Alpha Appalachia Holdings, Inc. 10-K 2008
Documents found in this filing:
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
For the fiscal year ended December 31, 2007
For the transition period from to
Commission File No. 1-7775
MASSEY ENERGY COMPANY
(Exact name of registrant as specified in its charter)
Registrant’s telephone number, including area code: (804) 788-1800
Securities registered pursuant to Section 12(b) of the Act:
Securities registered pursuant to Section 12(g) of the Act:
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes x No ¨
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ¨ No x
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No ¨
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ¨
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer,” “non-accelerated filer” and “smaller reporting company in Rule 12b-2 of the Exchange Act (Check One):
Large accelerated filer x Accelerated filer ¨ Non-accelerated filer ¨ (Do not check if a smaller reporting company) Smaller reporting company ¨
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨ No x
The aggregate market value of the Common Stock held by non-affiliates of the registrant on June 30, 2007, was $2,162,792,929 based on the last sales price reported that date on the New York Stock Exchange of $26.65 per share. In determining this figure, the Registrant has assumed that all of its directors and executive officers are affiliates. Such assumptions should not be deemed to be conclusive for any other purpose.
Common Stock, $0.625 par value, outstanding as of February 15, 2008 — 80,491,644 shares.
DOCUMENTS INCORPORATED BY REFERENCE
Part III incorporates certain information by reference from the registrant’s definitive proxy statement for the 2008 Annual Meeting of Shareholders, which proxy statement will be filed no later than 120 days after the close of the registrant’s fiscal year ended December 31, 2007.
Forward Looking Statements
From time to time, Massey Energy Company, which includes its direct and wholly owned subsidiary, A.T. Massey Coal Company, Inc, and its direct and indirect wholly owned subsidiaries (“we,” “our,” “us”), makes certain comments and disclosures in reports, including this report, or through statements made by our officers that may be forward-looking in nature. Examples include statements related to our future outlook, anticipated capital expenditures, projected cash flows and borrowings, and sources of funding. We caution readers that forward-looking statements, including disclosures that use words such as “believe,” “anticipate,” “expect,” “estimate,” “intend,” “may,” “plan,” “project,” “will” and similar statements are subject to certain risks, trends 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 the expectations 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. These assumptions are 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 circumstances and events beyond our control. We disclaim any obligation to update these forward-looking statements unless required by securities law, and we caution the reader not to rely on them unduly.
We have based any forward-looking statements we have made on our current expectations and assumptions about future events and circumstances that are subject to risks, uncertainties and contingencies that could cause results to differ materially from those discussed in the forward-looking statements, including, but not limited to:
Any forward-looking statements should be considered in context with the various disclosures made by us about our businesses, including without limitation the risk factors more specifically described below in Item 1A. Risk Factors of this Annual Report on Form 10-K. We are including this cautionary statement in this document to make applicable and take advantage of the safe harbor provisions of the Private Securities Litigation Reform Act of 1995 for any forward-looking statements made by, or on behalf, of us.
2007 ANNUAL REPORT ON FORM 10-K>
TABLE OF CONTENTS
Annual Shareholders Meeting
Our 2008 Annual Meeting of Shareholders will be held at 9:00 a.m. EDT on Tuesday, May 13, 2008 at The Jefferson Hotel, 101 West Franklin Street, Richmond, Virginia 23220.
Because certain terms used in the coal industry may be unfamiliar to many investors, we have provided a Glossary of Selected Terms beginning on page 19 at the end of Item 1. Business.
Item 1. Business
We are one of the premier coal producers in the United States. As measured by 2007 revenue, Energy Ventures Analysis, Inc. (“EVA”) ranks us as the fourth largest United States coal company in terms of coal revenue. We are the largest coal company in Central Appalachia, our primary region of operation, in terms of revenue, tons produced and total coal reserves.
We produce, process and sell bituminous coal of various steam and metallurgical grades, primarily of a low sulfur content, through our 22 processing and shipping centers (“Resource Groups”), many of which receive coal from multiple mines. At January 31, 2008, we operated 47 mines, including 35 underground (one of which employs both room and pillar and longwall mining) and 12 surface (with eight highwall miners in operation) in West Virginia, Kentucky and Virginia. The number of mines that we operate may vary from time to time depending on a number of factors, including the existing demand for and price of coal, exhaustion of economically recoverable reserves and availability of experienced labor.
Customers for our steam coal product include primarily electric power utility companies who use our coal as fuel for their steam-powered generators. Customers for our metallurgical coal include primarily steel producers who use our coal to produce coke, which is in turn used as a raw material in the steel manufacturing process.
Key statistics for 2007 include:
A.T. Massey was originally incorporated in Richmond, Virginia in 1920 as a coal brokering business. In the late 1940s, A.T. Massey expanded its business to include coal mining and processing. In 1974, St. Joe Minerals acquired a majority interest in A.T. Massey. In 1981, St. Joe Minerals was acquired by Fluor Corporation. A.T. Massey was wholly owned by Fluor Corporation from 1987 until November 30, 2000. On November 30, 2000, we completed a reverse spin-off (the “Spin-Off”) which separated Fluor Corporation into two entities: the “new” Fluor Corporation (“New Fluor”) and Fluor Corporation which retained our coal-related businesses and was subsequently renamed Massey Energy Company. Massey Energy Company has been a separate, publicly traded company since December 1, 2000.
Coal is the second most widely used form of energy in the United States, accounting for nearly one-fourth of the nation’s total energy consumption, according to the BP Statistical Review of World Energy (“BP”), June 2007. In 2006, coal was the fuel source of 50% of the electricity generated nationwide, as reported by the Energy Information Administration (“EIA”), a statistical agency of the United States Department of Energy.
The United States is the second largest coal producer in the world, exceeded only by China. Other leading coal producers include India, Australia, South Africa, Russia and Indonesia. The United States has the largest coal reserves in the world, with proved reserves totaling 247 billion tons. Russia ranks second in proved coal reserves with 157 billion tons, followed by China with 115 billion tons, according to BP.
United States coal reserves are more plentiful than oil or natural gas with 234 years of supply at current consumption rates. Proved United States reserves of oil amount to 12 years of supply at current production rates and proved United States reserves of natural gas amount to 11 years of supply at current levels of consumption, as reported by the BP study.
