Annual Energy Outlook 2011
Release Date: April 26, 2011 | Next Early Release Date: January 23, 2012 | Report Number: DOE/EIA-0383(2011)
Issues in Focus
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Introduction
The "Issues in focus" section of the Annual Energy Outlook (AEO) provides an in-depth discussion on topics of special interest, including significant changes in assumptions and recent developments in technologies for energy production and consumption. Detailed quantitative results are available in Appendix D. The first topic updates a discussion included in Annual Energy Outlook 2010 (AEO2010) that compared 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 sunset as they would under current law. The other case assumes the extension 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 include (2) a discussion of projected trends in world oil supply and prices based on assumed changes in demand from countries outside the Organization for Economnic Cooperation and Development (OECD) or in the availability of OPEC oil supply; (3) an examination of the potential impacts of proposed revisions to Corporate average fuel economy (CAFE) standards for light duty vehicles (LDVs) and (4) proposed CAFE standards for heavy-duty trucks; (5) potential impacts of a series of updates to efficiency standards for residential and commercial appliances, alone or in combination with revised building codes; (6) an analysis of potential impacts on natural gas and crude oil production of expanded drilling in U.S. offshore fields; (7) prospects for shale gas; (8) the impacts of cost uncertainty on the construction of new electric power plants; (9) the economics of carbon capture and storage; and (10) the impacts of proposed U.S. Environmental Protection Agency (EPA) regulations in the electric power sector.
The topics explored in this section represent current and emerging issues in energy markets; but many of the topics discussed in AEOs published in recent years also remain relevant today. Table 3 provides a list of titles from the 2010, 2009, and 2008 AEOs that are likely to be of interest to today's readers—excluding topics that are updated in AEO2011. The articles listed in Table 3 can be found on the U.S. Energy Information Administration's (EIA's) website at www.eia.gov/analysis/reports.cfm?t=128.
No Sunset and Extended Policies cases
Background
The Annual Energy Outlook AEO2011 Reference case is best described as a "current laws and regulations" case, because it generally assumes that existing laws and current regulations will 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 the analysis of proposed legislative or regulatory changes. While the definition of the Reference case is relatively straightforward, there may be considerable interest in a variety of alternative cases that reflect the updating or extension of current laws and regulations. In that regard, 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 the 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 National Highway Traffic Safety Administration (NHTSA) and the 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 (CAA) that require the EPA to issue or revise regulations if it finds that an environmental quality target is not being met.
To provide some insight into the sensitivity of results to different characterizations of baseline policies, two alternative cases are discussed in this section. 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.
| Table 3. Key analyses of interest from "Issues in focus" in recent AEOs | ||
|---|---|---|
| AEO2010 | AEO2009 | AEO2008 |
| Energy intensity trends in AEO2010 | Economics of plug-in hybrid electric vehicles | Impacts of uncertainty in energy project costs |
| Natural gas as a fuel for heavy trucks: issues and incentives | Impact of limitations on access to oil and natural gas resources in the Federal Outer Continental Shelf | Limited Electricity Generation Supply and Limited Natural Gas Supply cases |
| Factors affecting the relationship between crude oil and natural gas prices | Expectations for oil shale production | Trends in heating and cooling degree-days: Implications for energy demand |
| U.S. nuclear power plants: continued life or replacement after 60? | Bringing Alaska North Slope natural gas to market | Liquefied natural gas: Global challenges |
| Accounting for carbon dioxide emissions from biomass energy combustion | Tax credits and renewable generation | |
| Greenhouse gas concerns and power sector planning | ||
Analysis cases
The two cases prepared—the No Sunset case and Extended Policies case—incorporate all the assumptions from the AEO2011 Reference case, except as identified below. Changes from the Reference case assumptions in these cases include the following.
No Sunset case
- Extension of tax credits for renewable energy sources in the utility, industrial, and buildings sectors and for energy-efficient equipment in the buildings sector, including:
- The PTC of 2.1 cents per kilowatthour or the 30-percent ITC available for wind, geothermal, biomass, hydroelectric, and landfill gas resources, currently set to expire at the end of 2012 for wind and 2013 for the other eligible resources, are assumed to be extended indefinitely.
- For solar power investment, a 30-percent investment tax credit (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, tax credits for the purchase of energy-efficient equipment, including PV in new houses, are assumed to be extended indefinitely, as opposed to ending in 2010 or 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.
- In the industrial sector, the ITC for combined heat and power (CHP) that ends in 2016 in the AEO2011 Reference case is assumed to be extended through 2035.
- Extension through 2035 of the $0.45 per gallon blender's tax credit for ethanol (set to expire at the end of 2011).
- Extension through 2035 of the $1.00 per gallon biodiesel excise tax credit (set to expire at the end of 2011).
- Extension through 2035 of the $0.54 per gallon tariff on imported ethanol (set to expire at the end of 2011).
- Extension through 2035 of the PTC for cellulosic biofuels of up to $1.01 per gallon (set to expire at the end of 2012).
Extended Policies case
With the exception of the blender's and other biofuel tax credits, the Extended Policies case adopts the same assumptions as in the No Sunset case, plus the following:
- Federal equipment efficiency standards are updated at particular intervals consistent with the provisions in the existing law, with the levels based on ENERGY STAR specifications, or Federal Energy Management Program (FEMP) purchasing guidelines for Federal agencies. Standards are also introduced for products that currently are not subject to Federal efficiency standards.
- Updated Federal residential and commercial building energy codes reach 30-percent improvement in 2020 relative to the 2006 International Energy Conservation Code (IECC) in the residential sector and the American Society of Heating, Refrigerating and Air-Conditioning Engineers (ASHRAE) 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 these polices 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 "maximum technologically feasible" levels described in DOE's technical support documents. - The Extended Policies case modifies the Reference case by assuming a 3-percent annual increase in fuel economy standards for new LDVs from model year (MY) 2017 through MY 2025, with subsequent CAFE standards held constant. CAFE standards for LDVs increase from 34.1 miles per gallon (mpg) in MY 2016 to 46.0 mpg in MY 2025.
The AEO2011 Reference case and Extended Policies case include both the attribute-based CAFE standards for LDVs for MY 2011 and the joint attribute-based CAFE and vehicle GHG emissions standards for MY 2012 to MY 2016. However, the Reference case assumes that LDV CAFE standards increase to 35 miles per gallon by MY 2020, as called for in Energy Independence and Security Act of 2007 (EISA2007). CAFE standards are then held constant in subsequent model years, although the fuel economy of new LDVs continues to rise modestly over time. - The extensions of the blender's and all biofuels excise tax credits and import tariffs through 2035 adopted in the No Sunset case are not included in the Extended Policies case. The renewable fuels standard (RFS) enacted in EISA2007 is an alternative instrument for stimulating demand for biofuels. It already is represented in the AEO2010 Reference case, and it tends to be the binding driver on biofuels rather than the tax credits.
- In the industrial sector, CHP tax credits are extended to cover all system sizes rather than applying only to systems under 50 megawatts, and the maximum credit (cap) is increased from $15,000 to $25,000 per system. These extensions are consistent with previously proposed or pending legislation.
- Most shale gas wells are only a few years old, and their long-term productivity is untested. Consequently, reliable data on long-term production profiles and ultimate gas recovery rates for shale gas wells are lacking.
- In emerging shale formations, gas production has been confined largely to "sweet spots" that have the highest known production rates for the formation. When the production rates for the sweet spot are used to infer the productive potential of an entire formation, its resource potential may be overestimated.
- Many shale formations (particularly, the Marcellus shale) are so large that only a portion of the formation has been extensively production tested.
- Technical advances can lead to more productive and less costly well drilling and completion.
- Currently untested shale formations, such as thin seam formations, or untested portions of existing formations, could prove to be highly productive.
- In the High Shale EUR case, the EUR per shale gas well is assumed to be 50 percent higher than in the Reference case. The higher estimate could result from, for example, better placement of the horizontal lateral within the formation; better completion techniques that allow more of the pore space and absorbed gas to reach the well bore; and/or determination that well recompletions are both productive and economic.
- In the High Shale Recovery case, 50 percent more natural gas is assumed to be recovered from each shale formation. The EUR per well is unchanged from the Reference case, and so 50 percent more wells are needed to recover the gas contained in each shale play. Higher recovery could result if a larger portion of each shale formation than originally estimated proves to be productive and economic, and/or if the drilling of more wells, more horizontal laterals, or both closer to each other proves to be productive and economic.
- In the Low Shale EUR case, the EUR per shale gas well is assumed to be 50 percent lower than in the Reference case. The lower estimate could result, for example, from faster rates of decline in gas production than expected in the Reference case, and/or considerably lower ultimate recovery rates than expected for wells in areas where shale formations have not yet been tested.
- In the Low Shale Recovery case, 50 percent less natural gas is recovered from each shale gas play, because, for example, a large number of formations are less productive and less economic than currently anticipated. The EUR per well is unchanged from the Reference case, but the number of wells required to recover the resource is 50 percent lower, because there is 50 percent less natural gas in each shale gas play that can be recovered economically.
Analysis results
The changes made to 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 20 U.S. Energy Information Administration | Annual Energy Outlook 2011 04/25/11 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 impacts in the Extended Policies case tend to be greater than those in the No Sunset case. Although these cases show lower energy prices—because the tax credits and end-use efficiency standards lead to lower energy demand and reduce the cost of renewable fuels—consumers spend more on appliances that are more efficient in order to comply with the tighter appliance standards, and the Government receives lower tax revenues as consumers and businesses take advantage of the tax credits.
Energy consumption
Total energy consumption in the No Sunset case is close to the level in the Reference case (Figure 6). Improvements in energy efficiency lead to slightly reduced consumption in this case, despite somewhat lower energy prices.
Total energy consumption in the Extended Policies case, which assumes the issuance of more stringent efficiency standards for end-use equipment and LDVs in the future, is lower than in the Reference case. In 2035, total energy consumption in the Extended Policies case is nearly 7 percent below the projection in the Reference case. As an example of individual end uses, the assumed future standard for residential electric water heating, which requires installation of heat pumps starting in 2021, has the potential to reduce their electricity use by 50 percent from the Reference case level in 2035. Overall, delivered energy use in the buildings sector in 2035 is 8.5 percent lower in the Extended Policies case than in the Reference case.
Transportation energy consumption
The Extended Policies case modifies the Reference case by assuming a 3-percent annual increase in the stringency of CAFE standards for MY 2017 to MY 2025, with subsequent standards held constant. The LDV CAFE standards in the Extended Policies case increase from 34.1 mpg in 2016 to 46.0 mpg in 2025, as compared with 35.6 mpg in the Reference case. Sales of unconventional vehicles (including those that use diesel, alternative fuels, and/or hybrid electric systems) play a substantial role in meeting the higher fuel economy standards, growing to around 70 percent of new LDV sales in 2035, compared with about 40 percent in the Reference case.
As a result of more stringent CAFE standards, LDV energy consumption declines in the Extended Policies case, from 16.1 quadrillion British thermal unit (Btu) (8.6 million barrels per day) in 2009 to 14.8 quadrillion Btu (8.3 million barrels per day) in 2025 and 14.4 quadrillion Btu (8.1 million barrels per day) in 2035—representing a 10-percent reduction from the Reference case in 2025 and a 19-percent reduction in 2035 (Figure 7). Liquid fuel consumption in the transportation sector continues to grow in the Extended Policies case, from 13.6 million barrels per day in 2009 to 14.1 million in 2025 and 14.2 million in 2035, but at a slower rate than in the Reference case. Cumulative consumption of liquid fuel for transportation between 2017 and 2035 drops by 6.5 billion barrels, or 6 percent, in comparison with the Reference case.
Renewable electricity generation
The extension of tax credits for renewables through 2035 would, over the long run, lead to more rapid growth in renewable generation than projected in the Reference case. When the renewable tax credits are extended without extending energy efficiency standards, as is assumed in the No Sunset case, there is a significant increase in renewable generation in 2035 relative to the Reference case projection (Figure 8). Extending both renewable tax credits and energy efficiency standards results in more modest growth in renewable generation, because renewable generation in the near term 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. In the Reference case, growth in renewable generation accounts for 26 percent of total generation growth from 2009 to 2035. In the No Sunset and Extended Policies cases, growth in renewable generation accounts for 36 to 38 percent of total generation growth. In 2035, the share of total electricity generation accounted for by renewables is 14 percent in the Reference case, as compared with 16 percent in the No Sunset case and the Extended Policies case.
In all three cases, the most rapid growth in renewable capacity occurs in the near term. After that, the growth slows through 2020 before picking up again. Before 2015, ample supplies of renewable energy in relatively favorable resource areas (such as windy lands or accessible geothermal sites), combined with the Federal incentives, make renewable generation competitive with conventional sources. With slow growth in electricity demand and the addition of capacity stimulated by renewable incentives before 2015, little new capacity is needed between 2015 and 2020. In addition, in some regions, attractive low-cost renewable resources already have been exploited, leaving only less favorable sites that may require significant investment in transmission as well as other additional infrastructure costs. Starting around 2020, significant new sources of renewable generation also appear on the market as a result of cogeneration at biorefineries built primarily to produce renewable liquid fuels to meet the Federal RFS, where combustion of waste products to produce electricity is an economically attractive option.
After 2020, renewable generation in the No Sunset and Extended Policies cases increases more rapidly than in the Reference case, and as a result generation from nuclear and fossil fuels is reduced from the levels in the Reference case (Figure 9). Natural gas represents the largest source of displaced generation. In 2035, electricity generation from natural gas is 8 percent lower in the No Sunset case and 16 percent lower in the Extended Policies case than in the Reference case.
Energy-related CO2 emissions
In the No Sunset and Extended Policies cases, lower overall energy demand leads to lower levels of energy-related CO2 emissions than in the Reference case. The Extended Policies case shows much larger emissions reductions than the No Sunset and Reference cases, in part, due to the inclusion of a tighter CAFE policy for transportation. From 2012 to 2035, energy-related CO2 emissions are reduced by a cumulative total of 5.2 billion metric tons (a 3.7-percent reduction over the period) in the Extended Policies case from the Reference case projection, as compared with 0.7 billion metric tons (a 0.5-percent reduction over the period) in the No Sunset case (Figure 10). The increase in fuel economy assumed for new LDVs in the Extended Policies case leads to nearly one-half the total reduction in CO2 emissions in the Reference case projection by 2035. The balance of the reduction in CO2 emissions is due to greater efficiency improvement in appliances and increased penetration of renewable of electricity generation.
The majority of the emissions reductions in the No Sunset case are the result of increases in electricity generation from renewable fuels. By convention, emissions associated with the combustion of biomass for electricity generation are not counted, because they are assumed to be balanced by carbon uptake when the feedstock is grown. A small reduction in transportation sector emissions in the No Sunset case is counterbalanced by an increase in emissions from refineries during the production of synthetic fuels that receive tax credits. 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 the residential sector, 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 commercial sector, only the Extended Policies case sees substantial emission reductions in those categories.
Energy prices and tax credit payments
With lower levels of overall energy use and more consumption of renewable fuels in the No Sunset and Extended Policies cases, energy prices are lower than in the Reference case. In 2035, natural gas wellhead prices are $0.21 per thousand cubic feet (3 percent) and $0.60 per thousand cubic feet (9 percent) lower in the No Sunset and Extended Policies cases, respectively, than in the Reference case (Figure 11), and electricity prices are 2 percent and 6 percent lower than in the Reference case (Figure 12).
The reductions in energy consumption and CO2 emissions in the Extended Policies case require additional equipment costs to consumers and revenue reductions for the U.S. Government. From 2011 to 2035, residential and commercial consumers spend an additional $11 billion per year (in real 2009 dollars) on average for newly purchased end-use equipment, distributed generation systems, and residential building shell improvements in the Extended Policies case than in the Reference case. On the other hand, they save an average of $29 billion per year on their energy bills.
Tax credits paid to consumers in the buildings sector in the Extended Policies case average $14 billion (real 2009 dollars) more per year than in the Reference case. In comparison, revenue reductions as a result of tax credits in the buildings sector average $1 billion more per year over the same period than in the Reference case. However, 60 percent of the revenue reductions in the Reference case occur by 2016 when most of the tax credits are scheduled to expire.
The largest response to Federal PTC incentives for new renewable generation is seen in the No Sunset case, with extension of the PTC resulting in annual average reductions in Government tax revenues of approximately $730 million over the 2011 to 2035 period, as compared with $230 million per year in the Reference case. Additional reductions in Government tax revenue in the No Sunset case result from extensions of both the ethanol and biodiesel blenders tax credits and the cellulosic biofuels PTC, with annual average tax revenue reductions over the period from 2011 to 2035 of $3.1 billion per year (2009 dollars) in comparison with the Reference case.
