‹ Analysis & Projections

Annual Energy Outlook 2011

Release Date: April 26, 2011   |  Next Early Release Date: January 23, 2012  |   Report Number: DOE/EIA-0383(2011)

Changes AEO 2011Comparison with other projections

Only IHS Global Insight (IHSGI) produces a comprehensive energy projection with a time horizon similar to that of Annual Energy Outlook2011 (AEO2011). 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 AEO2011 Reference case.

1. Economic growth

The range of projected economic growth tends to be wider for the earlier years of the projection period and then narrows in the long run, because the group of concepts—such as population, productivity, and labor force growth—that explain long-run growth trends is smaller than the group of variables that affect projections of short-run growth. From 2009 to 2011, projections for the average annual rate of growth of real gross domestic product (GDP) in the United States range from -0.1 percent to 3.0 percent (Table 12).

In the AEO2011 Reference case, real GDP grows at a 2.4-percent average annual rate over the 2009-2011 period, lower than projected by the Office of Management and Budget (OMB) and the Interindustry Forecasting Project at the University of Maryland (INFORUM); however, not all of those projections have been updated to take account of the faster pace of economic recovery that became evident late in 2010. The AEO2011 projection of GDP growth is slightly lower than the projections by IHSGI and higher than projection by the Bureau of Labor Statistics (BLS), although the BLS macroeconomic projections are made only every 2 years. In March 2010, the consensus Blue Chip projection was for 3.0-percent average annual growth in GDP from 2009 to 2011.

The range of GDP growth rates narrows over the period from 2011 to 2015, with projections ranging from 3.0 to 4.0 percent per year. The average annual GDP growth of 3.2 percent in the AEO2011 Reference case from 2011 to 2015 falls in the middle of the range, with the OMB projecting a stronger recovery from the recession. OMB projects average annual GDP growth of 4.0 percent from 2011 to 2015. INFORUM, IHSGI, and the International Energy Agency (IEA) all project growth rates that are below that in the AEO2011 Reference case.

There are few public or private projections of GDP growth for the United States that extend to 2035. The AEO2011 Reference case projects 2.7-percent average annual GDP growth from 2009 to 2035, consistent with trends in labor force and productivity growth. IHSGI projects GDP growth averaging 2.7 percent per year from 2009 to 2035, and INFORUM projects lower GDP growth of 2.5 percent over the same period. INFORUM also projects lower growth in productivity and labor force.

2. World oil prices

In the AEO2011 Reference case, world oil prices rise from $62 per barrel to approximately $95 per barrel in 2015 and $108 per barrel in 2020 (Table 13). From 2020 to 2035, prices increase slowly to $125 per barrel in 2035. This price trend is slightly lower than the trend shown in the AEO2010 Reference case.

Market volatility and differing assumptions about the future of the world economy are reflected in the range of price projections for both the short term and the long term; however, most projections show prices rising over the entire course of the projection period although slowing after 2025. The other projections range from $78 per barrel to $95 per barrel in 2015, a span of $17 per barrel; and from $78 per barrel to $135 per barrel in 2035, a span of $57 per barrel. The wide range underscores the uncertainty inherent in the projections. The range of the other projections is encompassed in the range of the AEO2011 Low and High Oil Price cases, from $55 per barrel to $146 per barrel in 2015 and from $50 per barrel to $200 per barrel in 2035.

World oil price measures are, by and large, comparable across projections. EIA reports the price of imported low-sulfur, light crude oil, approximately the same as the West Texas Intermediate (WTI) price widely cited in the trade press as a proxy for world oil prices. The only series that do not report projections in WTI terms are IEA's World Energy Outlook 2010, where prices are expressed as the IEA crude oil import price, and INFORUM, where prices are expressed as the average U.S. refiner acquisition cost of imported crude oil.

