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 2010, DOE/EIA-M060(2010)
(Washington, DC, 2010).
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. Forty separate supply
curves are developed for each of 14 supply regions, nine coal types (unique
combinations of thermal grade and sulfur content), and two mine types (underground
and surface). 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 percent 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 1999, U.S. coal mining productivity increased at an average
rate of 6.7 percent per year from 1.93 to 6.61 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 1999, however, growth in overall U.S. coal mining productivity
has slowed substantially, decreasing at a rate of 1.1 percent per year
to 5.96 tons per miner hour in 2008. By region, productivity in most of
the coal producing basins represented in the CMM has declined some during
the past 5 years. In the Central Appalachian coal basin, which has been
mined extensively, productivity declined by a significant 33 percent between
1999 and 2008, corresponding to an average decline of 4.4 percent per year.
Over the projection period, labor productivity is expected to decline in
most coal supply regions, reflecting the trend of the previous five years.
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 40 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. [2] Data on
labor productivity are provided on a quarterly and annual basis by individual
coal mines and preparation plants on the U.S. Mine Safety and Health Administration’s
Form 7000-2, “Quarterly Mine Employment and Coal Production Report” and
the Energy Information Administration’s Form EIA-7A, Coal Production Report.
In the reference case, overall U.S. coal mining labor productivity declines
at rate of 0.3 percent a year between 2008 and 2035. Reference case projections
of coal mining productivity by region are provided in Table 12.1.
- With the exception of the AEO2010 Low and High Coal Cost Cases, both the
wage rate for U.S. coal miners and mine equipment costs are assumed to
remain constant in 2008 dollars (i.e., increase at the general rate of
inflation) over the projection period. This assumption primarily reflects
the recent trends in these cost variables.
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
10) and 16 demand regions (Figure 11) for 49 demand subsectors.
The projected levels of coal-to-liquids, industrial steam, coking, and
residential/commercial coal demand are provided by the petroleum market,
industrial, commercial, and residential demand modules, respectively; electricity
coal demands are projected by the EMM; coal imports and coal exports are
projected by the CMM based on non-U.S. coal supply availability, endogenously
determined U.S. import demand, and exogenously determined world coal demand
(non-U.S.).
The key assumptions underlying the coal distribution modeling are:
- Base-year (2008) 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 Report-Manufacturing
Plants, Form EIA-5, Quarterly Coke 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 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). [3]
- 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, on a tonnage basis, that occurs between successive years for coal
shipments. An east index is used for coal originating from eastern supply
regions while a west index is used for coal originating from western supply
regions. 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 percent),
less any capital gain associated with the worth of the equipment. In calculating
the user cost of capital, a risk premium is added to the cost of borrowing
in order to account for the possibility that greenhouse gas emissions may
be regulated in the future. The west index is a function of railroad productivity,
investment, and western share of national coal consumption. The indices
are universally applied to all domestic coal transportation movements within
the CMM. In the AEO2010 reference case, eastern coal transportation rates
are projected to be the same in 2035 and western rates are projected to
be 5 percent higher in 2035 compared to 2008.
- For the projection period, the explanatory values 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, productivity
is held flat for the projection period for both regions. For the east
for the projection period, diesel fuel is removed from the equation 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 AEO2010 cases are shown in Table 12.2.
- 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 AEO2010, 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 percent of all
coal shipments are subject to the surcharge program.
- 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 (2008) coal contracts
between coal producers and electricity generators are estimated on the
basis of receipts data reported by generators on the 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.
- Electric generation demand received by the CMM is subdivided into “coal
groups” representing demands for different sulfur and thermal heat content
categories. This process allows the CMM to determine the economically optimal
blend of different coals to minimize delivered cost, while meeting emissions
requirements. Similarly, nongeneration demands are subdivided into subsectors
with their own coal groups to ensure that, for example, lignite is not
used to meet a coking coal demand.
- 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 652 MW and the
capability of producing 50,000 barrels of liquid fuel 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, 46 percent of the energy
input is retained in the product with the remaining energy used for conversion
(38 percent) and for the production of power sold to the grid (17 percent).
The liquid products produced include naptha, kerosene, and diesel. For AEO2010, coal-biomass-to-liquids capability has been incorporated into
the NEMS structure. These facilities have the same operating features
as CTL plants except 80 percent of the energy input is derived from coal
with the remaining 20 percent derived from biomass.
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 linear program determines the pattern
of world coal trade flows that minimize the production and transportation
costs of meeting U.S. import demand and a pre-specified set of regional
world 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.
Data inputs for coal trade modeling:
- U.S. coal exports are determined, in part, by the projected level of world
coal import demand. World steam and metallurgical coal import demands for
the AEO2010 cases are shown in Tables 12.3 and 12.4.
- 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
(Hg) content and carbon dioxide emissions 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-5 which records the origin, cost,
and quality of coal receipts at domestic coke plants, and the Form EIA-3,
which records the origin, cost and quality of coal delivered to domestic
industrial consumers. Estimates of coal quality for the export and residential/commercial
sectors are made using the survey data for coal delivered to coking coal
and industrial steam coal consumers. Hg content data for coal by supply
region and coal type, in units of pounds of Hg per trillion Btu, shown
in Table 71, were derived from shipment-level data reported by electricity
generators to the Environmental Protection Agency in its 1999 Information
Collection Request. The database included approximately 40,500 Hg samples
reported for 1,143 generating units located at 464 coal-fired facilities.
