Coal Market Module
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Coal Market Module

The NEMS Coal Market Module (CMM) provides projections of U.S. coal production, consumption, exports, imports, 

distribution, and prices. The CMM comprises three functional areas: coal production, coal distribution, and coal exports. A 

detailed description of the CMM is provided in the EIA publication, Coal Market Module of the National Energy Modeling 

System 2014, DOE/EIA-M060(2014) (Washington, DC, 2014).

Key assumptions

Coal production

The coal production submodule of the CMM generates a different set of supply curves for the CMM for each year of the 

projection. Combinations of 14 supply regions, nine coal types (unique groupings of thermal grade and sulfur content), and two 

mine types (underground and surface), result in 41 separate supply curves. Supply curves are constructed using an econometric 

formulation that relates the minemouth prices of coal for the supply regions and coal types to a set of independent variables. 

The independent variables include: capacity utilization of mines, mining capacity, labor productivity, the user cost of capital of 

mining equipment, the cost of factor inputs (labor and fuel), and other mine supply costs.

The key assumptions underlying the coal production modeling are:

•	 As capacity utilization increases, higher minemouth prices for a given supply curve are projected. The opportunity to add 

capacity is allowed within the modeling framework if capacity utilization rises to a pre-determined level, typically in the 80% 

range. Likewise, if capacity utilization falls, mining capacity may be retired. The amount of capacity that can be added or 

retired in a given year depends on the level of capacity utilization, the supply region, and the mining process (underground or 

surface). The volume of capacity expansion permitted in a projection year is based upon historical patterns of capacity additions.

•	 Between 1980 and 2000, U.S. coal mining productivity increased at an average rate of 6.6% per year, from 1.93 to 6.99 short 

tons per miner per hour. The major factors underlying these gains were interfuel price competition, structural change in 

the industry, and technological improvements in coal mining [1]. Since 2000, however, growth in overall U.S. coal mining 

productivity has been negative, declining at a rate of 2.4% per year to 5.19 short tons per miner-hour in 2012. By region, productivity in all but one (Alaska/Washington) of the coal producing basins represented in the CMM has declined some during 

the past 12 years. In the Central Appalachian coal basin, which has been mined extensively, productivity declined by 52% 

between 2000 and 2012, corresponding to an average decline of 5.9% per year. While productivity declines have been more 

moderate at the highly productive mines in Wyoming’s Powder River Basin, coal mining productivity in this region still fell by 

32% between 2000 and 2012 corresponding to an average rate of decline of 3.1% per year. Of the coal producing regions, the 

Eastern Interior has shown the best overall performance with coal mining productivity declining by only 9% between 2000 

and 2012, or 0.8% per year. The Eastern Interior region, which has a substantial amount of thick, underground-minable coal 

reserves, is currently experiencing a resurgence in coal mining activity with several coal companies either opening or in the 

process of opening new, highly-productive longwall mines.

•	 Over the projection period, labor productivity is expected to decline in most coal supply regions, reflecting the trend of the 

previous decade. Higher stripping ratios and the added labor needed to maintain more extensive underground mines offset 

productivity gains achieved from improved equipment, automation, and technology. Productivity in some areas of the East is 

projected to decline as operations move from mature coalfields to marginal reserve areas. Regulatory restrictions on surface 

mines and fragmentation of underground reserves limit the benefits that can be achieved by Appalachian producers from 

economies of scale.

•	 In the CMM, different rates of productivity improvement are assumed for each of the 41 coal supply curves used to represent 

U.S. coal supply. These estimates are based on recent historical data and expectations regarding the penetration and impact 

of new coal mining technologies. Data on labor productivity are provided on a quarterly and annual basis by individual coal 

mines and preparation plants on the U.S. Department of Labor, Mine Safety and Health Administration’s Form 7000-2, 

“Quarterly Mine Employment and Coal Production Report,” and the U.S. Energy Information Administration’s Form EIA-7A, 

“Coal Production and Preparation Report”. In the Reference case, overall U.S. coal mining labor productivity declines at rate 

of 1.2% per year between 2012 and 2040. Reference case projections of coal mining productivity by region are provided in 

Table 12.1.

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Table 12.1. Coal mining productivity by region

short tons per miner hour

Supply Region 2012 2020 2025 2030 2035 2040

Average Annual 

Growth 12-40

Northern Appalachia 3.08 2.60 2.46 2.31 2.22 2.13 -1.3%

Central Appalachia 2.01 1.34 1.12 0.93 0.85 0.77 -3.4%

Southern Appalachia 1.68 1.33 1.22 1.12 1.05 0.99 -1.9%

Eastern Interior 4.29 4.39 4.38 4.40 4.39 4.39 0.1%

Western Interior 2.20 1.68 1.50 1.34 1.25 1.15 -2.3%

Gulf Lignite 6.93 6.14 5.84 5.55 5.36 5.18 -1.0%

Dakota Lignite 11.56 10.24 9.74 9.26 8.94 8.64 -1.0%

Western Montana 14.50 11.52 11.45 11.02 10.36 9.98 -1.3%

Wyoming, Northern Powder River Basin 29.17 24.01 22.15 20.43 19.33 18.29 -1.7%

Wyoming, Southern Powder River Basin 32.30 26.59 24.53 22.63 21.41 20.26 -1.7%

Western Wyoming 6.73 6.03 5.68 5.05 4.48 4.29 -1.6%

Rocky Mountain 5.50 4.09 3.62 3.20 2.97 2.74 -2.5%

Arizona/New Mexico 7.93 7.72 7.57 6.87 6.69 6.56 -0.7%

Alaska/Washington 5.98 6.35 6.51 6.67 6.77 6.88 0.5%

U.S. Average 5.19 4.64 4.35 4.02 3.81 3.68 -1.2%

Source: U.S. Energy Information Administration, AEO2014 National Energy Modeling System run REF2014.D102413A.