3. Total energy consumption

Three of the projections, IHSGI, INFORUM, and ExxonMobil, feature consumption by sector. However, to allow comparison with the IHSGI projection, the AEO2011 Reference case was adjusted to remove coal-to-liquids (CTL) heat and power, biofuels heat and co-products, and natural gas feedstock use. The ExxonMobil projections do not include electricity consumption in the sectoral consumption breakout. Both the IHSGI and INFORUM projections feature higher total energy consumption than AEO2011, while ExxonMobil features lower consumption (Table 14).

Both INFORUM and IHSGI have significantly higher projections of electricity consumption than AEO2011, which explains much of the difference in the levels of energy consumption among the three projections: the generation of electricity uses approximately three times the amount of energy from fuel as the amount of useful energy provided to end users. In both the INFORUM and IHSGI projections, the electric power sector consumes 10 quadrillion Btu more energy than projected in AEO2011. The greater use of electricity, predominantly for more conventional applications, results in higher electricity prices.

None of the electricity projections includes more than modest penetration of electric vehicles in the transportation sector by 2035 (IHSGI projects almost 300 trillion Btu of electricity consumed in the transportation sector in 2035). The ExxonMobil projection for electricity does not detail electricity consumption, but the amount of energy used to generate electricity is at the 2008 level in 2025 and 2030, with electricity producers aggressively switching to natural gas from coal (the amount of coal used by electricity generators ranks third behind natural gas and nuclear in 2030).

Projected commercial and transportation sector electricity consumption in INFORUM is comparable to that in AEO2011, but electricity consumption in the residential and industrial sectors in the INFORUM projection grows to a level more than 50 percent above consumption in 2009, much greater than the increase in AEO2011 (about 20 percent in the residential sector and 10 percent in the industrial sector). Residential and industrial sector electricity consumption in the IHSGI projection also grows faster than in AEO2011, but at a somewhat slower rate than in the INFORUM projection. However, commercial sector electricity consumption grows more rapidly in the IHSGI projection than in both the INFORUM and AEO2011 projections. AEO2011 includes the consensus agreement to implement one round of appliance standard updates that holds down residential electricity growth, as well as growth in industrial natural gas usage for combined heat and power, which shifts some industrial energy demand from electricity to natural gas.

Despite the much higher level of electricity consumption in the IHSGI projection, projected total energy consumption is only about 1.2 quadrillion Btu higher than in AEO2011. The difference is moderated by lower growth in motor gasoline consumption in the transportation sector in the IHSGI forecast. Motor gasoline consumption in the IHSGI projection in 2035 is almost 3 quads lower than in AEO2011, however, the lower level of gasoline consumption is partially offset by about one quad higher diesel fuel consumption. The IHSGI projection includes about 3 million more light-duty truck sales in 2035 (but comparable numbers of light-duty car sales) than AEO2011.

INFORUM projects higher prices for motor gasoline than AEO2011 (more than $1 higher in 2035), with more efficient light-duty vehicles (the vehicle stock average is about 1.8 mpg higher in 2035). However, the total stock of vehicles is larger (due mainly to a stock difference in 2009), and they are driven more miles, leading to a higher level of consumption in the INFORUM forecast than shown in AEO2011. The ExxonMobil projection has energy use in each sector level or declining from the level in 2008, which leads to lower overall energy consumption than in the AEO2011 Reference case.

4. Electricity

Table 15 provides a summary of the results from the AEO2011 Reference case and compares them with the other projections. Electricity sales increase on average by 1.1 percent per year through 2015 in AEO2011, reaching 3,811 billion kilowatthours, which is lower than the other projections. Electricity sales in 2015 range from a low of 3,811 billion kilowatthours in AEO2011 to a high of 4,500 billion kilowatthours in INFORUM. The IHSGI projection of electricity sales, at 4,119 billion kilowatthours in 2015, also projects higher sales than AEO2011 for the residential and commercial sectors, while industrial sector sales are slightly less than in AEO2011. Both IHSGI and INFORUM project higher sales in 2035 than AEO2011. In 2035, IHSGI projects sales of 5,551 billion kilowatthours, INFORUM projects 5,935 billion kilowatthours, and AEO2011 projects 4,483 billion kilowatthours. Although INFORUM does not provide sales by sector, IHSGI projects higher sales than AEO2011 for all sectors in 2035.

