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Annual Energy Outlook 2014

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

Changes AEO 2011Comparison with other projections

Only IHS Global Insight (IHSGI) produces a comprehensive energy projection with a time horizon similar to that of the Annual Energy Outlook 2013 (AEO2013). Other organizations, however, address one or more aspects of the U.S. energy market. The most recent projection from IHSGI, as well as others that concentrate on economic growth, international oil prices, energy consumption, electricity, natural gas, petroleum, and coal, are compared here with the AEO2013 Reference case.

1. Economic growth

The range of projected economic growth in the outlooks included in the comparison tends to be wider over the first 5 years of the projection than over a longer period, because the group of variables—such as population, productivity, and labor force growth—that influence long-run economic growth is smaller than the group of variables that affect projections of short-run growth. The average annual rate of growth of real gross domestic product (GDP) from 2011 to 2015 (in 2005 dollars) ranges from 2.2 percent to 2.9 percent (Table 8). From 2011 to 2025, the 14-year average annual growth rate ranges from 2.5 percent to 2.8 percent.

From 2011 to 2015, real GDP grows at a 2.5-percent average annual rate in the AEO2013 Reference case, lower than projected by the Congressional Budget Office (CBO), the Social Security Administration (SSA) (in The 2011 Annual Report of the Board of Trustees of the Federal Old-Age and Survivors Insurance and Federal Disability Insurance Trust Funds), Oxford Economic Group (OEG), and the Interindustry Forecasting Project at the University of Maryland (INFORUM) but higher than projected by Blue Chip Consensus (Blue Chip) and the Office of Management and Budget (OMB). The AEO2013 projection of GDP growth is similar to the average annual rate of 2.5 percent over the same period projected by IHSGI and by the International Energy Agency (IEA), in its November 2012 World Energy Outlook Current Policies Scenario.

The average annual GDP growth of 2.6 percent in the AEO2013 Reference case from 2011 to 2025 is at the mid-range of the outlooks, with OMB, CBO, and the SSA projecting the strongest recovery from the 2007-2009 recession. OMB and CBO project average annual GDP growth from 2011 to 2023 of 2.8 percent and 2.7 percent, respectively. The SSA and OEG project annual average growth of 2.7 percent from 2011 to 2025. IEA projects growth at a rate similar to that in the AEO2013 Reference case from 2011 to 2025—as do IHSGI and INFORUM—at 2.6 per year over the next 14 years. Blue Chip and ExxonMobil project growth at 2.5 percent, or 0.1 percentage point lower than in the AEO2013 Reference case.

There are few public or private projections of GDP growth for the United States that extend to 2040. The AEO2013 Reference case projects 2.5-percent average annual GDP growth from 2011 to 2040, consistent with trends in labor force and productivity growth. IHSGI and INFORUM also project GDP growth averaging 2.5 percent per year from 2011 to 2040. The SSA, ExxonMobil, and IEA project a lower rate of 2.4 percent per year, while the OEG and ICF International (ICF) project a higher rate of 2.6 percent per year from 2011 to 2040.

2. Oil prices

In AEO2013, oil prices are represented by spot prices for Brent crude. Prices rise in the Reference case from $111 per barrel in 2011 to about $117 per barrel in 2025 and $163 per barrel in 2040 (Table 9). The price rise starts slowly, then accelerates toward the end of the projection period. In the Annual Energy Outlook 2012 (AEO2012) Reference case, where oil prices were represented by the West Texas Intermediate (WTI) spot price, prices rose more sharply in the early years and more slowly at the end of the projection period. AEO2013 also presents the annual average WTI spot price of light, low-sulfur crude oil delivered in Cushing, Oklahoma, and includes the U.S. annual average refiners' acquisition cost (RAC) of imported crude oil, which is more representative of the average cost of all crude oils used by domestic refiners. In 2011, the WTI and Brent prices differed by $16 per barrel. In the AEO2013 Reference case, the gap closes to a difference of $2 per barrel in 2025, following resolution of transportation system constraints in the United States. In each of the other outlooks in the comparison, oil spot prices are based on either Brent or WTI prices, with the exception of IEA, which represents the international average of crude oil import prices.

Market volatility and different assumptions about the future of the world economy are reflected in the range of oil price projections for both the near and long term; however, most projections show oil prices rising over the entire projection period. The projections for 2025 range from $78 per barrel (WTI) to $137 per barrel (Brent) in 2025—a span of $59 per barrel—and from $81 per barrel (WTI) to $163 per barrel (Brent) in 2040—a span of $82 per barrel. The wide range underscores the uncertainty inherent in the projections. The range of the projections is encompassed in the range of the AEO2013 Low and High Oil Price cases, from $68 per barrel (WTI) to $173 per barrel (Brent) in 2025 and from $71 per barrel (WTI) to $213 per barrel (Brent) in 2035.

