‹ Analysis & Projections

Annual Energy Outlook 2014

Release Dates: April 7 - 30, 2014   |  Next Early Release Date: December 2014   |  See schedule

Market Trends — Oil/Liquids

Petroleum and other liquids consumption outside industrial sector is stagnant or declines


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Consumption of petroleum and other liquids peaks at 19.8 million barrels per day in 2019 in the AEO2013 Reference case and then falls to 18.9 million barrels per day in 2040 (Figure 93). The transportation sector accounts for the largest share of total consumption throughout the projection, although its share falls to 68 percent in 2040 from 72 percent in 2012 as a result of improvements in vehicle efficiency following the incorporation of CAFE standards for both LDVs and HDVs. Consumption of petroleum and other liquids increases in the industrial sector, by 0.6 million barrels per day from 2011 to 2040, but decreases in all the other end-use sectors.

Motor gasoline, ultra-low-sulfur diesel fuel, and jet fuel are the primary transportation fuels, supplemented by biofuels and natural gas. Motor gasoline consumption drops by approximately 1.6 million barrels per day from 2011 to 2040 in the Reference case, while diesel fuel consumption increases from 3.5 million barrels per day in 2011 to 4.3 million in 2040, primarily for use in heavy-duty vehicles. At the same time, natural gas use in heavy-duty vehicles displaces 0.7 million barrels per day of petroleum-based motor fuel in 2040, most of which is diesel.

An increase in consumption of biodiesel and next-generation biofuels [136], totaling about 0.4 million barrels per day from 2011 to 2040, is attributable to the EISA2007 RFS mandates. The relative competitiveness of CTL and GTL fuels improves over the projection period as petroleum prices rise. In 2040, CTL and GTL together supply 0.3 million barrels per day of nonpetroleum liquids. Both ethanol blending into gasoline and E85 consumption are essentially flat from 2011 through 2040, as a result of declining gasoline consumption and limited penetration of FFVs.

Crude oil leads initial growth in liquids supply, next-generation liquids grow after 2020


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In the AEO2013 Reference case, total production of petroleum and other liquids grows rapidly in the first decade and then slows in the later years before 2040 (Figure 94). Liquids production increases from 10.4 million barrels per day in 2011 to 13.1 million barrels per day in 2019 primarily as a result of growth in onshore production of crude oil and NGL from tight oil formations (including shale plays).

After 2019, total U.S. production of petroleum and other liquids declines, to 12.0 million barrels per day in 2040, as crude oil production from tight oil plays levels off when less-productive or less-profitable areas are developed. The crude oil share of total domestic liquids production declines to 51 percent in 2040 from a peak of 59 percent in 2016. NGL production also declines, to 2.9 million barrels per day in 2040 from a peak of 3.2 million barrels per day in 2024.

Domestic ethanol production remains relatively flat throughout the projection, as consumption of motor gasoline decreases and the penetration of ethanol in the gasoline pool is slowed by the limited availability of FFVs and retrofitted filling stations. Total biofuel production increases by 0.4 million barrels per day in the projection, as drop-in fuels from biomass enter the market. Other emerging technologies capable of producing liquids—such as xTL [137], which includes CTL and GTL technologies—also become economical as more plants are built. In 2040, liquids production from xTL plants totals 0.3 million barrels per day. Investment in xTL technologies is slowed somewhat by high capital costs and the risk that xTL liquids production will not remain price-competitive with crude oil.

U.S. oil production rates depend on resource availability and advances in technology


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The outlook for domestic crude oil production depends on the production profiles of individual wells over time, the costs of drilling and operating those wells, and the revenues they generate (Figure 95). Every year, EIA reestimates initial production rates and production decline curves, which determine EUR per well and total technically recoverable resources. The underlying resource for the AEO2013 Reference case is uncertain, particularly as exploration and development of tight oil continue to move into areas with little or no production history. Because many wells drilled in tight formations or shale formations using the latest technologies have less than two years of production history, the impacts of recent technology advances on the estimate of future recovery cannot be fully ascertained.

