Overview
We mine, process and sell bituminous, steam- and industrial-grade coal through six operating subsidiaries (“mining complexes”) located throughout eastern Kentucky and in southern Indiana. As of December 31, 2006, o ur six mining complexes include 15 underground mines, 11 surface mines and ten preparation plants, five of which have integrated rail loadout facilities and three of which use a common loadout facility at a separate location . As of December 31, 2006, we believe that we controlled approximately 273 million tons of proven and probable coal reserves. At current production levels, we believe these reserves would support greater than 22 years of production.
In 2006, we produced 12.3 million tons of coal (including 616,000 tons of coal produced in our mines that are operated by contract mine operators) and we purchased another 786,000 tons for resale. Of the 11.7 million tons we produced from Company-operated mines, approximately 69% came from underground mines, while the remaining 31% came from surface mines. In 2006, we generated revenues of $564.8 million and had a net loss of $26.2 million. Approximately 88% of our 2006 revenues were generated from coal sales to electric utility companies and 12% came from coal sales to industrial and other companies or from synfuel handling fees . In 2006, Georgia Power and South Carolina Public Service Authority were our largest customers, representing approximately 25% and 16% of our revenues, respectively. No other customer accounted for more than 10% of our revenues.
The coal that we sell is obtained from three sources: our Company-operated mines, mines that are operated by independent contract mine operators, and other third parties from whom we purchase coal for resale. Contract mining and coal purchased from other third parties provide flexibility to increase or decrease production based on market conditions. The table below reflects the amount and percentage of coal obtained from those sources in 2006:
|
Tons
(000)
|
Percentage
of total
coal obtained by the Company |
||||||
|
Coal
produced from Company-operated mines
|
11,652
|
89.3
|
%
|
||||
|
Coal
obtained from mines operated by independent contractors
|
616
|
4.7
|
%
|
||||
|
Coal
purchased from other third parties
|
786
|
6.0
|
%
|
||||
|
13,054
|
100
|
%
|
We also supply coal to a third party synfuel plant and receive fees for the handling, shipping and marketing of the synfuel product. Synfuel is a synthetic fuel product that is produced by chemically altering coal. In 2006, 1% of our total operating revenues came from synfuel handling, shipping and marketing.
Mining Methods
Our Company-operated and contractor mines produce coal using different mining methods. These methods are room and pillar underground mining and surface mining . These methods are described in more detail below.
Room and Pillar . In the underground room and pillar method of mining, continuous mining machines cut five to nine entries into the coal seam and connect them by driving crosscuts, leaving a series of rectangular pillars, or columns of coal, to help support the mine roof and control the flow of air. Generally, openings are driven 20 feet wide and the pillars are 40 to 100 feet wide. As mining advances, a grid-like pattern of entries and pillars is formed. When mining advances to the end of a panel, or section of the mine, retreat mining may begin. In retreat mining, as much coal as is feasible is mined from the pillars that were created in advancing the panel, allowing the roof to cave. When retreat mining is completed to the mouth of the panel, the mined panel is abandoned.
The coal face is cut with continuous mining machines and the coal is transported from the continuous mining machine to the mine conveyor belts using either a continuous haulage system, shuttle cars or ram cars. The mine conveyor system consists of a series of conveyor belts, which transport the coal from the active face areas to the surface. Once on the surface, the coal is transported to the preparation plants where it is processed to remove any impurities. The coal is then transported to the clean coal stockpiles or silos from which it is loaded for shipment to our customers. Reserve recovery, a measure of the percentage of the total coal in place that is ultimately produced, using this method of mining typically ranges from less than 50% to more than 70%, depending on the shape of the reserve, the amount of low-cover areas, and the geological characteristics of the reserve body.
Surface Mining . Surface mining is used when coal is found close to the surface. This method involves the removal of overburden (earth and rock covering the coal) with heavy earth-moving equipment and explosives, loading out the coal, replacing the overburden and topsoil after the coal has been excavated and reestablishing vegetation and plant life and making other improvements that have local community and environmental benefit. Overburden is typically removed at our mines by either hydraulic shovels or front-end loaders which place the overburden into large trucks.
In the CAPP region, we use the c ontour and highwall surface mining methods. Contour and highwall mining is used where removal of all the overburden overlying a coal seam is either uneconomical or impossible due to property control or other issues. With contour mining, a contour cut is taken along the outcrop of the seam and the coal is removed from the exposed pit. Highwall mining can then take place where the seam is exposed in the highwall. A highwall miner resembles an underground continuous miner. The highwall miner cuts entries into the coal seam 10’ wide and 900’ deep. The coal is transported to the surface through the augers and loaded into trucks using a loader. The contour area is then reclaimed by returning overburden to the pit and restoring the mountainside to its approximate original contour. Reserve recovery using this method of mining is typically approximately 70%.
As of December 31, 2006, we had nine Company-operated surface mines including one highwall miner and two contract operated surface mines.
Underground Mine Characteristics
Underground mines are characterized as either “drift” mines or “below drainage” mines. Drift mines are mines that are developed into the coal seam at a point where the seam intersects the surface. The area where the seam intersects the surface is commonly known as the “outcrop.” Multiple entries are developed into the coal seam and are used as airways for mine ventilation, passageways for miners and supplies, and entries for conveyor belts that transport coal from the active production areas of the mine to the surface.
In below drainage mines, the coal seam does not intersect the surface in the vicinity of the mining area. Therefore, the coal seam must be accessed through excavated passageways from the surface. These passageways typically consist of vertical shafts and angled slopes. The shafts are constructed with diameters ranging from 12 to 24 feet and are used as airways for mine ventilation and passageways for miners and supplies via elevators. The slopes, when used to house conveyor belts to transport the mined coal from the active production areas of the mine to the surface, are typically driven at an angle of less than 17 degrees from the horizontal. In addition, the slopes provide passageways for miners and supplies, and airways for mine ventilation.
As of December 31, 2006, we had 14 Company-operated and one contractor operated underground mines in operation, of which 11 were drift mines, and the remaining three were below-drainage slopes mines.
Mining Operations
Our coal production is conducted through five mining complexes in the Central Appalachia Region (CAPP) and one mining complex in the Midwest Region. We generally do not own the land on which we conduct our mining operations. Rather, our coal reserves are controlled pursuant to leases from third party landowners. We believe that greater than 95% and 90% of our coal reserves in the Central Appalachia Region and Midwest Region, respectively, are controlled pursuant to leases from third party landowners. These leases typically convey mining rights to the coal producer in exchange for a per ton fee or royalty payment of a percentage of the gross sales price to the lessor. The average royalties for coal reserves from our producing properties were approximately 7.9% (excluding a $4.1 million write-off of a prepaid royalty in the fourth quarter of 2006 in connection with the restructuring of mineral lease contract) and 2.8% of produced coal revenue for the year ended December 31, 2006 in the Central Appalachia Region and the Midwest Region, respectively.
