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Alpha Natural Resources 10-K 2010 Documents found in this filing:Table of Contents
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-K
(Mark One)
For the fiscal year ended December 31, 2009
OR
For the transition period from to
Commission File No. 001-32331
ALPHA NATURAL RESOURCES, INC.
(Exact name of registrant as specified in its charter)
Registrant’s telephone number, including area code:
(276) 619-4410 Securities registered pursuant to Section 12(b) of the Act:
Securities registered pursuant to Section 12(g) of the Act:
None Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule
405 of the Securities Act. Yes þ No o
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 o No þ
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 þ No o
Indicate by check mark whether the registrant has submitted electronically and posted on its
corporate Web site, if any, every Interactive Data File required to be submitted and posted
pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months
(or for such shorter period that the registrant was required to submit and post such files). Yes
þ No o
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation
S-K 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. þ
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” and “smaller reporting company” in Rule 12b-2 of the
Exchange Act.
Indicate by check mark whether the registrant is a shell company (as defined in Exchange Act
Rule 12b-2). Yes o No þ
The aggregate market value of the Common Stock held by non-affiliates of the registrant on
June 30, 2009, was approximately $1.3 billion based on the closing price of Old Alpha’s common
stock as reported that date on the New York Stock Exchange of $26.27 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, $0.01 par value, outstanding as of February 23, 2010
— 120,798.160 shares.
DOCUMENTS INCORPORATED BY REFERENCE
Part III incorporates certain information by reference from the registrant’s definitive proxy
statement for the 2010 annual meeting of stockholders (the “Proxy Statement”), which will be filed
no later than 120 days after the close of the registrant’s fiscal year ended December 31, 2009.
2009 ANNUAL REPORT ON FORM 10-K
TABLE OF CONTENTS
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CAUTIONARY NOTE REGARDING FORWARD LOOKING STATEMENTS
This report includes statements of our expectations, intentions, plans and beliefs that
constitute “forward-looking statements” within the meaning of Section 27A of the Securities Act of
1933 and Section 21E of the Securities Exchange Act of 1934 and are intended to come within the
safe harbor protection provided by those sections. These statements, which involve risks and
uncertainties, relate to analyses and other information that are based on forecasts of future
results and estimates of amounts not yet determinable and may also relate to our future prospects,
developments and business strategies. We have used the words “anticipate,” “believe,” “could,”
“estimate,” “expect,” “intend,” “may,” “plan,” “predict,” “project,” “should” and similar terms and
phrases, including references to assumptions, in this report to identify forward-looking
statements. These forward-looking statements are made based on expectations and beliefs concerning
future events affecting us and are subject to uncertainties and factors relating to our operations
and business environment, all of which are difficult to predict and many of which are beyond our
control, that could cause our actual results to differ materially from those matters expressed in
or implied by these forward-looking statements.
The following factors are among those that may cause actual results to differ materially from
our forward-looking statements:
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When considering these forward-looking statements, you should keep in mind the cautionary
statements in this report and the documents incorporated by reference. We do not undertake any
responsibility to release publicly any revisions to these forward-looking statements to take into
account events or circumstances that occur after the date of this report. Additionally, we do not
undertake any responsibility to update you on the occurrence of any unanticipated events, which may
cause actual results to differ from those expressed or implied by the forward-looking statements
contained in this report.
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PART I
Overview
On July 31, 2009, Alpha Natural Resources, Inc. (“Old Alpha”) and Foundation Coal Holdings,
Inc. (“Foundation”) merged (the “Merger”) with Foundation continuing as the surviving legal
corporation of the Merger which was renamed Alpha Natural Resources, Inc. (“Alpha”). Prior to the
Merger, Old Alpha, together with its affiliates, was a leading supplier of high-quality Appalachian
coal to the steel industry, electric utilities and other industries, with mining operations in
Virginia, West Virginia, Kentucky and Pennsylvania. Old Alpha was also the nation’s largest
supplier and exporter of metallurgical coal, a key ingredient in steel manufacturing. Prior to the
Merger, Foundation, together with its affiliates, was a major U.S. coal producer operating mines
and associated processing and loading facilities in Pennsylvania, West Virginia and Wyoming.
Foundation primarily supplied steam coal to U.S. utilities for use in generating electricity and
also sold steam coal to industrial plants and metallurgical coal to steel companies in the U.S.
Unless we have indicated otherwise, or the context otherwise requires, references in this
report to “Alpha,” “we,” “us” and “our” or similar terms are to Alpha and its consolidated
subsidiaries in reference to dates subsequent to the Merger and to Old Alpha and its consolidated
subsidiaries in reference to dates prior to the Merger.
We have provided a glossary of selected terms beginning on page 27, which defines certain
technical terms used in this Annual Report on Form 10-K.
We are one of America’s premier coal suppliers, ranked third largest among publicly-traded
U.S. coal producers as measured by combined Old Alpha and Foundation 2009 and 2008 pro forma
revenues of $3.4 billion and $4.0 billion, respectively (see Note 20 to the Consolidated Financial
Statements included elsewhere in this Annual Report on Form 10-K). We are the nation’s leading
supplier and exporter of metallurgical coal for use in the steel-making process and a major
supplier of thermal coal to electric utilities and manufacturing industries across the country. We
operate 61 mines and 14 coal preparation plants in Northern and Central Appalachia and the Powder
River Basin, with approximately 6,400 employees.
For financial accounting purposes, the Merger was treated as a “reverse acquisition” and Old
Alpha was treated as the accounting acquirer. Accordingly, Old Alpha’s financial statements became
the financial statements of Alpha and Alpha’s periodic filings subsequent to the Merger reflect Old
Alpha’s historical financial condition and results of operations shown for comparative purposes.
Old Alpha’s financial position as of December 31, 2008 and its results of operations for the years
ended December 31, 2008 and 2007 do not include financial results for Foundation. For the year
ended December 31, 2009, Foundation’s financial results are included for the five month post-Merger
period from August 1, 2009 through December 31, 2009.
Prior to the Merger, Old Alpha had one reportable segment, Coal Operations. As a result of the
Merger, we changed our organizational structure and now have two reportable segments: Eastern Coal
Operations and Western Coal Operations. Eastern Coal Operations consists of the mines in Central
and Northern Appalachia, our coal brokerage activities and our road construction business. Western
Coal Operations consists of two Powder River Basin mines in Wyoming. Our All Other category
includes an idled underground mine in Illinois; expenses associated with closed mines; Dry Systems
Technologies; Coal Gas Recovery; equipment sales and repair operations; terminal services; the
leasing of mineral rights and general corporate overhead. All prior period segment information has
been reclassified to conform to the current year presentation.
Steam coal, which is primarily purchased by large utilities and industrial customers as fuel
for electricity generation, accounted for approximately 83% of our 2009 coal sales volume.
Metallurgical coal, which is used primarily to make coke, a key component in the steel making
process, accounted for approximately 17% of our 2009 coal sales volume. Metallurgical coal
generally sells at a premium over steam coal because of its higher quality and its value in the
steelmaking process as the raw material for coke. We believe that the volume of the coal we sell
will grow when and if demand for power and steel increases.
During 2009, we sold a total of 47.2 million tons of steam and metallurgical coal and
generated coal revenues of $2.2 billion, EBITDA from continuing operations of $494.8 million and
income from continuing operations of $66.8 million. We define and reconcile EBITDA from continuing
operations and explain its importance in Item 6 under “Selected Financial Data.” Our coal sales
during 2009 consisted of 45.7 million tons of produced and processed coal, including 0.4 million
tons purchased from third parties and processed at our processing plants or loading facilities
prior to resale, and 1.5 million tons of purchased coal which we resold without processing.
Approximately 82% of the purchased coal in 2009 was blended with coal produced from our mines prior
to resale. Approximately 32% of our coal revenues combined with freight and handling revenues in
2009 was derived from sales made outside the United States, primarily in Brazil, Italy, Belgium,
Canada, and Spain.
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As of December 31, 2009, we owned or leased approximately 2.3 billion tons of proven and
probable coal reserves. Of our total proven and probable reserves, approximately 64% are low sulfur
reserves, with approximately 54% having sulfur content below 1%. Approximately
62% of our total proven and probable reserves have a high Btu content which creates more
energy per unit when burned compared to coals with lower Btu content. We believe that our total
proven and probable reserves will support current production levels for more than 20 years.
History
Old Alpha was formed under the laws of the State of Delaware on November 29, 2004. On
February 15, 2005, an initial public offering of Old Alpha’s common stock occurred and since then,
we have grown substantially through a series of acquisitions including the Foundation merger
discussed in more detail above. During 2005, Old Alpha acquired the Nicewonder Coal Group’s coal
reserves and operations in southern West Virginia and southwestern Virginia (“Nicewonder
Acquisition”), for an aggregate purchase price of $328.2 million. The operations that were
acquired in this acquisition now constitute our Callaway operations included in our Southern West
Virginia business unit. In 2005, the assets of our Colorado mining subsidiary, National King Coal
LLC, and related trucking subsidiary, Gallup Transportation and Transloading Company, LLC were
sold. During 2006, Old Alpha acquired certain coal mining operations in eastern Kentucky from
Progress Fuels Corp, a subsidiary of Progress Energy, for $28.8 million. These operations are
adjacent to our Enterprise operations and were integrated with Enterprise. During 2007, Old Alpha
paid $43.9 million for the acquisition of certain coal mining assets in western West Virginia known
as Mingo Logan from Arch Coal, Inc. The Mingo Logan purchase consisted of coal reserves, one
active deep mine and a load-out and processing plant, which is managed by our Callaway operations.
During 2008:
Competitive Strengths
We believe that the following competitive strengths enhance our prominent position in the
United States:
We are the third largest publicly traded coal producer in the United States based on 2009 and
2008 combined pro forma revenues and have significant coal reserves. Based on 2009 and 2008
combined pro forma revenues of $3.4 billion and $4.0 billion, we are the third largest publicly
traded coal producer in the United States. As of December 31, 2009, we controlled approximately 2.3
billion tons of proven and probable coal reserves. See Note 20 in the Consolidated Financial
Statements located elsewhere in this Annual Report on Form 10-K for pro forma revenues.
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We have a diverse portfolio of coal mining operations and reserves. We operate a total of 61
mines and have reserves in the three major U.S. coal producing regions: the Powder River Basin,
Northern Appalachia and Central Appalachia. Our mines are located in Wyoming, Pennsylvania, West
Virginia, Virginia, Illinois and Kentucky. We sell coal to domestic and foreign electric utilities,
steel producers and industrial users. We are the only producer with significant operations and
major reserve blocks in both the Powder River Basin and Northern Appalachia, two U.S. coal
production regions for which future demand is expected to increase. We believe that this geographic
diversity provides us with a significant competitive advantage, allowing us to source coal from
multiple regions to meet the needs of our customers and reduce their transportation costs.
We are a recognized industry leader in safety and environmental performance. Our focus on
safety and environmental performance results in a lower likelihood of disruption of production at
our mines, which leads to higher productivity and improved financial performance. We operate some
of the nation’s safest mines, with 2009 total injury incident rates, as tracked by the Mine Safety
and Health Administration (“MSHA”), below industry averages.
Our ability to blend coals from our operations allows us to increase our coal revenues and
gross margins while meeting our customer requirements. The strategic locations of our mines and
preparation plants provide us the ability to blend coals from our operations and increase coal
revenue and gross margins while meeting our customer requirements.
We have long-standing relationships and long-term contracts with many of the largest
coal-burning utilities in the United States. We supply coal to numerous power plants operated by a
diverse group of electricity generators across the country. We believe we have a reputation for
reliability and superior customer service that has enabled us to solidify our customer
relationships.
We are the largest producer of metallurgical coal in the United States and have access to
international customers. We are the largest producer of metallurgical coal in the United States and
have the ability to serve international customers. We have the capacity to ship approximately 14
million tons annually through our 41% ownership interest in DTA and through our access to other
international shipping points.
Our management team has a track record of success. Our management team has a proven record of
generating free cash flow, reducing costs, developing and maintaining long-standing customer
relationships and effectively positioning us for future growth and profitability.
Business Strategy
Our objective is to increase shareholder value through sustained earnings and cash flow
growth. Our key strategies to achieve this objective are described below:
Maintaining our commitment to operational excellence. We seek to maintain our operational
excellence with an emphasis on investing selectively in new equipment and advanced technologies. We
will continue to focus on profitability and efficiency by leveraging our significant economies of
scale, large fleet of mining equipment, information technology systems and coordinated purchasing
and land management functions. In addition, we continue to focus on productivity through our
culture of workforce involvement by leveraging our strong base of experienced, well-trained
employees.
Capitalizing on industry dynamics through a balanced approach to selling our coal. Despite the
volatility in coal prices over the past two years, we believe the long term fundamentals of the
U.S. coal industry are favorable. We plan to continue employing a balanced approach to selling our
coal, including the use of long-term sales commitments for a portion of our future production while
maintaining uncommitted planned production to capitalize on favorable future pricing environments.
Selectively expanding our production and reserves. Given our broad scope of operations and
expertise in mining in major coal-producing regions in the United States, we believe that we are
well-situated to capitalize on the expected continued growth in U.S. and international coal
consumption by evaluating growth opportunities, including expansion of production capacity at our
existing mining operations, further development of existing significant reserve blocks in Northern
and Central Appalachia, and potential strategic acquisition opportunities that arise in the United
States or internationally. We will prudently act to expand our reserves when appropriate.
Continuing to provide a mix of coal types and qualities to satisfy our customers’ needs. By
having operations and reserves in three major coal producing regions, we are able to source and
blend coal from multiple mines to meet the needs of our domestic and international customers. Our
broad geographic scope and mix of coal qualities provide us with the opportunity to work with many
leading electricity generators, steel companies and other industrial customers across the country.
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Continuing to focus on excellence in safety and environmental stewardship. We intend to
maintain our recognized leadership in operating some of the safest mines in the United States and
in achieving environmental excellence. Our ability to minimize workplace incidents and
environmental violations improves our operating efficiency, which directly improves our cost
structure and financial performance.
Coal Mining Techniques
We use four different mining techniques to extract coal from the ground: longwall mining,
room-and-pillar mining, truck-and-shovel mining and truck and front-end loader mining.
Longwall Mining
We utilize longwall mining techniques at our Pennsylvania Services business unit. Longwall
mining is the most productive and safest underground mining method used in the United States. A
rotating drum is trammed mechanically across the face of coal, and a hydraulic system supports the
roof of the mine while the drum advances through the coal. Chain conveyors then move the loosened
coal to a standard
underground mine conveyor system for delivery to the surface. Continuous miners are used to
develop access to long rectangular blocks of coal which are then mined with longwall equipment,
allowing controlled subsidence behind the advancing machinery. Longwall mining is highly productive
and most effective for large blocks of medium to thick coal seams. High capital costs associated
with longwall mining demand large, contiguous reserves. Ultimate seam recovery of in-place reserves
using longwall mining is much higher than the room-and-pillar mining underground technique. All of
the raw coal mined at our longwall mines is washed in preparation plants to remove rock and
impurities.
Room-and-Pillar Mining
Our AMFIRE, Southern West Virginia, Northern West Virginia, and Virginia/Kentucky business
units utilize room-and-pillar mining methods. In this type of mining, main airways and
transportation entries are developed and maintained while remote-controlled continuous miners
extract coal from so-called rooms by removing coal from the seam, leaving pillars to support the
roof. Shuttle cars and battery coal haulers are used to transport coal to the conveyor belt for
transport to the surface. This method is more flexible than longwall mining and often used to mine
smaller coal blocks or thin seams. Ultimate seam recovery of in-place reserves is typically less
than that achieved with longwall mining. All of this production is also washed in preparation
plants before it becomes saleable clean coal.
Truck-and-Shovel Mining and Truck and Front-End Loader Mining
We utilize truck-and-shovel mining methods in both of our mines in the Powder River Basin. We
utilize the truck and front-end loader method at the surface mines in our AMFIRE, Southern West
Virginia, Northern West Virginia, and Virginia/Kentucky business units. These methods are similar
and involve using large, electric or hydraulic-powered shovels or diesel-powered front-end loaders
to remove earth and rock (overburden) covering a coal seam which is later used to refill the
excavated coal pits after the coal is removed. The loading equipment places the coal into haul
trucks for transportation to a preparation plant or loadout area. Ultimate seam recovery of
in-place reserves on average exceeds 90%. This surface-mined coal rarely needs to be cleaned in a
preparation plant before sale. Productivity depends on overburden and coal thickness (strip ratio),
equipment utilized and geologic factors.
Coal Characteristics
In general, coal of all geological compositions is characterized by end use as either steam
coal or metallurgical coal. Heat value, sulfur and ash content, and volatility, in the case of
metallurgical coal, are the most important variables in the profitable marketing and transportation
of coal. These characteristics determine the best end use of a particular type of coal. We mine,
process, market and transport sub-bituminous and bituminous coal, characteristics of which are
described below.
Heat Value. The heat value of coal is commonly measured in British thermal units, or “Btus.” A
Btu is the amount of heat needed to raise the temperature of one pound of water by one degree
Fahrenheit. Alpha mines both sub-bituminous and bituminous coal. Bituminous coal is located
primarily in Appalachia, Arizona, the Midwest, Colorado, Wyoming and Utah and is the type most
commonly used for electric power generation in the United States. Sub-bituminous coal is used for
industrial steam purposes, while bituminous coal, depending on its quality, can be used for both
metallurgical and industrial steam purposes. Of our estimated 2.3 billion billion tons of proven
and probable reserves, approximately 62% have a heat value above 12,500 Btus per pound.
Sulfur Content. Sulfur content can vary from seam to seam and sometimes within each seam. When
coal is burned, it produces sulfur dioxide, the amount of which varies depending on the chemical
composition and the concentration of sulfur in the coal. Low sulfur coals have a sulfur content of
1.5% or less. Approximately 64% of our proven and probable reserves are low sulfur coal.
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High sulfur coal can be burned in plants equipped with sulfur-reduction technology, such as
scrubbers, which can reduce sulfur dioxide emissions by 50% to 90%. Plants without scrubbers can
burn high sulfur coal by blending it with lower sulfur coal or by purchasing emission allowances on
the open market, allowing the user to emit a predetermined amount of sulfur dioxide. Some older
coal-fired plants have been retrofitted with scrubbers, although most have shifted to lower sulfur
coals as their principal strategy for complying with Phase II of the Clean Air Act’s Acid Rain
regulations. We expect that any new coal-fired generation plant built in the United States will use
clean coal-burning technology.
Ash & Moisture Content. Ash is the inorganic residue remaining after the combustion of coal.
As with sulfur content, ash content varies from seam to seam. Ash content is an important
characteristic of coal because electric generating plants must handle and dispose of ash following
combustion. The absence of ash is also important to the process by which metallurgical coal is
transformed into coke for use in steel production. Moisture content of coal varies by the type of
coal, the region where it is mined and the location of coal within a seam. In general, high
moisture content decreases the heat value and increases the weight of the coal, thereby making it
more expensive to transport. Moisture content in coal, as sold, can range from approximately 5% to
30% of the coal’s weight.
Coking Characteristics. The coking characteristics of metallurgical coal are typically
measured by the coal’s fluidity, ARNU and volatility. Fluidity and ARNU tests measure the expansion
and contraction of coal when it is heated under laboratory conditions to determine the strength of
coke that could be produced from a given coal. Typically, higher numbers on these tests indicate
higher coke strength. Volatility refers to the loss in mass, less moisture, when coal is heated in
the absence of air. The volatility of metallurgical coal determines the percentage of feed coal
that actually becomes coke, known as coke yield. Coal with a lower volatility produces a
higher coke yield and is more highly valued than coal with a higher volatility, all other
metallurgical characteristics being equal.
Business Environment
Coal is an abundant, efficient and affordable natural resource used primarily to provide fuel
for the generation of electric power. World-wide economically recoverable coal reserves using
today’s technology are estimated to be approximately 910 billion tons. The United States is one of
the world’s largest producers of coal and has approximately 29% of global coal reserves,
representing nearly 250 years of supply based on current usage rates. According to the U.S.
Department of Energy, the energy content of the United States coal reserves exceeds that of all the
known oil supplies in the world.