World oil price and production trends in AEO2011
The world oil price is represented in AEO2011 as the price of light, low-sulfur crude oil delivered at Cushing, Oklahoma. Projections of future supply and demand are made for "liquids." The term "liquids" refers to conventional petroleum liquids, such as conventional crude oil, natural gas plant liquids, and refinery gain, in addition to unconventional liquids, such as biofuels, bitumen, coal-to-liquids (CTL), coal- and biomass-to-liquids, gas-to-liquids (GTL), extra-heavy oils, and oil shale (derived from kerogen).
World oil prices are influenced by a number of factors, some of which have mainly short-term impacts. Others, such as expectations about world oil demand and OPEC production decisions, affect prices in the longer term. Supply and demand in the world oil market are balanced through responses to price movements, and the factors underlying expectations for supply and demand are both numerous and complex. The key factors determining long-term expectations for oil supply, demand, and prices can be summarized in four broad categories: the economics of non-OPEC conventional liquids supply; OPEC investment and production decisions; the economics of unconventional liquids supply; and world demand for liquids.
In 2010, the "prompt month contract" for crude oil (the contract for the nearest month's trading) remained relatively steady from January to November, at a monthly average between $74 and $84 per barrel (2009 dollars), before increasing to just over $89 per barrel in December [44].
Long-term prospects
In past AEOs, High Oil Price and Low Oil Price cases have been used to explore the potential impacts of changes in world liquids supply on world (and U.S.) oil markets as a result of either OPEC production decisions or changes in economic access to non-OPEC resources. In AEO2011, the High Oil Price and Low Oil Price cases have been expanded to incorporate alternative assumptions about liquids supply, economic developments, and liquids demand as key price determinants. The assumed price paths in the AEO2011 High and Low Oil Price cases bracket a broad range of possible future world oil price paths, with prices in 2035 (in real 2009 dollars) at $200 per barrel in the High Oil Price case and $50 per barrel in the Low Oil Price case, as compared with $125 in the Reference case (Figure 13). This is by no means the full range of possible future oil price paths.
Reference case
The global oil market projections in the AEO2011 Reference case are based on the assumption that current practices, politics, and levels of access will continue in the near to mid-term. The Reference case assumes that continued robust economic growth in the non-OECD nations, including China, India, and Brazil, will more than offset relatively tepid growth projected for many OECD nations. In the Reference case, non-OECD liquids consumption is about 25 million barrels per day higher in 2035 than it was in 2009, but OECD consumption grows by less than 3 million barrels per day over the same period. Total liquids consumption grows to 103 million barrels per day by 2030 and 111 million barrels per day by 2035.
The AEO2011 Reference case assumes that limitations on economic access to resources in many areas restrain the growth of non-OPEC conventional liquids production over the projection period and that OPEC production meets a relatively constant share of about 40 percent of total world liquids supply. With those constraining factors, satisfying the growing world demand for liquids in coming decades requires production from higher cost resources, particularly for non-OPEC producers with technically challenging supply projects. In the Reference case, the increased cost of non-OPEC supplies and a constant OPEC market share combine to support average increases in real world oil prices of about 5.2 percent per year from 2009 to 2020 and 1.0 percent from 2020 to 2035. In 2035, the average real price of crude oil in the Reference case is $125 per barrel in 2009 dollars.
Increases in non-OPEC production in the Reference case come primarily from high-cost conventional projects in areas with inconsistent fiscal or political regimes and from increasingly expensive unconventional liquids projects that are made economical by rising oil prices and advances in production technology (Figure 14). Oil sands production in Canada and biofuels production mostly from the United States and Brazil are the most important components of the world's unconventional resources, accounting for nearly 70 percent of the projected incremental supply between 2009 and 2035 in the Reference case.
Low Oil Price cases
In earlier AEOs, the Low Oil Price case assumed that significantly improved access to resources and the willingness of OPEC members to increase their market share would result in low prices and ample supplies, leading to strong increases in demand over the long term. For AEO2011, the Low Oil Price case has been changed to one in which relatively low demand for liquids, combined with greater economic access to and production of conventional resources, results in sustained low oil prices. In particular, the new Low Oil Price case focuses on demand in non-OECD countries, where uncertainty about future growth is much higher than in the OECD nations. The AEO2011 Low Oil Price case assumes that world oil prices fall steadily after 2011 to about $50 per barrel in 2030 and stabilize at that level through 2035, and that relatively low gross domestic product (GDP) growth in the non-OECD countries, compared to the Reference case, keeps their liquids demand at relatively low levels. Average annual GDP growth in the non-OECD nations is assumed to be 1.5 percentage points lower than in the Reference case, or about 3.6 percent on average. The result is that non-OECD demand for liquids in 2035 is 15 million barrels per day lower than would have been projected in previous AEOs, as represented in the AEO2011 Traditional Low Oil Price case. Total world liquids consumption rises to only 108 million barrels per day in 2035 in the AEO2011 Low Oil Price case.
In both the Low Oil Price case and the Traditional Low Oil Price case, low prices limit the development of relatively expensive unconventional supplies. Thus, the volumes of unconventional production supplied are the same in the two cases (Figure 15). Similarly, there is only a modest difference between the volumes of non-OPEC conventional liquids supplies in the two cases. In contrast, OPEC conventional liquids supplies, which increase by about 28 million barrels per day in the Traditional Low Oil Price case, increase by only about 15 million barrels per day in the Low Oil Price case.
High Oil Price cases
In the AEO2011 High Oil Price case, high demand for liquids, combined with more constrained supply availability, results in a sharp, continued increase in world oil prices. As in the Low Oil Price case, GDP growth is used as a proxy for liquids demand growth in the non-OECD nations. Annual GDP growth in non-OECD nations is assumed to be 1.0 percentage points higher in the High Oil Price case than in the Reference case, or 5.7 percent on average. Coupled with more constrained supply, oil prices increase to $200 per barrel in 2035 as a consequence. Despite the higher prices, however, total world liquids consumption grows to 115 million barrels per day in the High Oil Price case, or 4 million barrels per day higher than in the Reference case. In contrast, in the Traditional High Oil Price case, only world liquids supply strategies are assumed to result in higher oil prices and tight supplies, which constrain increases in demand over the long term.
In both the High Oil Price case and the Traditional High Oil Price case, high prices and restrictions on the production of lower cost conventional liquids encourage the development of relatively expensive unconventional supplies. The outlook is similar in the two cases, with about 20 million barrels per day of unconventional resources brought to market in 2035. Non-OPEC liquids supplies are slightly higher in the High Oil Price case than in the Traditional High Oil Price case, but the largest difference between the two cases is in conventional OPEC supplies. The High Oil Price case assumes that OPEC will increase production to maximize revenues, because demand in non-OECD nations is not dampened by high prices. In this case, OPEC conventional liquids supplies increase by almost 8 million barrels per day from 2009 to 2035, as compared with a decline of 2 million barrels per day in the Traditional High Oil Price case.
Increasing light-duty vehicle greenhouse gas and fuel economy standards for model years 2017 to 2025
EPA Notice of Intent to conduct a joint rulemaking
In September 2010, the EPA and the NHTSA issued a Notice of Intent to issue a proposed rule that will set GHG emissions and fuel economystandards for LDVs for MY 2017 through 2025 [45]. The LDV standards cover both passenger cars and light trucks. The notice provides an initial GHG emissions assessment for several potential levels of stringency, representing decreases of 3, 4, 5, and 6 percent per year in GHG emissions and corresponding increases in mpg equivalent fuel efficiency levels from the MY 2016 fleetwide average of 250 grams per mile. For each level of stringency, four technological pathways were analyzed, corresponding to different penetration mixes of advanced gasoline technologies, vehicle mass reductions, and advanced hybrid electric, plug-in hybrid electric, and plug-in electric vehicles.
The four technological pathways were not meant as requirements but were used to show that the potential levels of stringency examined by the EPA and NHTSA are technically feasible. Although the notice provided an initial evaluation of a potential range of increases in stringency, it recognized that much more technological and economic analysis would be needed before a specific standard could be released. The EPA and NHTSA expect to release a proposed rulemaking in September 2011 and to issue a final rulemaking by July 2012.
Sensitivity cases
Two sensitivity cases were used to analyze the impacts of more stringent GHG emissions and fuel economy standards on LDVs in MY 2017 through MY 2025. Fuel economy and GHG emissions standards for MY 2011 through MY 2016 have been promulgated already as final rulemakings, and are already represented in the Reference case; they were, therefore, not modified in these sensitivity cases.
The CAFE 3% Growth (CAFE3) case is a modified Reference case that assumes a 3-percent annual increase in fuel economy standards for MY 2017 through MY 2025 LDVs, starting from the levels for MY 2016 LDVs, with the subsequent post-MY 2025 standards held constant. In 2025, the combined LDV fuel economy standard, at 46.1 mpg, is 29 percent higher than the standard assumed in the AEO2011 Reference case. The CAFE 6% Growth (CAFE6) case assumes a 6-percent annual increase in fuel economy standards for new LDVs from MY 2016 levels for MY 2017 through MY 2025, with the subsequent standards held constant. In 2025, the LDV fuel economy standard, at 59.3 mpg, is 66 percent higher than the standard assumed in the Reference case (Figure 16). For new passenger cars, the fuel economy standard in 2025 is 40.4 mpg in the Reference case, 53.5 mpg in the CAFE3 case, and 75.4 mpg in the CAFE6 case. For new light-duty trucks, the fuel economy standard in 2025 is 29.7 mpg in the Reference case, 38.1 mpg in the CAFE3 case, and 45.5 mpg in the CAFE6 case.
The standards enacted for MY 2011 through 2016 are attribute-based, using vehicle footprint, and allow credits for alternative technologies and fuels to be applied toward compliance. The Notice of Intent for MY 2017 through 2025 does not address the type of attribute standard that would be employed or the structure of credits allowed toward compliance. The sensitivity cases examined here assume a continuation of the current footprint-based attribute standards, as well as credit banking.
Results
In view of the substantial rate of fuel economy improvement required, compliance with the more stringent CAFE standards cases would require a rapid increase in sales of unconventional vehicles (those that use diesel, alternative fuels, and/or hybrid electric systems) and significant improvement in the fuel economy of conventional vehicles that continue to rely solely on gasoline spark-ignited engines for motive power (Table 4). Such rapid changes are likely to challenge the financial, engineering, and production capabilities of the automotive industry. In addition, increased costs for vehicles that employ technologies unfamiliar to consumers could result in lower new vehicle sales relative to the Reference case.
Although this analysis does not address those potential issues, it does project the levels of market penetration by unconventional vehicles and advanced technologies that would be needed for compliance with the more stringent standards, and it estimates the costs of compliance given Reference case assumptions for technology efficiency improvement and cost. The resulting impacts on new LDV sales, stocks, energy demand, and CO2 emissions are discussed below.
Sales of unconventional vehicles, which will be critical to achieving the required fuel economy improvements, are projected to grow to 70 percent of total new LDV sales in 2025 in the CAFE3 case and nearly 90 percent in the CAFE6 case, as compared with 40 percent in the Reference case. In the CAFE3 case, the largest increases in new sales market shares are among hybrid electric, diesel, and micro hybrid systems in conventional gasoline vehicles (Figure 17), all of which are more fuel efficient than their conventional gasoline counterparts. The increase in hybrid and diesel vehicle sales displaces sales of both conventional gasoline and flex-fuel vehicles. The more stringent standards in the CAFE6 case cause an even greater reduction in conventional gasoline and flex-fuel vehicle sales, significantly expanding the market adoption of plug-in hybrid and all-electric vehicles, which are more fuel efficient than their unconventional counterparts, and even greater sales share for hybrid electric and diesel vehicles.
While declining as a share of total new vehicle sales, sales of conventional gasoline vehicles without micro hybrid systems still account for a significant percentage (30 percent) of new vehicles in the CAFE3 case and a less, but still important share (11 percent) in the CAFE6 case. Conventional gasoline vehicle fuel economy increases in both cases through the introduction of new fuel-efficient technologies and improved vehicle designs. In order to meet the increased fuel economy requirements, conventional vehicle subsystems (engine, transmission, aerodynamics, vehicle weight, and horsepower) would have to be modified to ensure compliance. Included in conventional gasoline vehicle technologies but counted separately in the discussion above are micro hybrid systems, which are present in 36 percent of conventional gasoline vehicles in the CAFE3 case and 58 percent in the CAFE6 case in 2025, compared with 12 percent in the Reference case.
The market adoption of unconventional vehicles and inclusion of additional technologies that improve the fuel economy of conventional gasoline vehicles results in higher average prices for new LDVs compared to the Reference case. As a result, while vehicle operating costs would fall (see below), consumers would need to purchase more expensive vehicles (Figure 18). A distribution of vehicle sales by price in 2010, derived from Ward's Automotive data [46], shows that 31 percent of the new vehicles purchased by consumers were within a price range of $10,000 to $25,000, 49 percent within $25,000 to $35,000, and 19 percent at prices above $35,000. In the CAFE3 case, the distribution in 2025 shifts to 15 percent within $10,000 to $25,000, 61 percent within $25,000 to $35,000, and 24 percent above $35,000 (all 2009 dollars). The sales distribution in 2025 shifts even more in the CAFE6 case, with 9 percent within $10,000 to $25,000, 56 percent within $25,000 to $35,000, and 35 percent above $35,000 (all 2009 dollars).
The cases estimate a demand response for new vehicle sales as a result of changes in average new vehicle price by employing a price elasticity of demand of -1. While this measure attempts to quantify the potential impact of the increase in vehicle price on sales, it is not intended to be inclusive of all the potential factors that could affect new vehicle purchase decisions made by consumers. As a result of higher vehicle prices, total new LDV sales in 2025 are 8 percent lower in the CAFE3 case and 14 percent lower in the CAFE6 case than in the Reference case.
As vehicle attributes change to meet more stringent CAFE standards, such as decreased average vehicle horsepower and weight, some consumers switch from passenger cars to light-duty trucks, which in the CAFE3 case have average fuel economies in 2025 comparable to those for passenger cars in 2016. The share of total new LDV sales made up by light-duty trucks is 40 percent in the CAFE3 case and 41 percent in the CAFE6 case in 2025, up from 38 percent in the Reference case, but still far lower than their share (more than 50 percent) in 2005. Note, however, that consumer incentives to switch from cars to light trucks are sensitive to the assumed relative stringency of cars versus light truck CAFE.
Although the CAFE sensitivity cases allow for fluctuation in new LDV sales and switching between purchases of passenger cars and light-duty trucks, additional impacts on fuel demand would be associated with the continued use of existing vehicle stocks. As consumers defer new vehicle purchases, the utilization of older, less fuel-efficient vehicles increases relative to the Reference case. The demand for mobility and the stock of vehicles available in the Reference case are maintained over the projection period in the CAFE cases, but the two CAFE cases assume longer vehicle survival rates and more intensive use of older vehicles.
| Table 4. Unconventional light-duty vehicle types | |
|---|---|
| Unconventional vehicle types | Description |
| Micro hybrid | Vehicles with gasoline engines, larger batteries, and electrically powered auxiliary systems that allow the engine to be turned off when the vehicle is coasting or idle and then quickly restarted. Regenerative braking recharges the batteries but does not provide power to the wheels for traction. |
| Hybrid electric (gasoline or diesel) | Vehicles that combine internal combustion and electric propulsion but have limited all-electric range and batteries that cannot be recharged using grid power. |
| Diesel | Expectations for oil shale productionTrends in heating and cooling degree-days: Implications for energy demand |
| Plug-in hybrid electric (10- and 40-mile all-electric range) | Vehicles that use battery power to drive for some distance, until a minimum level of battery power is reached, at which point they operate on a mixture of battery and internal combustion power. Plug-in hybrids also can be engineered to run in a "blended mode," where an onboard computer determines the most efficient use of battery and internal combustion power. The batteries can be recharged from the grid by plugging a power cord into an electrical outlet. |
| Plug-in electric (100- and 200-mile range) | Vehicles that operate by electric propulsion from batteries that are recharged either from the grid exclusively or through regenerative breaking. |
| Flex-fuel | Vehicles that run on gasoline or any gasoline-ethanol blend up to 85 percent ethanol. |
The United States currently has a total LDV stock of around 230 million vehicles. That number grows to over 300 million vehicles by 2035 in the Reference and CAFE cases. Although the introduction of more stringent fuel economy standards in the CAFE cases stimulates sales of more fuel-efficient new vehicles, it takes time for the new vehicles to penetrate the vehicle fleet in significant numbers to affect the average of fuel economy of the entire LDV stock. In the CAFE cases, the trend is even slower, as a result of reduced scrappage and increased travel of older vehicles. Consequently, the average on-road fuel economy of the LDV stock, which represents the fuel economy realized by all vehicles in use, increases from 22.4 mpg in 2016 to 28.6 mpg in 2025 in the CAFE3 case and 30.2 mpg in the CAFE6 case, as compared with 25.7 mpg in the Reference case. In 2035, the average on-road fuel economy of the LDV stock increases to 34.0 mpg in the CAFE3 case and 39.4 mpg in the CAFE6 case, 22 percent and 41 percent higher, respectively, than the Reference case average of 27.9 mpg (Figure 19).