United States coal production has more than doubled over the last 40 years. In 2006, total United States coal production, as estimated by the EIA, was 1.2 billion tons. The primary producing regions by tons were as follows:
The EIA estimated that approximately 69% of United States coal was produced by surface mining methods. The remaining 31% was produced by underground mining methods, which include room and pillar mining and longwall mining (more fully described in Item 1. Business, under the heading “Mining Methods”).
Coal is used in the United States by utilities to generate electricity, by steel companies to make steel products, and by a variety of industrial users to produce heat and to power foundries, cement plants, paper mills, chemical plants and other manufacturing and processing facilities. Significant quantities of coal are also exported from both East and Gulf Coast terminals. The breakdown of 2006 United Statescoal consumption, as estimated by the EIA, is as follows:
Coal has long been favored as an electricity generating fuel because of its basic economic advantage. The largest cost component in electricity generation is fuel. This fuel cost is typically lower for coal than competing fuels such as oil and natural gas on a Btu-comparable basis. Platts, which provides global commodity news and information, estimated the average total production costs of electricity, using coal and competing generation alternatives in 2006 as follows:
There are factors other than fuel cost that influence each utility’s choice of electricity generation mode, including facility construction cost, access to fuel transportation infrastructure, environmental restrictions, and other factors. The breakdown of United States electricity generation by fuel source in 2006, as estimated by EIA, is as follows:
Demand for electricity has historically been driven by United States economic growth but it can fluctuate from year to year depending on weather patterns. In 2006, electricity consumption in the United States increased 0.2%but the average growth rate in the past decade was approximately 1.5% per year according to EIA estimates. Because coal-fired generation is used in most cases to meet base load requirements, coal consumption has generally grown at the pace of electricity demand growth.
According to the World Coal Institute (“WCI”), in 2006 the United States ranked seventh among worldwide exporters of coal. Australia was the largest exporter, with other major exporters including Indonesia, China, South Africa, Russia, Columbia and Canada. According to EVA, United States exports increased by 19% from 2006 to 2007. The usage breakdown for 2007 United States exports of 59 million tons was 45% for electricity generation and 55% for steel production. In 2007, United States coal exports were shipped to more than 30 countries. The largest purchaser of United States exported utility coal in 2007 continued to be Canada, which took 14.6 million tons or 55% of total utility coal exports. This was down 4% compared to the 15.2 million tons exported to Canada in 2006. Overall steam coal exports increased 22% in 2007 compared to 2006. The largest purchasers of United States exported metallurgical coal were Brazil, which imported approximately 6.5 million tons, or 20%, and Canada, which imported 3.7 million tons, or 12%. In total, metallurgical coal exports increased 16% in 2007 compared to 2006.
Depending on the relative strength of the United States dollar versus currencies in other coal producing regions of the world, United States producers may export more or less coal into foreign countries as they compete on price with other foreign coal producing sources. Likewise, the domestic coal market may be impacted due to the relative strength of the United States dollar to other currencies, as foreign sources could be cost-advantaged based on a coal producing region’s relative currency position. During 2007, the United States dollar weakened, making imported coal less competitive with United States produced coal, and positively impacting the competitiveness of United States exports in some overseas markets.
From 2003 to February 2008, the global marketplace for coal experienced swings in the demand/supply balance. In periods of supply shortfall, as occurred from 2003 to early 2006 and again in late 2007 through February 2008, the prices for coal reached record highs in the United States. Increased worldwide demand has been primarily driven by higher prices for oil and natural gas and economic expansion, particularly in China, India and elsewhere in Asia. At the same time, infrastructure and regulatory limitations in China contributed to a tightening of worldwide coal supply, affecting global prices of coal. The growth in China and India caused an increase in worldwide demand for raw materials and a disruption of expected coal exports from China to Japan, Korea and other countries.
Metallurgical grade coal is distinguished by special quality characteristics that include high carbon content, volatile matter, low expansion pressure, low sulfur content, and various other chemical attributes. High vol met coal is also high in heat content (as measured in Btus), and therefore is desirable to utilities as fuel for electricity generation. Consequently, high vol met coal producers have the ongoing opportunity to select the market that provides maximum revenue and profitability. The premium price offered by steel makers for the metallurgical quality attributes is typically higher than the price offered by utility coal buyers that value only the heat content. The primary concentration of United States metallurgical coal reserves is located in the Central Appalachian region. EVA estimates that the Central Appalachian region supplied 89% of domestic metallurgical coal and 73% of United States exported metallurgical coal during 2006.
For utility coal buyers, the primary goal is to maximize heat content, with other specifications like ash content, sulfur content, and size varying considerably among different customers. Low sulfur coals, such as those produced in the western United States and in Central Appalachia, generally demand a higher price due to restrictions on sulfur emissions imposed by the Clean Air Act of 1963 (“Clean Air Act”) and the volatility in SO2 allowance prices that occurred in recent years when the
demand for all specifications of coal increased. SO2 allowances permit utilities to emit a higher level of SO2 than otherwise required under the Clean Air Act regulations. The demand and premium price for low sulfur coal is expected to diminish as more utilities install scrubbers at their coal-fired plants.
Coal shipped for North American consumption is typically sold at the mine loading facility with transportation costs being borne by the purchaser. Offshore export shipments are normally sold at the ship-loading terminal, with the purchaser paying the ocean freight. According to the National Mining Association (“NMA”), approximately two-thirds of United States coal production in recent years was shipped via railroads. Final delivery to consumers often involves more than one transportation mode. A significant portion of United States production is delivered to customers via barges on the inland waterway system and ships loaded at Great Lakes ports.
Neither we nor any of our subsidiaries are affiliated with or have any investment in BP, EIA, EVA, Platts or WCI. We are a member of the NMA.
We produce coal using four distinct mining methods: underground room and pillar, underground longwall, surface and highwall mining, which are explained as follows:
In the underground room and pillar method of mining, continuous mining machines cut three to nine entries into the coal bed 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, 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 fall upon retreat. When retreat mining is completed to the mouth of the panel, the mined panel is abandoned.
In longwall mining (which is a type of underground mining), a shearer (cutting head) moves back and forth across a panel of coal typically about 1,000 feet in width, cutting a slice approximately 3.5 feet deep. The cut coal falls onto a flexible conveyor for removal. Longwall mining is performed under hydraulic roof supports (shields) that are advanced as the seam is cut. The roof in the mined out areas falls as the shields advance.