Coal Markets. Coal is primarily consumed by utilities to generate electricity. It is also used
by steel companies to make steel products and by a variety of industrial users to heat and power
foundries, cement plants, paper mills, chemical plants and other manufacturing and processing
facilities. In general, coal is characterized by end use as either steam coal or metallurgical
coal. Steam coal is used by electricity generators and by industrial facilities to produce steam,
electricity or both. Metallurgical coal is refined into coke, which is used in the production of
steel. Over the past forty years, total annual coal consumption in the United States (excluding
exports) has nearly doubled to approximately one billion tons in 2009. The growth in the demand for
coal has coincided with an increased demand for coal from electric power generators.
Much of the nation’s power generation infrastructure is coal-fired. As a result, coal has
consistently maintained a 46% to 53% market share during the past 10 years, principally because of
its relatively low cost, reliability and domestic abundance. Coal is the lowest cost fossil fuel
used for base-load electric power generation, typically being considerably less expensive than
natural gas or oil. Coal-fired generation is also competitive with nuclear power generation
especially on a total cost per megawatt-hour basis. The production of electricity from existing
hydroelectric facilities is inexpensive, but its application is limited both by geography and
susceptibility to seasonal and climatic conditions. Through 2009, non-hydropower renewable power
generation accounted for only 2.8% of all the electricity generated in the United States, and wind
and solar power represented only 1.8% of United States power generation.
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Coal consumption patterns are also influenced by the demand for electricity, governmental
regulation impacting power generation, technological developments, transportation costs, and the
location, availability and cost of other fuels such as natural gas, nuclear and hydroelectric
power.
Coal’s primary advantages are its relatively low cost and availability compared to other fuels
used to generate electricity.
According to the Electric Power Research Institute (EPRI) Energy Technology Assessment
Center, the levelized cost of electricity for various power generation technologies, including
overnight capital costs, owner’s costs (e.g., interest during construction), fuel costs, and
variable and fixed operations and maintenance (O&M) costs, are as follows:
Coal Production. United States coal production was approximately 1.1 billion tons in 2009. The
following table, derived from data prepared by the EIA, sets forth production statistics in each of
the major coal producing regions for the periods indicated.
Coal Regions. Coal is mined from coal fields throughout the United States, with the major
production centers located in the Western United States, Northern and Central Appalachia and the
Illinois Basin. The quality of coal varies by region. Physical and chemical characteristics of coal
are very important in measuring quality and determining the best end use of particular coal types.
Competition. The coal industry is intensely competitive. With respect to our U.S. customers,
we compete with numerous coal producers in the Appalachian region and with a large number of
western coal producers. Competition from coal with lower production costs shipped east from western
coal mines has resulted in increased competition for coal sales in the Appalachian region. In 2009,
imports accounted for a relatively small percentage of total U.S coal consumption. As of October
2009, 2% of total U.S. coal consumption in 2009 was imported. Excess industry capacity, which has
occurred in the past, tends to result in reduced prices for our coal. The most important factors on
which we compete are delivered coal price, coal quality and characteristics, transportation costs
from the mine to the customer and the reliability of supply. Demand for coal and the prices that we
will be able to obtain for our coal are closely linked to coal consumption patterns of the domestic
electric generation industry, which has accounted for greater than 93% of 2009 domestic coal
consumption. These coal consumption patterns are influenced by factors beyond our control,
including the demand for electricity, which is significantly dependent upon summer and winter
temperatures and commercial and industrial outputs in the United States, environmental and other
government regulations, technological developments and the location, availability, quality and
price of competing fuels for power such as natural gas, nuclear, fuel oil and alternative energy
sources such as hydroelectric power. Demand for our low sulfur coal and the prices that we will be
able to obtain for it will also be affected by the price and availability of high sulfur coal,
which can be marketed in tandem with emissions allowances in order to meet Clean Air Act
requirements.
Demand for our metallurgical coal and the prices that we will be able to obtain for
metallurgical coal will depend to a large extent on the demand for U.S. and international steel,
which is influenced by factors beyond our control, including overall economic activity and the
availability and relative cost of substitute materials. In the export metallurgical market, during
2009 and 2008, we largely competed with producers from Australia, Canada, and other international
producers of metallurgical coal.
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Mining Operations
We currently have six regional business units, operating in Virginia, West Virginia,
Pennsylvania, Kentucky and Wyoming. As of December 31, 2009, these business units include 14
preparation plants, each of which receive, blend, process and ship coal that is produced from one
or more of our 61 active mines (some of which are operated by third parties under contracts with
us), using four mining methods: longwall mining, room-and-pillar mining, truck-and-shovel mining
and truck and front-end loader mining. Our underground mines generally consist of one or more
single or dual continuous miner sections which are made up of the continuous miner, shuttle cars or
continuous haulage, roof bolters, and various ancillary equipment. We have two large underground
mines that employ a longwall mining system. Our Eastern surface mines are a combination of contour
highwall miner, auger operations using truck/loader-excavator equipment fleets along with large
production tractors and a small percentage using mountain top removal. Our Western surface mines
are large open-pit operations that use the truck-and-shovel mining method. Most of our preparation
plants are modern heavy media plants that generally have both coarse and fine coal cleaning
circuits. We employ preventive maintenance and rebuild programs to ensure that our equipment is
modern and well-maintained. During 2009, most of our preparation plants also processed coal that we
purchased from third party producers before reselling it to our customers. Within each regional
business unit, mines have been developed at strategic locations in close proximity to our
preparation plants and rail shipping facilities. Coal is transported from our regional business
units to customers by means of railroads, trucks, barge lines, and ocean-going vessels from
terminal facilities.
The following table provides location and summary information regarding our six regional
business units and the preparation plants and active mines associated with these business units as
of December 31, 2009:
Regional Business Units
BNSF = BNSF Railway
CSX = CSX Transportation RJCC = R.J. Corman Railroad Company NS = Norfolk Southern Railway Company UP = Union Pacific Railroad Company
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The coal production and processing capacity of our mines and processing plants is influenced
by a number of factors including reserve availability, labor availability, environmental permit
timing, and preparation plant capacity.
Pennsylvania Services
Our Pennsylvania Services business unit consists of our Cumberland and Emerald mining
complexes, which collectively shipped 5.4 million tons in 2009. Coal is mined primarily by using
longwall mining systems supported by continuous miners. We control approximately 779.2 million tons
of contiguous reserves through our Pennsylvania Services business unit. Approximately 178.8 million
tons are assigned to active mines and 600.4 million tons are unassigned. Both mines operate in the
Pittsburgh No. 8 Seam, the dominant coal-producing seam in the region, which is six to eight feet
thick in the mines. The mines sell high Btu, high sulfur coal primarily to eastern utilities. There
are 1,485 salaried and hourly employees at our Pennsylvania Services business unit.
The hourly work force at each mine is represented by the United Mine Workers of America (“UMWA”).
Cumberland shipped 2.9 million tons of coal in 2009. All of the coal at Cumberland is
processed through a preparation plant before being loaded onto Cumberland’s owned and operated
railroad for transportation to the Monongahela River dock site. At the dock site, coal is then
loaded into barges for transportation to river-served utilities or to other docks for
subsequent rail shipment to non-river-served utilities. The mine can also ship a portion of its
production via truck.
Emerald shipped 2.5 million tons of coal in 2009. Emerald has the ability to store clean coal
and blend variable sulfur products to meet customer requirements. All of Emerald’s coal is
processed through a preparation plant before being loaded into unit trains operated by the Norfolk
Southern Railway or CSX Transportation. The mine also has the option to ship a portion of its coal
by truck.
AMFIRE
Our AMFIRE business unit consists of five underground mines operated by AMFIRE employees and
ten surface mines, six of which are operated by independent contractors. Coal is mined primarily
using continuous miners employing the room and pillar mining method at the underground mines and
the truck and front end loader method at our surface mines. We control approximately 82.0 million
tons of coal reserves through our AMFIRE business unit. Approximately 59.6 million tons are
assigned to active mines and approximately 22.4 million tons are unassigned. AMFIRE employs
430 salaried and hourly employees. The mines sell high Btu, low, medium, and high
sulfur coal to eastern utilities and steel companies. All of the underground mining operations at
AMFIRE are staffed and operated by AMFIRE employees. The underground coal is delivered directly by
truck to the customer, or transported to the Clymer or Portage coal preparation plants or raw coal
loading docks where it is cleaned, blended and loaded onto a rail belt or truck for shipment to
customers. The surface mined coal is delivered directly by truck to the customer or transported to
the Clymer or Portage coal preparation plants or raw coal loading docks where it is blended and
loaded onto a rail belt or truck for shipment to customers. During 2009, AMFIRE shipped 2.6 million
tons, which included less than 0.1 million tons of coal purchased from third parties that was
blended with AMFIRE’s coal and shipped to our customers.
Southern West Virginia
Our Southern West Virginia business unit consists of our Brooks Run South and Callaway
operations, which collectively shipped 5.1 million tons in 2009. Coal is mined primarily using
continuous miners employing the room and pillar mining method at our underground mines and the
truck and front end loader method at our surface mines. We control approximately 99.3 million tons
of coal reserves through our Southern West Virginia business unit. Approximately 46.9 million tons
are assigned to active mines and approximately 52.4 million tons are unassigned. There are
760 salaried and hourly employees at our Southern West Virginia business unit.
Brooks Run South produces coal from nine underground mines, four of which are underground
mines operated by our employees, and five that are operated by independent contractors. The mines
sell high Btu, low sulfur coal to eastern utilities and metallurgical coal to steel companies. The
coal is transported by truck or rail to the Litwar and Kepler preparation plants operated by Brooks
Run South or the Moss #3 plant operated by Dickenson-Russell, where it is cleaned, blended and
loaded onto rail for shipment to customers. During 2009, Brooks Run South shipped 2.1 million
tons, which included approximately 0.3 million tons of coal purchased from third parties that was
blended with other coals and shipped to our customers.
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Callaway produces coal from three surface mining operations operated by our Callaway employees
and one underground mine operated by our subsidiary Cobra Natural Resources, LLC (“Cobra”) using
continuous miners and the room and pillar mining method. The mines sell high Btu, low sulfur coal
to eastern utilities and metallurgical coal to steel companies. Callaway also recovers coal from
the road construction business operated by our subsidiary Nicewonder Contracting, Inc. (“NCI”).
Coal from the three surface mines and NCI is transported by truck to the Black Bear preparation
plant or the Ben Creek or Mate Creek loadouts operated by Cobra or the Virginia Energy loadout
operated by Callaway where the coal is cleaned, blended, and loaded onto rail for shipment to
customers. Coal from the underground mine is belted to the Black Bear preparation plant where it is
cleaned and then loaded into railcars at the Ben Creek loadout for shipment to our customers.
During 2009, Callaway shipped 3.0 million tons, which included less than 0.1 million tons of coal
purchased from third parties.
Northern West Virginia
Our Northern West Virginia business unit consists of our Brooks Run North, Kingston,
Rockspring, and Pioneer operations, which collectively shipped 4.1 million tons in 2009. Coal is
mined primarily using continuous miners employing the room and pillar mining method at our
underground mines and the truck and front end loader method at our surface mines. We control
approximately 254.7 million tons of coal reserves through our Northern West Virginia business unit.
Approximately 75.0 million tons are assigned to active mines and approximately 179.7 million tons
are unassigned. There are 940 salaried and hourly employees at our Northern West
Virginia business unit.
Brooks Run North produces coal from two underground mines and one surface mine operated by our
Brooks Run North employees. The mines sell high Btu, medium sulfur coal primarily to eastern
utilities. The coal is transported by truck to the Erbacon preparation plant operated by Brooks Run
North where it is cleaned, blended and loaded onto rail for shipment to customers. During 2009,
Brooks Run North shipped 2.2 million tons.
Kingston produces coal from two underground mines operated by Kingston employees. Kingston
sells primarily metallurgical coal. The coal is trucked to the Kanawha River for shipment by barge
or to CSX Transportation or the Norfolk Southern Railway load-outs for shipment by rail. During
2009, Kingston shipped 0.4 million tons.
Rockspring operates a large multiple section mining complex called Camp Creek that produces
coal from one underground mine operated by our Rockspring employees. The mine sells mid Btu, low
and medium sulfur coal primarily to southeastern utilities. Rockspring has a mine site rail loadout
served by Norfolk Southern Railway. The mine can also ship a portion of its production by truck.
Rockspring shipped 1.1 million tons of coal in 2009.
Pioneer produces coal from two surface mines: Paynter Branch and Pax. These mines sell high
Btu, low and medium sulfur steam coal primarily to eastern utilities and metallurgical coal to
steel companies. The Pioneer mines shipped 0.4 million tons of steam and metallurgical coal in
2009. Coal from Paynter Branch is shipped by truck to our on-site rail loading facility on the
Norfolk Southern Railway and then on to domestic utilities and exported to metallurgical coal
customers. Coal from Pax is shipped to customers primarily via rail, with coal being trucked from
the mine to our on-site train loading facility served by CSX Transportation and R.J. Corman
Railroad. Pax coal may also be trucked to the Kanawha River for shipment by barge.
Virginia/Kentucky
Our Virginia/Kentucky business unit consists of our Paramont, Dickenson-Russell and Enterprise
operations, which collectively shipped 7.7 million tons in 2009. Coal is mined primarily using
continuous miners employing the room and pillar mining method at our underground mines and the
truck and front end loader method at our surface mines. We control approximately 363.0 million tons
of coal reserves through our Virginia/Kentucky business unit. Approximately 198.5 million tons are
assigned to active mines and approximately 164.5 million tons
are unassigned. There are 1,430 salaried and hourly employees at our Virginia/Kentucky business unit.
Paramont produces coal from seven underground mines, three of which are operated by
independent contractors. Paramont also operates five surface mines, two of which are operated by
independent contractors. These mines sell high Btu, low sulfur coal primarily to eastern utilities
and metallurgical coal to steel companies. The coal produced by the underground mines is
transported by truck to the Toms Creek preparation plant operated by Paramont, or the McClure River
or Moss #3 preparation plants operated by Dickenson-Russell. At the preparation plant, the coal is
cleaned, blended and loaded onto rail for shipment to customers. The coal produced by the surface
mines is transported to one of our preparation plants or raw coal loading docks where it is blended
and loaded onto rail for shipment to customers. During 2009, Paramont shipped 4.2 million tons,
which included less than 0.1 million tons of coal purchased from third parties that was blended
with Paramont’s coal and shipped to our customers.
Dickenson-Russell produces coal from four underground mines. These mines sell high Btu, low
sulfur coal primarily to eastern utilities and metallurgical coal to steel companies. The coal is
transported by truck to the McClure River or Moss #3 preparation plants operated by
Dickenson-Russell or the Toms Creek preparation plant operated by Paramont where it is cleaned,
blended and loaded on rail or truck for shipment to customers. During 2009, Dickenson-Russell
shipped 1.4 million tons, which included less than 0.1 million tons of coal purchased from third
parties that was blended with Dickenson-Russell’s coal and shipped to our customers.
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Enterprise produces coal from three underground mines, one of which is operated by an
independent contractor. Enterprise also has two surface mines, one of which is operated by an
independent contractor. These mines sell high Btu, low, medium, and high sulfur coal primarily to
eastern utilities and metallurgical coal to steel companies. The coal produced by the underground
mines is transported by truck to the Roxana coal preparation plant operated by Enterprise where it
is cleaned, blended and loaded onto rail for shipment to customers. The coal produced by the
surface mine is transported to the Roxana preparation plant and Pioneer loadout facility where it
is blended and loaded onto rail for shipment to customers. During 2009, Enterprise shipped 2.1
million tons, which included less than 0.1 million tons of coal purchased from third parties that
was blended with Enterprise’s coal and shipped to our customers.
Alpha Coal West
Our Alpha Coal West business unit is located in the Powder River Basin. Alpha Coal West
consists of our Belle Ayr and Eagle Butte operations, which collectively shipped 20.8 million tons
in 2009. Coal is mined primarily using the truck and shovel mining method. We control approximately
709.3 million tons of coal reserves through our Alpha Coal West business unit and all of the coal
reserves are assigned to active mines. There are 630 salaried and hourly employees at
our Alpha Coal West business unit.
Belle Ayr consists of one mine that produces sub-bituminous, low sulfur coal for sale
primarily to utility companies. Belle Ayr extracts coal from a coal seam that is 75 feet thick. The
mine sells 100% of raw coal mined and no washing is necessary. Belle Ayr shipped 12.4 million tons
of coal in 2009. We plan to apply to lease several hundred million tons of surface mineable,
unleased federal coal that adjoins Belle Ayr’s property under the LBA process. If we prevail in the
bidding process and obtain these leases, we will be able to extend the life of the mine. Belle Ayr
has the advantage of shipping its coal on both of the major western railroads, the BNSF Railway and
the Union Pacific Railroad to power plants located throughout the West, Midwest and the South.
Eagle Butte consists of one mine that produces sub-bituminous, low sulfur coal for sale
primarily to utility companies. Eagle Butte extracts coal from coal seams that total 100 feet
thick. The mine sells 100% of raw coal mined and no washing is necessary. Eagle Butte shipped 8.4
million tons of coal in 2009. Coal from Eagle Butte is shipped on the BNSF Railway to power plants
located throughout the West, Midwest and the South. The mine also ships a small portion by truck.
Other Operations
We have other operations and activities in addition to our coal production, processing and
sales business, including:
Road Construction Business. NCI operates a road construction business under a contract with
the State of West Virginia Department of Transportation. Pursuant to the contract, NCI is building
approximately 11 miles of rough grade road in West Virginia over the next one to two years and, in
exchange, NCI will be compensated by West Virginia based on the number of cubic yards of material
excavated and/or filled to create a road bed, as well as for certain other cost components. As the
road is constructed any coal recovered is sold by NCI as part of its coal operations. The Company
also has other minor road construction projects in conjunction with other surface mining
operations.
Maxxim Rebuild and Dry System Technology. Our subsidiary Maxxim Rebuild Co., LLC, is a mining
equipment company with facilities in Kentucky and Virginia. This business largely consists of
repairing and reselling equipment and parts used in surface mining and in supporting preparation
plant operations. Our subsidiary Dry Systems Technologies manufactures patented particulate
scrubbers and filters for underground diesel engine applications and rebuilds underground mining
equipment for external customers and our subsidiaries.
Coal Gas Recovery. Our Coal Gas Recovery business provides degassing services in advance of
mining in Pennsylvania. Coal bed methane is directed through pipelines and sold to third parties.
Dominion Terminal Associates. Through our subsidiary Alpha Terminal Company, LLC, we hold a
41% interest in DTA, a 20 million-ton annual capacity coal export terminal located in Newport News,
Virginia. The terminal, constructed in 1984, provides the advantages of unloading/transloading
equipment with ground storage capability, providing producers with the ability to custom blend
export products without disrupting mining operations. During 2009, we shipped a total of 1.6
million tons of coal to our customers through the terminal. We make periodic cash payments in
respect of the terminal for operating expenses, which are offset by payments we receive for
transportation incentive payments and for renting our unused storage space in the terminal to third
parties. In 2009, we received cash payments related to the terminal of $17.0 million, partially
offset by payments we made for expenses of $6.2 million. The terminal is held in a partnership with
subsidiaries of two other companies, Arch Coal and Peabody Energy.
Coal Brokerage. Our coal brokerage group purchases and sells third party coal and serves as an
agent of our coal subsidiaries.
Miscellaneous. We engage in the sale of certain non-strategic assets such as timber, gas and
oil rights as well as the leasing and sale of non-strategic surface properties and reserves. We
also provide coal and environmental analysis services.
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Marketing, Sales and Customer Contracts
Our marketing and sales force, which is principally based in Abingdon, Virginia, included 60
employees as of December 31, 2009, and consists of sales managers, distribution/traffic managers,
contract administrators and administrative personnel. In addition to marketing coal produced in our
six regional business units, we are also actively involved in the purchase and resale of coal mined
by others, the majority of which we blend with coal produced from our mines. We have coal supply
commitments with a wide range of electric utilities, steel manufacturers, industrial customers and
energy traders and brokers. Our marketing efforts are centered on customer needs and requirements.
By offering coal of both steam and metallurgical grades to provide specific qualities of heat
content, sulfur and ash, and other characteristics relevant to our customers, we are able to serve
a diverse customer base. This diversity allows us to adjust to changing market conditions and
provides us with the ability to sustain high sales volumes and sales prices for our coal. Many of
our larger customers are well-established public utilities and steel manufacturers who have been
customers of ours and our acquired companies for decades.