In the two CAFE cases, more stringent fuel economy standards lead to reductions in total delivered energy consumption, including all fuels. Fuel bills fall by a similar amount. Total cumulative delivered energy consumption by LDVs from 2017 to 2035 is 10 percent lower in the CAFE3 case than in the Reference case and 13 percent lower in the CAFE6 case. In 2025, total delivered energy consumption by LDVs is 19 percent lower in the CAFE3 case and 27 percent lower in the CAFE6 case than in the Reference case. Total liquids fuel consumption in 2035 is 1.9 million barrels per day lower in the CAFE3 case and 2.8 million barrels per day lower in the CAFE6 case than in the Reference case (Figure 20). Reductions in total delivered energy consumption and liquids fuel consumption are more pronounced later in the projection period, when a greater percentage of the total vehicle stock consists of vehicles with higher fuel economy.
The declines in total LDV energy demand in the CAFE cases lead to large reductions in motor gasoline consumption—from 98 percent of total LDV energy use in 2016 to 84 percent in 2025 and 77 percent in 2035 in the CAFE3 case, as compared with 91 percent in 2025 and 89 percent in 2035 in the Reference case. The more stringent fuel economy standards called for in the CAFE6 case lead to even greater reductions in motor gasoline consumption, to 83 percent of total LDV energy use in 2025 and 69 percent in 2035.
Despite the overall decline in energy consumption by LDVs, the changing composition of the fleet by vehicle fuel type leads to increased consumption of some fuels. Lower demand for motor gasoline reduces the amount of ethanol that can be blended into the motor gasoline pool as either E10 or E15. As a consequence, more fuel containing up to 85 percent ethanol (E85) is sold to meet the RFS. E85 accounts for 11 percent of total LDV energy use in 2035 in the CAFE3 case and 14 percent in the CAFE6 case, compared with 7 percent in the Reference case. Diesel fuel consumption increases to 11 percent and 15 percent of total LDV energy use in 2035 in the CAFE3 and CAFE6 cases, respectively, compared with 4 percent in the Reference case. Electricity use by LDVs remains less than 1 percent of total LDV energy use in both the Reference and CAFE3 cases but reaches 3 percent of the total in the CAFE6 case, where sales of plug-in vehicles and all-electric vehicles expand.
Reductions in LDV delivered energy consumption lead to lower GHG emissions from the transportation sector. Cumulative CO2 emissions from transportation over the period from 2009 through 2035 are 2.2 billion metric tons lower in the CAFE3 case and 2.6 billion metric tons lower in the CAFE6 case than in the Reference case, reductions of 6 percent and 7 percent, respectively. CO2 emissions decline from 1,927 million metric tons in 2016 to 1,826 million metric tons in 2025 in the CAFE3 case and to 1,815 million metric tons in the CAFE6 case, as compared with 1,940 million metric tons in the Reference case. In 2035, CO2 emissions from transportation fuel use total 1,859 million metric tons in the CAFE3 case and 1,788 million metric tons in the CAFE6 case, compared with 2,080 million metric tons in the Reference case (Figure 21).
CO2 emissions from the electric power and refinery sectors also are affected by increased electricity use for plug-in vehicles. Cumulative emissions from the electric power sector over the period from 2017 to 2035 are 118 million metric tons higher in the CAFE3 case and 416 million metric tons higher in the CAFE6 case than in the Reference case—increases that are equal to 0.3 percent and 0.9 percent of total CO2 emissions from electricity generation, respectively, over the same period. More stringent fuel economy standards reduce motor gasoline demand by more than they increase demand for diesel and E85 fuels. As a result, cumulative CO2 emissions from refineries between 2017 and 2035 decline by 359 million metric tons in the CAFE3 case and 471 million metric tons in the CAFE6 case from the Reference case level—declines of 8.8 percent and 11.6 percent, respectively.
Issues
Setting LDV fuel economy standards 6 to 14 years into the future is a difficult undertaking, given the uncertainties associated with technology availability and cost, consumer acceptance and willingness to pay for unfamiliar technology, and fuel prices. The availability and cost of advanced vehicle technologies are critical in determining the ability of manufacturers to meet more stringent standards, but there is a high degree of uncertainty regarding the cost and availability of key technologies so far into the future.
For example, battery technologies used in plug-in vehicles are important in meeting more stringent standards in the CAFE3 case and are critical to compliance in the CAFE6 case. The future cost and performance of battery technologies in 2025 cannot be known with confidence. If there are limited breakthroughs in the cost, safety, or life of batteries, then the ability to meet, for example, the levels of stringency called for in the CAFE6 case, which will very likely necessitate plug-in vehicles, will be extremely challenging. On the other hand, a breakthrough in battery technology or another known technology, or the introduction of a new unforeseen technology, could dramatically lessen the burden on manufacturers of meeting more stringent CAFE standards in terms of both cost and availability.
When manufacturers bring an advanced vehicle technology to market, consumers must be willing to buy it. There is a high level of uncertainty about consumer willingness to pay significantly higher prices for more fuel-efficient vehicles. In recent history, consumers have tended to value upgrades in performance, vehicle size, and other attributes at the expense of fuel economy.
For example, assuming an annual vehicle use of 14,000 miles per year, a fuel price of $4 per gallon, and no discount rate, a consumer would save 117 gallons of fuel worth $467 each year by driving a vehicle with a fuel economy of 40 mpg instead of 30 mpg. However, purchasing a vehicle that gets 70 mpg instead of 60 mpg would save only 33 gallons, worth $133 (Figure 22). This is important, because the cost of adding technology to an already fuel-efficient vehicle tends to get increasingly expensive (for example, changing a conventional gasoline vehicle to a plug-in hybrid electric vehicle). As manufacturers strive to improve fuel economy, the least costly technologies that reduce fuel consumption will be incorporated first. Employing additional technology to increase fuel economy further will require the use of more expensive technologies.
Consumer willingness to pay for improved fuel economy changes dramatically with different potential fuel prices, which are highly uncertain. If the price of fuel in 14 years is significantly higher than today's prices, a cost-conscious consumer may be willing to pay much more for a vehicle with higher fuel economy, perhaps even without increases in CAFE and GHG standards. Conversely, if fuel prices in the future are relatively low, it may be difficult to convince consumers to pay for fuel economy improvements if the savings from improving fuel economy have only a small impact on their annual fuel expenditures. The willingness of consumers to purchase vehicles with higher fuel economy could also affect both new vehicle sales and scrappage rates.
Fuel consumption and greenhouse gas emissions standards for heavy-duty vehicles
The proposed rulemaking
The EPA and NHTSA in November 2010 jointly issued a proposed rulemaking that would, for the first time, establish greenhouse gas emissions and fuel consumption standards for heavy-duty vehicles (HDV) [47].The proposed standards separately address three discrete vehicle categories: combination tractors, heavy-duty pickup trucks and vans, and vocational vehicles (Table 5). The final regulations are scheduled to be issued by July 2011.
For combination tractors, standards are proposed by cab type, roof type, and engine type. For heavy-duty pickups and vans, the proposed standards are categorized by diesel or gasoline engine and are set as total vehicle gallons per 100 miles, or grams per mile, based on a vehicle's "work factor"—a weighted average of payload and towing capacity. For vocational vehicles, the standards are proposed for different chassis types, according to gross vehicle weight rating (GVWR) and engine type. Standards for combination tractor cabs and vocational vehicles are set as gallons per 1,000 ton-miles or grams per ton-mile, and engine standards are set as gallons per 100 brake horsepower-hours [48] or grams per horsepower-hour.
Heavy-duty vehicle fuel economy standards
AEO2011 includes a sensitivity case that analyzes the estimated impacts of the proposed fuel consumption and GHG emissions standards for heavy-duty trucks. However, because of data and modeling limitations, impacts of the standards for specific truck types or engines could not be represented. Instead, the HDV Fuel Economy Standards case approximates the proposed fuel consumption and GHG emissions standards by increasing the on-road fuel economy of new heavy-duty trucks by approximately 8.5 percent in MY 2017 from MY 2010 levels.
The increase in on-road fuel economy for heavy-duty trucks in MY 2017 in the sensitivity case is based on estimates developed from the U.S. Census Bureau's 2002 Vehicle Inventory and Use Survey (VIUS) [49] and from Ward's Auto [50], which together provide data on vehicle body type, tractor cab type, and engine type by GVWR classification. The estimated vehicle distributions were combined with the EPA and NHTSA estimates of reductions in fuel consumption in MY 2017 for combination tractors and vocational vehicles and in MY 2018 for heavy-duty pickups and vans, compared to a MY 2010 baseline [51].
Using data from VIUS and Ward's Automotive, fuel consumption reductions provided by EPA and NHTSA were combined and aggregated into the reported categorization of heavy-duty trucks used in AEO2011: medium heavy-duty trucks (includes Class 3 through Class 6 trucks with GVWR 10,001 to 26,000 pounds) and heavy heavy-duty trucks (Class 7 and Class 8 trucks with GVWR greater than 26,001 pounds), regardless of vehicle body or engine type. This weighting and aggregation showed an approximately 10 percent reduction in fuel consumption for both categories of heavy-duty trucks in MY 2017 from MY 2010 levels, relative to a simulated fuel economy estimate. The reduction in fuel consumption was modeled as an increase in on-road new vehicle fuel economy to account for the potential variation of simulation-tested fuel economy from expected on-road performance. Increases in fuel economy begin in MY 2014, the first year that GHG emissions standards are binding (Figure 23).
Between MY 2014 and MY 2017, the new heavy-duty truck standards lead to the adoption of technologies to improve fuel economy that otherwise would not have been purchased. For new medium heavy-duty trucks, average on-road fuel economy increases from 7.9 mpg (gasoline) in 2013 (the year before imposition of binding GHG emission standards) to 8.5 mpg in 2017—a 7.8-percent increase from the AEO2011 Reference case projection. On-road fuel economy for heavy heavy-duty vehicles increases from 5.7 mpg in 2013 to 6.2 mpg in 2017, a 9.6-percent increase from the Reference case. After 2017 the standards are held constant, but owner-operators have the option of purchasing additional fuel-efficient technology according to their economic choice based on the net present value of fuel savings compared with the incremental cost of the technology. In 2035, the on-road fuel economy of new medium and heavy heavy-duty vehicles reaches 8.4 and 6.4 mpg, respectively, as compared with 7.8 and 6.4 mpg in the Reference case.
Results
In the HDV Fuel Economy Standards case, new medium and heavy heavy-duty trucks with higher on-road fuel economy gradually penetrate the market. Progress is limited, however, due to the slow turnover in the stock of heavy trucks, which have a median lifetime of 29 years. Between 2014 and 2035, new heavy-duty truck sales per year are equal to about 6 percent of the total heavy-duty truck stock, ranging between about 600,000 and 900,000 new heavy-duty trucks sales per year out of a total stock that grows from 10 million in 2014 to 17 million in 2035. As new heavy-duty trucks are added to the total stock and older trucks with lower fuel economy are removed from service, the average on-road fuel economy for the total stock of medium and heavy heavy-duty trucks increases in the HDV Fuel Economy Standards case (Figure 24).
For medium heavy-duty trucks average on-road fuel economy increases from 7.9 median mpg in 2013 to 8.0 mpg in 2017 and 8.4 mpg in 2035, as compared with 7.9 mpg and 7.8 mpg, respectively, in the Reference case. For heavy heavy-duty trucks, on-road fuel economy increases from 5.7 mpg in 2013 to 5.9 mpg in 2017 and 6.3 mpg in 2035, as compared with 5.7 mpg and 6.2 mpg, respectively, in the Reference case.
The higher on-road fuel economy of the heavy-duty truck stock reduces total delivered energy consumption in the Fuel Economy Standards case. Total cumulative delivered energy consumption by heavy-duty trucks from 2014 to 2035 is 3 percent lower in the Fuel Economy Standards case than in the Reference case. The difference amounts to a cumulative reduction of slightly less than 1 percent of total delivered transportation energy consumption from 2014 to 2035. Total delivered energy consumption is 0.6 percent lower in 2017, the first year of complete implementation, and 0.5 percent lower in 2035 in the Fuel Economy Standards case than in the Reference case. Total liquids fuel consumption in 2035 is about 75 thousand barrels per day lower in the Fuel Economy Standards case than in the Reference case (Figure 25).
However, heavy-duty truck total delivered energy and liquids fuel consumption climbs in both cases, as travel demand increases with growth in industrial output.
Cumulative CO2 emissions from 2014 to 2035 are lower by 276 million metric tons (about 3 percent) in the HDV Fuel Economy Standards case than in the Reference case, representing a reduction of less than 1 percent in total CO2 emissions from the transportation sector (Figure 26).
Issues
The HDV Fuel Economy Standards case approximates the proposed rulemaking by aggregating vehicle body type data from the 2002 VIUS. (The survey has not been updated since 2002.) There may be significant differences between the heavy-duty truck market today and the market a decade ago. Further, there are data uncertainties associated with the 2002 VIUS, but the data were used because VIUS is the only source of information on vehicle body type. Also, little if any information is available on other metrics used in the proposed standards.
Numerous limitations in the available data on the types and numbers of heavy trucks sold according to the vehicle classifications specified in the proposed standards make it difficult to estimate the energy impacts that could be expected as heavy-duty trucks begin to comply with the new standards. Without better and more complete data, it is difficult to analyze the composition of the heavy-duty truck market at the level of diversity included in the proposed standards, or the efficiency and fuel economy metrics associated with each classification in the standards. In addition, the lack of data makes it difficult to define an accurate baseline from which to gauge improvement.
Another issue is how compliance will be measured, and how well compliance testing procedures will replicate the average real-world performance of combination tractors, heavy-duty pickups and vans, and vocational vehicles. For combination tractors, which tend to spend a majority of their operation under steady conditions, such as highway driving, engine manufacturers must demonstrate compliance by using the steady-state Supplemental Engine Test [52]. Tractor manufacturers will then be required to install certified engines, with tractor compliance measured by an input-based truck simulation model, the Greenhouse Gas Emissions Model (GEM). GEM uses fixed input values, such as payload and trailer weights. Compliance will vary with the GEM inputs for aerodynamics, weight, tires, and idle reduction and speed limiter technologies.
Compliance for heavy-duty pickups and vans will be determined by a vehicle test procedure similar to the national program for LDVs, using the highway fuel economy test and the Federal test procedure for city driving, weighted 45 percent and 55 percent, respectively. Heavy-duty pickups and vans are assumed to be loaded to one-half of their payload capacity.
Vocational vehicles also use the GEM simulation model to demonstrate chassis compliance, using fixed curb and payload weights for each vehicle category, with tires being the only manufacturer-specific technology that can be input into the model. The proposed rulemaking weights the test drive-cycle as 37 percent at 65 miles per hour cruise, 21 percent at 55 miles per hour cruise, and 42 percent in transient performance, which broadly covers urban conditions. Chassis manufacturers will be allowed to install only certified CO2 and fuel consumption compliant engines based on the transient Heavy-Duty Federal Test Procedure.