All of our operations are located on or near public highways and receive electrical power from commercially available sources. Existing facilities and equipment are maintained in good working condition and are continuously updated through capital expenditure investments.
The following table provides summary information on our mining complexes as of December 31, 2006:
|
Number
and Type of Mines
|
Quality
of Shipments for the
year ended 2006 |
|||||||||||||||||||||
|
Mining
Complex
|
Underground
|
Surface
|
Total
|
Tons
Shipped
(in
000’s
of
tons)
|
Sulfur
Content
|
Ash
Content
|
Average
BTU Content
|
|||||||||||||||
|
Central
Appalachia
|
||||||||||||||||||||||
|
Bell
County Coal Corporation
|
2
|
—
|
2
|
929
|
1.4
|
9.4
|
12,699
|
|||||||||||||||
|
Bledsoe
Coal Corporation
|
3
|
2
|
5
|
2,992
|
1.2
|
10.5
|
12,431
|
|||||||||||||||
|
Blue
Diamond Coal Corporation
|
4
|
2
|
6
|
1,647
|
0.9
|
9.0
|
12,790
|
|||||||||||||||
|
Leeco,
Inc.
|
1
|
1
|
2
|
1,419
|
1.0
|
10.1
|
12,625
|
|||||||||||||||
|
McCoy
Elkhorn Coal Corporation
|
4
|
—
|
4
|
2,793
|
1.5
|
8.6
|
12,831
|
|||||||||||||||
|
Midwest
|
||||||||||||||||||||||
|
Triad
Mining, Inc
|
1
|
6
|
7
|
3,348
|
2.7
|
8.8
|
11,223
|
We obtained rights to these mining complexes as follows: McCoy Elkhorn and Bell County were the original operating companies that made up James River Coal Company when we were formed in 1988 through the purchase of General Energy Corp. In 1992, we acquired the operations of Johns Creek Coal Company and the Bevins Branch Preparation Plant, both of which are now included within the McCoy Elkhorn complex. The Leeco and Bledsoe operating companies were both acquired in our acquisition of Transco Coal Company in 1995. The Blue Diamond operating company was purchased in 1998. In 1999, we acquired Shamrock Coal Company, which added mines, reserves, a preparation plant and the Clover loadout facility to the Bledsoe complex. In 2005, we acquired Triad Mining, Inc.
The following summarizes additional information concerning each of our six mining complexes:
Bell County . The Bell County complex is located in Bell County in eastern Kentucky, and consists of two Company-operated underground mines. We use room and pillar mining to mine the Buckeye Springs and Garmedia seams of coal. Coal is processed at our preparation plant and loaded into railcars via an integrated four-hour unit train loadout that is serviced by both the CSX and Norfolk Southern railroads. As of December 31, 2006, we employed 117 mining and support personnel at this complex.
Bledsoe . The Bledsoe complex is located in Leslie and Harlan counties in eastern Kentucky, and consists of three Company-operated underground mines, one Company-operated surface mine and one contract surface mine. We use room and pillar mining to mine the Hazard #4 seam of coal at this complex for our underground mine, and our surface mines use the contour method to mine Hazard Seams #7, #10, #11 and #12. Coal is processed at one of two preparation plants and loaded into railcars at a separate location via a four-hour unit train loadout on the CSX railroad. As of December 31, 2006, we employed 395 mining and support personnel at this complex.
Blue Diamond . The Blue Diamond complex is located in Leslie, Perry and Letcher counties in eastern Kentucky, and consists of four underground and two surface mines. These mines are operated by the Company with the exception of one surface mine and one underground mine that are operated by contractors. Our Company operated underground mines use room and pillar mining to mine the Hazard #4 and Alma seams of coal and our contract mine operator use s the same method to mine the Leatherwood seam. The surface mines use the contour method to mine the #9, #5A, and #7 seams. Coal is processed at our preparation plant, and loaded into railcars via an integrated four-hour unit train loadout on the CSX railroad. As of December 31, 2006, we employed 269 mining and support personnel at this complex.
Leeco . The Leeco complex is located in Knott and Perry counties in eastern Kentucky, and consists of one Company-operated underground mine and one surface mine with a highwall miner. Our underground mine uses room and pillar mining to mine the Amburgy seam of coal and our surface mine uses the contour and highwall mining methods to mine the Hazard #8 and #9 seams. Coal is processed at our preparation plant and loaded into railcars via an integrated four-hour unit train loadout on the CSX railroad. As of December 31, 2006, we employed 211 mining and support personnel at this complex.
McCoy Elkhorn . The McCoy Elkhorn complex is located in Pike and Floyd counties in eastern Kentucky, and consists of four Company-operated underground mines. We use room and pillar mining to mine the Millard, Elkhorn #2, Elkhorn #3, and Pond Creek seams of coal. Coal is processed at one of our two preparation plants and loaded into railcars via integrated four-hour unit train loadouts on the CSX railroad. As of December 31, 2006, we employed 422 mining and support personnel at this complex.
Triad . The Triad complex is located in Pike and Knox counties in s outhern Indiana and consists of six surface mines and one underground mine, all of which we operate. We use room and pillar mining to mine the Springfield seam of coal, and use the surface mine method to mine multiple seams, including the Danville, Millersburg, Hym era , Bucktown and Springfi el d seams. Coal is processed at one of three active preparation plants and loaded into trucks for delivery to the customer or by rail at our Switz City loadout. The Switz City loadout is serviced by Indiana R ailroad and the Indiana Southern Railroad. As of December 31, 2006, we employed approximately 270 mining and support personnel at this complex.
Contract mining represented approximately 4.7% of our coal production in the year ended December 31, 2006. Each mining complex monitors its contract mining operations and provides geological and engineering assistance to the contract mine operators. The contract mine operators generally provide their own equipment and operate the mines using their employees. Independent contract mine operators are paid a fixed rate for each ton of saleable product. We are primarily responsible for the reclamation activities involved with all contractor-operated mines. Contractors that operate surface mines, however, typically are contractually obligated to perform, on our behalf, the reclamation activities associated with the mines they operate. Our relationships with contract mine operators typically can be cancelled by either party without penalty by giving between 30 and 60 days notice.
