Comparison with other projections

Few organizations produce energy projections with details and time horizons comparable with those in the Annual Energy Outlook 2016 (AEO2016). Other organizations do, however, address one or more aspects of the U.S. energy market. Projections from other organizations, which tend to focus on selected areas—such as economic growth, international oil prices, energy consumption, electricity, natural gas, petroleum, and coal—are compared with the AEO2016 Reference case in the following sections.

CP1. Economic growth

CP1. Economic growth The range of projected economic growth rates in the outlooks included in this comparison tends to be wider over the first 3 years of the projection than over longer periods because the group of variables that influence long-run economic growth—such as population, productivity, and labor force growth—is smaller than the group of variables that affect projections of short-run growth. The 5-year average annual growth rate of real gross domestic product (GDP) from 2015–20 ranges from 2.0% to 3.1% (Table CP1), and the 11-year average annual growth rate from 2015–26 ranges from 1.9% to 2.7%.

From 2015–20, real GDP growth averages 2.6%/year in the AEO2016 Reference case, lower than projected by the Social Security Administration (SSA) in The 2015 Annual Report of the Board of Trustees of the Federal Old-Age and Survivors Insurance and Federal Disability Insurance Trust Funds and by ExxonMobil, but higher than projected by IHS Global Insight (IHSGI), the Congressional Budget Office (CBO), the Office of Management and Budget (OMB), the Interindustry Forecasting Project at the University of
Maryland (INFORUM), Energy Ventures Analysis (EVA), the International Energy Agency (IEA) in its November 2015 World Energy Outlook Current Policies Scenario, and the Oxford Economics Group (OEG).

The average annual GDP growth of 2.4% in the AEO2016 Reference case from 2015–26 is identical to the mid-range of the outlooks, with IHSGI and CBO projecting 2.4% average growth; SSA and Exxon Mobil projecting higher average growth (2.7%/year and 2.6%/year, respectively); and OEG, OMB, INFORUM, and EVA projecting lower average growth (2.0%/year, 2.1%/year, 2.2%/year, and 1.9%/year, respectively).

There are few public or private projections of GDP growth for the United States that extend to 2040. The AEO2016 Reference case projects 2.2% average annual GDP growth from 2015–2040, consistent with trends in labor force and productivity growth. OEG, IEA, INFORUM, and EVA project lower GDP growth than in the AEO2016 Reference case, averaging 1.9%/year, 2.1%/year, 2.1%/year, and 2.0%/year, respectively. Exxon Mobil and SSA project higher GDP growth from 2015–40, both averaging 2.4%/year.
IHSGI projects the same growth rate, at 2.2%/year, as in the AEO2016 Reference case.

CP2. Oil prices

In the AEO2016 Reference case, crude oil prices are represented by spot prices for North Sea Brent (Brent) crude oil and West Texas Intermediate (WTI) crude oil price, and by the imported U.S. refiner acquisition cost for crude oil (IRAC). The WTI price generally is lower than the North Sea Brent price. The historical record shows substantial variability in crude oil prices, and there is arguably even more uncertainty about prices in the long term. AEO2016 considers three crude oil price cases (Reference, Low Oil
Price, and High Oil Price) to allow assessment of alternative views on the future course of crude oil prices (Table CP2).

In AEO2016, the North Sea Brent spot crude oil price is tracked as the main benchmark for world crude oil prices, because it better reflects the marginal price paid by refineries for imported light, sweet crude oil (used to produce petroleum products for consumers) than the West Texas Intermediate (WTI) crude oil price does. The WTI price has continued to trade at a discount relative to other world crude oil prices. In 2015, the WTI and North Sea Brent crude oil prices differed by $4 per barrel ($4/b). In the AEO2016 Reference case, the discount grows to $7/ b in 2040.

Spot crude oil prices in the other outlooks used in the comparison are based on either Brent, WTI, or IRAC prices, except for prices from the IEA, which are based on the average of crude oil import prices paid by members of the Organization for Economic Cooperation and Development (OECD) and prices from the Organization of Petroleum Exporting Countries (OPEC), which reflect the average price of a basket of crude oil sold by OPEC member countries.

