‹ Analysis & Projections

AEO2011 Early Release Overview

Release Date: December 16, 2011   |  Next Release Date: January 2012  |   Report Number: DOE/EIA-0383ER(2011)

Energy Productions and Imports


Figure Data
Net imports of energy meet a major, but declining, share of total U.S. energy demand in the AEO2011 Reference case (Figure 10). The projected growth in energy imports is moderated by increased use of biofuels (much of which are produced domestically), demand reductions resulting from the adoption of new efficiency standards, and rising energy prices. Rising fuel prices also spur domestic energy production across all fuels, particularly natural gas from plentiful shale gas resources, and temper the growth of energy imports. The net import share of total U.S. energy consumption in 2035 is 18 percent, compared with 24 percent in 2009. (The share was 29 percent in 2007, but it dropped considerably during the recession.)

Liquids


Figure Data
U.S. dependence on imported liquid fuels measured as a share of total U.S. liquid fuel use, which reached 60 percent in 2005 and 2006 before falling to 52 percent in 2009, is expected to continue declining over the projection period, to 42 percent in 2035.

In the AEO2011 Reference case, U.S. domestic crude oil production increases from 5.4 million barrels per day in 2009 to 5.7 million barrels per day in 2035 (Figure 11). Production increases are expected from onshore enhanced oil recovery (EOR) projects, shale oil plays, and deepwater drilling in the Gulf of Mexico. Cumulatively, oil production in the lower 48 States in the AEO2011 Reference case is approximately the same as in the AEO2010 Reference case, but the pattern diff ers in that more onshore and less off shore oil is produced in AEO2011.

Onshore oil production is higher in AEO2011 as a result of an increase in EOR, as well as increased oil production from shale oil sources, for which the estimate has been increased relative to AEO2010. In AEO2011, EOR accounts for 33 percent of cumulative onshore oil production. The bulk of the EOR production uses CO2. For CO2-enhanced EOR oil production, naturally produced CO2 or man-made CO2 captured from sources such as natural gas plants and power plants is injected into a reservoir to allow the oil to flow more easily to the well bore.

Off shore oil production in AEO2011 is lower than in AEO2010 throughout most of the projection period because of expected delays in near-term projects, in part as a result of drilling moratoria and in part due to the change in lease sales expected in the Pacifi c and Atlantic outer continental shelf (OCS), as well as increased uncertainty about future investment in off shore production. As with natural gas, the application of horizontal drilling together with hydrofracturing techniques have allowed significant increases in the development of shale oil resources (oil resident in shale rock). With AEO2011 incorporating five key shale oil plays (as opposed to two in AEO2010), oil production rises significantly in areas of the country where shale oil is being produced, including the Rocky Mountains (primarily from the Bakken shale), the Gulf Coast (primarily from the Eagle Ford and Austin Chalk plays), the Southwest (primarily from the Avalon play), and California (primarily from the Lower Monterey and Santos plays).

Natural Gas

The addition of shale gas resources in existing plays that can be produced at prices under $7 per thousand cubic feet results in higher shale gas production overall and a higher rate of development in the AEO2011 Reference case than in the AEO2010 Reference case. Cumulative natural gas production in the lower 48 States over the projection period in the AEO2011 Reference case is 25 percent higher than in the AEO2010 Reference case as a result of greater supply availability from shale gas plays.

In the AEO2010 Reference case, technically recoverable unproved shale gas resources were estimated at 347 trillion cubic feet; in the AEO2011 Reference case they are estimated at 827 trillion cubic feet. The revised estimate results from the availability of additional information as more drilling activity takes place in both existing and new shale plays.

As a result of updated shale gas resources in existing plays (key additions were in the Marcellus, Haynesville, and Eagle Ford plays) and an assumption of increased well productivity for the newer plays, shale gas production in 2035 in the AEO2011 Reference case is almost double that in the AEO2010 Reference case.

There is considerable uncertainty about the amounts of recoverable shale gas in both developed and undeveloped areas. Well characteristics and productivity vary widely not only across different plays but within individual plays. Initial production rates can vary by as much as a factor of 10 across a formation, and the productivity of adjacent gas wells can vary by as much as a factor of 2 or 3. Many shale formations, such as the Marcellus Shale, are so large that only a small portion of the entire formation has been intensively production-tested. Environmental considerations, particularly in the area of water usage, lend additional uncertainty. Although signifi cant updates have been made to the estimates of undiscovered shale gas resources in newer areas, most of the resulting additions are not economically recoverable at AEO2011 prices and have little, if any, impact on the projection.

The Alaska natural gas pipeline, expected to be completed in 2023 in the AEO2010 Reference case, is not constructed in the AEO2011 Reference case. This change is a result of increased capital cost assumptions and lower natural gas wellhead prices, which make it uneconomical to proceed with the project over the projection period.

Although net pipeline imports of natural gas from Canada and Mexico decline to lower levels in 2035 in the AEO2011 Reference case than were projected in the AEO2010 Reference case, the cumulative volumes of net imports over the projection period are higher in AEO2011. The higher levels of cumulative net pipeline imports in AEO2011 result largely from a decrease in Canada's domestic consumption of natural gas and an increase in the country's assumed shale gas resources and production.

Total U.S. net imports of LNG in the AEO2011 Reference case are lower than in the AEO2010 Reference case, due in part to less world liquefaction capacity and greater world regasifi cation capacity, as well as increased use of LNG in markets outside North America. For example, spot market purchases of LNG in Europe are expected to displace pipeline gas supplies that are indexed to world oil prices. Lower natural gas prices in the United States are also a contributing factor.

Coal

Although coal remains the leading fuel for U.S. electricity generation, its share of total electricity generation is consistently lower in the AEO2011 Reference case than in the AEO2010 Reference case through about 2023 (but similar thereafter). As a consequence, while still growing in most projection years, total coal production is slightly lower in the AEO2011 Reference case than in the AEO2010 Reference case.

As U.S. coal use grows in the AEO2011 Reference case, domestic coal production increases at an average rate of 0.7 percent per year, from 21.6 quadrillion Btu (1,075 million short tons) in 2009 to 25.8 quadrillion Btu (1,305 million short tons) in 2035. Production from mines west of the Mississippi River trends upward over the entire projection period. Following a substantial decline in output between 2009 and 2015, coal production east of the Mississippi River remains relatively constant from 2015 through 2035. On a Btu basis, 60 percent of domestic coal production originates from States west of the Mississippi River in 2035, up from 50 percent in 2009.

Typically, trends in U.S. coal production are linked to its use for electricity generation, which currently accounts for 93 percent of total coal consumption. Coal consumption in the electric power sector in the AEO2011 Reference case (21.8 quadrillion Btu in 2035) is about 1.3 quadrillion Btu less than in the AEO2010 Reference case (23.1 quadrillion Btu in 2035). For the most part, the reduced outlook for coal consumption in the electricity sector is the result of lower natural gas prices that support increased generation from natural gas in the AEO2011 Reference case.