes that existing tax credits expire as currently scheduled, mostly by 2016.

The largest response to federal tax incentives for new renewable generation is seen in the No Sunset case, with extension of the PTC and the 30-percent ITC resulting in annual average reductions in government tax revenues of approximately $2.3 billion from 2011 to 2040, as compared with $650 million per year in the Reference case.

3. U.S. reliance on imported liquid fuels in alternative scenarios

Liquid fuels [71] play a vital role in the U.S. energy system and economy, and access to affordable liquid fuels has contributed to the nation's economic prosperity. However, the extent of U.S. reliance on imported oil has often been raised as a matter of concern over the past 40 years. U.S. net imports of petroleum and other liquid fuels as a share of consumption have been one of the most watched indicators in national and global energy analyses. After rising steadily from 1950 to 1977, when it reached 47 percent by the most comprehensive measure, U.S. net import dependence declined to 27 percent in 1985. Between 1985 and 2005, net imports of liquid fuels as a share of consumption again rose, reaching 60 percent in 2005. Since that time, however, the trend toward growing U.S. dependence on liquid fuels imports has again reversed, with the net import share falling to an estimated 41 percent in 2012, and with EIA projecting further significant declines in 2013 and 2014. The decline in net import dependence since 2005 has resulted from several disparate factors, and continued changes in those and other factors will determine how this indicator evolves in the future. Key questions include:

  • What are the key determinants of U.S. liquid fuels supply and demand?
  • Will the supply and demand trends that have reduced dependence on net imports since 2005 intensify or abate?
  • What supply and demand developments could yield an outcome in which the United States is no longer a net importer of liquid fuels?

This discussion considers potential changes to the U.S. energy system that are inherently speculative and should be viewed as what-if cases. The four cases that are discussed include two cases (Low Oil and Gas Resources and High Oil and Gas Resources) in which only the supply assumptions are varied, and two cases (Low/No Net Imports and High Net Imports) in which both supply and demand assumptions change. The changes in these cases generate wide variation from the liquid fuels import dependence values seen in the AEO2013 Reference case, but they should not be viewed as spanning the range of possible outcomes. Cases in which both supply and demand assumptions are modified show the greatest changes. In the Low/No Net Imports case, the United States ceases to be a net liquid fuels importer in the mid-2030s, and by 2040 U.S. net exports are 8 percent of total U.S. liquid fuel production. In contrast, in the High Net Imports case, net petroleum import dependence is above 44 percent in 2040, higher than the Reference case level of 37 percent but still well below the 60-percent level seen in 2005. Cases in which only supply assumptions are varied show intermediate levels of change in liquid fuels import dependence.

As the case names suggest, the Low Oil and Gas Resource case incorporates less-optimistic oil and natural gas resource assumptions than those in the Reference case, while the High Oil and Gas Resource case does the opposite. The other two cases combine different oil and natural gas resource assumptions with changes in assumptions that influence the demands for liquid fuels. The Low/No Net Imports case simulates an environment in which U.S. energy production grows rapidly while domestic consumption of liquid fuels declines. Conversely, the High Net Imports case combines the Low Oil and Gas Resource case assumptions with demand-related assumptions including slower improvements in vehicle efficiency, higher levels of vehicle miles traveled (VMT) relative to the Reference case, and reduced use of alternative transportation fuels.

Resource assumptions

A key contributing factor to the recent decline in net import dependence has been the rapid growth of U.S. oil production from tight onshore formations, which has followed closely after the rapid growth of natural gas production from similar types of resources. Projections of future production trends inevitably reflect many uncertainties regarding the actual level of resources available, the difficulty in extracting them, and the evolution of the technologies (and associated costs) used to recover them. To represent these uncertainties, the assumptions used in the High and Low Oil and Gas Resource cases represent significant deviations from the Reference case.

Estimates of technically recoverable resources from the rapidly developing tight oil formations are particularly uncertain and change over time as new information is gained through drilling, production, and technology experimentation. Over the past decade, as more tight and shale formations have gone into commercial production, estimates of technically and economically recoverable resources have generally increased. Technically recoverable resource estimates, however, embody many assumptions that might not prove to be true over the long term, over the entire range of tight or shale formations, or even within particular formations. For example, the tight oil resource estimates in the Reference case assume that production rates achieved in a limited portion of a given formation are representative of the entire formation, even though neighboring tight oil well production rates can vary widely. Any specific tight or shale formation can vary significantly across the formation with respect to relevant characteristics [72], resulting in widely varying rates of well production. The application of refinements to current technologies, as well as new technological advancements, can also have a significant but highly uncertain impact on the recoverability of tight and shale crude oil.

As shown in Table 5, the High and Low Oil and Gas Resource cases were developed with alternative crude oil and natural gas resource assumptions giving higher and lower technically recoverable resources than assumed in the Reference case. While these cases do not represent upper and lower bounds on future domestic oil and natural gas supply, they allow for an examination of the potential effects of higher and lower domestic supply on energy demand, imports, and prices.