The range of oil price projections in both the near term and the long term reflects current market conditions, including low prices due to crude oversupply in the near term and different assumptions about the future of the world economy. The wide range of the projections underscores the inherent uncertainty associated with future crude oil prices. With the exception of Strategic Energy & Economic Research (SEER)—which projects Brent prices remaining between $40/b and $45/b (2015 dollars)—the projections
show crude oil prices rising over the entire projection period. On the other hand, the spread of the projections (again with the exception of SEER) is encompassed by the AEO2016 Low and High Oil Price cases, ranging from $49/b to $207/b for Brent in 2030 and from $73/b to $230/b in 2040. However, except for IEA (in 2030 and 2040) and IHSGI (in 2025), all the other projections in this comparison show lower crude oil prices than those in the AEO2016 Reference case for every year of the projection.

CP3. Total energy consumption

Three other organizations—ExxonMobil, BP, and IEA—provide projections of energy consumption by sector. IHSGI provides a projection of total primary energy consumption (but not consumption by sector) and projections of electricity sales, petroleum, and natural gas demand by end-use sector. To allow comparisons with the BP and IEA projections, AEO2016 Reference case projections for the residential and commercial sectors have been combined to produce a buildings sector projection (Table CP3). The IEA projections have a base year of 2013. ExxonMobil did not provide data for a base year. The BP projection extends through 2035, with a base year of 2014. The AEO2016 Reference case includes an unspecified sector, which has been combined with transportation for this comparison, in order to make it comparable with other projections.

Both IEA and ExxonMobil account for electricity generation from renewable energy sources at a conversion rate of 3,412 British thermal units (Btu) per kilowatthour (kWh) rather than a heat rate for displaced fossil fuel, as is used in the AEO2016 and other projections. As a result, their estimates for total energy consumption are lower. The BP projection appears to include the Clean Power Plan (CPP), with coal use for electricity generation showing the largest drop from 2020–25, as well as smaller declines in all other 5-year periods. The ExxonMobil projection does not include the CPP but assumes the implementation of unspecified environmental regulations related to carbon dioxide (CO2) emissions, which reduce demand for coal, particularly after 2030, whereas the CPP has a larger impact before 2030. Although the IEA New Policies Scenario includes the CPP, it is not included in this comparison because it assumes other new policies that are difficult to compare with the AEO2016 Reference case. IEA also includes scenarios that do not anticipate policies. The IEA Current Policies Scenario, which does not include the CPP and assumes that no new policies are added to those in place in mid-2015, is used for this comparison.

For all the years shown, ExxonMobil and IEA project lower total energy consumption than in the AEO2016 Reference case. Total energy consumption is higher in all years of the IHSGI projection than in the AEO2016 Reference case. IHSGI projects significantly higher total electricity sales than in the AEO2016 Reference case, which helps to explain much of the difference in total energy consumption between the two projections.

The use of unspecified CO2 emissions regulations instead of the CPP in the ExxonMobil projections results in a different path for energy use and lower total energy use in 2040 in the electric power sector than in the other projections. The AEO2016 Reference case shows switching from coal to natural gas and renewables in the electric power sector from 2020–25, with the CPP beginning in 2022. With the assumption of more general CO2 emissions regulations in the ExxonMobil projection, the transition away from coal begins in the 2030s and occurs more gradually. Both the AEO2016 Reference case and ExxonMobil projections show residential energy consumption slightly lower in 2040, commercial consumption growing slowly, and transportation consumption lower in 2040. Industrial consumption increases through 2040 in the AEO2016 Reference case, while ExxonMobil shows industrial consumption declining from 2030–40. The direction of the trends is relatively consistent, if not the timing, even with different assumptions for the timing of environmental regulations.

The base year consumption figures used by BP are lower than the AEO2016 base year data, with most of the difference in transportation consumption. Part of the difference is that AEO2016 uses 2015 as a base year and BP uses 2014, but that does not account for all the difference. Base year consumption in the BP projection is about 7 quadrillion Btu less than in the AEO2016 Reference case, and the BP projections are about 10 quadrillion Btu lower in 2035. The gap widens in the 2030–35 period, due mainly to transportation consumption (which declines by a little more than 1 quadrillion Btu in the BP projection) and electric power consumption. Over the same period, transportation consumption remains relatively constant, and electric power consumption increase by about 1 quadrillion Btu, in the AEO2016 Reference case. The difference in accounting for renewable electricity generation could explain the variation in the electric power sector.

