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 2009, DOE/EIA-M060(2009)
(Washington, DC, 2009).
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 0.9 percent per year
to 6.27 tons per miner hour in 2007. 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 29 percent between
1999 and 2007, corresponding to an average decline of 4.2 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 0.2 percent a year between 2007 and 2030. Reference case projections
of coal mining productivity by region are provided in Table 12.1.
- With the exception of the AEO2009 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 2007 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 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 (2007) 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,
calculated econometrically, are measures of the change in average transportation
rates, on a tonnage basis, that occurs between successive years for coal
shipments. The methodology used to formulate these indices was revised
for the AEO2009. 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 for railroad equipment, projected 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. 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 AEO2009 reference case, eastern coal transportation rates
are projected to be 4 percent higher in 2030 and western rates are projected
to be 18 percent higher in 2030 compared to 2007.
- For the projection period, the explanatory values are assumed to have varying
impacts on the calculation of the indices. 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. For the west, investment is the analogous variable to the
user cost of capital of railroad equipment. The investment value increases
with an increase in western coal tons. 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 AEO2009 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, 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 AEO2009, 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 (2007) 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 from preliminary information reported
on the Form EIA-923, Power Plant Operation Report for 2008, 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 AEO2009 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 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 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 AEO2009 is based on current laws and regulations in effect before November
5, 2008.
The AEO2009 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 addressed
further SO2 emissions and seasonal and annual NOx emissions while CAMR
addressed mercury emissions. As a result of the court rulings, CAIR and
CAMR are not included in the AEO2009 reference case and, in the absence
of a cap-and-trade system, mercury, SO2 and NOX 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 AEO2009. CAIR was partly intended
to help States meet their National Ambient Air Quality Standards (NAAQS)
for ozone and particulate matter.
For AEO2009, although CAIR is not modeled, States are still required to
comply with the NAAQS and are projected to do so through the addition of
emission control equipment and the elimination of higher sulfur coal consumption
at unscrubbed electricity plants after 2014.
The Energy Improvement and Extension Act of 2008 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 AEO2009 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 AEO2009.
Title XVII of the Energy Policy Act of 2005 authorizes loan guarantees
for projects that avoid, reduce, or sequester greenhouse gasses. For AEO2009,
1.2 gigawatts of advanced coal-fired power plants are 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 AEO2009 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 0.2 percent per year through 2030 while miner wage rates
and mine equipment costs remain constant in 2007 dollars. Eastern and
Western transportation rates are 4 and 18 percent higher, respectively,
in 2030 compared to 2007. In two alternative coal cost cases, productivity,
average miner wages, equipment cost, and transportation rate assumptions
were modified for 2010 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 3.6 percent per year through 2030. Coa
mining wages, mine equipment costs, and other mine suppy costs are all
assumed to be about 20 percent lower by 2030 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 2030, decreasing at a rate of 1.4
percent per year from 2009.
In the high mining cost case, coal mine labor productivity is assumed to
decline at an average rate of 3.6 percent per year through 2030. Coal
mining wages, mine equipment costs, and other mine supply costs are assumed
to be about 20 percent higher by 2030. Compared to the reference case,
coal transportation rates are assumed to be 25 percent higher by 2030,
increasing at a rate of 1.1 percent per year from 2009.
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 |