The Low Oil and Gas Resource case only reflects the uncertainty around tight oil and shale gas resources. The resource estimates in the Reference case are based on crude oil and natural gas production rates achieved in a limited portion of the tight or shale formation and are assumed to be representative of the entire formation. However, the variability in formation characteristics described earlier can also affect the estimated ultimate recovery (EUR) of wells. For the Low Oil and Gas Resource case, the EUR per tight and shale well is assumed to be 50 percent lower than in the AEO2013 Reference case. All other resource assumptions are unchanged from the Reference case.

The High Oil and Gas Resource case reflects a broad-based increase in crude oil and natural gas resources. Optimism regarding increased supply has been buoyed by recent advances in crude oil and natural gas production that resulted in an unprecedented annual increase in U.S. crude oil production in 2012. The AEO2013 Reference case shows continued near-term production growth followed by a decline in U.S. production after 2020. The High Oil and Gas Resource case presents a scenario in which U.S. crude oil production continues to expand after about 2020 due to assumed higher technically recoverable tight oil resources, as well as undiscovered resources in Alaska and the offshore Lower 48 states. In addition, the maximum annual penetration rate for GTL technology is doubled compared to the Reference case.

The tight and shale resources are increased by changing both the EUR per well and the well spacing. A doubling in tight and shale well EUR, when assumed to occur through raising the production type curves [73] across the board, is responsible for the significantly faster increases in production and is also a contributing factor in avoiding the production decline during the projection period. This assumption change is quite optimistic and may alternatively be considered as a proxy for other changes or combinations of changes that have yet to be observed.

Although initial production rates have increased over the past few years, it is too early to conclude that overall EURs have increased and will continue to increase. Instead, producers may just be recovering the resource more quickly, resulting in a more dramatic decline in production later, with little impact on the well's overall EUR. The decreased well spacing reflects less the capability to drill wells closer together (i.e., avoid interference) and instead more the discovery of and production from other shale plays that are not yet in commercial development. These may either be stacked in the same formation or reflect future technological innovations that would bring into production plays that are otherwise not amenable to current hydraulic fracturing technology.

Other resources also are assumed to contribute to supply, as technological or other unforeseen changes improve their prospects. The resource assumptions for the offshore Lower 48 states in the High Oil and Gas Resource case reflect the possibility that resources may be substantially higher than assumed in the Reference case. Resource estimates for most of the U.S. Outer Continental Shelf are uncertain, particularly for resources in undeveloped regions where there has been little or no exploration and development activity, and where modern seismic survey data are lacking [74]. The increase in crude oil resources in Alaska reflects the possibility that there may be more crude oil on the North Slope, including tight oil. It does not, however, reflect an opening of the Arctic National Wildlife Refuge to exploration or production activity. Finally, modest production from kerogen (oil shale) resources, which remains below 140,000 barrels per day through the 2040 projection horizon, is included in the High Oil and Gas Resource case.

Demand assumptions

Reductions in demand for liquid fuels in some uses, such as personal transportation and home heating, coupled with slow growth in other applications, have been another key contributing factor in the decline of the nation's net dependence on imported liquid fuels since 2005. As with supply assumptions, the key analytic assumptions that drive future trends in liquid fuels demand in EIA's projections are subject to considerable uncertainty. The most important assumptions affecting future demand for liquids fuels include:

  • The future level of activities that use liquid fuels, such as VMT
  • The future efficiency of equipment that uses liquid fuels, such as automobiles, trucks, and aircraft
  • The future extent of fuel switching that replaces liquid fuels with other fuel types, such as liquefied natural gas (LNG), biofuels, or electricity.

Two alternative sets of demand assumptions that lead to higher or lower demand for liquid fuels than in the AEO2013 Reference case are outlined below. The two alternative scenarios are then applied in conjunction with the High and Low Oil and Gas Resource cases to develop the Low/No Net Import and High Net Import cases.

Vehicle miles traveled

Projected fuel use by LDVs is directly proportional to light-duty VMT, which can be influenced by policy, but it is driven primarily by market factors, demography, and consumer preferences. All else being equal, VMT is more likely to grow when the driving-age population is growing, economic activity is robust, and fuel prices are moderate. For example, there is a strong linkage between economic activity, employment, and commuting. In addition, there is a correlation between income and discretionary travel that reinforces the economy-VMT link. Turning to demography, factors such as the population level, age distribution, and household composition are perhaps most important for VMT. For example, lower immigration would lead to a smaller U.S. population over time, lowering VMT. The aging of the U.S. population continues and will also have long-term effects on VMT trends, as older drivers do not behave in the same ways as younger or middle-aged drivers. At times, the factors that influence VMT intertwine in ways that change long-term trends in U.S. driving and fuel consumption. For example, the increase in two-income families that occurred beginning in the 1970s created a surge in VMT that involved both economic activity and demographics.

Alternative modes of travel affect VMT to the degree that the population substitutes other travel services for personal LDVs. The level of change is related to the cost, convenience, and geographic extent of mass transit, rail, biking, and pedestrian travel service options. Car-sharing services, which have grown in popularity in recent years, could discourage personal vehicle VMT by putting more of the cost of incremental vehicle use on the margin when compared with traditional vehicle ownership or leasing, where many of the major costs of vehicle use are incurred at the time a vehicle is acquired, registered, and insured. Improvements in the fuel efficiency of vehicles, however, could increase VMT by lowering the marginal costs of driving. In recent analyses supporting the promulgation of new final fuel economy and GHG standards for LDVs in MY 2017 through 2025, NHTSA and EPA applied a 10-percent rebound in travel to reflect the lower fueling costs of more efficient vehicles [75]. Both higher and lower values for the rebound have been advanced by various analysts [76].