We sold a total of 47.2 million tons of coal in 2009, consisting of 45.7 million tons of
produced and processed coal and 1.5 million tons of purchased coal that we resold without
processing. A portion of purchased coal was blended prior to resale, meaning the coal was mixed
with coal produced from our mines prior to resale, which generally allows us to realize a higher
overall margin for the blended product than we would be able to achieve selling these coals
separately. Approximately 0.4 million tons of our 2009 purchased coal sales were processed by us,
meaning we washed, crushed or blended the coal at one of our preparation plants or loading
facilities prior to resale.
Old Alpha sold a total of 26.9 million tons of coal in 2008, consisting of 22.0 million tons
of produced and processed coal and 4.9 million tons of purchased coal that was resold without
processing. Of the total purchased coal sales of 6.2 million tons in 2008, approximately 4.0
million tons were blended prior to resale. Approximately 1.3 million tons of 2008 purchased coal
sales were processed by us.
Old Alpha sold a total of 26.9 million tons of coal in 2007, consisting of 22.8 million tons
of produced and processed coal and 4.1 million tons of purchased coal that was resold without
processing. Of the total purchased coal sales of 5.6 million tons in 2007, approximately 3.5
million tons were blended prior to resale. Approximately 1.5 million tons of 2007 purchased coal
sales were processed by us.
The breakdown of tons sold for 2009, 2008 and 2007 is set forth in the table below:
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We sold coal to over 150 different customers in 2009. Our top ten customers in 2009 accounted
for approximately 47% of 2009 total revenues and our largest customer during 2009 accounted for
approximately 12% of 2009 total revenues. The following table provides information regarding
exports (including to Canada) in 2009, 2008 and 2007 by revenues and tons sold:
Export shipments during 2009, 2008 and 2007 serviced customers in 19, 20 and 14 countries,
respectively, across North America, Europe, South America, Asia and Africa. Brazil was the largest
export market in 2009 and 2008, with sales to Brazil accounting for approximately 23% and 15%,
respectively, of total export revenues and 7% and 8%, respectively, of total revenues. Canada was
the largest export market in 2007, with sales to Canada accounting for approximately 16% of export
revenues and 6% of total revenues. All of our sales are made in U.S. dollars, which reduces foreign
currency risk. A portion of our coal sales volume is subject to seasonal fluctuation, with sales to
certain customers being curtailed during the winter months due to the freezing of lakes that we use
to transport coal to those affected customers.
As is customary in the coal industry, when market conditions are appropriate and particularly
in the steam coal market, we enter into long-term contracts (exceeding one year 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. A significant majority
of our steam coal sales are shipped under long-term contracts. During 2009, approximately 71% and
55% of our steam and metallurgical coal sales volume, respectively, was delivered pursuant to
long-term contracts and during 2008, approximately 80% and 64% of the steam and metallurgical coal
sales volume, respectively, was delivered pursuant to long-term contracts.
Our sales backlog, including backlog subject to price reopener and/or extension provisions,
was approximately 208.9 million tons as of February 8, 2010 and approximately 34.7 million tons at
the beginning of 2009. Of these tons, approximately 38% and 56% were expected to be filled within
one year.
The terms of our contracts result from bidding and negotiations with customers. Consequently,
the terms of these contracts typically vary significantly in many respects, including price
adjustment features, provisions permitting renegotiation or modification of coal sale prices, coal
quality requirements, quantity parameters, flexibility and adjustment mechanisms, permitted sources
of supply, treatment of environmental constraints, options to extend and force majeure, suspension,
termination and assignment provisions, and provisions regarding the allocation between the parties
of the cost of complying with future governmental regulations.
Distribution
We employ transportation specialists who negotiate freight and terminal agreements with
various providers, including railroads, trucks, barge lines, and terminal facilities.
Transportation specialists also coordinate with customers, mining facilities and transportation
providers to establish shipping schedules that meet the customer’s needs. Our produced and
processed coal is loaded from our 14 preparation plants, loadout facilities, and in certain cases
directly from our mines. The coal we purchase is loaded in some cases directly from mines and
preparation plants operated by third parties or from an export terminal. Virtually all of our coal
is transported from the mine to our preparation plants by truck or rail, and then from the
preparation plant to the customer by means of railroads, trucks, barge lines, lake-going vessels
and ocean-going vessels from terminal facilities. Rail shipments constituted approximately 75% of
total shipments of coal volume produced and processed coal from our mines to the preparation plant
to the customer in 2009. The balance was shipped from our preparation plants, loadout facilities or
mines via truck. In 2009, approximately 6% of our coal sales volume were delivered to our customers
through transport on the Great Lakes, approximately 8% was moved through the Norfolk Southern
export facility at Norfolk, Virginia, approximately 3% was moved through the coal export terminal
at Newport News, Virginia operated by Dominion Terminal Associates, and less than 1% was moved
through the export terminals at Baltimore, MD and New Orleans, LA. We own a 41% interest in the
coal export terminal at Newport News, VA operated by Dominion Terminal Associates. See “Other
Operations.”
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Transportation
Coal consumed domestically is usually sold at the mine and transportation costs are normally
borne by the purchaser. Export coal is usually sold at the loading port, with purchasers
responsible for further transportation. Producers usually pay shipping costs from the mine to the
port.
We depend upon rail, barge, trucking and other systems to deliver coal to markets. In 2009,
our produced coal was transported from the mines and to the customer primarily by rail, with the
main rail carriers being CSX Transportation, Norfolk Southern Railway Company, BNSF Railway and
Union Pacific Railroad Company. The majority of our sales volume is shipped by rail, but a portion
of our production is shipped by barge and truck.
We have positive relationships with rail carriers and barge companies due, in part, to our
modern coal-loading facilities and the experience of our transportation and logistics employees.
Suppliers
We incur a substantial amount of expenses per year to procure goods and services in support of
our business activities, excluding capital expenditures. Principal goods and services include
maintenance and repair parts and services, electricity, fuel, roof control and support items,
explosives, tires, conveyance structure, ventilation supplies and lubricants. We use suppliers for
a significant portion of our equipment rebuilds and repairs both on- and off-site, as well as
construction and reclamation activities and to support computer systems.
Each of our regional mining operations has developed its own supplier base consistent with
local needs. We have a centralized sourcing group for major supplier contract negotiation and
administration, for the negotiation and purchase of major capital goods, and to support the
business units. The supplier base has been relatively stable for many years, but there has been
some consolidation. We are not dependent on any one supplier in any region. We promote competition
between suppliers and seek to develop relationships with suppliers that focus on lowering our
costs. We seek suppliers who identify and concentrate on implementing continuous improvement
opportunities within their area of expertise.
Employees
As of December 31, 2009, we had approximately 6,400 employees. As of December 31, 2009, the
UMWA represented approximately 21% of our employees located in Virginia, West Virginia and
Pennsylvania. UMWA represented employees produced approximately 13% of our coal sales volume during
the fiscal year ended December 31, 2009. Relations with organized labor are important to our
success, and we believe our relations with our employees are satisfactory.
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ENVIRONMENTAL AND OTHER REGULATORY MATTERS
Federal, state and local authorities regulate the United States coal mining and oil and gas
industries with respect to matters such as: employee health and safety; permitting and licensing
requirements; emissions to air and discharges to water; plant and wildlife protection; the
reclamation and restoration of properties after mining or other activity has been completed; the
storage, treatment and disposal of wastes; remediation of contaminated soil; protection of surface
and groundwater; surface subsidence from underground mining; the effects on surface and groundwater
quality and availability; noise; dust and competing uses of adjacent, overlying or underlying lands
such as for oil and gas activity, pipelines, roads and public facilities. These ordinances,
regulations and legislation (and judicial or agency interpretations thereof) have had, and will
continue to have, a significant effect on our production costs and our competitive position. New
laws and regulations, as well as future interpretations or different enforcement of existing laws
and regulations, may require substantial increases in equipment and operating costs to us and
delays, interruptions, or a termination of operations, the extent of which we cannot predict. We
intend to respond to these regulatory requirements and interpretations thereof at the appropriate
time by implementing necessary modifications to facilities or operating procedures. When
appropriate, we may also challenge actions in regulatory or court proceedings. Future legislation,
regulations, interpretations or enforcement may also cause coal to become a less attractive fuel
source due to factors such as investments necessary to use coal or caps, allocations or taxes
imposed upon its use, such as those that may result from climate change legislation. As a result,
future legislation, regulations, interpretations or enforcement may adversely affect our mining or
other operations, cost structure or the ability of our customers to use coal.
We endeavor to conduct our mining and other operations in compliance with all applicable
federal, state, and local laws and regulations. However, violations occur from time to time. None
of the violations identified or the monetary penalties assessed upon us have been material. It is
possible that future liability under or compliance with environmental and safety requirements could
have a material effect on our operations or competitive position. Under some circumstances,
substantial fines and penalties, including revocation or suspension of mining or other permits or
plans, may be imposed under the laws described below. Monetary sanctions and, in severe
circumstances, criminal sanctions may be imposed for failure to comply with these laws.
Mine Safety and Health
The Coal Mine Health and Safety Act of 1969 and the Federal Mine Safety and Health Act of 1977
impose stringent safety and health standards on all aspects of mining operations. Also, 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
one of the most comprehensive and pervasive systems for protection of employee health and safety
affecting any segment of U.S. industry. Regulation has a significant effect on our operating costs.
In recent years, legislative and regulatory bodies at the state and federal levels, including
MSHA, have promulgated or proposed various statutes, regulations and policies relating to mine
safety and mine emergency issues. In the case of MSHA, the MINER Act passed in 2006 mandated mine
rescue regulations, new and improved technologies and safety practices in the area of tracking and
communication, and emergency response plans and equipment. Although some new laws, regulations and
policies are in place, these legislative and regulatory efforts are still ongoing. At this time, it
is not possible to predict the full effect that the new or proposed statutes, regulations and
policies will have on our operating costs, but it will increase our costs and those of our
competitors. Some, but not all, of these additional costs may be passed on to customers.
Black Lung
Under the Black Lung Benefits Revenue Act of 1977 and the Black Lung Benefits Reform Act of
1977, as amended in 1981, each coal mine operator must secure payment of federal black lung
benefits to claimants who are current and former employees and to a trust fund for the payment of
benefits and medical expenses to eligible claimants. The trust fund is funded by an excise tax on
production of up to $1.10 per ton for deep-mined coal and up to $0.55 per ton for surface-mined
coal, neither amount to exceed 4.4% of the gross sales price.
In December 2000, the Department of Labor amended regulations implementing the federal black
lung laws to, among other things, establish a presumption in favor of a claimant’s treating
physician and limit a coal operator’s ability to introduce medical evidence regarding the
claimant’s medical condition. The number of claimants who are awarded benefits has since increased,
and will continue to increase, as will the amounts of those awards.
As of December 31, 2009, all of our various payment obligations for federal black lung
benefits to claimants entitled to such benefits are either fully secured by insurance coverage or
paid from a tax exempt trust established for that purpose. Based on actuarial reports and required
funding levels, from time to time we may have to supplement the trust corpus to cover the
anticipated liabilities going forward.
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Coal Industry Retiree Health Benefit Act of 1992
The Coal Industry Retiree Health Benefit Act of 1992 (the “Coal Act”) provides for the funding
of health benefits for certain UMWA retirees and their spouses or dependants. The Coal Act
established the Combined Benefit Fund into which employers who are “signatory operators” are
obligated to pay annual premiums for beneficiaries. The Combined Benefit Fund covers a fixed group
of individuals who
retired before July 1, 1976, and the average age of the retirees in this fund is over 80 years
of age. Premiums paid in 2009 for our obligations to the Combined Benefit Fund were approximately
$0.4 million. The Coal Act also created a second benefit fund, the 1992 UMWA Benefit Plan (“the
1992 Plan”), for miners who retired between July 1, 1976 and September 30, 1994, and whose former
employers are no longer in business to provide them retiree medical benefits. Companies with 1992
Plan liabilities also pay premiums into this plan. Premiums paid in 2009 for our obligation to the
1992 Plan were less than $0.1 million. These per beneficiary premiums for both the Combined Benefit
Fund and the 1992 Plan are adjusted annually based on various criteria such as the number of
beneficiaries and the anticipated health benefit costs.
On December 20, 2006, the Tax Relief and Health Care Act of 2006 (“TRHC”) became law. The TRHC
seeks to reduce or eliminate the premium obligation of companies due to the expanded transfers from
the Abandoned Mine Land Fund (“AML”). The additional transfer of funds from AML will incrementally
eliminate by 2010, to the extent the new transfers are adequate, the unassigned beneficiary premium
under the Combined Benefit Fund effective October 1, 2007. The additional transfers will also
reduce incrementally the pre-funding and assigned beneficiary premium to cover the cost of
beneficiaries for which no individual company is responsible (“orphans”) under the 1992 Plan
beginning January 1, 2008. For the first time, the 1993 Benefit Plan (“the 1993 Plan”) (all of the
beneficiaries of which are orphans) will begin receiving a subsidy from a new federal transfer that
will ultimately cover the entire cost of the eligible population as of December 31, 2006. Under the
Combined Benefit Fund, the 1992 Plan and the 1993 Plan, if the federal transfers are inadequate to
cover the cost of the “orphan” component, the current or former signatories of the UMWA wage
agreement will remain liable for any shortfall.
Environmental Laws
We and our customers are subject to various federal, state and local environmental laws. Some
of the more material of these laws and issues, discussed below, place stringent requirements on our
coal mining and other operations, and on the ability of our customers to use coal. Federal, state
and local regulations require regular monitoring of our mines and other facilities to ensure
compliance with these many laws and regulations.
Mining Permits and Necessary Approvals
Numerous governmental permits, licenses or approvals are required for mining, oil and gas
operations, and related operations. When we apply for these permits and approvals, we may be
required to present data to federal, state or local authorities pertaining to the effect or impact
our operations may have upon the environment. The requirements imposed by any of these authorities
may be costly and time consuming and may delay commencement or continuation of mining or other
operations. These requirements may also be supplemented, modified or re-interpreted from time to
time. Regulations also 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 mining permit
violations. Thus, past or ongoing violations of federal and state mining laws could provide a basis
to revoke existing permits and to deny the issuance of additional permits.
In order to obtain mining permits and approvals from state regulatory authorities, we must
submit a reclamation plan for restoring, upon the completion of mining operations, the mined
property to its prior or better condition, productive use or other permitted condition. Typically,
we submit our necessary permit applications several months, or even years, before we plan to begin
mining a new area. In the past, we have generally obtained our mining permits in time so as to be
able to run our operations as planned. However, we may experience difficulty or delays in obtaining
mining permits or other necessary approvals in the future, or even face denials of permits
altogether. In particular, issuance of Army Corps of Engineers (the “COE”) permits in Central
Appalachia allowing placement of material in valleys have been slowed in recent years due to
ongoing proceedings over the requirements for obtaining such permits. These delays could spread to
other geographic regions.
Mountaintop removal mining is a legal but controversial method of surface mining. Certain
anti-mining special interest groups have recently waged a public relations assault upon this mining
method and have encouraged the introduction of legislation at the state and federal level to
restrict or ban it and to preclude purchasing coal mined by this method. Should changes in laws,
regulations or availability of permits severely restrict or ban this mining method in the future,
our production and associated profitability could be adversely impacted.
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Surface Mining Control and Reclamation Act
The Surface Mining Control and Reclamation Act of 1977 (the “SMCRA”), which is administered by
the Office of Surface Mining Reclamation and Enforcement within the Department of the Interior (the
“OSM”), establishes mining, environmental protection and reclamation standards for all aspects of
surface mining, as well as many aspects of deep mining that impact the surface. Where state
regulatory agencies have adopted federal mining programs under SMCRA, the state becomes the
regulatory authority with primacy and issues the permits, but OSM maintains oversight. SMCRA
stipulates compliance with many other major environmental statutes, including the federal Clean Air
Act, Clean Water Act, Resource Conservation and Recovery Act (“RCRA”) and Comprehensive
Environmental Response, Compensation and Liability Act (“CERCLA” or “Superfund”). SMCRA permit
provisions include requirements for, among other actions, coal prospecting; mine plan development;
topsoil removal, storage and replacement; selective handling of overburden materials; mine pit
backfilling and grading; protection of the hydrologic balance; mitigation plans; subsidence control
for underground mines; surface drainage control; mine drainage and mine discharge control and
treatment; and re-vegetation. The permit application process is initiated by collecting
baseline data to adequately characterize the pre-mine environmental condition of the permit
area. This work includes surveys of cultural and historical resources, soils, vegetation, wildlife,
assessment of surface and ground water hydrology, climatology, and wetlands. In conducting this
work, we collect geologic data to define and model the soil and rock structures and coal that we
will mine. We develop mining and reclamation plans by utilizing this geologic data and
incorporating elements of the environmental data. The mining and reclamation plan incorporates the
provisions of SMCRA, the state programs, and the complementary environmental programs that affect
coal mining. Also included in the permit application are documents defining ownership and
agreements pertaining to coal, minerals, oil and gas, water rights, rights of way and surface land.
Some SMCRA mine permits take over a year to prepare, depending on the size and complexity of
the mine. Once a permit application is prepared and submitted to the regulatory agency, it goes
through a completeness review and technical review. Proposed permits also undergo a public notice
and comment period. Some SMCRA mine permits may take several years or even longer to be issued.
Regulatory authorities have considerable discretion in the timing of the permit issuance and the
public and other agencies have rights to comment on and otherwise engage in the permitting process,
including through intervention in the courts.
Before a SMCRA permit is issued, a mine operator must submit a bond or otherwise secure the
performance of reclamation obligations. The AML, which is part of SMCRA, requires a fee on all coal
produced. The proceeds are used to reclaim mine lands closed prior to 1977 when SMCRA came into
effect. The current fee is $0.315 per ton on surface-mined coal and $0.135 on deep-mined coal from
2008 to 2012, with reductions to $0.28 per ton on surface-mined coal and $0.12 per ton on
deep-mined coal from 2013 to 2021.
In December 2008, OSM issued revisions to its Stream Buffer Zone Rule under SMCRA. The
revisions allow disposal of excess spoil within 100 feet of streams if OSM makes findings of impact
minimization that overlap findings required by the COE in administration of the Clean Water Act
Section 404 permit program. Several environmental groups have filed legal challenges seeking to
invalidate the revisions, and legislation in Congress has been introduced in the past and may be
introduced in the future in an attempt to preclude placing any fill material in streams. An adverse
court decision or enactment of such legislation would negatively impact our future ability to
conduct certain types of mining activities.
Surety Bonds
Federal and state laws require us to obtain surety bonds to secure payment of certain
long-term obligations including mine closure or reclamation costs, federal and state workers’
compensation costs, obligations under federal coal leases and other miscellaneous obligations. Many
of these bonds are renewable on a yearly basis. We cannot predict the ability to obtain or the cost
of bonds in the future.
Climate Change Initiatives
One major by-product of burning coal and all other fossil fuels is carbon dioxide
(“CO2”), which is considered by the U.S. Environmental Protection Agency (the “EPA”) as
a greenhouse gas, and is perceived by environmental groups as a major source of concern with
respect to global warming. Methane, which must be expelled from our underground coal mines for
mining safety reasons, also is classified as a greenhouse gas. Although our gas operations capture
much of the coalbed methane, some is vented into the atmosphere when the coal is mined.
Considerable and increasing government attention in the United States and other countries is
being paid to reducing greenhouse gas emissions, including emissions from coal-fired power plants.
Although the United States has not ratified the Kyoto Protocol to the 1992 Framework Convention on
Global Climate Change, which became effective for many countries in 2005 and establishes a binding
set of emission targets for greenhouse gases, it is actively participating in various international
initiatives to reduce greenhouse gas emissions. Any international agreement to regulate emissions,
including any pact that emerges in the aftermath of the December 2009 UN Climate Change Conference
in Copenhagen to replace the Kyoto Protocol, could adversely affect the price and demand for coal.
In addition to possible future U.S. treaty obligations, regulation of greenhouse gases in the
United States could occur pursuant to federal legislation, regulatory changes under the Clean Air
Act, state initiatives, or otherwise. At the federal level, Congress is actively considering
legislation that would establish nationwide cap-and-trade programs to reduce greenhouse gas
emissions. In June 2009, the U.S. House of Representatives approved the American Clean Energy and
Security Act, also referred to as the Waxman-Markey bill, and similar legislation currently is
being considered by the U.S. Senate.
