U.S. Energy Information Administration - EIA - Independent Statistics and Analysis
Annual Energy Outlook 2011
Release Date: April 26, 2011 | Next Early Release Date: January 23, 2012 | Report Number: DOE/EIA-0383(2011)
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Unlike crude oil prices, natural gas prices do not return to the higher levels recorded before the 2007-2009 recession (Figure 86). Although some supply factors continue to relate the two markets loosely, the two do not track directly (Figure 87). The large difference between crude oil and natural gas prices results in a shift in drilling toward shale formations with high concentrations of liquids.
Shale gas continues to have enormous potential. To satisfy consumption levels in the Reference case, the number of lower 48 natural gas wells completed increases by 2.3 percent per year from 2009 to 2035. As a result, the average wellhead price for natural gas increases by an average of 2.1 percent per year, to $6.26 per million Btu in 2035 (2009 dollars). Henry Hub prices increase by 2.3 percent per year, to $7.07 per million Btu in 2035. Nonetheless, the Henry Hub price and average wellhead prices do not pass $5.00 per million Btu until 2020 and 2024, respectively.
The extent to which natural gas prices in the Rapid and Slow Oil and Gas Technology cases differ from the Reference case depends on assumptions about the rate of improvement in natural gas exploration and production technologies. Technology improvement can reduce drilling and operating costs, expand the economically recoverable resource base, and affect the timing of production increases. It is particularly important to the production of natural gas from shale formations. The Reference case assumes that annual technology improvements follow historical trends. In the Rapid Oil and Gas Technology case, exploration and development costs decline at a faster rate, accelerating growth in production, which puts downward pressure on prices. In the Slow Oil and Gas Technology case, slower respective cost declines lead to higher natural gas prices and lower levels of consumption than in the Reference case (Figure 88).
The same type of impact can be seen from changes in economic growth and demand technologies. In the High Economic Growth and Integrated Low Technology cases, higher levels of demand result in increased production, which puts upward pressure on natural gas prices. In the Low Economic Growth and Integrated High Technology cases, the opposite impact is seen. Lower levels of demand put downward pressure on natural gas prices.
In the High Economic Growth and Slow Oil and Gas Technology cases with faster production growth, prices rise to levels that cause the Alaska pipeline to be completed towards the end of the projection, leading to temporary declines in natural gas prices. In the other cases, natural gas prices remain too low to make the Alaska pipeline economical before 2035.
The increase in natural gas production from 2009 to 2035 in the AEO2011 Reference case results primarily from continued exploration and development of shale gas resources (Figure 89). Shale gas is the largest contributor to production growth, while production from tight sands, coalbed methane deposits, and offshore waters remains stable. Shale gas makes up 47 percent of total U.S. production in 2035, nearly triple its 16-percent share in 2009. The estimate for technically recoverable unproved shale gas resources in the AEO2011 Reference case is 827 trillion cubic feet. Although more information has become available as a result of increased drilling activity in developing shale gas plays, estimates of technically recoverable resources and well productivity remain highly uncertain. The "Issues in focus" section explores several sensitivity cases that alter the outlook for shale gas resources.
Offshore natural gas production in the Reference case declines initially, reflecting delays in near-term projects in the Gulf of Mexico. According to the latest leasing plan from the Bureau of Ocean Energy Management, lease sales in the Mid- and South Atlantic outer continental shelf (OCS) will not occur before 2017. Because the Pacific OCS is considered to have low economic potential, AEO2011 assumes that leasing in the Pacific will occur only in the southern California offshore and only after 2023.
Production from coalbeds and tight sands does not contribute to total production growth in the Reference case but does remain an important source of natural gas, accounting for 29 to 40 percent of total production from 2009 to 2035.
Economic growth and technology progress affect natural gas supply
The level of domestic natural gas production is influenced by changes in the rate of economic growth and improvement in exploration and development technologies. The effect of economic growth results from its impact on the level of natural gas consumption. Changes in the rate of technology improvement affect natural gas drilling and production costs, which in turn can affect productive capacity of natural gas wells and change the number of successful wells, resulting in lower or higher production.