Other types of technological change also can affect projected VMT growth. E-commerce, telework, and social media can supplant (or complement) personal vehicle use. Some analysts have suggested an association between rising interest in social media and a decline in the rates at which driving-age youth secure driver licenses; however, that decline also could be related to recent weakness in the economy.

Many of the factors reviewed above were also addressed in the August 2012 National Petroleum Council Future Transportation Fuels study [77]. That study considered numerous specific research efforts, as well as available summaries of the literature on VMT, and concluded that the economic and demographic factors remain dominant. The VMT scenario adopted for most of the analysis in that study reflected declining compound annual growth rates of VMT over time, with the growth rate in VMT, which was 3.1 percent in the 1971-1995 and 2.0 percent in the 1996-2007 periods, falling to under 1 percent after 2035.

In the AEO2013 Reference case, the compound annual rate of growth in light-duty VMT over the period from 2011 to 2040 is 1.2 percent—well below the historical record through 2005 but significantly higher than the average annual light-duty VMT growth rate of 0.7 percent from 2005 through 2011. The 2005-2011 period was marked by generally poor economic performance, high unemployment, and high liquid fuel prices, all of which likely contributed to lower VMT growth. While VMT growth rates are expected to rise as the economy and employment levels improve, it remains to be seen to what extent such effects might be counteracted or reinforced by some of the other market factors identified above.

The low demand scenario used in the Low/No Net Imports case holds the growth rate of light-duty VMT over the 2011-2040 period at 0.2 percent per year, lower than its 2005-2011 growth rate. The application of a lower growth rate over a 29-year projection period results in total light-duty VMT 26 percent below the Reference case level in 2040. With population growth at 0.9 percent per year, this implies a decline of 0.7 percent per year in VMT per capita. VMT per licensed driver, which increases by 0.3 percent per year in the AEO2013 Reference case, declines at a rate of 0.8 percent per year in the Low/No Net Imports case. In the High Net Imports case, which assumes more robust demand than in the Reference case, the VMT projection remains close to that in the Reference case, with higher demand resulting from other factors.

Vehicle efficiencies

Turning to vehicle efficiency, the rising fuel economy of new LDVs already has contributed to recent trends in liquid fuels use. Looking forward, the EPA and NHTSA have established joint CAFE and GHG emissions standards through MY 2025. The new CAFE standards result in a fuel economy, measured as a program compliance value, of 47.3 mpg for new LDVs in 2025, based on the distribution of production of passenger cars and light trucks by footprint in AEO2013. The EPA and NHTSA also have established a fuel efficiency and GHG emissions program for medium- and heavy-duty vehicles for MY 2014-18. The fuel consumption standards for MY 2014-15 set by NHTSA are voluntary, while the standards for MY 2016 and beyond are mandatory, except those for diesel engines, which are mandatory starting in 2017.

The AEO2013 Reference case does not consider any possible reduction in fuel economy standards resulting from the scheduled midterm review of the CAFE standards for MY 2023-25, or for any increase in fuel economy standards that may be put in place for model years beyond 2025. The low demand scenario in this article adopts the assumption that post-2025 LDV CAFE standards increase at an average annual rate of 1.4 percent, the same assumption made in the AEO2013 Extended Policies case. In contrast, the high demand scenario assumes some reduction in current CAFE standards following the scheduled midterm review.

Fuel switching

In the AEO2013 Reference case, fuel switching to natural gas in the form of compressed natural gas (CNG) and LNG already is projected to achieve significant penetration of natural gas as a fuel for heavy-duty trucks. In the Reference case, natural gas use in heavy-duty vehicles increases to 1 trillion cubic feet per year in 2040, displacing 0.5 million barrels per day of diesel use. The use of natural gas in the Reference case is economically driven. Even after the substantial costs of liquefaction or compression, fuel costs for LNG or CNG are expected to be well below the projected cost of diesel fuel on an energy-equivalent basis. The fuel cost advantage is expected to be large enough in the view of a significant number of operators to offset the considerably higher acquisition costs of vehicles equipped to use these fuels, in addition to offsetting other disadvantages, such as reduced maximum range without refueling, a lower number of refueling locations, reduced volume capacity in certain applications, and an uncertain resale market for vehicles using alternative fuels. For purposes of the low demand scenario for liquid fuels, factors limiting the use of natural gas in heavy-duty vehicles are assumed to be less significant, allowing for higher rates of market penetration.