3. Total energy consumption

Four projections by other organizations—INFORUM, IHSGI, ExxonMobil, and IEA—include energy consumption by sector (Table 10). To allow comparison with the IHSGI projection, the AEO2013 Reference case was adjusted to remove coal-to-liquids (CTL) heat and power, natural gas-to-liquids heat and power, biofuels heat and co-products, and natural gas feedstock use. To allow comparison with the ExxonMobil projection, electricity consumption in each sector was removed from the AEO2013 Reference case. To allow comparison with the IEA projections, the AEO2013 Reference case projections for the residential and commercial sectors were combined to produce a buildings sector projection. The IEA projections have a base year of 2010, as opposed to 2011 in the other projections. The INFORUM and IEA projections extend only through 2035.

ExxonMobil includes a cost for carbon dioxide (CO2) emissions in their projection, which helps to explain the lower level of consumption in their outlook. Although the IEA's central case also includes a cost for CO2 emissions, its Current Policies Scenario (which assumes that no new policies are added to those in place in mid-2012) is used for comparison in this analysis, because it corresponds better with the assumptions in the AEO2013 Reference case. ExxonMobil and IEA show lower total energy consumption across all years in comparison with the AEO2013 Reference case. Total energy consumption is higher in all years of the IHSGI projection than in the AEO2013 Reference case but starts from a lower level in 2011.

The INFORUM projection of total energy consumption in 2035 is 2.4 quadrillion British thermal units (Btu) higher than the AEO2013 Reference case projection, with the transportation sector 2.4 quadrillion Btu higher, the buildings sector 1 quadrillion Btu higher, and the industrial sector 1 quadrillion Btu lower. For the transportation sector, the difference could be related to vehicle efficiency, as the INFORUM projection for motor gasoline consumption (2 quadrillion Btu lower than AEO2013) is comparable with the EIA projection in AEO2012, which did not include the efficiency standard for vehicle model years 2017 through 2025. Energy consumption growth in the INFORUM projection is weaker than projected in AEO2013 through 2020 but stronger after 2020.

IHSGI projects significantly higher electricity consumption for all sectors than in the AEO2013 Reference case, which helps to explain much of the difference in total energy consumption between the two projections. In the IHSGI projection, the electric power sector consumes 10.0 quadrillion Btu more energy in 2040 than in the AEO2013 Reference case. The greater use of electricity in the IHSGI projection, including 150 trillion Btu used in the transportation sector (more than double the amount in AEO2013), also results in higher electricity prices than in the AEO2013 Reference case.

Total energy consumption declines in the ExxonMobil projection, primarily as a result of the inclusion of a tax on CO2 emissions, which is not considered in the AEO2013 Reference case. Energy consumption in the transportation and industrial sectors declines from 2011 levels in the ExxonMobil projection, based on expected policy changes and technology improvements.

Total energy consumption in the IEA projection is higher in 2035 than in 2010 because of increased consumption in the buildings sector, where an increase of 3.7 quadrillion Btu includes 3.1 quadrillion Btu of additional electricity demand. Energy consumption in the transportation and industrial sectors declines from 2020 to 2030 in the IEA projection, by less than 1 quadrillion Btu in each sector. IEA projects little change in energy use for those two sectors from 2030 to 2035, with industrial energy consumption declining very slowly and transportation energy consumption increasing slightly. IEA projects total energy consumption that is higher than ExxonMobil’s projection in 2035, but considerably lower than in the AEO2013 Reference case for both 2030 and 2035.

4. Electricity

Table 11 compares summary results from the AEO2013 Reference case with projections from EVA, IHSGI, INFORUM, ICF, and the National Renewable Energy Laboratory (NREL). In 2025, total electricity sales range from a low of 4,095 billion kilowatthours (INFORUM) to a high of 4,712 billion kilowatthours (IHSGI) [145]. The AEO2013 Reference case projects 4,140 billion kilowatthours of total electricity sales in 2025, EVA projects 4,311 billion kilowatthours in 2025, and NREL projects 4,487 billion kilowatthours in 2026. In comparison with the other projections, IHSGI shows higher sales across all sectors in 2025, with the exception of the commercial sector (1,709 billion kilowatthours), where the EVA projection of 1,824 billion kilowatthours is 115 billion kilowatthours higher. The higher total in the commercial sector counterbalances EVA's lower projection of 736 billion kilowatthours for the industrial sector, compared with 1,186 billion kilowatthours in the AEO2013 Reference case, 1,246 billion kilowatthours in the IHSGI projection, and 1,033 billion kilowatthours in the INFORUM projection.