Reserves
We have an ongoing mineral development drilling and exploration program on our coal properties. The purpose of the drilling and exploration program is to assist us with planning our mining activities and to better assess our coal reserves. In April 2004, we asked Marshall Miller & Associates, Inc. (“MM&A”) to prepare a detailed study of our reserves in Central Appalachia as of March 31, 2004 based on all of our geologic information, including our updated drilling and mining data. For the Triad properties MM&A also prepared a detailed study of Triad’s reserves as of February 1, 2005 for the reserves obtained in the acquisition of Triad and as of April 11, 2006 for 15.8 million tons of reserves acquired in the second quarter of 2006. We have used MM&A’s March 31, 2004 study as the basis for our current internal estimate of our Central Appalachia reserves and MM&A’s February 1, 2005 and April 11, 2006 studies as the basis for our current internal estimate of our Midwest reserves (collectively the “MM&A studies”).
The coal reserve studies conducted by MM&A were planned and performed to obtain reasonable assurance of our subject demonstrated (proven plus probable) reserves. In connection with the studies, MM&A prepared reserve maps and had certified professional geologists develop estimates based on data supplied by us and using standards accepted by government and industry.
After reviewing the maps and information we supplied, MM&A prepared an independent mapping and estimate of our demonstrated reserves using methodology outlined in U.S. Geological Survey Circular 891 and SEC Industry Guide 7. MM&A developed reserve estimation criteria to assure that the basic geologic characteristics of the reserves ( e.g. , minimum coal thickness and wash recovery, interval between deep mineable seams, mineable area tonnage for economic extraction, etc.) are in reasonable conformity with present and recent mine operation capabilities on our various properties.
MM&A has not conducted a coal reserve study on our December 31, 2006 reserve estimate. We continue to have an ongoing mineral development drilling and exploration program on our coal properties and plan to update our third party reserve study from time to time. Any future negative changes in our reserves could have a material adverse impact on our depreciation, depletion and amortization expense. A material adverse impact could also lead to a charge for impairment of the value of our coal property assets.
As of December 31, 2006, we estimated that we controlled approximately 233.0 million tons of proven and probable coal reserves in Central Appalachia and 40.2 millions tons of proven and probable coal reserves in the Midwest.
Reserves for these purposes are defined by SEC Industry Guide 7 as that part of a mineral deposit which could be economically and legally extracted or produced at the time of the reserve determination. The reserve estimates have been prepared using industry-standard methodology to provide reasonable assurance that the reserves are recoverable, considering technical, economic and legal limitations. Although the MM&A studies found our reserves to be reasonable (not withstanding unforeseen geological, market, labor or regulatory issues that may affect the operations), by assignment, MM&A has not performed an economic feasibility study for our reserves. In accordance with standard industry practice, we have performed our own economic feasibility analysis for our assigned reserves. It is not generally considered to be practical, however, nor is it standard industry practice, to perform a feasibility study for a company’s entire reserve portfolio. In addition, MM&A did not independently verify our control of our properties, and has relied solely on property information supplied by us. Reserve acreage, average seam thickness, average seam density and average mine and wash recovery percentages were verified by MM&A to prepare a reserve tonnage estimate for each reserve.
The following table provides information on our mining complexes. Except as noted, the reserve and quality information is based on the MM& A studies:
|
Proven
& Probable
Reserves
(1)
(millions
of tons)
|
Approximate
Overall
Reserve
Quality
(2),
(3)
|
||||||||||||||||||
|
Mining
Complex
|
As
of
Most
Recent
MM&A
Studies
(3)
|
As
of
December
31,
2006
(4)
|
Estimated
Years
of
Reserve
Life
Based
on 2006 Production
Levels
|
Ash
Content
(%)
|
Sulfur
Content
(%)
|
Heat
Value
(Btu/lb.)
|
|||||||||||||
|
Central
Appalachia
|
|||||||||||||||||||
|
Bell
County
|
12.5
|
11.8
|
19.6
|
5.1
|
1.0
|
13,500
|
|||||||||||||
|
Bledsoe
|
59.1
|
58.1
|
20.0
|
7.8
|
1.2
|
13,000
|
|||||||||||||
|
Blue
Diamond
|
66.2
|
83.6
|
55.1
|
4.7
|
1.1
|
13,700
|
|||||||||||||
|
Leeco
|
35.7
|
43.1
|
33.0
|
7.0
|
1.2
|
13,200
|
|||||||||||||
|
McCoy
Elkhorn
|
33.8
|
36.4
|
13.9
|
5.7
|
1.6
|
13,300
|
|||||||||||||
|
Total/Average
|
207.3
|
233.0
|
26.0
|
6.3
|
1.3
|
13,300
|
|||||||||||||
|
Midwest
|
|||||||||||||||||||
|
Triad
|
33.4
|
40.2
|
12.1
|
8.8
|
3.2
|
12,000
|
(1)
(1) Proven reserves have the highest degree of geologic assurance and are reserves for which (a) quantity is computed from dimensions revealed in outcrops, trenches, workings, or drill holes; grade and/or quality are computed from the results of detailed sampling and (b) the sites for inspections, sampling and measurement are spaced so closely and the geologic character is so well defined that size, shape, depth and mineral content of reserves are well-established. Probable reserves have a moderate degree of geologic assurance and are reserves for which quantity and grade and/or quality are computed from information similar to that used for proven reserves, but the sites for inspection, sampling and measurement are farther apart or are otherwise less adequately spaced. The degree of assurance, although lower than that for proven reserves, is high enough to assume continuity between points of observation. This reserve information reflects recoverable tonnage on an as-received basis with 5.5% moisture.
(2) Ash and sulfur content is expressed as the percent by weight of those constituents in the coal sample compared to the total weight of the sample being tested. Heat value is expressed as Btu per pound in the coal based on laboratory testing of coal samples. The samples are typically obtained from exploratory core borings placed at strategic locations within the coal reserve area. Approximately 82% of the reserve tons have representative samples (degree of representation varies from area to area) and 18% of the reserve tons have no site-specific samples (and are therefore not included in the overall quality estimate). The samples are sent to accredited laboratories for testing under protocols established by the American Society of Testing and Materials (ASTM). The estimated overall quality values are derived by a multiple step process, including: a) for each mine or reserve area, an arithmetic average quality (dry basis) was prepared to represent the coal tons within the area, based on samples from the area; b) the overall quality of reserves for each mine complex was determined by performing a tonnage-weighted average of the average quality of all mine and reserve areas within the division; and c) the resulting dry basis overall quality was converted to wet product basis to reflect its anticipated moisture content at the time of sale. The actual quality of the shipped coal may vary from these estimates due to factors such as: a) the particle size of the coal fed to the plant; b) the specific gravity of the float media in use at the preparation plant; c) the type of plant circuit(s); d) the efficiency of the plant circuit(s); e) the moisture content of the final product; and f) customer requirements.