From 2009 to 2035, average annual natural gas consumption is 1.1 trillion cubic feet higher in the High Economic Growth case than in the Reference case. Domestic production accounts for 90 percent of this increase, with imports from Canada supplying most of the rest. On average in the High Economic Growth case, 64 percent of the increase in domestic production from 2009 to 2035 comes from shale gas, 15 percent from tight sands, and the remainder from offshore wells, coalbeds, and an Alaska pipeline completed in 2034.
Average annual natural gas production from 2009 to 2035 is 0.7 trillion cubic feet higher and 0.9 trillion cubic feet lower in the Rapid and Slow Technology cases, respectively, than in the Reference case (Figure 90). Shale gas production accounts for most of the difference, increasing by 0.8 trillion cubic feet per year on average from Reference case levels in the High Technology case and decreasing by 0.9 trillion cubic feet per year on average in the Slow Technology case. Higher prices in the Slow Technology case enable the Alaska pipeline to be completed in 2032, displacing more expensive production from tight sands and coalbed methane sources in the Rocky Mountain region, where shale gas is less abundant. Lower production levels in the Slow Technology case result from higher costs, lower resource availability, and, ultimately, reduced consumption in response to higher prices.
An almost four-fold increase in shale gas production from 2009 to 2035 more than offsets a 26-percent decline in non-shale lower 48 onshore natural gas production in the AEO2011 Reference case. Significant increases in shale gas production occur in the Northeast and Gulf Coast regions. (See Figure F4 in Appendix F for a map of the regions.) Resource estimates for the Marcellus, Haynesville, and Eagle Ford plays have continued to increase as new information becomes available from exploration and development in those areas.
Dry gas production in the Northeast region increases in the Reference case nearly five-fold from 2009 to 2035 (Figure 91). The majority of the increase comes from the Marcellus shale gas play, which has an estimated technically recoverable resource base of about 400 trillion cubic feet. Because the growth in shale gas production displaces much of the natural gas that currently is supplied to the Northeast from the Gulf Coast and Canada, Gulf Coast gas tends to saturate the Henry Hub market and put downward pressure on natural gas prices.
Even with significant growth in shale gas production, total production in the Gulf Coast and Midcontinent regions falls, reflecting significant declines in sources other than shale formations. In particular, rigs previously used for drilling in tight sands are being moved to shale deposits. In the Southwest, as shale production increases, production from non-shale sources is maintained at a level that allows the region's total production to grow. In the Rocky Mountain region, production increases from tight sands and coalbed methane sources support increases in total production.
U.S. net imports of natural gas decline as domestic production rises
U.S. net imports of natural gas decline in the AEO2011 Reference case from 11 percent of total supply in 2009 to 1 percent in 2035. The reduction consists primarily of lower imports from Canada and higher net exports to Mexico (Figure 92), as a result of demand growth in both countries that outpace growth in their production.
Supplies of natural gas from Canada's conventional sources decline from 2009 to 2035, but those declines are offset by increased production from coalbeds, tight formations, and shale gas deposits, allowing for a relatively constant level of exports to the United States through 2018 before they begin to decline. In addition, net imports to the United States from Canada are offset somewhat by an increase in exports from the United States to eastern Canada.
Mexico's natural gas consumption shows robust growth through 2035, and expected increases in its domestic production are not sufficient to meet demand growth. As a result, Mexico will need to import natural gas to fill the gap. Some of the increased supply to Mexico will be delivered by LNG tankers, largely to the south of the country, with the remainder coming from the United States.
LNG imports by the United States are minimal in the Reference case and occur largely during periods when world liquefaction capacity exceeds demand. Although U.S. LNG export projects have been proposed, their economic viability remains uncertain in view of the relatively inexpensive sources of natural gas supply available elsewhere in the world. As a result, existing liquefaction capacity in Alaska is the only source for U.S. exports of LNG that is considered in the AEO2011 Reference case .
Decisions to add capacity and the choice of fuel depend on a number of factors . With growing electricity demand and the retirement of 39 gigawatts of existing capacity, 223 gigawatts of new generating capacity (including end-use combined heat and power) will be needed between 2010 and 2035 (Figure 78).