Surface mining is used to extract coal deposits found close to the surface. This method involves removal of overburden (earth and rock covering coal) with heavy earth moving equipment, including large shovels and draglines, and explosives, followed by extraction of coal from coal seams. After extraction of coal, disturbed parcels of land are reclaimed by replacing overburden and reestablishing vegetation and plant life.
Highwall mining is used in connection with surface mining. A highwall mining system consists of a remotely controlled continuous mining machine, which extracts coal and conveys it via augers or belt conveyors to the portal. The cut is typically a rectangular, horizontal opening in the highwall (the unexcavated face of exposed overburden and coal in a surface mine) 11-feet wide and reaching depths of up to 1,000 feet. Multiple, parallel openings are driven into the highwall, separated by narrow pillars that extend the full depth of the hole.
Use of continuous mining machines in the room and pillar method of underground mining represented approximately 41% of our 2007 coal production. Production from underground longwall mining operations constituted approximately 6% of our 2007 production. Surface mining represented approximately 47% of our 2007 coal production. Surface mines also use highwall mining systems to produce coal from high overburden areas. Highwall mining represented approximately 6% of our 2007 coal production.
We currently have 22 distinct Resource Groups, including sixteen in West Virginia, five in Kentucky and one in Virginia. These complexes blend, process and ship coal that is produced from one or more mines, with a single complex handling the coal production of as many as seven distinct underground or surface mines. Our mines have been developed at strategic locations in close proximity to our preparation plants and rail shipping facilities.
We operate solely in the Central Appalachian region, which is the principal source of low sulfur bituminous coal in the United States, used for power generation, metallurgical coke production and industrial boilers. Central Appalachian coal accounted for 20% of 2007 United States coal production according to EIA.
The following map provides the location of our operations within the Central Appalachian region:
The following table provides key operational information on our Resource Groups in 2007:
The following descriptions of the Resource Groups are current as of January 31, 2008.
West Virginia Resource Groups
Black Castle. The Black Castle complex includes a large surface mine, two highwall miners, the Homer III direct-ship loadout, a stoker plant, and the Omar preparation plant. Some of the surface mine coal is trucked to the stoker plant where the coal is crushed and screened. The stoker product is trucked to river docks for barge delivery or trucked directly to customers. A portion of the coal is transported to the Omar plant via an underground belt conveyor system, where it is crushed and
shipped to customers or, if the coal needs processing, it is belted to the preparation plant at the Independence Resource Group for processing and shipment. The Omar preparation plant was not utilized for processing coal in 2006. The direct-ship facility at the preparation plant can crush 500 tons per hour and the preparation plant can process 800 tons per hour. The Omar preparation plant serves CSX rail system customers with unit train shipments of up to 110 railcars. Coal is also trucked to the Homer III loadout where it is crushed and shipped to customers by rail, trucked to river docks for barge delivery, or trucked directly to customers. The Homer III loadout serves CSX rail system customers with unit train shipments of up to 100 railcars.
Delbarton. The Delbarton complex includes one underground room and pillar mine and a preparation plant. Production from the mine is transported to the Delbarton preparation plant via overland conveyor. The Delbarton preparation plant also processes coal from two surface mines of the Logan County Resource Group. The Delbarton preparation plant can process 600 tons per hour. The clean coal product is shipped to customers via the Norfolk Southern railway in unit trains of up to 110 railcars.
Edwight. The Edwight complex includes one underground room and pillar mine, a surface mine, a highwall miner and the Goals preparation plant. Production from all of the mines is transported via conveyor system to the Goals preparation plant. The Goals preparation plant can process 800 tons per hour. The rail loading facility serves CSX railway customers with unit trains of up to 100 railcars.
Elk Run. The Elk Run complex produces coal from four underground room and pillar mines and the Logans Fork longwall. All of the room and pillar mines belt coal to the Elk Run preparation plant, while the longwall belts coal to the preparation plant of the Marfork Resource Group. Additionally, Elk Run processes coal produced by surface mines of the Progress Resource Group and transported via underground conveyor system. The Elk Run preparation plant has a processing capacity of 2,200 tons per hour. Elk Run also operates a 200 ton per hour stoker facility that produces screened, small dimension coal for certain of our industrial customers. Customer shipments are loaded on the CSX rail system in unit trains of up to 150 railcars.
Endurance. The Endurance complex includes a surface mine, highwall miner and a direct-ship loadout. A portion of the production from the surface mine is loaded for shipment to customers at the direct ship loadout and the remainder is trucked to a conveyor system, which transports the coal to the preparation plant at the Independence Resource Group for processing.
Green Valley. The Green Valley complex includes two underground room and pillar mines and a preparation plant. The Green Valley preparation plant, which has a processing capacity of 600 tons per hour, receives coal from the mines via trucks. The rail loading facility services customers on the CSX rail system with unit train shipments of up to 75 railcars.
Guyandotte. The Guyandotte complex, formerly known as Kepler, includes one underground room and pillar mine. The mine trucks coal to a third-party preparation plant for washing and shipment to customers via the Norfolk Southern railway system.
Independence. The Independence complex includes the Revolution longwall mine, two underground room and pillar mines and a preparation plant. Production from the underground mines is transported via overland conveyor system to the Independence preparation plant. The Black Castle surface mine and highwall miner and the surface mine at the Endurance Resource Group transport coal requiring processing to the Independence preparation plant via conveyor system. The Independence plant has a processing capacity of 2,200 tons per hour. Customers are served via rail shipments on the CSX rail system in unit trains of up to 150 railcars.
Logan County. The Logan County complex includes four surface mines, one highwall miner and two underground room and pillar mines, plus the Bandmill preparation plant and the Feats loadout, all on the CSX rail system. The surface mines and the highwall miners deliver coal to the Bandmill plant via truck and conveyor system, while both underground mines belt coal directly to this plant. The Feats loadout can service customers via the CSX rail system with unit train shipments of up to 80 cars. The Bandmill preparation plant has a processing capacity of 1,800 tons per hour. The Bandmill rail loading facility services customers via the CSX rail system with unit train shipments of up to 150 railcars.
Mammoth. The Mammoth complex operates three underground room and pillar mines and a preparation plant. Coal is transported to the preparation plant, with two mines using on-highway trucks and one mine using a conveyor system. The plant has a 1,200 tons per hour processing facility capacity with barge loading capabilities on the upper Kanawha River.