(3) For the CAPP region, represents reserve information for our mining complexes as of March 31, 2004. For the Midwest region, represents weighted average reserve information as of February 1, 2005 and April 11, 2006, for the reserves obtained on the acquisition of the Triad mining complex and for a lease entered into during 2006, respectively. The reserve information is based on the independent reserve studies conducted by MM&A.
(4) Represents the Company’s estimate of reserves at December 31, 2006 based on additional information or reserves obtained from exploration and acquisition activities, production activities or discovery of new geologic information. We calculated the adjustments to the reserves in the same manner, and based on the same assumptions and qualifications, as used in the MM&A studies described above, but these December 31, 2006 estimates have not been reviewed by MM&A.
Processing and Transportation
Coal from each of our mine complexes is transported by conveyor belt or by truck to one of our ten preparation plants or directly to one of our load-outs, all of which are in close proximity to our mining operations. These preparation plants remove impurities from the run-of-mine coal (the raw coal that comes directly from the mine) and offer the flexibility to blend various coals and coal qualities to meet specific customer needs. We regularly upgrade and maintain all of our preparation plants to achieve a high level of coal cleaning efficiency and maintain the necessary capacity.
In Central Appalachia, substantially all of our coal is shipped by train and sold f.o.b. the railcar at the point of loading; transportation costs are normally borne by the purchaser. In addition to our well-positioned unit train loadout facilities on the CSX Corporation railroad, our Bell County mining complex has dual service provided by the CSX and Norfolk Southern Corporation railroads in Bell County, Kentucky.
In the Midwest, coal is shipped by train and by truck to our customers. The trucked coal is primarily sold f.o.b delivery point with transportation costs borne by either the customer or us. Coal delivered by train is sold f.o.b. the railcar at the point of loading, with transportation costs normally borne by the purchaser. Our Triad mining complex has rail service provided by Indiana Railroad and Indiana Southern Railroad.
Our mining complexes are supported by personnel located in London, Kentucky who provide engineering and permitting assistance, project management, land management and lease administration, coal quality control and quality reporting, accounting and purchasing support, and railroad transportation scheduling services.
Customers and Coal Contracts
As is customary in the coal industry, we regularly enter into long-term contracts (which we define as contracts with terms of more than one year) with many of our customers. These arrangements allow customers to secure a supply for their future needs and provide us with greater predictability of sales volume and sales prices. In 2006, we generated approximately 72% of our total revenues from seven long-term contracts to sell coal to electric utilities.
For the year ended December 31, 2006, Georgia Power (25%) and South Carolina Public Service Authority (16%) were our largest customers by revenues. No other customer accounted for more than 10% of revenues.
The terms of our contracts result from a bidding and negotiation process with our customers. Consequently, the terms of these contracts often vary significantly in many respects. Our long-term supply contracts typically contain one or more of the following pricing mechanisms:
·
Fixed price contracts;
·
Annually negotiated prices that reflect market conditions at the time; or
·
Base-price-plus-escalation methods that allow for periodic price adjustments based on fixed percentages or, in certain limited cases, pass-through of actual cost changes.
A limited number of our contracts have features of several contract types, such as provisions that allow for renegotiation of prices on a limited basis within a base-price-plus-escalation agreement. Such re-opener provisions allow both the customer and us an opportunity to adjust prices to a level close to then current market conditions. Each contract is negotiated separately, and the triggers for re-opener provisions differ from contract to contract. Some of our existing contracts with re-opener provisions adjust the contract price to the market price at the time the re-opener provision is triggered. Re-opener provisions could result in early termination of a contract or a reduction in the volume to be purchased if the parties were to fail to agree on price.
Our long-term supply contracts also typically contain force majeure provisions allowing for the suspension of performance by the customer or us for the duration of specified events beyond the control of the affected party, including labor disputes. Some contracts may terminate upon continuance of an event of force majeure for an extended period, which are generally three to six months. Contracts also typically specify minimum and maximum quality specifications regarding the coal to be delivered. Failure to meet these conditions could result in substantial price reductions or termination of the contract, at the election of the customer. Although the volume to be delivered under a long-term contract is stipulated, we, or the buyer, may vary the timing of delivery within specified limits.
The terms of our long-term coal supply contracts also vary significantly in other respects, including: coal quantity parameters, flexibility and adjustment mechanisms, permitted sources of supply, treatment of environmental constraints, options to extend, suspension, termination and assignment provisions, and provisions regarding the allocation between the parties of the cost of complying with future government regulations.
Competition
The U.S. coal industry is highly competitive, with numerous producers in all coal producing regions. We compete against various large producers and hundreds of small producers. According to the U.S. Department of Energy, the largest producer produced approximately 17.8% (based on tonnage produced) of the total United States production in 2005, the latest year for which government statistics are available. The U.S. Department of Energy also reported 1,398 active coal mines in the United States in 2005. Demand for our coal by our principal customers is affected by:
·
the price of competing coal and alternative fuel supplies, including nuclear, natural gas, oil and renewable energy sources, such as hydroelectric power;
·
coal quality;
·
transportation costs from the mine to the customer; and
·
the reliability of supply.
Continued demand for our coal and the prices that we obtain are affected by demand for electricity, environmental and government regulation, technological developments and the availability and price of competing coal and alternative fuel supplies.
Employees
At December 31, 2006, we had 1,742 employees. None of our employees are currently represented by collective bargaining agreements. Relations with our employees are generally good.
Government Regulation
The coal mining industry is subject to extensive regulation by federal, state and local authorities on matters such as:
·
employee health and safety;
·
permitting and licensing requirements;
·
air quality standards;
·
water quality standards;
·
plant , wildlife and wetland protection;
·
blasting operations;
·
the management and disposal of hazardous and non-hazardous materials generated by mining operations;
·
the storage of petroleum products and other hazardous substances;
·
reclamation and restoration of properties after mining operations are completed;
·
discharge of materials into the environment , including air emissions and wastewater discharge ;
·
surface subsidence from underground mining; and
·
the effects of mining operations on groundwater quality and availability.
