TODAY’S STUDY: ENERGY OLD AND NEW, THE GOVERNMENT REPORT
Annual Energy Outlook 2012 Early Release Overview
January 23, 2012 (U.S. Energy Information Administration)
AEO2012 Early Release Overview Executive Summary
Projections in the Annual Energy Outlook 2012 (AEO2012) Reference case focus on the factors that shape U.S. energy markets in the long term, under the assumption that current laws and regulations remain generally unchanged throughout the projection period. The AEO2012 Reference case provides the basis for examination and discussion of energy market trends and serves as a starting point for analysis of potential changes in U.S. energy policies, rules, or regulations or potential technology breakthroughs. Some of the highlights in the AEO2012 Reference case include:
Projected growth of energy use slows over the projection period, reflecting an extended economic recovery and increasing energy efficiency in end-use applications Projected transportation energy demand grows at an annual rate of 0.2 percent from 2010 through 2035 in the Reference case, and electricity demand grows by 0.8 percent per year. Energy consumption per capita declines by an average of 0.5 percent per year from 2010 to 2035. The energy intensity of the U.S. economy, measured as primary energy use in British thermal units (Btu) per dollar of gross domestic product (GDP) in 2005 dollars, declines by 42 percent from 2010 to 2035.
Domestic crude oil production increases Domestic crude oil production has increased over the past few years, reversing a decline that began in 1986. U.S. crude oil production increased from 5.1 million barrels per day in 2007 to 5.5 million barrels per day in 2010. Over the next 10 years, continued development of tight oil, in combination with the ongoing development of offshore resources in the Gulf of Mexico, pushes domestic crude oil production in the Reference case to 6.7 million barrels per day in 2020, a level not seen since 1994. Even with a projected decline after 2020, U.S. crude oil production remains above 6.1 million barrels per day through 2035.
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With modest economic growth, increased efficiency, growing domestic production, and continued adoption of nonpetroleum liquids, net petroleum imports make up a smaller share of total liquids consumption U.S. dependence on imported petroleum liquids declines in the AEO2012 Reference case, primarily as a result of growth in domestic oil production by more than 1 million barrels per day by 2020; an increase in biofuels use of more than 1 million barrels per day crude oil equivalent by 2024; and modest growth in transportation sector demand through 2035. Net petroleum imports as a share of total U.S. liquid fuels consumed drop from 49 percent in 2010 to 36 percent in 2035 in AEO2012 (Figure 1). Proposed fuel economy standards covering vehicle model years 2017 through 2025 that are not included in the Reference case would further reduce projected liquids use and the need for liquids imports.
Natural gas production increases throughout the projection period Much of the growth in natural gas production is a result of the application of recent technological advances and continued drilling in shale plays with high concentrations of natural gas liquids and crude oil, which have a higher value in energy equivalent terms than dry natural gas. Shale gas production increases from 5.0 trillion cubic feet in 2010 (23 percent of total U.S. dry gas production) to 13.6 trillion cubic feet in 2035 (49 percent of total U.S. dry gas production) (Figure 2).
U.S. production of natural gas is expected to exceed consumption early in the next decade The United States is projected to become a net exporter of liquefied natural gas (LNG) in 2016, a net pipeline exporter in 2025, and an overall net exporter of natural gas in 2021. The outlook reflects increased use of LNG in markets outside of North America, strong domestic natural gas production, reduced pipeline imports and increased pipeline exports, and relatively low natural gas prices in the United States compared to other global markets.
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Use of renewable fuels and natural gas for electric power generation rises The natural gas share of electric power generation increases from 24 percent in 2010 to 27 percent in 2035, and the renewables share grows from 10 percent to 16 percent over the same period. In recent years, the U.S. electric power sector’s historical reliance on coal-fired power plants has begun to decline. Over the next 25 years, the projected coal share of overall electricity generation falls to 39 percent, well below the 49-percent share seen as recently as 2007 (Figure 3), because of slow growth in electricity demand, continued competition from natural gas and renewable plants, and the need to comply with new environmental regulations.
Total U.S. energy-related carbon dioxide emissions remain below their 2005 level through 2035 Energy-related carbon dioxide (CO2) emissions grow by 3 percent from 2010 to 2035, to a total of 5,806 million metric tons in 2035. They are more than 7 percent below their 2005 level of 5,996 million metric tons in 2020 and are still below the 2005 level at the end of the projection period (Figure 4). Emissions per capita fall by an average of 1 percent per year from 2005 to 2035, as growth in demand for transportation fuels is moderated by higher energy prices and Federal corporate average fuel economy (CAFE) standards, and as electricity-related emissions are tempered by efficiency standards, State renewable portfolio standard (RPS) requirements, competitive natural gas prices that dampen coal use by electricity generators, and the need to comply with new environmental regulations. Proposed fuel economy standards covering model years 2017 through 2025 that are not included in the Reference case would further reduce projected energy use and emissions.