The average retail electricity price in AEO2011 falls from 9.8 cents per kilowatthour in 2009 to 8.9 cents per kilowatthour in 2015. IHSGI projects a higher average retail price of 10.4 cents per kilowatthour in 2015, consistent with the higher level of demand in that projection. The average retail electricity price remains relatively flat after 2015 in AEO2011, rising to only 9.2 cents per kilowatthour in 2035. In comparison, the average retail electricity price increases to 12.9 cents per kilowatthour in the IHSGI projection, again reflecting the much higher level of electricity sales in that projection.

Although the average retail electricity price in the residential sector falls in AEO2011 from 11.5 cents per kilowatthour in 2009 to 10.6 cents per kilowatthour in 2025 before rising to 10.8 cents per kilowatthour in 2035, it rises steadily in the Energy Ventures Analysis (EVA) and IHSGI projections, to 18.5 cents per kilowatthour and 13.2 cents per kilowatthour in 2025, respectively. The average residential retail electricity price in the INFORUM projection is similar to those in AEO2011. The relative patterns of change in retail electricity prices in the commercial and industrial sectors in the AEO2011, EVA, IHSGI, and INFORUM projections are similar to those in the residential sector.

The change in total generation and imports of electricity in 2015 is consistent with sales, ranging from 4,286 billion kilowatthours in AEO2011 to 4,522 billion kilowatthours in the IHSGI projection. The level of generation continues to increase with the growth in sales. In 2035, the total electricity supply from generation plus imports ranges from 5,181 billion kilowatthours in AEO2011 to 6,025 billion kilowatthours in the IHSGI projection, over 16 percent higher than in AEO2011.

AEO2011 projects more coal-fired generation in 2035 than IHSGI—2,218 billion kilowatthours compared with 1,487 billion kilowatthours. The difference in the IHSGI projection, which includes greater electricity demand, is made up by increased generation primarily from natural gas but also from nuclear and hydroelectric/other energy sources. While AEO2011 shows 1,288 billion kilowatthours of natural-gas-fired generation in 2035, IHSGI shows 2,261 billion kilowatthours. Nuclear generation in 2035 totals 874 billion kilowatthours in AEO2011, compared with 1,163 billion kilowatthours in the IHSGI projection, and hydroelectric/other generation in 2035 is 740 billion kilowatthours in AEO2011, compared with 1,069 billion kilowatthours in the IHSGI projection.
The mix of generating capability by fuel is relatively similar across the projections in 2015. By 2025, however, the mix of generating capacity begins to change, due to variations in the projected rates of growth in electricity demand and more aggressive retirements of coal capacity in the EVA and ICF International (ICF) projections. Although little coal-fired capacity is retired in the IHSGI projection by 2025, the greater growth in electricity demand is met by a sharp increase in natural gas and hydroelectric/other capacity. Natural-gas- and oil-fired capacity in 2025 totals 574 gigawatts in the IHSGI projection, compared with 489 gigawatts in AEO2011. While the ICF projection shows less growth in demand, it shows more retirements of coal capacity by 2025. As a result, ICF shows the highest level of natural-gas- and oil-fired capacity in 2025, at 579 gigawatts.