•	 In the AEO2014 Reference case, the wage rate for U.S. coal miners increases by 0.9% per year and mine equipment costs 

are assumed to remain constant in 2012 dollars (i.e., increase at the general rate of inflation) over the projection period.

Coal distribution

The coal distribution submodule of the CMM determines the least-cost (minemouth price plus transportation cost) supplies of 

coal by supply region for a given set of coal demands in each demand sector using a linear programming algorithm. Production 

and distribution are computed for 14 supply (Figure 11) and 16 demand regions (Figure 12) for 49 demand subsectors.

The projected levels of coal-to-liquids, industrial steam, coking, and commercial/institutional coal demand are provided by 

the liquid fuel market, industrial, and commercial demand modules, respectively; electricity coal demands are projected by 

the Electricity Market Module (EMM) coal imports and coal exports are projected by the CMM based on non-U.S. supply 

availability, endogenously determined U.S. import demand, and exogenously determined world coal import demands (nonU.S.).

The key assumptions underlying the coal distribution modeling are:

•	 Base-year (2012) transportation costs are estimates of average transportation costs for each origin-destination pair without differentiation by transportation mode (rail, truck, barge, and conveyor). These costs are computed as the difference 

between the average delivered price for a demand region (by sector and for export) and the average minemouth price for 

a supply curve. Delivered price data are from Form EIA-3, “Quarterly Coal Consumption and Quality Report, Manufacturing and Transformation/Processing Coal Plants and Commercial and Institutional Coal Users”, Form EIA-5, Quarterly Coal 

Consumption and Quality Report, Coke Plants”, Form EIA-923, “Power Plant Operations Report”, and the U.S. Bureau of the 

Census, “Monthly Report EM-545”. Minemouth price data are from Form EIA-7A, “Coal Production and Preparation Report”.

•	 For the electricity sector only, a two-tier transportation rate structure is used for those regions which, in response to rising 

demands or changes in demands, may expand their market share beyond historical levels. The first-tier rate is representative of the historical average transportation rate. The second-tier transportation rate is used to capture the higher cost of 

expanded shipping distances in large demand regions. The second tier is also used to capture costs associated with the use 

of subbituminous coal at units that were not originally designed for its use. This cost is estimated at $0.10 per million Btu 

(2000 dollars) [2].

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Figure 11. Coal Supply Regions

Source: U.S. Energy Information Administration, Office of Energy Analysis.

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•	 Coal transportation costs, both first- and second-tier rates, are modified over time by two regional (east and west) transportation indices. The indices, calculated econometrically, are measures of the change in average transportation rates for 

coal shipments on a tonnage basis, which occurs between successive years for coal shipments. An east index is used for 

coal originating from coal supply regions located east of the Mississippi River while a west index is used for coal originating from coal supply regions located west of the Mississippi River. The east index is a function of railroad productivity, 

the user cost of capital for railroad equipment, and national average diesel fuel price. The user cost of capital for railroad 

equipment is calculated from the producer price index (PPI) for railroad equipment, and accounts for the opportunity cost 

of money used to purchase equipment, depreciation occurring as a result of use of the equipment (assumed at 10%), 

less any capital gain associated with the worth of the equipment. In calculating the user cost of capital, three percentage 

points are added to the cost of borrowing in order to account for the possibility that a national level program to regulate greenhouse gas emissions may be implemented in the future. The west index is a function of railroad productivity, 

investment, and the western share of national coal consumption. The indices are universally applied to all domestic coal 

transportation movements within the CMM. In the AEO2014 Reference case, both eastern and western coal transportation rates are projected to remain near their 2012 levels in 2012 dollars.

Figure 12. Coal Demand Regions

Source: U.S. Energy Information Administration, Office of Energy Analysis.

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•	 For the projection period, the explanatory variables are assumed to have varying impacts on the calculation of the indices. For 

the west, investment is the analogous variable to the user cost of capital of railroad equipment. The investment value and the 

PPI for rail equipment, which is used to derive the user cost of capital, increase with an increase in national ton-miles (total 

tons of coal shipped multiplied by the average distance). Increases in investment (west) or the user cost of capital for railroad equipment (east) cause projected transportation rates to increase. For both the east and the west, any related financial 

savings due to productivity improvements are assumed to be retained by the railroads and are not passed on to shippers in 

the form of lower transportation rates. For that reason, transportation productivity is held flat for the projection period for 

both regions. For the projection period, diesel fuel is removed from the equation for the east in order to avoid double-counting 

the influence of diesel fuel costs with the impact of the fuel surcharge program. The transportation rate indices for seven 

AEO2014 cases are shown in Table 12.2.