Total energy consumption in the IEA projection is higher in 2040 than in 2013 as a result of an increase of 3.5 quadrillion Btu in buildings sector energy consumption, including a 3.0 quadrillion Btu increase in buildings electricity use. IEA projects a small increase in energy use in the industrial sector of 0.4 quadrillion Btu from 2020–40 after a 10% increase from 2013–20. The increase through 2020 is similar to that in the AEO2016 Reference case, and it continues to grow through 2040 but at a slower rate than in the AEO2016 Reference case.

CP4. Electricity

Table CP4 compares AEO2016 Reference case projections for electricity with those from IEA, NREL, and EVA. The IEA and NREL projections for total electricity generation are similar to the AEO2016 Reference case projections for 2025, 2035, and 2040, whereas the EVA projections for total electricity generation are significantly higher than those of the other projections across all years. The AEO2016 Reference case projects total U.S. generation of 4,420 billion kWh in 2025, as compared with the EVA projection of 5,361 billion kWh, which is about 20% higher than AEO2016 and the highest among all of the projections compared. The EVA projection appears to be based on policy assumptions that are similar to those in the AEO2016 Reference case, including the CPP.

In the AEO2016 Reference case, as a result of the CPP, total generation from coal-fired power plants in 2025 is 217 billion kWh lower than generation from natural gas-fired plants. In the NREL projection, total coal-fired generation is 558 billion kWh higher than natural gas-fired generation in 2025, even with the assumed implementation of both carbon taxes and carbon pollution standards for new power plants. The NREL projection shows a decline in total electricity generation from natural gas-fired power plants over the projection. In IEA’s Current Policies scenario, which is based on current laws and regulations (excluding the CPP), electricity generation from natural gas-fired power plants does not surpass generation from coal-fired power plants until the later part of the 2030s. The EVA projection shows total natural gas-fired generation surpassing coal-fired generation in the early 2030s. One possible cause for the variation in projected timing of the transition (although no cause was suggested) may be differences in the IEA and EVA trends for natural gas and coal prices.

Electricity generation from U.S. nuclear power plants varies widely among the projections. In the AEO2016 Reference and No CPP cases, nuclear generation declines from 798 billion kWh in 2015 to 770 billion kWh in 2019 before rebounding to 789 billion kWh/year from 2022–40. In the IEA projection, nuclear generation grows by 5% (39 billion kWh) from 2013–20 and remains nearly constant through 2040. In the NREL projection, nuclear generation falls steadily, with an accelerated decline after 2025.

EVA projects rising nuclear generation through 2025, followed by a decline. Across the projections, nuclear electricity generation in 2025 ranges from a low of 789 billion kWh in the AEO2016 Reference case to a high of 861 billion kWh in the IEA projection.

Generation from nonhydroelectric renewable resources accounts for a significant portion of the total increase in electricity generation, but its share of total generation varies across the projections. In the AEO2016 Reference case, wind and solar provide 10% and 4%, respectively, of total generation in 2025, compared with 9% and 3%, respectively, in the No CPP case. In the EVA projection, wind and solar energy provide the smallest share of total generation in 2025, 2035, and 2040. In the NREL projection,
wind and solar have the largest shares of total generation in 2025, 2035, and 2040 of the projections compared. Differences among the projections may result from different assumptions about technology costs and performance or from different treatments of federal and state policies for renewable electricity generation (i.e., production tax credits, investment tax credits, renewable fuel standards, etc.).

Total generating capacity (including combined heat and power) is similar across the projections, ranging from 1,112 gigawatts (GW) in 2025 in the AEO2016 No CPP case to 1,144 GW in the AEO2016 Reference case and 1,192 GW in the IEA projection. NREL projects slightly more growth in total generating capacity, corresponding to a higher projection of total generation from nonhydroelectric renewables, despite having the lowest projections for total generation in 2025, 2035, and 2040.

The implied capacity utilization rate for coal-fired power plants in the AEO2016 Reference case (calculated from total coal-fired capacity and generation) is about 60% in both 2035 and 2040, which is lower than for any other projection. In comparison, IEA and NREL project more than 70% utilization of total U.S. coal-fired capacity in 2035 and 2040. For oil/natural gas, hydroelectric/other, and solar energy, however, the AEO2016 Reference case has the highest utilization rates among the projections, at about 38% for oil/natural gas, 40% for hydroelectric/other, and 22% for solar in 2035 and 2040. NREL projects the highest utilization rate for wind capacity in 2035 and 2040 (47%) and the lowest utilization rates for oil, natural gas, and nuclear capacity in the same years. IEA projects the highest utilization rate for nuclear capacity in 2035 and 2040 (92%) and the lowest for wind in both years. IEA also has the lowest utilization rates for hydroelectric/other and solar capacity in 2035, but the utilization rates for hydroelectric/other in 2040 are similar in all of the projections. IEA's utilization rate for solar in 2040 is lower than in the AEO2016 Reference case but similar to NREL’s projection.