Natural gas could also prove to be an attractive fuel in other transportation applications. The use of LNG as a fuel for rail transport, which had earlier been considered for environmental reasons, is now under active consideration by major U.S. railroads for economic reasons, motivated by the same gap between the cost of diesel fuel and LNG now and over the projection period. Because all modern railroad locomotives use electric motors to drive their wheels, a switch from diesel to LNG would entail the use of a different fuel to drive the onboard electric generation system. Retrofits have been demonstrated, but new locomotives with generating units specifically optimized for LNG could prove to be more attractive. Because railroads already maintain their own on-system refueling infrastructure, they may be less subject to the concern that truckers considering a switch to alternative fuel vehicles might have regarding the risks that natural gas refueling systems they require would not actually be built. The high concentration of ownership in the U.S. railroad industry could also facilitate a rapid switch toward LNG refueling, with the associated transition to new equipment, under the right circumstances because there are only a few owners making the decisions.

Marine operators have traditionally relied on oil-based fuels, with large oceangoing vessels almost exclusively fueled with heavy high-sulfur fuel oil that typically sells at a discount relative to other petroleum products. Under the International Maritime Organization's International Convention on the Prevention of Pollution from Ships agreement (MARPOL Annex VI) [78], the use of heavy high-sulfur fuel oil in international shipping started being phased out for environmental reasons in 2010. Although LNG is one possible option, there are many cost and logistical challenges, including the high cost of retrofits, the long lifetime of existing vessels, and relatively low utilization rates for many routes that will have adverse impacts on the economics of marine LNG refueling infrastructure. Unlike the heavy-duty truck market, there has not yet been an LNG-fueled product offered for general use by manufacturers of marine or rail equipment, making cost and performance comparisons inherently speculative.

In addition to the demand assumptions discussed above, other assumption changes were made to capture potential shifts in vehicle cost and consumer preference for LDVs powered by alternative fuels. In the Low/No Net Imports case, the costs of efficiency technologies and battery technologies were lowered, and the market penetration of E85 fuel was increased, relative to the Reference case levels. With regard to E85, assumptions about consumer preference for flex-fuel vehicles were altered to allow for increases in vehicle sales and E85 demand, leading to greater use of domestically-produced biofuel than projected in the Reference case.

Table 6 summarizes the demand-side assumptions in the alternative demand scenarios for liquid fuels. As with the supply assumptions, the assumptions used in the higher and lower demand cases represent substantial deviations from the AEO2013 Reference case, and they might instead be realized in terms of other, as-yet-unforeseen developments in technology, economics, or policy.

Results

The cases considered show how the future share of net imports in total U.S. liquid fuel use varies with changes in assumptions about the key factors that drive domestic supply and demand for liquid fuels (Figure 24). Some of the assumptions in the Low/No Net imports case, such as assumed increases in LDV fuel economy after 2025 and access to offshore resources, could be influenced by future energy policies. However, other assumptions in this case, such as the greater availability of onshore technically recoverable oil and natural gas resources, depend on geological outcomes that cannot be influenced by policy measures; and economic, consumer, or technological factors may likewise be unaffected or only slightly affected by policy measures.

Net imports and prices

In the Low/No Net Imports case, U.S. net imports of liquid fuels are eliminated in the mid-2030s, and the United States becomes a modest net exporter of those fuels by 2040. As discussed above, this case combines optimistic assumptions about the availability of domestic oil and natural gas resources with assumptions that lower demand for liquid fuels, including a decline in VMT per capita, increased switching to natural gas fuels for transportation (including heavy-duty trucks, rail, boats, and ships), continued significant improvements in the fuel efficiency of new vehicles beyond 2025, wider availability and lower costs of electric battery technologies, and greater market penetration of biofuels and other nonpetroleum liquids. Although other combinations of assumptions, or unforeseen technology breakthroughs, might produce a comparable outcome, the assumptions in the Low/No Net Imports case illustrate the magnitude and type of changes that would be required for the United States to end its reliance on net imports of liquid fuels, which began in 1946 and has continued to the present day. Moreover, regardless of how much the United States is able to reduce its reliance on imported liquids, it will not be entirely insulated from price shocks that affect the global oil market [79].


figure data

As shown in Figure 24, the supply assumptions of the High Oil and Gas Resource case alone result in a decline in net import dependence to 7 percent in 2040, compared to 37 percent in the Reference case, with U.S. crude oil production rising to 10.2 million barrels per day in 2040, or 4.1 million barrels per day above the Reference case level. Tight oil production accounts for more than 77 percent (or 3 million barrels per day) of the difference in production between the two cases. Production of NGL in the United States also exceeds the Reference case level.

As a result of higher U.S. liquid fuels production, Brent crude oil prices in the High Oil and Gas Resource case are lower than in the Reference case, which also lowers motor gasoline and diesel prices to the transportation sector, encouraging greater consumption and partially dampening the projected decline in net dependence on liquid fuel imports. In the High Oil and Gas Resource case, the reduction in motor fuels prices increases fuel consumption in 2040 by 350 thousand barrels per day in the transportation sector and 230 thousand barrels per day in the industrial sector, which accounts for nearly all of the increase in total U.S. liquid fuels consumption (600 thousand barrels per day) relative to the Reference case total in 2040.