Total electricity sales in 2035 in the IHSGI projection (5,316 billion kilowatthours) are higher than in the others: 4,406 billion kilowatthours in the INFORUM projection, 4,421 billion kilowatthours in the AEO2013 Reference case, 4,824 billion kilowatthours (in 2036) in the NREL projection, and 4,923 billion kilowatthours in the EVA projection. EVA projects the highest level of electricity sales in both the residential and commercial sectors in 2035 but a lower level of industrial sales in comparison with the other projections. Electricity sales in the industrial sector in the IHSGI projection are 1,332 billion kilowatthours in 2035, as compared with 1,142 billion kilowatthours in the AEO2013 Reference case, 978 billion kilowatthours in the INFORUM projection, and only 515 billion kilowatthours in the EVA projection. Total electricity sales in 2040 are again led by the IHSGI projection, with 5,602 billion kilowatthours, followed by 5,238 billion kilowatthours in the EVA projection, 4,608 billion kilowatthours in the AEO2013 Reference case, and 4,940 billion kilowatthours in the NREL projection.

IHSGI, INFORUM, and the AEO2013 Reference case provide projections for average electricity prices by sector for 2025 and 2035. NREL provides a U.S. average electricity price projection for 2026 and 2036, but not by sector. IHSGI, NREL, and the AEO2013 Reference case provide projections for average electricity prices in 2040. Average electricity prices in the AEO2013 Reference case are 9.5 cents per kilowatthour in 2025, 10.1 cents per kilowatthour in 2035, and 10.8 cents per kilowatthour in 2040. Average electricity prices in the INFORUM projection are 10.0 cents per kilowatthour in 2025 and 10.5 cents per kilowatthour in 2035 [146]. IHSGI projects considerably higher average electricity prices than either the AEO2013 Reference case or INFORUM, at 11.2 cents per kilowatthour in 2025, 11.9 cents per kilowatthour in 2035, and 12.2 cents per kilowatthour in 2040. NREL projects overall average electricity prices of 10.4 cents per kilowatthour in 2026, 11.7 cents per kilowatthour in 2036, and 12.0 cents per kilowatthour in 2040 (the NREL prices were provided in 2009 dollars).

In all the projections, average electricity prices by sector follow patterns similar to changes in the weighted average electricity price across all sectors (including transportation services). The lowest prices by sector in 2025 are in the AEO2013 Reference case (11.6 cents per kilowatthour for the residential sector, 9.7 cents per kilowatthour for the commercial sector, and 6.5 cents per kilowatthour for the industrial sector). The highest average electricity prices by sector in 2025 are in the IHSGI projection (13.3 cents per kilowatthour for the residential sector, 11.6 cents per kilowatthour for the commercial sector, and 7.6 cents per kilowatthour for the industrial sector). The AEO2013 Reference case, IHSGI, and NREL reflect similar price patterns for 2035 (or 2036 for NREL) and 2040.

Total U.S. electricity generation plus imports in 2025 range from a low of 4,296 billion kilowatthours in the INFORUM projection to a high of 5,207 billion kilowatthours in the IHSGI projection. Within that range, the AEO2013 Reference case projects total generation of 4,612 billion kilowatthours. Coal continues to represent the largest share of generation in 2025 in the AEO2013 Reference case, which reports 1,727 billion kilowatthours from coal versus 1,252 billion kilowatthours from natural gas. By comparison, the natural gas share of total generation in the IHSGI projection in 2025 surpasses generation from coal by 126 billion kilowatthours, with 1,732 billion kilowatthours of generation from natural gas and 1,605 billion kilowatthours from coal. IHSGI projects 1,646 billion kilowatthours of electricity generation from both coal and natural gas in 2023, with the natural gas total exceeding that for coal in 2024 and beyond as a result of the assumed implementation of a carbon tax in the IHSGI projection. Conversely, coal continues to represent the largest share of generation in the AEO2013 Reference case in 2035—1,807 billion kilowatthours as compared with 1,519 billion kilowatthours from natural gas. The AEO2013 Reference case is based on current regulations and policies and does not assume a carbon tax. In 2035, the natural gas share of total generation in the IHSGI projection exceeds generation from coal by 808 billion kilowatthours. In the AEO2013 Reference case, coal continues to represent the largest share of generation in 2040 at 1,829 billion kilowatthours, compared with 1,582 billion kilowatthours from natural gas. In comparison, the natural gas share of total generation in 2040 in the IHSGI projection widens its lead over coal by 1,088 billion kilowatthours. In the EVA projection, coal is outpaced by natural gas as a share of total generation in 2040, with 2,330 billion kilowatthours from natural gas and 1,740 billion kilowatthours from coal [147].