CP5. Natural gas

CP5. Natural gas Projections for natural gas consumption, production, imports, and prices (Table CP5) differ significantly, largely as a result of different assumptions. For example, the AEO2016 Reference case assumes that current laws and regulations generally remain unchanged from 2015–40, whereas other projections may include assumptions about policy developments over the period. In particular, the AEO2016 Reference case does not incorporate any future changes in policies affecting carbon emissions or other environmental issues.

Production

All the outlooks shown in Table CP5 (with the exception of IHSGI, which did not provide production data) project increases in natural gas production from 2015, when production totaled 27.2 trillion cubic feet (Tcf). BP projects the largest production increase, to 42.0 Tcf in 2035, or 54% more than the 2015 level. BP is followed closely by ExxonMobil, which projects 40.8 Tcf of natural gas production in 2035 and 41.4 Tcf in 2040, or 50% and 53% above 2015 levels, respectively.

The AEO2016 Reference case, ICF, BP, and ExxonMobil all project larger increases in natural gas production before 2025 than in the later years. In the AEO2016 Reference case, natural gas production increases by 28% from 2015–25 and by 15% from 2025–35. ICF, BP, and ExxonMobil project production increases of more than 30% from 2015–25 and less than 20% from 2025–35. EVA projects roughly equal growth rates for natural gas production from 2015–25 and 2025–35. EVA projects production increases of 23% (to 33.4 Tcf) from 2015–25 and 22% (to 40.6 Tcf) from 2025–35.

Net imports/exports

The AEO2016 Reference case projection for growth in U.S. natural gas exports from 2015–40 is the largest among those reviewed here, from net imports of 1.0 Tcf in 2015 to net exports in 2018. U.S. export growth to 7.6 Tcf in 2040 consists mostly of liquefied natural gas (LNG) exports, along with a smaller increase in net pipeline exports to Mexico through 2020 and a reduction in net pipeline imports from Canada through 2040, which offsets a gradual decline in net pipeline exports to Mexico after 2020.

EVA, ICF, and BP also provide projections for net imports of natural gas that show the United States becoming a net exporter by 2020, but they differ from the AEO2016 Reference case in terms of export levels. ICF shows net exports growing early in the projection but declining through 2035, when net exports of 3.4 Tcf are less than one-half of those in the AEO2016 Reference case (7.2 Tcf). The decline of net natural gas exports in the ICF projection results from a decrease in net LNG exports, from 3.2 Tcf in
2025 to 2.6 Tcf in 2035. EVA and BP show continued growth in net exports, to 4.7 Tcf and 7.6 Tcf in 2035, respectively. The BP projection of 7.6 Tcf of net natural gas exports in 2035 is fairly close to the AEO2016 Reference case projection of 7.2 Tcf in 2035. EVA projects net pipeline imports of natural gas into the United States after 2020, rather than net pipeline exports, with U.S. gross pipeline imports of natural gas more than doubling from 2025–35.

Consumption

In the AEO2016 Reference case, total domestic natural gas consumption increases by 19% from 2015–35 and by 25% from 2015–40 to a total of 34.4 Tcf in 2040. The 5.1 Tcf increase in total domestic consumption in the AEO2016 Reference case from 2020–35 is 0.8 Tcf larger than the projected increase in net natural gas exports (4.3 Tcf). The domestic consumption share of total U.S. natural gas production declines in the Reference case from 90% in 2020 to 82% in 2035 and 2040. From 2015–35, natural gas consumption in the electric power sector grows by 16%, to a total of 11.1 Tcf, as compared with a 22% increase in the industrial sector, to 9.2 Tcf, and a 10% increase in the commercial sector, to 3.6 Tcf in 2035. In the residential sector, natural gas consumption remains constant at 4.6 Tcf from 2015 to 2035 in the Reference case.