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The EPA also is implementing plans to regulate carbon dioxide emissions. In October 2009, the
EPA published its final Mandatory Greenhouse Gas Reporting Rule, which requires power plants and
other large sources of greenhouse gases to commence data collection in January 2010 and to file
their first annual reports disclosing greenhouse gas emissions in 2011. More generally, in April
2007, the U.S. Supreme Court ruled in Massachusetts v. Environmental Protection Agency that the
Clean Air Act gives the EPA the authority to regulate vehicle tailpipe emissions of greenhouse
gases and that the EPA had not yet articulated a reasonable basis for not issuing such regulation.
Accordingly, in July 2008 the EPA issued an Advance Notice of Proposed Rulemaking seeking comments
on the complex issues associated with the possible regulation of greenhouse gases under the Clean
Air Act from both mobile and stationary sources. The issues that the EPA raised in the advance
notice included: (i) advantages and disadvantages of regulating greenhouse gases under various
provisions of the Clean Air Act; (ii) how a decision to regulate greenhouse gases under one
provision of the Clean Air Act would lead to regulation under other
provisions; (iii) issues relevant to legislation to regulate greenhouse gases and the
potential overlap of the Clean Air Act and such future legislation; and (iv) scientific information
relevant to, and the issues raised by, an analysis as to whether greenhouse gas emissions from
automobiles may reasonably be anticipated to endanger public health or welfare. Subsequently, in
September 2009, the EPA proposed new thresholds for greenhouse gas emissions that define when Clean
Air Act permits would be required, encompassing large facilities including coal fired power plants,
and in December 2009, the EPA made a determination that greenhouse gases cause or contribute to air
pollution and may reasonably be anticipated to endanger public health or welfare, which findings
are prerequisites to EPA regulation of greenhouse gases under the Clean Air Act. The EPA currently
plans to take further regulatory action during 2010.
In addition, there are several new state programs to limit greenhouse gas emissions and others
have been proposed. State and regional climate change initiatives are taking effect before federal
action. Ten Northeastern states (Connecticut, Delaware, Maine, Maryland, Massachusetts, New
Hampshire, New Jersey, New York, Rhode Island, and Vermont) have entered into the Regional
Greenhouse Gas Initiative (“RGGI”) Agreement, calling for a ten percent reduction of carbon dioxide
emissions by 2018. RGGI has commenced auctioning of carbon dioxide allowances for its first control
period of 2009 to 2011. Many other greenhouse gas initiatives, including the Western Regional
Climate Action Initiative and recently enacted legislation in California and other states, are in
various stages of development.
Considerable uncertainty is associated with these climate change initiatives. The content of
new treaties or legislation is not yet determined and many of the new regulatory initiatives remain
subject to review by the agencies or the courts. In addition to the timing for implementing any new
legislation, open issues include matters such as the applicable baseline of emissions to be
permitted, initial allocations of any emission allowances, required emissions reductions,
availability of offsets to emissions such as planting trees or capturing methane emitted during
mining, the extent to which additional states will adopt the programs, and whether they will be
linked with programs in other states or countries.
Predicting the economic effects of climate change legislation is difficult given the various
alternatives proposed and the complexities of the interactions between economic and environmental
issues. Coal-fired generators could switch to other fuels that generate less of these emissions,
possibly reducing the construction of coal-fired power plants or causing some users of our coal to
switch to a lower CO2 generating fuel, or more generally reducing the demand for coal-fired
electricity generation. This could result in an indeterminate decrease in demand for coal
nationally, and various mechanisms proposed to limit greenhouse gas emissions could impact the
price of coal and the cost of coal-fired generation. The majority of our coal supply agreements
contain provisions that allow a purchaser to terminate its contract if legislation is passed that
either restricts the use or type of coal permissible at the purchaser’s plant or results in
specified increases in the cost of coal or its use to comply with applicable ambient air quality
standards. In addition, if regulation of greenhouse gas emissions does not exempt the release of
coalbed methane, we may have to curtail coal production, pay higher taxes, or incur costs to
purchase credits that permit us to continue operations as they now exist at our underground coal
mines.
Other Clean Air Act Regulations
The federal Clean Air Act and corresponding state laws that regulate the emissions of
materials into the air affect coal mining operations both directly and indirectly. Direct impacts
on coal mining and processing operations arise primarily from permitting requirements and/or
emission control requirements relating to particulate matter, such as fugitive dust, including
regulation of fine particulate matter measuring 2.5 micrometers in diameter or smaller. Our
customers also are subject to extensive air emissions requirements, including those applicable to
the air emissions of sulfur dioxide, nitrogen oxides, particulates, mercury and other compounds
from coal-fueled electricity generating plants and industrial facilities that burn coal. These
requirements are complex, lengthy and becoming increasingly stringent as new regulations or
amendments to existing regulations are adopted. In addition, legal challenges to regulations may
impact their content and the timing of their implementation.
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More stringent air emissions regulations in future years may increase the cost of producing
and consuming coal and impact the demand for coal. Initially, we believe that such regulations will
result in an upward pressure on the price of lower sulfur eastern coals, and more demand for
western coals, as coal-fired power plants continue to comply with the more stringent restrictions
initially focused on sulfur dioxide emissions. As utilities continue to invest the capital to add
scrubbers and other devices to address emissions of nitrogen oxides, mercury and other hazardous
air pollutants, demand for lower sulfur coals may drop. However, we cannot predict these impacts
with certainty. Some of the more material Clean Air Act requirements that may directly or
indirectly affect our operations include the following:
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Clean Water Act
The Clean Water Act of 1972 (the “CWA”) and corresponding state laws affect coal mining
operations by imposing restrictions on the discharge of certain pollutants into water and on
dredging and filling wetlands. The CWA establishes in-stream water quality standards and treatment
standards for wastewater discharge through the National Pollutant Discharge Elimination System
(“NPDES”). Regular monitoring, as well as compliance with reporting requirements and performance
standards, are preconditions for the issuance and renewal of NPDES permits that govern the
discharge of pollutants into water. These requirements are complex, lengthy and becoming
increasingly stringent as new regulations or amendments to existing regulations are adopted. In
addition, legal challenges to regulations may impact their content and the timing of their
implementation.
Some of the more material CWA issues that may directly or indirectly affect our operations are
discussed below.
Section 404 Permitting
Permits under Section 404 of the CWA are required for coal companies to conduct dredging or
filling activities in jurisdictional waters for the purpose of creating slurry ponds, water
impoundments, refuse disposal areas, valley fills or other mining activities. Jurisdictional waters
typically include ephemeral, intermittent, and perennial streams and may in certain instances
include man-made conveyances that have a hydrologic connection to a stream or wetland. The COE only
has jurisdiction over the “navigable waters” of the United States, and outside these waters there
is arguably no need to procure a 404 permit. The United States Supreme Court ruled in Rapanos v.
United States in 2006 that upper reaches of streams which are intermittent or do not flow might not
be jurisdictional waters requiring 404 permits. The case did not involve disposal of mining refuse,
but has implications for the mining industry. Subsequently, in June 2007 the COE and EPA issued a
joint guidance document to attempt to develop a policy that will apply the jurisdictional standards
imposed by the Supreme Court. The guidance requires a case-by-case analysis of whether the area to
be filled has a sufficient nexus to downstream navigable waters so as to require 404 permits. How
the COE field offices will apply this new guidance, and to what extent decisions made pursuant to
it will be challenged, are still open questions.
The COE issuance of 404 permits is subject to the National Environmental Policy Act (“NEPA”).
NEPA defines the procedures by which a federal agency must run its permitting programs. The law
says that a federal agency must take a “hard look” at any activity that may “significantly affect
the quality of the human environment.” This “hard look” is accomplished through an Environmental
Impact Statement (“EIS”), a very lengthy data collection and review process. After the EIS is
complete, only then can the 404 permit application be considered. However, the law also allows an
initial Environmental Assessment (“EA”) to be completed to determine if a project will have a
significant impact on the environment. To date the COE has typically used the less detailed EA
process to determine the impacts from impoundments, fills and other activities associated with coal
mining. In general, the preliminary findings show that these types of mining related activities
will not have a significant effect on the environment, and as such a full EIS is not required.
Should a full EIS be required for every permit, significant permitting delays could affect mining
costs or cause operations not to be opened in the first instance, or to be idled or closed.
In March 2007, the U.S. District Court for the Southern District of West Virginia issued a
decision concerning 404 permitting for fills. The court held that widely used pre-mining
assessments of areas to be impacted required by the COE and conducted by the permit applicants are
inadequate and do not accurately assess the nature of the headwater areas being filled. As such,
the court found the COE erred in its finding of no significant impact from this activity. Based on
this conclusion, the court went on to find that proposed mitigation to offset the adverse impacts
of the area to be filled also are not supported by adequate data. Due to this decision, the COE is
assessing the protocol for evaluating the pre-mining stream conditions, as well as procedures used
in the measurement of the success of mitigation. That effort to revise the protocol and associated
findings is ongoing and may be challenged as it is applied to newly issued permits. Until this
process is completed, preparing and submitting new permit applications is somewhat hindered. The
March 2007 decision was appealed to the Fourth Circuit Court of Appeals. In June 2007, the same
federal district court also effectively prohibited mine operators from impounding streams below
their valley fills for the purpose of constructing sediment ponds. Mine operators are required to
route drainage from valley fills to sediment control structures and to meet NPDES permit limits for
discharges from those structures. In the steep sloped areas of Central Appalachia, often the only
practicable location for those structures is in the stream channel itself downstream of the valley
fills. The COE and EPA had both considered such ponds to be “treatment systems” excluded from the
definition of “waters of the United States” to which the Clean Water Act applies. The court’s June
2007 opinion, though, held that these ponds remain “waters of the United States” and that mine
operators must meet effluent limits for discharges into the ponds as well as from the ponds.
Meeting these limits at the point where water first leaves a valley fill or enters the stream or
pond would be difficult. This decision was also appealed to the Fourth Circuit Court of Appeals. In
February 2009, the Fourth Circuit Court of Appeals overturned these lower court decisions. The
plaintiffs have a pending petition before the United States Supreme Court seeking review of the
Fourth Circuit’s ruling. Legislation also may be introduced at the state or federal level in order
to override this decision by the Court of Appeals. An outcome that prevents the placement of mining
spoil or refuse into valleys could have a material adverse impact on the ability to maintain
current operations and to permit new operations.
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The COE is empowered to issue nationwide permits for specific categories of filling activity
that are determined to have minimal environmental adverse effects in order to save the cost and
time of issuing individual permits under Section 404. Nationwide Permit 21 (“NWP 21”) authorizes
the disposal of dredge-and-fill material from mining activities into the waters of the United
States. On October 23, 2003, several citizens groups sued the COE in the United States District
Court for the Southern District of West Virginia seeking to invalidate nationwide permits utilized
by the COE and the coal industry for permitting most in-stream disturbances associated with coal
mining, including excess spoil valley fills and refuse impoundments. The plaintiffs sought to
enjoin the prospective approval of these nationwide permits and to enjoin some coal operators from
additional use of existing nationwide permit approvals until they obtain more detailed individual
permits. On July 8, 2004, the court issued an order enjoining the further issuance of NWP 21
permits and rescinded certain listed permits where construction of valley fills and surface
impoundments had not commenced. On August 13, 2004, the court extended the ruling to all NWP 21
permits within the Southern District of West Virginia. The COE appealed the decision to the United
States Court of Appeals for the Fourth Circuit. In November 2005, the Fourth Circuit Court of
Appeals overturned the July 2004 decision, thereby allowing the continued use of the NWP 21
permitting process, but remanded remaining challenges to the NWP 21 permits to the district court.
Resolution of those additional challenges is still pending before that court. A similar challenge
to the NWP 21 and related permit processes was filed in Kentucky. In addition, in July 2009, the
COE published a proposal to suspend and modify the NWP 21 to eliminate its use within a six state
region,
including Kentucky, Ohio, Pennsylvania, Tennessee, Virginia and West Virginia. Public comments
were accepted however a final decision on this proposal has not yet been announced.
In September 2009, the EPA announced it had identified 79 pending permit applications for
Appalachian surface coal mining, under an enhanced coordination process with the “COE” and the
United States Department of the Interior entered into in June 2009, that the EPA believes warrant
further review because of its continuing concerns about water quality and/or regulatory compliance
issues. These included five of our permit applications, two of which were already withdrawn when
the EPA issued its list. While the EPA has stated that its identification of these 79 permit
applications does not constitute a determination that the mining involved cannot be permitted under
the CWA and does not constitute a final recommendation from the EPA to the COE on these projects,
it is uncertain how long the further review will take for our three subject permit applications or
what the final outcome will be.
National Pollutant Discharge Elimination (“NPDES”) Permits
The Clean Water Act (“CWA”) requires that all of our operations obtain NPDES permits for
discharges of water from all of our mining operations. All NPDES permits require regular monitoring
and reporting of one or more parameters on all discharges from permitted outfalls. Additional
parameters and increasingly more restrictive limits are being added to NPDES permits in all states
which potentially could create requirements for treatment systems and higher costs to comply with
permits conditions. When a water discharge occurs and one or more parameters are outside the
approved limits permitted in an NPDES permit, these exceedances of permit limits are voluntarily
reported to the pertinent agency. The agency may impose penalties for each such release in excess
of permitted amounts. If factors such as heavy rains or geologic conditions cause persistent
releases in excess of amounts allowed under NPDES permits, costs of compliance can be material,
fines may be imposed, or operations may have to be idled until remedial actions are possible.
Additionally, the CWA has citizen suit provisions which allow individuals or organized groups to
file suit against permit holders or the EPA or state agencies for failure to enforce all aspects of
the CWA. Although we are not aware of any citizen suit actions against any of our permits at this
time, similar actions have been filed in recent months against other companies.
Recently, there have been renewed efforts by the EPA to examine the coal industry’s record of
compliance with these limits. That enhanced scrutiny recently resulted in an agreement by one coal
operator to pay a $20 million penalty for over 4,000 alleged NPDES permit violations. Subsequently,
each of our operating subsidiaries conducted an assessment of their NPDES monitoring and reporting
practices, which identified some exceedances of permit limits. In 2009 and 2008, each of the
Company’s West Virginia subsidiaries entered into Consent Orders with the West Virginia Department
of Environmental Protection on this matter. Future exceedances of permit limits may be unavoidable
and future fines may be imposed.
The Clean Water Act has specialized sections that address NPDES permit conditions for
discharges to waters in which State-issued water quality standards are violated and where the
quality exceeds the levels established by those standards. For those waters where conditions
violate State water quality standards, states or the EPA are required to prepare a Total Maximum
Daily Load (“TMDL”) by which new discharge limits are imposed on existing and future discharges in
an effort to restore the water quality of the receiving streams. Likewise, when water quality in a
receiving stream is better than required, states are required to adopt an “anti-degradation policy”
by which further “degradation” of the existing water quality is reviewed and possibly limited. In
the case of both the TMDL and anti-degradation review, the limits in our NPDES discharge permits
could become more stringent, thereby potentially increasing our treatment costs and making it more
difficult to obtain new surface mining permits. New standards may also require us to install
expensive water treatment facilities or otherwise modify mining practices and thereby substantially
increase mining costs. These increased costs may render some operations unprofitable.
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Other Regulations on Steam Impacts
Federal and state laws and regulations can also impose measures to be taken to minimize and\or
avoid altogether stream impacts caused by both surface and underground mining. Temporary stream
impacts from mining are not uncommon, but when such impacts occur there are procedures we follow to
mitigate or remedy any such impacts. These procedures have generally been effective and we work
closely with applicable agencies to implement them. Our inability to mitigate or remedy any
temporary stream impacts in the future, and the application of existing or new laws and regulations
to disallow any stream impacts, could adversely affect our operating and financial results.
Endangered Species Act
The Federal Endangered Species Act and counterpart state legislation protect species
threatened with possible extinction. Protection of threatened and endangered species may have the
effect of prohibiting or delaying us from obtaining mining permits and may include restrictions on
timber harvesting, road building and other mining or agricultural activities in areas containing
the affected species or their habitats. A number of species indigenous to our properties are
protected under the Endangered Species Act. Based on the species that have been identified to date
and the current application of applicable laws and regulations, however, we do not believe there
are any species protected under the Endangered Species Act that would materially and adversely
affect our ability to mine coal from our properties in accordance with current mining plans.
Resource Conservation and Recovery Act
The Resource Conservation and Recovery Act (“RCRA”) affects coal mining operations by
establishing requirements for the treatment, storage, and disposal of hazardous wastes. Certain
coal mine wastes, such as overburden and coal cleaning wastes, are exempted from hazardous waste
management.
Subtitle C of RCRA exempted fossil fuel combustion wastes from hazardous waste regulation
until the EPA completed a report to Congress and made a determination on whether the wastes should
be regulated as hazardous. In a 1993 regulatory determination, the EPA addressed some high
volume-low toxicity coal combustion wastes generated at electric utility and independent power
producing facilities, such as coal ash. In May 2000, the EPA concluded that coal combustion wastes
do not warrant regulation as hazardous under RCRA. The EPA is retaining the hazardous waste
exemption for these wastes. However, the EPA has determined that national non-hazardous waste
regulations under RCRA Subtitle D are needed for coal combustion wastes disposed in surface
impoundments and landfills and used as mine-fill. The EPA also concluded beneficial uses of these
wastes, other than for mine-filling, pose no significant risk and no additional national
regulations are needed. As long as this exemption remains in effect, it is not anticipated that
regulation of coal combustion waste will have any material effect on the amount of coal used by
electricity generators. However, the recent failure of an ash disposal dam in Tennessee has focused
attention on this issue and many environmental groups continue to push for classification of ash as
a hazardous waste. The EPA is reconsidering its previous position and is drafting new regulations
to govern ash dispoal. Proposed regulations should be published for public comment in the near
future.
Federal and State Superfund Statutes
Superfund and similar state laws affect coal mining and hard rock operations by creating
liability for investigation and remediation in response to releases of hazardous substances into
the environment and for damages to natural resources. Under Superfund, joint and several liability
may be imposed on waste generators, site owners or operators and others, regardless of fault. In
addition, mining operations may have reporting obligations under the Emergency Planning and
Community Right to Know Act and the Superfund Amendments and Reauthorization Act.
GLOSSARY OF SELECTED TERMS
Ash. Impurities consisting of iron, alumina and other incombustible matter that are contained
in coal. Since ash increases the weight of coal, it adds to the cost of handling and can affect the
burning characteristics of coal.
Assigned reserves. Coal that is planned to be mined at an operation that is currently
operating, currently idled, or for which permits have been submitted and plans are eventually to
develop the operation.
Bituminous coal. A common type of coal with moisture content less than 20% by weight and
heating value of 9,500 to 14,000 Btus per pound. It is dense and black and often has well-defined
bands of bright and dull material.
British thermal unit, or Btu. A measure of the thermal energy required to raise the
temperature of one pound of pure liquid water one degree Fahrenheit at the temperature at which
water has its greatest density (39 degrees Fahrenheit).
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Central Appalachia. Coal producing area in eastern Kentucky, Virginia, southern West Virginia
and a portion of eastern Tennessee.
Coal seam. Coal deposits occur in layers. Each layer is called a “seam.”
Coke. A hard, dry carbon substance produced by heating coal to a very high temperature in the
absence of air. Coke is used in the manufacture of iron and steel. Its production results in a
number of useful byproducts.
Compliance coal. Coal which, when burned, emits 1.2 pounds or less of sulfur dioxide per
million Btu, as required by Phase II of the Clean Air Act.
Continuous miner. A machine which constantly extracts coal while loading. This is to be
distinguished from a conventional mining unit which must stop the extraction process in order for
loading to commence.
Fossil fuel. Fuel such as coal, petroleum or natural gas formed from the fossil remains of
organic material.
High Btu coal. Coal which has an average heat content of 12,500 Btus per pound or greater.
Illinois Basin. Coal producing area in Illinois, Indiana and western Kentucky.
Lignite. The lowest rank of coal with a high moisture content of up to 15% by weight and heat
value of 6,500 to 8,300 Btus per pound. It is brownish black and tends to oxidize and disintegrate
when exposed to air.
Longwall mining. The most productive underground mining method in the United States. A
rotating drum is trammed mechanically across the face of coal, and a hydraulic system supports the
roof of the mine while the drum advances through the coal. Chain conveyors then move the loosened
coal to a standard underground mine conveyor system for delivery to the surface.