Projections for electricity generation from U.S. nuclear power plants in 2025 range from a low of 794 billion kilowatthours (NREL, in 2026) to a high of 923 billion kilowatthours in the IHSGI projection. NREL projects a steady decline in nuclear generation, from 794 billion kilowatthours in 2025 to 510 billion kilowatthours in 2036 and 442 billion kilowatthours in 2040, due to significant plant retirements. For 2035, the AEO2013 Reference case projects a drop in nuclear generation from the 2025 level, to 875 billion kilowatthours, as a result of capacity retirements. In contrast, nuclear generation increases to 953 billion kilowatthours in 2035 in the IHSGI projection. The AEO2013 Reference case shows nuclear generation rebounding to 903 billion kilowatthours in 2040, as compared with 991 billion kilowatthours in the IHSGI projection.

Total generating capacity by fuel in 2025 (including combined heat and power [CHP]) is fairly similar across the projections, ranging from a low of 1,098 gigawatts in the AEO2013 Reference case to a high of 1,237 gigawatts in the IHSGI projection. IHSGI projects slightly more growth in total generating capacity due to what appears to be a much higher demand projection. Natural gas- and oil-fired capacity combined is projected to total 555 gigawatts in 2025 in the IHSGI projection, compared with 500 gigawatts in the AEO2013 Reference case and a maximum of 568 gigawatts in the EVA projection. In all the projections, the hydroelectric/other category includes generation from both hydroelectric and nonhydroelectric renewable resources. In all the projections, hydroelectric capacity remains essentially unchanged, with almost all growth attributable to nonhydroelectric renewable resources. Hydroelectric/other capacity is the highest in 2025 in the IHSGI outlook at 289 gigawatts, compared with 257 gigawatts in the NREL projection (for 2026), 234 gigawatts in the ICF projection, 210 gigawatts in the EVA projection, and 208 gigawatts in the AEO2013 Reference case.

Both the IHSGI and NREL projections reflect lower levels of coal-fired generating capacity in 2040, with 251 gigawatts projected by IHSGI and 224 gigawatts by NREL. In comparison, natural gas- and oil-fired capacity (again dominated by natural gas-fired generating capacity) and hydroelectric/other capacity (dominated by nonhydroeletric renewable capacity) are projected to increase from 2025 levels. IHSGI projects 722 gigawatts of natural gas- and oil-fired capacity and 396 gigawatts of hydroelectric/other capacity in 2040. NREL projects 691 gigawatts of natural gas- and oil-fired capacity and 322 gigawatts of hydroelectric/other capacity in 2040. The AEO2013 Reference case projects 632 gigawatts of natural gas- and oil-fired capacity and 270 gigawatts of hydroelectric/other capacity in 2040.

Cumulative capacity retirements from 2011 through 2025 range from 151 gigawatts in the EVA projection to 82 gigawatts in the AEO2013 Reference case. The majority of the retirements in the IHSGI, ICF, and AEO2013 Reference case projections from 2011 to 2025 are attributed to coal-fired capacity. In the EVA and ICF outlooks, 73 gigawatts of coal-fired capacity is retired from 2011 to 2025. Over the same period, 46 gigawatts of coal-fired capacity is retired in the IHSGI outlook and 49 gigawatts in the AEO2013 Reference case. The NREL projection assumes 33 gigawatts of coal-fired capacity retirements from 2011 to 2026. EVA projects 73 gigawatts of oil- and natural gas-fired capacity retirements between 2011 and 2025, as compared with the ICF, AEO2013 Reference case, and IHSGI projections, which range between 29 gigawatts and 36 gigawatts over the same period. NREL projects 69 gigawatts of oil- and natural gas-fired retirements through 2026. With the exception of EVA and ICF, all the capacity retirements greater than 1 gigawatt between 2011 and 2025 in the outlooks are attributed to coal, oil, and natural gas capacity. EVA and ICF both project 3 gigawatts of nuclear retirements by 2025, while EVA projects 2 gigawatts of hydroelectric/other capacity retirements for the same period.

Cumulative capacity retirements through 2035 range from a high of 161 gigawatts in the EVA projection to a low of 100 gigawatts in the AEO2013 Reference case. Coal-fired capacity represents a large portion of the cumulative retirements from 2011 to 2035, with ICF projecting 82 gigawatts, EVA 77 gigawatts, IHSGI 68 gigawatts, and the AEO2013 Reference case 49 gigawatts. The AEO2013 Reference case projects no retirements of coal-fired capacity from 2025 to 2035. Over the same period, EVA projects only 4 gigawatts, ICF 9 gigawatts, and IHSGI 22 gigawatts. Cumulative retirements of oil- and natural gas-fired capacity from 2011 to 2035 total 44 gigawatts in the AEO2013 Reference case and 74 gigawatts in the EVA projection. NREL projects cumulative totals of 70 gigawatts and 138 gigawatts of retirements for coal-fired capacity and for oil- and natural gas-fired capacity, respectively, from 2011 to 2036. EVA and the AEO2013 Reference case project cumulative nuclear capacity retirements of 9 gigawatts and 6 gigawatts, respectively, from 2011 to 2035, and IHSGI projects 21 gigawatts of cumulative nuclear retirements over the same period. NREL projects 35 gigawatts of cumulative nuclear retirements from 2011 to 2036.

