U.S. Energy Information Administration - EIA - Independent Statistics and Analysis
Annual Energy Outlook 2014
Release Dates: April 7 - 30, 2014 | Next Early Release Date: December 2014 | See schedule
Issues in Focus
The "Issues in focus" section of the Annual Energy Outlook (AEO) provides an in-depth discussion on topics of special significance, including changes in assumptions and recent developments in technologies for energy production and consumption. Selected quantitative results are available in Appendix D. The first topic updates a discussion included in a number of previous AEOs that compared the Reference case to the results of two cases with different assumptions about the future course of existing energy policies. One case assumes the elimination of sunset provisions in existing energy policies; that is, the policies are assumed not to terminate as they would under current law. The other case assumes the extension or expansion of a selected group of existing policies—corporate average fuel economy (CAFE) standards, appliance standards, and production tax credits (PTCs)—in addition to the elimination of sunset provisions.
Other topics discussed in this section, as identified by numbered subsections below, include (2) oil price and production trends in Annual Energy Outlook 2013 (AEO2013); (3) petroleum import dependence under a range of cases; (4) competition between coal and natural gas in the electric power sector; (5) nuclear power in AEO2013; and (6) the impact of natural gas liquids (NGL) growth.
The topics explored in this section represent current and emerging issues in energy markets. However, many of the topics discussed in previous AEOs also remain relevant today. Table 4 provides a list of titles from the 2012, 2011, and 2010 AEOs that are likely to be of interest to today's readers—excluding topics that are updated in AEO2013. The articles listed in Table 4 can be found on the U.S. Energy Information Administration (EIA) website at eia.gov/analysis/reports.cfm?t=128.
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.
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  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 ), 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.
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.
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 , 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.
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.
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 , 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."
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 . 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.
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.
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.
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
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).
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.
The benchmark oil price in AEO2013 is based on spot prices for Brent crude oil (commonly cited as Dated Brent in trade publications), an international benchmark for light sweet crude oil. The West Texas Intermediate (WTI) price has diverged from Brent and other benchmark prices over the past few years as a result of rapid growth in U.S. midcontinent and Canadian oil production, which has overwhelmed the transportation infrastructure needed to move crude oil from Cushing, Oklahoma, where WTI is quoted, to the Gulf Coast. EIA expects the WTI discount to the Brent price level to decrease over time as additional pipeline projects come on line, and will continue to report WTI prices (a critical reference point for the value of growing production in the U.S. midcontinent), as well as imported refiner acquisition costs (IRAC).
AEO2013 projections of future oil supply include two broad categories: petroleum liquids and other liquid fuels. The term petroleum liquids refers to crude oil and lease condensate—which includes tight oil, shale oil, extra-heavy crude oil, and bitumen (i.e., oil sands, either diluted or upgraded), plant condensate, natural gas plant liquids (NGPL), and refinery gain. The term other liquids refers to oil shale (i.e., kerogen-to-liquids), gas-to-liquids (GTL), coal-to-liquids (CTL), and biofuels (including biomass-to-liquids).
The key factors determining long-term supply, demand, and prices for petroleum and other liquids can be summarized in four broad categories: the economics of non-Organization of the Petroleum-Exporting Countries (OPEC) petroleum liquids supply; OPEC investment and production decisions; the economics of other liquids supply; and world demand for petroleum and other liquids.
To reflect the significant uncertainty associated with future oil prices, EIA develops three price cases that examine the potential impacts of different oil price paths on U.S. energy markets (Figure 21). The three price cases are developed by adjusting the four key factors described above. The following sections discuss the adjustments made in AEO2013. Each price case represents one of potentially many combinations of supply and demand that would result in the same price path. EIA does not assign probabilities to any of the oil price cases.
Because EIA's oil price paths represent market equilibrium between supply and demand in terms of annual average prices, they do not show the price volatility that occurs over days, months, or years. As a frame of reference, over the past two decades, volatility within a single year has averaged about 30 percent . Although that level of volatility could continue, the alternative oil price cases in AEO2013 assume smaller near-term price variation than in previous AEOs, because larger near-term price swings are expected to lead to market changes in supply or demand that would dampen the price.
The AEO2013 oil price cases represent internally consistent scenarios of world energy production, consumption, and economics. One interesting outcome of the three oil price cases is that, although the price paths diverge, interactions among the four key factors lead to nearly equal total volumes of world liquids supply in the three cases in the 2030 timeframe (Figure 22).
Among the key factors defining the Reference case are the Organization for Economic Cooperation and Development (OECD) and non-OECD gross domestic product (GDP) growth rates and liquid fuels consumption per dollar of GDP. Both the OECD and non-OECD growth rates and liquids fuels consumption per dollar of GDP decline over the projection period in the Reference case. OPEC continues restricting production in a manner that keeps its market share of total liquid fuels production between 39 percent and 43 percent for most of the projection, rising to 43 percent in the final years. Most other liquid fuels production technologies are economical at Reference case prices. In the Reference case, the Brent price declines to $96 per barrel in 2015 and then increases over the remainder of the period, to $163 per barrel in 2040, as a result of demand increases and supply pressures.
OPEC production in the Reference case grows from 35 million barrels per day in 2011 to 48 million barrels per day in 2040 (Figure 23). Although the OPEC resource base is sufficient to support much higher production levels, the OPEC countries have an incentive to restrict production in order to support higher prices and sustain revenues in the long term. The Reference case assumes that OPEC will maintain a cohesive policy of limiting supply growth, rather than maximizing total annual revenues. The Reference case also assumes that no geopolitical events will cause prolonged supply shocks in the OPEC countries that could further limit production growth.
Non-OPEC petroleum production grows significantly in the early years of the Reference case projection, to 55 million barrels per day in 2020 from 50 million barrels per day in 2011, primarily as a result of increased production from tight oil formations. After 2020, production growth continues at a slower pace, adding another 4 million barrels per day to net production in 2040, with production from new wells increasing slightly faster than the decline in production from existing wells. The growth in non-OPEC production results primarily from the development of new fields and the application of new technologies, such as enhanced oil recovery (EOR), horizontal drilling, and hydraulic fracturing, which increase recovery rates from existing fields. The average cost per barrel of non-OPEC oil production rises as production volumes increase, and the rising costs dampen further production growth.
Non-OPEC production of other liquids grows from 1.8 million barrels per day in 2011 to 4.6 million barrels per day in 2040, as Brent crude oil prices remain sufficiently high to make other liquids production technologies economically feasible. Non-OPEC liquids production in the Reference case totals 58 million barrels per day in 2020, 61 million barrels per day in 2030, and 64 million barrels per day in 2040.