Low Btu coal. Coal which has an average heat content of 9,500 Btus per pound or less.
Low sulfur coal. Coal which, when burned, emits 1.6 pounds or less of sulfur dioxide per
million Btu.
Medium sulfur coal. Coal which, when burned, emits between 1.6 and 4.5 pounds of sulfur
dioxide per million Btu.
Metallurgical coal. The various grades of coal suitable for carbonization to make coke for
steel manufacture. Also known as “met” coal, its quality depends on four important criteria:
volatility, which affects coke yield; the level of impurities including sulfur and ash, which
affect coke quality; composition, which affects coke strength; and basic characteristics, which
affect coke oven safety. Met coal typically has a particularly high Btu but low ash and sulfur
content.
Mid Btu coal. Coal which has an average heat content of between 9,500 and 12,500 Btus per
pound.
Nitrogen oxide (NOx). A gas formed in high temperature environments such as coal combustion.
It is a harmful pollutant that contributes to smog.
Northern Appalachia. Coal producing area in Maryland, Ohio, Pennsylvania and northern West
Virginia.
Overburden. Layers of earth and rock covering a coal seam. In surface mining operations,
overburden is removed prior to coal extraction.
Pillar. An area of coal left to support the overlying strata in a mine; sometimes left
permanently to support surface structures.
Powder River Basin. Coal producing area in northeastern Wyoming and southeastern Montana. This
is the largest known source of coal reserves and the largest producing region in the United States.
Preparation plant. Usually located on a mine site, although one plant may serve several mines.
A preparation plant is a facility for crushing, sizing and washing coal to remove impurities and
prepare it for use by a particular customer. The washing process has the added benefit of removing
some of the coal’s sulfur content.
Probable reserves. 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.
Proven reserves. Reserves for which 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 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.
Reclamation. The process of restoring land and the environment to their original state
following mining activities. The process commonly includes “recontouring” or reshaping the land to
its approximate original appearance, restoring topsoil and planting native grass and ground covers.
Reclamation operations are usually underway before the mining of a particular site is completed.
Reclamation is closely regulated by both state and federal law.
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Reserve. That part of a mineral deposit that could be economically and legally extracted or
produced at the time of the reserve determination.
Roof. The stratum of rock or other mineral above a coal seam; the overhead surface of a coal
working place.
Room-and-Pillar Mining. Method of underground mining in which the mine roof is supported
mainly by coal pillars left at regular intervals. Rooms are placed where the coal is mined.
Scrubber (flue gas desulfurization system). Any of several forms of chemical/physical devices
which operate to neutralize sulfur compounds formed during coal combustion. These devices combine
the sulfur in gaseous emissions with other chemicals to form inert compounds, such as gypsum, that
must then be removed for disposal. Although effective in substantially reducing sulfur from
combustion gases, scrubbers require about 6% to 7% of a power plant’s electrical output and
thousands of gallons of water to operate.
Steam coal. Coal used by power plants and industrial steam boilers to produce electricity,
steam or both. It generally is lower in Btu heat content and higher in volatile matter than
metallurgical coal.
Sub-bituminous coal. Dull coal that ranks between lignite and bituminous coal. Its moisture
content is between 20% and 30% by weight and its heat content ranges from 7,800 to 9,500 Btus per
pound of coal.
Sulfur. One of the elements present in varying quantities in coal that contributes to
environmental degradation when coal is burned. Sulfur dioxide is produced as a gaseous by-product
of coal combustion.
Surface mine. A mine in which the coal lies near the surface and can be extracted by removing
the covering layer of soil (see “Overburden”). About 67% of total U.S. coal production comes from
surface mines.
Tons. A “short” or net ton is equal to 2,000 pounds. A “long” or British ton is equal to 2,240
pounds; a “metric” tonne is approximately 2,205 pounds. The short ton is the unit of measure
referred to in this document.
Truck-and-Shovel Mining and Truck and Front-End Loader Mining. Similar forms of mining where
large shovels or front-end loaders are used to remove overburden, which is used to backfill pits
after the coal is removed. Smaller shovels load coal in haul trucks for transportation to the
preparation plant or rail loadout.
Unassigned reserves. Coal that is likely to be mined in the future, but which is not
considered Assigned reserves.
Underground mine. Also known as a “deep” mine. Usually located several hundred feet below the
earth’s surface, an underground mine’s coal is removed mechanically and transferred by shuttle car
and conveyor to the surface. Underground mines account for about 33% of annual U.S. coal
production.
Unit train. A train of 100 or more cars carrying a single product. A typical coal unit train
can carry at least 10,000 tons of coal in a single shipment.
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Item 1A. Risk Factors
Any change in coal consumption patterns by steel producers or North American electric power
generators resulting in a decrease in the use of coal by those consumers could result in lower
prices for our coal, which would reduce our revenues and adversely impact our earnings and the
value of our coal reserves.
Steam coal accounted for approximately 83% and 58% of our coal sales volume during 2009 and
2008, respectively. The majority of our sales of steam coal were to U.S. and Canadian electric
power generators. The amount of coal consumed for U.S. and Canadian electric power generation is
affected primarily by the overall demand for electricity, the location, availability, quality and
price of competing fuels for power such as natural gas, nuclear, fuel oil and alternative energy
sources such as hydroelectric power, technological developments, and environmental and other
governmental regulations. We expect many new power plants will be built to produce electricity
during peak periods of demand, when the demand for electricity rises above the “base load demand,”
or minimum amount of electricity required if consumption occurred at a steady rate. However, we
also expect that many of these new power plants will be fired by natural gas because they are
cheaper to construct than coal-fired plants and because natural gas is a cleaner burning fuel with
plentiful supplies at the current time. In addition, the increasingly stringent requirements of the
Clean Air Act may result in more electric power generators shifting from coal to natural gas-fired
power plants. Any reduction in the amount of coal consumed by North American electric power
generators could reduce the price of steam coal that we mine and sell, thereby reducing our
revenues and adversely impacting our earnings and the value of our coal reserves.
We produce metallurgical coal that is used in both the U.S. and foreign steel industries.
Metallurgical coal accounted for approximately 17% and 42% of our coal sales volume during 2009 and
2008, respectively. Any deterioration in conditions in the U.S. steel industry would reduce the
demand for our metallurgical coal and could impact the collectability of our accounts receivable
from U.S. steel industry customers. In addition, the U.S. steel industry increasingly relies on
electric arc furnaces or pulverized coal processes to make steel. These processes do not use coke.
If this trend continues, the amount of metallurgical coal that we sell and the prices that we
receive for it could decrease, thereby reducing our revenues and adversely impacting our earnings
and the value of our coal reserves. If the demand and pricing for metallurgical coal in
international markets decreases in the future, the amount of metallurgical coal that we sell and
the prices that we receive for it could decrease, thereby reducing our revenues and adversely
impacting our earnings and the value of our coal reserves.
A substantial or extended decline in coal prices could reduce our revenues and the value of
our coal reserves.
Our results of operations are substantially dependent upon the prices we receive for our coal.
The prices we receive for coal depend upon factors beyond our control, including:
Declines in the prices we receive for our coal could adversely affect our operating results
and our ability to generate the cash flows we require to improve our productivity and invest in our
operations.
The government extensively regulates our mining operations, which imposes significant actual
and potential costs on us, and future regulations could increase those costs or limit our
ability to produce coal.
Our operations are subject to a variety of federal, state and local environmental, health and
safety, transportation, labor and other laws and regulations. Examples include those relating to
employee health and safety; emissions to air and discharges to water; plant and wildlife
protection; the reclamation and restoration of properties after mining or other activity has been
completed; the storage, treatment and disposal of wastes; remediation of contaminated soil, surface
and groundwater; surface subsidence from underground mining; noise; and the effects of operations
on surface water and groundwater quality and availability. In addition, we are subject to
significant legislation mandating certain benefits for current and retired coal miners. We incur
substantial costs to comply with the laws and regulations that apply to our mining and other
operations. Because of extensive and comprehensive regulatory requirements, violations of laws,
regulations and permits occur at our
operations from time to time and may result in significant costs to us to correct such
violations, as well as civil or criminal penalties and limitations or shutdowns of our operations.
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These laws and regulations require us to obtain numerous governmental permits. Many of our
permits are subject to renewal from time to time, and renewed permits may contain more restrictive
conditions than our existing permits. Many of our permits governing discharges to or impacts upon
surface streams and groundwater will be subject to new and more stringent conditions to address
various new water quality requirements that permitting authorities are now required to address when
those permits are renewed over the next several years. To obtain new permits, we may have to
petition to have stream quality designations changed based on available data, and if we are
unsuccessful we may not be able to operate the planned facility or to operate as planned. Although
we have no estimates at this time, our costs to satisfy such conditions could be substantial. We
may also be required under certain permits to provide authorities data pertaining to the effect or
impact that a proposed exploration for or production of coal may have on the environment.
In recent years, the permitting required under the Clean Water Act to address filling
ephemeral and intermittent streams and other valleys with materials from mountaintop coal mining
operations and preparation plant refuse disposal has been the subject of extensive litigation by
environmental groups against coal mining companies and environmental regulatory authorities, as
well as regulatory changes by legislative initiatives in the U.S. Congress. It is unclear at this
time how the issues will ultimately be resolved, but for this as well as other issues that may
arise involving permits necessary for coal mining and other operation, such requirements could
prove costly and time-consuming, and could delay commencing or continuing exploration or production
operations. New laws and regulations, as well as future interpretations or different enforcement of
existing laws and regulations, may require substantial increases in equipment and operating costs
to us and delays, interruptions or a termination of operations, the extent of which we cannot
predict.
In September 2009, the U.S. Environmental Protection Agency (“EPA”) announced it had
identified 79 pending permit applications for Appalachian surface coal mining, under a coordination
process with the Army Corps of Engineers (the “COE”) and the United States Department of the
Interior entered into in June 2009, that the EPA believes warrant further review because of its
continuing concerns about water quality and/or regulatory compliance issues. These included five of
our permit applications, two of which we have withdrawn. While the EPA has stated that its
identification of these 79 permit applications does not constitute a determination that the mining
involved cannot be permitted under the Clean Water Act and does not constitute a final
recommendation from the EPA to the COE on these projects, it is uncertain how long the further
review will take for our three subject permit applications or what the final outcome will be. It
is also unclear what impact this process may have on our future applications for surface coal
mining permits and surface facilities at underground mines.
Extensive regulation of these matters has had and will continue to have a significant effect
on our costs of production and competitive position. Further legislation, regulations or
enforcement may also cause our sales or profitability to decline by hindering our ability to
continue our mining operations, by increasing our costs or by causing coal to become a less
attractive fuel source.
Climate change initiatives could significantly reduce the demand for coal, increase our costs
and reduce the value of our coal and gas assets.
Global climate change continues to attract considerable public and scientific attention with
widespread concern about the impacts of human activity, especially the emissions of greenhouse
gases, such as carbon dioxide and methane. Combustion of fossil fuels, such as the coal and gas we
produce, results in the creation of carbon dioxide that is currently emitted into the atmosphere by
coal and gas end users, such as coal-fired electric generation power plants. Our underground mines
emit methane, which must be expelled for safety reasons.
Numerous proposals have been made and are likely to continue to be made at the international,
national, regional and state levels of government that are intended to limit emissions of
greenhouse gases.The United States and more than 160 other nations are signatories to the 1992
United Nations Framework Convention on Climate Change, which is intended to limit emissions of
greenhouse gases, such as carbon dioxide which is a major by-product of burning coal. Since 1992,
numerous conferences have been held among the participants, the goals of which were to agree on a
plan to reduce emissions of gasses that are considered to cause global warming, including the most
recent conference in Copenhagen in December 2009. However, there have been no agreements to date.
Such an agreement, if consummated, will likely have significant, but undetermined, impacts on the
demand for coal
U.S. legislative and regulatory action also may address greenhouse gas emissions. In June
2009, the Waxman-Markey bill, which would establish a cap-and-trade program designed to achieve
substantial reductions in greenhouse gas emissions, passed the U.S. House of Representatives.
Similar legislation currently is under consideration in the U.S. Senate. The EPA also has commenced
regulatory action that could lead to controls on carbon dioxide from larger emitters such as
coal-fired power plants and industrial sources. In advance of federal action, state and regional
climate change initiatives, such as the Regional Greenhouse Gas Initiative of eastern states, the
Western Regional Climate Action Initiative, and recently enacted legislation in California and
other states are taking effect before federal action. In addition, some states and municipalities
in the United States have adopted or may adopt in the future regulations on greenhouse gas
emissions. Some states and municipal entities have commenced litigation in different jurisdictions
seeking to have certain utilities, including some of our customers, reduce their emission of carbon
dioxide. President Obama has pledged to implement an economy-wide cap-and-trade program to reduce
greenhouse gas emissions 80 percent by 2050. He also pledged the United States to be a world leader
on greenhouse gas reduction and re-engage with the United Nations Framework Convention on Climate
Change to develop a global greenhouse gas program. Apart from governmental regulation, in February
2008, three of Wall Street’s largest investment banks announced that they had adopted climate
change
guidelines for lenders. The guidelines require the evaluation of carbon risks in the financing
of utility power plants which may make it more difficult for utilities to obtain financing for
coal-fired plants.
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Considerable uncertainty is associated with these climate change initiatives. The content of
new treaties, legislation or regulation is not yet determined, and many of the new regulatory
initiatives remain subject to review by the agencies or the courts. Predicting the economic effects
of climate change legislation is difficult given the various alternatives proposed and the
complexities of the interactions between economic and environmental issues. Any regulations on
greenhouse gas emissions, however, are likely to impose significant emissions control expenditures
on many coal-fired power plants and industrial boilers and could have the effect of making them
unprofitable. As a result, these generators may switch to other fuels that generate less of these
emissions, possibly reducing future demand for coal and the construction of coal-fired power
plants. In this regard, many of our coal supply agreements contain provisions that allow a
purchaser to terminate its contract if legislation is passed that either restricts the use or type
of coal permissible at the purchaser’s plant or results in specified increases in the cost of coal
or its use to comply with applicable ambient air quality standards. Any switching of fuel sources
away from coal, closure of existing coal-fired plants, or reduced construction of new plants could
have a material adverse effect on demand for and prices received for our coal and a material
adverse effect on our results of operations, cash flows and financial condition. In addition, if
regulation of greenhouse gas emissions does not exempt the release of coalbed methane, we may have
to curtail coal production, pay higher taxes, or incur costs to purchase credits that permit us to
continue operations as they now exist at our underground coal mines.
Other extensive environmental regulations also could affect our customers and could reduce the
demand for coal as a fuel source and cause our sales to decline.
The operations of our customers are subject to extensive laws and regulations relating to
emissions to air and discharges to water, plant and wildlife protection, the storage, treatment and
disposal of wastes, and permitting of operations. These requirements are a significant part of the
costs of their respective businesses, and their costs are increasing as environmental requirements
become more stringent. These requirements could adversely affect our sales by causing coal to
become a less attractive fuel source of energy.
In particular, the Clean Air Act and similar state and local laws extensively regulate the
amount of sulfur dioxide, particulate matter, nitrogen oxides, mercury and other compounds emitted
into the air from electric power plants, which are the largest end-users of our coal. A series of
more stringent requirements are expected to become effective in coming years. These requirements
include implementation of the current and more stringent proposed ambient air quality standards for
particulate matter and ozone, implementation of and forthcoming revisions to the Clean Air
Interstate rule governing emission levels of sulfur dioxide and nitrogen oxides, and the EPA’s
projected rule to limit emissions of mercury and other hazardous air pollutants from power plants.
Such requirements may require significant emissions control expenditures for coal-fired power
plants. Any switching of fuel sources away from coal, closure of existing coal-fired plants, or
reduced construction of new plants could have a material effect on demand for and prices received
for our coal.
MSHA and state regulators may order certain of our mines to be temporarily closed or
operations therein modified, which would adversely affect our ability to meet our contracts or
projected costs.
MSHA and state regulators may order certain of our mines to be temporarily closed due to an
investigation of an accident resulting in property damage or injuries, or due to other incidents
such as fires, roof falls, water flow, equipment failure or ventilation concerns. In addition,
regulators may order changes to mine plans or operations due to their interpretation or application
of existing or new laws or regulations. Any required changes to mine plans or operations may result
in temporary idling of production or addition of costs.
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Our coal mining production and delivery is subject to conditions and events beyond our
control, which could result in higher operating expenses and decreased production and sales
and adversely affect our operating results and could result in impairments to our assets.
A majority of our coal mining operations are conducted in underground mines and the balance of
our operations is at surface mines. The level of our production at these mines is subject to
operating conditions and events beyond our control that could disrupt operations, affect production
and the cost of mining at particular mines for varying lengths of time and have a significant
impact on our operating results. Adverse operating conditions and events that we have experienced
in the past include:
If any of these conditions or events occur in the future at any of our mines or affect
deliveries of our coal to customers, they may increase our cost of mining and delay or halt
production at particular mines or sales to our customers either permanently or for varying lengths
of time, which could adversely affect our operating results and could result in impairments to our
assets.
We may be unable to obtain and renew permits necessary for our operations, which would reduce
our production, cash flow and profitability.
Mining companies must obtain numerous permits that impose strict conditions on various
environmental and safety matters in connection with coal mining. These include permits issued by
various federal and state agencies and regulatory bodies. The permitting rules are complex and may
change over time, making our ability to comply with the applicable requirements more difficult or
impractical, possibly precluding the continuance of ongoing operations or the development of future
mining operations. The public, including special interest groups and individuals, have certain
rights under various statutes to comment upon, submit objections to, and otherwise engage in the
permitting process, including bringing citizens’ lawsuits to challenge such permits or mining
activities. Accordingly, required permits may not be issued or renewed in a timely fashion (or at
all), or permits issued or renewed may be conditioned in a manner that may restrict our ability to
efficiently conduct our mining activities. Such inefficiencies would likely reduce our production,
cash flow, and profitability.
In particular, certain of our activities involving valley fills, ponds or impoundments,
refuse, road building, placement of excess material, and other mine development activities require
a Section 404 dredge and fill permit from the Army Corps of Engineers (“COE”) and a Section 401
certification or its equivalent from the state in which the mining activities are proposed. In
recent years, the Section 404 permitting process has faced a series of court challenges that have
resulted in increased costs and delays in the permitting process. Future challenges or changes to
the permitting process could cause additional increases in the costs, time, and difficulty
associated with obtaining and complying with the permits, and could, as a result, adversely affect
our coal production.
Our operations may impact the environment or cause exposure to hazardous substances, and our
properties may have environmental contamination, which could result in material liabilities to
us.
Our operations currently use hazardous materials, and from time to time we generate limited
quantities of hazardous wastes. We and our acquired companies also utilized certain hazardous
materials and generated similar wastes. We may be subject to claims under federal or state statutes
or common law doctrines for toxic torts, natural resource damages and other damages as well as for
the investigation and clean up of soil, surface water, sediments, groundwater, and other natural
resources. Such claims may arise out of current or former conditions at sites that we own or
operate currently, as well as at sites that we and our acquired companies owned or operated in the
past, and at contaminated sites that have always been owned or operated by third parties. Our
liability for such claims may be joint and several, so that we may be held responsible for more
than our share of the contamination or other damages, or even for the entire share.
We maintain extensive coal slurry impoundments at a number of our mines. Such impoundments are
subject to extensive regulation. Slurry impoundments maintained by other coal mining operations
have been known to fail, causing extensive damage to the environment and natural resources, as well
as liability for related personal injuries and property damages. Some of our impoundments overlie
mined out areas, which can pose a heightened risk of failure and of damages arising out of failure.
If one of our impoundments were to fail, we could be subject to substantial claims for the
resulting environmental contamination and associated liability, as well as for fines and penalties.
The recent failure of the fly ash impoundment at the Tennessee Valley Authority’s Kingston Power
Plant, which is not regulated in the same manner as our slurry impoundments, could result in
additional scrutiny of our impoundments.
These and other unforeseen environmental impacts that our operations may have, as well as
exposures to hazardous substances or wastes associated with our operations, could result in costs
and liabilities that could materially and adversely affect our business.
Also, see Item 1 “Business-Environmental and Other Regulatory Matters” for discussion related
to “Superfund” and “RCRA.”