Table 12.2. Transportation rate multipliers

constant dollar index, 2012=1.000

Scenario Region: 2012 2020 2025 2030 2035 2040

Reference Case East 1.0000 1.0224 1.0121 1.0086 1.0074 1.0083

West 1.0000 1.0051 1.0140 1.0117 1.0036 0.9964

Low Oil Price East 1.0000 1.0182 1.0091 1.0045 1.0003 1.0053

West 1.0000 1.0125 1.0250 1.0303 1.0177 1.0148

High Oil Price East 1.0000 1.0360 1.0175 1.0122 1.0137 1.0156

West 1.0000 0.9943 1.0038 1.0002 0.9944 1.0025

Low Economic Growth East 1.0000 1.0294 1.0195 1.0186 1.0214 1.0028

West 1.0000 1.0008 1.0043 1.0019 0.9952 0.9857

High Economic Growth East 1.0000 1.0177 1.0076 1.0036 1.0027 1.0037

West 1.0000 1.0141 1.0229 1.0223 1.0152 1.0053

Low Coal Cost East 1.0000 0.9600 0.9000 0.8500 0.8000 0.7600

West 1.0000 0.9400 0.9000 0.8500 0.8000 0.7500

High Coal Cost East 1.0000 1.0900 1.1200 1.1700 1.2100 1.2600

West 1.0000 1.0700 1.1300 1.1700 1.2100 1.2500

Source: Projections: U.S. Energy Information Administration, National Energy Modeling System runs REF2014.D102413A, LOWPRICE.D120613A, HIGHPRICE.

D120613A, LOWMACRO.D112913A, HIGHMACRO.D112913A, LCCST14.D120413A, and HCCST14.D120413A. Based on methodology described in Coal Market 

Module of the National Energy Modeling System 2014, DOE/EIA-M060(2014) (Washington, DC, 2014).

•	 Major coal rail carriers have implemented fuel surcharge programs in which higher transportation fuel costs have been passed 

on to shippers. While the programs vary in their design, the Surface Transportation Board (STB), the regulatory body with 

limited authority to oversee rate disputes, recommended that the railroads agree to develop some consistencies among their 

disparate programs and likewise recommended closely linking the charges to actual fuel use. The STB cited the use of a 

mileage-based program as one means to more closely estimate actual fuel expenses.

•	 For AEO2014, representation of a fuel surcharge program is included in the coal transportation costs. For the west, the methodology is based on BNSF Railway Company’s mileage-based program. The surcharge becomes effective when the projected 

nominal distillate price to the transportation sector exceeds $1.25 per gallon. For every $0.06 per gallon increase above $1.25, 

a $0.01 per carload mile is charged. For the east, the methodology is based on CSX Transportation’s mileage-based program. 

The surcharge becomes effective when the projected nominal distillate price to the transportation sector exceeds $2.00 per 

gallon. For every $0.04 per gallon increase above $2.00, a $0.01 per carload mile is charged. The number of tons per carload 

and the number of miles vary with each supply and demand region combination and are a pre-determined model input. The 

final calculated surcharge (in constant dollars per ton) is added to the escalator-adjusted transportation rate. For every projection year, it is assumed that 100% of all coal shipments are subject to the surcharge program.

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•	 Coal contracts in the CMM represent a minimum quantity of a specific electricity coal demand that must be met by a unique 

coal supply source prior to consideration of any alternative sources of supply. Base-year (2012) coal contracts between coal 

producers and electricity generators are estimated on the basis of receipts data reported by generators on the Form EIA-923, 

“Power Plant Operations Report”. Coal contracts are specified by CMM supply region, coal type, demand region, and whether 

or not a unit has flue gas desulfurization equipment. Coal contract quantities are reduced over time on the basis of contract 

duration data from information reported on the Form EIA-923, “Power Plant Operations Report”, historical patterns of coal use, 

and information obtained from various coal and electric power industry publications and reports. 

•	 Coal-to-liquids (CTL) facilities are assumed to be economic when low-sulfur distillate prices reach high enough levels. These 

plants are assumed to be co-production facilities with generation capacity of 832 megawatts (MW) (295 MW for the grid 

and 537 MW to support the conversion process) and the capability of producing 48,000 barrels of liquid fuels per day. The 

technology assumed is similar to an integrated gasification combined cycle, first converting the coal feedstock to gas, and 

then subsequently converting the syngas to liquid hydrocarbons using the Fisher-Tropsch process. Of the total amount of coal 

consumed at each plant, 40% of the energy input is retained in the product with the remaining energy used for conversion and 

for the production of power sold to the grid. For AEO2014, coal-biomass-to-liquids (CBTL) are not modeled. CTL facilities 

produce paraffinic naptha used in plastics production and blendable naptha used in motor gasoline (together about 28% of the 

total by volume) and distillate fuel oil (about 72%).