Global market, the economy, and refining

The addition of assumptions that slow the growth of demand for liquid fuels in the Low/No Net Imports case more than offsets the increase in demand that results from lower liquid fuel prices, so that total liquid fuels consumption in 2040 is 2.1 million barrels per day lower than projected in the Reference case. The combination of high crude oil and natural gas resources and lower demand for liquid fuels pushes Brent crude oil prices to $29 per barrel below the Reference case level in 2040. However, given the cumulative impact of factors that tend to raise world oil prices in real terms over the projection period, inflation-adjusted crude oil prices in the Low/No Net Imports case are still above today's price level.

One of the most uncertain aspects of the analysis concerns the effect on the global market for liquid fuels, which is highly integrated. Although the analysis reflects price effects that are based on the relative scale of the changes in U.S. domestic supply and net U.S. imports of liquid fuels within the overall international crude oil market, strategic choices made by the leading oil-exporting countries could result in price and quantity effects that differ significantly from those presented here. Moreover, regardless of how much the United States reduces its reliance on imported liquids, consumer prices will not be insulated from global oil prices if current policies and regulations remain in effect and world markets for crude oil streams of sulfur quality remain closely aligned absent transportation bottlenecks [80].

Although the focus is mainly on liquid fuels markets, the more optimistic resource assumptions in the High Oil and Gas Resource case also lead to more natural gas production. The higher productivity of shale and tight gas wells puts downward pressure on natural gas prices and thus encourages increased domestic consumption of natural gas (38 trillion cubic feet in the High Oil and Gas Resource case, compared to 30 trillion cubic feet in the Reference case in 2040) and higher net exports (both pipeline and LNG) of natural gas. As a result, projected domestic natural gas production in 2040 is considerably higher in the High Oil and Gas Resource case (45 trillion cubic feet) than in the Reference case (33 trillion cubic feet).

The Low Oil and Gas Resource case illustrates the implications of an outcome in which U.S. oil and gas resources turn out to be smaller than expected in the Reference case. In this case, domestic crude oil production peaks in 2016 at 6.9 million barrels per day, declines to 5.9 million barrels per day in 2028, and remains relatively flat (between 5.8 and 6.0 million barrels per day) through 2040. The lower well productivity in this case puts upward pressure on natural gas prices, resulting in lower natural gas consumption and production. In 2040, U.S. natural gas production is 27 trillion cubic feet in the Low Oil and Gas Resource case, compared with 33 trillion cubic feet in the Reference case.

These alternative cases may also have significant implications for the broader economy. Liquid fuels provide power and raw materials (feedstocks) for a substantial portion of the U.S. economy, and the macroeconomic impacts of both the High Oil and Gas Resource case and the Low/No Net Imports case suggest that significant economic benefits would accrue if some version of those futures were realized (see discussion of NGL later in "Issues in focus"). This is in spite of the fact that petroleum remains a global market in each of the scenarios, which limits the price impacts for gasoline, diesel, and other petroleum-derived fuels. In the High Oil and Gas Resource case, increasing energy production has immediate benefits for the economy. U.S. industries produce more goods with 12 percent lower energy costs in 2025 and 15 percent lower energy costs in 2040. Consumers see roughly 10 percent lower energy prices in 2025, and 13 percent lower energy prices in 2040, as compared with the Reference case. Cheaper energy allows the economy to expand further, with real GDP attaining levels that are on average about 1 percent above those in the Reference case from 2025 through 2040, including growth in both aggregate consumption and investment.

The alternative cases also imply substantial changes in the future operations of U.S. petroleum refineries, as is particularly evident in the Low/No Net Imports case. Drastically reduced product consumption and increased nonpetroleum sources of transportation fuels, taken in isolation, would tend to reduce utilization of U.S. refineries. The combination of higher domestic crude supply and reduced crude runs in the refining sector would sharply reduce or eliminate crude oil imports and could potentially create market pressure for crude oil exports to balance crude supply with refinery runs. However, under current laws and regulations, crude exports require licenses that have not been issued except in circumstances involving exports to Canada or exports of limited quantities of specific crude streams, such as California heavy oil [81].

Rather than assuming a change in current policies toward crude oil exports, and recognizing the high efficiency and low operating costs of U.S. refineries relative to global competitors in the refining sector, exports of petroleum products, which are not subject to export licensing requirements, rise significantly to avoid the uneconomical unloading of efficient U.S. refinery capacity, continuing a trend that has already become evident over the past several years. Product exports rise until the incremental refining value of crude oil processed is equivalent to the cost of crude imports. To balance the rest of the world as a result of increased U.S. product exports, it is assumed that the increased volumes of U.S. liquid fuel product exports would result in a decrease in the volume of the rest of the world's crude runs, and that world consumption, net of U.S. exports, would also be reduced by an amount necessary to keep demand and supply volumes in balance.