The faster growth in natural gas and hydroelectric/other capacity continues through 2035 in the IHSGI and ICF projections. Natural-gas- and oil-fired capacity reaches 675 gigawatts and 655 gigawatts in 2035 in the IHSGI and IFC projections, respectively. By comparison, natural-gas- and oil-fired capacity grows to only 572 gigawatts in AEO2011 in 2035. Hydroelectric/other capacity continues to grow in each of the three projections after 2025, to 384 gigawatts and 297 gigawatts in the IHSGI and ICF projections, respectively, compared with 205 gigawatts in AEO2011. The IHSGI projection shows the most growth in U.S. nuclear power capacity, to 147 gigawatts in 2035, compared with 111 gigawatts in AEO2011. ICF shows 108 gigawatts of nuclear capacity in 2035.

Environmental regulations are an important factor in the selection of technologies for electricity generation. While complete information on the regulations assumed in each of the projection is not available. AEO2011 includes only current laws and regulations; it does not assume a cap or tax on carbon dioxide (CO2) emissions. Restrictions on CO2 emissions could change the mix of technologies used to generate electricity.

5. Natural gas

The variation among published projections of natural gas consumption, production, imports, and prices (Table 16) can be significant. It results from differences in the assumptions that underlie the projections. For example, the natural gas projection in the AEO2011 Reference case assumes, for the most part, that current laws and regulations will continue through the projection period, whereas other natural gas projections may include anticipated policy developments over the next 25 years. In particular, AEO2011 does not assume the implementation of regulations limiting CO2 emissions or other types of emissions beyond those already in effect.

Each of the projections examined here shows an increase in overall natural gas consumption from 2009 to 2035, with the ICF and IHSGI projections having the most significant increases, at 43 percent and 41 percent, respectively. Total natural gas consumption in the INFORUM and ExxonMobil projections remains flat from 2009 to 2015 but grows to a level comparable with those in the AEO2011, Deutsche Bank (DB), and EVA projections in 2025. In the later years of all the projections, total natural gas consumption grows despite increasing natural gas prices, with the exception of the DB projection, which shows a decline in consumption from 2025 to 2035. Total natural gas consumption in 2035 in the ICF and IHSGI projections is about 30 percent higher than in the DB projection, which shows the lowest level of total natural gas consumption.

The ICF, ExxonMobil, and IHSGI projections for natural gas consumption by electricity generators are significantly different from the other projections. In 2035, IHGSI is more than double the lowest projection, the AEO2011 Reference case. AEO2011, DB, EVA, and INFORUM show similar projections of natural gas consumption for the electricity generation sector, with annual growth rates of 1 percent across the projection period; the ICF, ExxonMobil, and IHSGI projections show 3-percent annual growth. The slow growth in AEO2011 reflects slow growth for electricity generation due to the construction of planned coal, renewable, and nuclear capacity builds.

Industrial natural gas consumption varies greatly across the different projections. ICF, INFORUM, EVA, and the AEO2011 Reference case show growing industrial natural gas consumption throughout the projection period. Industrial natural gas consumption in AEO2011, however, increases by 31 percent from 2009 to 2015 and then levels off for the remainder of the projection, whereas in the other projections it grows more steadily. The growth in industrial natural gas consumption in AEO2011 is attributable to relatively low industrial natural gas prices, a strong increase in natural gas use in combined heat and power plants, and a significant increase in the use of natural gas as a feedstock in the chemical and hydrogen industries. Industrial natural gas consumption remains constant in the ExxonMobil projection throughout the projection period, while industrial natural gas consumption in the IHSGI and DB projections increases initially, then declines from 2015 to 2035. The projections of industrial natural gas consumption in 2035 range from 36 percent above the 2009 level (INFORUM) to 11 percent below the 2009 level (DB).

The basic consumption patterns and levels of natural gas consumption are relatively similar across the residential sector projections, with the exception of DB. (It should be noted that ExxonMobil's projection for residential consumption includes commercial consumption.) Residential sector natural gas consumption in the DB projection increases steadily, growing to 26 percent above the 2009 level in 2035. Three of the six projections (INFORUM, AEO2011, and EVA) show relatively similar growth in commercial consumption in the projection period. The projections of commercial natural gas consumption in the ICF, DB and IHSGI projections are initially similar to the other projections, but demand eventually declines, resulting in 2035 projections of commercial natural gas consumption that are below 2009 levels. (INFORUM's 2009 commercial consumption level is 3.68 trillion cubic feet, significantly higher than the others.) The DB projection includes the most significant decline, falling to 23 percent below 2009 levels in 2035.