Low Oil Price case
The AEO2013 Low Oil Price case assumes slower GDP growth for the non-OECD countries than in the Reference case. OPEC is less successful in restricting production in the Low Oil Price case, and as a result its share of total world liquids production increases to 49 percent in 2040. Despite lower Brent prices than in the Reference case, non-OPEC petroleum production levels are maintained at roughly 54 million barrels per day through 2030. After 2030, total non-OPEC production declines as existing fields are depleted and not fully replaced by production from new fields and more costly EOR technologies. With higher average costs for resource development in the non-OPEC countries, the Brent crude oil price in the Low Oil Price case is not sufficient to make all undeveloped fields economically viable. Non-OPEC petroleum production rises slightly in the projection, to 54 million barrels per day, before returning to roughly current levels of 51 million barrels per day in 2040. Non-OPEC production of other liquids grows more rapidly than in the Reference case, and in 2040 it is 25 percent higher than projected in the Reference case.
Brent crude oil prices fall below $80 per barrel in 2015 in the Low Oil Price case and decline further to just below $70 per barrel in 2017, followed by a slow increase to $75 per barrel in 2040. In the near term, extra supply enters the market, and lower economic growth in the non-OECD countries leads to falling prices. The higher levels of OPEC petroleum production assumed in the Low Oil Price case keep prices from increasing appreciably in the long term.
OPEC's ability to support higher oil prices is weakened by its inability to limit production as much as in the Reference case. Lower prices squeeze the revenues of OPEC members, increasing their incentive to produce beyond their quotas. As a result, OPEC liquids production increases to 54 million barrels per day in 2040. The lower prices in the Low Oil Price case cause a decline in OPEC revenue to the lowest level among the three cases, illustrating the relatively strong incentive for OPEC members to restrict supply.
High Oil Price case
In the High Oil Price case, non-OECD GDP growth is more rapid than projected in the Reference case, and liquid fuels consumption per unit of GDP in the non-OECD countries declines more slowly than in the Reference case. Continuing restrictions on oil production keep the OPEC market share of total liquid fuels production between 37 and 40 percent, with total oil production about 1.0 million barrels per day lower than in the Reference case. Despite higher Brent oil prices, non-OPEC petroleum production initially expands at about the same rate as in the Reference case because of limited access to existing resources and lower discovery rates. Non-OPEC production of other liquids grows strongly in response to higher prices, rising to 8 million barrels per day in 2040.
Brent crude oil prices in the High Oil Price case increase to $155 per barrel in 2020 and $237 per barrel in 2040 in reaction to very high demand for liquid fuels in the non-OECD countries. The robust price increase keeps total world demand within the range of expected production capabilities.
Liquid fuels  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.
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 , 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  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 . 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.
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 . Both higher and lower values for the rebound have been advanced by various analysts .
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 . 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.
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.
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) , 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.
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 .
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 .
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 .
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
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.
Over the past 20 years, natural gas has been the go-to fuel for new electricity generation capacity. From 1990 to 2011, natural gas-fired plants accounted for 77 percent of all generating capacity additions, and many of the plants added were very efficient combined-cycle plants. However, with slow growth in electricity demand and spikes in natural gas prices between 2005 and 2008, much of the added capacity was used infrequently. Since 2009 natural gas prices have been relatively low, making efficient natural gas-fired combined-cycle plants increasingly competitive to operate in comparison with existing coal-fired plants, particularly in the Southeast and other regions where they have been used to meet demand formerly served by coal-fired plants. In 2012, as natural gas prices reached historic lows, there were many months when natural gas displacement of coal-fired generation was widespread nationally.
In the AEO2013 Reference case, the competition between coal and natural gas in electricity generation is expected to continue in the near term, particularly in certain regions. However, because natural gas prices are projected to increase more rapidly than coal prices, existing coal plants gradually recapture some of the market lost in recent years. Natural gas-fired plants continue to be the favored source for new generating capacity over much of the projection period because of their relatively low costs and high efficiencies. The natural gas share of total electricity generation increases in the Reference case from 24 percent in 2011 to 30 percent in 2040. Coal remains the largest source of electricity generation, but its share of total electricity generation, which was 51 percent in 2003, declines from 42 percent in 2011 to 35 percent in 2040.
At any point, short-term competition between existing coal- and gas-fired generators—i.e., the decisions determining which generators will be dispatched to generate electricity—depends largely on the relative operating costs for each type of generation, of which fuel costs are a major portion. A second aspect of competition occurs over the longer term, as developers choose which fuels and technologies to use for new capacity builds and whether or not to make mandated or optional upgrades to existing plants. The natural gas or coal share of total generation depends both on the available capacity of each fuel type (affected by the latter type of competition) and on how intensively the capacity is operated.
There is significant uncertainty about future coal and natural gas prices, as well as about future growth in electricity demand, which determines the need for new generating capacity. In AEO2013, alternative cases with higher and lower coal and natural gas prices and variations in the rate of electricity demand growth are used to examine the potential impacts of those uncertainties. The alternative cases illustrate the influence of fuel prices and demand on dispatch and capacity planning decisions.
Recent history of price-based competition
In recent years, natural gas has come into dispatch-level competition with coal as the cost of operating natural gas-fired generators has neared the cost of operating coal-fired generators. A number of factors led to the growing competition, including:
- A build-out of efficient combined-cycle capacity during the early 2000s, which in general was used infrequently until recently
- Expansion of the natural gas pipeline network, reducing uncertainty about the availability of natural gas
- Gains in natural gas production from domestic shale formations that have contributed to falling natural gas prices
- Rising coal prices.
Until mid-2008, coal-fired generators were cheaper to operate than natural gas-fired generators in most applications and regions. Competition between available natural gas combined-cycle generators (NGCC) and generators burning eastern (Appalachian) and imported coal began in southeastern electric markets in 2009. Rough parity between NGCC and more expensive coal-fired plants continued until late 2011, when increased natural gas production led to a decline in the fuel price and, in the spring of 2012, a dramatic increase in competition between natural gas and even less expensive types of coal. With natural gas-fired generation increasing steadily, the natural gas share of U.S. electric power sector electricity generation was almost equal to the coal share for the first time in April 2012.
The following discussion focuses on the electric power sector, excluding other generation sources in the residential, commercial, and industrial end-use sectors. The industrial sector in particular may also respond to changes in coal and natural gas fuel prices by varying their level of development, but industrial users typically do not have the option to choose between the fuels as in the power sector, and there are fewer opportunities for direct competition between coal and natural gas for electricity generation.
Outlook for fuel competition in power generation.
The difference between average annual prices per million Btu for natural gas and coal delivered to U.S. electric power plants narrowed substantially in 2012, so that the fuel costs of generating power from NGCC units and coal steam turbines per megawatthour were essentially equal on a national average basis (Figure 26), given that combined-cycle plants are much more efficient than coal-fired plants. When the ratio of natural gas prices to coal prices is approximately 1.5 or lower, a typical natural gas-fired combined-cycle plant has lower generating costs than a typical coal-fired plant. In the Reference case projection, natural gas plants begin to lose competitive advantage over time, as natural gas prices increase relative to coal prices. Because fuel prices vary by region, and because there is also considerable variation in efficiencies across the existing fleet of both coal-fired and combined-cycle plants, dispatch-level competition between coal and natural gas continues.