Coal imports and exports

Coal imports and exports are modeled as part of the CMM’s linear program that provides annual projections of U.S. steam and 

metallurgical coal exports, in the context of world coal trade. The CMM projects steam and metallurgical coal trade flows from 17 

coal-exporting regions of the world to 20 import regions for two coal types (steam and metallurgical). It includes five U.S. export 

regions and four U.S. import regions. The linear program determines the pattern of world coal trade flows that minimizes the 

production and transportation costs of meeting U.S. import demand and a pre-specified set of regional coal import demands. It 

does this subject to constraints on export capacity and trade flows.

The key assumptions underlying coal export modeling are:

•	 Coal buyers (importing regions) tend to spread their purchases among several suppliers in order to reduce the impact of 

potential supply disruptions, even though this may add to their purchase costs. Similarly, producers choose not to rely on any 

one buyer and instead endeavor to diversify their sales.

•	 Coking coal is treated as homogeneous. The model does not address quality parameters that define coking coals. The values 

of these quality parameters are defined within small ranges and affect world coking coal flows very little. 

The data inputs for coal trade modeling are:

•	 World steam and metallurgical coal import demands for the AEO2014 cases (Tables 12.3 and 12.4). U.S. coal exports are 

determined, in part, by these estimates of world coal import demand. 

•	 Step-function coal export supply curves for all non-U.S. supply regions. The curves provide estimates of export prices per metric ton, inclusive of minemouth and inland freight costs, as well as the capacities for each of the supply steps.

•	 Ocean transportation rates (in dollars per metric ton) for feasible coal shipments between international supply regions and international demand regions. The rates take into account typical vessel sizes and route distances in thousands of nautical miles 

between supply and demand regions.

Coal quality

Each year the values of base year coal production; heat, sulfur, and mercury content; and carbon dioxide emission factors for 

each coal source in CMM are calibrated to survey data. Surveys used for this purpose are the Form EIA-923, a survey of the 

origin, cost and quality of fossil fuels delivered to generating facilities, the Form EIA-3, which records the origin, cost, and quality 

of coal delivered to U.S. manufacturers, transformation and processing plants, and commercial and institutional users, and the 

Form EIA-5, which records the origin, cost and quality of coal delivered to domestic coke plants. Estimates of coal quality for the 

export sector are based on coal quality data collected on EIA surveys for domestic shipments. Mercury content data for coal by 

supply region and coal type, in units of pounds of mercury per trillion Btu, shown in Table 12.5, were derived from shipment-level 

data reported by electricity generators to the U.S. Environmental Protection Agency in its 1999 Information Collection Request. 

Carbon dioxide emission factors for each coal type, based on data published by the U.S. Environmental Protection Agency, are 

shown in Table 12.5 in units of pounds of carbon dioxide emitted per million Btu [3].

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Table 12.3. World steam coal import demand by import region1

million metric tons of coal equivalent

2012 2020 2025 2030 2035 2040

The Americas 30.8 29.3 28.7 29.4 32.2 32.9

 United States2 6.4 0.8 0.4 0.0 0.8 0.0

 Canada 3.5 2.0 1.2 0.7 0.7 0.7

 Mexico 6.0 6.6 6.5 7.1 7.5 7.5

 South America 14.9 19.9 20.6 21.6 23.2 24.7

Europe 165.9 188.5 185.8 181.7 176.7 172.6

 Scandinavia 8.2 6.6 5.9 5.0 4.6 4.1

 U.K./Ireland 36.0 29.2 26.4 24.6 22.8 20.1

 Germany/Austria/Poland 39.3 38.8 37.8 36.8 35.8 34.8

 Other NW Europe 15.4 21.6 20.5 19.5 18.5 17.5

 Iberia 17.5 17.3 16.9 16.9 15.7 14.0

 Italy 14.3 22.8 21.9 20.1 18.2 16.4

 Med/E Europe 35.2 52.2 56.4 58.8 61.1 65.7

Asia 561.0 626.6 684.5 739.1 795.9 849.0

 Japan 94.2 94.3 93.5 92.2 90.6 88.0

 East Asia 123.9 129.0 134.4 136.5 144.5 149.9

 China/Hong Kong 189.0 212.8 236.3 258.1 272.2 286.2

 ASEAN 44.1 60.0 79.3 94.9 113.0 131.2

 Indian Sub 109.8 130.5 141.0 157.4 175.6 193.7

TOTAL 757.7 844.4 899.0 950.2 1,004.8 1,054.5

1

Import Regions: United States: East Coast, Gulf Coast, Northern Interior, Non-Contiguous; Canada: Eastern, Interior; South America: Argentina, Brazil, 

Chile, Puerto Rico; Scandinavia: Denmark, Finland, Norway, Sweden; Other NW Europe: Belgium, France, Luxembourg, Netherlands; Iberia: Portugal, Spain; 

Med/E Europe: Algeria, Bulgaria, Croatia, Egypt, Greece, Israel, Malta, Morocco, Romania, Tunisia,

Turkey; East Asia: North Korea, South Korea, Taiwan; ASEAN: Malaysia, Philippines, Thailand, Vietnam; Indian Sub: Bangladesh, India, Iran, Pakistan, Sri 

Lanka.

2

Excludes imports to Puerto Rico and the U.S. Virgin Islands.