Projected carbon dioxide emissions


figure data

Total U.S. CO2 emissions show the impacts of changing fuel prices through all the sectors of the economy. In the High Oil and Gas Resource case, the availability of more natural gas at lower prices encourages the electric power sector to increase its reliance on natural gas for electricity generation. Coal is the most affected, with coal displaced over the first part of the projection, and new renewable generation sources also affected after 2030 or so, resulting in projected CO2 emissions in the High Oil and Gas Resource case that exceed those in the Reference case after 2035 (Figure 25). With less-plentiful and more-expensive natural gas in the Low Oil and Gas Resource and High Net Imports cases, the reverse is true, with fewer coal retirements leading to higher CO2 emissions than in the Reference case early in the projection period. Later in the projection, however, the electric power sector turns first to renewable technologies earlier in the Low Oil and Gas Resource and High Net Imports cases, and after 2030 invests in more nuclear plants, reducing CO2 emissions from the levels projected in the Reference case. In the Low Oil and Gas Resource case, CO2 emissions are lower than in the Reference case starting in 2026. In the Low/No Net Imports case, annual CO2 emissions from the transportation sector continue to decline as a result of reduced travel demand; these emissions are conversely higher in the High Net Imports case. Figure 25 summarizes the CO2 emissions projections in the cases completed for this analysis.