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In preparing the AEO2012 Reference case, the U.S. Energy Information Administration (EIA) evaluated a wide range of trends and issues that could have major implications for U.S. energy markets. This overview presents the AEO2012 Reference case and compares it with the AEO2011 Reference case released in April 2011 (see Table 1 on pages 12-13). Because of the uncertainties inherent in any energy market projection, the Reference case results should not be viewed in isolation. Readers are encouraged to review the alternative cases when the complete AEO2012 publication is released, in order to gain perspective on how variations in key assumptions can lead to different outlooks for energy markets.
To provide a basis against which alternative cases and policies can be compared, the AEO2012 Reference case generally assumes that current laws and regulations affecting the energy sector remain unchanged throughout the projection (including the implication that laws which include sunset dates do, in fact, become ineffective at the time of those sunset dates). This assumption helps increase the comparability of the Reference case with other analyses, clarifies the relationship of the Reference case to other AEO2012 cases, and enables policy analysis with less uncertainty arising from speculative legal or regulatory assumptions. Currently, there are many pieces of legislation and regulation that appear to have some probability of being enacted in the not-too-distant future, and some existing laws include sunset provisions that may be extended. However, it is difficult to discern the exact forms that the final provisions of pending legislation or regulations will take, and sunset provisions may or may not be extended. Even in situations where existing legislation contains provisions to allow revision of implementing regulations, those provisions may not be exercised consistently. In certain situations, however, where it is clear that a law or regulation will take effect shortly after the AEO Reference case is completed, it may be considered in the projection.
As in past editions of the AEO, the complete AEO2012 will include additional cases, many of which reflect the impacts of extending a variety of current energy programs beyond their current expiration dates and the permanent retention of a broad set of programs that currently are subject to sunset provisions. In addition to the alternative cases prepared for AEO2012, EIA has examined proposed policies at the request of Congress over the past few years. Reports describing the results of those analyses are available on EIA’s website.1
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Key updates made for the AEO2012 Reference case include the following:
• Industrial cogeneration was updated with historical rather than assumed capacity factors for new units and with updated investment decision procedures that reflect regional acceptance rates for new cogeneration facilities.
• A new heavy-duty vehicle model was adopted in the transportation module, with greater detail on size classes and end-use vehicle types to enable modeling of fuel economy regulations covering the heavy-duty vehicle fleet.
• The light-duty fleet model in the transportation module was updated to include a new algorithm for consumer purchase choice that compares fuel savings against incremental vehicle cost for advanced technologies, new technology cost and performance assumptions, and representation of fuel efficiency standards already in effect.
• Shale gas resource estimates for four plays (Haynesville, Fayetteville, Eagle Ford, and Woodford) were updated using the mean value of resource assessments recently released by the U.S. Geological Survey (USGS). The shale gas resource estimate for the Marcellus play was updated using new geologic data from the USGS and recent production data. EIA’s estimate of Marcellus resources is substantially below the estimate used for AEO2011 and falls within the 90-percent confidence range in the August 2011 USGS assessment, although it is higher than the USGS mean value.
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• The tight oil resource estimate for the Bakken play was increased to include more of the Three Forks and Sanish zones.
• The handling of U.S. LNG exports of domestically sourced gas was updated, resulting in exports beginning in 2016.
• The electricity module was updated to incorporate the Cross-State Air Pollution Rule (CSAPR)2 as finalized by the EPA in July 2011. CSAPR requires reductions in emissions from power plants that contribute to ozone and fine particle pollution in 28 States.
• Assumptions regarding the potential for capacity uprates at existing nuclear plants and the timing for existing nuclear plant retirements were revised.
• Updates were made to reflect recent information pertaining to retirement dates for existing power plants and scheduled in-service dates for new power plants.
• California Assembly Bill 32 (AB 32), the Global Warming Solutions Act of 2006, was incorporated for electricity sector power plants serving California. As modeled, AB 32 imposes a limit on power sector CO2 emissions, beginning in 2012 and declining at a uniform annual rate through 2020.
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Recovery from the 2008-2009 recession is expected to show the slowest growth of any recovery since 1960. Table 2 compares average annual growth rates over a five-year period following U.S. recessions that have occurred since 1960.
For the most recent recession, the expected five-year average annual growth rate in real GDP from 2009 to 2014 is 1.3 percentage points below the corresponding average for the three past recessions, with consumption and non-farm employment recovering even more slowly. The slower growth in the early years of the projection has implications for the long term, with a lower economic growth rate leading to a slower recovery in employment and higher unemployment rates.