Marfork. The Marfork complex includes seven underground room and pillar mines and a preparation plant. Production from six of the mines is belted directly to the preparation plant via conveyor while the remainder is trucked on private haul
roads to the preparation plant. The Marfork preparation plant has a capacity of 2,400 tons per hour. Customers are served via the CSX rail system with unit trains of up to 150 railcars.
Nicholas Energy. The Nicholas Energy complex includes an underground room and pillar mine, a large surface mine, two highwall miners and a preparation plant. Coal from the underground mine is transported to the preparation plant for processing via conveyor system. Coal from the highwall miners and the portion of surface mined coal requiring processing is transported to the preparation plant using off-road trucks. Coal not requiring processing is transported via off road trucks to a conveyor system that moves the coal directly to a rail loadout facility. The plant has a processing capacity of 1,200 tons per hour. Coal shipments are loaded into rail cars for delivery via the Norfolk Southern railway in unit trains of up to 140 railcars, or are transported via on-highway trucks to the Mammoth Resource Group’s barge loading facility.
Progress. The Progress complex includes the large Twilight MTR surface mine. A dragline is also utilized at the Twilight MTR surface mine. Production from the Twilight MTR surface mine is transported via underground conveyor to the Elk Run Resource Group for processing and rail shipment.
Rawl. The Rawl complex includes two underground room and pillar mines and a preparation plant. Production from the mines is transported via truck to the preparation plant of the Stirrat Resource Group. The Rawl plant, which was idled in December 2006, has a throughput capacity of 1,450 tons per hour. Customers are served via the Norfolk Southern railway with unit trains of up to 150 railcars.
Republic Energy. The Republic Energy complex consists of one surface mine. Direct-ship coal is trucked using on-highway trucks to various docks on the Kanawha River for barge delivery to customers and to the Marfork Resource Group for rail delivery to customers. Coal requiring processing is trucked using on-highway trucks to Mammoth Resource Group’s preparation plant for processing and barge delivery to customers.
Stirrat. The Stirrat complex includes one surface mine, a preparation plant and the Superior loadout. The surface mine belts coal directly to two 12,500 ton silos at the Superior loadout. The Superior loadout serves CSX railway customers with unit trains of up to 100 railcars. The Stirrat preparation plant cleans coal from two adjacent underground room and pillar mines of the Rawl Resource Group. The plant has a rated capacity of 600 tons per hour. Customers are served via the CSX rail system with unit trains of up to 100 railcars.
Coalgood Energy. The Coalgood Energy complex, which was idled in January 2007, includes one surface mine and a direct-ship loadout. When in operation, the coal is trucked off-road to the loadout, which serves CSX railway customers with unit trains of up to 75 railcars. Although no firm plans have been made, we continue to evaluate options for the complex, which may include a resumption of operations, allowing it to remain idle or pursuing disposal alternatives.
Long Fork. The Long Fork preparation plant processes coal produced by two underground room and pillar mines of the Sidney Resource Group. All production is transported via conveyor system to the Long Fork preparation plant for processing and shipping to customers. The Long Fork plant has a rated capacity of 1,500 tons per hour. The rail loading facility services customers on the Norfolk Southern railway with unit trains of up to 150 railcars.
Martin County. The Martin County complex, which was idled in January 2007, has historically produced coal from underground and surface mines. Direct-ship coal production from the surface mines was shipped to river docks via truck. Coal requiring processing was transported by conveyor belt or truck to the preparation plant. Martin County’s preparation plant has a throughput capacity of 1,500 tons per hour, although the throughput capacity is limited due to decreased impoundment availability. The coal from the preparation plant can be shipped either via the Norfolk Southern railway in unit trains of up to 125 railcars or to river docks via truck. Although no firm plans have been made, we continue to evaluate options for the complex, which may include a resumption of operations, allowing it to remain idle or pursuing disposal alternatives.
New Ridge. The New Ridge complex loads clean coal that is transported via truck from the preparation plant of the Sidney Resource Group and coal trucked directly from Sidney’s surface mine. The New Ridge preparation plant has a capacity of 800 tons per hour. The preparation plant is currently idle but may be reactivated from time to time during 2008 as needed. All coal is loaded for shipment to customers via the CSX rail system in unit trains of up to 100 railcars.
Sidney. The Sidney complex includes six underground room and pillar mines, one surface mine, a highwall miner and a preparation plant. Two of the underground mines transport coal via underground conveyor system to the Long Fork Resource Group for processing and shipment, and the remainder of the underground mines transport production via underground conveyor system or truck to Sidney’s preparation plant. A portion of the coal from Sidney’s preparation plant and coal from the surface mines are trucked to the New Ridge Resource Group for loading into railroad cars. Sidney’s preparation plant has
a capacity of 1,500 tons per hour. The rail loading facility at the preparation plant serves customers on the Norfolk Southern rail system with unit trains of up to 140 railcars.
Knox Creek. The Knox Creek complex includes one underground room and pillar mine and a preparation plant. Production from the mine is belted by conveyor system to the preparation plant. The preparation plant has a feed capacity of 650 tons per hour. The preparation plant serves customers on the Norfolk Southern rail system with unit trains of up to 100 railcars.
We estimate that, as of December 31, 2007, we had total recoverable reserves of approximately 2.3 billion tons consisting of both proven and probable reserves. “Reserves” are defined by the 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. “Recoverable” reserves means coal that is economically recoverable using existing equipment and methods under federal and state laws currently in effect. Approximately 1.5 billion tons of reserves are classified as proven reserves. “Proven (measured) reserves” are defined by the SEC Industry Guide 7 as 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 inspection, 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. The remaining 0.8 billion tons of our reserves are classified as probable reserves. “Probable reserves” are defined by the SEC Industry Guide 7 as reserves for which quantity and grade and/or quality are computed from information similar to that used for proven (measured) 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 (measured) reserves, is high enough to assume continuity between points of observation.
Information about our reserves consists of estimates based on engineering, economic and geological data assembled and analyzed by our internal engineers, geologists and finance associates. Reserve estimates are updated annually using geologic data taken from drill holes, adjacent mine workings, outcrop prospect openings and other sources. Coal tonnages are categorized according to coal quality, seam thickness, mineability and location relative to existing mines and infrastructure. In accordance with applicable industry standards, proven reserves are those for which reliable data points are spaced no more than 2,700 feet apart. Probable reserves are those for which reliable data points are spaced 2,700 feet to 7,900 feet apart. Further scrutiny is applied using geological criteria and other factors related to profitable extraction of the coal. These criteria include seam height, roof and floor conditions, yield and marketability.