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Mining in Central and Northern Appalachia is more complex and involves more regulatory
constraints than mining in other areas of the United States, which could affect our mining
operations and cost structures in these areas.
The geological characteristics of Central and Northern Appalachian coal reserves, such as
depth of overburden and coal seam thickness, make them complex and costly to mine. As mines become
depleted, replacement reserves may not be available when required or, if available, may not be
capable of being mined at costs comparable to those characteristic of the depleting mines. In
addition, as compared to mines in the Powder River Basin, permitting, licensing and other
environmental and regulatory requirements are more costly and time
consuming to satisfy. These factors could materially adversely affect the mining operations and cost structures of,
and our customers’ ability to use coal produced by, our mines in Central and Northern Appalachia.
Competition within the coal industry may adversely affect our ability to sell coal, and excess
production capacity in the industry could put downward pressure on coal prices.
We compete with numerous other coal producers in various regions of the United States for
domestic and international sales. Recent increases in coal prices could encourage the development
of expanded capacity by new or existing coal producers. Any resulting overcapacity could reduce
coal prices and therefore reduce our revenues.
Demand for our higher sulfur coal and the price that we can obtain for it is impacted by,
among other things, the changing laws with respect to allowable emissions and the price of emission
allowances. Significant increases in the price of those allowances could reduce the competitiveness
of higher sulfur coal at plants not equipped to reduce sulfur dioxide emissions. Competition from
low sulfur coal and possibly natural gas could result in a decrease in the higher-sulfur coal
market share and revenues from some of our operations.
Demand for our low sulfur coal and the prices that we can obtain for it are also affected by,
among other things, the price of emissions allowances. Decreases in the prices of these emissions
allowances could make low sulfur coal less attractive to our customers. In addition, more
widespread installation by electric utilities of technology that reduces sulfur emissions (which
could be accelerated by increases in the prices of emissions allowances), may make high sulfur coal
more competitive with our low sulfur coal. This competition could adversely affect our business and
results of operations.
We also compete in international markets against coal produced in other countries. Measured by
tons sold, exports accounted for approximately 14% of our sales in 2009. The demand for U.S. coal
exports is dependent upon a number of factors outside of our control, including the overall demand
for electricity in foreign markets, currency exchange rates, the demand for foreign-produced steel
both in foreign markets and in the U.S. market (which is dependent in part on tariff rates on
steel), general economic conditions in foreign countries, technological developments, and
environmental and other governmental regulations. For example, if the value of the U.S. dollar were
to rise against other currencies in the future, our coal would become relatively more expensive and
less competitive in international markets, which could reduce our foreign sales and negatively
impact our revenues and net income. In addition, if the amount of coal exported from the United
States were to decline, this decline could cause competition among coal producers in the United
States to intensify, potentially resulting in additional downward pressure on domestic coal prices.
Overcapacity in the coal industry, both domestically and internationally, may affect the price
we receive for our coal. For example, in the past, increased demand for coal and attractive pricing
brought new investors to the coal industry and promoted the development of new mines. These factors
resulted in added production capacity throughout the industry, which led to increased competition
and lower coal prices.
We face numerous uncertainties in estimating our economically recoverable coal reserves, and
inaccuracies in our estimates could result in lower than expected revenues, higher than
expected costs or decreased profitability.
We base our reserve information on engineering, economic and geological data assembled and
analyzed by our staff, which includes various engineers and geologists, and which is periodically
reviewed by outside firms. The reserve estimates as to both quantity and quality are annually
updated to reflect production of coal from the reserves and new drilling, engineering or other data
received. There are numerous uncertainties inherent in estimating quantities and qualities of and
costs to mine recoverable reserves, including many factors beyond our control. Estimates of
economically recoverable coal reserves and net cash flows necessarily depend upon a number of
variable factors and assumptions, such as geological and mining conditions which may not be fully
identified by available exploration data or which may differ from experience in current operations,
historical production from the area compared with production from other similar producing areas,
the assumed effects of regulation and taxes by governmental agencies and assumptions concerning
coal prices, operating costs, mining technology improvements, severance and excise tax, development
costs and reclamation costs, all of which may vary considerably from actual results.
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For these reasons, estimates of the economically recoverable quantities and qualities
attributable to any particular group of properties, classifications of reserves based on risk of
recovery and estimates of net cash flows expected from particular reserves prepared by different
engineers or by the same engineers at different times may vary substantially. Actual coal tonnage
recovered from identified reserve areas or properties and revenues and expenditures with respect to
our reserves may vary materially from estimates. These estimates thus may not accurately reflect
our actual reserves. Any inaccuracy in our estimates related to our reserves could result in lower
than expected revenues, higher than expected costs or decreased profitability.
Our ability to operate our company effectively could be impaired if we fail to attract and
retain key personnel.
Our ability to operate our business and implement our strategies depends, in part, on the
efforts of our executive officers and other key employees. In addition, our future success will
depend on, among other factors, our ability to attract and retain other qualified personnel. The
loss of the services of any of our executive officers or other key employees or the inability to
attract or retain other qualified personnel in the future could have a material adverse effect on
our business or business prospects.
Due to our participation in multi-employer pension plans, we may have exposure under those
plans that extend beyond what our obligation would be with respect to our employees.
We contribute to two multi-employer defined benefit pension plans administered by the UMWA. In
2009, our total contributions to these plans and other contractual payments under our UMWA wage
agreement were approximately $8.4 million.
In the event of a partial or complete withdrawal by us from any plan which is underfunded, we
would be liable for a proportionate share of such plan’s unfunded vested benefits. Based on the
information available from plan administrators, we believe that our portion of the contingent
liability in the case of a full withdrawal or termination would be material to our financial
position and results of operations. In the event that any other contributing employer withdraws
from any plan which is underfunded, and such employer (or any member in its controlled group)
cannot satisfy its obligations under the plan at the time of withdrawal, then we, along with the
other remaining contributing employers, would be liable for our proportionate share of such plan’s
unfunded vested benefits.
The Pension Protection Act of 2006 (“Pension Act”) requires a minimum funding ratio of 80% be
maintained for this multi-employer pension plan and if the plan is determined to have a funding
ratio of less than 80%, it will be deemed to be “endangered”, and if less than 65% it will deemed
to be “critical”, and in either case will be subject to additional funding requirements. Based on
an estimated funding percentage of 91.4%, a certification was provided by the multi-employer plan
actuary, stating that the plan is in neither “endangered” nor “critical” status for the plan year
beginning July 1, 2008. If a subsequent estimate of the funding ratio performed by the
multi-employer plan actuary were to deem the plan to be in “endangered” or “critical” status, such
a determination would require certain of our subsidiaries to make additional contributions pursuant
to a funding improvement plan implemented in accordance with the Pension Act, and, therefore, could
have a material impact on our operating results.
Our defined benefit pension plans are currently underfunded and we may have to make
significant cash payments to the plans, reducing the cash available for our business.
We sponsor defined benefit pension plans in the United States for certain salaried and
non-union hourly employees. For these plans, the Pension Protection Act (“PPA”) generally
establishes a funding target of 100% of the present value of accrued benefits. The PPA includes a
funding target phase-in provision such that the funding target is 92% in 2008, 94% in 2009, 96% in
2010 and 100% thereafter. Generally, a plan with a funding ratio below the prescribed target is
subject to additional contributions requirements (amortization of funding shortfalls). Furthermore,
any such plan with a funding ratio of less than 80% will be deemed at risk and will be subject to
even higher funding requirements under the PPA. The current volatile economic environment and the
rapid deterioration in the equity markets since July 1, 2008 caused investment income and the value
of existing assets held in our pension trust to decline. As a result, we may be required to make
significant cash contributions into the pension trust in order to comply with the funding
requirements of the Pension Act. In 2009 we contributed approximately $22.7 million to our pension
plans. We currently expect to make contributions in 2010 of approximately $30.0 million to maintain
at least an 80% funding ratio.
As of December 31, 2009, our annual measurement date, our salaried and hourly pension plans
were underfunded by $86.5 million (based on the actuarial assumptions used for Employers’
Accounting for Defined Benefit Pension and Other Postretirement Plans, (“ASC 715”). These pension
plans are subject to the Employee Retirement Income Security Act of 1974 (“ERISA”). Under ERISA,
the Pension Benefit Guaranty Corporation, or PBGC, has the authority to terminate an underfunded
pension plan under limited circumstances. In the event our U.S. pension plans are terminated for
any reason while the plans are underfunded, we may incur a liability to the PBGC that could exceed
the entire amount of the underfunding.
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Our work force could become increasingly unionized in the future and our unionized or
union-free hourly work force could strike, which could adversely affect the stability of our
production and reduce our profitability.
Approximately 87% of our 2009 coal production came from mines operated by union-free
employees. As of December 31, 2009, approximately 79% of our employees are union-free. However, our
subsidiaries’ employees have the right at any time under the National Labor Relations Act to form
or affiliate with a union. Any further unionization of our subsidiaries’ employees, or the
employees of third-party contractors who mine coal for us, could adversely affect the stability of
our production and reduce our profitability.
Two of our Pennsylvania subsidiaries have separate wage agreements with the United Mine
Workers of America (“UMWA”). Their existing wage agreements cover 1,113 (571 and 542,
respectively) employees, and both wage agreements will expire at the end of the fourth quarter of
2011. Additionally, there is an agreement between Emerald Coal Resources, LP (“Emerald”) and the
UMWA on behalf of the five employees working at the warehouse for Emerald, which
expires at the end of the fourth quarter of 2011. Another Pennsylvania subsidiary has a wage
agreement with the International Brotherhood of Electrical Workers (“IBEW”) covering 8 employees.
One of our Virginia subsidiaries has two contracts with the UMWA that cover 234
employees. Those contracts were terminated by the employer on December 31, 2009, and the parties
are currently engaged in good faith bargaining for new wage agreements.
One of our West Virginia subsidiaries has a wage agreement with the UMWA, covering
16 employees. Also, another West Virginia subsidiary, which is idle, has a wage
agreement with the UMWA that could be terminated by our subsidiary or the UMWA with notice but
since it is idle, no employees are affected at this time. However, if the operation becomes active
again, these employees could be affected.
The hourly workforce at the Wabash mine in southern Illinois was represented by the UMWA prior
to its idling in 2007. The effects of the idling were the subject of an agreement with the UMWA
signed in April 2007.
As is the case with our union-free operations, the UMWA and IBEW represented employees could
strike, which would disrupt our production, increase our costs, and disrupt shipments of coal to
our customers, or result in the closure of affected mines due to a strike by the workers or a
lockout by mine management, which could reduce our profitability.
A shortage of skilled labor in the mining industry could pose a risk to achieving improved
labor productivity and competitive costs and could adversely affect our profitability.
Efficient coal mining using modern techniques and equipment requires skilled laborers,
preferably with at least a year of experience and proficiency in multiple mining tasks. In recent
years, a shortage of trained coal miners in the mining industry has caused us to operate certain
units without full staff, which decreases our productivity and increases our costs. If the shortage
of experienced labor continues or worsens, it could have an adverse impact on our labor
productivity and costs and our ability to expand production in the event there is an increase in
the demand for our coal, which could adversely affect our profitability.
Acquisitions that we have completed since our formation, as well as acquisitions that we may
undertake in the future, involve a number of risks, any of which could cause us not to realize
the anticipated benefits.
We continually seek to expand our operations and coal reserves through acquisitions. In the
past five years, we have completed significant acquisitions and several smaller acquisitions
and investments. Our ability to complete acquisitions is subject to availability of attractive
targets on terms acceptable to us and general market conditions, among other things. If we are
unable to successfully integrate the companies, businesses or properties that we acquire, our
profitability may decline and we could experience a material adverse effect on our business,
financial condition or results of operations. Acquisition transactions involve various inherent
risks, including:
Any one or more of these factors could cause us not to realize the benefits anticipated to
result from an acquisition.
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Moreover, any acquisition opportunities we pursue could materially affect our liquidity and
capital resources and may require us to incur indebtedness, seek equity capital or both. Future
acquisitions could also result in our assuming more long-term liabilities relative to the value of
the acquired assets than we have assumed in our previous acquisitions. Further, new acquisition
accounting rules adopted January 1, 2009 require changes in certain assumptions made subsequent to
the measurement period as defined in current accounting standards, to be recorded in current period
earnings, which could affect our results of operations.
Changes in purchasing patterns in the coal industry may make it difficult for us to extend
existing supply contracts or enter into new long-term supply contracts with customers, which
could adversely affect the capability and profitability of our operations.
We sell a significant portion of our coal under long-term coal supply agreements, which are
contracts with a term greater than 12 months. The execution of a satisfactory long-term coal supply
agreement is frequently the basis on which we undertake the development of coal reserves required
to be supplied under the contract. During 2009, approximately 71% and 55% of our steam and
metallurgical coal sales volume, respectively, was delivered pursuant to long-term contracts. At
December 31, 2009, our long-term coal supply agreements had remaining terms of up to eight years
and an average remaining term of approximately two years. When our current contracts with customers
expire or are otherwise renegotiated, our customers may decide to purchase fewer tons of coal than
in the past or on different terms, including pricing terms less favorable to us. For additional
information relating to our long-term coal supply contracts, see “Business — Marketing, Sales and
Customer Contracts.”
As of February 8, 2010, approximately 3% and 25%, respectively, of our planned production for
2010 and 2011 was uncommitted. We may not be able to enter into coal supply agreements to sell this
production on terms, including pricing terms, as favorable to us as our existing agreements.
As electric utilities continue to adjust to frequently changing regulations, including the
Acid Rain regulations of the Clean Air Act, the Clean Air Mercury Rule, the Clean Air Interstate
Rule and the possible deregulation of their industry, they are becoming increasingly less willing
to enter into long-term coal supply contracts and instead are purchasing higher percentages of coal
under short-term supply contracts. The industry shift away from long-term supply contracts could
adversely affect us and the level of our revenues. For example, fewer electric utilities will have
a contractual obligation to purchase coal from us, thereby increasing the risk that we will not
have a market for our production. The prices we receive in the spot market may be less than the
contractual price an electric utility is willing to pay for a committed supply. Furthermore, spot
market prices tend to be more volatile than contractual prices, which could result in decreased
revenues.
Certain provisions in our long-term supply contracts may reduce the protection these contracts
provide us during adverse economic conditions or may result in economic penalties upon our
failure to meet specifications.
Price adjustment, “price reopener” and other similar provisions in long-term supply contracts
may reduce the protection from short-term coal price volatility traditionally provided by these
contracts. Price reopener provisions are particularly common in international metallurgical coal
sales contracts. Some of our coal supply contracts contain provisions that allow for the price to
be renegotiated at periodic intervals. Generally, price reopener provisions require the parties to
agree on a new price based on the prevailing market price, however, some contracts provide that the
new price is set between a pre-set “floor” and “ceiling.” In some circumstances, failure of the
parties to agree on a price under a price reopener provision can lead to termination of the
contract. Any adjustment or renegotiation leading to a significantly lower contract price could
result in decreased revenues. Accordingly, supply contracts with terms of one year or more may
provide only limited protection during adverse market conditions.
Coal supply agreements also typically contain force majeure provisions allowing temporary
suspension of performance by us or the customer during the duration of specified events beyond the
control of the affected party. Most of our coal supply agreements contain provisions requiring us
to deliver coal meeting quality thresholds for certain characteristics such as Btu, sulfur content,
ash content, grindability and ash fusion temperature. Failure to meet these specifications could
result in economic penalties, including price adjustments, the rejection of deliveries or
termination of the contracts. In addition, some of these contracts allow our customers to terminate
their contracts in the event of changes in regulations affecting our industry that increase the
price of coal beyond specified limits.
As a result of the economic slowdown that has resulted in deep cuts in worldwide steel
production in late 2008 and the first half of 2009 and the application of such price adjustment and
other similar provisions in our long-term supply contracts, we had to restructure certain
agreements under mutually acceptable terms with steel customers starting in late 2008 and
continuing through 2009. A slowing in the current economic recovery would likely result in an
increase in the number of restructured agreements.
Due to the risks mentioned above with respect to long-term supply contracts, we may not
achieve the revenue or profit we expect to achieve from these sales commitments.
The loss of, or significant reduction in, purchases by our largest customers could adversely
affect our revenues and profitability.
Our largest customer during 2009 accounted for approximately 12% of our total revenues. We
derived approximately 47% of our 2009 total revenues from sales to our ten largest customers. These
customers may not continue to purchase coal from us under our current coal supply agreements, or at
all. If these customers were to reduce their purchases of coal from us significantly or if we were
unable to sell coal to them on terms as favorable to us as the terms under our current agreements,
our revenues and profitability could suffer materially.
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A decline in demand for metallurgical coal would limit our ability to sell our high quality
steam coal as higher-priced metallurgical coal and could affect the economic viability of
certain of our mines that have higher operating costs.
Portions of our coal reserves possess quality characteristics that enable us to mine, process
and market them as either metallurgical coal or high quality steam coal, depending on the
prevailing conditions in the metallurgical and steam coal markets. We decide whether to mine,
process and market these coals as metallurgical or steam coal based on management’s assessment as
to which market is likely to provide us with a higher margin. We consider a number of factors when
making this assessment, including the difference between the current and anticipated future market
prices of steam coal and metallurgical coal, the lower volume of saleable tons that results from
producing a given quantity of reserves for sale in the metallurgical market instead of the steam
market, the increased costs incurred in producing coal for sale in the metallurgical market instead
of the steam market, the likelihood of being able to secure a longer-term sales commitment by
selling coal into the steam market and our contractual commitments to deliver different types of
coals to our customers. A decline in the metallurgical market relative to the steam market could
cause us to shift coal from the metallurgical market to the steam market, thereby reducing our
revenues and profitability.
Most of our metallurgical coal reserves possess quality characteristics that enable us to
mine, process and market them as high quality steam coal. However, some of our mines operate
profitably only if all or a portion of their production is sold as metallurgical coal to the steel
market. If demand for metallurgical coal declined to the point where all the production from
these mines had to be sold as steam coal, theses mines may not be economically viable and subject
to closure. Such closures would lead to asset impairment charges, accelerated reclamation costs, as
well as reduced revenue and profitability.
Disruption in supplies of coal produced by contractors and other third parties could
temporarily impair our ability to fill customers’ orders or increase our costs.
In addition to marketing coal that is produced by our subsidiaries’ employees, we utilize
contractors to operate some of our mines. Operational difficulties at contractor-operated mines,
changes in demand for contract miners from other coal producers, and other factors beyond our
control could affect the availability, pricing, and quality of coal produced for us by contractors.
The majority of the coal that we purchase from third parties is blended with coal produced from our
mines prior to resale, and we also process (which includes washing, crushing or blending coal at
one of our preparation plants or loading facilities) a portion of the coal that we purchase from
third parties prior to resale. We sold 1.5 million tons of coal purchased from third parties during
2009, representing approximately 3% of our total coal sales volume during 2009. Approximately 82%
of our purchased coal sales volume in 2009 was blended with coal produced from our mines prior to
resale, and approximately 1% of our total coal sales volume in 2009 consisted of coal purchased
from third parties that we processed before resale. The availability of specified qualities of this
purchased coal may decrease and prices may increase as a result of, among other things, changes in
overall coal supply and demand levels, consolidation in the coal industry and new laws or
regulations. Disruption in our supply of contractor-produced coal and purchased coal could
temporarily impair our ability to fill our customers’ orders or require us to pay higher prices in
order to obtain the required coal from other sources. Any increase in the prices we pay for
contractor-produced coal or purchased coal could increase our costs and therefore lower our
earnings. Although increases in market prices for coal generally benefit us by allowing us to sell
coal at higher prices, those increases also increase our costs to acquire purchased coal, which
lowers our earnings.
Our ability to collect payments from our customers could be impaired if their creditworthiness
deteriorates.
Our ability to receive payment for coal sold and delivered depends on the continued
creditworthiness of our customers. Our customer base is changing with deregulation as utilities
sell their power plants to their non-regulated affiliates or third parties that may be less
creditworthy, thereby increasing the risk we bear on payment default. These new power plant owners
may have credit ratings that are below investment grade. In addition, competition with other coal
suppliers could force us to extend credit to customers and on terms that could increase the risk we
bear on payment default.
We have contracts to supply coal to energy trading and brokering companies under which those
companies sell coal to end users. If the creditworthiness of the energy trading and brokering
companies declines, this would increase the risk that we may not be able to collect payment for all
coal sold and delivered to or on behalf of these energy trading and brokering companies.