As validation, GEM results for fuel consumption and CO2 emissions were compared with three SmartWay certified tractors in a chassis testing procedure. The GEM results were within 4 percent of the chassis testing results. Although the testing mechanisms may accurately reflect real-world conditions, they may either underestimate or overestimate average fuel consumption and CO2 emissions by vehicle category. Ultimately, fuel savings will be realized from the new standards; but given data limitations it is difficult to say with certainty the extent to which they will occur.
| Table 5. Vehicle categories for the HDV standards | ||
|---|---|---|
| Vehicle category | Description | Truck classes covered |
| Combination tractors | Semi trucks that typically pull trailers. | Class 7 and Class 8 (GVWR 26,001 pounds and above). |
| Heavy-duty pickups and vans | Pickup trucks and vans, such as 3/4-ton or 1-ton pickups used on construction sites or 12- to 15-person passenger vans. | Class 2b and Class 3 (GVWR 8,501 to 14,000 pounds). |
| Vocational vechicles | Includes a wide range of truck configurations, such as delivery, refuse, utility, dump, cement, school bus, ambulance, and tow trucks. For purposes of the rulemaking, vocational vehicles are defined as all heavy-duty trucks that are not combination tractors or heavy-duty pickups or vans. | Class 2b through Class 8 (GVWR 8,501 pounds and above). |
Potential efficiency improvements in alternative cases for appliance standards and building codes
In 2009, the residential and commercial buildings sectors used 19.6 quadrillion Btu of delivered energy, or 21 percent of total U.S. energy consumption. The residential sector accounted for 57 percent of that energy use and the commercial sector 43 percent. In the AEO2011 Reference case, delivered energy for buildings increases by 16 percent, to 22.8 quadrillion Btu in 2035, which is moderate relative to the rate of increase in the number of buildings and their occupants. Accordingly, energy use in the buildings sector on a per-capita basis declines in the projection. The decline of buildings energy use per capita in past years is attributable in part to improvements in the efficiencies of appliances and building shells, and efficiency improvements continue to play a key role in projections of buildings energy consumption.
Three alternative cases in AEO2011 illustrate the impacts of appliance standards and building codes on energy delivered to the residential and commercial sectors (Figure 27). The Expanded Standards case assumes multiple rounds of updates to appliance standards for most end uses. The Expanded Standards and Codes case includes the same updates to standards and adds several rounds of updates to national building codes. These cases differ from the Extended Policies case, in that they do not include the tax credit extensions assumed in the No Sunset case. The 2010 Technology case assumes that future equipment purchases are limited to the options available in 2010, and that the 2010 building codes remain unchanged through 2035. The 2010 Technology case includes all current Federal standards, but unlike the Reference case it does not include future efficiency levels established by equipment manufacturers and efficiency advocates through consensus agreements.
Without the benefits of technology improvement, buildings energy use in the 2010 Technology case grows to more than 24 quadrillion Btu in 2035, compared to under 23 quadrillion Btu in the Reference case. In the Expanded Standards and Codes case, energy delivered to the buildings sectors does not exceed 21 quadrillion Btu throughout the projection period.
Background
Governments at both the State and Federal levels have used appliance standards and building codes to mandate minimum levels of efficiency in commercially available products and in new construction. California first established standards for selected appliances in the mid-1970s, and the Federal Government followed in 1987 with the National Appliance Energy Conservation Act. Currently, most major end-use devices are covered by Federal standards, and some States have added standards for such products as televisions, audio and video equipment, swimming pool pumps, commercial holding cabinets for hot food, and bottle-type water dispensers.
There are no Federal building codes; rather, codes are set at the State level. For residential buildings, most State codes are some version of the IECC. Commercial building codes are more likely to be based on specifications developed jointly by the American National Standards Institute, the ASHRAE, and the Illuminating Engineering Society of North America. In addition, the States have sole responsibility for compliance monitoring and enforcement of the codes, and efforts vary significantly across States.
Although both contribute to efficiency improvements and reduced energy consumption, building codes and appliance standards achieve those goals in different ways. Appliance standards set efficiency levels and require new equipment to provide a given level of service output (e.g., heat, light, or refrigeration) with a reduced level of energy input.
Building codes can reduce energy mainly for heating and cooling equipment by increasing insulation and decreasing air infiltration. Better insulation impedes heat transfer, and better infiltration control reduces air transfer between outdoor elements and indoor conditioned space. Those measures make the work done by heating and cooling equipment more effective, essentially by creating a more robust barrier between outdoor and indoor spaces.
Appliance standards
DOE's thresholds for setting Federal standards include average energy use in excess of 150 kilowatthours (or Btu equivalent) per household for any 12-month period; aggregate household energy use in excess of 4.2 billion kilowatthours (14.3 trillion Btu); and technological feasibility of substantial efficiency improvement for the product. For example, a typical refrigerator under the 2001 DOE standard can use up to 510 kilowatthours per year, and residential refrigeration in aggregate consumed 367 trillion Btu in 2009. Once a product is covered by DOE, the States must seek waivers from Federal preemption in order to implement their own standards.
Assumptions for future efficiency standards in the Extended Policies case and the Expanded Standards case are based on ENERGY STAR specifications or, for some products in the commercial sector, FEMP guidelines. The first round of standards in the Expanded Standards case assumes ENERGY STAR levels, but the improvements assumed for subsequent rounds are only 50 percent of those assumed for the first round (7.5 percent in the case of dehumidifiers). This approach is taken because, for example, an ENERGY STAR dehumidifier uses 15 percent less energy than required by the most recent standard, but it may be unreasonable to assume that future standards for dehumidifiers (or any other equipment) will always be able to achieve improvements of the same magnitude. In addition, the assumed future standards do exceed the "maximum technologically feasible" levels described in technical support documents for DOE's rulemaking.
Future efficiency levels for several products, in addition to standards already promulgated by DOE, are included in the AEO2011 Reference case. Efficiency advocates and equipment manufacturers have developed consensus agreements on regional standards for electric heat pumps, central air conditioners, and furnaces, and national standards for refrigerators, freezers, clothes washers, clothes dryers, dishwashers, and room air conditioners. In those cases, efficiency levels in additional rounds of standards are limited to one-half the ENERGY STAR improvement increment.
The ENERGY STAR program provides an annual summary of market penetration by qualified products [53]. For some product categories with high levels of market penetration, ENERGY STAR specifications are updated more frequently, to encourage greater efficiency. Consequently, ENERGY STAR levels may be the most up-to-date and consistent set of efficiency levels that are plausible for future standards.
The Expanded Standards case includes updated standards for currently covered products as well as new standards for products not yet covered. Updated standards for covered products are introduced according to DOE's rulemaking schedule, which typically staggers rulemakings and revisits standard levels every 6 years. Standards for products not previously covered are assumed to be added to the schedule, with the last standard being introduced in 2019. For most end uses, only one additional round of standards is applied. Exceptions in the residential sector include boilers, geothermal heat pumps, and dehumidifiers, with two rounds of standards. Two additional rounds of standards are also assumed for geothermal heat pumps in the commercial sector.
By law, the DOE rulemaking process requires that efficiency improvements be imposed at neutral cost to consumers. Extensive cost-benefit analysis in the process involves thorough engineering and market analyses of potential impacts on consumers and is subject to scrutiny and input from equipment manufacturers, efficiency advocates, and other stakeholders. The sensitivity cases described here focus on the aggregate energy impacts of additional standards and codes, but do not address the impacts on consumer welfare. Future efficiency levels are based solely on estimations of improvements for currently available products.
Building Codes
Residential and commercial building energy codes [54] are currently applied at the State level with no consistent schedule for adoption, compliance, or enforcement. Current residential building codes vary widely: some States comply with 2009 IECC or better, while others have codes that predate the 1998 MEC / IECC or have no mandatory codes at all. On the commercial side, the most stringent States have adopted ASHRAE 90.1-2007 or better, while the least stringent States either have no mandatory code or have codes that precede ASHRAE 90.1-1999. The Energy Policy Act of 1992 required certification of building energy code updates from all States, so that residential codes would meet or exceed the (now obsolete) Council of American Building Officials' 1992 Model Energy Code, and commercial codes would meet or exceed ASHRAE 90.1-1989. As of 2010, a State-level scorecard from efficiency advocates identified 12 States that still do not have mandatory energy codes for either residential or commercial buildings [55].
The American Recovery and Reinvestment Act of 2009 (ARRA) provides State Energy Program (SEP) funding, contingent on the updating of a State's building codes to ASHRAE 90.1-2007 and the IECC that was most recent when ARRA was passed in 2009, and on the State's providing a plan to achieve at least 90-percent compliance within 8 years. All 50 States applied for and received SEP funds with those conditions. The Reference case assumes that States comply with ARRA. The Expanded Standards and Codes case adds three rounds of building codes, the first of which mandates a 15-percent improvement over IECC 2009 in the residential sector and a 30-percent improvement over ASHRAE 90.1-2004 in the commercial sector by 2020. Two subsequent rounds in 2023 and 2026 each add an assumed 5-percent incremental improvement.
Results for the residential sector
Because many of the products targeted by the appliance standards program are used in the residential sector, about 60 percent of the additional buildings sector efficiency gains in the Expanded Standards and Codes case are realized there. Figure 28 shows cumulative energy savings relative to the 2010 Technology case in three cases for various groups of residential end uses.
The Reference case includes technology improvement in every end use. Also, two consensus agreements among equipment manufacturers and efficiency advocates provide additional significant reductions in consumption. In 2009, a consensus agreement recommended regional standards for some heating and cooling equipment as an alternative to the national standards of the past. In 2010, a consensus agreement recommended standards for refrigerators, freezers, room air conditioners, clothes washers, clothes dryers, and dishwashers. Those consensus agreements are included in the Reference case as de facto standards, and they contribute to the cumulative reduction in delivered energy use of 13.4 quadrillion Btu in the Reference case relative to the 2010 Technology case.
The Expanded Standards case shows significant improvement in miscellaneous energy loads, mostly as the result of an assumed standard for standby power in 2014. Standards for televisions and computer monitors are introduced in 2016, as recent improvements in display technology have offered room for energy savings. Products such as home audio equipment and DVD players that have been subject to State standards are assumed to be covered at the Federal level, further contributing to energy savings. Similarly, energy use for personal computers and related equipment, such as printers, modems, and routers, also are affected by the standards for standby power and assumed new DOE rulemakings for peripheral devices. Ultimately, the energy consumption associated with televisions, set-top boxes, personal computers, and related equipment is reduced by 1.8 quadrillion Btu in 2035 in the Expanded Standards case.
Electric water heating, with an assumed standard mandating heat pump water heaters in 2021, is reduced by 2.0 quadrillion Btu in 2035 in the Expanded Standards case relative to the Reference case. Electricity use for large kitchen appliances (refrigeration and cooking) display relatively little improvement in the Expanded Standards case. Refrigeration already is subject to stringent standards in the Reference case, whereas cooking equipment has less room for technological improvement. A lighting standard is assumed to be set in 2026, establishing an efficacy level for general-service bulbs at the level of compact fluorescent lamps; however, that level is not much higher than the standard that already has been promulgated and will go into effect in 2014. Energy use for laundry and dishwashing equipment shows little direct improvement in the Expanded Standards case, because standards for those products are more likely to limit water use than energy use.
The building codes in the Expanded Standards and Codes case provide an additional 2.9 quadrillion Btu of savings for space heating and cooling relative to those in the Expanded Standards case. Space heating accounts for most of the savings. In addition, some features of new building codes could focus on thermal improvements, such as reducing air infiltration or increasing the solar heat gain coefficients of windows, which may be beneficial in winter months but slightly detrimental in summer months.
Results for the commercial sector
Buildings in the commercial sector are less homogeneous than those in the residential sector, in terms of both form and function. The wider range of commercial equipment makes standard-setting more difficult, and although many products have been subject to Federal efficiency standards, FEMP guidelines, and ENERGY STAR specifications, coverage is not as comprehensive as in the residential sector. Figure 29 shows cumulative energy savings relative to the 2010 Technology case in three cases for various groups of commercial end uses.
Like the residential sector, commercial buildings with residential-size equipment were affected by the 2009 consensus agreement for heating and cooling products, which is included in the Reference case. This contributes to a cumulative reduction in delivered energy use for commercial heating, ventilation, and air conditioning of 1.5 quadrillion Btu (2 percent) in the Reference case relative to the 2010 Technology case. Office-related computer equipment sees significant energy savings, primarily because laptops gain market share from desktop computers.
In the Expanded Standards case, office equipment again accounts for a large share of the efficiency gains, because desktop computers and their monitors, laptops, copiers, fax machines, printers, and multi-function devices are assumed to be subject to efficiency standards, ultimately saving 1.2 quadrillion Btu over the projection period. Lighting in the commercial sector is subject to a tighter standard in 2017, saving 0.6 quadrillion Btu in total through 2035. In addition, an assumed 2021 standard requiring the use of heat pump water heaters leads to a 29-percent reduction in electricity consumption for water heating in 2035.
Building codes in the Expanded Standards and Codes case have nearly as much impact as the assumed standards in the Expanded Standards case, because the assumed building codes are much more stringent than those in the Reference case. Ultimately, the new codes provide almost 3 quadrillion Btu of savings in energy consumption for space heating savings and about 1 quadrillion Btu of savings for space cooling, beyond the reductions attributable to equipment standards.
Summary
In comparison with a case that restricts future equipment to what was available in 2010, the alternative cases described here show the potential for energy savings from the technological improvement and the application of appliance standards and building codes. In the Reference case, assumed technology improvement in general, and consensus agreements on efficiency improvements for some end uses in particular, save 13.4 quadrillion Btu of residential delivered energy—equivalent to 4.4 percent of total residential energy use—from 2010 to 2035. In the commercial sector, 5.6 quadrillion Btu of energy—equivalent to 2.2 percent of total commercial delivered energy—is saved from 2010 to 2035. Assumed appliance standards in the Expanded Standards case provide additional cumulative energy savings from 2010 to 2035 of 2.8 percent and 1.4 percent in the residential and commercial sectors, respectively. On top of those savings, the tighter building codes assumed in the Expanded Standards and Codes case provide additional cumulative reductions in energy use of 1.0 percent and 1.6 percent in the residential and commercial sectors, respectively. Ultimately, in the Reference case, 19.0 quadrillion Btu of delivered energy consumption is avoided over 25 years relative to projected consumption in the 2010 Technology case. That total is roughly equivalent to the energy that the buildings sectors consumed in 2006. The Expanded Standards and Codes case goes beyond the Reference case to save an additional 19.0 quadrillion Btu of delivered energy from 2010 to 2035.
Potential of offshore crude oil and natural gas resources
The 2010 Macondo oil well accident in the Gulf of Mexico heightened awareness of the risks associated with exploration and development of offshore crude oil and natural gas resources, particularly in deep water. In addition, there is significant uncertainty about the offshore resources available in the Gulf of Mexico and Alaska offshore areas. Despite the risks and uncertainties, however, offshore crude oil and natural gas production is expected to remain an important component of U.S. supply through 2035.
In 2009, offshore production accounted for 1.79 million barrels per day or 33 percent of the 5.36 million barrels per day of total U.S. crude oil production and 2.70 trillion cubic feet or 13 percent of the 20.96 trillion cubic feet of U.S. natural gas production. In the AEO2011 Reference case, offshore production accounts for roughly 32 percent of total domestic crude oil production and 11 percent of total domestic natural gas production over next 25 years.
Analysis cases
Three sensitivity cases were used to evaluate the impacts of key assumptions related to the availability of offshore crude oil and natural gas resources and the costs of exploring and developing them. Specific assumptions in the three cases are discussed below.
High OCS Resource case
Resource estimates for most of the U.S. outer continental shelf (OCS) are uncertain, particularly for resources in undeveloped regions where there has been little or no exploration and development activity, and modern seismic survey data are lacking. In several recent studies prepared for the DOE [56] and the National Association of Regulatory Utility Commissioners[57], technically recoverable resources in undeveloped areas of the OCS have been estimated at 2 to 5 times the latest (2006) estimates from the U.S. Department of the Interior's Bureau of Ocean Energy Management.