Complying with these requirements, including the terms of our permits, has had, and will continue to have, a significant effect on our costs of operations. We could incur substantial costs, including clean up costs, fines, civil or criminal sanctions and third party claims for personal injury or property damage as a result of violations of or liabilities under these laws and regulations.
In addition, the utility industry, which is the most significant end-user of coal, is subject to extensive regulation regarding the environmental impact of its power generation activities, which could affect demand for our coal. The possibility exists that new legislation or regulations may be adopted which would have a significant impact on our mining operations or our customers’ ability to use coal and may require us or our customers to change operations significantly or incur substantial costs.
Numerous governmental permits and approvals are required for mining operations. In connection with obtaining these permits and approvals, we are, or may be, required to prepare and present to federal, state or local authorities data pertaining to the effect or impact that any proposed exploration for or production of coal may have upon the environment, the public, historical artifacts and structures, and our employees’ health and safety. The requirements imposed by such authorities may be costly and time-consuming and may delay commencement or continuation of exploration or production operations. Future legislation and administrative regulations may emphasize the protection of the environment and health and safety and, as a consequence, our activities may be more closely regulated. Such legislation and regulations, as well as future interpretations of existing laws, may require substantial increases in our equipment and operating costs and delays, interruptions or a termination of operations, the extent of which cannot be predicted.
While it is not possible to quantify the costs of compliance with all applicable federal and state laws, those costs have been and are expected to continue to be significant. We estimate that we will make expenditures of approximately $2.0 million per year for environmental control facilities and complying with new safety regulations in 2007 and 2008. These costs are in addition to reclamation and mine closing costs and the costs of treating mine water discharge, when necessary. Compliance with these laws has substantially increased the cost of coal mining, but is, in general, a cost common to all domestic coal producers.
Mine Health and Safety Laws
Stringent health and safety standards were imposed by federal legislation when the Federal Coal Mine Safety and Health Act of 1969 was adopted. The Federal Mine Safety and Health Act of 1977, which significantly expanded the enforcement of safety and health standards of the Coal Mine Safety and Health Act of 1969, imposes safety and health standards on all mining operations. Regulations are comprehensive and affect numerous aspects of mining operations, including training of mine personnel, mining procedures, blasting, the equipment used in mining operations and other matters. The Federal Mine Safety and Health Administration monitors compliance with these federal laws and regulations and can impose penalties can impose under recently enacted regulations maximum penalties of up to $220,000 for certain violations, as well as closure of the mine. In addition, as part of the Coal Mine Safety and Health Act of 1969 and the Federal Mine Safety and Health Act of 1977, the Black Lung Benefits Revenue Act of 1977 and the Black Lung Benefits Reform Act of 1977, as amended in 1981, require payments of benefits to disabled coal miners with black lung disease and to certain survivors of miners who die from black lung disease.
In 2001, Kentucky made significant changes to its mining laws. A new independent agency, the Kentucky Mine Safety Review Commission, was created to assess penalties against anyone, including owners or part owners (defined as anyone owning one percent or more shares of publicly traded stock), whose intentional violations or order to violate mine safety laws place miners in imminent danger of serious injury or death. Mine safety training and compliance with state statutes and regulations related to coal mining is monitored by the Kentucky Office of Mine Safety and Licensing. The Commission can impose a penalty of up to $10,000 per violation, as well as suspension or revocation of the mine license.
The mine disasters in West Virginia and other states that occurred in 2006 have resulted in increased scrutiny of coal mining in general and underground coal mining in particular. New legislation has been enacted at the state and federal level that creates requirements for maintaining caches of self-contained self-rescuers throughout underground mines; equipping all underground miners with wireless communications devices and tracking devices; and in some cases, installing cable lifelines from the mine portal to all sections of the mine for assistance in emergency escape. Additionally, new requirements for prompt reporting of accidents and increased fines and penalties for violation of these and other regulations have been enacted. The Federal Mine Safety and Health Administration issued final regulations in December 2006 that place new or amended requirements on all underground mines relating to the storage and use of self-contained self-rescuers, evacuation training for miners, the installment and maintenance of lifelines and notification of MSHA in the event of an accident.
It is our responsibility to our employees to provide a safe and healthy environment through training, communication, following and improving safety standards and investigating all accidents, incidents and losses to avoid reoccurrence. The combination of federal and state safety and health regulations in the coal mining industry is, perhaps, the most comprehensive system for protection of employee safety and health affecting any industry. Most aspects of mine operations are subject to extensive regulation. This regulation has a significant effect on our operating costs. However, our competitors are subject to the same level of regulation.
Black Lung Legislation
Under the federal Black Lung Benefits Act (as amended) (the “Black Lung Act”), each coal mine operator is required to make black lung benefits or contribution payments to:
·
current and former coal miners totally disabled from black lung disease;
·
certain survivors of a miner who dies from black lung disease or pneumoconiosis; and
·
a trust fund for the payment of benefits and medical expenses to any claimant whose last mine employment was before January 1, 1970, or where a miner’s last coal employment was on or after January 1, 1970 and no responsible coal mine operator has been identified for claims, or where the responsible coal mine operator has defaulted on the payment of such benefits.
Federal black lung benefits rates are periodically adjusted according to the percentage increase of the federal pay rate.
In addition to the Black Lung Act, we also are liable under various state statutes for black lung claims. To a certain extent, our federal black lung liabilities are reduced by our state liabilities. Our total (federal and state) black lung benefit liabilities, including the current portions, totaled approximately $26.8 million at December 31, 2006. These obligations were unfunded at December 31, 2006.
The United States Department of Labor issued a final rule, effective January 19, 2001, amending the regulations implementing the Black Lung Act. The amendments give greater weight to the opinion of the claimant’s treating physician, expand the definition of black lung disease and limit the amount of medical evidence that can be submitted by claimants and respondents. The amendments also alter administrative procedures for the adjudication of claims, which, according to the Department of Labor, results in streamlined procedures that are less formal, less adversarial and easier for participants to understand. These and other changes to the black lung regulations could significantly increase our exposure to federal black lung benefits liabilities. Experience to date related to these changes is not sufficient to determine the impact of these changes. The National Mining Association challenged the amendments but the courts, to date, with minor exception, affirmed the rules. However, the decision left many contested issues open for interpretation. Consequently, we anticipate increased litigation until the various federal District Courts have had an opportunity to rule on these issues.