With the exception of the DB and INFORUM projections for the period after 2025, all the projections show growing domestic natural gas production throughout the projection period, although at different rates. The greatest growth in natural gas production is in the ICF projection, and the lowest is in the INFORUM projection. Natural gas production in the ICF projection exceeds that in the INFORUM projection by 28 percent in 2025. With significant declines in net pipeline imports, ICF and the AEO2011 Reference case project strong increases in the domestic production share of total natural gas supply. The rest of the projections show domestic natural gas production maintaining a relatively stable share of total natural gas supply, with the exception of the DB projection, where domestic production drops off notably in 2035 with a big increase in LNG imports. In all the other projections, net LNG imports remain well under 1 trillion cubic feet throughout the projection period. Some of the projections show declines in net pipeline imports relative to the 2009 level. The exception is IHSGI, which shows increasing net pipeline imports after 2015, following an initial dip. In comparison with EVA and DB, the AEO2011 and ICF projections show severe declines in pipeline imports.

The AEO2011 Reference case, EVA, and ICF all show similar natural gas production and price levels that increase over time. In contrast, DB projects lower but more stable production levels, with greater price increases; and IHSGI projects stronger growth in natural gas production than AEO2011, EVA, and ICF, with lower and more stable prices.

Only three of the projections provide delivered natural gas prices for comparison: the AEO2011 Reference case, ICF, and IHSGI. However, the ICF and IHSGI price projections are difficult to compare with the AEO2011 prices because of apparent definitional differences. In the ICF projection, end-use sector prices for the 2009 base year are very different from those in the AEO2011 and IHSGI projections. Further, the IHSGI industrial delivered natural gas price is difficult to compare. The IHSGI industrial delivered natural gas price in 2009 is $1.23 higher than the 2009 price in AEO2011 and $1.35 higher than the 2009 price in the ICF projection (all prices in 2009 dollars per thousand cubic feet). The AEO2011 historical delivered industrial natural gas price is based on the Manufacturing-Industrial Energy Production Survey (rather than EIA's Natural Gas Monthly, which represents prices paid to local distribution companies by industrial customers). To put the prices on a more common basis, price margins (the difference between delivered prices and average wellhead prices) can be compared.

For the residential and commercial sectors, each of the projections shows an initial decline in natural gas price margins from 2009 levels. The margins in the AEO2011 Reference case, however, recover 86 percent of the decline from the 2009 level by 2035, while the ICF and IHSGI margins continue declining throughout the projection period at relatively similar rates. The increase in residential and commercial margins in AEO2011 is attributable to a significant decline in consumption per customer. From 2015 forward, the projected industrial margins are relatively stable in all three projections, although at significantly different levels. The AEO2011 and IHSGI natural gas price margins for the electricity sector are similar, with IHSGI showing slightly higher margins; however, those in the ICF projection range from 31 to 106 percent higher than the margins in the other projections from 2015 to 2035.

6. Liquid fuels

In the AEO2011 Reference case, the U.S. imported refiner's acquisition cost (RAC) for crude oil (in 2009 dollars) increases to $86.83 per barrel in 2015, $107.40 barrel in 2025, and $113.70 per barrel in 2035 (Table 17). Prices are lower in all years in the DB, ICF, and IHSGI projections, ranging from $70 per barrel to $106 per barrel in 2035. In fact, the IHSGI price in 2035 is 9 percent lower than the 2015 price. The ICF price remains steady at $70 per barrel over the entire projection. The prices in the INFORUM projection are slightly higher in 2025 and 2035, reaching $125 per barrel in 2035. Purvin & Gertz (P&G) did not provide a projection of RAC prices.