In the Reference case, coal-fired generation increases from 2012 levels and recaptures some of the power generation market lost to natural gas in recent years. The extent of that recovery varies significantly, however, depending on assumptions about the relative prices of the two fuels. The following alternative cases, which assume higher or lower availability or prices for natural gas and coal than in the Reference case are used to examine the likely effects of different market conditions:
- The Low Oil and Gas Resource case assumes that the EUR per shale gas, tight gas, or tight oil well is 50 percent lower than in the Reference Case. In 2040, delivered natural gas prices to the electric power sector are 26 percent higher than in the Reference case.
- The High Oil and Gas Resource case assumes that the EUR per shale gas, tight gas, or tight oil well is 100 percent higher than in the Reference case, and the maximum well spacing for shale gas, tight gas, and tight oil plays is assumed to be 40 acres. This case also assumes that the EUR for wells in the Alaska offshore and the Federal Gulf of Mexico is 50 percent higher than in the Reference case, that there is development of kerogen resources in the lower 48 states, and that the schedule for development of Alaskan resources is accelerated. In 2040, delivered natural gas prices are 39 percent lower than projected in the Reference case.
- The High Coal Cost case assumes lower mine productivity and higher costs for labor, mine equipment, and coal transportation, which ultimately result in higher coal prices for electric power plants. In 2040, the delivered coal price is 77 percent higher than in the Reference case.
- The Low Coal Cost case assumes higher mining productivity and lower costs for labor, mine equipment, and coal transportation, leading to lower coal prices for electric power plants. In 2040, the delivered coal price is 41 percent lower than in the Reference case.
Figure 27 compares the ratio of average per-megawatthour fuel costs for NGCC plants and coal steam turbines at the national level across the cases. It illustrates the relative competitiveness of dispatching coal-fired steam turbines versus NGCC plants, including the differences in efficiency (heat rates) of the two types of generators. The ratio of natural gas to coal would be about 1.5 without considering the difference in efficiency. Higher coal prices or lower natural gas prices move the ratio closer to the line of competitive parity, where NGCC plants have more opportunities to displace coal-fired generators. In contrast, when coal prices are much lower than in the Reference case, or natural gas prices are much higher, the ratio is higher, indicating less likelihood of dispatch-level competition between coal and natural gas. In both the High Oil and Gas Resource case and the High Coal Cost case, the average NGCC plant is close to parity with, or more economical than, the average coal-fired steam turbine.
Capacity by plant type
In all five cases, coal-fired generating capacity in 2025 (Figure 28) is below the 2011 total and remains lower through 2040 (Figure 29), as retirements outpace new additions of coal-fired capacity. Coal and natural gas prices are key factors in the decision to retire a power plant, along with environmental regulations and the demand for electricity. In the Low Oil and Gas Resource case and Low Coal Cost case, there are slightly fewer retirements than in the Reference case, as a higher fuel cost ratio for power generation is more favorable to coal-fired power plants. In the High Oil and Gas Resource case and High Coal Cost case, coal-fired plants are used less, and more coal-fired capacity is retired than in the Reference case. In the Reference case, 49 gigawatts of coal-fired capacity is retired from 2011 to 2040, compared with a range from 38 gigawatts to 73 gigawatts in the alternative cases. The interaction of fuel prices and environmental rules is a key factor in coal plant retirements. AEO2013 assumes that all coal-fired plants have flue gas desulfurization equipment (scrubbers) or dry sorbent injection systems installed by 2016 to comply with the Mercury and Air Toxics Standards. Higher coal prices, lower wholesale electricity prices (often tied to natural gas prices), and reduced use may make investment in such equipment uneconomical in some cases, resulting in plant retirements.
In all the cases examined, new additions of coal-fired capacity from 2012 to 2040 total less than 15 gigawatts. For new builds, natural gas and renewables generally are more competitive than coal, and concerns surrounding potential future GHG legislation also dampen interest in new coal-fired capacity . New capacity additions are not the most important factor in the competition between coal and natural gas for electricity generation. There is also significant dispatch-level competition in determining how intensively to operate existing coal-fired power plants versus new and existing natural gas-fired plants.
New natural gas-fired capacity, including combined-cycle units and combustion turbines, comprises the majority of new additions in the Reference case. The total capacity of all U.S. natural gas-fired power plants grows in each of the cases, but the levels vary depending on the relative fuel prices projected. Across the resource cases, NGCC capacity in 2025 ranges between 227 and 243 gigawatts, and in 2040 it ranges between 262 and 344 gigawatts, reflecting the impacts of fuel prices on the operating costs of new capacity.
New nuclear capacity and renewable capacity are affected primarily by changes in natural gas prices, with substantial growth in both technologies occurring in the Low Oil and Gas Resource case. Most of the increase occurs after 2025, when delivered natural gas prices in that case exceed $7 per million Btu, and the costs of the nuclear and renewable technologies have fallen from current levels. In this case, higher natural gas prices reduce the competitiveness of natural gas as a fuel for new capacity builds, leading to higher prices and lower demand for electricity. Total generating capacity is similar in the Reference case and the Low Oil and Gas Resource case, but the large amount of renewable capacity built in the Low Oil and Gas Resource case—particularly wind and solar—does not contribute as much generation as NGCC capacity toward meeting either electricity demand or reserve margin requirements.
Generation by fuel
In the Reference case, coal-fired generation increases by an average of 0.2 percent per year from 2011 through 2040. Even though less capacity is available in 2040 than in 2011, the average capacity utilization of coal-fired generators increases over time. In recent years, as natural gas prices have fallen and natural gas-fired generators have displaced coal in the dispatch order, the average capacity factor for coal-fired plants has declined substantially. The coal fleet maintained an average annual capacity factor above 70 percent from 2002 through 2008, but the capacity factor has declined since then, falling to about 57 percent in 2012. As natural gas prices increase in the AEO2013 Reference case, the utilization rate of coal-fired generators returns to previous historical levels and continues to rise, to an average of around 74 percent in 2025 and 78 percent in 2040. Across the alternative cases, coal-fired generation varies slightly in 2025 (Figure 30) and 2040 (Figure 31) as a result of differences in plant retirements and slight differences in utilization rates. The capacity factor for coal-fired power plants in 2040 ranges from 69 percent in the High Oil and Gas Resource case to 81 percent in the Low Oil and Gas Resource case.
Natural gas-fired generation varies more widely across the alternative cases, as a result of changes in the utilization of NGCC capacity, as well as the overall amount of combined-cycle capacity available. In recent years, the utilization rate for NGCC plants has increased, while the utilization rate for coal-fired steam turbines has declined. Capacity factors for the two technologies were about equal at approximately 57 percent in 2012. As natural gas prices rise in the Reference case, the average capacity factor for combined-cycle plants drops below 50 percent in the near term and remains between 48 percent and 54 percent over the remainder of projection period. In the High Oil and Gas Resource case, where combined-cycle generation is more competitive with existing coal-fired generation and the largest amount of new combined-cycle capacity is added, the average capacity factor for combined-cycle plants rises to 70 percent in the middle years of the projection period and remains about 63 percent through the remainder of the projection period. In the Low Oil and Gas Resource case, generation from combined-cycle plants is 37 percent lower in 2040 than in the Reference case, and the capacity factor for NGCC plants declines from around 45 percent in the mid term to 36 percent in 2040. Natural gas-fired generation in the Low Oil and Gas Resource case is replaced primarily with generation from new nuclear and renewable power plants. Similar fluctuations in natural gas-fired generation, but smaller in magnitude, are also seen across the coal cost cases.