Carbon dioxide emission factors for each coal type are shown in Table
12.5 in pounds of carbon dioxide emitted per million Btu. [4]
The CMM projects steam and metallurgical coal trade flows from 17 coal-exporting
regions of the world to 20 import regions for three coal types (coking,
bituminous steam, and subbituminous). It includes five U.S. export regions
and four U.S. import regions.
Legislation and Regulations
The AEO2010 is based on current laws and regulations in effect before October
31, 2009.
The AEO2010 reference case incorporates provisions of the Clean Air Act
Amendments of 1990 as they apply to SO2 and NOx emissions.
The Clean Air Mercury Rule (CAMR) and the Clean Air Interstate Rule (CAIR)
are additional rules promulgated by EPA related to coal emissions but were
vacated by the courts in February and July 2008, respectively. CAIR addresses
further SO2 emissions and seasonal and annual NOx emissions while CAMR
addresses mercury emissions. As a result of the court ruling, CAMR is
not included in the AEO2010 reference case and, in the absence of a cap-and-trade
system, mercury allowance prices are not modeled. However, with or without
CAMR, many States were planning to implement mercury rules of their own.
For those States, the effects of state laws are approximated and modeled
for the AEO2010. CAIR, however, was temporarily reinstated by the courts
in December 2008 and is included in AEO2010.
The Energy Improvement and Extension Act of 2008 (EIEA) 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.
These provisions are assumed to result in 1 gigawatt of advanced coal-fired
capacity with carbon capture and sequestration by 2017 in the AEO2010 reference
case. Subtitle B also extends the phaseout of payments by coal producers
to the Black Lung Disability Trust Fund from 2013 to 2018 and is also modeled
in the AEO2010.
Title IV, under Energy and Water Development, of the American Recovery
and Revitalization Act of 2009 (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. In July
2009, a total of $408 million, was allocated to two projects, the Basin
Electric Power Cooperative’s Antelope Valley Station in North Dakota and
the Hydrogen Energy Project in California, to collectively demonstrate
the capability to capture 3,000,000 tons of carbon dioxide per year. In
December 2009, three additional project awards were announced through the
CCPI program and will receive part of their government funding through
ARRA. These projects include American Electric Power’s Mountaineer plant
in West Virginia (235 megawatt flue gas stream), Alabama Power’s Barry
plant in Alabama (160 megawatt flue gas stream), and a new plant to be
built by Summit Texas Clean Energy in Texas. To reflect the impact of this
provision, the AEO2010 reference case assumes that an additional 1 gigawatt
of coal capacity with CCS will be stimulated by 2017.
Title XVII of the Energy Policy Act of 2005 authorizes loan guarantees
for projects that avoid, reduce, or sequester greenhouse gasses. For AEO2010,
The 2 gigawatts of advanced coal-fired capacity with carbon capture and
sequestration assumed for EIEA and ARRA are also assumed to benefit from
these loan guarantees.
Beginning in 2009, electricity generating units of 25 megawatts and greater
are required to hold an allowance for each ton of CO2 emitted in 10 Northeastern
States as part of the Regional Greenhouse Gas Initiative (RGGI). The States
participating in RGGI include Connecticut, Maine, Maryland, Massachusetts,
Rhode Island, Vermont, New York, New Jersey, New Hampshire, and Delaware.
RGGI is modeled in AEO2010 as an emissions reduction for the Middle Atlantic
region.
Coal Alternative Cases
Coal Cost Cases
In the reference case, coal mine labor productivity is assumed to decline
on average by 0.3 percent per year through 2035 while miner wage rates
and mine equipment costs remain constant in 2008 dollars. Eastern and
Western transportation rates are flat and 5 percent higher, respectively,
in 2035 compared to 2008. In two alternative coal cost cases, productivity,
average miner wages, equipment cost, and transportation rate assumptions
were modified for 2010 through 2035 in order to examine the impacts on
U.S. coal supply, demand, distribution and prices.
In the low mining cost case, coal mine labor productivity is assumed to
increase at an average rate of 3.2 percent per year through 2035. Coal
mining wages, mine equipment costs, and other mine suppy costs are all
assumed to be about 25 percent lower by 2035 in real terms in the low coal
cost case. Coal transportation rates, excluding the impact of fuel surcharges,
are assumed to be 25 percent lower by 2035.
In the high mining cost case, coal mine labor productivity is assumed to
decline at an average rate of 3.0 percent per year through 2035. Coal
mining wages, mine equipment costs, and other mine supply costs are assumed
to be about 30 percent higher by 2035. Compared to the reference case,
coal transportation rates are assumed to be 25 percent higher by 2035.
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 plants without carbon capture and sequestration
technology and new coal-to-liquids plants is assumed. Those assumptions
affect cost evaluations for the construction of new capacity but not the
actual operating costs when a new plant begins operation nor does it affect
the operation of existing plants. This adjustment was first implemented
for AEO2009.
The No GHG concern case excludes the 3-percentage point increase in the
cost of capital.
Coal - Tables
Coal Market Module Notes |