Domestic crude oil production increases by 11 percent from 2009 to 2035 in the AEO2011 projection. The INFORUM projection shows production varying within a slightly wider band but remaining at a lower overall level than in AEO2011. DB, IHSGI, and P&G all project decreasing domestic crude production. DB's projection for 2035 is 40 percent lower than the AEO2011 projection, and IHSGI's is 43 percent lower. In the AEO2011 Reference case, total net imports of crude oil and petroleum products in 2035 are 9 percent lower than in 2009, consistent with projected increases in domestic production of crude oil. IHSGI and INFORUM both project higher total net imports in 2035.

Prices for motor gasoline prices and diesel fuel increase steadily through 2035 in the AEO2011 projection. INFORUM also projects rising prices but at a faster rate than in AEO2011. IHSGI projects decreasing prices. Biofuels supply is listed separately only in the AEO2011 Reference case and in the P&G projection. In AEO2011, biofuels supply increases steadily through 2035 in response to the Renewable Fuels Standard mandate. In the P&G projection, biofuel supply remains steady. Total product demand, including both petroleum products and biofuels, is similar in the AEO2011 and P&G projections.

7. Coal

The coal projections provided by DB, EVA, ICF, INFORUM, and Wood Mackenzie (WM) present interesting contrasts with the AEO2011 Reference case. Only AEO2011 and INFORUM show growth in coal consumption; the other projections show declines ranging between 10 percent and 38 percent from 2009 levels by the end of their respective projection horizons.

Of the six coal projections, only ICF and WM explicitly state that they include a price on carbon. In the ICF projection, coal consumption in 2015 (before implementation of the carbon price) is 3 percent higher than projected in AEO2011. In 2025, however, coal consumption in the ICF projection is 19 percent lower than ICF's projection for 2015 and 27 percent lower than the AEO2011 projection for 2025 (on a Btu basis); this difference is most likely attributable to inclusion of the carbon price in 2025 along with other assumed regulations affecting coal use that are specified in the notes for Table 18. In 2030 and 2035, ICF's outlook for coal consumption is the lowest of the projections.

For most years, the WM projection shows less coal consumption and production than in the AEO2011 projection, consistent with the impact of a carbon price. The WM projection also showed a decline in regional coal production, again consistent with the assumed carbon price. Coal production both east and west of the Mississippi declines in 2025 relative to 2015 in the WM projection. In 2030, total coal production (excluding coking coal) in the WM projection is 27 percent lower than in the AEO2011 projection. (WM provides projections only for thermal coal, thus excluding coking coal, which is used in steelmaking. In 2009, coking coal production occurred only in the East, and it accounted for 11 percent of eastern coal production.)

Excluding coking coal, the average minemouth price of coal per ton in 2015 in the WM projection is 19 percent higher than the corresponding price in the AEO2011 projection. The price difference narrows after 2015, however, and in 2030 the AEO2011 and WM prices are nearly identical, despite very different coal production outlooks. The WM projection has generally lower production levels than the AEO2011 projection throughout the period, implying that WM includes higher production costs.

The AEO2011 and WM projections show similar levels of eastern coal production (excluding coking coal) in 2030, differing by only 0.5 percent, which is noteworthy given the carbon price assumption in the WM projection. It appears that production west of the Mississippi falls more (in terms of tonnage) in the WM projection as a result of the carbon price, but the regional shares of total production remain constant over the projection. Coal production east of the Mississippi (excluding coking coal) represents 38 to 39 percent of total production in all years in the WM projection, consistent with the historical share, but in the AEO2011 projection coal production east of the Mississippi falls to a 28-percent share in 2030. In AEO2011, more favorable pricing of western coal than eastern coal facilitates growth in western coal's share of total production.