EVA, ICF, BP, and ExxonMobil provided outlooks for domestic natural gas consumption at different levels of detail, with the ICF projections being the most comprehensive. BP provided separate projections for consumption in the industrial and electric power sectors—projections of residential and commercial sector consumption are included with projections of consumption in the transportation sector, for lease and plant operations, for liquefaction to LNG for export and for pipeline fuel. BP consistently shows higher projections than those in the AEO2016 Reference case for total natural gas consumption. BP shows increasing consumption of natural gas in all domestic sectors, led by consumption in the electric power sector, with ICF showing a greater increase than BP in electric power sector consumption from 2020–35. ICF projects 63% growth in power sector natural gas use, to 16.3 Tcf in 2035, which is higher than projected in the AEO2016 Reference case and the other outlooks. The AEO2016 projection for natural gas consumption in the electric power sector is lower than the others, and its projection for industrial sector natural gas consumption in 2035 is lower than the EVA, BP, and ExxonMobil projections.

ICF shows the U.S. domestic sector consuming a steady share of U.S. natural gas production from 2020–35, varying from 89% to 92%. BP shows the share of production consumed in the United States declining from 88% in 2020 to 82% to 2035. In the AEO2016 Reference case, the share of production consumed in domestic markets falls from 90% in 2020 to 82% in 2035.

Although the EVA and ExxonMobil projections show lower volumes of natural gas consumption, they are not comparable with the other outlooks. EVA does not include natural gas consumed for lease and plant operations, liquefaction for export, or pipeline fuel. ExxonMobil does not include natural gas consumed in the commercial sector for transportation, lease and plant operations, liquefaction for export, and pipeline fuel. Also, ExxonMobil provides a combined projection for residential and commercial natural gas consumption. EVA differs from ExxonMobil in that it shows industrial consumption growing to 10.8 Tcf in 2035 (the second highest level among the projections), whereas ExxonMobil shows relatively flat consumption in the industrial sector. The ExxonMobil projections for total domestic consumption of natural gas through 2035 are higher than the EVA projections but lower than the AEO2016 Reference case projections.

Prices

Only IHSGI, EVA, and ICF provide projections for Henry Hub natural gas spot prices. All the price projections, including those in the AEO2016 Reference case, are in real 2015 dollars. Prices in the IHSGI, EVA, and ICF outlooks are lower than those in the AEO2016 Reference case from 2015–30. After 2030, the EVA, IHSGI, and ICF prices are above $5.00, in million British thermal unit (MMBtu), while, with the exception of 2031 and 2032, the price in the AEO2016 Reference case remains below $5.00/MMBtu throughout the projection period. EVA projects the highest Henry Hub prices through 2035, followed closely by IHSGI, with EVA having a projected 2035 spot natural gas price of $5.93/MMBtu, IHGSI $5.73/MMBtu, and ICF $5.20/MMBtu, all in real 2015 dollars. IHSGI is the only other outlook that provides a projection in 2040, with a projected spot price of $6.82/MMBtu in 2040, 40% higher than projected in the AEO2016 Reference case.

In the AEO2016 Reference case, residential natural gas prices rise to $12.74/thousand cubic feet (Mcf) in real 2015 dollars in 2040. Commercial natural gas prices rise to $10.72/Mcf in 2030, and remain between $10.66 and $10.73/Mcf through 2040. Electric power and industrial natural gas prices rise to $6.15/Mcf in 2025 and $5.74/Mcf in 2030 in real 2015 dollars, respectively, before gradually declining to $5.52/Mcf and $5.89/Mcf, respectively, in 2040. EVA, and ICF did not project natural gas prices by sector.

CP6. Petroleum and other liquid fuels

In the AEO2016 Reference case, the North Sea Brent spot crude oil price (in 2015 dollars) increases from about $52/barrel (b) in 2015 to $92/b in 2025 and then continues rising to $120/b in 2035 and $136/b in 2040 (Table CP6). North Sea Brent spot crude oil prices are relatively flat in the Energy Ventures Analysis (EVA) projection, rising from $65/b in 2025 to $67/b in 2035. In the AEO2016 projection, the U.S. imported refiner acquisition cost (IRAC) of crude oil (in 2015 dollars) increases from $46/b in 2015 to about $83/b in 2025, and then increases to $110/b in 2035 and $126/b in 2040. IRAC prices in the International Energy Agency (IEA) projection are similar but rise faster, increasing from $46/b in 2015 to $152/b in 2040, while IHS-Global Insight (IHSGI) project that IRAC prices will increase from $46/b in 2015 to $87/b in 2025 and then gradually to $91/b in 2035 and $93/b in 2040. IRAC prices in the ICF projection are relatively flat after increasing from 2015 levels, averaging $76/b in both 2025 and 2035. BP and ExxonMobil did not report projections of North Sea Brent or IRAC crude oil prices.