The coal and natural gas shares of total electricity generation vary widely across the alternative cases. The coal share of total generation varies from 30 percent to 43 percent in 2025 and from 28 percent to 40 percent in 2040. The natural gas share varies from 22 percent to 36 percent in 2025 and from 18 percent to 42 percent in 2040. In the High Oil and Gas Resource case, natural gas becomes the dominant generation fuel after 2015, and its share of total generation is 42 percent in 2040 (Figure 32).
Competition in the southeastern United States
While examining the national-level results is useful, the competition between coal and natural gas is best examined in a region that has significant amounts of both coal-fired and natural gas-fired capacity, such as the southeastern United States. In the southeastern subregion of the SERC Reliability Corporation (EMM Region 14), the ratio of average fuel costs for NGCC plants to average fuel costs for coal-fired steam turbines in both the High Coal Cost case and the High Oil and Gas Resource case is below that in the Reference case (Figure 33). In this region, which has a particularly efficient fleet of NGCC plants, the fuel cost ratios in both the High Coal Cost case and the High Oil and Gas Resource case remain near or below competitive parity for the majority of the projection period, indicating continued strong competition in the region. While average coal steam turbine heat rates remain largely static over the projection period, the average NGCC heat rates in this region drop appreciably by 2040, and are among the lowest in the nation.
The delivered cost of coal in the region is somewhat higher than in many other regions. Central Appalachian and Illinois Basin coals must be transported by rail or barge to the Southeast, and coal from the Powder River Basin must travel great distances by rail. The region also uses some imported coal, typically along the Gulf Coast, which tends to be more expensive.
In the High Oil and Gas Resource case, retirements of coal-fired generators in this region total 8 gigawatts in 2016 (5 gigawatts higher than in the Reference case) and remain at that level through 2040. Lower fuel prices for new natural gas-fired capacity, along with requirements to install environmental control equipment on existing coal-fired capacity, leads to additional retirements of coal-fired plants. As a result, the coal share of total capacity in the region drops from 39 percent in 2011 to 23 percent in 2040 in the High Oil and Gas Resource case, and the NGCC share rises from 24 percent in 2011 to 40 percent in 2040, when it accounts for the largest share of total generating capacity.
The capacity factors of coal-fired and NGCC power plants also vary across the cases, resulting in a significant shift in the shares of generation by fuel. The natural gas share of total electric power generation in the SERC southeast subregion grows from 31 percent in 2011 to 36 percent in 2040 in the Reference case, as compared with 56 percent in 2040 in the High Oil and Gas Resource case. Conversely, the coal share drops from 47 percent in 2011 to 40 percent in 2040 in the Reference case, compared with 20 percent in 2040 in the High Oil and Gas Resource case.
Competition in the Midwest
In the western portion of the ReliabilityFirst Corporation (RFC) region (EMM Region 11), which covers Ohio, Indiana, and West Virginia as well as portions of neighboring states, the ratio of the average fuel cost for natural gas-fired combined-cycle plants to the average fuel cost for coal-fired steam turbines approaches parity in the High Coal Cost case and the High Oil and Gas Resource case (Figure 34). The RFC west subregion is more heavily dependent on coal, with coal-fired capacity accounting for 58 percent of the total in 2011. The coal share of total capacity falls to 48 percent in 2040 in the Reference case with the retirement of nearly 15 gigawatts of coal-fired capacity from 2011 to 2017. NGCC capacity, which represented only 7 percent of the region's total generating capacity in 2011, accounts for 11 percent of the total in 2040 in the Reference case.
In the High Coal Cost case, only a limited amount of shifting from coal to natural gas occurs in this region, which has a large amount of existing coal-fired capacity and access to multiple sources of coal, including western basins as well as the Illinois and Appalachian basins. Higher transportation rates in this case deter the use of Western coal in favor of more locally sourced Interior and Appalachian coal. The ability to switch coal sources to moderate fuel expenditures reduces the economic incentive to build new NGCC plants, even with coal prices that are higher than those in the Reference case. The NGCC share of the region's total capacity does increase in the High Oil and Gas Resource case relative to the Reference case, to 16 percent in 2040. In all the cases, however, coal-fired generating capacity makes up more than 42 percent of the total in 2040.
The different capacity factors of coal-fired steam turbines and NGCC capacity contribute to a shift in the generation fuel shares, but the lower levels of natural gas-fired capacity in the region limit the impacts relative to those seen in the Southeast. The natural gas share of total generation in the region grows from 6 percent in 2011 to 8 percent in 2040 in the Reference case, 10 percent in 2040 in the High Coal Cost case, and 18 percent in 2040 the High Oil and Gas Resource case. Coal's share of the region's electric power sector generation declines from 66 percent in 2011 to 64 percent in 2040 in the Reference case, and to 54 percent in both the High Coal Cost case and the High Oil and Gas Resource case. In the High Coal Cost case, much of the coal-fired generation is replaced with biomass co-firing rather than natural gas, because without the lower natural gas prices in the High Oil and Gas Resource case, it is more economical to use biomass in existing coal-fired units than to build and operate new natural gas-fired generators.
Other factors affecting competition
In addition to relative fuel prices, a number of factors influence the competition between coal-fired steam turbines and natural gas-fired combined-cycle units. One factor in the dispatch-level competition is the availability of capacity of each type. In New England, for example, competition between coal and natural gas is not discussed, because very little coal-fired capacity exists or is projected to be built in that region, even in the AEO2013 alternative fuel price cases. New England is located far from coal sources, and a regional cap on GHG emissions is in place, which makes investment in new coal-fired capacity unlikely. In the southeastern United States, however, there is more balance between natural gas-fired and coal-fired generating resources.
Further limitations not discussed above include:
- Start-up and shutdown costs. In general, combined-cycle units are considered to be more flexible than steam turbines. They can ramp their output up and down more easily, and their start-up and shutdown procedures involve less time and expense. However, plants that are operated more flexibly (i.e., ramping up and down and cycling on and off) often have higher maintenance requirements and higher maintenance costs.
- Emission rates and allowance costs. Another component of operating costs not mentioned above is the cost of buying emissions allowances for plants covered by the Acid Rain Program and Clean Air Interstate Rule. In recent years, allowance prices have dropped to levels that make them essentially negligible, although for many years they were a significant component of operating costs.
- Transmission constraints on the electricity grid and other reliability requirements. Certain plants, often referred to as reliability must-run plants, are located in geographic areas where they are required to operate whenever they are available. In other cases, transmission limitations on the grid at any given time may determine maximum output levels for some plants.