In the High Oil and Gas Resource case, domestic crude oil production continues to increase through the projection period, to more than 10 million barrels per day in 2040. This case includes: (1) higher estimates of onshore lower 48 tight oil, tight gas, and shale gas resources than in the Reference case, as a result of higher estimated ultimate recovery per well and closer well spacing as additional layers of low-permeability zones are identified and developed; (2) tight oil development in Alaska; and (3) higher estimates of offshore resources in Alaska and the lower 48 states, resulting in more and earlier development of those resources than in the Reference case.

The Low Oil and Gas Resource case considers the impacts of lower estimates of tight oil, tight gas, and shale gas resources than in the Reference case. These two alternative cases provide a framework for examining the impacts of higher and lower domestic supply on energy demand, imports, and prices.

Lower 48 onshore tight oil development spurs increase in U.S. crude oil production


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U.S. crude oil production rises through 2016 in the AEO2013 Reference case, before leveling off at about 7.5 million barrels per day from 2016 through 2020—approximately 1.8 million barrels per day above 2011 volumes (Figure 96). Growth in lower 48 onshore crude oil production results primarily from continued development of tight oil resources, mostly in the Bakken, Eagle Ford, and Permian Basin formations. Tight oil production reaches 2.8 million barrels per day in 2020 and then declines to about 2.0 million barrels per day in 2040, still higher than 2011 levels, as high-productivity sweet spots are depleted. There is uncertainty about the expected peak level of tight oil production, because ongoing exploration, appraisal, and development programs expand operators' knowledge about producing reservoirs and could result in the identification of additional tight oil resources.

Crude oil production using carbon dioxide-enhanced oil recovery (CO2-EOR) increases appreciably after about 2020, when oil prices rise as output from the more profitable tight oil deposits begins declining, and affordable anthropogenic sources of carbon dioxide (CO2) become available. Production plateaus at about 650,000 barrels per day from 2034 to 2040, when production is limited by reservoir quality and CO2 availability. From 2012 through 2040, cumulative crude oil production from CO2-EOR projects is 4.7 billion barrels.

Lower 48 offshore oil production varies between 1.4 and 1.8 million barrels per day over the projection period. Toward the end of the projection the pace of exploration and production activity quickens, and new large development projects, associated predominantly with discoveries in the deepwater and ultra-deepwater portions of the Gulf of Mexico, are brought on stream. New offshore oil production in the Alaska North Slope areas partially offsets the decline in production from North Slope onshore fields.

Tight oil formations account for a significant portion of total U.S. production


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The term tight oil does not have a specific technical, scientific, or geologic definition. Tight oil is an industry convention that generally refers to oil produced from very-low-permeability [138] shale, sandstone, and carbonate formations. Some of these geologic formations have been producing low volumes of oil for many decades in limited portions of the formation.

In the AEO2013 Reference Case, about 25.3 billion barrels of tight oil are produced cumulatively from 2012 through 2040. The Bakken-Three Forks formations contribute 32 percent of this production, while the Eagle Ford and Permian Basin formations respectively account for 24 and 22 percent of the cumulative tight oil production. The remaining 22 percent of cumulative tight oil production comes from other formations, including but not limited to the Austin Chalk, Niobrara, Monterey, and Woodford formations. Permian Basin tight oil production comes primarily from the Spraberry, Wolfcamp, and Avalon/Bone Spring formations, which are listed here relative to their contribution to cumulative production.

After 2021, tight oil production declines in the AEO2013 Reference case (Figure 97), as the depleted wells located in high-productivity areas are replaced by lower-productivity wells located elsewhere in the formations. In 2040, tight oil production is 2.0 million barrels per day, about 33 percent of total U.S. oil production. Because tight oil wells exhibit high initial production rates followed by slowly declining production rates in later years, production declines rather slowly at the end of the projection period.

Tight oil development is still at an early stage, and the outlook is highly uncertain. Alternative cases, including ones in which tight oil production is significantly above the Reference case projection, are examined in the "Issues in focus" section of this report (see "Petroleum import dependence in a range of cases").