In the AEO2016 Reference Case, domestic crude oil production decreases from about 9.4 million barrels/day (b/d) in 2015 to 8.6 million b/d in 2017, before growing to 9.4 million b/d in 2025, 10.7 million b/d in 2035, and 11.3 million b/d by 2040. Overall, the production level in 2040 is about 20% higher than in 2015. Production in the BP projection grows from 9.4 million b/d in 2015 to 10.2 million b/d in 2025 and then grows modestly to 10.5 million b/d in 2035. The ICF projection shows production falling from the 9.4 million b/d produced in 2015 to 8.9 million b/d in 2025 and to 8.5 million b/d in 2035. Production increases from 2015 levels in the IEA projection to 12.0 million b/d in 2025 before falling to 10.6 million b/d in 2040. The ExxonMobil projection includes only total domestic production of crude oil and natural gas liquids, which is higher than in the AEO2016 Reference Case. Total production in the ExxonMobil projection increases from 2015 levels of 12.7 million b/d to 18.7 million b/d in 2025 before increasing to 19.1 million b/d in 2035, and then falling again to 18.0 million b/d in 2040. These levels are all higher than in the AEO2016 projection where production falls to 14.2 million b/d in 2025 before rising to 15.6 million b/d in 2035 and 16.3 million b/d in 2040.

With rapid growth in U.S. crude oil production, net imports fall in the AEO2016 Reference case and other projections. In the Reference case, total net imports of crude oil and products fall from 4.6 million b/d in 2015 to 3.3 million b/d in 2025, 1.7 million b/d in 2035, and 1.4 million b/d in 2040. In the BP projection, total net imports are even lower than in the AEO2016 Reference Case, falling to 1.2 million b/d in 2025. By 2035, the United States is a net exporter of 1.9 million b/d of crude oil and products.

Biofuel production increases to about 1.0 million b/d in 2025 and remains at roughly that level through 2040 in the AEO2016 Reference case. In the BP projection, biofuel production on an energy-equivalent basis increases to 1.2 million b/d in 2025 and 1.4 million b/d in 2035. Biofuels production is not explicitly included in the EVA, ICF, IEA, ExxonMobil, and IHSGI projections.

CP7. Coal

CP7. Coal Projections for U.S. coal production, consumption, exports, and prices vary widely in the AEO2016 Reference case and the projections from EVA, Wood Mackenzie (WoodMac), SNL Energy, IEA, and BP (Table CP7). The range of projections implies significant differences in analysts' views on how CO2 emissions and other environmental regulations will be implemented and how U.S. coal mining regions will compete with each other, with alternative energy sources, and with coal from other parts of the world. Most of the projections point to an overall downward trend for total coal consumption and production; however, the size and pace of the expected declines in coal consumption and production, as well as expectations for coal imports, vary even among projections with similar regulatory assumptions.

The projections generally noted the environmental regulations or programs considered; however, the respondents did not provide details for how the environmental regulations and programs were implemented in the projections, such as the assumed start dates for rules currently in litigation. WoodMac incorporated the CPP, Carbon Pollution Standards for new plants, regional carbon programs that constrain CO2 emissions, and rules that limit conventional air emissions. EVA and SNL Energy excluded the CPP
but included everything else mentioned above, including CO2 emissions standards for new coal-fired power plants. IEA's Current Policies Scenario took into account only policies formally enacted as of mid-2015, implying that it excludes regulations that would limit coal use the most, such as the CPP [1].

Collectively, the projections demonstrate the profound impact of the CPP on coal consumption in the electricity sector. Compared with 2015, coal consumption is projected to decline by 13% in 2025 and 30% in 2035 in the AEO2016 Reference case, as compared with 17% in 2025 and 42% in 2035 in the WoodMac projection [2]. BP projects the most significant drop from 2015 levels with coal consumption falling by 7.4 quadrillion Btu by 2035, compared with a 4.3 quadrillion Btu decline in the AEO2016 Reference case [3]. In the EVA projection, consumption declines between 2014 and 2020, recovers in the following five years, and then drops by 12% from 2025–40 [4]. Coal consumption for electricity generation in 2025 is slightly higher in the SNL Energy projection and remains nearly constant before 2030 in the IEA Current Policies Scenario. The EVA, SNL Energy, and IEA projections do not include the CPP.