5. Natural gas

Projections for natural gas consumption, production, imports, and prices differ significantly among the outlooks compared in Table 12. The variations result, in large part, from differences in underlying assumptions. For example, the AEO2013 Reference case assumes that current laws and regulations are unchanged through the projection period, whereas some of the other projections include assumptions about anticipated policy developments over the next 25 years. In particular, the AEO2013 Reference case does not incorporate any future changes in policy directed at carbon emissions or other environmental issues, whereas ExxonMobil and some of the other outlooks include explicit assumptions about policies aimed at reducing carbon emissions.

IHSGI and ICF project large increases in natural gas production and consumption over the projection period. IHSGI projects that, as production increases, prices will remain low and U.S. consumers, particularly in the electric power sector, will continue to benefit from an abundance of relatively inexpensive natural gas. In contrast, ICF projects that prices will rise at a more rapid rate than in the IHSGI projection. EVA projects growth in natural gas production, but at lower rates than IHSGI and ICF. Both EVA and ExxonMobil also project strong growth in natural gas consumption in the electric power sector through 2035. EVA differs from the others, however, by projecting strong growth in natural gas consumption despite a rise in natural gas prices to $8.00 per million Btu in 2035. Timing of the growth in consumption is somewhat different between the ExxonMobil projection and the other outlooks. ExxonMobil expects consumption to increase only through 2025, after which it remains relatively flat. The AEO2013 Reference case projects a smaller increase in natural gas consumption for electric power generation than in the other outlooks, with additional natural gas production allowing for a sharp increase in net exports, particularly as liquefied natural gas (LNG). The INFORUM projection shows a smaller rise in production and consumption of natural gas than in any of the other projections.

Production

All the outlooks shown in Table 12 project increases in natural gas production from the 2011 production level of 23.0 trillion cubic feet. IHSGI projects the largest increase, to 36.1 trillion cubic feet in 2035—13.1 trillion cubic feet or 57 percent more than the 2011 levels—with most of the increase coming in the near term (9.3 trillion cubic feet from 2011 to 2025). An additional 1.5 trillion cubic feet of natural gas production is added from 2035 to 2040. In the ICF projection, natural gas production grows by 12.5 trillion cubic feet over the period from 2011, to 35.5 trillion cubic feet in 2035. More than one-half of the increase (6.5 trillion cubic feet) occurs before 2020. INFORUM projects the smallest increase in natural gas production, at only 4.9 trillion cubic feet from 2011 to the 2035 total of 27.9 trillion cubic feet.

The AEO2013 Reference case and EVA project more modest growth in natural gas production. In the AEO2013 Reference case and EVA projections, natural gas production grows to 31.4 trillion cubic feet in 2035, an increase of 8.4 trillion cubic feet from 2011 levels. The AEO2013 Reference case and EVA projections show slower growth in natural gas production from 2011 to 2025, at 5.6 trillion cubic feet and 6.9 trillion cubic feet, respectively. Although the AEO2013 Reference case shows the least aggressive near-term growth in natural gas production, it shows the strongest growth from 2025 to 2035 among the projections, with another increase of 1.8 trillion cubic feet from 2035 to 2040.

Net imports/exports

Differences among the projections for natural gas production generally coincide with differences in total natural gas consumption or net imports/exports. EVA projects positive growth in net imports throughout the projection period, driven by strong growth in natural gas consumption. Although the EVA projection shows significant growth in pipeline imports, it shows no growth in net LNG exports. In contrast, the IHSGI, ICF, and AEO2013 Reference case projections show net exports of natural gas starting on or before 2020. The AEO2013 Reference case projects the largest increase in net exports of natural gas, with net pipeline exports increasing alongside steady growth in net LNG exports. In the ICF projection, the United States becomes a net exporter of natural gas by 2020 but remains a net importer of pipeline through 2035. Combined net exports of natural gas grow to 0.7 trillion cubic feet in 2035 in the ICF projection, with all the growth accounted for by LNG exports, which increase by 1.5 trillion cubic feet from 2011 to 2035. IHSGI projects a U.S. shift from net importer to net exporter of natural gas after 2017, with net exports declining after 2024.