Notes: One “metric ton of coal equivalent” equals 27.78 million Btu. Totals may not equal sum of components due to independent rounding. 

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Table 12.4. World metallurgical coal import demand by import region1

million metric tons of coal equivalent

2012 2020 2025 2030 2035 2040

The Americas 21.6 31.0 34.0 37.0 41.0 47.1

 United States2 1.0 1.0 1.0 1.0 1.0 1.0

 Canada 4.5 3.9 3.9 3.7 3.6 3.5

 Mexico 1.0 1.5 1.5 1.5 1.5 3.1

 South America 15.1 24.6 27.7 30.8 34.9 39.5

Europe 57.1 62.1 60.9 59.9 59.8 59.8

 Scandinavia 2.9 2.7 2.7 2.7 2.7 2.7

 U.K./Ireland 5.6 6.0 6.0 6.0 6.0 6.0

 Germany/Austria/Poland 10.4 13.2 12.2 11.2 11.2 11.2

 Other NW Europe 13.1 14.7 14.5 14.4 14.2 14.1

 Iberia 2.2 3.9 3.8 3.8 3.6 3.5

 Italy 7.1 7.4 7.3 7.2 7.3 7.3

 Med/E Europe 15.8 14.2 14.4 14.6 14.8 15.0

Asia 193.9 240.3 256.7 266.3 274.0 280.0

 Japan 70.5 79.0 77.2 74.8 71.9 67.1

 East Asia 36.0 41.2 43.3 45.5 47.1 48.8

 China/Hong Kong 52.0 60.9 63.0 65.0 67.2 69.5

 ASEAN3 0.0 0.0 0.0 0.0 0.0 0.0

 Indian Sub 35.4 59.2 73.2 81.0 87.8 94.6

TOTAL 272.6 333.4 351.6 363.2 374.8 386.9

1

 Import Regions: United States: East Coast, Gulf Coast, Northern Interior, Non-Contiguous; Canada: Eastern, Interior; South America: Argentina, Brazil, Chile, 

Puerto Rico; Scandinavia: Denmark, Finland, Norway, Sweden; Other NW Europe: Belgium, France, Luxembourg, Netherlands; Iberia: Portugal, Spain; Med/E 

Europe: Algeria, Bulgaria, Croatia, Egypt, Greece, Israel, Malta, Morocco, Romania, Tunisia, Turkey; East Asia: North Korea, South Korea, Taiwan; ASEAN: 

Malaysia, Philippines, Thailand, Vietnam; Indian Sub: Bangladesh, India, Iran, Pakistan, Sri Lanka.

2

 Excludes imports to Puerto Rico and the U.S. Virgin Islands.

3

 Malaysia, Philippines, Thailand, and Vietnam are not expected to import significant amounts of metallurgical coal in the projection.

Notes: One “metric ton of coal equivalent” equals 27.78 million Btu. Totals may not equal sum of components due to independent rounding.

Legislation and regulations

The AEO2014 is based on current laws and regulations in effect before September 30, 2013. The Mercury Air Toxics Standard 

MATS), finalized in December 2011, is included in the AEO2014 Reference case as is the Clean Air Interstate Rule (CAIR). MATS 

sets emissions limits for mercury, other heavy metals, and acid gases from coal and oil power plants that are 25 MW or greater. 

Since generators are expected to request one-year extensions for compliance, MATS is assumed to be fully in place by 2016 rather 

than 2015 as stated in the regulation.

CAIR is a cap-and-trade program that regulates sulfur dioxide and nitrous oxide (NOx) emissions from fossil-fueled power plants 

with a nameplate capacity greater than 25 MW in 27 states and the District of Columbia. Initial implementation of CAIR for NOX

occurred in 2009 and for SO2 in 2010, with both caps subject to further tightening in 2015. The AEO2014 includes trading and 

banking of allowances consistent with CAIR’s provisions. States covered by CAIR can trade allowances amongst themselves or 

with non-CAIR states participating in the Clean Air Act Amendment Title IV program. Non-CAIR state allowances are considered 

less valuable than CAIR state allowances and are traded at a discounted rate. 

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Table 12.5. Production, heat content, sulfur, mercury and carbon dioxide emission factors by coal type and region

Coal Supply Region States

Coal Rank and Sulfur 

Level Mine Type

2012 

Production 

(million 

short tons)

Heat Content 

(million Btu 

per short ton)

Sulfur 

Content 

(pounds per 

million Btu)

Mercury 

Content 

(pounds per 

trillion Btu)

CO2

(pounds per 

million Btu)

Northern Appalachia

PA, OH, MD, 

WV (North) Metallurgical Underground 22.4 26.30 0.88 N/A 204.7

Mid-Sulfur 

Bituminous All 31.5 25.19 1.39 11.17 204.7

High-Sulfur 

Bituminous All 71.8 24.67 2.76 11.67 204.7

Waste Coal (Gob 

and Culm) Surface 11.0 11.60 3.65 63.90 204.7

Central Appalachia

KY (East), WV 

(South), VA, TN 

(North) Metallurgical Underground 54.9 26.30 0.62 N/A 206.4

Low-Sulfur 

Bituminous All 10.2 24.72 0.54 5.61 206.4

Mid-Sulfur 

Bituminous All 82.8 24.66 0.95 7.58 206.4

Southern Appalachia AL, TN (South) Metallurgical Underground 12.2 26.30 0.46 N/A 204.7