The AEO2011 High OCS Resource case assumes a technically recoverable undiscovered crude oil resource base in the Atlantic, Pacific, and Alaska OCS and in areas of the eastern and central Gulf of Mexico (which are currently under a statutory drilling moratorium) that is triple the size of the resource base assumed in the Reference case (Table 6), resulting in a total OCS level of technically recoverable resources of 144.0 billion barrels of crude oil, as compared with 69.3 billion barrels in the Reference case. For natural gas, the High OCS Resource case triples the technically recoverable undiscovered resources in some areas, with the exception of the Alaska OCS. Projected natural gas production from the Alaska OCS is not sensitive to the level of technically undiscovered resources, because natural gas prices are not high enough to support investment in a pipeline to bring natural gas from the North Slope area to market.
| Table 6. Technically recoverable iundiscovered U.S. offshore oil and natural gas resources assumed in two cases | ||||
|---|---|---|---|---|
| Crude oil (billioin barrels) | Natural gas (trillion cubic feet) | |||
| Reference | High OCS Resource | Reference | High OCS Resource | |
| Developing Gulf of Mexico | 32.0 | 32.0 | 173.7 | 173.7 |
| Undeveloped Gulf of Mexico | 3.7 | 11.0 | 21.5 | 64.4 |
| Mid-and South Atlantic | 1.4 | 4.1 | 12.4 | 37.1 |
| Southern Pacific | 5.7 | 17.1 | 10.1 | 30.4 |
| Alaska | 26.6 | 79.8 | 132.1 | 132.1 |
| Total undiscovered | 69.3 | 144.0 | 349.8 | 437.7 |
Reduced OCS Access case
The Reduced OCS Access case assumes leases in the Pacific, Atlantic, Eastern Gulf of Mexico, and Alaska OCS regions are not available until after 2035, as detailed in Table 7.
| Table 7. First year of available offshore leasing in two cases | ||
|---|---|---|
| Reference | Reduced OCS Access | |
| Eastern Gulf of Mexico | 2022 | After 2035 |
| North Atlantic | After 2035 | After 2035 |
| Mid-and South Atlantic | 2018 | After 2035 |
| Northern and Central Pacific | After 2035 | After 2035 |
| Southern Pacific | 2033 | After 2035 |
| Alaska | 2010 | After 2035 |
High OCS Cost case
The High OCS Cost case assumes that costs for exploration and development of offshore oil and natural gas resources are 30 percent higher than those in the Reference case. The higher cost assumption is not intended to be an estimate of the impact of any new regulatory or safety requirements, but is simply used to illustrate the potential impacts of higher costs on the production of OCS crude oil and natural gas resources.
Analysis results
In the High OCS Resource case, the assumed increase in technically recoverable OCS resources in undeveloped areas impacts crude oil and natural gas production through 2035, primarily because of the long lead times required for resource development in the offshore, regardless of the size of the resources discovered. In most areas, depending on location and water depth, a period of 3 to 10 years for exploration, infrastructure development, and developmental drilling is required from lease acquisition to first production. Because the assumed availability of leases in the Pacific, Atlantic, Eastern Gulf of Mexico, and Alaska is the same in the Reference and High OCS Resource cases, crude oil and natural gas production is not affected by the high resource assumption until 2025 and after.
In 2035, offshore crude oil production in the High OCS Resource case is 51 percent higher, at 3.25 million barrels per day, than the Reference case production level of 2.15 million barrels per day (Figure 30). The majority of the increase (65 percent) is from the Alaska OCS, based on the assumed discovery and development of a large field with 2 billion barrels of recoverable crude oil resources. As a result, total domestic crude oil production in 2035 is 1.05 million barrels per day (18 percent) higher in the High OCS Resource case than in the Reference case. Cumulative total domestic crude oil production from 2010 to 2035 in the High OCS Resource case is only 5 percent higher than in the Reference case.
Changes in domestic oil production tend to have only a modest impact on crude oil and petroleum product prices, because any change in domestic oil production is diluted in the world oil market. In 2009, the United States produced 5.36 million barrels per day of crude oil and lease condensate, or 7 percent of the world total of 72.26 million barrels per day. Unlike crude oil supply and prices, domestic natural gas supply and prices are determined largely by supply and demand for natural gas in the North American market, where the development and production of shale gas in the Lower 48 States is largely responsible for current and foreseeable future market conditions.
Natural gas production in U.S. offshore areas in 2035 is 0.7 trillion cubic feet higher in the High OCS Resource case than in the Reference case, putting some downward pressure on natural gas prices (Figure 31). In 2035, the Henry Hub spot price is about 3 percent lower in the High OCS Resource case than in the Reference case. However, the lower price results in only a small increase in natural gas consumption, 0.2 trillion cubic feet. Thus, the increase in OCS natural gas production is offset by a decrease of 0.5 trillion cubic feet in production from onshore domestic supply sources.
In the Reduced OCS Access case, removing the Pacific, Atlantic, Eastern Gulf of Mexico, and Alaska OCS from future leasing consideration lowers projected domestic production of both crude oil and natural gas. The impact on domestic crude oil production starts after 2026 as a result of the lead time between leasing and production and the economics of projects in undeveloped areas. In 2035, offshore crude oil production in the Reduced OCS Access case, at 1.78 million barrels per day, is 17 percent or 0.17 million barrels per day lower than in the Reference case, resulting in a 6 percent decrease in total domestic crude oil production.
Offshore natural gas production in 2035 is 5 percent lower in the Reduced OCS Access case than in the Reference case (2.92 trillion cubic feet compared with 3.05 trillion cubic feet), resulting in a decrease in total U.S. natural gas production of less than 1 percent. Cumulatively, total domestic crude oil and natural gas production from 2010 to 2035 is less than 1 percent lower in the Reduced OCS Access case than in the Reference case.
In the High OCS Cost case, exploration and development costs for crude oil and natural gas resources in all U.S. offshore regions are 30 percent higher than in the Reference case, resulting in lower levels of offshore crude oil and natural gas production throughout the projection period. The largest difference in production levels between the two cases occurs in 2015, when total U.S. offshore crude oil production is 112,000 barrels per day (6 percent) lower and offshore natural gas production is 0.2 trillion cubic feet (9 percent) lower than in the Reference case.
The higher exploration and production costs in the High OCS cost case change the economics of oil and gas development projects and reduce the number of wells drilled annually in offshore areas. Because of the higher costs, exploration and development of some offshore resources occur later, when prices are higher. In 2035, lower 48 offshore crude oil production is 2 percent lower, and lower 48 offshore natural gas production is 3 percent lower, in the High OCS Cost case than in the Reference case. Impacts on crude oil and natural gas prices and consumption are small. In Alaska, however, the increase in costs deters the development of additional offshore resources that are economically viable in the Reference case.
Prospects for shale gas
Production of natural gas from large underground shale formations (shale gas) in the United States grew by an average of 17 percent per year from 2000 to 2006. Early successes in shale gas production occurred primarily in the Barnett Shale of north central Texas. By 2006, successful shale gas operations in the Barnett shale, improvements in shale gas recovery technologies, and attractive natural gas prices encouraged the industry to accelerate its development activity in other shale plays. The combination of two technologies—horizontal drilling and hydraulic fracturing—made it possible to produce shale gas economically, and from 2006 to 2010 U.S. shale gas production grew by an average of 48 percent per year. Further increases in shale gas production are expected, with total production growing by almost threefold from 2009 to 2035 in the AEO2011 Reference case. However, there is a high degree of uncertainty around the projection, starting with the estimated size of the technically recoverable shale gas resource.
Estimates of technically recoverable shale gas are certain to change over time as new information is gained through drilling and production, and through development of shale gas recovery technology. Over the past decade, as more shale formations have been explored and used for commercial production, estimates of technically and economically recoverable shale gas resources have skyrocketed. However, the estimates embody many assumptions that might prove to be untrue in the long term.
In the AEO2011 Reference case, estimates of shale gas resources are based in part on an assumption that production rates achieved to date in a limited portion of a formation are representative of future production rates across the entire formation—even though experience to date has shown that production rates from neighboring shale gas wells can vary by as much as a factor of 3. Moreover, across a single shale formation, there are significant variations in depth, thickness, porosity, carbon content, pore pressure, clay content, thermal maturity, and water content, and as a result production rates for different wells in the same formation can vary by as much as a factor of 10.
There is also considerable uncertainty about the ultimate size of the technically and economically recoverable shale gas resource base in the onshore lower 48 States and about the amount of gas that can be recovered per well, on average, over the full extent of a shale formation. Uncertainties associated with shale gas formations include, but are not limited to, the following:
Although public estimates of onshore lower 48 shale gas resources, as reported by private institutions, have grown over the past decade as more shale gas plays have been production tested, it is not known what shale formations were included in the estimates or what methodology and data were used to derive them. For example, an estimate relying only on publicly reported costs and performance profiles for shale gas wells would tend to overestimate the size of the economic resource base, because public information is skewed toward high-production and high-profit wells. Given the lack of information about how private institutions have derived their resource estimates, this analysis considers a set of alternative resource estimates that are intended to provide a plausible but not definitive range of potential shale gas resources.
Analysis cases
Two key determinants of the estimated technically recoverable shale gas resource base are (1) estimated ultimate recovery (EUR) per well and (2) an assumed recovery factor that is used to estimate how much of the acreage of shale gas plays contains recoverable natural gas. Four AEO2011 cases examine the impacts of higher and lower estimates of total recoverable shale gas resources on natural gas prices and production. The four cases are not intended to represent a confidence interval for the resource base, but rather to illustrate how different resource assumptions affect projections of domestic production, prices, and consumption.
High resource cases
Two high shale resource cases were created by increasing two different assumptions underlying the resource estimate. The estimated unproved technically recoverable resource base (excluding 20.1 trillion cubic feet of inferred reserves) is the same in both high shale resource cases and is 50 percent higher than in the Reference case (1,230 trillion cubic feet in the two high shale resource cases, compared with 827 trillion cubic feet in the Reference case).
Low shale resource cases
Two low shale resource cases were created by adjusting the same factors described above for the high shale resources cases, but in the opposite direction. The estimated unproved technically recoverable shale gas resources is 423 trillion cubic feet in both of the low shale resource cases, 50 percent lower than the 827 trillion cubic feet level in the Reference case.
The 50-percent variations in the shale gas cases approximate the range of shale gas resource estimates reported by the U.S. Geological Survey for 20 shale gas assessment units in 5 petroleum basins, using the Survey's 95 percent and 5 percent probability resource volumes as indicative of the degree of uncertainty in shale gas resource estimates.
As discussed below, in the High Shale EUR and High Shale Recovery cases, natural gas prices are lower than in the Reference case; however, the energy models used for the AEO2011 projections do not allow for liquefied natural gas (LNG) exports from domestic facilities. Consequently, net natural gas exports in the Reference, High Shale EUR, and High Shale Recovery cases could be greater if domestic LNG export terminals were represented in the models.
Analysis results
The four shale gas cases illustrate the uncertainties that surround shale gas resources, which could have significant implications for future natural gas prices, production, and consumption (Table 8). They also illustrate that the type of uncertainty involved (EUR or recovery) also bears on the question of how prices, production, and consumption could unfold as uncertainties about the U.S. shale gas resource base are resolved over time.
| Table 8. Natural gas prices, production, imports, and consumption in five cases, 2035 | |||||
|---|---|---|---|---|---|
| Projection | Low Shale EUR | Low Shale Recovery | Reference | High Shale Recovery | High Shale EUR |
| Henry Hub spot natural gas (2009 dollars per million Btu) |
9.26 | 8.17 | 7.07 | 6.0 | 5.35 |
| Total U.S. natural gas production (trillion cubic feet) |
22.4 | 24.6 | 26.3 | 28.5 | 30.1 |
| Onshore lower 48 | 17.2 | 19.6 | 23.1 | 25.5 | 27.2 |
| Shale gas | 5.5 | 8.2 | 12.2 | 15.1 | 17.1 |
| Other gas | 11.7 | 11.4 | 10.8 | 10.4 | 10.1 |
| Offshore lower 48 | 3.5 | 3.2 | 3.1 | 2.8 | 2.7 |
| Alaska | 1.8 | 1.8 | 0.2 | 0.2 | 0.2 |
| Total net U.S. natural gas imports (trillion cubic feet) |
1.7 | 0.7 | 0.2 | -0.3 | -0.5 |
| Total U.S. natural gas consumption (trillion cubic feet) |
24.1 | 25.4 | 26.6 | 28.3 | 29.6 |
| Electric power | 6.4 | 7.1 | 7.9 | 8.9 | 9.6 |
| Residential | 4.6 | 4.7 | 4.8 | 4.9 | 4.9 |
| Commercial | 3.6 | 3.7 | 3.8 | 3.9 | 4.1 |
| Industrial | 7.5 | 7.8 | 8.0 | 8.4 | 8.7 |
| Other | 2.0 | 2.1 | 2.1 | 2.2 | 2.3 |
The largest variations from the Reference case are in the High and Low Shale EUR cases, where lower and higher costs per unit of shale gas production have the effect of increasing and decreasing total production from U.S. shale gas wells. In the Low Shale EUR case, the Henry Hub natural gas price in 2035 is $2.19 per million Btu or 31 percent higher than the Reference case price of $7.07 per million Btu (2009 dollars). Conversely, in the High Shale EUR case, the Henry Hub price in 2035 is $1.72 per million Btu or 24 percent lower than in the Reference case.
In 2035, shale gas production is more than three times as high in the High Shale EUR case as in the Low Shale EUR case, at 17.1 trillion cubic feet and 5.5 trillion cubic feet, respectively, as compared with 12.2 trillion cubic feet in the Reference case. The High and Low Shale EUR cases show the largest variation in shale gas production, as well as the greatest variation in natural gas prices. The High and Low Shale Recovery cases show less variation in production and natural gas prices. In the Low Shale Recovery case, shale gas production totals 8.2 trillion cubic feet in 2035, as compared with 15.1 trillion cubic feet in the High Shale Recovery case. Even in the Low Shale EUR case, however, with the lowest production projections, overall growth in U.S. natural gas production is still primarily the result of an increase in shale gas production from the 2009 level of 3.3 trillion cubic feet.
Price impacts in the High and Low Shale Recovery cases are less pronounced, because the cost per unit of production from each shale formation is the same as in the Reference case. Instead, the recoverable shale gas volume associated with each formation is varied, leading to a corresponding change in the level of drilling required to recover the gas. In the Low Shale Recovery case, the Henry Hub natural gas price in 2035 is $1.10 per million Btu or 16 percent higher than in the Reference case. In the High Shale Recovery case, the Henry Hub price is $1.04 per million Btu or 15 percent lower than in the Reference case. As discussed below, other types of domestic natural gas production and imports are affected by, and reflected in, changes in natural gas prices across the shale gas analysis cases.
In the Low Shale EUR and Low Shale Recovery cases, with higher natural gas prices, total U.S. natural gas consumption in 2035 is 2.4 trillion cubic feet and 1.2 trillion cubic feet lower, respectively, than the Reference case projection of 26.6 trillion cubic feet. Conversely, in the High Shale EUR and High Shale Recovery cases, with lower natural gas prices, total U.S. natural gas consumption in 2035 is 3.1 trillion cubic feet and 1.7 trillion cubic feet higher, respectively, than the Reference case projection.
Natural gas consumption in the specific end-use sectors varies similarly with changes in natural gas prices: higher prices result in less consumption, and lower prices result in more consumption. The electric power sector shows the greatest sensitivity to changes in natural gas prices. In the Low Shale EUR and Low Shale Recovery cases, natural gas use for electric power generation in 2035 is 6.4 trillion cubic feet and 7.1 trillion cubic feet, respectively, compared with 7.9 trillion cubic feet in the Reference case in 2035. In the High Shale EUR and High Shale Recovery cases, total natural gas use for electricity generation in 2035 is 9.6 trillion cubic feet and 8.9 trillion cubic feet, respectively (higher than in the Reference case).
Natural gas consumption in the electric power sector is more responsive to price changes than in the other sectors, because much of the electric power sector's fuel consumption is determined by the dispatching of existing generation units based on the operating cost of each unit, which in turn is determined largely by the costs of competing fuels, such as coal and natural gas. Natural gas use in the end-use consumption sectors is generally less responsive to variations in fuel prices, because opportunities to switch to other fuels typically arise only when a new facility is built, or when an existing facility's equipment is retired or replaced.
Other sources of natural gas supply also respond to changes in shale gas production and natural gas prices across the shale gas analysis cases. Higher shale gas production tends to imply lower production of other natural gas. For example, other onshore lower 48 natural gas production in 2035 varies by 1.6 trillion cubic feet, and offshore lower 48 natural gas production varies by 0.8 trillion cubic feet, between the High and Low Shale EUR cases.
The volume of Alaska natural gas production is determined largely by the presence or absence of an Alaska natural gas pipeline to transport gas into Alberta, Canada, where the gas would be transshipped to the lower 48 States. Whether and when an Alaska gas pipeline is built depends on whether lower 48 natural gas prices are sufficiently high to allow recovery of the pipeline's capital and operating expenses while also providing a sufficient natural gas price at the North Slope wellhead. In the Low Shale EUR and Low Shale Recovery cases, an Alaska gas pipeline begins operation in 2026 and in 2030, respectively, delivering 3.8 billion cubic feet per day into the lower 48 natural gas market.