Consumption

All the projections show total natural gas consumption growing throughout the projection periods, and most of them expect the largest increases in the electric power sector. IHSGI projects the greatest growth in natural gas consumption for electric power generation, driven by relatively low natural gas prices, followed by ExxonMobil and EVA, with somewhat higher projections for natural gas prices. The ICF projection shows less growth in natural gas consumption for electric power generation, despite lower natural gas prices, than in the EVA projection. In the AEO2013 Reference case and INFORUM projections, natural gas consumption for electric power generation is somewhat less than in the other outlooks. Some of that variation may be the result of differences in assumptions about potential fees on carbon emissions. For example, the ExxonMobil outlook assumes a tax on carbon emissions, whereas the AEO2013 Reference case does not.

Projections for natural gas consumption in the residential and commercial sectors are similar in the outlooks, with expected levels of natural gas use remaining relatively stable over time. The AEO2013 Reference case projects the lowest level of residential and commercial natural gas consumption, largely as a result of increases in equipment efficiencies, with projected consumption in those sectors falling by 0.1 trillion cubic feet from 2011 to 2040, to a level slightly below those projected by IHSGI and ICF. ExxonMobil projects a significant one-time decrease of 1.0 trillion cubic feet from 2020 to 2025.

The largest difference among the outlooks for natural gas consumption is in the industrial sector, where definitional differences can make accurate comparisons difficult. ExxonMobil and the AEO2013 Reference case both project increases in natural gas consumption in the industrial sector from 2011 to 2040 that are greater than 1.0 trillion cubic feet, with most of the growth in the AEO2013 Reference case occurring from 2015 to 2020. ICF projects the largest increase in industrial natural gas consumption, at 2.2 trillion cubic feet from 2011 to 2035, followed by EVA's projection of 1.8 trillion cubic feet over the same period. Although ExxonMobil projects a significant one-time decrease in industrial natural gas consumption—1.0 trillion cubic feet from 2025 to 2030—its projected level of industrial consumption in 2025, at 9.0 trillion cubic feet, is higher than in any of the other projections. Despite ExxonMobil's projected decrease in industrial natural gas consumption from 2025 to 2030, its projection for 2030 (8.0 trillion cubic feet) is second only to EVA's projection of 8.4 trillion cubic feet. IHSGI and INFORUM show modest increases in industrial natural gas consumption from their 2011 levels, to 6.9 trillion cubic feet in 2035 in both outlooks. Projected industrial natural gas consumption declines in the IHSGI projection after 2035, to 6.7 trillion cubic feet in 2040.

Prices

Only four of the outlooks included in Table 12 provide projections for Henry Hub natural gas spot prices. EVA shows the highest Henry Hub prices in 2035 and IHSGI the lowest. In the IHSGI projection, Henry Hub prices remain low through 2035, when they reach $4.98 per million Btu, compared with $3.98 per million Btu in 2011. Natural gas prices to the electric power sector rise from $4.87 per thousand cubic feet in 2011 to $5.47 per thousand cubic feet in 2035 in the IHSGI projection. The low Henry Hub prices in the IHSGI projection are supported by an abundant supply of relatively inexpensive natural gas, with only a small increase in net exports in comparison with the increase in the AEO2013 Reference case. EVA, in contrast, shows the Henry Hub price rising to a much higher level of $8.00 per million Btu in 2035, apparently as a result of stronger growth in natural gas consumption, particularly for electric power generation, and a lower level of natural gas exports. Indeed, the EVA outlook shows the U.S. remaining a net importer of natural gas through 2035.

Henry Hub natural gas prices in the ICF and AEO2013 Reference case projections for 2035—at $6.21 per million Btu and $6.32 per million Btu, respectively—fall within the price range bounded by IHSGI and EVA. In the AEO2013 Reference case, commercial, electric power, and industrial natural gas prices all rise by between $2 and $3 per thousand cubic feet from 2011 to 2035, while residential prices rise by $3.88 per thousand cubic feet over the same period. The residential sector is also the only sector for which the AEO2013 Reference case projects a decline in natural gas consumption to below 2011 levels in 2035. ICF projects a much smaller increase in delivered natural gas prices for the commercial, industrial, and electric power sectors, with prices rising to more than $2 per thousand cubic feet above 2011 levels by 2035 only in the electric power sector. With smaller price increases, ICF projects a much larger increase for natural gas consumption in the electric power and industrial sectors from 2011 to 2035 than in the AEO2013 Reference case.

6. Liquid fuels

In the AEO2013 Reference case, the Brent crude oil spot price (in 2011 dollars) increases to $117 per barrel in 2025, $145 per barrel in 2035, and $163 per barrel in 2040 (Table 13). Prices are higher earlier in the INFORUM and IEA projections but lower in the later years, ranging from $136 per barrel in 2025 to $150 per barrel in 2035. In the AEO2013 Reference case, the U.S. imported RAC for crude oil (in 2011 dollars) increases to $113 per barrel in 2025, $139 per barrel in 2035, and $155 per barrel in 2040. RAC prices in the INFORUM projection are higher, ranging from $126 per barrel in 2025 to $138 per barrel in 2035. EVA and ExxonMobil did not provide projections for Brent or RAC crude oil prices.

