Coal Market Module

The NEMS Coal Market Module (CMM) provides forecasts of U.S. coal production, consumption, exports, 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 2001, DOE/EIA-M060(2001) January 2001.

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 forecast. Separate supply curves are developed for each of 11 supply regions, and 12 coal types (unique combinations of thermal grade, sulfur content, and mine type).   The modeling approach used to construct regional coal supply curves addresses the relationship between the minemouth price of coal and corresponding levels of coal production, labor productivity, and the cost of factor inputs (mining equipment, mine labor, and fuel requirements).

The key assumptions underlying the coal production modeling are:

• Mining costs are assumed to vary with changes in mine production, labor productivity, and factor input costs.  Factor input costs are represented by projections of electricity prices from the Electricity Market Module (EMM) and estimates of future coal mine labor and mining equipment costs.  

• Between 1979 and 1999, U.S. coal mining productivity (measured in short tons of coal produced per miner per hour) increased at an estimated average rate of 6.7 percent per year.  The major factors underlying these gains were interfuel price competition, structural change in the industry, and technological improvements in coal mining.107  Based on the expectation that further penetration of certain more productive mining technologies, such as longwall methods and large capacity surface mining equipment, will gradually level off, productivity improvements are assumed to continue, but to decline in magnitude. Different rates of improvement are assumed by region and by mine type, surface and underground. On a national basis, labor productivity increases on average at a rate of 2.2 percent a year over  the entire forecast, declining from an estimated annual rate of 5.9 percent in 1999 to approximately 1.2 percent over the 2010 to 2020 period. These estimates are based on recent historical data reported on Form EIA-7A, Coal Production Report, and expectations regarding the penetration and impact of new coal mining technologies.108

• Between 1985 and 1993, the average hourly wage for U.S. coal miners (in 1999 dollars) declined at an average rate of 1.5 percent per year, falling from $21.67 to $19.18.109  During this same time period the producer price index (PPI) for mining machinery and equipment (in 1999 dollars) declined by 0.6 percent per year, falling from 159.1 to 152.1.110  In the reference case, both the wage rate for U.S. coal miners and mine equipment costs are to remain constant in 1999 dollars (i.e., increase at the general rate of inflation).  This assumption reflects the more recent trend in wages and mine equipment costs that has prevailed since 1993.  In 1999, the average hourly wage rate for coal miners was $19.34, and the PPI for mining machinery and equipment was 153.2.

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 in each demand region using a linear programming algorithm.  Production and distribution are computed for 11 supply and 13 demand regions for 18 demand subsectors.

The projected levels of industrial, coking, and residential/commercial coal demand are provided by the industrial, commercial, and residential demand modules; electricity coal demands are provided by the EMM, and coal export demands are provided from the CMM itself.

The key assumptions underlying the coal distribution modeling are:

• Base-year transportation costs are estimates of average transportation costs for each origin-destination pair.  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, Coke Plant Report-Quarterly, 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.

• Coal transportation costs are modified over time in response to projected variations in reference case fuel costs (No. 2 diesel fuel in the industrial sector), labor costs, the producer price index for transportation equipment, and a time trend. The transportation rate multipliers used for all five AEO2001 cases are shown in Table 73.

• Electric utility 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 the sulfur emissions requirements of the Clean Air Act Amendments of 1990.  Similarly, nonutility 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.

Table 73.  Transportation Rate Multipliers

Coal Exports

Coal exports are modeled as part of the CMM’s linear program that provides annual forecasts 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 a prespecified set of regional world coal import demands.  It does this subject to constraints on export capacity and trade flows.

The CMM projects steam and metallurgical coal trade flows from 16 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.

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 disruption, even though this adds 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 export 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 AEO2001 forecast cases are shown in Tables 74 and 75.

Table 74.  World Steam Coal Import Demand by Import Region, 1999-2020

Table 75.  World Metallurgical Coal Import Demand by Import Region, 1999-2020

• 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 thousand nautical miles.

Coal Quality

Each year the values of base year coal production, heat content, sulfur and carbon emissions for each coal source in the Coal Market Module of the NEMS 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 FERC 867 which records the quality of coal receipts at independent power producers, the Form EIA5 and 5a which record the origin, cost, and quality of coal receipts at domestic coke plants, and the Forms EIA 3 and 3a, which record 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.   Sulfur emissions levels shown below (Table 76) have been adjusted from percent by weight data (on an ‘as received basis’) to reflect U.S. Environmental Protection Agency assumptions about the variation in the completeness of combustion by coal rank: 95 percent for bituminous coals, 87.5 percent for sub-bituminous coals and 75 percent for lignite.   These emissions are appropriate for unscrubbed boilers; depending on the type of scrubber employed, emissions from scrubbed boilers would be further reduced by between 70 and 95 percent.  Carbon emissions levels for each coal type are listed in Table 76 in pounds of carbon dioxide emitted per million Btu.111

Table 76. Production, Heat Content, and Sulfur and Carbon Emissions by Coal Type and Region

Legislation

It is assumed that provisions of the Energy Policy Act of 1992 that relate to the future funding of the Health and Benefits Fund of the United Mine Workers of America will have no significant effect on estimated production costs, although liabilities of company’s contributions will be redistributed.  Electricity sector demand for coal, which represented 89 percent of domestic coal demand in 1999, incorporates the provisions of the Clean Air Act Amendments of 1990.  It is assumed that electricity producers will be granted full flexibility to meet the specified reductions in sulfur dioxide emissions.

Mining Cost Cases

In the reference case, labor productivity is assumed to increase at an average rate of 2.2 percent a year through 2020, while wage rates and mine equipment costs remain constant in 1999 dollars.  Two alternative cases were modeled in the NEMS CMM, assuming different growth rates for both labor productivity and miner wages.  In a low mining cost sensitivity case, productivity increases at 3.7 percent a year, and real wages and mine equipment costs decline by 0.5 percent a year.  In a high mining cost sensitivity case, productivity increases by 0.6 percent a year, and real wages and mine equipment costs increase by 0.5 percent a year. In the alternative cases, the annual growth rates for productivity were increased and decreased by mine type (underground and surface), based on historical variations in labor productivity during the years 1980 through 1998.  Both cases were run using only the NEMS Energy Supply Modules (Oil and Gas Supply Module, Natural Gas Transmission and Distribution Module, Coal Market Module, and Renewable Fuels Module), the Petroleum Market Module, and the Electricity Market Module, rather than as a fully integrated NEMS run.  Consequently, no price-induced demand feedback in end-use coal markets was captured.  In an integrated run, the demand response would tend to moderate the magnitude of the equilibrium price response.

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