As with most coal-producing companies in Central Appalachia, the majority of our coal reserves are controlled pursuant to leases from third party landowners. These leases convey mining rights to the coal producer in exchange for a per ton or percentage of gross sales price royalty payment to the lessor. However, approximately 18% of our reserve holdings are owned and require no royalty or per ton payment to other parties. Royalty expense for coal reserves from our producing properties (owned and leased) was approximately 4.1% of Produced coal revenue for the year ended December 31, 2007.
The following table provides proven and probable reserve data by “status” (i.e., location, owned or leased, assigned or unassigned, etc.) as of December 31, 2007:
The categorization of the “quality” (i.e., sulfur content, Btu, coal type, etc.) of coal reserves is as follows:
Compliance compared to non-compliance coal
Coals are sometimes characterized as compliance or non-compliance coal. The phrase compliance coal, as it is commonly used in the coal industry, refers to compliance only with sulfur dioxide emissions standards imposed by Title IV of the Clean Air Act and indicates that when burned, the coal will produce emissions that will meet the current standard without further cleanup. A coal that is considered a compliance coal for meeting sulfur dioxide standards may not meet an emission standard for a different pollutant such as mercury. Moreover, the term compliance coal is always used with reference to the then-current regulatory limit. Clean air regulations that further restrict sulfur dioxide emissions will likely reduce significantly the amount of coal that can be labeled compliance. Currently, coal classified as compliance will meet the power plant emission standard of 1.2 pounds of sulfur dioxide per million Btu’s of fuel consumed. At December 31, 2007, approximately 0.9 billion tons, or 41%, of our coal reserves met the current standard as compliance coal.
We employ transportation specialists who negotiate freight and terminal agreements with various providers, including railroads, barge lines, ocean-going vessels, bulk motor carriers and terminal facilities. Transportation specialists also coordinate with customers, mining facilities and transportation providers to establish shipping schedules that meet each customer’s needs.
Our 2007 shipments of 39.9 million tons were loaded from 22 mining complexes. Rail shipments constituted 90% of total shipments, with 25% loaded on Norfolk Southern trains and 65% loaded on CSX trains. The balance was shipped from mining complexes via truck or barge.
Approximately 20% of production was ultimately delivered via the inland waterway system. Coal is loaded directly into barges, or is transported by rail or truck to docks on the Ohio, Big Sandy and Kanawha Rivers and then ultimately transported by barge to electric utilities, integrated steel producers and industrial consumers served by the inland waterway system. We also moved approximately 4% of our production to Great Lakes’ ports for transport to various United States and Canadian customers.
Customers and Coal Contracts
We have coal supply commitments with a wide range of electric utilities, steel manufacturers, industrial customers and energy traders and brokers. By offering coal of both steam and metallurgical grades, we are able to serve a diverse customer base. This market diversity allows us to adjust to changing market conditions and sustain high sales volumes. The majority of our customers purchase coal for terms of one year or longer, but we also supply coal on a spot basis for some customers. Our largest customer, American Electric Power Company, Inc. and its affiliates, accounted for 11% of total fiscal year 2007 Produced coal revenue.
As is customary in the coal industry, we enter into long-term contracts (one year or more in duration) 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. Long-term contracts are a result of extensive negotiations with customers. As a result, the terms of these contracts vary with respect to price adjustment mechanisms, pricing terms, permitted sources of supply, force majeure provisions, quality adjustments and other parameters. Some of the contracts contain price adjustment mechanisms that allow for changes to prices based on statistics from the United States Department of Labor. Coal quality specifications may be especially stringent for steel customers.
For the year ended December 31, 2007, approximately 95% of coal sales volume was pursuant to long-term contracts. We anticipate that in 2008, coal sales volume percentage pursuant to long-term arrangements will be comparable to 2007. As of February 14, 2008, we had contractual sales commitments of approximately 123 million tons, including commitments subject to price reopener and/or optional tonnage provisions. Remaining contractual terms of our sales commitments range from one to 12 years with an average volume-weighted remaining term of approximately 2.3 years. Eighty-four percent of the contracted sales tons are priced. As of February 14, 2008, we have committed most of our expected 2008 production. In addition, we purchase coal from third-party coal producers from time to time to supplement production and resell this coal to customers.
The main types of goods we purchase are mining equipment and replacement parts, explosives, fuel, tires, steel-related (including roof control) products and lubricants. Although we have many well-established, strategic relationships with our key suppliers, we do not believe that we are dependent on any of our individual suppliers, except as noted below. The supplier base providing mining materials has been relatively consistent in recent years, although there continues to be some consolidation. Consolidation of suppliers of explosives has limited the number of sources for these materials. Although our current supply of explosives is concentrated with one supplier, some alternative sources are available to us in the regions where we operate. Further consolidation of underground equipment suppliers has resulted in a situation where purchases of
certain underground mining equipment are concentrated with one principal supplier; however, supplier competition continues to develop. In recent years, demand for certain surface and underground mining equipment and off-the-road tires has increased. As a result, lead times for certain items have generally increased, although no material impact is currently expected to our cash flows, results of operations or financial condition.
The coal industry in the United States and overseas is highly competitive, with numerous producers selling into all markets that use coal. We compete against large and small producers in the United States and overseas. The NMA estimated that in 2006 there were 25 coal companies in the United States with annual production in excess of 5 million tons, which together account for approximately 84% of United States production. According to the EIA, we were the sixth largest coal company in terms of tons produced in 2006, exceeded by Peabody Energy Corporation (“Peabody”), Rio Tinto Energy America, Inc., Arch Coal, Inc. (“Arch”), CONSOL Energy Inc. (“CONSOL”), and Foundation Coal Holdings Inc. (“Foundation”) . However, according to company reports, we were the fourth largest United States coal company in terms of revenue in 2006, exceeded by Peabody, CONSOL and Arch.
We compete with other producers primarily on the basis of price, coal quality, transportation cost and reliability of supply. Continued demand for coal is also dependent on factors outside of our control, including demand for electricity and steel, general economic conditions, environmental and governmental regulations, weather, technological developments, and the availability and cost of alternative fuel sources. We sell coal to foreign electricity generators and to the more specialized metallurgical coal market, both of which are significantly affected by international demand and competition.