Real GDP in 2035 is 4 percent lower in the AEO2012 Reference case than was projected in the AEO2011 Reference case. Real GDP grows by an average of 2.6 percent per year from 2010 to 2035 in the AEO2012 Reference case, 0.1 percent per year lower than in the AEO2011 Reference case. The Nation’s population, labor force, and productivity grow at annual rates of 0.9 percent, 0.7 percent, and 1.9 percent, respectively, from 2010 to 2035.
Beyond 2012, the economic assumptions underlying the AEO2012 Reference case reflect trend projections that do not include short-term fluctuations. Economic growth projections for 2012 are consistent with those published in EIA’s October 2011 Short-Term Energy Outlook….
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With increased production, average annual wellhead prices for natural gas remain below $5 per thousand cubic feet (2010 dollars) through 2023 in the AEO2012 Reference case. The projected prices reflect continued industry success in tapping the Nation’s extensive shale gas resource. The resilience of drilling levels, despite low natural gas prices, is in part a result of high crude oil prices, which significantly improve the economics of natural gas plays that have high concentrations of crude oil, condensates, or natural gas liquids. After 2023, natural gas prices generally increase as the numbers of tight gas and shale gas wells drilled increase to meet growing domestic demand for natural gas and offset declines in natural gas production from other sources. Natural gas prices rise as production gradually shifts to resources that are less productive and more expensive. Natural gas wellhead prices (in 2010 dollars) reach $6.52 per thousand cubic feet in 2035, compared with $6.48 per thousand cubic feet (2010 dollars) in AEO2011.
The average minemouth price of coal increases by 1.4 percent per year in the AEO2012 Reference case, from $1.76 per million Btu in 2010 to $2.51 per million Btu in 2035 (2010 dollars). The upward trend of coal prices primarily reflects an expectation that cost savings from technological improvements in coal mining will be outweighed by increases in production costs associated with moving into reserves that are more costly to mine. The coal price outlook in the AEO2012 Reference case represents a change from the AEO2011 Reference case, where coal prices were essentially flat.
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Following the recent rapid decline of natural gas prices, real average delivered electricity prices in the AEO2012 Reference case fall from 9.8 cents per kilowatthour in 2010 to as low as 9.2 cents per kilowatthour in 2019, as natural gas prices remain relatively low. Electricity prices tend to reflect trends in fuel prices—particularly, natural gas prices, because in much of the country natural gas-fired plants often set wholesale power prices. It can take time, however, for fuel price changes to affect electricity prices because of the varying lengths of fuel- and power-supply contracts and the periods between electricity rate cases. In the AEO2012 Reference case, electricity prices are higher throughout the projection than they were in the AEO2011 Reference case. Although natural gas prices to electricity generators are similar to those in AEO2011, the cost of coal is higher. In addition, reliance on natural gas-fired generation in the power sector increases partially as a result of new environmental regulation covering emissions of sulfur dioxide (SO2) and nitrogen oxides (NOX) that make it a more economical option. Electricity prices in 2035 are 9.5 cents per kilowatthour (2010 dollars) in the AEO2012 Reference case, compared with 9.3 cents per kilowatthour in the AEO2011 Reference case….
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Total electricity consumption, including both purchases from electric power producers and on-site generation, grows from 3,879 billion kilowatthours in 2010 to 4,775 billion kilowatthours in 2035 in the AEO2012 Reference case, increasing at an average annual rate of 0.8 percent, about the same rate as in the AEO2011 Reference case.
The combination of slow growth in electricity demand, competitively priced natural gas, programs encouraging renewable fuel use, and the implementation of new environmental rules dampens coal use in the future. The AEO2012 Reference case includes the impacts of the CSAPR, which was finalized in July 2011 and was not represented in the AEO2011 Reference case. CSAPR requires reductions in SO2 and NOX emissions in roughly one-half of the States, with an initial target in 2012 and further reductions in 2014. Even so, coal remains the dominant energy source for electricity generation, but its share of total generation declines from 45 percent in 2010 to 39 percent in 2035 (see Figure 3 on page 2). Market concerns about GHG emissions continue to slow the expansion of coal-fired capacity in the AEO2012 Reference case, even under current laws and policies. Low projected fuel prices for new natural gas-fired plants also affect the relative economics of coal-fired capacity, as does the continued rise in construction costs for new coal-fired power plants. As retirements outpace new additions, total coal-fired generating capacity falls from 318 gigawatts in 2010 to 301 gigawatts in 2035 in the AEO2012 Reference case.