Natural-gas-fired plants account for 60 percent of capacity additions between 2010 and 2035 in the AEO2011 Reference case, compared with 25 percent for renewables, 11 percent for coal-fired plants, and 3 percent for nuclear. Escalating construction costs have the largest impact on capital-intensive technologies, including nuclear, coal, and renewables. However, Federal tax incentives, State energy programs, and rising prices for fossil fuels increase the competitiveness of renewable and nuclear capacity. In contrast, uncertainty about future limits on greenhouse gas emissions and other possible environmental regulations reduces the competitiveness of coal-fired plants (reflected in the AEO2011 Reference case by adding 3 percentage points to the cost of capital for new coal-fired capacity).
Capacity additions also are affected by demand growth and by fuel prices, which are uncertain. Total capacity additions from 2010 to 2035 range from 172 gigawatts in the Low Economic Growth case to 290 gigawatts in the High Economic Growth case. With higher natural gas prices, such as in the AEO2011 Low Shale EUR case, fewer natural-gas-fired plants are added than in the Reference case. In the High Shale EUR case, where delivered natural gas prices are 21 percent lower than in the Reference case by 2035, total gas-fired capacity additions increase to 154 gigawatts between 2009 and 2035 compared to 135 gigawatts in the Reference case. Total capacity additions range from 212 gigawatts in the Low Shale EUR case to 230 gigawatts in the High Shale EUR case.
With world oil prices rising in the AEO2011 Reference case, domestic liquids production grows (Figure 94). From 2009 to 2035, U.S. crude oil production increases by about 600,000 barrels per day.
As a result of the EISA2007 RFS, biofuels production increases by almost 1.5 million barrel per day, with ethanol accounting for the largest share of the increase. Ethanol production increases by more than 800,000 barrels per day from 2009 to 2035, displacing approximately 12 percent of gasoline demand in 2035 on an energy-equivalent basis. In the early years of the projection, ethanol is blended with gasoline and consumed as E10, motor gasoline blends containing up to 10 percent ethanol, or E15, moror gasoline blends containing up to 15 percent ethanol. By 2035, however, ethanol is consumed in roughly equal shares as E10, E15, and E85.
NGL production increases by 1.0 million barrels per day, to 2.9 million barrels per day in 2035, mainly as a result of strong growth in gas shale production, which tends to have relatively large amounts of liquids associated with it. BTL production increases to 516,000 barrels per day, and CTL production increases to 550,000 barrels per day in 2035.
Much of the increased liquids production comes from oil in shale formations (i.e., produced from kerogen, a solid hydrocarbon), CO2-enhanced oil recovery (EOR), and next-generation "xTL" production, which includes biomass-to-liquids (BTL), GTL, and CTL.
U.S. reliance on imported natural gas falls, and exports rise
The energy markets of the three North American nations (United States, Canada, and Mexico) are well integrated, with extensive infrastructure that allows cross-border trade between the United States and both Canada and Mexico. The United States, which is by far the region’s largest energy consumer, relies on Canada and Mexico for supplies of liquid fuels. Canada and Mexico were the largest suppliers of U.S. liquids imports in 2009, providing 2.5 and 1.2 million barrels per day, respectively. In addition, Canada supplies the United States with substantial natural gas supplies, exporting 3.2 trillion cubic feet to U.S. markets in 2009 (Figure 51).
In the AEO2011 Reference case, the existing trade relationships between the United States and the two other North American countries continue. In 2035, the United States still imports 2.6 million barrels per day of liquid fuels from Canada and about 1.0 million barrels per day from Mexico. The improving prospects for domestic U.S. natural gas production, however, mean a smaller natural gas import requirement. In 2035, U.S. imports of Canadian natural gas fall to 2.8 trillion cubic feet. On the other hand, U.S. natural gas exports to both Canada and Mexico increase. Canada's imports of U.S. natural gas rise from 0.7 trillion cubic feet in 2009 to 1.0 trillion cubic feet in 2035, and Mexico’s imports rise from 0.3 trillion cubic feet in 2009 to 1.6 trillion cubic feet in 2035."