Historically, global coal markets have responded to increased demand and higher prices for coal by increasing production and supply. In recent years, however, capacity expansion has been somewhat limited by the increased costs of mining, high capital requirements, coal seam degradation, reserve depletion, labor shortages, transportation issues related to rail, barge and truck shipments, higher costs related to compliance with new and increasingly stringent regulations, the difficulty of obtaining permits and bonding, and other factors. While these constraints persist in major coal producing countries and regions, periods of supply and demand imbalance may be extended and increased pricing volatility, particularly upward, may result.
Other Related Operations
We have other related operations and activities in addition to our normal coal production and sales business. The following business activities are included in this category:
Coal Handling Joint Venture. We hold a 50% interest in a joint venture that owns and operates third-party end-user coal handling facilities. Certain subsidiaries currently operate the coal handling facilities for the joint venture.
Gas Operations. We hold interests in operations that produce, gather and market natural gas from shallow reservoirs in the Appalachian Basin. In the eastern United States, conventional natural gas reservoirs are located in various types of sedimentary formations at depths ranging from 2,000 to 15,000 feet. The depths of the reservoirs drilled and operated by us range from 2,500 to 5,600 feet.
Nearly all of our gas production is from operations in southern West Virginia. In this region, we own and operate approximately 188 wells, 200 miles of gathering line, and various small compression facilities. Our southern West Virginia operations control approximately 27,000 acres of drilling rights. In addition, we own a majority working interest in 48 wells operated by others, and minority working interests in approximately 30 wells operated by others. The December 2007 average daily production, from the 236 wells owned or controlled, was 1.9 million cubic feet per day. We do not consider our current gas production level, revenues or costs to be material to our cash flows, results of operations or financial condition.
Other. From time to time, we also engage in the sale of certain non-strategic assets such as timber, oil and gas rights, surface properties and reserves. In addition, we have established several contractual arrangements with customers where services other than coal supply are provided on an ongoing basis. None of these contractual arrangements is considered to be material. Examples of such other services include arrangements with several metallurgical and industrial customers to coordinate shipment of coal to their stockpiles, maintain ownership of the coal inventory on their property and sell tonnage to them as it is consumed. We work closely with customers to provide other services in response to the current needs of each individual customer.
Marketing and Sales
Our marketing and sales force, based in the corporate office in Richmond, Virginia, includes sales managers, distribution/traffic managers and administrative personnel.
During the year ended December 31, 2007, we sold 39.9 million tons of produced coal for total Produced coal revenue of $2.1 billion. The breakdown of produced tons sold by market served was 69% utility, 21% metallurgical and 10%
industrial. Sales were concluded with over 100 customers. Export shipment revenue totaled approximately $330.7 million, representing approximately 16.1% of 2007 Produced coal revenue. In 2007, we exported shipments to customers in 12 countries across the globe, which included Brazil, Canada, Egypt, Finland, Germany, India, Japan, Italy, Netherlands, South Korea, Spain and Sweden. Sales are made in United States dollars, which minimizes foreign currency risk.
Employees and Labor Relations
As of December 31, 2007, we had 5,407 employees, including 108 employees affiliated with the United Mine Workers of America (“UMWA”). Relations with employees are generally good, and there have been no material work stoppages in the past ten years.
Environmental, Safety and Health Laws and Regulations
The coal mining industry is subject to regulation by federal, state and local authorities on matters such as the discharge of materials into the environment, employee health and safety, permitting and other licensing requirements, reclamation and restoration of mining properties after mining is completed, management of materials generated by mining operations, surface subsidence from underground mining, water pollution, water appropriation and legislatively mandated benefits for current and retired coal miners, air quality standards, protection of wetlands, endangered plant and wildlife protection, limitations on land use, and storage of petroleum products and substances that are regarded as hazardous under applicable laws. The possibility exists that new legislation or regulations may be adopted that could have a significant impact on our mining operations or on our customers’ ability to use coal.
Numerous governmental permits and approvals are required for mining operations. Regulations provide that a mining permit or modification can be delayed, refused or revoked if an officer, director or a stockholder with a 10% or greater interest in the entity is affiliated with or is in a position to control another entity that has outstanding permit violations. Thus, past or ongoing violations of federal and state mining laws by individuals or companies no longer affiliated with us could provide a basis to revoke existing permits and to deny the issuance of addition permits. We are required to prepare and present to federal, state or local authorities data and/or analysis pertaining to the effect or impact that any proposed exploration for or production of coal may have upon the environment, public and employee health and safety. All requirements imposed by such authorities may be costly and time-consuming and may delay commencement or continuation of exploration or production operations. Accordingly, the permits we need for our mining and gas operations may not be issued, or, if issued, may not be issued in a timely fashion. Permits we need may involve requirements that may be changed or interpreted in a manner that restricts our ability to conduct our mining operations or to do so profitably. Future legislation and administrative regulations may increasingly emphasize the protection of the environment, 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 equipment and operating costs, delays, interruptions or a termination of operations, the extent of which cannot be predicted.
While it is not possible to quantify the expenditures we incur to maintain compliance with all applicable federal and state laws, those costs have been and are expected to continue to be significant. We post surety performance bonds or letters of credit pursuant to federal and state mining laws and regulations for the estimated costs of reclamation and mine closing, often including the cost of treating mine water discharge when necessary. Compliance with these laws has substantially increased the cost of coal mining for all domestic coal producers. We endeavor to conduct our mining operations in compliance with all applicable federal, state and local laws and regulations. However, even with our substantial efforts to comply with extensive and comprehensive regulatory requirements, violations during mining operations occur from time to time. In 2007, the EPA filed suit against us and twenty-seven of our subsidiaries alleging violations of the Federal Clean Water Act. In January 2008, we announced that we had agreed with the EPA to settle the lawsuit for a payment of $20 million in penalties (see Note 17 to the Notes to Consolidated Financial Statements). In 2007, we spent approximately $23.1 million to comply with environmental laws and regulations, of which $13.8 million was for reclamation, including $11.1 million for final reclamation. None of these expenditures were capitalized. We anticipate spending approximately $38.8 million and $31.7 million in such non-capital expenditures in 2008 and 2009, respectively. Of these expenditures, $29.3 million and $22.0 million for 2008 and 2009, respectively, are anticipated to be for reclamation.
