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 2008, DOE/EIA-M060(2008)
(Washington, DC, 2008).
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, and the cost of factor inputs
(labor and fuel).
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 0.8 percent per year
to 6.26 tons per miner hour in 2006. By region, productivity in most of
the coal producing basins represented in the CMM has remained essentially
constant during the past 5 years. In the Central Appalachian coal basin,
which has been mined extensively, productivity declined by a significant
28 percent between 1999 and 2006, corresponding to an average decline of
4.6 percent per year.
Over the projection period, labor productivity is expected to remain near
current levels 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 increases
at rate of 0.6 percent a year between 2006 and 2030. Reference case projections
of coal mining productivity by region are provided in Table 67.
In theAEO2008 scenarios, both the wage rate for U.S. coal miners and mine
equipment costs are assumed to remain constant in 2006 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.
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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 14 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 (2006) 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-423, Monthly Cost and Quality of Fuels for Electric Plants
Report, Federal Energy Regulatory Commission (FERC) Form 423, Monthly Report
of Cost and Quality of Fuels for Electric Plants, 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 are measures of the change in average transportation rates, on
a tonnage basis, that occurs between successive years for rail and multi-mode
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 indices are calculated econometrically as a function
of railroad productivity, the user cost of capital of railroad equipment,
average contract duration, and average distance (west only). Although
the indices are derived from railroad information, they are universally
applied to all domestic coal transportation movements within the CMM.
In the AEO2008 reference case, eastern coal transportation rates are projected
to be 1 percent higher in 2030 and western rates are projected to be 2
percent higher in 2030 compared to 2006.
- Railroad productivity, measured in freight ton-miles per employee per year, is expected to increase at an average rate of 2.9 percent per year for
the east and 1.8 percent per year for the west from 2006. The user cost
of capital for railroad equipment is calculated from the PPI for railroad
equipment, projected exogenously to remain flat in real terms, 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. Contract
duration is held constant at 2001 levels over the projection reflecting
the assumption that new contracts will continue to be, on average, less
than 5 years in length. For the west, distance is held constant over the
projection reflecting that distance is already implicitly accounted for
in the model by using the origin-destination pair transportation rate structure.
The transportation rate indices for seven AEO2008 cases are shown in Table
68.
- 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, has
recommended that the railroads agree to develop some consistencies among
their disparate programs and has likewise recommended closely linking the
charges to actual fuel use. The STB has cited the use of a mileage-based
program as one means to more closely estimate actual fuel expenses.
- For AEO2008, 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 (2006) coal contracts
between coal producers and electricity generators are estimated on the
basis of receipts data reported by electric utilities on FERC Form 423, Monthly Report of Cost and Quality of Fuels for Electric Plants, and by
nonutility generators on Form EIA-423, Monthly Cost and Quality of Fuels
for Electric Plants 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 reported by electric utilities on
FERC Form 580, “Interrogatory on Fuel and Energy Purchase Practices,” 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).
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:
- The coal market is competitive. In other words, no large suppliers or groups
of producers are able to influence the price through adjusting their output.
Producers’ decisions on how much and who they supply are driven by their
costs, rather than prices being set by perceptions of what the market can
bear. In this situation, the buyer gains the full consumer surplus.
- 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 AEO2008 cases are shown in Tables 69 and 70.
- 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 maximum vessel sizes that can be
handled at export and import piers and through canals and reflect route
distances in thousands of nautical miles.
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 FERC
Form 423, a survey of the origin, cost and quality of fossil fuels delivered
to electric utilities, the Form EIA-423, a survey of the origin, cost and
quality of fossil fuels delivered to non-utility 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 71 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 AEO2008 reference case incorporates provisions of the Clean Air Act
Amendments of 1990 as they apply to sulfur dioxide and nitrogen oxide emissions.
EPA finalized the Clean Air Interstate Rule (CAIR) and the Clean Air Mercury
Rule (CAMR) in March 2005, and both are represented in the reference case.
For affected states, CAIR further restricts emissions of sulfur dioxide
beginning in 2010 to 3.6 million tons and nitrogen oxides beginning in
2009 to 1.5 million tons. Beginning in 2015, for affected states, tighter
emission limits for sulfur dioxide (2.5 million tons) and nitrogen oxides
(1.3 million tons) are required in Phase 2 of CAIR. A nationwide cap for
mercury of 38 tons per year beginning in 2010 and then 15 tons per year
beginning in 2018 are specified in CAMR. The reference case excludes any
potential environmental actions not currently mandated such as carbon dioxide
reductions or other rules or regulations not finalized.
Coal Alternative Cases
Coal Cost Cases
In the reference case, coal mine labor productivity is assumed to increase
on average by 0.6 percent per year through 2030 while miner wage rates
and mine equipment costs remain constant in 2006 dollars. Eastern and
western railroad productivity is assumed to grow at an average rate of
2.9 and 1.8 percent respectively from 2006. Railroad equipment costs are
assumed to remain flat in real terms from 2006 levels. In two alternative
coal cost cases, productivity, average miner wages, and equipment cost
assumptions were modified for 2009 through 2030 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 3.7 percent per year through 2030. Miner
wages are assumed to decline in constant dollars by 1.0 percent per year.
Mine equipment costs and railroad equipment costs are projected to fall
by 1.0 percent. In the low mining cost case, eastern and western railroad
productivity is assumed to grow at an average rate of 5.3 and 4.2 percent,
respectively from 2006.
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 2030. Miner
wages are assumed to increase in constant dollars by 1.0 percent per year.
Mine equipment costs and railroad equipment costs are projected to increase
by 1.0 percent. In the high mining cost case, eastern railroad productivity
is assumed to increase by 0.5 percent per year and western railroad productivity
is assumed to decrease by 0.6 percent per year from 2006.
For the coal cost cases, adjustments to the reference case coal mining
and railroad productivity assumptions were based on variations in growth
rates observed in the data for these industries since 1980. 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.
Coal Market Module Notes |