Just as natural gas prices determine the levels of domestic gas production and consumption, they also determine the level of net natural gas imports, with higher gas prices resulting in higher net natural gas imports. The High Shale EUR and High Shale Recovery cases are particularly noteworthy, because projected natural gas prices in those cases are sufficiently low to cause increases in Mexico's imports of U.S. natural gas that, in 2035, make the United States a net exporter of natural gas, with net exports totaling about 0.5 and 0.3 trillion cubic feet, respectively. U.S. net exports could be even greater if domestic LNG export terminals were developed, but this is not represented in the AEO models in the High Shale EUR and High Shale Recovery cases. Under the higher prices associated with the Low Shale EUR and Low Shale Recovery cases, the United States is a net importer of natural gas in 2035, with net imports totaling 1.7 and 0.7 trillion cubic feet year (7 percent and 3 percent of consumption), respectively.
Cost uncertanties for new electric power plants
Capital costs are a key consideration in decisions about the type of new generating plant or capacity addition that will be built to meet future demand for electricity. Capital costs for new power plants include materials, skilled labor, and generating equipment. For AEO2011, EIA commissioned a study of the cost components for different utility-scale electric power technologies, with the goal of presenting costs for different plant types in a common set of cost categories to facilitate comparison of capital costs. A major change from previous years in assumptions for the cost study included a significant increase in the assumed costs for coal and nuclear power projects [58].
There is, however, a great deal of uncertainty about future capital costs for all generating technologies. The completion of initial projects could yield experience that enables costs for future projects to be reduced, through a "learning by doing" process. A slow economic recovery could soften demand for the materials and labor used in building new power plants, which also could lower construction costs. Conversely, a failure to "learn" increases in the costs of labor and key commodities, or an uncertain outlook for the economy in general could increase the costs of future projects.
Because some plant types—coal, nuclear, and most renewables—are more capital-intensive than others (in particular, natural gas), the mix of future capacity installations and consequently the fuels used for power generation depends on both the relative and absolute level of capital costs. If construction costs increase proportionately for plants of all types, leaving relative costs unchanged, natural-gas-fired capacity will be more economical than the more capital-intensive coal and nuclear technologies. Over the longer term, higher construction costs could lead to higher electricity prices, which could slow the growth of electricity consumption.
Case descriptions
Several alternative cases assuming different trends in capital costs for power plant construction were used to examine the implications of different cost paths for new power plant construction. Because there is a correlation between rising power plant construction costs and rising commodity prices, construction costs in AEO2011 are tied to a producer price index for metals and metal products.
The nominal index is converted to a real annual cost factor, using 2013 as the base year. The resulting cost factor for the Reference case remains nearly flat in the early years of the projection, then declines through the end of the projection, so that the construction cost factors in 2035 are nearly 20 percent lower than in 2011. As a result, future capital costs are lower even before technology learning adjustments are applied. The cost factor remains constant across all technology types.
In the Frozen Plant Capital Cost case, base overnight construction costs for all new electricity generating technologies are assumed to remain constant at 2015 levels, when the cost factor peaks in the Reference case. Cost decreases can still occur as a result of technology learning, but overall decreases are slower than in the Reference case. In 2035, capital costs for each technology are roughly 25 percent higher in the Frozen Plant Capital Cost case than in the Reference case.
In the Decreasing Plant Capital Cost case, base overnight construction costs for each generating technology in 2010 is 20 percent lower than in the Reference case in 2010, and they decline more rapidly in the projection. In 2035, capital costs for all technologies are about 40 percent lower in the Decreasing Plant Capital Cost case than in the Reference case.
Other alternative cost cases focus on specific technologies to examine the effects of cost reductions that could occur more rapidly for a given technology (for example, as a result of research and development funding or international learning experience).
In the Low Nuclear Cost case, capital and operating costs for new nuclear capacity are 20 percent lower than in the Reference case in 2010, and they fall to 40 percent lower in 2035.
In the Low Fossil Technology Cost case, capital and operating costs for each new fossil-fired generating technology is 20 percent lower than in the Reference case in 2010, and they fall to 40 percent lower in 2035.
Capacity additions
Overall capacity requirements and the mix of generating types change across the cases. In the Reference case, 223 gigawatts of new generating capacity are added from 2010 to 2035, as compared with 216 gigawatts in the Frozen Capital Cost case and 272 gigawatts in the Decreasing Plant Capital Cost case, where higher and lower electricity prices, respectively, lead to changes in total electricity demand. In addition, slightly more existing capacity is retired in the Decreasing Plant Capital Cost case, because new capacity is less expensive, and some older plants are retired and replaced with new capacity.
In all the cost cases, the majority of new capacity is natural-gas-fired (Figure 32). In the Frozen Plant Capital Cost case, builds of all types drop slightly from the level in the Reference case, but the mix of new generating capacity is similar to that in the Reference case. In the Decreasing Plant Capital Cost case, more new capacity of all types is built than in the Reference case, with nuclear and renewables both capturing slightly higher shares of total capacity builds. The increase in renewable capacity builds the Decreasing Plant Capital Cost case consists primarily of wind capacity.
In the cases that focus on specific technologies, the mix of capacity builds changes to favor those with declining costs. In the Low Fossil Technology Cost case, all coal- and natural-gas fired capacity is less expensive to build than in the Reference case, but the costs for nuclear and renewable capacity are the same as those in the Reference case. As a result, more coal and natural gas capacity is built, and less renewable capacity. Similarly, in the Low Nuclear Cost case, total additions of new nuclear capacity increase to 25 gigawatts, from 6 gigawatts in the Reference case. The new nuclear capacity primarily displaces natural-gas-fired capacity.
Electricity generation and prices
The alternative capital cost cases have smaller impacts on the overall mix of generation by fuel type, because capital cost assumptions do not affect the operation of existing capacity. Coal maintains the largest share of total generation in 2035 in all the cases, varying only from 42 percent to 44 percent across all the cases (Figure 33).
The renewable share of generation in 2035 also remains fairly constant at 14 percent to 15 percent in all the cases, because the requirements of different State and regional RPS programs still must be met. In the Decreasing Plant Capital Cost case, generation from biomass co-firing is lower than in the Reference case, and wind generation provides more of the renewable requirement, because generating costs for new technologies, including wind, are lower than the costs for biomass co-firing. The nuclear share of total generation in 2035 is between 17 and 18 percent in all but one of the cases, increasing to 20 percent in the Low Nuclear Cost case. Natural-gas-fired generation, typically the marginal generating choice, drops in the Decreasing Plant Capital Cost case, where new capacity of all types is cheaper than in the Reference case.
Electricity prices in 2035 are 1 percent higher in the Frozen Plant Capital Cost case than in the Reference case, because construction costs are higher. In the Decreasing Plant Capital Cost case, electricity prices in 2035 are 4 percent lower than in the Reference case. In the Lower Nuclear Cost and Low Fossil Technology Cost cases, where only those two technologies are affected, price changes are smaller than those in the cases where all technologies were adjusted (Figure 34).
Carbon capture and storage: Economics and issues
Background
Carbon capture and storage (CCS) is a process in which CO2 is separated from emission streams and injected into geologic formations, avoiding its release into the atmosphere. Typically, the captured CO2 is transported by pipeline from the emissions source to a suitable storage site.
Capturing and storing CO2 from power plants and industrial processes adds significant capital and operating costs. In some cases, captured CO2 may have considerable value—for example, it may be sold to oil producers for use in CO2 enhanced oil recovery (EOR). In some mature oil fields, producers can recover significantly more of the oil in place by injecting CO2 into a well. CO2-EOR has been used in the United States for more than 30 years, providing experience in transporting and injecting CO2 as well as increasing petroleum production [59]. However, broad deployment of CCS technology would require additional incentives to be economical, beyond the value added from CO2-EOR. At present, CCS activity is limited to a few large-scale tests around the world, largely funded by governments.
Wide-scale adoption of CCS could allow for continued widespread use of fossil fuels in a low-carbon energy system. Significant barriers to the technology remain, however, such as the cost of building and operating capture-ready industrial facilities, the feasibility of permanently storing CO2 underground, and the difficulty of constructing significant infrastructure to transport CO2 to injection sites. Such challenges would have to be overcome in order to enable widespread deployment of CCS. The preponderance of expected costs for CCS deployment are for capturing and compressing the CO2. However, uncertainty in the cost of permanent storage is also significant.
Current research on CCS is focused on lowering the cost of carbon capture and validating the feasibility of permanent CO2 storage. The primary goal of the research is to make CCS viable for fossil fuel power plants, which are the largest potential source of CO2 for CCS and present the most difficult technical hurdles in making CCS economically feasible. A few industrial processes, such as ethanol and ammonia production, yield emissions that are nearly pure CO2, mitigating the technical challenge and energy intensity of CO2 capture.
In 2009, CO2-EOR operators injected nearly 50 million metric tons of CO2 into operating domestic oil wells, most of which was obtained from natural sources. However, the limited supply of natural CO2 has provided enough incentive for a few facilities to capture anthropogenic CO2. This activity has also financed the construction of several pipelines to transport CO2 to oil fields. There is potential for more early adopters of CCS to continue receiving payments from CO2-EOR operators, but the quantity of CO2 that potentially could be used for EOR is small in comparison with the 2.2 billion metric tons emitted in the U.S. power sector in 2009.
Table 9 lists the five commercial-scale CCS projects now in operation worldwide, according to the International Energy Agency. All the projects shown in Table 9 are being monitored over the long term, to ensure that the stored CO2 does not leak. This is why the Rangely Weber and Weyburn-Midale projects are counted as CCS demonstrations even though they are primarily EOR projects [60].
| Table 9. Commercial-scale CCS projects operating in 2010 | ||||
|---|---|---|---|---|
| Project name | Country | CO2 source | Quantity injected (milliion metric tons per year) |
Start year |
| Sleipner | Norway | Natural gas processing | 1.0 | 1996 |
| In Salah | Algeria | Natural gas processing | 1.0 | 2004 |
| Snohvit | Norway | Natural gas processing | 0.7 | 2008 |
| Rangely Weber | United States | Natural gas processing | 1.0 | 1986 |
| Weyburn-Midale | United States/Canada | Coal lgasification plant | 3.2 | 2000 |
Carbon capture
In order for CO2 to be transported and stored, it must be isolated from emissions sources and compressed to a supercritical state [61]. For fossil fuel power plants, this is the most expensive component of CCS, because the flue gases of existing coal-fired power plants contain only 12 to 14 percent CO2, and those from existing natural-gas-fired power plants contain only 3 to 4 percent CO2 [62]. Existing technologies for capturing the CO2 from dilute flue gases are energy-intensive, and consequently their operating costs are high. The National Energy Technology Laboratory is supporting research focused on the development of technologies that can lower the cost of capture, either by developing techniques to lower the cost of purifying dilute CO2 streams or by increasing the purity of CO2 in the flue gases of fossil fuel power plants. The goal of the research is to develop and eventually commercialize carbon capture technologies that can be used routinely by power plant operators while adding less than 10 percent to consumers' electricity costs [63].
CO2 emissions from fossil-fuel power plants can be captured through pre-combustion, post-combustion, or oxy-combustion processes. In the near term, the most likely approach for capturing CO2 from existing coal-fired power plants is to retrofit them with post-combustion capture systems, in which flue gas is treated with a solvent (usually, an amine or chilled ammonia) to separate CO2 from the flue gas before it is released to the atmosphere. Not all existing fossil fuel power plants can be retrofitted for CCS, however, given the costs, space requirements, and need for access to cooling water, all of which can contribute to making a project infeasible.
CCS technology may be more easily integrated as part of a new fossil-fuel plant, where cost and efficiency savings could be realized by including CCS in the initial design. New coal-fired plants with CCS can be built with post-combustion capture systems, similar to retrofits, or with pre-combustion capture systems that gasify the coal and capture CO2 from the newly formed syngas before combustion. Retrofitting natural-gas-fired combined-cycle plants with post-combustion technology is also a possibility, as are new natural gas power plants with pre-combustion capture. Carbon capture technologies currently are in the early stages of development, and it is unclear which may be developed on a commercial scale.
CO2 pipelines
Once captured, CO2 must be transported to a suitable site for sequestration or EOR. The most cost-effective method is to move CO2, compressed to a supercritical state, by pipeline. The technology for building pipelines to transport gases over long distances is mature, based on experience with natural gas pipelines, as well as more than 3,000 miles of CO2 pipelines currently in use to supply CO2-EOR fields. Large-scale adoption of CCS is likely to require significant construction of new pipelines. Interstate CO2 pipelines (unlike natural gas pipelines) are not regulated by the Federal Energy Regulatory Commission, and the lack of national eminent domain authority to ease construction [64] represents a possible impediment to the development of a national pipeline network.
Geologic sequestration and CO2-EOR
Several types of geologic formation have been identified as being suitable for permanent carbon sequestration. Key requirements for a formation that can be used for CO2 storage include being able to store CO2 cost-effectively, prevent leakage of injected CO2, and avoiding interference with other valuable geologic formations, such as freshwater aquifers. The largest contributors to the costs of sequestration are the drilling, operating, and monitoring of wells. Cost-effective storage depends largely on the ability of a field to store the CO2 densely so as to limit the number of injection wells required. Permanent storage capabilities depend on the presence of an impermeable cap rock and lack of faults or uncapped well bores to the surface. Depleted oil and gas fields, deep saline aquifers, and unmineable coal seams all meet these criteria, and all have been identified as good candidates for sequestration. Basalt formations and offshore sediments may also prove to be feasible in the future [65].
In the United States, many specific formations have been identified as suitable for sequestration; however, their potential costs and capacities are uncertain. With the exception of depleted oil and gas fields, the geology of sequestration opportunities is not well characterized, and the behavior of injected supercritical CO2 is not completely understood. It has been estimated that the cost of injection in a saline aquifer can vary by a factor of 3 within a single formation, depending on the geology of the aquifer. Furthermore, injection costs can vary between reservoirs by orders of magnitude [66]. Current research is focused on characterizing the geology of sequestration sites and developing methods to estimate capacities and the feasibility of permanently storing CO2 in specific formations accurately.
Until now, U.S. experience with injecting CO2 underground has largely been limited to CO2-EOR. Natural sources of CO2 comprise a majority of current supply, but some anthropogenic CO2, largely from natural gas processing plants, is captured and used for CO2-EOR [67]. As long as CO2 is a valuable commodity, CO2-EOR operators will maximize oil production to the extent possible and attempt to recover as much injected CO2 as they can, but there will be little interest in permanent storage. However, CO2-EOR has helped to establish a market for captured CO2 and has provided a better understanding of the technical issues involved in injecting CO2.
Analysis results
Reference case
Without a cost for emitting CO2 or government support for CCS, there is no reason to add CCS capabilities to facilities other than when oil producers are willing to pay the entire capital and operating costs of capturing and transporting CO2 for EOR. In the Reference case oil producers are assumed to purchase CO2 from emitters in several industries at a price that gives emitters sufficient economic incentive to capture their emissions. Interregional CO2 pipelines may be constructed if oil prices and EOR opportunities make them economical. Pipeline construction is delayed, however, by the time required to get permits and construct such large projects.
In the Reference case, CO2-EOR plays an increasing role in U.S. petroleum production. Early in the projection period, most CO2 is obtained from natural sources (Figure 35). As demand for CO2 increases beyond the capacity of natural sources, industrial emitters with relatively pure streams of CO2 begin to capture and sell the CO2 to EOR operators. No anthropogenic CO2 is captured from power plants beyond the 2 gigawatts of advanced coal with sequestration that is assumed to be supported by Federal incentives, because the cost is too high for oil producers to implicitly fund the construction of a CCS-capable power plant. CO2-EOR supports more than 1.1 million barrels per day of domestic oil production in 2035 in the Reference case, nearly 4 times the CO2-EOR production level in 2009. CO2-EOR provides 19 percent of total U.S. crude oil production in 2035.
figure data
Oil prices represent a key uncertainty for future CO2-EOR projects, because they are the most significant factor in determining the economic feasibility of projects. Other major uncertainties are the amount of CO2 available to oil producers and the CO2 emissions cost required to give emitters enough incentive to capture it. In 2035, more than 125 million metric tons CO2 per year is captured from anthropogenic sources outside the power sector—equivalent to more than 10 percent of the 1,147 million metric tons of direct CO2 emissions from the industrial sector in 2035. Because not all industrial emissions are sufficiently pure to be captured cheaply, the Reference case results for CO2-EOR imply that a large proportion of all CO2 emissions from ethanol fermentation, CTL and BTL plants, hydrogen production in refineries, ammonia plants, and natural gas processing plants will be captured for sale.