In 2011, approximately 19 percent of the nation's electricity was generated by 104 operating commercial nuclearreactors, totaling 101 gigawatts of capacity. In the AEO2013 Reference case, annual generation from nuclear power grows by 14.3 percent from the 2011 total to 903 gigawatthours in 2040. However, the nuclear share of the overall generation mix declines to 17 percent as growth in nuclear generation is outpaced by the increases in generation from natural gas and renewables. The Reference case projects the addition of 19 gigawatts of nuclear capacity from 2011 to 2040, in comparison with the addition of 215 gigawatts of natural gas capacity and 104 gigawatts of renewable capacity.
Nuclear capacity is added both through power uprates at existing nuclear power plants and through new builds. Uprates at existing plants account for 8.0 gigawatts of nuclear capacity additions in the Reference case and new construction adds 11.0 gigawatts of capacity over the projection period. About 5.5 gigawatts of new capacity results from Watts Bar Unit 2, Summer Units 2 and 3, and Vogtle Units 3 and 4, all of which are projected to be online by 2020. The AEO2013 Reference case includes the retirement of 0.6 gigawatts at Oyster Creek in 2019, as well as retirements of an additional 6.5 gigawatts of capacity toward the end of the projection. AEO2013 also includes several alternative cases that examine the impacts of different assumptions about the long-term operation of existing nuclear power plants, new builds, deployment of new technologies, and the impacts on electricity markets of different assumptions about future nuclear capacity.
Power uprates increase the licensed capacity of existing nuclear power plants and enable those plants to generate more electricity . The U.S. Nuclear Regulatory Commission (NRC) must approve all uprate projects before they are undertaken and verify that the reactors will still be able to operate safely at the proposed higher levels of output. Power uprates can increase plant capacity by up to 20 percent of the original licensed capacity, depending on the magnitude and type of uprate project. Capital expenditures may be small (e.g., installing a more accurate sensor) or significant (e.g., replacing key plant components, such as turbines).
EIA relied on both reported data and estimates to define the uprates included in AEO2013. Reported data comes from the Form EIA-860 , which requires all nuclear power plant owners to report plans to build new plants or make modifications (such as an uprate) to existing plants within the next 10 years. In 2011, nuclear power plants reported plans to complete a total of 1.5 gigawatts of uprate projects over the next 10 years.
In addition to the reported uprates, EIA included an additional 6.5 gigawatts of uprates over the projection period. The inclusion of potential uprate capacity is based on interactions with EIA stakeholders who have significant experience in implementing power plant uprates.
Building a new nuclear power plant is a complex operation that can take more than a decade to complete. Projects generally require specialized high-wage workers, expensive materials and components, and engineering construction expertise, which can be provided by only a select group of firms worldwide. In the current economic environment of low natural gas prices and flat demand for electricity, the overall market conditions for new nuclear plants are challenging.
Nuclear power plants are among the most expensive options for new electric generating capacity . The AEO2013 Reference case assumes that the overnight capital costs (the cost before interest) associated with building a nuclear power plant in 2012 were $5,429 (2011 dollars) per kilowatt, which translates to almost $12 billion for a dual-unit 2,200-megawatt power plant. The estimate does not include such additional costs as financing, interest carried forward, and peripheral infrastructure updates . Despite its cost, deployment of new nuclear capacity supports the long-term resource plans of many utilities by allowing fuel diversification and by providing a hedge against potential future GHG regulations or higher natural gas prices.
Incentive programs encourage the construction of new reactors in the United States. At the federal level, the Energy Policy Act of 2005 (EPACT2005) established a Loan Guarantee Program for new nuclear plants that are completed and operational by 2020 . A total of $18.5 billion is available, of which $8.3 billion has been conditionally committed to the construction of Southern Company's Vogtle Units 3 and 4 . EPACT2005 also provided a PTC of $18 per megawatt hour for electricity produced during the first 8 years of plant operation . To be eligible for this credit, new nuclear plants must be operational by 2021, and the credit is limited to the first 6 gigawatts of new nuclear capacity. In addition to federal incentives, several states provide a favorable regulatory environment for new nuclear plants by allowing plant owners to recover their investments through retail electricity rates.
In addition to reported plans to build new nuclear power plants, another 5.5 gigawatts of unplanned capacity is built in the later years of the Reference case projection. Higher natural gas prices, growth in electricity demand, and the need to displace retired nuclear and coal-fired capacity all play a role in the growth at the end of the projection period in the Reference case.
NRC has the authority to issue initial operating licenses for commercial nuclear power plants for a period of 40 years. Decisions to apply for operating license renewals are made entirely by nuclear power plant owners, and typically they are based on economics and the ability to meet NRC requirements.
In April 2012, Oyster Creek Unit 1 became the first commercial nuclear reactor to have operated for 40 years, followed by Nine Mile Point Unit 1 in August, R. E. Ginna in September, and Dresden Unit 2 in December 2012. Two additional plants, H.B. Robinson Unit 2 and Point Beach Unit 1, will complete 40 years of operation in 2013. As of December 2012, the NRC had granted license renewals to 72 of the 104 operating U.S. reactors, allowing them to operate for a total of 60 years. Currently, the NRC is reviewing license renewal applications for 13 reactors, and 15 more applications for license renewals are expected between 2013 and 2019.
NRC regulations do not limit the number of license renewals a nuclear power plant may be granted. The nuclear power industry is preparing applications for license renewals that would allow continued operation beyond 60 years. The first such application, for permission to operate a commercial reactor for a total of 80 years is tentatively scheduled to be submitted in 2015. Aging plants may face a variety of issues that could lead to a decision not to apply for a second license renewal, including both economic and regulatory issues—such as increased operation and maintenance (O&M) costs and capital expenditures to meet NRC requirements. Industry research is focused on identifying challenges that aging facilities might encounter and formulating potential approaches to meet those challenges [90, 91]. Typical challenges involve degradation of structural materials, maintaining safety margins, and assessing the structural integrity of concrete .
The outcome of pending research and market developments will be important to future decisions regarding life extensions beyond 60 years. The AEO2013 Reference case assumes that the operating lives of most of the existing U.S. nuclear power plants will be extended at least through 2040. The only planned retirement included in the Reference case is the announced early retirement of the Oyster Creek nuclear power station in 2019, as reported on Form EIA-860. The Reference case also assumes an additional 7.1 gigawatts of nuclear power capacity retirements by 2040, representing about 7 percent of the current fleet. These generic retirements reflect uncertainty related to issues associated with long-term operations and age management.
In March 2012, the NRC issued three orders  that require nuclear power plants to implement requirements related to lessons learned from the accident at Japan's Fukushima Daiichi nuclear power plant in March 2011. Compliance assessments are underway currently at U.S. nuclear power plants. The requirements of the orders must be implemented by December 2016 and will remain in place until they are superseded by rulemaking. Given the evolving nature of NRC's regulatory response to the accident at Fukushima Daiichi, the Reference case does not include any retirements that could result from new NRC requirements that may involve plant modifications to meet such requirements.