Domestic production of tight oil leads to lower imports of light sweet crude oil


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API gravity is a measure of the specific gravity, or relative density, of a liquid, as defined by the American Petroleum Institute (API). It is expressed in degrees, where a higher number indicates lower density. Refineries generally process a mix of crude oils with a range of API gravities in order to optimize refinery operations. Over the past 15 years, the API gravity of crude oil processed in U.S. refineries has averaged between 30 and 31 degrees. As U.S. refiners run more domestic light crude produced from tight formations, they need less imported light oil crude to maintain an optimal API gravity. With increasing U.S. production of light crude oil in the Reference case, the average API gravity of crude oil imports declines (Figure 98).

In the AEO2013 Reference case, the trend toward increasing imports of heavier crude oils continues through 2035 before stabilizing [139]. The increase in demand for diesel fuel in the projection, from 3.5 to 4.3 million barrels per day, leads to an increase in distillate and gas oil hydrocracking capacity (which increases diesel production capability) from 1.6 to 3.0 million barrels per day from 2011 to 2040.

The large increase in domestic production of light crude oil and the increase in imports of heavier crude oils have prompted significant investments in crude midstream infrastructure, including pipelines that will bring higher quantities of light sweet crudes to petroleum refineries along the U.S. Gulf Coast. In addition, significant investments are being made to move crude oil to refineries by rail. The Reference case assumes that sufficient infrastructure investments will be made through 2040 to move both light and heavy crude oils.

Increasing U.S. supply results in decreasing net imports of petroleum and other liquids


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The net import share of U.S. petroleum and other liquids consumption (including crude oil, petroleum liquids, and liquids derived from nonpetroleum sources) grew steadily from the mid-1980s to 2005 but has fallen in every year since then. In the AEO2013 Reference and High Oil Price cases, U.S. imports of petroleum and other liquids decline through 2020, while still providing approximately one-third of total U.S. supply. As a result of increased production of domestic petroleum, primarily from tight oil formations, and a moderation of demand growth with tightening fuel efficiency standards, the import share of total supply declines. Domestic production of crude oil from tight oil formations, primarily from the Williston, Western Gulf, and Permian basins, increases by about 1.5 million barrels per day from 2011 to 2016 in both the Reference and High Oil Price cases.

The net import share of U.S. petroleum and other liquids consumption, which fell from 60 percent in 2005 to 45 percent in 2011, continues to decline in the Reference case, with the net import share falling to 34 percent in 2019 before increasing to 37 percent in 2040 (Figure 99). In the High Oil Price case, the net import share falls to an even lower 27 percent in 2040. In the Low Oil Price case, the net import share remains relatively flat in the near term but rises to 51 percent in 2040, as domestic demand increases, and imports become less expensive than domestically produced crude oil.

As a result of increased domestic production and slow growth in consumption, the United States becomes a net exporter of petroleum products, with net exports in the Reference case increasing from 0.3 million barrels per day in 2011 to 0.7 million barrels per day in 2040. In the High Oil Price case, net exports of petroleum products increase to 1.2 million barrels per day in 2040.

U.S. consumption of cellulosic biofuels falls short of EISA2007 Renewable Fuels Standard target


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Biofuel consumption grows in the AEO2013 Reference case but falls well short of the EISA2007 RFS target [140] of 36 billion gallons ethanol equivalent in 2022 (Figure 100), largely because of a decline in gasoline consumption as a result of newly enacted CAFE standards and updated expectations for sales of vehicles capable of using E85. From 2011 to 2022, demand for motor gasoline ethanol blends (E10 and E15) falls from 8.7 million barrels to 8.1 million barrels per day.

Because the current and projected vehicle fleets are not equipped to use ethanol's increased octane relative to gasoline, they cannot offset its lower energy density. As a result, the wholesale price of ethanol does not exceed two-thirds of the wholesale gasoline price. This reflects the energy-equivalent value of ethanol and would be the equilibrium price in periods with significant market penetration of blends with high ethanol content, such as E85. The RFS program does not provide sufficient incentives to promote significant new ethanol capacity in this pricing environment. Also during the projection period, consumption of biomass-based diesel levels off in the Reference case after growing to meet the current RFS target of 1.9 billion gallons ethanol equivalent in 2013.