Electricity generation using natural gas is higher in the AEO2012 Reference case than was projected in the AEO2011 Reference case, particularly over the next 10 years, during which natural gas prices are expected to remain low. New natural gas-fired plants also are much cheaper to build than new renewable or nuclear plants. In 2015, natural gas-fired generation in AEO2012 is 13 percent higher than in AEO2011, and in 2035 it is still 6 percent higher. Electricity generation from nuclear power plants grows by 11 percent in the AEO2012 Reference case, from 807 billion kilowatthours in 2010 to 894 billion kilowatthours in 2035, accounting for about 18 percent of total generation in 2035 (compared with 20 percent in 2010).
Nuclear generating capacity increases from 101 gigawatts in 2010 to a high of 115 gigawatts in 2025, after which a few retirements result in a decline to 112 gigawatts in 2035. AEO2012 incorporates new information about planned nuclear plant construction, as well as an updated estimate of the potential for capacity uprates at existing units. A total of 10 gigawatts of new nuclear capacity is projected through 2035, as well as an increase of 7 gigawatts achieved from uprates to existing nuclear units. About 6 gigawatts of existing nuclear capacity is retired, primarily in the last few years of the projection, as not all owners of existing nuclear capacity apply for and receive license renewals to operate their plants beyond 60 years. Increased generation from renewable energy in the electric power sector, excluding hydropower, accounts for 33 percent of the overall growth in electricity generation from 2010 to 2035.
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Generation from renewable resources grows in response to Federal tax credits, State-level policies, and Federal requirements to use more biomass-based transportation fuels, some of which can produce electricity as a byproduct of the production process. Near-term market growth in some sectors, such as solar energy, is projected to result in significantly reduced costs in the AEO2012 Reference case, increasing the projected growth for those resources as compared with the AEO2011 projections. More retirements of coal-fired capacity are expected in the AEO2012 Reference case than were projected in AEO2011 because of slower growth in electricity demand, continued competition from natural gas and renewable plants, and the need to comply with new environmental regulations. Growth in renewable generation is supported by many State requirements, as well as new regulations on CO2 emissions in California. The share of U.S. electricity generation coming from renewable fuels (including conventional hydropower) grows from 10 percent in 2010 to 16 percent in 2035. In the AEO2012 Reference case, Federal subsidies for renewable generation are assumed to expire as enacted. Extensions of such subsidies could have a large impact on renewable generation.
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Energy-related CO2 emissions
Although total U.S. energy-related CO2 emissions increased by almost 4 percent in 2010, they do not return to their 2005 level (5,996 million metric tons) by the end of the AEO2012 projection period (see Figure 4 on page 2). Emissions per capita fall by an average of 1 percent per year from 2005 to 2035, as growth in demand for transportation fuels is moderated by higher energy prices and Federal CAFE standards. In addition, electricity-related emissions are tempered by efficiency standards, State RPS requirements, and implementation of the CSAPR, which helps shift the fuel mix away from coal toward lower carbon fuels.
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Energy-related CO2 emissions reflect the mix of fossil fuels consumed. Given the high carbon content of coal and its use to generate 45 percent of the U.S. electricity supply in 2010, prospects for CO2 emissions depend, in part, on growth in electricity demand as well as the portion of that demand satisfied by coal-fired generation. After declining from 2007 to 2009, electricity sales grew in 2010 by 4.3 percent. Electricity sales continue to grow through 2035 in the AEO2012 Reference case, but the growth is tempered by a variety of regulatory and socioeconomic factors, including appliance and building efficiency standards and a continued transition to a more service-oriented economy. The combination of slow demand growth, competitive natural gas prices, and CSAPR included in the AEO2012 Reference case lowers the consumption of coal within the first 5 years of the projection period; as a result, emissions from coal combustion in the power sector in 2015 are 149 million metric tons below the AEO2011 Reference case projection. With modest growth in electricity demand and increased use of renewables for electricity generation, electricity-related CO2 emissions grow by a total of 4.9 percent (0.2 percent per year) from 2010 to 2035. Growth in CO2 emissions from transportation activity also slows in comparison with the recent pre-recession experience, as Federal CAFE standards increase the efficiency of the vehicle fleet, employment recovers slowly, and higher fuel prices moderate growth in travel. The AEO2012 Reference case projections do not include proposed increases in fuel economy standards for model years 2017 through 2025, which are expected to further reduce fuel use and emissions.
Taken together, these factors tend to slow the growth in primary energy consumption and CO2 emissions. As a result, energy-related CO2 emissions in 2035 are only 3 percent higher than in 2010 (as compared with the 10-percent increase in total energy use), and the carbon intensity of U.S. energy consumption falls from 57.4 to 53.8 kilograms per million Btu (6.3 percent). Over the same period, U.S. economic activity becomes less carbon-intensive, as energy-related CO2 emissions per dollar of GDP decline by 45 percent.