Small Modular Reactors
Small Modular Reactor (SMR) technology differs from traditional, large-scale light-water reactor technology in both reactor size and plant scalability. SMRs are typically smaller than 300 megawatts and can be built in modular arrangements. Traditional reactors are generally 1,000 megawatts or larger. The initial estimates for scalable SMRs range from 45 to 225 megawatts. SMRs are small enough to be fabricated in factories and can be shipped to sites via barge, rail, or truck. Those factors may reduce both capital costs and construction times. Smaller SMRs offer utilities the flexibility to scale nuclear power production as demand changes.
The actual construction of a large nuclear power plant can take up to a decade. During construction, the plant owner may incur significant interest costs and risk further cost increases because of delays and cost overruns. SMRs have the potential to mitigate some of the risks, based on their projected construction period of 3 years. Moody's credit rating agency has described large nuclear power plants as bet-the-farm endeavors for most companies, given the size of the investment and length of time needed to build a nuclear power facility , as highlighted by comparisons of the costs of building nuclear power plants with the overall sizes of the companies building them. AEO2013 assumes that the overnight cost of a 2,200-megawatt nuclear power plant is approximately $12 billion, which is a significant share of the market capitalization of some of the nation's largest electric power companies. For example, the largest publicly traded company that owns nuclear power plants in the United States has a market capitalization of about $50 billion .
Although SMRs may offer several potential advantages, there are key issues that remain to be resolved. SMRs are not yet licensed by the NRC. While there are many similarities between SMRs and traditional large reactors, there are several key differences identified by the NRC that will need to be reviewed before a design certification is issued. Until the situation is clarified, there will be substantial uncertainty about the final costs of SMRs. In addition, the NRC must develop a regulatory infrastructure to support licensing review of the SMR designs. The NRC has identified several potential policy and technical issues associated with SMR licensing . In August 2012, the NRC provided a report to Congress that addressed the licensing of reactors, including SMRs [97, 98].
Ultimately, the path to commercialization for SMRs is to develop the infrastructure to manufacture the modules in factories and then ship the completed units to plant sites. Performing a majority of the construction in factories could standardize the assembly process and result in cost savings, as has occurred with U.S. Navy shipbuilding, where construction cost savings have been achieved by centralizing much of the production in a controlled factory setting .
In March 2012, DOE announced its intention to provide $450 million in funding to assist in the initial development of SMR technology . Through cost-sharing agreements with private industry, DOE solicited proposals for promising SMR projects that have the potential to be licensed by the NRC and achieve commercial operation by 2022. In November 2012, DOE announced the selection of Babcock & Wilcox , in partnership with the Tennessee Valley Authority (TVA) and Bechtel International, to share the costs of preparing a license application for up to four SMRs at TVA's Clinch River site in Oak Ridge, Tennessee.
Alternative nuclear cases
In the AEO2013 Low Nuclear case, uprates currently under review by, or expected to be submitted to, the NRC are not included unless they have been reported to EIA. No nuclear power plants are assumed to receive second license renewals in the Low Nuclear case; all plants are assumed to retire after roughly 60 years of operation, except for those specifically discussed below. Other than the 5.5 gigawatts of new capacity already planned, no new nuclear power plants are assumed to be built.
In addition to the retirement of Oyster Creek in 2019, the Low Nuclear case includes the retirement of Kewaunee in 2013. Nuclear power plants that are in long-term shutdown also are assumed to be retired, including San Onofre Nuclear Generating Station (SONGS) Unit 3 and Crystal River Unit 3. Both plants have been in extended shutdown for more than a year, and there is substantial uncertainty about the cost and feasibility of operating the facilities in the future. Southern California Edison is assessing the long-term viability of SONGS Unit 3 and has indicated that it will not be operating for some time, in light of ongoing steam generator issues [102, 103, 104]. Crystal River Unit 3 has been offline since September 2009, as a result of cracks in the containment structure. As of October 2012, replacement power costs and the repairs to Unit 3 were initially estimated to be between $1.3 and $3.5 billion. However, repairs could eventually include replacement of the entire containment structure. Further repairs to Crystal River Unit 3 are being evaluated [105, 106]. In the Reference and High Nuclear cases, SONGS Unit 3 and Crystal River Unit 3 are assumed to return to service when maintenance and repairs have been completed.
The High Nuclear case assumes that all existing nuclear power plants receive their second license renewals and operate through 2040. Uprates in the High Nuclear case are consistent with those in the Reference case (8.0 gigawatts added by 2025). In addition to plants already under construction, the High Nuclear case assumes that nuclear power plants with active license applications at the NRC are constructed, provided that they have a tentatively scheduled Atomic Safety and Licensing Board hearing and will deploy a certified Nuclear Steam Supply System design. This assumption results in the planned addition of 13.3 gigawatts of new nuclear capacity, which is 7.8 gigawatts above what is assumed in the Reference case.
In the High Nuclear case, planned capacity additions are more than double those in the Reference case, but unplanned additions do not change noticeably. The additional planned capacity reduces the need for new unplanned capacity. The importance of natural gas prices for nuclear power plant construction is highlighted in the results of the Low Oil and Gas Resource case, where the average price of natural gas delivered to the electric power sector in 2040 is 26 percent higher than in the Reference case. The higher natural gas prices make nuclear power a more competitive source for new generating capacity, resulting in the addition of 26 gigawatts of unplanned nuclear power capacity from 2011 to 2040. In the High Oil and Gas Resource case, where the average price of natural gas delivered to the electric power sector in 2040 is 39 percent lower than in the Reference case, no unplanned nuclear capacity is built. Similarly, no unplanned nuclear capacity is added in the Low Nuclear case (Figure 35).
The Small Modular Reactor case assumes that SMRs will be the nuclear technology choice available after 2025, rather than traditional gigawatt-scale nuclear power plants. There is uncertainty surrounding SMR design certification and supply chain and infrastructure development, which makes it difficult to develop capital cost assumptions for SMRs. The Small Modular Reactor case assumes that SMRs have the same overnight capital costs per kilowatt as a traditional 1,100-megawatt unit, consistent with cost assumptions in the Reference case. This assumption was made for the purpose of assessing the impact on the amount of new nuclear capacity of a shorter construction period for SMRs than for traditional nuclear power plants.
In the High Nuclear case, nuclear generation in 2040 is 12 percent higher than in the Reference case, and the nuclear share of total generation is 19 percent, compared with 17 percent in the Reference case. The increase in nuclear generation offsets a decline in generation from natural gas (Figure 36) and renewable fuels, which are 5 percent and 2 percent lower in 2040, respectively, than in the Reference case. Coal-fired generation in the High Nuclear case is virtually the same as in the Reference case.
In the Low Nuclear case, generation from nuclear power in 2040 is 44 percent lower than in the Reference case, due to the loss of 45.4 gigawatts of nuclear capacity that is retired after 60 years of operation. As a result, the nuclear share of total generation falls to 10 percent in 2040. The loss of generation is made up primarily by increased generation from natural gas, which is 17 percent higher in the Low Nuclear case than in the Reference case in 2040. Generation from coal and generation from renewables in 2040 both are 2 percent higher than projected in the Reference case.