GHG Price Economywide case
An additional case, which includes a CO2 price, illustrates the potential role for CCS in mitigating U.S. CO2 emissions. In the GHG Price Economywide case, the CO2 price (in 2009 dollars) rises from $25 per ton in 2013 to $77 per ton in 2035, encouraging the deployment of CCS technology in the power sector. Due to lower capital costs and relatively low natural gas prices, natural gas combined-cycle plants with sequestration are cheaper to build than advanced coal plants with sequestration (Figure 36), although a significant number of existing coal-fired power plants are retrofitted for CCS after 2030. Additional carbon capture capability is constructed for CTL and BTL plants in the refining sector. Commercial-scale CTL and BTL plants with CCS provide a relatively inexpensive source of CO2 that can be used for EOR.
One factor that could limit future CO2-EOR activity is the availability of CO2. In the GHG Price Economywide case, emitters have an economic incentive to capture and store CO2, given the cost of emitting CO2 into the atmosphere. In this case, oil producers can purchase CO2 captured from power plants, with the price to oil producers decreasing as the amount of CO2 captured increases due to the higher CO2 supply.
Oil producers cannot use all the CO2 that is captured in the electricity and refining sectors in the GHG Price Economywide case, especially in the later years of the projection period. As a result, significant quantities of CO2 are sequestered in non-EOR geologic fields (Figure 37). However, despite the low-cost sources of CO2 for oil producers that come on line after 2015 in the GHG Price Economywide case, there is only a relatively small increase (127,000 barrels per day) in domestic petroleum production, primarily because of the relatively late timing of CCS installations in the power sector and a limit to the number of oil fields suitable for CO2-EOR that are not already developed in the Reference case.
An alternative viewpoint on the effect that a U.S. carbon mitigation policy could have on CO2-EOR production is provided in a recent report by Advanced Resources International (ARI) [68], which suggests that as much as 3.6 million barrels per day of incremental oil production could have been stimulated if the American Clean Energy and Security Act had passed in 2009. That analysis is not fully comparable with the AEO2011 projections, however, because the ARI projection was based in part on an earlier version of National Energy Modeling System that did not fully incorporate a comprehensive framework for developing EOR fields, pipeline infrastructure, and deployment of the technology.
Other sensitivity cases
Two sensitivity cases illustrate the uncertainties in the Reference case projections for CO2-EOR production. The Low EOR case assumes that the amount of inexpensive, anthropogenic CO2 that can be accessed by oil producers is lower than in the Reference case. The Low EOR/GHG Price Economywide case adds the GHG Price Economywide case assumptions to those of the Low EOR case.
Figure 38 shows projected CO2-EOR volumes in the Reference case, GHG Price Economywide case, Low EOR case, and Low EOR/GHG Price Economywide case. The Low EOR case and the Low EOR/GHG Price Economywide case show a stronger response of CO2-EOR to the increase in availability of CO2 from carbon capture as a result of the assumed carbon policy. In the Low EOR case, there is significant unsatisfied demand for CO2 at fields that are suitable for EOR. The GHG price provides a means for that demand to be satisfied.
Power sector environmental regulations on the horizon
The U.S. EPA is expected to enact several key regulations in the coming decade—pertaining to air emissions, solid waste, and cooling water intake—that will affect the U.S. electric power sector, particularly the fleet of coal-fired power plants. In order to comply with those new regulations, existing coal-fired plants may need extensive environmental control retrofits if they are to remain in operation [69]. Because the final makeup of the expected rules is uncertain, AEO2011 includes alternative cases that assume different variations of possible retrofit requirements. They should be viewed as sensitivity cases, rather than projections of what is likely to happen.
Background on rules
Transport Rule
The Transport Rule, proposed by the EPA in July 2010 [70], is designed to reduce emissions of sulfur dioxide (SO2) and nitrous oxide (NOX) from electric power plants in the eastern half of the United States. The purpose of the rule is to assist States in complying with the National Ambient Air Quality Standards (NAAQS) for fine particulate matter (PM2.5) and ground-level ozone [71]. The EPA determined that a major reason many States were not meeting the NAAQS for PM2.5 and ozone was emissions from power plants in upwind States. Accordingly, the Transport Rule establishes State-level emissions caps designed to limit the effects of power plant emissions on the air quality of neighboring States.
The Transport Rule was developed to address legal flaws in the EPA's Clean Air Interstate Rule (CAIR), which was vacated by the U.S. District Court of Appeals in 2008 [72]. First proposed in 2005, CAIR would have established an interstate cap-and-trade system for SO2 and NOX emissions in 28 eastern States, designed to meet the same goals as the Transport Rule. The court ruled that CAIR could not be implemented under the Clean Air Act, concluding that a broad regional cap-and-trade system would not guarantee improved air quality in specific local regions, as required by CAA. The court temporarily reinstated CAIR in December 2008, but it ordered the EPA to revise the rule to address the flaws cited. The EPA included limits on interstate trading in the newly proposed Transport Rule specifically for that purpose.
In June 2010, the EPA proposed three versions of the Transport Rule. The EPA's preferred option would cap emissions in each participating State, allow for a limited amount of emissions trading between States, and permit unlimited intrastate trading. A second alternative would prohibit any interstate trading but allow intrastate trading. A third option would disallow all emissions trading. The EPA is expected to announce a final rule in the spring of 2011.
In designing the Transport Rule, the EPA determined that 28 States have SO2 emissions levels high enough to contribute significantly to PM2.5 nonattainment in downwind States, and that 26 States have NOX emissions levels high enough to contribute to ozone nonattainment. The Transport Rule would require each of those States to reduce emissions to a defined cap by 2012. An additional 15 States would be required to reduce SO2 emissions further by 2014 (Table 10).
| Table 10. Transport Rule emissions targets, 2012 and 2014 (million metric tons) | ||||
|---|---|---|---|---|
| Annual SO2 (28 States) |
Annual NOx (28 States) |
Ozone season NOx (28 States) |
Annual SO2 (15 additional States) |
|
| Actual 2005 emissions | 8.9 | 2.7 | 0.9 | -- |
| Actual 2009 emissions | 4.6 | 1.4 | 0.6 | -- |
| 2012 emissions targets | 3.4 | 1.3 | 0.6 | -- |
| 2014 emissions targets | 3.4 | 1.3 | 0.6 | 2.6 |
In addition, the EPA is considering lowering the NAAQS for annual ozone concentrations from the current limit of 75 part per billion. If it does, additional reductions in NOX emissions from power plants probably will be required beyond the sensitivity case evaluated here. The EPA has hinted that this would be done by increasing the stringency of the Transport Rule for NOX at some point in the future.
There are several possible strategies for reducing SO2 emissions from coal-fired power plants: plant owners can use lower sulfur coal in their boilers, retire plants without emissions controls, or install emissions control equipment—primarily, flue gas desulfurization (FGD) scrubbers. There are two key types of FGD scrubbers, wet and dry. Wet scrubbers remove SO2 from post-combustion flue gas by using a wet alkaline solution, typically containing limestone. Dry scrubbers send the flue gas through a semi-dry alkaline sorbent that removes the SO2 [73]. AEO2011 assumes that all future SO2 control systems will consist of wet FGD scrubbers.
For NOX there are two basic emissions reduction technologies: combustion and post-combustion. Combustion technologies adjust the combustion reaction so that less NOX is produced. Post-combustion technologies remove NOX from the exhaust after it is produced. The choice of control technology is based on plant-specific characteristics, such as unit capacity, boiler configuration, and coal type. Combustion retrofits generally are accomplished by modifying existing boilers so that less NOX is produced in the combustion process—usually a less costly option but also less effective at removing emissions than post-combustion controls.
There are two types of post combustion NOX controls: selective catalytic converters (SCRs) and selective noncatalytic converters (SNCRs). Both technologies use a reagent (typically ammonia or urea) to react with the flue gas in order to reduce NOX to nitrogen and water. In SCRs the reaction occurs in the presence of a catalyst bed; in SNCRs the catalyst bed is not included. The catalyst increases the cost and scale of a retrofit project, but it also increases the efficiency of NOX removal. SCRs also are more easily scaled up, which makes them a more effective option for larger plants. The most stringent pollution control case in AEO2011 assumes that all plants not currently using NOX controls will be required to install SCRs.
Utility boiler MACT
In March 2011, the EPA proposed rules to regulate emissions of mercury, other metals, and acid gases from power plants. The rules are intended to enforce Section 112 of the Clean Air Act's limits on emissions of hazardous air pollutants (HAPs) from electric power plants. The rule requires that all power plants larger than 25 megawatts capacity install the MACT needed to reduce emissions of affected pollutants to levels that match the performance of top-performing plants of the same type. Hydrogen chloride (HCl) and PM2.5 were used as proxies for all acid gases and for metals other than mercury, respectively, because they would tend to be captured by the same control devices. The rule is intended to result in the removal of 91 percent of mercury and HCl from the emissions of coal-fired power plants and the installation of fabric filters at all plants in order to meet the PM limits.
Potential regulation of coal combustion residuals
In June 2010, the EPA released a proposal for regulating coal combustion residuals (CCRs) from electric power plants under the Resource Conservation and Recovery Act (RCRA). Two options given by the EPA were to regulate CCRs under Subtitle C of the RCRA, which would classify CCRs as a hazardous waste pollutant, or Subtitle D, which would classify them as a nonhazardous waste pollutant. By defining CCRs as hazardous, Subtitle C would place more stringent regulations on the storage of coal ash, which probably would result in the closure of surface ash impoundments.
Subtitle D would require the EPA to establish a national criterion for permitting CCR disposal but would leave implementation of such a system to the States. Under Subtitle D, the EPA is considering two options for existing surface impoundments, which are referred to as "Subtitle D" and "Subtitle D Prime." The primary difference between the two options is that, under Subtitle D, existing surface impoundments would either have to be retrofitted with composite liners or cease receiving CCRs within 5 years, while under the Subtitle D Prime, existing surface impoundments could continue to operate to the end of their useful lifetimes without the installation of composite liners. RCRA Subtitle C would require active regulation by the EPA. Under Subtitle D, the main vehicle for enforcement would be citizen lawsuits. As of January 2011, the EPA was reviewing comments on the proposed rule, with a final rule expected to be released in 2011.
In complying with the proposed regulations for CCRs, plants could face increased costs for CCR disposal, depending on specific plant characteristics. Plants with on-site coal ash impounds could incur costs for retrofits or replacements. Plants with wet ash handling systems could be required to switch to dry ash handling systems. The Tennessee Valley Authority (TVA) has already announced that it will replace all wet ash handling systems with dry systems across its entire coal-fired fleet (about 17 gigawatts total capacity). TVA estimates that the investment required for the conversion will be between $1.5 billion and $2.0 billion over the next 10 years [74]. However, because of uncertainty about the makeup of the final rule and the difficulty of assessing project costs, which are inherently site-specific, the potential CCR regulations are not included in any AEO2011 cases.
The EPA has been seeking to regulate mercury emissions from power plants since they were first designated a HAP in December 2000. In 2005, the EPA proposed a cap-and-trade system for mercury under the Clean Air Mercury Rule (CAMR). However, regulating with a cap-and-trade policy required that the EPA first remove mercury from the HAPs list. That action was challenged in court by several States and environmental organizations, and as a result the U.S. Court of Appeals for the District of Columbia Circuit vacated CAMR in 2008 [75].
Despite the court's ruling, the EPA still is required by the CAA to regulate mercury emissions from power plants. The utility boiler MACT rules are intended to fulfill that obligation. Currently, there are 189 listed HAPs. In developing the MACT standards, the EPA determines the emissions of each of those pollutants from power plant boilers. In its proposed rule, the EPA has designated certain pollutants as "proxy" pollutants, meaning that the regulation of one substance could serve to cover others. The rule is expected to be finalized by November 2011. After it is issued, power plant owners will have until 2015 to comply, although extensions of up to 2 years may be granted.
Mercury emissions from power plants can be reduced by fabric filters and activated carbon injection (ACI) systems, which work by injecting powdered carbon into flue gases to bind the mercury and then using particulate control equipment, such as fabric filters, to remove it. Mercury can also be removed by equipment designed to reduce other pollutants, such as FGD scrubbers. FGD scrubbers are especially effective in reducing mercury from bituminous coal emissions, due to its particular chemical makeup. ACI systems may be necessary to remove mercury from subbituminous and lignite coal emissions. In the sensitivity cases discussed here, all coal-fired plants are required to reduce mercury emissions by 90 percent.
Acid gas can be removed through the use of FGD scrubbers or direct sorbent injection (DSI). DSI has lower capital costs than FGD scrubbers, but the technology has not yet been widely deployed in the power sector. In its regulatory impact analysis of the Air Toxics Rule, the EPA assumes significant deployment of DSI [76]. Because of DSI's relatively low capital costs, the EPA sees it as an attractive, low-cost way for smaller coal plants with lower utilization factors to comply with the rule and continue operating. Other analyses are not as optimistic on the prospect of DSI. For example, a study by the Edison Electric Institute on the impacts of several proposed EPA rules for the power sector shows DSI being installed on only 9 gigawatts of capacity to comply with the utility boiler MACT [77]. In order to represent a more stringent case, AEO2011 assumes that FGDs will be needed for compliance with the rule.
Retrofit or retire?
Several key economic factors can influence owners' decisions as to whether older power plants should be retrofitted or retired. The stringency of regulations, compliance costs, remaining life of a plant, fuel prices, and expectations regarding electricity demand and prices all may be considered. Plant owners must determine whether expected future revenues from their plants over their remaining lives will be sufficient to recover the investment in new equipment needed to comply with environmental regulations. Key variables in the determination are the costs of retrofit equipment and future electricity prices.
Because natural gas often is the marginal fuel for electricity generation, low natural gas prices make it more likely that older coal-fired plants will be retired. Low natural gas prices reduce the overall cost of generating electricity, eventually leading to reduced revenues from coal-fired plants. The updated estimates of capital costs for coal and nuclear power plants in AEO2011 are 25 to 37 percent higher than those used in AEO2010, whereas capital costs for natural gas combined-cycle plants are essentially unchanged from AEO2010. In addition, projected natural gas prices in the AEO2011 Reference case are lower than those in AEO2010, reducing the levelized costs of generation for new natural gas power plants. Consequently, new combined-cycle plants are an attractive alternative for replacing capacity lost as a result of coal-fired plant retirements.
Potential regulation of cooling water intakes
Section 316(b) of the Clean Water Act (CWA) requires facilities with cooling water intake structures to use the best technology available (BTA) to mitigate the environmental impacts of the systems—specifically, damage to aquatic wildlife. In 2004, the EPA originally proposed regulation of existing power plants under Section 316(b), which is intended to apply to all facilities that remove at least 50 million gallons of water per day from the environment and use at least 25 percent of the water for cooling. A typical 500-megawatt plant with once-through cooling uses approximately 500 million gallons of cooling water per day. However, determining BTA as it applies to the CWA has been the subject of extensive legal delays, culminating in a Supreme Court case, which has delayed implementation of the rule [78]. Because of the Court's ruling, the EPA is able to consider both the costs and benefits in the design of its final rule. The EPA issued proposed standards for comment on March 28, 2011.
In a once-through system, intake structures withdraw water for use in a thermal power plant's cooling system. Once used, the water is discharged back into the body of water at a higher temperature. Both the water intake and thermal discharge can cause significant damage to local fish populations. In a closed-cycle cooling system, heat from the power plant is removed through evaporation in a nearby cooling tower. Closed-cycle systems require significantly less water intake than once-through systems, mitigating much of the environmental damage associated with the cooling system.
The determination of BTA for cooling water in power plants could have a substantial effect on the entire power sector. New York State and California already have issued rules that essentially require all plants in their States to have closed-loop cooling systems. If the same standard were implemented nationwide, extensive retrofits would be required. The Electric Power Research Institute (EPRI) has estimated that 312 gigawatts of capacity currently in operation (252 gigawatts of fossil fuel capacity and 60 gigawatts of nuclear capacity) would be affected by such a rule. In some cases it may not be possible to install a closed-loop cooling system, and such a requirement could, therefore, cause some plants to be retired.
Closed-loop cooling is considered the most stringent form of compliance with Section 316(b) of the CWA. Other methods of reducing fish mortality, such as wedge wires, variable speed pumps, and traveling water screens, may not be as effective as cooling towers, but they can be installed at much lower cost. In view of that uncertainty, the AEO2011 cases do not include compliance with Section 316(b).