Low-Sulfur 

Bituminous All 0.2 26.20 0.50 3.87 204.7

Mid-Sulfur 

Bituminous All 7.0 24.43 1.37 10.15 204.7

East Interior

IL, IN, KY(West), 

MS

Mid-Sulfur 

Bituminous All 7.5 22.51 1.21 5.60 203.1

High-Sulfur 

Bituminous All 120.0 22.75 2.66 6.35 203.1

Mid-Sulfur Lignite Surface 3.0 10.36 0.96 14.11 216.5

West Interior

IA, MO, KS, AR, 

OK, TX (Bit)

High-Sulfur 

Bituminous Surface 1.6 21.25 1.44 21.55 202.8

Gulf Lignite TX (Lig), LA Mid-Sulfur Lignite Surface 36.8 13.46 1.26 14.11 212.6

High-Sulfur Lignite Surface 11.4 11.99 2.65 15.28 212.6

Dakota Lignite ND, MT (Lig) Mid-Sulfur Lignite Surface 27.8 13.21 1.29 8.38 219.3

Western Montana MT (Bit & Sub)

Low-Sulfur

Bituminous Underground 5.7 19.81 0.50 5.06 215.5

Low-Sulfur 

Subbituminous Surface 14.7 18.10 0.38 5.06 215.5

Mid-Sulfur 

Subbituminous Surface 16.0 17.25 0.77 5.47 215.5

Wyoming, 

Northern PRB

WY (Northern 

Powder River 

Basin

Low-Sulfur 

Subbituminous Surface 150.9 6.84 0.38 7.08 214.3

Mid-Sulfur 

Subbituminous Surface 2.4 16.22 0.68 7.55 214.3

Wyoming, 

Southern PRB

WY (Southern 

Powder River 

Basin)

Low-Sulfur 

Subbituminous Surface 235.0 17.63 0.28 5.22 214.3

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Table 12.5. Production, heat content, sulfur, mercury and carbon dioxide emission factors by coal type and region (cont)

Coal Supply Region States

Coal Rank and Sulfur 

Level Mine Type

2012 

Production 

(million 

short tons

Heat Content 

(million Btu 

per Short 

ton)

Sulfur 

Content 

(pounds per 

million Btu)

Mercury 

Content 

(pounds 

per trillion 

Btu)

CO2

(pounds per 

million Btu)

Western Wyoming

WY (Other basins, 

excluding Powder 

River Basin)

Low-Sulfur 

Subbituminous Underground 4.6 18.87 0.63 2.19 214.3

Low-Sulfur 

Subbituminous Surface 3.5 19.02 0.49 4.06 214.3

Mid-Sulfur 

Subbituminous Surface 4.9 19.54 0.79 4.35 214.3

Rocky Mountain CO, UT Metallurgical Underground 0.1 26.30 0.43 N/A 209.6

Low-Sulfur 

Bituminous Underground 40.0 22.74 0.51 3.82 209.6

Low-Sulfur 

Subbituminous Surface 5.5 19.93 0.51 2.04 212.8

Southwest AZ, NM

Low-Sulfur 

Bituminous Surface 7.6 24.54 0.56 4.66 207.1

Mid-Sulfur 

Subbituminous Surface 17.4 17.98

 

0.91 7.18 209.2

Mid-Sulfur 

Bituminous Underground 5.0 19.07 0.79 7.18 207.1

Northwest WA, AK

Low-Sulfur 

Subbituminous Surface 2.1 16.02 0.29 6.99 216.1

N/A = not available.

Source: U.S. Energy Information Administration, Form EIA-3, “Quarterly Coal Consumption and Quality Report, Manufacturing and Transformation/Processing 

Coal Plants and Commercial and Institutional Coal Users”; Form EIA-5, “Quarterly Coal Consumption and Quality Report, Coke Plants”; Form EIA-7A, “Coal 

Production and Preparation Report”, and Form EIA-923, “Power Plant Operations Report”. U.S. Department of Commerce, Bureau of the Census, “Monthly Report 

EM-545.” U.S. Environmental Protection Agency, Emission Standards Division, Information Collection Request for Electric Utility Steam Generating Unit,

Mercury Emissions Information Collection Effort (Research Triangle Park, NC, 1999). U.S. Environmental Protection Agency, Inventory of U.S. Greenhouse Gas 

Emissions and Sinks: 1990-2008, ANNEX 2 Methodology and Data for Estimating CO2 Emissions from Fossil Fuel Combustion, EPA 430-R-10-006 (Washington, 

DC, April 2010), Table A-37, http://www.epa.gov/climatechange/ghgemissions/usinventoryreport/archive.html.

The Energy Improvement and Extension Act of 2008 (EIEA) and Title IV, under Energy and Water Development, of the American 

Recovery and Revitalization Act of 2009 (ARRA), together, are assumed to result in the development of about 1 gigawatt of coalfired generating capacity with carbon capture and sequestration by the end of 2018.