Global financial markets experienced extreme disruption in late 2008 and early 2009, which,
among other things, severely limited liquidity and credit availability. Conditions improved
starting in the second quarter of 2009, and liquidity has become available in the bond markets and,
to a lesser extent, the term loan markets. Nevertheless, we continue to closely monitor economic
conditions and credit availability and the resulting impacts on our business and our suppliers and
customers. If the current economic recovery proves to be only temporary, the current economic
conditions worsens or a prolonged global, national or regional economic recession or other similar
events occur, it is likely to significantly impact the creditworthiness of our customers and could
increase the risk we bear on payment default.
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Fluctuations in transportation costs and the availability or reliability of transportation
could affect the demand for our coal or temporarily impair our ability to supply coal to our
customers.
Transportation costs represent a significant portion of the total cost of coal for our
customers. Increases in transportation costs could make coal a less competitive source of energy or
make our coal production less competitive than coal produced from other sources.
We depend upon railroads, trucks, beltlines, ocean vessels and barges to deliver coal to our
customers. Disruption of these transportation services due to weather-related problems, mechanical
difficulties, strikes, lockouts, bottlenecks, terrorist attacks, and other events could temporarily
impair our ability to supply coal to our customers, resulting in decreased shipments. For example,
in 2005 certain shipments of coal to our customers were delayed by hurricanes in the Gulf Coast and
by two derailments in the Powder River Basin. Decreased shipment performance levels over longer
periods of time could cause our customers to look to other sources for their coal needs, negatively
affecting our revenues and profitability.
In 2009, 75% of our produced and processed coal volume was transported from the load-out or
preparation plant to the customer by rail. From time to time in the past, we have experienced
deterioration in the reliability of the service provided by rail carriers, which increased our
internal coal handling costs. If there is future deterioration of the transportation services
provided by the railroad companies we use and we are unable to find alternative transportation
providers to ship our coal, our business could be adversely affected.
We have investments in mines, loading facilities, and ports that in most cases are serviced by
a single rail carrier. Our operations that are serviced by a single rail carrier are particularly
at risk to disruptions in the transportation services provided by that rail carrier, due to the
difficulty in arranging alternative transportation. If a single rail carrier servicing our
operations does not provide sufficient capacity, revenue
from these operations and our return on investment could be adversely impacted. In addition,
much of our eastern coal is transported from our mines to our loading facilities by trucks owned
and operated by third parties. An increase in transportation costs could have an adverse effect on our ability to increase
or to maintain production on a profit-making basis and could therefore adversely affect our
revenues and earnings.
Our mining operations consume significant quantities of commodities. If commodity prices
increase significantly or rapidly, it could impact our cost of production.
Coal mines consume large quantities of commodities such as steel, copper, rubber products and
liquid fuels, such as diesel fuel. Some commodities, such as steel, are needed to comply with roof
control plans required by regulation. The prices we pay for these products are strongly impacted by
the global commodities market. A rapid or significant increase in cost of some commodities could
impact our mining costs because we have limited ability to negotiate lower prices, and, in some
cases, do not have a ready substitute for these commodities.
Fair value of derivative instruments that are not accounted for as a hedge could cause
earnings volatility in our Statements of Operations for a given period.
Derivative financial instruments are recognized as either assets or liabilities in the
Consolidated Balance Sheets and measured at fair value. Changes in fair value are recognized either
in earnings or equity, depending on whether the transaction qualifies for cash flow hedge
accounting, and if so, how effective the derivatives are at offsetting price movements in the
underlying exposure. We account for certain of our coal forward purchase and sales agreements that
do not qualify for the “normal purchase and normal sales” exception available under existing
accounting rules as derivative instruments. We use significant quantities of diesel fuel and
explosives in our operations and enter into commodity swap and option agreements for a portion of
our diesel fuel and explosive needs to reduce the risk that changes in the market price of diesel
fuel and explosives can have on our operations. A portion of our commodity swap agreements have not
been designated as qualifying cash flow hedges and therefore, we are required to record changes in
fair value of these derivative instruments in our Consolidated Statements of Operations. We also
have outstanding debt that includes a variable interest rate component. We entered into an
interest rate swap to reduce the risk that changing interest rates could have on our operations.
The swap initially qualified for cash flow hedge accounting and changes in fair value were recorded
as a component of equity; however, the debt instrument was subsequently paid and the swap no longer
qualified for cash flow hedge accounting. The amounts that were previously recorded in equity of
$17.7 million were recognized in our Consolidated Statements of Operations in 2009. Subsequent
changes in fair value of the interest rate swap will be recorded in earnings. During 2009 and 2008,
we recorded a $3.6 million gain and a $47.3 million loss, respectively, related to changes in the
fair value of our derivative instruments.
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Our business will be adversely affected if we are unable to develop or acquire additional coal
reserves that are economically recoverable.
Our profitability depends substantially on our ability to mine coal reserves possessing
quality characteristics desired by our customers in a cost-effective manner. As of December 31,
2009, we owned or leased 2,291.0 million tons of proven and probable coal reserves that we believe
will support current production levels for more than 20 years. We have not yet applied for the
permits required, or developed the mines necessary, to mine all of our reserves. Permits are
becoming increasingly more difficult and expensive to obtain and the review process continues to
lengthen. In addition, we may not be able to mine all of our reserves as profitably as we do at our
current operations.
Because our reserves are depleted as we mine our coal, our future success and growth depend,
in part, upon our ability to acquire additional coal reserves that are economically recoverable. If
we are unable to replace or increase our coal reserves on acceptable terms, our production and
revenues will decline as our reserves are depleted. Exhaustion of reserves at particular mines also
may have an adverse effect on our operating results that is disproportionate to the percentage of
overall production represented by such mines. Our ability to acquire additional coal reserves
through acquisitions in the future also could be limited by restrictions under our existing or
future debt agreements, competition from other coal companies for attractive properties, or the
lack of suitable acquisition candidates.
Because our profitability is substantially dependent on the availability of an adequate supply
of coal reserves that can be mined at competitive costs, the unavailability of these types of
reserves would cause our profitability to decline.
We have not yet applied for all of the permits required, or developed the mines necessary, to
use all of our reserves. Furthermore, we may not be able to mine all of our reserves as profitably
as we do at our current operations. Our planned development projects and acquisition activities may
not result in significant additional reserves and we may not have continuing success developing new
mines or expanding existing mines beyond our existing reserves. Most of our mining operations are
conducted on properties owned or leased by us. Because title to most of our leased properties and
mineral rights is not thoroughly verified until a permit to mine the property is obtained, our
right to mine some of our reserves may be materially adversely affected if defects in title or
boundaries exist. In addition, in order to develop our reserves, we must receive various
governmental permits. We may be unable to obtain the permits necessary for us to operate profitably
in the future. Some of these permits are becoming increasingly more difficult and expensive to
obtain and the review process continues to lengthen.
Our profitability depends substantially on our ability to mine coal reserves that have the
geological characteristics that enable them to be mined at competitive costs and to meet the
quality needed by our customers. Replacement reserves may not be available when required or, if
available, may not be capable of being mined at costs comparable to those characteristic of the
depleting mines. We may not be able to accurately assess the geological characteristics of any
reserves that we now own or subsequently acquire, which may adversely affect our profitability and
financial condition. Exhaustion of reserves at particular mines also may have an adverse effect on
our operating results that is disproportionate to the percentage of overall production represented
by such mines. Our ability to obtain other reserves through acquisitions in the future could be
limited by restrictions under our existing or future debt agreements, competition from other coal
companies for attractive properties, the lack of suitable acquisition candidates or the inability
to acquire coal properties on commercially reasonable terms.
Demand for our coal changes seasonally and could have an adverse effect on the timing of our
cash flows and our ability to service our existing and future indebtedness.
Our business is seasonal, with operating results varying from quarter to quarter. We have
historically experienced lower sales during winter months primarily due to the freezing of lakes
that we use to transport coal to some of our customers. As a result, our first quarter results may
be negatively impacted. Lower than expected sales by us during this period could have an adverse
affect on the timing of our cash flows and therefore our ability to service our obligations with
respect to our existing and future indebtedness.
Failure to obtain or renew surety bonds on acceptable terms could affect our ability to secure
reclamation and coal lease obligations, which could adversely affect our ability to mine or
lease coal.
Federal and state laws require us to obtain surety bonds to secure payment of certain
long-term obligations such as mine closure or reclamation costs, federal and state workers’
compensation costs, coal leases and other obligations. These bonds are typically renewable
annually. Surety bond issuers and holders may not continue to renew the bonds or may demand
additional collateral or other less favorable terms upon those renewals. Our failure to maintain,
or our inability to acquire, surety bonds that are required by state and federal law would affect
our ability to secure reclamation and coal lease obligations, which could adversely affect our
ability to mine or lease coal. That failure could result from a variety of factors including,
without limitation:
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In addition, due to the current instability and volatility of the financial markets, our
current surety bond providers may experience difficulties in providing new surety bonds to us,
maintaining existing surety bonds, or satisfying liquidity requirements under existing surety bond
contracts. In that event, we would be required to find alternative sources of funding to satisfy
our payment obligations, which may require greater use of our credit facility.
We have reclamation and mine closure obligations. If the assumptions underlying our accruals
are inaccurate, we could be required to expend greater amounts than anticipated.
The Surface Mining Control and Reclamation Act (“SMCRA”) establishes operational, reclamation
and closure standards for all aspects of surface mining as well as deep mining. We accrue for the
costs of current mine disturbance and final mine closure, including the cost of treating mine water
discharge where necessary. Estimates of our total reclamation and mine-closing liabilities are
based upon permit requirements and our experience. The amounts recorded are dependent upon a number
of variables, including the estimated future retirement costs, estimated proven reserves,
assumptions involving profit margins, inflation rates, discount rates and the assumed
credit-adjusted risk-free interest rates. Furthermore, these obligations are unfunded. If these
accruals are insufficient or our liability in a particular year is greater than currently
anticipated, our future operating results could be adversely affected.
Defects in title in our mine properties could limit our ability to recover coal from these
properties or result in significant unanticipated costs.
We conduct a significant part of our mining operations on properties that we lease. Title to
most of our leased properties and mineral rights is not thoroughly verified until a permit to mine
the property is obtained, and in some cases title with respect to leased properties is not verified
at all. Our right to mine some of our reserves may be materially adversely affected by actual or
alleged defects in title or boundaries. In order to obtain leases or mining contracts to conduct
our mining operations on property where these defects exist, we may in the future have to incur
unanticipated costs or could even lose our right to mine on that property, which could adversely
affect our profitability.
Expenditures for benefits for non-active employees could be materially higher than we have
anticipated, which could increase our costs and adversely affect our financial results.
We are responsible for certain long-term liabilities under a variety of benefit plans and
other arrangements with active and inactive employees. The unfunded status (the excess of projected
benefit obligation over plan assets) of these obligations as of December 31, 2009, as reflected in
Note 16 to our Consolidated Financial Statements, included $614.4 million of postretirement
obligations, $95.9 million of defined benefit pension and supplemental employee retirement plan
obligations, $43.9 million of workers’ compensation obligations and $30.3 million of self-insured
black lung obligations. These obligations have been estimated based on assumptions including
actuarial estimates, discount rates, estimates of mine lives, expected returns on pension plan
assets and changes in health care costs. We could be required to expend greater amounts than
anticipated. In addition, future regulatory and accounting changes relating to these benefits could
result in increased obligations or additional costs, which could also have a material adverse
affect on our financial results. Several states in which we operate consider changes in workers’
compensation laws from time to time, which, if enacted, could adversely affect us.
Our indebtedness could harm our business by limiting our available cash and our access to
additional capital and could force us to sell material assets or take other actions to attempt
to reduce our indebtedness.
At December 31, 2009, we had $870.5 million of indebtedness outstanding before discounts
applied for financial reporting, representing 25% of our total capitalization. This indebtedness
consisted of $287.5 million principal of our convertible notes, $298.3 million
principal of our 7.25% senior notes and a $284.8 million term loan under our credit facility. In
addition, at December 31, 2009, we had $113.6 million of letters of credit outstanding under our
credit facility and $143.5 million of letters of credit outstanding under our accounts receivable
securitization facility.
This level of indebtedness could have important consequences to our business. For example, it
could:
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If our cash flows and capital resources are insufficient to fund our debt service obligations
or our requirements under our other long-term liabilities, we may be forced to sell assets, seek
additional capital or seek to restructure or refinance our indebtedness. These alternative measures
may not be successful and may not permit us to meet our scheduled debt service obligations or our
requirements under our other long term liabilities. In the absence of sufficient cash flows and
resources, we could face substantial liquidity problems and might be required to sell material
assets or operations to attempt to meet our debt service and other obligations. Our credit facility
restricts our ability to sell assets and use the proceeds from the sales. We may not be able to
consummate any such sales or to obtain the proceeds which we could realize from them and these
proceeds may not be adequate to meet any debt service obligations then due. Furthermore,
substantially all of our material assets secure our indebtedness under our credit facility.
We may also be able to incur substantially more debt which could further exacerbate the risks
associated with our significant indebtedness.
We may be able to incur substantial additional indebtedness in the future under the terms of
our credit facility and the indentures governing our 7.25% senior notes and our convertible
notes. Our credit facility provides for a revolving line of credit of up to $650.0 million,
of which $536.4 million was available as of December 31, 2009. The addition of new debt to our
current debt levels could increase the related risks that we now face. For example, the spread over
the variable interest rate applicable to loans under our revolving line of credit is dependent on
our leverage ratio, and it would increase if our leverage ratio increases. Additional drawings
under our revolving line of credit could also limit the amount available for letters of credit in
support of our bonding obligations, which we will require as we develop and acquire new mines.
The terms of our credit facility and the indenture governing our 7.25% senior notes limit our
and our subsidiaries’ ability to take certain actions, which may limit our operating and
financial flexibility and adversely affect our business.
Our credit facility and the indenture governing our 7.25% senior notes contain a number of
significant restrictions and covenants that limit our ability and our subsidiaries’ ability to,
among other things, incur additional indebtedness, enter into sale and leaseback transactions, pay
dividends, make redemptions and repurchases of certain capital stock, make loans and investments,
create liens, engage in transactions with affiliates, and merge or consolidate with other companies
or sell substantially all of our assets. These covenants could adversely affect our
ability to finance our future operations or capital needs or to execute preferred business
strategies. In addition, complying with these covenants may make it more difficult for us to
successfully execute our business strategy and compete against companies who are not subject to
such restrictions.
Operating results below current levels or other adverse factors, including a significant
increase in interest rates, could result in our being unable to comply with our covenants and
payment obligations contained in our credit facility and the indentures governing our 7.25% senior
notes and 2.375% convertible senior notes. If we violate these covenants or obligations under any
of these agreements and are unable to obtain waivers from our lenders, our debt under all of these
agreements would be in default and could be accelerated by our lenders. If our indebtedness is
accelerated, we may not be able to repay our debt or borrow sufficient funds to refinance it. Even
if we were able to obtain new financing, it may not be on commercially reasonable terms, on terms
that are acceptable to us, or at all. If our debt is in default for any reason, our business,
financial condition and results of operations could be materially and adversely affected.
Failure to maintain capacity for required letters of credit could limit our available
borrowing capacity under our credit facility, limit our ability to provide financial assurance
for self-insured obligations and negatively impact our ability to obtain additional financing
to fund future working capital, capital expenditure or other general corporate requirements.
At December 31, 2009, we had $257.1 million of letters of credit in place, of which $113.6
million was outstanding under our credit facility and $143.5 million was outstanding under our
accounts receivable securitization facility. These outstanding
letters of credit supported workers’ compensation bonds, coal mining reclamation obligations, UMWA retiree health care
obligations, and other miscellaneous obligations. Our credit facility provides for revolving
commitments of up to $650.0 million, up to $500.0 million of which can be used to issue letters of
credit, and our accounts receivable securitization facility provides for the issuance of up to
$150.0 million in letters of credit. Obligations secured by letters of credit may increase in the
future. Any such increase would limit our available borrowing capacity under our current or future
credit facilities and could negatively impact our ability to obtain additional financing to fund
future working capital, capital expenditure or other general corporate requirements. Moreover, if
we do not maintain sufficient borrowing capacity under our revolving credit facility and accounts
receivable securitization facility for additional letters of credit, we may be unable to provide
financial assurance for our mining operations.
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Certain terms of our convertible notes may adversely impact our liquidity.
Upon conversion of our convertible notes, we will be required to pay in cash the
lesser of the principal amount of the converted notes and the sum of a calculated daily conversion
value over an averaging period. As a result, the conversion of the convertible notes
may significantly reduce our liquidity.
The inability of the sellers of the companies that we have acquired to fulfill their
indemnification obligations to us under our acquisition agreements could increase our
liabilities and adversely affect our results of operations and financial position.
In the acquisition agreements entered into with the sellers of the companies that we have
acquired, including the acquisition agreements entered into related to the Coastal Coal Company,
Nicewonder and Progress acquisitions, the respective sellers and, in some of the acquisitions,
their parent companies, agreed to retain responsibility for and indemnify Old Alpha against damages
resulting from certain third-party claims or other liabilities, such as workers’ compensation
liabilities, black lung liabilities, postretirement medical liabilities and certain environmental
or mine safety liabilities. The failure of any seller and, if applicable, its parent company, to
satisfy their obligations with respect to claims and retained liabilities covered by the
acquisition agreements could have an adverse effect on our results of operations and financial
position if claimants successfully assert that we are liable for those claims and/or retained
liabilities. The obligations of the sellers and, in some instances, their parent companies, to
indemnify us with respect to their retained liabilities will continue for a substantial period of
time, and in some cases indefinitely. The sellers’ indemnification obligations with respect to
breaches of their representations and warranties in the acquisition agreements will terminate upon
expiration of the applicable indemnification period (generally 18-24 months from the acquisition
date for most representations and warranties, and from two to five years from the acquisition date
for environmental representations and warranties), are subject to deductible amounts and will not
cover damages in excess of the applicable coverage limit. The assertion of third-party claims after
the expiration of the applicable indemnification period or in excess of the applicable coverage
limit, or the failure of any seller to satisfy its indemnification obligations with respect to
breaches of its representations and warranties, could have an adverse effect on our results of
operations and financial position.
Our inability to continue or expand the Nicewonder existing road construction and coal
recovery business could adversely affect the expected benefits from the Nicewonder
acquisition.
Our subsidiary, Nicewonder Contracting, Inc. (“NCI”), operates a road construction business
under a contract with the State of West Virginia. Pursuant to the contract, NCI is building
approximately 11 miles of rough grade highway in West Virginia over the next one to two years and,
in exchange, NCI will be compensated by West Virginia based on the number of cubic yards of
material excavated or filled to create a road bed, as well as for certain other cost components. In
the course of the road construction, NCI will recover any coal encountered and sell the coal to its
customers, subject to certain costs, including coal loading, transportation, coal royalty payments
and applicable taxes and fees.
The State of West Virginia has only approved funding for a portion of this road construction.
If West Virginia does not fund the remaining sections of the highway project, it would adversely
affect NCI’s earnings. Even if West Virginia funds the remainder of this project through the next
one to two years, we are uncertain whether the state will fund any similar projects in the future.
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If we are unable to accurately estimate the overall risks or costs when we bid on a road
construction contract that is ultimately awarded to us, we may achieve a lower than
anticipated profit or incur a loss on the contract.
A large percentage of our road construction revenues and contract backlog is typically derived
from fixed unit price contracts. Fixed unit price contracts require us to perform the contract for
a fixed unit price irrespective of our actual costs. As a result, we realize a profit on these
contracts only if we successfully estimate our costs and then successfully control actual costs and
avoid cost overruns. If our cost estimates for a contract are inaccurate, or if we do not execute
the contract within our cost estimates, then cost overruns may cause us to incur losses or cause
the contract not to be as profitable as we expected. Also, if we do not recover the amounts of
coal estimated on our construction projects, profitability on our construction contracts could be
less than projected. This, in turn, could negatively affect our cash flow, earnings and financial
position.
The costs incurred and gross profit realized on those contracts can vary, sometimes
substantially, from the original projections due to a variety of factors, including, but not
limited to:
Sales of additional shares of our common stock, the exercise or granting of additional equity
securities or conversion of our convertible notes could cause the price of our common stock to
decline.