Emission Control Technology. We own a majority interest in Coalsolv, LLC, which holds the United States marketing rights for the coal-fired plant emission control technologies developed by Cansolv Technologies, Inc., in which we hold a minority interest. Cansolv’s technologies remove sulfur dioxide (SO2), nitrogen oxide (NOx), mercury, carbon dioxide (CO2), and other greenhouse gases from flue gas emissions. The Cansolv process has been utilized at various industrial facilities around the world, with additional projects underway in China and Canada. Through Coalsolv, we contributed funds for a pilot plant that has been utilized in the United States and Canada for the testing and piloting of the Cansolv SO2, NOX, mercury, and CO2 capture technology on coal-fired power plants.
Mine Safety and Health
Stringent health and safety standards have been in effect since Congress enacted the Federal Coal Mine Health and Safety Act of 1969. The Federal Coal Mine Safety and Health Act of 1977 significantly expanded the enforcement of safety and health standards and imposed safety and health standards on all aspects of mining operations. A further expansion occurred in June 2006 with the enactment of the Mine Improvement and New Emergency Response Act of 2006 (“MINER Act”).
The MINER Act and related Mine Safety and Health Administration (“MSHA”) regulatory action require, among other things, improved emergency response capability, increased availability of emergency breathable air, enhanced communication and tracking systems, more available mine rescue teams, increased mine seal strength and monitoring of sealed areas in underground mines, as well as larger penalties by MSHA for noncompliance by mine operators. Coal producing states, including West Virginia and Kentucky, passed similar legislation. The bituminous coal mining industry was actively engaged throughout 2007 in activities to achieve compliance with these new requirements. These compliance efforts will continue into 2008.
On February 8, 2008, MSHA published a final rule that revises existing standards for mine rescue teams for underground coal mines. This final rule implements Section 4 of the MINER Act to improve overall mine rescue capability, mine emergency response time and mine rescue team effectiveness. It also calls for increased quantity and quality of mine rescue team training. Additional substantive legislation is also possible in 2008 with the passage by the United States House of Representatives in January 2008 of the Supplementary Mine Improvement and New Emergency Response Act, (“S-MINER Act”). The House legislation augments portions of the MINER Act and proposes changes to retreat mining practices, study of substance abuse issues and the use of coal dust monitors to reduce miner respirable dust exposure.
All of the states in which we operate have state programs for mine safety and health regulation and enforcement. Collectively, federal and state safety and health regulation in the coal mining industry is perhaps the most comprehensive and pervasive system for protection of employee health and safety affecting any segment of industry in the United States. While regulation has a significant effect on our operating costs, our United States competitors are subject to the same degree of regulation.
Our goal is sustainable excellence in our safety and health performance. We are committed to doing our best, and then learning to do even better. We recognize each employee’s contributions to our collective safety and health efforts and reward outstanding performance. We measure our success in this area primarily through the use of occupational injury and illness frequency rates. We believe that a superior safety and health regime is inherently tied to achieving productivity and financial goals, with overarching benefits for our shareholders, the community and the environment.
Black Lung. Under federal black lung benefits legislation, each coal mine operator is required to make payments of black lung benefits or contributions to: (i) current and former coal miners totally disabled from black lung disease; and (ii) certain survivors of a miner who dies from black lung disease. The Black Lung Disability Trust Fund, to which we must make certain tax payments based on tonnage sold, provides for the payment of medical expenses to claimants whose last mine employment was before January 1, 1970 and to claimants employed after such date, where 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. In addition to federal acts, we are also liable under various state statutes for black lung claims. Federal benefits are offset by any state benefits paid.
Workers’ Compensation. We are liable for workers’ compensation benefits for traumatic injuries under state workers’ compensation laws in which we have operations. Workers’ compensation laws are administered by state agencies with each state having its own set of rules and regulations regarding compensation owed to an employee injured in the course of employment.
Coal Industry Retiree Health Benefit Act of 1992 and Tax Relief and Retiree Health Care Act of 2006. The Coal Industry Retiree Health Benefit Act of 1992 (“Coal Act”) provides for the funding of health benefits for certain UMWA retirees. The Coal Act established the Combined Benefit Fund (“CBF”) into which “signatory operators” and “related persons” are obligated to pay annual premiums for covered beneficiaries. The Coal Act also created a second benefit fund, the 1992 Benefit Plan, for miners who retired between July 21, 1992 and September 30, 1994 and whose former employers are no longer in business. On December 20, 2006, President Bush signed the Tax Relief and Retiree Health Care Act of 2006. This legislation includes important changes to the Coal Act that impacts all companies required to contribute to the CBF. Effective October 1, 2007, the SSA revoked all beneficiary assignments made to companies that did not sign a 1988 UMWA contract (“reachback companies”), but phased-in their premium relief. As a pre-1988 signatory, Massey related reachback companies will receive the applicable premium relief. Effective October 1, 2007, reachback companies will pay only 55% of their plan year 2008 assessed premiums, 40% of their plan year 2009 assessed premiums, and 15% of their plan year 2010 assessed premiums. General United States Treasury money will be transferred to the CBF to make up the difference. After
Pension Protection Act. The Pension Protection Act of 2006 (“Pension Act”) will simplify and transform rules governing the funding of defined benefit plans, accelerate funding obligations of employers, make permanent certain provisions of the Economic Growth and Tax Relief Reconciliation Act of 2001, make permanent the diversification rights and investment education provisions for plan participants and encourage automatic enrollment in defined contribution 401(k) plans. In general, most provisions of the Pension Act will take effect for plan years beginning on or after December 31, 2007. Plans generally will be required to set a funding target of 100% of the present value of accrued benefits and sponsors will be required to amortize unfunded liabilities over a 7-year period. The Pension Act includes a funding target phase-in provision consisting of a 92% funding target in 2008, 94% in 2009, 96% in 2010, and 100% thereafter. Plans with a funded ratio of less than 80%, or less than 70% using special assumptions, will be deemed to be “at risk” and will be subject to additional funding requirements. Our qualified pension plans are currently fully funded.