Uncertainty about future GHG regulations continues to loom in power sector investment decisions. Despite a lack of Congressional action, many utilities include a CO2 emissions price in their long-term investment decisions [79]. A carbon price would increase the cost of generation for all fossil fuel plants, but the largest impact would be on coal-fired generation. Thus, plant owners could be reluctant to retrofit existing coal plants, given the possibility that GHG regulations might be enacted in the near future. This uncertainty may influence the expectations of plant owners about the economic lives of particular facilities.
In the Reference case and most of the alternative cases for AEO2011, existing power plants are assumed to continue operating for at least 20 years, allowing the costs of environmental retrofits to be recovered over a 20-year period. In addition, AEO2011 includes two cases described below, which assume that investors will implement retrofits only if their costs can be recovered over a 5-year period, given their concern that future laws or regulations aimed at limiting GHG emissions present a significant risk to the long-term operation of the affected units.
Analysis cases
Transport Rule Mercury MACT 20 case
The Transport Rule Mercury MACT 20 case assumes that the Transport Rule will be enacted in 2014, placing limits on SO2 and NOX emissions. It also assumes a 90-percent MACT for mercury starting in 2015. This case assumes a 20-year capital recovery period for financing FGD scrubbers and SCRs.
Transport Rule Mercury MACT 5 case
This case is identical to the Transport Rule Mercury MACT 20 case, except that it assumes a 5-year capital recovery period for financing FGD scrubbers and SCRs.
Retrofit Required 20 case
The Retrofit Required 20 case assumes more stringent regulation of air emissions from coal-fired plants and utility boilers, requiring the installation of FGD scrubbers and SCRs. It is based on assumptions of more stringent utility boiler MACT requirements and future NOX emissions limits. Utility boiler MACT regulations are scheduled to be effective in 2015, but this case assumes a lag of several years to account for possible delays in implementation.
Retrofit Required 5 case
This case is identical to the Retrofit Required 20 case, except that it assumes a 5-year capital recovery period for financing FGD scrubbers and SCRs.
Low Gas Price Retrofit Required 20 case
This case is similar to the Transport Rule Mercury MACT 20 case but uses more optimistic assumptions about future volumes of shale gas production, which leads to lower natural gas prices. The domestic shale gas resource assumption in this case comes from the AEO2011 High Shale Estimated Ultimate Recovery (EUR) case (Figure 39).
Low Gas Price Retrofit Required 5 case
This case is identical to the Low Gas Price Retrofit Required 20 case, except that it assumes a 5-year capital recovery period for financing FGD scrubbers and SCRs.
GHG Price Economywide case
The GHG Price Economywide case assumes a price on CO2 emissions that rises from $25 per ton (2009 dollars) in 2013 to $77 per ton in 2035. It does not include any specific provisions of the proposed Kerry-Lieberman and Waxman-Markey bills [80], such as offsets, bonus allowances, targeted allowance allocations, or increased efficiency mandates. None of the EPA rules described above is included in the GHG Price Economywide case.
Results
Coal-fired plant retirements
Retirements of coal-fired power plants in the different analysis cases vary with the assumed stringency of environmental rules, the assumed cost recovery period for retrofit investments, natural gas price levels, and assumptions regarding future GHG regulations. Of the 316 gigawatts of coal-fired capacity currently in operation in the United States, 117 gigawatts has no FGD scrubbers installed or currently under construction [81]. Lacking some of the controls necessary to comply with potential future regulations, those coal plants may be candidates for retirement if the regulations are enacted. Generally, the poorest performing plants, with the highest heat rates and lowest utilization rates, are the first that might be retired. Table 11 shows the amount of capacity retired along with the retired plants average heat rates and capacity factors in each case.
| Table 11. Coal-fired plant retirements in nine cases, 2010-2035 | |||
|---|---|---|---|
| Analysis case | Coal-fired capacity retired gigawatts) |
Average size of coal- fired plants retired (gigawatts) |
Average heat rate of coal-fired plants retired (million Btu per kilowatthour) |
| Reference | 8.9 | 93.0 | 12,338 |
| Transport Rule Mercury MACT 20 | 13.5 | 91.4 | 12,053 |
| Transport Rule Mercury MACT 5 | 17.8 | 83.3 | 12,102 |
| Retrofit Required 20 | 19.2 | 84.5 | 12,034 |
| Retrofit Required 5 | 44.8 | 91.2 | 11,579 |
| Low Gas Price | 15.6 | 104 | 12,098 |
| Low Gas Price Retrofit Requird 20 | 39.5 | 97.8 | 11,576 |
| Low Gas Price Retrofit Required 5 | 72.6 | 109.6 | 11,363 |
| GHG Price Economywide | 135.2 | 157.0 | 11,454 |
Projected retirements of coal-fired capacity are higher in each of the analysis cases shown in Table 11 than in the Reference case. Because the emissions reduction requirements in CAIR and the Transport Rule are similar, increased retirements in the Transport Rule Mercury MACT 20 and MACT 5 cases can be attributed to restrictions on allowance trading and to the Mercury MACT. In the Retrofit Required 20 and Retrofit Required 5 cases, explicit mandates are assumed to require the installation of FGDs and SCRs, so that retirement decisions are based on the costs of retrofits. In the Retrofit Required 20 case, most coal-fired plants continue operating beyond 2020. In the Retrofit Required 5 case, with only 5 years to recover the costs of installing retrofits, the amount of coal-fired capacity retired is more than double the amount retired in the Retrofit Required 20 case.
Lower natural gas prices in the Low Gas Price Retrofit Required 20 and Low Gas Price Retrofit Required 5 cases lead to comparatively more retirements of coal-fired capacity—39.5 and 72.6 gigawatts, respectively. Lower natural gas prices reduce the price of electricity in general, lowering power plant revenues. For natural-gas-fired plants, revenue reductions are largely offset by lower fuel costs. For coal-fired plants, assuming that coal prices do not change, there is no offset for the revenue declines, and retrofit projects become uneconomical in some instances. The GHG Price Economywide case assumes a price on CO2 emissions, which renders many existing coal-fired plants uneconomical. As a result, retirements of coal-fired capacity total 135 gigawatts by 2035.
Retrofit equipment installations
In the Retrofit Required 20 and Retrofit Required 5 cases, power plants are required to install FGD scrubbers and SCRs in order to continue operating after 2020, based on the assumption that stringent controls will be required by the EPA for compliance with clean air rules. The combined cost of the two retrofits could range from $500 to $1,000 per kilowatt of capacity, depending on plant size and characteristics [82]. More retrofits occur in the Retrofit Required 20 case than in the Retrofit Required 5 case, because the economics of retrofit projects improve with the longer capital recovery period.
The Transport Rule Mercury MACT 20 and Transport Rule Mercury MACT 5 cases mandate emissions reductions, but they do not require the installation of any particular control equipment. Therefore, while there are more retrofit projects in these cases than in the Reference case, there are not nearly as many as in the Retrofit Required 20 and 5 cases, because there are other options for compliance with the rule, such as using more low-sulfur coal and dispatching uncontrolled plants less often—options that are not available in the Retrofit Required 20 and 5 cases. In the Low Gas Price Retrofit Required 20 and 5 cases, lower prices for natural gas lead to lower overall electricity prices and lower plant revenues. There are fewer retrofits in the Low Gas Price cases, because lower revenues make it less likely that plant owners will be able to recover their investments in the equipment.
In the GHG Price Economywide case, 16 gigawatts of existing coal-fired capacity is retrofitted with CCS equipment. CCS is still unproven on a commercial scale, but AEO2011 assumes that the technology will be available as a carbon mitigation option if a sufficient CO2 price is in place.
Generation by fuel
Despite the decline in coal-fired capacity in all the analysis cases above, coal remains the largest single source of generation through 2035 in all but one of the cases (Figure 40). Even with more stringent emission caps, once a coal plant has been retrofitted it becomes more economical to run, because SO2 and NOX emission allowance costs are no longer incurred. Many of the coal plants that are retired have low utilization factors and high heat rates, and their contribution to overall coal generation is relatively small. In the Retrofit Required 20 and 5 cases, coal-fired generation increases in 2020, as plants that overcome the regulatory hurdle and install retrofits are run more frequently. In the Retrofit Required 20 case, coal-fired generation in 2035 is higher than in the Transport Rule Mercury MACT 20 and 5 cases, as the retrofitted plants are heavily utilized. Other than in the GHG Price Economywide case, electricity generation from coal is lowest in the Low Gas Price Retrofit Required 20 and 5 cases, where low natural gas prices stimulate construction of new natural gas plants to replace retired coal capacity, and existing gas-fired capacity is dispatched more frequently, displacing additional coal-fired generation. In the Low Gas Price Retrofit Required 20 and 5 cases, generation from coal in 2035 is 10 percent and 19 percent below the Reference case level, respectively. In the Low Gas Price Retrofit Required 5 case, the natural gas and coal shares of total generation in 2035 are the same, at 34 percent.
Natural-gas-fired electricity generation in 2035 is higher in all the cases (although it is lower in some earlier years) than in the Reference case. Rapid growth in gas-fired generation is supported by low natural gas prices and relatively low capital costs for new natural gas plants, which improve the relative economics of natural gas when regulatory pressure is placed on the existing coal fleet. Natural gas emits virtually no SO2 and less NOX than does coal, making it a more attractive fuel for environmental compliance.
In the Transport Rule Mercury MACT 20 and 5 cases, generation from natural gas grows steadily throughout the projection. In the early years, gas-fired generation is slightly higher than in the Reference case, because fuel switching is used as an option to comply with the flexible requirements of the Transport Rule. In the Retrofit Required 20 case, electricity generation from natural gas increases more slowly, and it is 4 percent lower than the Reference case level in 2025, when retrofitted coal plants no longer incur costs for SO2 and NOX emissions allowances (Figure 41). In the Low Gas Price Retrofit Required 20 and 5 cases, utilization of existing combined-cycle natural gas plants is higher throughout the projections, resulting in more gas-fired generation. In all the cases, increases in natural-gas-fired generation after 2025 result predominantly from the construction of new combined-cycle plants to meet growing demand for electricity and replace retired coal capacity.
In the GHG Price Economywide case, coal-fired generation declines steadily throughout the projection. In 2035, generation from coal is approximately 54 percent below the 2009 level, and 11 percent of the electricity generated from coal comes from either new or retrofitted coal plants with CCS. Generation from natural gas increases by more than 90 percent from 2009 to 2035 in the GHG Price Economywide case. Natural gas is a more attractive fuel for complying with a GHG price, because when it is used in an efficient combined-cycle plant, it emits approximately 60 percent less CO2 per kilowatthour of generation than coal burned in a typical existing plant. Toward the end of the projection, new natural gas plants with CCS are also built in the GHG Price Economywide case, and in 2035 13 percent of gas-fired electricity generation is from plants with CCS.
Generation from nuclear power is the same as in the AEO2011 Reference case in all cases, with the exception of the GHG Price Economywide and Low Gas Price Retrofit Required 20 cases. In the GHG Price Economywide case, generation from nuclear capacity increases as a result of additional capacity builds. In the Low Gas Price Retrofit Required 20 case, 2.9 gigawatts of nuclear capacity is retired because electricity prices are low. Generation from renewables remains relatively unchanged from the Reference case level through 2035 in all cases.
Fuel use
High levels of electricity generation from natural gas generally mean more natural gas consumption. In all cases examined here, natural gas use in 2035 is higher than in the Reference case (Figure 42). The largest increase in natural gas consumption occurs in the Low Gas Price Retrofit Required 20 and 5 cases, where natural gas consumption in 2035 is 23 percent and 36 percent higher, respectively, than in the Reference case, as well as in the GHG Price Economywide case, where natural gas consumption is 30 percent higher in 2035.
Capacity additions
The retirement of significant amounts of coal-fired capacity, combined with growth in electricity demand, necessitates the construction of additional generation capacity. Natural gas plants with lower generating costs make up the majority of new capacity in all cases, with the largest amount of new natural gas capacity constructed in the Low Gas Price Retrofit Required 20 and 5 cases. Most of the new coal-fired plants that are built have already been announced and are in either planning or construction stages. All new nuclear plants are built as a result of public policies (such as PTCs and the loan guarantee programs). A small amount of new coal-fired capacity is built in the last few years of the Reference case projection, because natural gas prices rise. Renewable capacity additions are similar to the Reference case in all cases.
In the GHG Price Economywide case there is significantly more new capacity construction than in any of the other cases, as coal-fired plants are retired and need to be replaced with low CO2-emitting technologies (Figure 43). This includes 29 gigawatts of new nuclear capacity added through 2035. In the cases without a CO2 emissions price, new nuclear power plants are built beyond those explicitly helped by the loan guarantee program. However, a price on CO2 emissions raises the cost of electricity sufficiently for nuclear power (which releases no CO2) to become an economically viable option without additional subsidies. Additions of renewable capacity, also a low-CO2 source of electricity, are 36 percent higher in the GHG Price Economywide case than in the Reference case in 2035.
Emissions
Emissions of SO2 decline from Reference case levels in all cases, with more dramatic declines in the Retrofit Required 20 and 5 cases. With the Transport Rule in force, SO2 emissions decline to levels slightly below the Reference case level. The Reference case already includes CAIR, which remains in effect until the Transport Rule takes effect. CAIR features a flexible trading system and allowance banking, resulting in slightly higher annual emissions toward the end of the projection and more variability in year-to-year emissions levels. Trading is more limited with the Transport Rule because of restrictions on the banking of allowances, which levels out emissions over the projection. NOX emissions are slightly higher with the Transport Rule than in the Reference case, because fewer NOX control retrofits are built as a result of the higher NOX allowance prices under CAIR than under the Transport Rule. There are significant reductions in SO2 and NOX emissions in the four Retrofit Required cases, where all coal-fired plants that continue to operate through 2020 are required to be equipped with FGD and SCR. The Retrofit Required 20 and 5 cases are assumed to be implemented nationwide, whereas the Transport Rule Mercury MACT 20 and 5 cases apply only to the targeted States. Except for the Low Gas Price and GHG Price Economywide cases, all cases assume a 90-percent mercury MACT, which reduces mercury emissions significantly from Reference case levels after 2015.
CO2 emissions from the electric power sector in 2035 are lower in all cases than in the Reference case because of the shift from coal-fired to natural-gas-fired generation, but with electricity demand increasing throughout the projection period they are higher than the 2009 level except in the GHG Price Economywide case (Figure 44). Coal-fired plants that are not retired are used heavily, and natural gas plants still emit CO2 albeit at a significantly lower rate per kilowatthour than coal plants. In the GHG Price Economywide case, significantly more coal-fired capacity is retired than in the other cases, and more nuclear and renewable capacity, as well as coal and natural gas capacity equipped with CCS, is deployed.
Electricity prices
Electricity prices in 2035 are less than 2 percent above the Reference case level in the Transport Rule Mercury MACT 20, Retrofit Required 20, and Retrofit Required 5 cases. The increase is relatively modest because several low-cost alternatives for complying with the regulations are available. When lower natural gas prices are assumed, the real price of electricity price declines relative to the Reference case price, as lower natural gas prices are reflected in electricity prices. In the GHG Policy case, which assumes that the cost of CO2 emissions allowances is passed through directly to customers, average electricity prices in 2035 are 38 percent higher than in the Reference case. However, the GHG Price Economywide case does not include any of the consumer rebates from the Waxman-Markey and Kerry-Lieberman bills, which have the effect of significantly lowering electric prices.
Reliability
The possible retirement of significant amounts of coal-fired generating capacity has raised concerns about reliability of the electric power grid. For example, the North American Electric Reliability Council has warned that EPA regulation of emissions from the power sector is a threat to reliability standards. Specific plants may be important to the reliability of a specific region, and if they are shut down before replacement capacity has been constructed, local reliability shortfalls could ensue. However, several safeguards exist to prevent such problems. Merchant plant owners must obtain permission from grid operators before retiring capacity [83], and regulated utilities must demonstrate to their public utility commissions that their fleets meet the reliability standards included in their integrated resource plans.
On a national level, electric reliability shortfalls resulting from the retirement of coal plants can be mitigated both by increasing the utilization of other existing plants and by constructing new capacity. From 2000 to 2009, about 190 gigawatts of natural-gas-fired capacity was added in the U.S. electric power sector. In the AEO2011 Reference case another 135 gigawatts of natural-gas-fired capacity is added from 2010 to 2035, and in the Low Gas Price case 154 gigawatts of new natural-gas-fired capacity is added. Most of the new capacity is built after 2020 in both cases.