The Kentucky Supreme Court has taken discretionary review of a Kentucky Court of Appeals decision, Bartrum v. Hunter Excavating, which rendered unconstitutional a 2002 statute governing black lung claims. The Court of Appeals held that to the extent the statute limited evidence, it violated due process rights. The effect upon future black lung claims, if any, is dependent upon the Kentucky Supreme Court’s review.
In recent years, proposed legislation on black lung reform has been introduced in, but not enacted by, Congress and the Kentucky legislature. It is possible that legislation on black lung reform will be reintroduced for consideration by these legislative bodies. If any of the proposals that have been introduced are passed, the number of claimants who are awarded benefits could significantly increase. Any such changes in black lung legislation, if approved, or in state or federal court rulings, may adversely affect our business, financial condition and results of operations.
Workers’ Compensation
We are required to compensate employees for work-related injuries. Our accrued workers’ compensation liabilities, including the current portion, were $53.4 million at December 31, 2006. These obligations are unfunded. Our expense for workers’ compensation was $11.4 million in 2006. Both the federal government and the states in which we operate consider changes in workers’ compensation laws from time to time. Such changes, if enacted, could adversely affect us.
Environmental Laws and Regulations
We are subject to various federal environmental laws and regulatory entities, including:
·
the Surface Mining Control and Reclamation Act of 1977;
·
the Clean Air Act;
·
the Clean Water Act;
·
the Toxic Substances Control Act;
·
the Comprehensive Environmental Response, Compensation and Liability Act;
·
the U.S. Army Corps of Engineers; and
·
the Resource Conservation and Recovery Act.
We are also subject to state laws of similar scope in each state in which we operate.
These environmental laws require reporting, permitting and/or approval of many aspects of coal operations. Both federal and state inspectors regularly visit mines and other facilities to ensure compliance. We have ongoing compliance and permitting programs designed to ensure compliance with such environmental laws.
Given the retroactive nature of certain environmental laws, we have incurred and may in the future incur liabilities, including clean-up costs, in connection with properties and facilities currently or previously owned or operated as well as sites to which we or our subsidiaries sent waste materials.
Surface Mining Control and Reclamation Act (SMCRA)
The SMCRA, and its state counterparts, establish operational, reclamation and closure standards for all aspects of surface mining as well as many aspects of underground mining. The Act requires that comprehensive environmental protection and reclamation standards be met during the course of and following completion of mining activities. Permits for all mining operations must be obtained from the Federal Office of Surface Mining Reclamation and Enforcement or, where state regulatory agencies have adopted federally approved state programs under the Act, the appropriate state regulatory authority.
The SMCRA and similar state statutes, among other things, require that mined property be restored in accordance with specified standards and approved reclamation plans. The mine operator must submit a bond or otherwise secure the performance of these reclamation obligations. The earliest a reclamation bond can be fully released is five years after reclamation has been achieved. All states impose on mine operators the responsibility for repairing or compensating for damage occurring on the surface as a result of mine subsidence, a possible consequence of underground mining. In addition, the Abandoned Mine Reclamation Fund, which is part of the SMCRA, imposes a tax on all current mining operations, the proceeds of which are used to restore unreclaimed mines closed before 1977. The maximum tax, effective October 1, 2007, is $0.315 per ton on surface mined coal and $0.135 per ton on underground-mine coal.
Statement of Financial Accounting Standards No. 143 (“Statement No. 143”) provides the guidance to account for the costs related to the closure of mines and the reclamation of the land upon exhaustion of coal reserves. This statement requires the fair value of an asset retirement obligation be recognized in the period in which it is incurred if a reasonable estimate of fair value can be made. The present value of the estimated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. Asset retirement obligations primarily relate to the closure of mines and the reclamation of the land upon exhaustion of coal reserves. At December 31, 2006 and December 31, 2005, we had accrued $29.7 million and $26.8 million, respectively, related to estimated mine reclamation costs. The amounts recorded are dependent upon a number of variables, including the amount and timing of estimated future retirement costs, estimated proven reserves, assumptions involving profit margins, inflation rates, and the assumed credit-adjusted risk-free interest rate.
Our future operating results would be adversely affected if these accruals were determined to be insufficient. These obligations are unfunded. The amount that was expensed for the year ended December 31, 2006 was $2.1 million, while the related cash payment for such liability during the same period was $1.1 million.
We also lease some of our coal reserves to third-party operators. Under the SMCRA, responsibility for unabated violations, unpaid civil penalties and unpaid reclamation fees of independent contract mine operators can be imputed to other companies which are deemed, according to the regulations, to have “owned” or “controlled” the contract mine operator. Sanctions against the “owner” or “controller” are quite severe and can include being blocked, nationwide, from receiving new permits and revocation of any permits that have been issued since the time of the violations or, in the case of civil penalties and reclamation fees, since the time such amounts became due.
Clean Air Act
The federal Clean Air Act and similar state laws and regulations, which regulate emissions into the air, affect coal mining and processing operations primarily through permitting and/or emissions control requirements. In addition, the Environmental Protection Agency (the “EPA”) has issued certain, and is considering further, regulations relating to fugitive dust and particulate matter emissions that could restrict our ability to develop new mines or require us to modify our operations. In July 1997, the EPA adopted new, more stringent National Ambient Air Quality Standards for particulate matter, which may require some states to change existing implementation plans for particulate matter. Because coal mining operations and plants burning coal emit particulate matter, our mining operations and utility customers are likely to be directly affected when the revisions to the National Ambient Air Quality Standards are implemented by the states. Regulations under the Clean Air Act may restrict our ability to develop new mines or could require us to modify our existing operations, and may have a material adverse effect on our financial condition and results of operations.
The Clean Air Act also indirectly affects coal mining operations by extensively regulating the air emissions of coal-fired electric power generating plants. Coal contains impurities, such as sulfur, mercury and other constituents, many of which are released into the air when coal is burned. New environmental regulations governing emissions from coal-fired electric generating plants could reduce demand for coal as a fuel source and affect the volume of our sales. For example, the federal Clean Air Act places limits on sulfur dioxide emissions from electric power plants. In order to meet the federal Clean Air Act limits for sulfur dioxide emissions from electric power plants, coal users need to install scrubbers, use sulfur dioxide emission allowances (some of which they may purchase), blend high sulfur coal with low sulfur coal or switch to low sulfur coal or other fuels. The cost of installing scrubbers is significant and emission allowances may become more expensive as their availability declines. Switching to other fuels may require expensive modification of existing plants.