CO2 emissions from the electric power sector are affected by the share of nuclear power in the generation mix. Unlike coal- and natural gas-fired plants, nuclear power plants do not emit CO2. Consequently, CO2 emissions from the electric power sector in 2040 are 5 percent lower in the Reference case than in the Low Nuclear case, as a result of switching from nuclear generation to mostly natural gas and some coal . In the High Nuclear case, CO2 emissions from the power sector are 1 percent lower than projected in the Reference case, because the High Nuclear case results in slightly more generation from nuclear units than from fossil-fueled units (Figure 37).
Real average electricity prices in 2040 are 1 percent lower in the High Nuclear case than in the Reference case, as slightly less natural gas capacity is dispatched, reducing natural gas prices, which lowers the marginal price of electricity. In the Low Nuclear case, average electricity prices in 2040 are 5 percent higher than in the Reference case as a result of the retirement of a significant amount of nuclear capacity, which has relatively low operating costs, and its replacement with natural gas capacity, which has higher fuel costs that are passed through to consumers in retail electricity prices.
The impacts of nuclear plant retirements on retail electricity prices in the Low Nuclear case are more apparent in regions with relatively large amounts of nuclear capacity. For example, electricity prices in the Low Nuclear case are 9 percent higher in 2040 than in the Reference case for the SERC (Southeast) region, 8 percent higher for the MRO (Midwest) region, and 6 percent higher in the Northeast, Mid-Atlantic, and Ohio River Valley regions . Even in regions where no nuclear capacity is retired, there are small increases in electricity prices compared to the Reference case, because higher demand for natural gas in regions where nuclear plants are retired increases the price of natural gas in all regions.
In the Small Modular Reactor case, shorter construction periods result in lower interest costs, which help to reduce the overall cost of nuclear construction projects. Figure 38 compares the resulting levelized costs for traditional large reactors and for SMRs in the Reference case. For SMRs, there is a savings of approximately $6 per megawatthour in the capital portion of the levelized cost. However, estimates of the fixed O&M costs for SMRs, derived from a University of Chicago study , are 40 percent higher than those assumed in AEO2013 for a new large-scale plant on a dollar per megawatt basis. The higher O&M cost could offset, in part, the capital cost benefit of a shorter construction period. Therefore, the SMR case shows only a 1.4-percent reduction in overall levelized cost relative to the Reference case. The small difference results in about 2.3 gigawatts more new nuclear power capacity in the Small Modular Reactor case than projected in the Reference case. The sensitivity to small changes in cost is notable, given the high degree of uncertainty associated with SMR costs based on the maturity of the technology.
NGL include a wide range of components produced during natural gas processing and petroleum refining. As natural gas production in recent years has grown dramatically, there has been a concurrent rapid increase in NGL production. NGL include ethane, propane, normal butane (n-butane), isobutane, and pentanes plus. The rising supply of some NGL components (particularly ethane and propane) has led to challenges, in finding markets and building the infrastructure necessary to move NGL to the new domestic demand and export markets. This discussion examines recent changes in U.S. NGL markets and how they might evolve under several scenarios. The future disposition of U.S. NGL supplies, particularly in international markets, is also discussed.
Recent growth in NGL production (Figure 39) has resulted largely from strong growth in shale gas production. The lightest NGL components, ethane and propane, account for most of the growth in NGL supply between 2008 and 2012. With the exception of propane, the main source of NGL is natural gas processing associated with growing natural gas production. That growth has led to logistical problems in some areas. For example, much of the increased ethane supply in the Marcellus region is stranded because of the distance from petrochemical markets in the Gulf Coast area.
The uses of NGL are diverse. The lightest NGL component, ethane, is used almost exclusively as a petrochemical feedstock to produce ethylene, which in turn is a basic building block for plastics, packaging materials, and other consumer products. A limited amount of ethane can be left in the natural gas stream (ethane rejection) if the value of ethane sinks too close to the value of dry natural gas, but the amount of ethane mixed in dry natural gas is small. Propane is the most versatile NGL component, with applications ranging from residential heating, to transportation fuel for forklifts, to petrochemical feedstock for propylene and ethylene production (nearly one-half of all propane use in the United States is as petrochemical feedstock). Butanes are produced in much smaller quantities and are used mostly in refining (for gasoline blending or alkylation) or as chemical feedstock. The heaviest liquids, known as pentanes plus, are used as ethanol denaturant, blendstock for gasoline, chemical feedstock, and, more recently, as diluent for the extraction and pipeline movement of heavy crude oils from Canada.
Unlike the other NGL components, a large proportion of propane is produced in refineries (which is mixed with refinery-marketed propylene). Given that refinery production of propane and propylene has been largely unchanged since 2005 at about 540 thousand barrels per day, the growth of propane/propylene supply shown in Figure 39 is solely a result of increased propane yields from natural gas processing plants.
International demand for NGL has provided an outlet for growing domestic production, and after years of being a net importer, the United States became a net exporter of propane in 2012 (Figure 40). Although the quantities shown in Figure 40, based on EIA data, represent an aggregated mixture of propane and propylene, other sources indicate that U.S. propylene exports have been on the decline since 2007 , implying that the recent change to net exporter status is the result of increased supplies of propane from natural gas processing plants.
Current developments in NGL markets
The market currently is reacting to the growing supply of ethane and propane by expanding both domestic use of NGL and export capacity. On the domestic side, much of the U.S. petrochemical industry can absorb ethane and propane by switching from heavier petroleum-based naphtha feedstock in ethylene crackers to lighter feedstock, and recent record low NGL prices have motivated petrochemical companies to maximize the amount of ethane and propane in their feedstock slate. To take advantage of the expected growth in supplies of light NGL components resulting from shale gas production, multiple projects and expansions of petrochemical crackers have been announced (Table 7).
Although the proposed projects shown in Table 7 will largely take advantage of the growing ethane supply, a few petrochemical projects that will use propane directly as a propylene feedstock through propane dehydrogenation also have been announced . Although expanded feedstock use is expected to be by far the largest source of expanded demand for NGL, increased use of NGL as a fuel, especially propane, also is expected—including the marketing of propane as an alternative vehicle fuel  and for agricultural use, with propane suppliers currently offering incentives for farmers to use propane as a fuel to power irrigation systems .