Steam coal exports fall to only 8 million tons in 2015 in the WM projection, a decline of 63 percent from 2009 levels, and then exceed 2009 levels by 2025. While steam coal exports show modest gains after 2015, they never reach the higher levels seen in 2008. In contrast, steam coal exports in the AEO2011 projection vary little, ranging between 18 and 20 million tons from 2009 to 2035 and remaining well below the volumes exported in 2008.

In the INFORUM projection, coal exports total 177 million tons in 2035, the equivalent of about 11 percent of total U.S. production in 2035 and 64 million tons higher than the historical record set in 1981. Total coal exports in 2035 in the INFORUM case are more than double the total in the AEO2011 projection. Imports are also notably higher in the INFORUM projection, at 113 million tons in 2035—triple the highest historical level of U.S. imports.

Although ICF does not explicitly provide a coal export projection, coal consumption (in Btu) declines at a far faster rate than coal production (provided in tons only), implying strong growth in exports. For example, from 2015 to 2025, coal production east of the Mississippi—historically, where most U.S. coal exports originate—rises by nearly 100 million tons; and while total coal production falls by 4 percent (47 million tons), coal consumption (in Btu) declines by a much larger 19 percent. The gap between production and consumption closes somewhat by 2035, with production 29 percent lower and consumption 39 percent lower than ICF's projection for 2015. EVA also projects strong coal exports that remain in the range of 80 million tons, similar to 2008 export levels, for the projection years shown. In the AEO2011 Reference case, exports hover in the 70 million ton range.

In the INFORUM projection, the average minemouth price of coal (in constant 2009 dollars) increases by about 140 percent from 2009 to 2035. The rise may be due in part to higher mining costs and expectations of growth in domestic coal demand, but it may also be due to strong international demand for U.S. coal. Larger exports of coking coal—which typically command higher prices than thermal coal exports—might also explain some of the increase in the average coal minemouth price in the INFORUM projection.

ICF projects a minemouth coal price on 2015 that is 8 percent lower on a Btu basis than the AEO2011 price in 2015, although coal production in 2015 is 11 percent higher in the ICF projection. All of the increase in production in 2015 relative to AEO2011 is attributed to production east of the Mississippi, possibly for export. Over the projection, as ICF's total production falls relative to AEO2011, its average minemouth price still continues to rise, so that in 2035 it is only 4 percent lower than the corresponding price in AEO2011. The rise in minemouth prices in the ICF projection could be the result of strong international demand, a larger share of higher-cost eastern production, or rising mining costs. In contrast, ICF's delivered coal price to the electricity sector falls slightly from 2015 levels, possibly reflecting either a larger proportion of eastern coal production, which would have lower total transport costs, or generally lower transportation rates for all U.S. coal shipments. AEO2011 projects an increase in the delivered price of coal to the electricity sector, reflecting higher transportation costs for western coal, as well as higher projected minemouth prices for coal from most basins.

The strongest growth in coal production is projected by INFORUM. In 2035, coal production in the INFORUM projection is 24 percent above the AEO2011 projection. Similarly, coal consumption in the INFORUM projection is the highest among all the projections regardless of the projection year.

Total coal consumption declines at a rate of 0.5 percent per year (on a tonnage basis) from 2009 to 2030 in the EVA projection, as compared with an average increase of 1.1 percent per year in AEO2011. For the same period, thermal coal consumption (excluding coking coal) declines by 0.7 percent per year in the WM projection but increases by 1.1 percent per year in the AEO2011 projection. From 2009 to 2035, coal consumption increases by 1.7 percent per year (on a tonnage basis) in the INFORUM projection and by 1.1 percent per year in the AEO2011 Reference case. Also over the 2009-2035 period, coal consumption in the DB and ICF projections (on a Btu basis) declines at by 0.4 percent per year and 1.8 percent per year, respectively, compared with an increase of 0.8 percent per year in the AEO2011 projection.