Ethanol consumption falls from 16.4 billion gallons in 2022 to 14.9 billion gallons in 2040 in the AEO2013 Reference case, as gasoline demand continues to drop and E85 consumption levels off. However, domestic consumption of drop-in cellulosic biofuels grows from 0.3 billion gallons to 9.0 billion gallons ethanol equivalent per year from 2011 to 2040, as rising oil prices lead to price increases for diesel fuel, heating oil, and jet fuel, while production costs for biofuel technologies fall.

Renewable Fuel Standard and California Low Carbon Fuel Standard boost the use of new fuels


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In response to the RFS implemented nationwide and the California Low Carbon Fuel Standard (LCFS), consumption of advanced biofuels increases in the AEO2013 Reference case (Figure 101). As defined in the RFS, the advanced renewable fuels category consists of fuels that achieve a 50-percent reduction in life-cycle GHG emissions (including indirect changes in land use). The advanced fuel category includes ethanol produced from sugar cane (but not from corn starch), biodiesel, renewable diesel, and cellulosic biofuels [141]. California uses a large fraction of the total advanced renewable fuel pool in the early years of the projection.

Under the California LCFS, each fuel is considered individually according to its carbon intensity relative to the LCFS target. In general, fuels that qualify as advanced renewable fuels under the RFS have low carbon intensities for the purposes of the California LCFS, but the reverse is not always true.

Starting about 2030, production of cellulosic drop-in biofuels ramps up in California and other states. Outside California, production and consumption of cellulosic biofuels increases rapidly enough to cause a decline in California's fraction of the total advanced biofuels market. Starting in about 2035, corn ethanol with low carbon intensity begins to displace imported sugar cane ethanol in California.

Efficiency standards shift consumption from motor gasoline to diesel fuel


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Based on NHTSA estimates, more stringent efficiency standards for LDVs will require new LDVs to average approximately 49 mpg in 2025, in addition to regulations requiring increased use of ethanol. The combination contributes to a decline in consumption of motor gasoline and an increase in consumption of diesel fuel and ethanol in the AEO2013 Reference case. Motor gasoline consumption falls despite an increase in VMT by LDVs over the projection period.

The decrease in gasoline consumption, combined with growth in diesel consumption, leads to a shift in refinery outputs and investments. Motor gasoline consumption and diesel fuel consumption trend in opposite directions in the Reference case: consumption of diesel fuel increases by approximately 0.8 million barrels per day from 2011 to 2040, while finished motor gasoline consumption falls by 1.6 million barrels per day (Figure 102). Although some smaller and less-integrated refineries begin to idle capacity as a result of higher costs, new refinery projects focus on shifting production from gasoline to distillate fuels to meet growing demand for diesel.

In the Reference case, as a result of refinery economics and slower growth in domestic demand, no new petroleum refinery capacity expansions are built during the projection period besides those already under construction. Further, approximately 200,000 barrels per day of capacity is retired, beginning in 2012. In addition to meeting domestic demand, refineries continue exporting finished products to international markets throughout the projection period. From 2014 to 2017 gross exports of finished products increase to more than 3.0 million barrels per day for the first time, and they remain near that level through 2040. Further, the United States, which became a net exporter of finished products in 2011, remains a net exporter through 2040 in the Reference case.

Shifts in demand for liquid fuels change petroleum refinery yields and crack spreads


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The transition to lower gasoline and higher diesel production has a significant effect on petroleum refinery operations. In the AEO2013 Reference case, the ratio of gasoline to diesel production at petroleum refineries declines from 2.3 in 2012 to 1.6 after 2035 (Figure 103). In response to the drop in gasoline demand, refinery utilization of fluid catalytic cracking (FCC) units drops from 83 percent in 2011 to about 62 percent in 2040. In contrast, with diesel production increasing, installed distillate and gas oil hydrocracking capacity grows from about 1.8 million barrels per day in 2012 to 3.0 million barrels per day in 2040. The increase in installed hydrocracking capacity implies a shifting of FCC feeds to hydrocrackers in order to maximize diesel production.