Notwithstanding the efforts to encourage the use of propane as a fuel in the United States, and despite current low prices, opportunities to expand the market for propane in uses other than as feedstock are limited. Therefore, producers, gas processors, and fractionators are looking for a growing export outlet for both ethane and liquefied petroleum gases (LPG—a mixture of propane and butane). Export capacity is being expanded, both on the U.S. Gulf Coast (Targa's expansion of both its gas processing and fractionation capability at Mont Belvieu and its export facility at Galena Park ) and on the U.S. East Coast (Sunoco Logistics' Mariner East project to supply propane and ethane to Philadelphia's Marcus Hook terminal [115, 116]). Exports of ethane from the Marcellus shale to chemical facilities in Sarnia, Ontario, via the Mariner West pipeline system, and from the Bakken formation to a NOVA Chemical plant near Joffre, Alberta, via the Vantage pipeline , are expected by the end of 2013. In addition to planned exports to Canada, a pipeline is being developed to transport ethane from the Marcellus to the Gulf Coast to relieve oversupply. The midstream sector's rapid buildup and expansion of natural gas processing, pipeline, and storage capacity have accommodated increasing volumes of NGL resulting from the sharp growth in shale gas production.
AEO2013 projects continued growth in both natural gas production and NGL supplies, with NGL prices determined in large part by Brent crude oil prices and Henry Hub spot prices for natural gas (Figure 41). In the AEO2013 Reference, Low Oil and Gas Resource, and High Oil and Gas Resource cases, industrial propane prices in 2040 range from $22.13 per million Btu (2011 dollars) in the High Oil and Gas Resource case to $27.48 per million Btu in the Low Oil and Gas Resource case, a difference of approximately 24 percent. The difference between the propane prices in the High and Low Oil and Gas Resource cases increases from $3.49 per million Btu in 2015 to $7.00 per million Btu in 2025 as natural gas prices and NGL production diverge in the two cases. Over time, however, as the divergence in NGL production narrows between the cases, the influence of oil prices on propane prices increases, and the difference in the propane prices narrows in the cases.
Production of NGPL, which are extracted from wet natural gas by gas processors, rises more steeply than natural gas production in the first half of the projection period as a result of increased natural gas and oil production from shale wells, which have relatively high liquids contents. As shale gas plays mature, NGPL production levels off or declines even as dry natural gas production increases (Figure 42).
Variations in NGL supplies and prices contribute to variations in demand for NGL. In the High Oil and Gas Resource case, propane demand in all sectors is higher than projected in the Reference case, and in the Low Oil and Gas Resource case propane demand is lower than in the Reference case. Some of the difference results from changes in the expected energy efficiency of space heating equipment in the residential sector, and possibly some fuel switching, in response to different price levels in the three cases. The remainder is attributed to variations in NGL feedstock consumption in the bulk chemicals sector, where the use of NGL as a fuel and feedstock varies with different price levels. In addition, because NGL feedstock competes with petroleum naphtha in the petrochemical industry, lower NGL prices relative to oil prices lead to more NGL consumption in the petrochemical industry.
The LPG import-export balance changes rapidly when domestic supply exceeds demand. This trend continues in the near term in all three cases. In the High Oil and Gas Resource case, however, with more LPG production, net exports continue to grow throughout the projection (Figure 43). Propane accounts for most of the higher export volumes, which also include smaller amounts of butane and ethane. Currently, most U.S. exports of LPG go to Latin America, where LPG is used for heating and cooking.
The projected growth in NGL demand both for U.S. domestic uses and for export depends heavily on international markets. Current plans for ethane exports are limited to pipelines to Canada, and to date ethane is not shipped by ocean-going vessels. There is room for growth in propane exports, however, because propane is a far more versatile fuel. Propane exports to Latin America are expected to continue, along with some expansion into European markets. In addition, growing markets in Africa  for propane used in heating and cooking, along with continued demand from Asia (for fuel and feedstock), are expected to support exports of propane from both the United States and the Middle East. It remains to be seen how the market for propane exports will develop in the long term, and how the United States will seek value for its propane—converting it into chemicals for domestic use or for export, or exporting raw propane.
International markets also play a role in increased domestic consumption, particularly for expanded petrochemical feedstock consumption. The declining price of ethane improves the economics of ethylene crackers, as indicated by the planned capacities shown in Table 7. The new capacity suggests that companies are planning to gain a greater market share of ethylene demand in Asia, especially in China, which continues to be a growing importer of ethylene . However, that economic advantage has to be weighed against the massive growth in chemical manufacturing complexes in the Middle East, as well as expansions in Asia. Feedstock availability will not be a concern in the Middle East, but most petrochemical plants in China and other Asian countries rely heavily on naphtha as a feedstock, and naphtha is produced from crude oil, which China imports. China is making efforts to diversify its feedstock slate and has announced plans to build coal-to-olefins plants . In addition, China may develop its own shale gas resources over the next 10 to 15 years, which could provide less expensive supplies of ethane and propane. The advantage in the Middle East is its long-term access to feedstocks. Whether the United States can further capitalize on growth in basic chemical production (ethylene, propylene) to build up its higher-value chemical base, and how the production cost of those higher value chemicals would compete with those from Asia and the Middle East, is an open question.
Future plans for U.S. propane disposition will be based on the balance between growth in domestic demand and exports. Rising exports of propane and butane raise issues as well. For example, both propane and butane can be used not only as feedstock in ethylene crackers, but also as feedstock for specific chemical product. For example, dehydrogenation processes can make propylene from propane  and butadiene from butane . The economic value of those chemicals (which would depend on both local and global markets), weighed against the export value of the NGL inputs (propane and butane), will need to be assessed. In addition, the value of derivatives (such as polyethylene and polypropylene) will be considered from the perspective of both their export value and their production costs, which will be tied directly to the price of their precursor inputs, ethylene and propylene. Finally, U.S. refineries produce a significant amount of propylene. There is some degree of flexibility within refineries' fluid catalytic cracker units to produce propylene , and future refinery production of propylene will depend on the value of propylene itself, the value of its co-products (mostly gasoline and propane), and refining costs.
Endnotes for Issues in Focus
65. United States Internal Revenue Code, Title 26, Subtitle A—Income Taxes, Â§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, Â§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.
70. Volatility is a measure of variability in a data series over time (more technically, the annualized standard deviation from the mean). This analysis was conducted using the GARCH estimation method for monthly average Brent crude oil prices.
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 wellâ€™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.
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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.
82.EPA's Proposed Carbon Pollution Standard for New Power Plants would require that new fossil fuel-fired power plants meet an output-based standard of 1,000 pounds of carbon dioxide per megawatthour of electricity generated. That standard would effectively prohibit the construction of new coal-fired power plants without carbon capture and storage. Currently, the EPA is evaluating comments and expects to issue a final rule in 2013. Because the rule is not yet final, it is not assumed to take effect in any of the AEO2013 cases.
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107. Coal has a CO2 emissions factor approximately double that of natural gas. CO2 uncontrolled emissions factors for the electric power sector can be found in EIA's "Electric Power Annual," Table A.3, http://www.eia.gov/electricity/annual/html/epa_a_03.html.
108. The SERC Region in NEMS is represented by an aggregate of EMM Regions 12, 13, 14, 15, and 16. The MRO Region is represented by EMM Regions 3 and 4. The Northeast is represented by EMM regions 5, 6, 7, and 8. The Mid-Atlantic and Ohio Valley are represented by EMM Regions 9, 10, and 11.
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Sections in this chapter