EIEA was passed in October 2008 as part of the Emergency Economic Stabilization Act of 2008. Subtitle B provides investment 

tax credits for various projects sequestering CO2. Subtitle B of EIEA, which extends the payment of current coal excise taxes for 

the Black Lung Disability Trust Fund program of $1.10 per ton on underground-mined coal and $0.55 per ton on surface-mined 

coal from 2013 to 2018, is also represented in the AEO2014. Prior to the enactment of EIEA, contribution rates for the Black Lung 

Disability Trust Fund were to be reduced in 2014 to $0.50 per ton on underground-mined coal and to $0.25 per ton on surfacemined coal. Lignite production is not subject to the Black Lung Disability Trust Fund program’s coal excise taxes. 

Title IV under ARRA provides $3.4 billion for additional research and development on fossil energy technologies. This includes 

$800 million to fund projects under the Clean Coal Power Initiative (CCPI) program, focusing on projects that capture and 

sequester greenhouse gases or use captured carbon dioxide for enhanced oil recovery (EOR). The Hydrogen Energy California 

(HECA) project in Kern County, California and the Texas Clean Energy Project (TCEP) in Penwell, Texas include efforts to use 

captured carbon dioxide for EOR.

Title XVII of the Energy Policy Act of 2005 (EPACT2005) authorized loan guarantees for projects that avoid, reduce, or sequester 

greenhouse gasses. EPACT05 also provided a 20% investment tax credit for Integrated Coal-Gasification Combined Cycle (IGCC) 

capacity and a 15% investment tax credit for other advanced coal technologies. EIEA allocated an additional $1.25 billion in 

investment tax credits for IGCC and other advanced coal-based generation technologies. For the AEO2014, all of the EPACT 2005 

and EIEA investment tax credits are assumed to have been fully allocated and, therefore, not available for new, unplanned capacity 

builds in the NEMS Electricity Market Module.

162 U.S. Energy Information Administration | Assumptions to the Annual Energy Outlook 2014
Coal Market Module

Beginning in 2008, electricity generating units of 25 megawatts or greater were required to hold an allowance for each ton 

of CO2 emitted in nine Northeastern States as part of the Regional Greenhouse Gas Initiative (RGGI). The States currently 

participating in RGGI include Connecticut, Maine, Maryland, Massachusetts, Rhode Island, Vermont, New York, New Hampshire, 

and Delaware. RGGI is modeled in AEO2014 as an emissions reduction program for the Central Atlantic region. In the AEO2014, 

the impact on coal use is generally small, as the CO2 allowance price remains relatively low in the projections. 

The AEO2014 includes a representation of California Assembly Bill 32 (AB32), the California Global Warming Solutions Act of 

2006, which authorized the California Air Resources Board (CARB) to set California’s overall GHG emissions reduction goal to 

its 1990 level by 2020 and establish a comprehensive, multi-year program to reduce GHG emissions in California, including a 

cap-and-trade program. The cap-and-trade program features an enforceable cap on GHG emissions that will decline over time. 

In the AEO2014, an allowance price, representing the incremental cost of complying with AB32 cap-and-trade, is modeled in 

the NEMS Electricity Market Module via a region-specific emissions constraint. This allowance price increases the effective 

delivered price of coal, reducing its ability to compete with other generating sources such as natural gas which emits less CO2

per unit of electricity produced. 

In accordance with California Senate Bill 1368 (SB 1368), which established a greenhouse gas emission performance standard for 

electricity generation, the AEO2014 prohibits builds of new coal-fired generating capacity without carbon capture and storage 

(CCS) for satisfying electricity demand in California. SB 1368 limits the generating emissions rate for all power plants that 

California utilities build, invest in, or sign a long-term contract with to be no more than 1,100 pounds of CO2 per megawatthour, 

which is the approximate emissions rate for a new natural gas combined-cycle power plant [4].

Coal alternative cases

Coal Cost cases

In the Reference case, coal mine labor productivity is assumed to decline on average by 1.2% per year from 2012 to 2040. Miner 

wage rates increase by about 0.9% per year, and mine equipment costs remain constant in 2012 dollars. Eastern and western 

coal transportation rates are projected to remain near their 2012 levels in 2012 dollars.

In two alternative coal cost cases, productivity, average miner wages, equipment cost, and transportation rate assumptions were 

modified for 2014 through 2040 in order to examine the impacts on U.S. coal supply, demand, distribution, and prices. The key 

modeling assumptions for the alternative Coal Cost cases and Reference case are shown in Table 12.6. 

In the Low Coal Cost case, coal mine labor productivity is assumed to increase at an average rate of 1.0% per year from 2012 to 

2040. Coal mining wages, mine equipment costs, and other mine supply costs all are assumed to be about 24% lower (in 2012 

dollars) in 2040 in the Low Coal Cost case than in the Reference case. Coal transportation rates, excluding the impact of fuel 

surcharges, are assumed to be approximately 25% lower by 2040. In the international coal market, the price change for nonU.S. export supplies (e.g., coal exported to the international market from ports in Australia) is assumed to be roughly 10% less 

than the price change projected for U.S. coal exports.