Refinery profitability is a function of crude input costs, processing costs, and market prices for the end products. Profitability often is estimated from the crack spread, which is the difference between the price of crude oil and the price of distilled products, typically gasoline and distillate fuel. The 3-2-1 crack spread estimates the profitability of processing 3 barrels of crude oil to produce 2 barrels of gasoline and 1 barrel of distillate. In the Reference case, the 3-2-1 crack spread (based on Brent) declines steadily from $17 per barrel (2011 dollars) in 2012 to about $5 per barrel in 2040. This represents a gross margin for the refinery, based on Brent crude prices and average gasoline and diesel prices in the United States. In the current environment, this gross margin would drop by the differential between the prices of Brent and Gulf Coast light crudes. To relate the gross margin to refinery profitability, operating costs for specific refineries would also have to be deducted. The decline in the 3-2-1 crack spread slows after 2016. As product demands shift, petroleum refineries may alter the ratio of gasoline to diesel production. A 5-3-2 crack spread would be more consistent with the 1.6 gasoline-to-diesel production ratio after 2035.

Endnotes for Market Trends: Oil/Liquids

136.Next-generation biofuels include pyrolysis oils, biomass-derived Fisher-Tropsch liquids, and renewable feedstocks used for on-site production of diesel and gasoline.
137.xTL refers to liquid fuels that are created from biomass, as in biomass-to-liquids (BTL); from natural gas, as in GTL; and from coal, as in CTL.
138. Permeability is a laboratory measurement of a rock's ability to transmit liquid and gaseous fluids through its pore spaces. High-permeability sandstones have many large and well-connected pore spaces that readily transmit fluids, while low-permeability shales have smaller and fewer interconnected pore spaces that retard fluid flow. Laboratory measurements of rock permeability are stated in terms of darcies or millidarcies.
139. One option for balancing the mix of crudes might be to allow the export of domestically produced light crude in exchange for heavier crudes. Crude exports and swaps, however, are currently permitted only in limited cases and require a license from the Department of Commerce.
140. U.S. Environmental Protection Agency, "EPA Finalizes 2012 Renewable Fuel Standards," EPA-420-F-11-044 (Washington, DC: December 2011), http://www.epa.gov/otaq/fuels/renewablefuels/documents/420f11044.pdf.
141. R. Schnepf and B.D. Yacobucci, Renewable Fuel Standard (RFS): Overview and Issues (Washington, DC: Congressional Research Service, January 23, 2012), http://www.fas.org/sgp/crs/misc/R40155.pdf.

Reference Case Tables
Table 1. Total Energy Supply, Disposition, and Price Summary XLS
Table 11. Liquid Fuels Supply and Disposition XLS
Table 12. Petroleum Product Prices XLS
Table 14. Oil and Gas Supply XLS
Table 18. Energy-Related Carbon Dioxide Emissions by Sector and Source - United States XLS
Table 18.1. Energy-Related Carbon Dioxide Emissions by Sector and Source - New England XLS
Table 18.2. Energy-Related Carbon Dioxide Emissions by Sector and Source - Middle Atlantic XLS
Table 18.3. Energy-Related Carbon Dioxide Emissions by Sector and Source - East North Central XLS
Table 18.4. Energy-Related Carbon Dioxide Emissions by Sector and Source - West North Central XLS
Table 18.5. Energy-Related Carbon Dioxide Emissions by Sector and Source - South Atlantic XLS
Table 18.6. Energy-Related Carbon Dioxide Emissions by Sector and Source - East South Central XLS
Table 18.7. Energy-Related Carbon Dioxide Emissions by Sector and Source - West South Central XLS
Table 18.8. Energy-Related Carbon Dioxide Emissions by Sector and Source - Mountain XLS
Table 18.9. Energy-Related Carbon Dioxide Emissions by Sector and Source - Pacific XLS
Table 21. International Liquids Supply and Disposition XLS
Table 60. Lower 48 Crude Oil Production and Wellhead Prices by Supply Region XLS
Table 62. Oil and Gas End-of-Year Reserves and Annual Reserve Additions XLS