Surface Mining Control and Reclamation Act. The Surface Mining Control and Reclamation Act, (“SMCRA”), which is administered by the Office of Surface Mining Reclamation and Enforcement (“OSM”), establishes mining, environmental protection and reclamation standards for all aspects of surface mining as well as many aspects of deep mining. The SMCRA and similar state statutes require, among other things, the restoration of mined property in accordance with specified standards and an approved reclamation plan. In addition, the Abandoned Mine Land Fund, which is part of the SMCRA, imposes a fee on all current mining operations, the proceeds of which are used to restore mines closed before 1977. The maximum tax is $0.315 per ton on surface-mined coal and $0.135 per ton on deep-mined coal. A mine operator must submit a bond or otherwise secure the performance of its reclamation obligations. Mine operators must receive permits and permit renewals for surface mining operations from the OSM or, where state regulatory agencies have adopted federally approved state programs under the act, the appropriate state regulatory authority. We accrue for reclamation and mine-closing liabilities in accordance with Statement of Financial Accounting Standard (“SFAS”) No. 143, “Accounting for Asset Retirement Obligations” (“SFAS 143”) (see Note 9 to the Notes to Consolidated Financial Statements).
Clean Water Act. Section 301 of the Clean Water Act prohibits the discharge of a pollutant from a point source into navigable waters of the United States except in accordance with a permit issued under either Section 402 or Section 404 of the Clean Water Act. Navigable waters are broadly defined to include streams, even those that are not navigable in fact, and may include wetlands. All mining operations in Appalachia generate excess material, which must be placed in fills in adjacent valleys and hollows. Likewise, coal refuse disposal areas and coal processing slurry impoundments are located in valleys and hollows. Almost all of these areas contain intermittent or perennial streams, which are considered navigable waters under the Clean Water Act. An operator must secure a Clean Water Act permit before filling such streams. For approximately the past twenty-five years, operators have secured Section 404 fill permits that authorize the filling of navigable waters with material from various forms of coal mining. Operators have also obtained permits under Section 404 for the construction of slurry impoundments although the use of these impoundments, including discharges from them, requires permits under Section 402. Section 402 discharge permits are generally not suitable for authorizing the construction of fills in navigable waters.
Clean Air Act. Coal contains impurities, including sulfur, mercury, chlorine, nitrogen oxide and other elements or compounds, many of which are released into the air when coal is burned. The Clean Air Act and corresponding state laws extensively regulate emissions into the air of particulate matter and other substances, including sulfur dioxide, nitrogen oxide and mercury. Although these regulations apply directly to impose certain requirements for the permitting and operation of our mining facilities, by far their greatest impact on us and the coal industry generally is the effect of emission limitations on utilities and other customers. Owners of coal-fired power plants and industrial boilers have been required to expend considerable resources in an effort to comply with these air pollution standards. The United States Environmental Protection Agency (“EPA”) has imposed or attempted to impose tighter emission restrictions in a number of areas, some of which are currently subject to litigation. The general effect of such tighter restrictions could be to reduce demand for coal. This in turn may result in decreased production and a corresponding decrease in revenue and profits.
National Ambient Air Quality Standards. In 1997, EPA adopted a new National Ambient Air Quality Standard (“NAAQS”) for very fine particulate matter and a more stringent NAAQS for ozone. Ozone is produced by a combination of two precursor pollutants: volatile organic compounds and nitrogen oxide, a by-product of coal combustion. States were required to submit to EPA revisions to their State Implementation Plans (“SIPs”) that demonstrate the manner in which the states will attain the fine particulate NAAQS by December 18, 2007. The ozone NAAQS has been the subject of litigation and, during the course of this litigation, EPA has proposed revisions to the ozone NAAQS that are more stringent than the standards being litigated. EPA intends to begin the promulgation process for the new, more stringent ozone NAAQS in the Spring of 2008. Revised SIPs could require electric power generators to further reduce nitrogen oxide and sulfur dioxide emissions. In addition to the SIP process, the Clean Air Act permits states to assert claims against sources in other “upwind” states alleging that emission sources including coal fired power plants in the upwind states are preventing the “downwind”
states from attaining a NAAQS. All these actions could result in additional controls being required on coal fired power plants and we are unable to predict the effect on coal production.
Acid Rain Control Provisions. The acid rain control provisions promulgated as part of the Clean Air Act Amendments of 1990 in Title IV of the Clean Air Act (“Acid Rain program”) required reductions of sulfur dioxide emissions from power plants. The Acid Rain program is now a mature program and we believe that any market impacts of the required controls have likely been factored into the price of coal in the national coal market.
Regional Haze Program. EPA promulgated a regional haze program designed to protect and to improve visibility at and around so-called Class I Areas, which are generally National Parks, National Wilderness Areas and International Parks. This program may restrict the construction of new coal-fired power plants whose operation may impair visibility at and around the Class I Areas. Moreover, the program requires certain existing coal-fired power plants to install additional control measures designed to limit haze-causing emissions, such as sulfur dioxide, nitrogen oxide and particulate matter. States were required to submit Regional Haze SIPs to EPA by December 17, 2007. Many states did not meet the December 17, 2007, deadline and we are unable to predict the impact on the coal market of the failure to submit Regional Haze SIPs by the deadline.
New Source Review Program. Under the Clean Air Act, new and modified sources of air pollution must meet certain new source standards (“New Source Review Program”). In the late 1990s, the EPA filed lawsuits against many coal-fired plants in the eastern United States alleging that the owners performed non-routine maintenance, causing increased emissions that should have triggered the application of these new source standards. Some of these lawsuits have been settled, with the owners agreeing to install additional pollution control devices in their coal-fired plants. The remaining litigation and the uncertainty around the New Source Review Program rules could adversely impact utilities’ demand for coal in general or coal with certain specifications, including the coal produced by us.
Multi-Pollutant Strategies. In March 2005, EPA issued two closely related rules designed to significantly reduce levels of sulfur dioxide, nitrogen oxide and mercury: the Clean Air Interstate Rule and the Clean Air Mercury Rule. The Clean Air Interstate Rule sets a cap-and-trade program in 28 states and the District of Columbia to establish emissions limits for sulfur dioxide and nitrogen oxide, by allowing utilities to buy and sell credits to assist in achieving compliance with the NAAQS for 8-hour ozone and fine particulates. The Clean Air Mercury Rule as promulgated will cut mercury emissions nearly 70% by 2018 through a cap-and-trade program. Both rules were challenged in numerous lawsuits. Portions of each of these rules are still in litigation, and o