Endnotes

6. U.S. Environmental Protection Agency and National Highway Traffic Safety Administration, "2017 and Later Model Year Light-Duty Vehicle Greenhouse Gas Emissions and Corporate Average Fuel Economy Standards," Federal Register, Vol. 77, No. 199 (Washington, DC: October 15, 2012), https://www.federalregister.gov/articles/2012/10/15/2012-21972/2017-and-latermodel-year-light-duty-vehicle-greenhouse-gas-emissions-and-corporate-average-fuel.
7. Liquid motor fuels include diesel and liquid fuels from gas-to-liquids (GTL) processes. Liquid fuel volumes from GTL for motor vehicle use are estimated based on the ratio of onroad diesel and gasoline to total diesel and gasoline.
16. U.S. Environmental Protection Agency and National Highway Traffic Safety Administration, "2017 and Later Model Year Light-Duty Vehicle Greenhouse Gas Emissions and Corporate Average Fuel Economy Standards; Final Rule," Federal Register, Vol. 77, No. 199 (Washington, DC: October 15, 2012), https://www.federalregister.gov/articles/2012/10/15/2012-21972/2017-and-later-model-year-light-duty-vehicle-greenhouse-gas-emissions-and-corporate-average-fuel.
17. Fuel economy projection averages based on a 2010 baseline fleet. NHTSA alternatively lists projected compliance fuel economy averages based on the 2008 baseline fleet. EPA lists compliance-level average CO2 tailpipe emissions based solely on the 2008 baseline fleet.
18. U.S. Environmental Protection Agency and National Highway Traffic Safety Administration, "Light-Duty Vehicle Greenhouse Gas Emission Standards and Corporate Average Fuel Economy Standards; Final Rule," Federal Register, Vol. 75, No. 88 (Washington, DC: May 7, 2010), https://www.federalregister.gov/articles/2010/05/07/2010-8159/light-duty-vehicle-greenhouse-gas-emission-standards-and-corporate-average-fuel-economy-standards.
31. Clean Air Act, 42 U.S.C. 7412 (2011), http://www.gpo.gov/fdsys/pkg/USCODE-2011-title42/pdf/USCODE-2011-title42-chap85-subchapI-partA.pdf.
32. U.S. Environmental Protection Agency, "National Emission Standards for Hazardous Air Pollutants for Major Sources: Industrial, Commercial, and Institutional Boilers; Final Rule," Federal Register, Vol. 76, No. 54 (Washington, DC: March 21, 2011) pp. 15,608-15,702, http://www.gpo.gov/fdsys/pkg/FR-2011-03-21/pdf/2011-4494.pdf.
33. U.S. Environmental Protection Agency, "Definitions," Code of Federal Regulations, 40 CFR §63.2 (July 1, 2012), http://www.gpo.gov/fdsys/pkg/CFR-2012-title40-vol10/pdf/CFR-2012-title40-vol10-part63-subpartA.pdf, p. 16.
34. U.S. Environmental Protection Agency, "Definitions," Code of Federal Regulations, 40 CFR §63.2 (July 1, 2012), http://www.gpo.gov/fdsys/pkg/CFR-2012-title40-vol10/pdf/CFR-2012-title40-vol10-part63-subpartA.pdf, pp. 13-14.
35. U.S. Environmental Protection Agency, "National Emission Standards for Hazardous Air Pollutants for Major Sources: Industrial, Commercial, and Institutional Boilers and Process Heaters; Proposed Rule," Federal Register, Vol. 76, No. 247 (Washington, DC: December 23, 2011), p. 80,622, http://www.gpo.gov/fdsys/pkg/FR-2011-12-23/pdf/2011-31667.pdf.
36. U.S. Environmental Protection Agency, "National Emission Standards for Hazardous Air Pollutants for Area Sources: Industrial, Commercial, and Institutional Boilers; Final Rule," Federal Register, Vol. 76, No. 54 (Washington, DC: March 21, 2011), p. 15,579, http://www.gpo.gov/fdsys/pkg/FR-2011-03-21/pdf/2011-4493.pdf.
37. U.S. Environmental Protection Agency, "National Emission Standards for Hazardous Air Pollutants for Major Sources: Industrial, Commercial, and Institutional Boilers and Process Heaters; Final Rule," Federal Register, Vol. 76, No. 54 (Washington, DC: March 21, 2011), p. 15,695, http://www.gpo.gov/fdsys/pkg/FR-2011-03-21/pdf/2011-4494.pdf.
38. U.S. Environmental Protection Agency, "National Emission Standards for Hazardous Air Pollutants for Major Sources: Industrial, Commercial, and Institutional Boilers and Process Heaters; Final Rule," Federal Register, Vol. 76, No. 54 (Washington, DC: March 21, 2011), pp. 15,689-15,691, http://www.gpo.gov/fdsys/pkg/FR-2011-03-21/pdf/2011-4494.pdf.
39. CU.S. Environmental Protection Agency, "National Emission Standards for Hazardous Air Pollutants for Major Sources: Industrial, Commercial, and Institutional Boilers and Process Heaters; Final Rule," Federal Register, Vol. 76, No. 54 (Washington, DC: March 21, 2011), p. 15,615, http://www.gpo.gov/fdsys/pkg/FR-2011-03-21/pdf/2011-4494.pdf.
40. U.S. Environmental Protection Agency, "National Emission Standards for Hazardous Air Pollutants for Major Sources: Industrial, Commercial, and Institutional Boilers and Process Heaters; Final Rule," Federal Register, Vol. 76, No. 54 (Washington, DC: March 21, 2011), p. 15,696, http://www.gpo.gov/fdsys/pkg/FR-2011-03-21/pdf/2011-4494.pdf.
41. U.S. Environmental Protection Agency, "National Emission Standards for Hazardous Air Pollutants for Major Sources: Industrial, Commercial, and Institutional Boilers and Process Heaters," Federal Register, Vol. 76, No. 54 (Washington, DC: March 21, 2011), p. 15,665, http://www.gpo.gov/fdsys/pkg/FR-2011-03-21/pdf/2011-4494.pdf.
42. U.S. Environmental Protection Agency, "National Emission Standards for Hazardous Air Pollutants for Area Sources: Industrial, Commercial, and Institutional Boilers; Final Rule," Federal Register, Vol. 76, No. 54 (Washington, DC: March 21, 2011), p. 15,594, http://www.gpo.gov/fdsys/pkg/FR-2011-03-21/pdf/2011-4493.pdf.
43. U.S. Environmental Protection Agency, "National Emission Standards for Hazardous Air Pollutants for Area Sources: Industrial, Commercial, and Institutional Boilers, Final Rule," Federal Register, Vol. 76, No. 54 (Washington, DC: March 21, 2011), pp. 15,601-15,602, http://www.gpo.gov/fdsys/pkg/FR-2011-03-21/pdf/2011-4493.pdf.
44. The eligible technology, and even the definition of the technology or fuel category, will vary by state. For example, one state's definition of renewables may include hydroelectric power generation, while another's definition may not. Table 3 provides more detail on how the technology or fuel category is defined by each state.
45. More information about the Database of State Incentives for Renewables & Efficiency can be found at http://www.dsireusa.org/incentives.
46. Database of State Incentives for Renewables & Efficiency, http://www.dsireusa.org/rpsdata/index.cfm.
65. United States Internal Revenue Code, Title 26, Subtitle A—Income Taxes, §48(a)(2)(A)(ii), http://www.gpo.gov/fdsys/pkg/USCODE-2011-title26/pdf/USCODE-2011-title26-subtitleA-chap1-subchapA.pdf.
66. United States Internal Revenue Code, Title 26, Subtitle A—Income Taxes, §48(c)(3)(B)(iii), http://www.gpo.gov/fdsys/pkg/USCODE-2011-title26/pdf/USCODE-2011-title26-subtitleA-chap1-subchapA.pdf.
67. Calculations based on U.S. Energy Information Administration, Form EIA-860, Schedule 3, 2011 data (Washington, DC: January 9, 2013), http://www.eia.gov/electricity/data/eia860/index.html.
68. U.S. Congress, "American Taxpayer Relief Act of 2012," P.L. 112-240, Sections 401 through 412, http://www.gpo.gov/fdsys/pkg/PLAW-112publ240/pdf/PLAW-112publ240.pdf.
69. Modeled provisions based on U.S. Congress, "American Taxpayer Relief Act of 2012," P.L. 112-240, Sections 401, 404, 405, 407, 408, 409, and 412, http://www.gpo.gov/fdsys/pkg/PLAW-112publ240/pdf/PLAW-112publ240.pdf.