On March 15, 2005, the EPA adopted a new federal rule to cap and reduce mercury emissions from both new and existing coal-fired power plants. The reductions will be implemented in stages, primarily through a market-based cap-and-trade program. Nevertheless, the new regulations will likely require some power plants to install new equipment, at substantial cost, or discourage the use of certain coals containing higher levels of mercury.
Other new and proposed reductions in emissions of sulfur dioxides, nitrogen oxides, particulate matter or various greenhouse gases may require the installation of additional costly control technology or the implementation of other measures, including trading of emission allowances and switching to other fuels. For example, the EPA recently proposed separate regulations to reduce the interstate transport of fine particulate matter and ozone through reductions in sulfur dioxides and nitrogen oxides throughout the eastern United States. The EPA continues to require reduction of nitrogen oxide emissions in 22 eastern states and the District of Columbia and will require reduction of particulate matter emissions over the next several years for areas that do not meet air quality standards for fine particulates and for certain major sources contributing to those exceedances. In addition, the EPA has issued draft regulations, and Congress and several states are now considering legislation, to further control air emissions of multiple pollutants from electric generating facilities and other large emitters. These new and proposed reductions will make it more costly to operate coal-fired plants and could make coal a less attractive fuel alternative in the planning and building of utility power plants in the future. To the extent that any new and proposed requirements affect our customers, this could adversely affect our operations and results.
Along with these regulations addressing ambient air quality, a regional haze program initiated by the EPA to protect and to improve visibility at and around national parks, national wilderness areas and international parks may restrict the construction of new coal-fired power plants whose operation may impair visibility at and around federally protected areas and may require some existing coal-fired power plants to install additional control measures designed to limit haze-causing emissions. These requirements could limit the demand for coal in some locations.
The United States Department of Justice, on behalf of the EPA, has filed lawsuits against several investor-owned electric utilities and brought an administrative action against one government-owned utility for alleged violations of the Clean Air Act. Some of these lawsuits have settled, requiring the utilities to pay penalties, install pollution control equipment and/or undertake other emission reduction measures, and the remaining lawsuits or future lawsuits could require the utilities involved to take similar steps, which could adversely impact their demand for coal.
Any reduction in coal’s share of the capacity for power generation could have a material adverse effect on our business, financial condition and results of operations. The effect such regulations, or other requirements that may be imposed in the future, could have on the coal industry in general and on us in particular cannot be predicted with certainty.
We believe we have obtained all necessary permits under the Clean Air Act. We monitor permits required by operations regularly and take appropriate action to extend or obtain permits as needed. Our permitting costs with respect to the Clean Air Act are typically less than $100,000 per year.
Framework Convention On Global Climate Change
The United States and more than 160 other nations are signatories to the 1992 United Nations Framework Convention on Climate Change, commonly known as the Kyoto Protocol, which is intended to reduce or offset emissions of greenhouse gases such as carbon dioxide. In December 1997, the signatories to the convention established a binding set of emissions targets for developed nations. Although the specific emissions targets vary from country to country, the United States would be required to reduce emissions to 93% of 1990 levels over a five-year budget period from 2008 through 2012. The U.S. Senate has not ratified the treaty commitments, and the Bush administration has officially opposed the Kyoto Protocol and has proposed an alternative to reduce the intensity of United States emissions of greenhouse gases. With Russia’s ratification of the Kyoto Protocol in 2004, it became binding on all ratifying countries. The implementation of the Kyoto Protocol in a number of countries, and other emissions limits, such as those adopted by the European Union, could affect demand for coal outside the United States. If the Kyoto Protocol or other comprehensive regulations focusing on greenhouse gas emissions are implemented by the United States, it could have the effect of restricting the use of coal. Other efforts to reduce emissions of greenhouse gases and federal initiatives to encourage the use of coal bed methane gas also may affect the use of coal as an energy source.
Clean Water Act
The federal Clean Water Act and corresponding state laws affect coal mining operations by imposing restrictions on discharges into regulated effluent waters. Permits requiring regular monitoring and compliance with effluent limitations and reporting requirements govern the discharge of pollutants into regulated waters. We believe we have obtained all permits required under the Clean Water Act and corresponding state laws and are in substantial compliance with such permits. However, new requirements under the Clean Water Act and corresponding state laws may cause us to incur significant additional costs that could adversely affect our operating results.
In addition, the U.S. Army Corps of Engineers imposes stream mitigation requirements on surface mining operations. These regulations require that footage of stream loss be replaced through various mitigation processes, if any ephemeral, intermittent, or perennial streams are in-filled due to mining operations. These regulations may also cause us to incur significant additional operating costs.
Comprehensive Environmental Response, Compensation and Liability Act
The Comprehensive Environmental Response, Compensation and Liability Act (commonly known as Superfund) and similar state laws create liabilities for the investigation and remediation of releases of hazardous substances into the environment and for damages to natural resources. Our current and former coal mining operations incur, and will continue to incur, expenditures associated with the investigation and remediation of facilities and environmental conditions, including underground storage tanks, solid and hazardous waste disposal and other matters under these environmental laws. We also must comply with reporting requirements under the Emergency Planning and Community Right-to-Know Act and the Toxic Substances Control Act.
The magnitude of the liability and the cost of complying with environmental laws with respect to particular sites cannot be predicted with certainty due to the lack of specific information available, the potential for new or changed laws and regulations and for the development of new remediation technologies and the uncertainty regarding the timing of remedial work. As a result, we may incur material liabilities or costs related to environmental matters in the future and such environmental liabilities or costs could adversely affect our results and financial condition. In addition, there can be no assurance that changes in laws or regulations would not result in additional costs and affect the manner in which we are required to conduct our operations.
Resource Conservation and Recovery Act
The RCRA and corresponding state laws and regulations affect coal mining operations by imposing requirements for the treatment, storage and disposal of hazardous wastes. Facilities at which hazardous wastes have been treated, stored or disposed of are subject to corrective action orders issued by the EPA and other potential obligations, which could adversely affect our results and financial condition.