In the AEO2013 Reference case, domestic crude oil production increases from about 5.7 million barrels per day in 2011 to 6.8 million barrels per day in 2025, then declines to about 6.3 million barrels per day in 2035 and 6.1 million barrels per day in 2040. Overall, projected crude oil production in 2035 is more than 10 percent higher than the 2011 total. The INFORUM projection shows a considerable increase in crude oil production, to 9.5 million barrels per day in 2035. Similarly, the EVA projection shows crude oil production increasing consistently to 8.5 million barrels per day in 2035. The IHSGI projection is closer to the AEO2013 Reference case, with domestic crude oil production reaching 6.4 million barrels per day in 2035. Similar to the AEO2013 Reference case, all the outlooks assume continued significant growth in crude oil production from non-OPEC countries, specifically in North America from tight oil formations.

Total net imports of crude oil and other liquids in the AEO2013 Reference case increase from 8.6 million barrels per day in 2011 to 7.0 million barrels per day in 2025 and remain at that level through the remainder of the projection. The INFORUM projection is similar, at 7.1 million barrels per day in 2025 and 7.4 million barrels per day in 2035. In the IHSGI projection, however, total net imports fall dramatically, to approximately 4.7 million barrels per day in 2035 and around 4.1 million in 2040. IHSGI projects efficiency improvements that would decrease total U.S. demand for liquids and lessen the need for imports.

Biofuel production on a crude oil equivalent basis increases to about 1.1 million barrels per day in both 2025 and in 2035 and to more than 1.3 million barrels per day in 2040 in the AEO2013 Reference case. IHSGI projects biofuel production of 1.2 million barrels per day in 2025. The IHSGI projection assumes that technology hurdles and economic factors limit the growth of U.S. biofuel production to only a marginal share of total energy supply. IHSGI projects 1.4 million barrels per day of biofuel production in 2035 and a similar level in 2040. The EVA, INFORUM, IEA, and ExxonMobil outlooks do not include biofuels production.

Prices for both diesel fuel and gasoline increase through 2040 in the AEO2013 Reference case projection, with diesel prices higher than gasoline prices. INFORUM projects increasing gasoline prices and decreasing diesel prices, so that in 2035 the gasoline price is higher than the diesel price. IHSGI projects falling prices for both gasoline and diesel fuel, with 2040 prices for gasoline more than $1.00 per gallon lower and for diesel fuel prices $2.00 per gallon lower than projected in the AEO2013 Reference case. The EVA, IEA, and ExxonMobil projections do not include delivered fuel prices.

7. Coal

The AEO2013 Reference case projects the highest levels of total coal production and prices in comparison with other coal outlooks available from EVA, ICF, IHSGI, INFORUM, the IEA’s World Energy Outlook, and ExxonMobil. Total consumption in AEO2013 is also higher than in the other outlooks, except for INFORUM and ICF, whose consumption projections for 2035 are 2 percent and 5 percent higher, respectively, than projected in the AEO2013 Reference case (Table 14).

The detailed assumptions that underlie the various projections are not generally available, although there are some important known differences that contribute to the differences among the outlooks. For instance, EVA and ICF assume the implementation of new regulations for cooling water intake and coal combustion residuals; ExxonMobil, which has the lowest projection of coal consumption, assumes a carbon tax; and ICF also includes a carbon cap-and-trade program beginning in 2023. Because those policies are not current law, the AEO2013 Reference case excludes them, which contributes to the lower coal consumption projections in many of the other outlooks relative to AEO2013. Variation among the assumptions about growth in energy demand and other fuel prices, particularly for natural gas, also contribute to the differences.

Although the AEO2013 projections for total coal consumption are actually somewhat lower than the ICF and INFORUM projections, the other outlooks offer more pessimistic projections. ExxonMobil is the most pessimistic, with coal consumption 33 percent and 55 percent lower in 2025 and 2030, respectively, than in the AEO2013 Reference case. Coal consumption in 2025 is 17 percent (174 million tons) less in the EVA outlook than in the AEO2013 Reference case and 8 percent less in the IHSGI outlook. The INFORUM and ICF outlooks for total coal consumption in 2035 are between 21 million tons (2 percent) and 55 million tons (5 percent) higher, respectively, than in the AEO2013 Reference case.