The key difference among the projections for end-use (residential, commercial, industrial, and transportation sectors) coal use is in the other industrial/buildings sector. In the AEO2016 Reference case, the largest share of coal use in the other industrial/buildings sector is in combined heat and power plants and small on-site generating plants. Coal consumption in those applications increases throughout the 2015–40 projection period in the AEO2016 Reference case. Coking plants account for the remaining coal consumption. Only EVA and SNL Energy provide projections for coal consumption at coking plants, and both projections are largely in line with the AEO2016 Reference case, with coal use at coking plants declining steadily throughout the projection. Total end-use coal consumption, including coal use in the other industrial/buildings sector and at coking plants, remains largely constant through 2040 in the AEO2016 Reference case, while all the other projections show steady declines in end-use coal consumption resulting from declines in both the other industrial/building sector and at coking plants. The decline in total domestic coal consumption through 2040 significantly outweighs the impact of any changes in net coal exports, resulting in declines in total coal production in all of the projections. From 2015–35, the reductions in coal production range from 24% (EIA) to 31% (WoodMac), based on tonnage, and from 22% (EIA) to 34% (BP), based on energy content.

There are also differences among the projections of coal production by region, especially for the Appalachian and West regions. All of the projections suggest that Appalachian coal production will be lower in 2040 than in 2015. In the AEO2016 Reference case and WoodMac projections most of the decline occurs before 2030, compared with after 2035 in the EVA projection. The projections also disagree on how much the Appalachian region’s production will shrink, with WoodMac projecting a decline to 83 million tons in 2035, compared with 154 million tons in the AEO2016 Reference case. Coal production in the West region declines rapidly in the AEO2016 Reference case, beginning in 2020, and falls to 335 million tons in 2035. In the WoodMac projection, coal production declines rapidly from 2025–2030 before leveling off at about 373 million tons through 2040. EVA projects only moderate declines before 2035, with 2040 production at approximately 445 million tons. Compared with Appalachia and the West, production in the Interior region is relatively flat in all of the projections, ranging from about 150 million tons (WoodMac) to 200 million tons (EVA). Production in the AEO2016 Reference case falls within that range.

Coal exports increase from 75 million tons in 2015 to 94 million tons in 2040 in the AEO2016 Reference case. In comparison, WoodMac projects a more substantial increase in coal exports, to 191 million tons in 2035. EVA projects an increase to 82 million tons in 2025, followed by a decline to 78 million tons in 2040. BP does not project coal exports and imports separately, but the difference between its projections for production and consumption suggests a significant increase in net exports from 2015–25, by 2.1 quadrillion Btu, compared with an increase of 0.1 quadrillion Btu over the same period in the AEO2016 Reference case. Net exports decline in the BP projection by 0.9 quadrillion Btu from 2025–35, as compared with an increase of 0.4 quadrillion Btu from 2025–35 in the AEO2016 Reference case.

All the projections show coal imports declining over time. The largest reduction is in the AEO2016 Reference case, with imports declining from 11 million tons in 2015 to 55,000 tons in 2020 and remaining at that level through 2040. EVA projects that imports will remain at a level of about 10 million tons through 2040, and SNL projects that imports will remain at about 7 million tons from 2020–25. In the WoodMac projection, imports decline to 6 million tons in 2020, then drop to 2 million tons in 2025 and remain at that level through 2040.

The only projection for coal prices that can be compared with the EIA projections is from SNL Energy, which shows coal prices declining from 2015–20 and remaining relatively flat from 2020–25. In the AEO2016 Reference case, both minemouth prices and delivered prices to power plants increase moderately from 2015–40.

Endnotes

1. International Energy Agency, World Energy Outlook 2015, http://www.worldenergyoutlook.org/weo2015/.
2. The ranges of percentages are based on the tonnage of coal.
3. BP, Energy Outlook 2016, http://www.bp.com/en/global/corporate/energy-economics/energy-outlook-2035/energy-outlookdownloads.html.
4. All changes over time in this section are calculated based on projections provided to EIA starting 2020 and in 5-year increments. Values for 2020 and 2030 are not shown in Table CP7. When values for 2015 are available in a projection provided to EIA, they are used in calculations for the projection but not shown in Table CP7; when they are not available, EIA data for 2015 are used to calculation changes from 2015.