FORWARD-LOOKING INFORMATION
From time to time, we make certain comments and disclosures in reports and statements, including this report, or statements made by our officers, which may be forward-looking in nature. These statements are known as “forward-looking statements,” as that term is used in Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. Examples include statements related to our future outlook, anticipated capital expenditures, future cash flows and borrowings, and sources of funding. These forward-looking statements could also involve, among other things, statements regarding our intent, belief or expectation with respect to:
·
our cash flows, results of operation or financial condition;
·
the consummation of acquisition, disposition or financing transactions and the effect thereof on our business;
·
governmental policies and regulatory actions;
·
legal and administrative proceedings, settlements, investigations and claims;
·
weather conditions or catastrophic weather-related damage;
·
our production capabilities;
·
availability of transportation;
·
market demand for coal, electricity and steel;
·
competition;
·
our relationships with, and other conditions affecting, our customers;
·
employee workforce factors;
·
our assumptions concerning economically recoverable coal reserve estimates;
·
future economic or capital market conditions; and
·
our plans and objectives for future operations and expansion or consolidation.
Any forward-looking statements are subject to the risks and uncertainties that could cause actual cash flows, results of operations, financial condition, cost reductions, acquisitions, dispositions, financing transactions, operations, expansion, consolidation and other events to differ materially from those expressed or implied in such forward-looking statements. Any forward-looking statements are also subject to a number of assumptions regarding, among other things, future economic, competitive and market conditions generally. These assumptions would be based on facts and conditions as they exist at the time such statements are made as well as predictions as to future facts and conditions, the accurate prediction of which may be difficult and involve the assessment of events beyond our control.
We wish to caution readers that forward-looking statements, including disclosures which use words such as “believe,” “intend,” “expect,” “may,” “should,” “anticipate,” “could,” “estimate,” “plan,” “predict,” “project,” or their negatives, and similar statements, are subject to certain risks and uncertainties which could cause actual results to differ materially from expectations. These risks and uncertainties include, but are not limited to, the following: a change in the demand for coal by electric utility customers; the loss of one or more of our largest customers; our dependency on one railroad for transportation of a large percentage of our products; failure to exploit additional coal reserves; failure to diversify our operations; increased capital expenditures; increased compliance costs; lack of availability of financing sources; the effects of regulation and competition; and the risk factors set forth in this Annual Report on Form 10-K under Item 1A “Risk Factors.” Those are representative of factors that could affect the outcome of the forward-looking statements. These and the other factors discussed elsewhere in this document are not necessarily all of the important factors that could cause our results to differ materially from those expressed in our forward-looking statements. Forward-looking statements speak only as of the date they are made and we undertake no obligation to update them.
Item 1A. Risk Factors
Risks Related to the Coal Industry
Because the demand and pricing for coal is greatly influenced by consumption patterns of the domestic electricity generation industry, a reduction in the demand for coal by this industry would likely cause our revenues and profitability to decline significantly.
We derived 88% of our total revenues (contract and spot) in 2006 and 85% of our total revenues in 2005, from our electric utility customers. Fuel cost is a significant component of the cost associated with coal-fired power generation, with respect to not only the price of the coal, but also the costs associated with emissions control and credits ( i.e. , sulfur dioxide, nitrogen oxides, etc.), combustion by-product disposal ( i.e. , ash) and equipment operations and maintenance ( i.e. , materials handling facilities). All of these costs must be considered when choosing between coal generation and alternative methods, including natural gas, nuclear, hydroelectric and others.
Weather patterns also can greatly affect electricity generation. Extreme temperatures, both hot and cold, cause increased power usage and, therefore, increased generating requirements from all sources. Mild temperatures, on the other hand, result in lower electrical demand, which allows generators to choose the lowest-cost sources of power generation when deciding which generation sources to dispatch. Accordingly, significant changes in weather patterns could reduce the demand for our coal.
Overall economic activity and the associated demands for power by industrial users can have significant effects on overall electricity demand. Robust economic activity can cause much heavier demands for power, particularly if such activity results in increased utilization of industrial assets during evening and nighttime periods.
Any downward pressure on coal prices, whether due to increased use of alternative energy sources, changes in weather patterns, decreases in overall demand or otherwise, would likely cause our profitability to decline.
Deregulation of the electric utility industry may cause our customers to be more price-sensitive in purchasing coal, which could cause our profitability to decline.
Electric utility deregulation is expected to provide incentives to generators of electricity to minimize their fuel costs and is believed to have caused electric generators to be more aggressive in negotiating prices with coal suppliers. To the extent utility deregulation causes our customers to be more cost-sensitive, deregulation may have a negative effect on our profitability.
Changes in the export and import markets for coal products could affect the demand for our coal, our pricing and our profitability.
We compete in a worldwide market. The pricing and demand for our products is affected by a number of factors beyond our control. These factors include:
|
|
·
|
currency
exchange rates;
|
|
|
·
|
growth
of economic development; and
|
·
ocean freight rates.
Any decrease in the amount of coal exported from the United States, or any increase in the amount of coal imported into the United States, could have a material adverse impact on the demand for our coal, our pricing and our profitability.
Increased consolidation and competition in the U.S. coal industry may adversely affect our revenues and profitability.
During the last several years, the U.S. coal industry has experienced increased consolidation, which has contributed to the industry becoming more competitive. Consequently, many of our competitors in the domestic coal industry are major coal producers who have significantly greater financial resources than us. The intense competition among coal producers may impact our ability to retain or attract customers and may therefore adversely affect our future revenues and profitability.
Fluctuations in transportation costs and the availability and dependability of transportation could affect the demand for our coal and our ability to deliver coal to our customers.
Increases in transportation costs could have an adverse effect on demand for our coal. Customers choose coal supplies based, primarily, on the total delivered cost of coal. Any increase in transportation costs would cause an increase in the total delivered cost of coal. That could cause some of our customers to seek less expensive sources of coal or alternative fuels to satisfy their energy needs. In addition, significant decreases in transportation costs from other coal-producing regions, both domestic and international, could result in increased competition from coal producers in those regions. For instance, coal mines in the western United States could become more attractive as a source of coal to consumers in the eastern United States. if the costs of transporting coal from the West were significantly reduced.
Our Central Appalachia mines generally ship coal via rail systems. During 2006, we shipped in excess of 95% of our coal from our Central Appalachia mines via CSX. In the Midwest, we shipped approximately 63% of our produced coal by truck and the remainder via rail systems. Our dependence upon railroads and third party trucking companies impacts our ability to deliver coal to our customers. Disruption of service due to weather-related problems, strikes, lockouts, bottlenecks and other events could temporarily impair our ability to supply coal to our customers, resulting in decreased shipments. Decreased performance levels over longer periods of time could cause our customers to look elsewhere for their fuel needs, negatively affecting our revenues and profitability.
In past years, the major eastern railroads (CSX and Norfolk Southern) have experienced an increase in overall rail traffic from the expanding economy and shortages of both equipment and personnel. This incre