The electricity sector is the predominant consumer of coal and the primary source of differences among the projections, due to their differing assumptions about regulations and the economics of coal versus other fuel choices over time. Although EVA shows a greater reduction in coal use for electricity generation in 2025 than does IHSGI, for 2035 the two projections are similar. After 2035, EVA shows a continued small increase in coal use for electricity generation, whereas it continues to fall in the IHSGI projection and in 2040 is 37 million tons less than projected by EVA. The ICF outlook for coal consumption in electricity generation is similar to the AEO2013 projection through 2025 but then declines gradually through 2035. IEA projects a level of coal use for electricity generation in 2035 that is most similar to the AEO2013 Reference case.

In all the projections, coal consumption in the end-use sectors is low in comparison with the electric power sector; however, there are several notable differences among the outlooks. Most notably, the ICF outlook shows increasing coal use in the other sectors that offsets declining consumption for electric power. ICF is the only projection that shows an increase in coal use in the industrial and buildings sectors. AEO2013 shows the next highest level of coal consumption in the industrial and buildings sectors, but it is still less than half of ICF's projection for industrial and buildings consumption in 2035. Both IHSGI and EVA show significant declines in coal use in those sectors over the projection period. In 2040, coal use in the buildings and industrial sectors in the IHSGI and EVA projections is equal to only 39 percent and 60 percent, respectively, of the coal use in those sectors in AEO2013. In addition, only AEO2013 and ICF project coal use for liquids production. Some of the gains in the two sectors are offset in the ICF outlook by lower consumption of coal at coke plants, which falls from 21 million tons in 2011 to 12 million tons in 2035. In the other outlooks, coal use at coke plants is similar to the levels in the AEO2013 Reference case, with modest declines through the end of their projections.

Differences among the projections for U.S. domestic coal production fall within a smaller range than the projections for coal consumption, depending in part on each outlook's projections for net exports. For example, coal production in the EVA and IHSGI projections is buoyed by relatively high export levels after 2011, with total coal production falling by 13 percent and 5 percent, respectively, from 2011 to 2035, compared with a 16-percent decline in total coal consumption in both projections. The ICF and INFORUM outlooks, which project 11-percent and 8-percent increases in total coal consumption through 2035, respectively, show changes in total coal production of 4 percent and no growth, respectively, as a result of significantly lower net export levels.

The projections for coal exports in the AEO2013 Reference case generally fall between the EVA and IHSGI projections. INFORUM's projection for coal exports is the lowest among the outlooks but similar to ICF's projection for 2035. The composition of EVA's exports also differs from that in AEO2013, in that EVA expects most exports to be thermal coal, whereas most exports in the early years of the AEO2013 Reference case are coking coal. In 2025, coking coal accounts for 57 percent of total coal exports in the AEO2013 Reference case, compared with 34 percent in the EVA projection. In 2040, however, the coking coal share of exports in the AEO2013 projection declines to 44 percent, compared with 32 percent in the EVA projection. In comparison, coking coal accounts for 74 percent of total coal exports in 2035 in the ICF projection.

In the EVA and IHSGI projections, coal imports remain low and relatively flat. AEO2013 also shows low levels of imports initially, but they grow to 36 million tons in 2040 from 5 million tons in 2025. For 2035, the ICF outlook implies 136 million tons of coal imports (calculated by subtracting production from the sum of consumption and exports), which is higher than all the others shown in the comparison table. Coal imports remain above 20 million tons in the INFORUM projections, and as in the ICF and AEO2013 projections, they increase over time, doubling in 2035 from the 2025 level.

Only AEO2013, ICF, and INFORUM provide projections of minemouth coal prices. In the ICF projections, minemouth prices in 2025 are 20 percent below those in 2011 (on a dollar-per-ton basis), and they decline only slightly through 2035. INFORUM projects coal minemouth prices that are very similar to the AEO2013 prices (on a dollar-per-million Btu basis).

The ICF outlook shows the lowest price for coal delivered to the electricity sector in both 2025 and 2035, with the real coal price lower than in 2011. INFORUM's prices for coal delivered to electricity generators (on a dollar-per-ton basis) are similar. IHSGI's delivered coal prices to electricity generators are significantly lower than those in the AEO2013 Reference case and remain close to the 2011 price over the entire projection period. As a result, the IHSGI delivered coal price to electricity generators is 9 percent lower in 2025 and 22 percent lower in 2040, on a dollar-per-ton basis, than projected in the AEO2013 Reference case.

Endnotes

145. EIA summed the sector-level sales from the INFORUM and EVA projections to develop a total electricity sales value for comparison purposes.
146. EIA estimated a weighted-average electricity price for INFORUM based on the sector-level prices and sales.
147. For purposes of comparison, generation from natural gas, turbine, and oil/gas steam capacity from EVA was combined, resulting in a total of 2,330 billion kilowatthours of generation from natural gas for 2040, as shown in Table 25.