In the High Coal Cost case, coal mine labor productivity is assumed to decline at an average rate of 4.0% per year from 2012 to 

2040. Coal miner wages, mine equipment costs, and other mine supply costs all are assumed to be about 31% higher in 2040 

in real terms in the High Coal Cost case than in the Reference case. Compared to the Reference case, coal transportation rates 

are assumed to be approximately 25% higher by 2040. In the international coal market, the price change for non-U.S. export 

supplies is assumed to be roughly 10% less than the price change projected for U.S. coal exports. The low and high coal cost 

cases represent fully integrated NEMS runs, with feedback from the Macroeconomic Activity, International, supply, conversion, 

and end-use demand modules.

No Greenhouse Gas Concern case

In the Reference case, to reflect the market reaction to potential future GHG regulation, a 3-percentage-point increase in the 

cost of capital for investments in new coal-fired power and coal-to-liquids plants without carbon capture and sequestration 

technology is assumed. These assumptions affect cost evaluations for the construction of new capacity but not the actual 

operating costs for new existing plants. This adjustment was first implemented for AEO2009. Beginning with AEO2012, a 

3-percentage-point increase in the cost of capital for investments in retrofits at existing coal plants is also applied for emission 

control equipment (excluding CCS). The No GHG concern case excludes the 3-percentage point increase in the cost of capital.

U.S. Energy Information Administration | Assumptions to the Annual Energy Outlook 2014 163
Coal Market Module

Table 12.6. Key modeling assumptions for AEO2014 reference and coal cost cases

constant dollar index, 2012=1.000, unless otherwise noted

2012 2020 2040 Growth Rate, 2012-2040

Low 

Cost Reference

High 

Cost

Low 

Cost Reference

High 

Cost

Low 

Cost Reference

High 

Cost

Cost Indices

Transportation Rte Multipliers

Eastern Railroads 1.000 0.960 1.022 1.090 0.760 1.008 1.260 -1.0% 0.0% 0.8%

Western Railroad 1.000 0.940 1.005 1.070 0.750 0.996 1.250 -1.0% 0.0% 0.8%

Mine Equipment Costs

Underground 1.000 0.932 1.000 1.072 0.762 1.000 1.308 -1.0% 0.0% 1.0%

Surface 1.000 0.932 1.000 1.072 0.762 1.000 1.308 -1.0% 0.0% 1.0%

Other Mine Supply Costs

East of the 

Mississippi: 

 All Mines 1.000 0.932 1.000 1.072 0.762 1.000 1.308 -1.0% 0.0% 1.0%

West of the 

Mississippi: 

 Underground 1.000 0.932 1.000 1.072 0.762 1.000 1.308 -1.0% 0.0% 1.0%

West of the 

Mississippi: 

 Surface 1.000 0.932 1.000 1.072 0.762 1.000 1.308 -1.0% 0.0% 1.0%

Coal Mining Labor 

Productivity

(short tons per miner 

per hour) 1.000 5.52 4.64 3.85 6.89 3.68 1.68 1.0% -1.2% -4.0%

Average Coal Miner 

Wage

(2012 dollars per year) 80,450 87,295 93,666 100,431 79,835 104,525 136,440 0.0% 0.9% 1.9%

Sources: 2012 data based on: U.S. Energy Information Administration (EIA), Annual Coal Report 2012, DOE/EIA-0584(2012) 

(Washington, DC, December 2013); and U.S. Department of Labor, Bureau of Labor Statistics, Quarterly Census of Employment 

and Wages: Coal Mining, Series ID : ENUUS0005052121; Projections: EIA, AEO2014 National Energy Modeling System runs 

LCCST14.D120413A, REF2014.D102413A, and HCCST14.D120413A.

Notes and sources

[1] Flynn, Edward J., “Impact of Technological Change and Productivity on The Coal Market,” U.S. Energy Information 

Administration (Washington, DC, October 2000), http://www.eia.gov/oiaf/analysispaper/pdf/coal.pdf; and U.S. Energy 

Information Administration, The U.S. Coal Industry, 1970-1990: Two Decades of Change, DOE/EIA-0559 (Washington, DC, 

November 1992).

[2] The estimated cost of switching to subbituminous coal, $0.10 per million Btu (2000 dollars), was derived by Energy 

Ventures Analysis, Inc. and was recommended for use in the CMM as part of an Independent Expert Review of the Annual 

Energy Outlook 2002’s Powder River Basin production and transportation rates. Barbaro, Ralph and Schwartz,Seth, Review of 

the Annual Energy Outlook 2002 Reference Case Forecast for PRB Coal, prepared for the Energy Information Administration 

(Arlington, VA: Energy Ventures Analysis, Inc., August 2002).

[3] U.S. Environmental Protection Agency, Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2008, Annex 2 

Methodology and Data for Estimating CO2 Emissions from Fossil Fuel Combustion, EPA 430-R-10-006 (Washington, DC, April 

2010), Table A-37, http://www.epa.gov/climatechange/ghgemissions/usinventoryreport/archive.html.

[4] California Energy Commission, SB 1368 Emission Performance Standards, http://www.energy.ca.gov/emission_standards/

index.html.

164 U.S. Energy Information Administration | Assumptions to the Annual Energy Outlook 2014