71. Liquid fuels consists of crude oil and condensate to petroleum refineries, refinery gain, NGPL, biofuels, and other liquid fuels produced from non-crude oil feedstocks such as CTL and GTL.
72. Geologic characteristics relevant for hydrocarbon extraction include depth, thickness, porosity, carbon content, pore pressure, clay content, thermal maturity, and water content.
73. A production type curve represents the expected production each year from a well. A well’s EUR equals the cumulative production of that well over a 30-year productive life, using current technology without consideration of economic or operating conditions. A description of a production type curve is provided in the Annual Energy Outlook 2012 "Issues in focus" article, "U.S. crude oil and natural gas resource uncertainty," http://www.eia.gov/forecasts/archive/aeo12/IF_all.cfm#uscrude.
74. A more detailed analysis of the uncertainty in offshore resources is presented in the Annual Energy Outlook 2011 "Issues in focus" article, "Potential of offshore crude oil and natural gas resources," http://www.eia.gov/forecasts/archive/aeo11/IF_all.cfm#potentialoffshore.
75. U.S. Environmental Protection Agency and National Highway Transportation Safety Administration, "2017 and Later Model Year Light-Duty Vehicle Greenhouse Gas Emissions and Corporate Average Fuel Economy Standards: Final Rule," Federal Register, Vol. 77, No. 199 (Washington, DC: October 15, 2012), https://www.federalregister.gov/articles/2012/10/15/2012-21972/2017-and-later-model-year-light-duty-vehicle-greenhouse-gas-emissions-and-corporate-average-fuel.
76. K.A. Small and K.Van Dender, "Fuel Efficiency and Motor Vehicle Travel: The Declining Rebound Effect," University of California, Irvine, Department of Economics, Working Paper #05-06-03 (Irvine, CA: August 18, 2007), http://www.economics.uci.edu/files/economics/docs/workingpapers/2005-06/Small-03.pdf.
77. National Petroleum Council, "Advancing Technology for America’s Transportation Future" (Washington, DC: August 1, 2012), http://www.npc.org/FTF-report-080112/NPC-Fuels_Summary_Report.pdf.
78. International Maritime Organization, Information Resources on Air Pollution and Greenhouse Gas (GHG) Emissions from International Shipping (Marpol Annex VI (SOX, NOX, ODS, VOC) / Greenhouse Gas (CO2) and Climate Change) (London, United Kingdom: December 23, 2011), http://www.imo.org/KnowledgeCentre/InformationResourcesOnCurrentTopics/AirPollutionand
GreenhouseGasEmissionsfromInternationalShippping/Documents/Information%20Resources%20on%20AIR%20POLLUTION%20AND%20GHG%20EMISSIONS%20FROM%20
INTERNATIONAL%20SHIPPING.pdf
.
79. U.S. Energy Information Administration, Could the United States become the leading global producer of liquid fuels, and how much does it matter to U.S. and world energy markets?," This Week in Petroleum (Washington, DC: December 19, 2012), http://www.eia.gov/oog/info/twip/twiparch/2012/121219/twipprint.html.
80. U.S. Energy Information Administration, "Could the United States become the leading global producer of liquid fuels, and how much does it matter to U.S. and world energy markets?," This Week in Petroleum (Washington, DC: December 19, 2012), http://www.eia.gov/oog/info/twip/twiparch/2012/121219/twipprint.html.
81. The circumstances under which the United States can and cannot export crude oil under current law are more fully described in U.S. Energy Information Administration, "Market implications of increased domestic production of light sweet crude oil?," This Week in Petroleum (Washington, DC: November 28, 2012), http://www.eia.gov/oog/info/twip/twiparch/2012/121128/twipprint.html.
125 These expenditures relative to GDP are not the energy-share of GDP, since expenditures include energy as an intermediate product. The energy-share of GDP corresponds to the share of value added due to domestic energy-producing sectors, which would exclude the value of energy as an intermediate product.
127. S.C. Davis, S.W. Diegel, and R.G. Boundy, Transportation Energy Databook: Edition 31, ORNL-6987 (Oak Ridge, TN: July 2012), Chapter 4, Table 4.6, “New Retail Sales of Trucks 10,000 Pounds GVWR and Less in the United States, 1970-2011.�
128. U.S. Department of Transportation, National Highway Safety Administration, "Summary of Fuel Economy Performance" (Washington, DC: October 2012), http://www.nhtsa.gov/staticfiles/rulemaking/pdf/cafe/Oct2012_Summary_Report.pdf.
129. U.S. Environmental Protection Agency and National Highway Traffic Safety Administration, "Light-Duty Vehicle Greenhouse Gas Emission Standards and Corporate Average Fuel Economy Standards; Final Rule," Federal Register, Vol. 75, No. 88 (Washington, DC: May 7, 2010), https://www.federalregister.gov/articles/2010/05/07/2010-8159/light-duty-vehicle-greenhouse-gas-emission-standards-and-corporate-average-fuel-economy-standards.
130. U.S. Environmental Protection Agency and National Highway Traffic Safety Administration, 2017 and Later Model Year Light-Duty Vehicle Greenhouse Gas Emissions and Corporate Average Fuel Economy Standards; Final Rule, Federal Register, Vol. 77, No. 199 (Washington, DC: October 15, 2012), https://www.federalregister.gov/articles/2012/10/15/2012-21972/2017-and-later-model-year-light-duty-vehicle-greenhouse-gas-emissions-and-corporate-average-fuel.
131. Light-duty vehicle fuel economy includes alternative-fuel vehicles and banked credits towards compliance.
141. R. Schnepf and B.D. Yacobucci, Renewable Fuel Standard (RFS): Overview and Issues (Washington, DC: Congressional Research Service, January 23, 2012), http://www.fas.org/sgp/crs/misc/R40155.pdf.

Executive Summary

Market Trends

Legislation and Regulations

Issues in Focus

Reference Case Tables