Sales of substantial amounts of our common stock in the open market and the availability of
those shares for sale could adversely affect the price of our common stock. In addition, future
issuances of equity securities, including pursuant to outstanding options or the conversion of our
convertible bonds, could dilute the interests of our existing stockholders and could cause the
market price for our common stock to decline. We may issue equity securities in the future for a
number of reasons, including to finance our operations and business strategy, to adjust our ratio
of debt to equity, to satisfy our obligations upon the exercise of outstanding warrants or options
or for other reasons.
As of December 31, 2009, there were:
The price of our common stock could also be affected by hedging or arbitrage trading activity
that may exist or develop involving our common stock and our convertible notes.
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Ongoing instability and volatility in the worldwide financial markets have created
uncertainty, which could adversely affect our business and the price of our common shares.
As widely reported, financial markets in the United States, Europe and Asia experienced
extreme disruption in late 2008 and the first half of 2009 including, among other things, extreme
volatility in security prices, severely diminished liquidity and credit availability, rating
downgrades of certain investments and declining valuations of others, including real estate. The
tightening of credit in financial markets adversely affected our customers’ ability to obtain
financing for operations and resulted in a temporary decrease in demand, the cancellation of some
orders for our coal products and the restructuring of agreements with certain of our coal
customers. Beginning in the second half of 2009, economic conditions started to improve and most
economies are now regarded as recovering from a deep recession. Reversal of the current economic
recovery, a prolonged global, national or regional economic recession or other similar events could
have a material adverse effect on the demand for coal and on our sales, margins, and profitability.
During this recent period of intense market disruption, the market price for our common shares
declined substantially. We continue to monitor economic developments and the resulting impact on
our business and other suppliers and customers closely. However, we are unable to predict the
timing, duration and severity of potential future disruptions in financial markets and potential
future adverse economic conditions in the U.S. and other countries and the impact these events may
have on our operations and the industry in general.
We do not intend to pay cash dividends on our common stock in the foreseeable future.
We have never declared or paid a cash dividend, and our Board of Directors periodically
evaluates commencing a dividend policy. If we were to decide in the future to pay dividends, our
ability to do so would be dependent on the ability of our subsidiaries to make cash available to
us, by dividend, debt repayment or otherwise. Our ability to pay
dividends is limited by restrictions in our credit facility.
Terrorist attacks and threats, escalation of military activity in response to such attacks or
acts of war may negatively affect our business, financial condition and results of operations.
Terrorist attacks and threats, escalation of military activity in response to such attacks or
acts of war may negatively affect our business, financial condition, and results of operations. Our
business is affected by general economic conditions, fluctuations in consumer confidence and
spending, and market liquidity, which can decline as a result of numerous factors outside of our
control, such as terrorist attacks and acts of war. Future terrorist attacks against U.S. targets,
rumors or threats of war, actual conflicts involving the United States or its allies, or military
or trade disruptions affecting our customers may materially adversely affect our operations and
those of our customers. As a result, there could be delays or losses in transportation and
deliveries of coal to our customers, decreased sales of our coal and extension of time for payment
of accounts receivable from our customers. Strategic targets such as energy-related assets may be
at greater risk of future terrorist attacks than other targets in the United States. In addition,
disruption or significant increases in energy prices could result in government-imposed price
controls. It is possible that any of these occurrences, or a combination of them, could have a
material adverse effect on our business, financial condition and results of operations.
Provisions
in our certificate of incorporation and bylaws and the indentures for our
convertible notes and our 7.25% senior notes may discourage a takeover attempt even if doing so might be beneficial to
our stockholders.
Provisions contained in our certificate of incorporation and bylaws could impose impediments
to the ability of a third party to acquire us even if a change of control would be beneficial to
our stockholders. Provisions of our certificate of incorporation and bylaws impose various
procedural and other requirements, which could make it more difficult for stockholders to effect
certain corporate actions. For example, our certificate of incorporation authorizes our board of
directors to determine the rights, preferences, privileges and restrictions of unissued series of
preferred stock, without any vote or action by our stockholders. Thus, our board of directors can
authorize and issue shares of preferred stock with voting or conversion rights that could adversely
affect the voting or other rights of holders of our common stock. These provisions may have the
effect of delaying or deterring a change of control of our Company, and could limit the price that
certain investors might be willing to pay in the future for shares of our common stock.
If a “fundamental change” (as defined in the indenture for our convertible notes) occurs,
holders of the convertible notes will have the right, at their option, either to convert their
convertible notes or require us to repurchase all or a portion of their convertible notes. In the
event of a “make-whole fundamental change” (as defined in the indenture for the convertible notes),
we also may be required to increase the conversion rate applicable to any convertible notes
surrendered for conversion. If a “change in control” (as defined in
the indenture for the 7.25% senior notes) occurs, holders of the 7.25% senior notes will have the right to require us to
repurchase all or a portion of their 7.25% senior notes. In addition,
each indenture prohibits us from
engaging in certain mergers or acquisitions unless, among other things, the surviving entity is a
U.S. entity that assumes our obligations under the applicable notes. Our credit facility imposes
similar restrictions on us, including with respect to mergers or consolidations with other
companies and the sale of substantially all of our assets. These provisions could prevent or deter
a third party from acquiring us even where the acquisition could be beneficial to our stockholders.
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None.
Coal Reserves
We periodically retain outside experts to independently verify our estimates of our coal
reserves. “Reserves” are defined by the Securities and Exchange Commission (“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. “Proven (Measured) Reserves” are defined by SEC Industry
Guide 7 as reserves for which (1) 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 (2) 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. “Probable reserves” are defined by 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, as well as third party consultants retained by us. We periodically update our reserve
estimates to reflect past coal production, new drilling information and other geological or mining
data, and acquisitions or sales of coal properties. Coal tonnages are categorized according to coal
quality, mining method, permit status, mineability and location relative to existing mines and
infrastructure. 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.
Prior to Old Alpha’s initial public offering in 2005, a third party consultant was retained to
perform reserve estimates in November 2004. Since November 2004, a third party consultant has been
retained to verify reserves for our major acquisitions, which include the Callaway, Progress Fuels,
Mingo Logan Ben’s Creek Complex, and Foundation acquisitions, as well as to conduct ongoing reserve
updates, on an annual basis, for specific properties that have undergone substantial modification
to the reserve base. Properties that have undergone insignificant or no changes since the original
assessment in November 2004 have been carried forward without re-evaluation. These reviews include
the preparation of reserve maps and the development of estimates by certified professional
geologists based on data supplied by us and using standards accepted by government and industry,
including the methodology outlined in U.S. Circular 891. Reserve estimates were developed using
criteria to assure that the basic geologic characteristics of the reserve (such as minimum coal
thickness and wash recovery, interval between deep mineable seams and mineable area tonnage for
economic extraction) were in reasonable conformity with existing and recently completed operation
capabilities on our properties.
We estimate that, as of December 31, 2009, we owned or leased total proven and probable coal
reserves of approximately 2,291.0 million tons. We believe that we have sufficient reserves to
replace capacity from depleting mines for the foreseeable future and that our current reserves are
one of our strengths. We believe that the current level of production at our major mines is
sustainable for the foreseeable future.
Of the 2,291.0 million tons, approximately 1,268.6 million tons are assigned reserves that we
expect to be mined in future operations. Approximately 1,048.5 million tons are unassigned reserves
that we are holding for future development. All of our reserves in Wyoming are assigned. We have
unassigned reserves in Pennsylvania, West Virginia, and Virginia/Kentucky of 622.8 million tons,
235.1 million tons, and 164.5 million tons, respectively.
Approximately 63% of our reserves are classified as high Btu coal (coal delivered with an
average heat value of 12,500 Btu per pound or greater) and are located in Pennsylvania, West
Virginia, and Virginia/Kentucky. Approximately 64% of our reserves are classified as compliance
coal which meets the 1.2 lb SO 2 /mm Btu standard of Phase II of the Clean Air Act. Our compliance
coal reserves are located in Pennsylvania, Wyoming, West Virginia, and Virginia/Kentucky.
As with most coal-producing companies that operate in Appalachia, which include our operations
in Pennsylvania, West Virginia, and Virginia/Kentucky, the great majority of our Appalachian
reserves are subject to leases from third-party landowners. These leases convey mining rights to
the coal producer in exchange for a percentage of gross sales in the form of a royalty payment to
the lessor, subject to minimum payments. Of our Appalachian reserve holdings at December 31, 2009,
415.1 million tons of reserves are owned and require no royalty or per-ton payment to other
parties. Our remaining Appalachian reserve holdings at December 31, 2009, of 1,166.6 million tons
are leased and require minimum royalty and/or per-ton payments.
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Our mines in Wyoming are subject to federal coal leases that are administered by the U.S.
Department of Interior under the Federal Coal Leasing Amendment Act of 1976. Each lease requires
diligent development of the lease within ten years of the lease award with a required coal
extraction of 1.0% of the reserves within that 10-year period. At the end of the 10-year
development period, the mines are required to maintain continuous operations, as defined in the
applicable leasing regulations. All of our federal leases are in full compliance with these
regulations. We pay to the federal government an annual rent of $3.00 per acre and production
royalties of 12.5% of gross proceeds on surface mined coal. Effective October 1, 2008, the Federal
Government remits 48% of royalties, rentals and any lease bonus payments to the state of Wyoming.
Of our Wyoming reserve holdings at December 31, 2009, 24.2 million tons of reserves are owned and
require no royalty or per-ton payments. Our remaining Wyoming reserve holdings at December 31,
2009, of 685.1 million tons are leased and are subject to the terms described above.
Our idled mine in Illinois is subject to coal leases and requires payments of minimum
royalties, payable in periodic installments. We expect to continue leasing these reserves until
future development is feasible. Our reserve holdings attributable to our idled Illinois mine at
December 31, 2009 are 26.1 million tons.
Although our coal leases have varying renewal terms and conditions, they generally last for
the economic life of the reserves. According to our current mine plans, any leased reserves
assigned to a currently active operation will be mined during the tenure of the applicable lease.
Because the great majority of our leased or owned properties and mineral rights are covered by
detailed title abstracts prepared when the respective properties were acquired by predecessors in
title to us and our current lessors, we generally do not thoroughly verify title to, or maintain
title insurance policies on, our leased or owned properties and mineral rights.
The following table provides the “quality” (sulfur content and average Btu content per pound)
of our proven and probable coal reserves as of December 31, 2009.
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The following table summarizes, by regional business unit, the tonnage of our coal reserves
that is assigned to our operating mines, our property interest in those reserves and whether the
reserves consist of steam or metallurgical coal, as of December 31, 2009.
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The
following map shows the locations of Alpha’s properties as of December 31, 2009:
Alpha Business Unit Structure
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The
following map shows the locations of Alpha’s shipping points as of December 31,
2009:
See Item 1, “Business”, for additional information regarding our coal operations and
properties.
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Item 3. Legal Proceedings
We are a party to a number of legal proceedings incident to our normal business activities.
While we cannot predict the outcome of these proceedings, we do not believe that any liability
arising from these matters individually or in the aggregate should have a material impact upon our
consolidated cash flows, results of operations or financial condition.
Nicewonder Litigation
In December 2004, prior to Old Alpha’s Nicewonder acquisition in October 2005, the Affiliated
Construction Trades Foundation brought an action against the West Virginia Department of
Transportation, Division of Highways (“WVDOH”) and Nicewonder Contracting, Inc. (“NCI”), which
became our wholly-owned indirect subsidiary as a result of the Nicewonder acquisition, in the
United States District Court in the Southern District of West Virginia. The plaintiff sought a
declaration that the contract between NCI and the State of West Virginia related to NCI’s road
construction project was illegal as a violation of applicable West Virginia and federal competitive
bidding and prevailing wage laws. The plaintiff also sought an injunction prohibiting performance
of the contract but has not sought monetary damages.
In September 2007, the Court ruled that the WVDOH and the Federal Highway Administration
(which is now a party to the suit) could not, under the circumstances of this case, enter into a
contract that did not require the contractor to pay the prevailing wages as required by the
Davis-Bacon Act. In anticipation of a potential Court directive that the contract be renegotiated
for such payment, for which the WVDOH had committed to reimburse NCI, we recorded a $9.0 million
long-term liability for the potential obligations under the ruling and an offsetting $9.0 million
long-term receivable for the recovery of these costs from the WVDOH.
On September 30, 2009, the Court issued an order that dismissed or denied for lack of standing
all of the plaintiff’s claims under federal law and remanded the remaining state claims to circuit
court in Kanawha County, WV for resolution. The Court also vacated portions of its September 2007
order, and held that the plaintiff lacked standing to pursue the Davis-Bacon Act claim and further
concluded that no private right of action exists to challenge the absence of a provision in a
contract for highway construction requiring payment of prevailing wages established by the
Davis-Bacon Act. As a result of the September 30, 2009 ruling, our previously established long-term
liability and offsetting long-term receivable of $9.0 million have been reversed.
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PART II
The initial public offering of Old Alpha’s common stock occurred on February 15, 2005, and its
common stock was then listed on the New York Stock Exchange under the symbol “ANR.” There was no
public market for the common stock of Old Alpha prior to this date. On July 31, 2009, after the
Merger, the common stock of Foundation, the surviving company of the Merger, which was renamed
Alpha Natural Resources, Inc., replaced the common stock of Old Alpha on the New York Stock
Exchange listing under the symbol “ANR,” and the Company’s common stock has since continued to
trade under the symbol “ANR.”
Price range of our common stock
The following table sets forth, for the periods indicated, the high and low sales prices per
share of our common stock reported in the New York Stock Exchange consolidated tape.
As of December 31, 2009, there were 2,279 registered holders of record of our
common stock, including 189 unvested restricted stock positions. The transfer agent and registrar
for our common stock is Computershare Trust Company, N.A.
Dividend Policy
We do not presently pay dividends on our common stock. Our Board of Directors periodically
evaluates the initiation of dividends.
Stock Performance Graph
We are comparing our stock performance to the S&P 500 Index (instead of the Russell 3000 Index as in Old Alpha’s Annual
Report on Form 10-K for the year ended December 31, 2008) because due to the Merger we believe that companies included
the S&P 500 Index have a comparable market capitalization to Alpha.
The following stock performance graph compares the cumulative total return to stockholders on
an annual basis on our common stock with the cumulative total return to stockholders on an annual
basis on two indices, the S&P 500 Index and the Russell 3000 Coal Index. In addition, the stock
performance graph includes the date of the Merger.
The graph assumes that:
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You are cautioned against drawing any conclusions from the data contained in this graph, as
past results are not necessarily indicative of future performance. The indices used are included
for comparative purposes only and do not indicate an opinion of management that such indices are
necessarily an appropriate measure of the relative performance of our stock.
COMPARISON
OF 5 YEAR CUMULATIVE TOTAL RETURN*
Among Alpha Natural Resources, Inc, The S&P 500 Index And The Russell 3000 Coal Index 
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The following table presents selected financial and other data for the most recent five fiscal
periods. The selected financial data as of December 31, 2009 and 2008, and for the years ended
December 31, 2009, 2008 and 2007 have been derived from the audited Consolidated Financial
Statements and related Notes thereto of Alpha Natural Resources, Inc. and subsidiaries included in
this Annual Report on Form 10-K. You should read the following table in conjunction with the
Consolidated Financial Statements and related Notes thereto included elsewhere in this Annual
Report on Form 10-K and “Management’s Discussion and Analysis of Financial Condition and Results of
Operations”.
On July 31, 2009, Alpha Natural Resources, Inc. (“Old Alpha”) and Foundation Coal Holdings,
Inc. (“Foundation”) merged (the “Merger”) with Foundation continuing as the surviving legal
corporation of the Merger which was renamed Alpha Natural Resources, Inc. (“Alpha”). For financial
accounting purposes, the Merger was treated as a “reverse acquisition” and Old Alpha was treated as
the accounting acquirer. Accordingly, Old Alpha’s financial statements became the financial
statements of Alpha and Alpha’s periodic filings subsequent to the Merger reflect Old Alpha’s
historical financial condition and results of operations shown for comparative purposes. Old
Alpha’s financial position as of December 31, 2008 and its results of operations for the years
ended December 31, 2008, 2007, 2006 and 2005 do not include financial results for Foundation. For
the year ended December 31, 2009, Foundation’s financial results are included for the five month
period from August 1, 2009 through December 31, 2009.
The results of operations for the historical periods included in the following table are not
necessarily indicative of the results to be expected for future periods. In addition, see Item 1A
“Risk Factors” of this report for a discussion of risk factors that could impact our future results
of operations.
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EBITDA from continuing operations attributable to Alpha Natural Resources, Inc. and EBITDA
from continuing operations attributable to Alpha Natural Resources, Inc., as adjusted, are
calculated as follows (unaudited, in thousands):
The numerator for purposes of computing basic and diluted net income (loss) per share, as adjusted, includes
the reported net income (loss) and a pro forma adjustment for income taxes to reflect the pro forma income taxes for
ANR Fund IX Holdings, L.P.’s portion of reported pre-tax income (loss), which would have been recorded if the issuance
of the shares of common stock received by the ANR Fund IX Holdings, L.P. and Alpha NR Holding, Inc. (“FR Affiliates”)
in exchange for their ownership in ANR Holdings in connection with the Internal Restructuring (the “Internal Restructuring”)
had occurred as of January 1, 2004. For purposes of the computation of basic and diluted net income (loss) per share, as adjusted,
the pro forma adjustment for income taxes only applies to the percentage interest owned by ANR Fund IX Holding, L.P., the
non-taxable FR Affiliate. No pro forma adjustment for income taxes is required for the percentage interest owned by Alpha NR
Holding, Inc., the taxable FR Affiliate, because income taxes have already been recorded in the historical results of operations.
Furthermore, no pro forma adjustment to reported net income (loss) is necessary subsequent to February 11, 2005 because we are subject to income taxes.
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The denominator for purposes of computing basic net income (loss) per share, as adjusted,
reflects the retroactive impact of the common shares received by the FR Affiliates in exchange for
their ownership in ANR Holdings in connection with the Internal Restructuring on a
weighted-average outstanding share basis as being outstanding as of January 1, 2004. The common
shares issued to the minority interest owners of ANR Holdings in connection with the Internal
Restructuring, including the immediately vested shares granted to management, have been reflected
as being outstanding as of February 11, 2005 for purposes of computing the basic net income (loss)
per share, as adjusted. The unvested shares granted to management on February 11, 2005 that vest
monthly over the two-year period from January 1, 2005 to December 31, 2006 are included in the
basic net income (loss) per share, as adjusted, computation as they vest on a weighted-average
outstanding share basis starting on February 11, 2005. The 33,925,000 new shares issued in
connection with the initial public offering have been reflected as being outstanding since
February 14, 2005, the date of the initial public offering, for purposes of computing the basic
net income (loss) per share, as adjusted.
The unvested shares issued to management are considered options for purposes of computing
diluted net income (loss) per share, as adjusted. Therefore, for diluted purposes, all remaining
unvested shares granted to management are added to the denominator subsequent to February 11, 2005
using the treasury stock method, if the effect is dilutive. In addition, the treasury stock method
is used for outstanding stock options, if dilutive, beginning with the November 10, 2004 grant of
options to management to purchase units in ACM that were automatically converted into options to
purchase up to 596,985 shares of Alpha Natural Resources, Inc. common stock at an exercise price
of $12.73 per share.
The computation of basic and diluted net income per share, as adjusted for 2005 is set forth
below:
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Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following discussion and analysis should be read in conjunction with our Consolidated
Financial Statements and related Notes thereto included elsewhere in this Annual Report on Form
10-K.
Explanatory Note
On July 31, 2009, Alpha Natural Resources, Inc. (“Old Alpha”) and Foundation Coal Holdings,
Inc. (“Foundation”) merged (the “Merger”) with Foundation continuing as the surviving legal
corporation of the Merger which was renamed Alpha Natural Resources, Inc. (“Alpha”). For accounting
purposes, the Merger is treated as a “reverse acquisition” with Old Alpha considered the accounting
acquirer. Accordingly, Old Alpha’s historical financial statements are included in periodic filings
of Alpha subsequent to the Merger. The results of operations and cash flows for the year ended
December 31, 2009 include the results of operations from Old Alpha for the period January 1, 2009
to July 31, 2009 and include the results of operations of the combined company for the five month
period August 1, 2009 to December 31, 2009.
Unless we have indicated otherwise, or the context otherwise requires, references in this
report to “Alpha,” “we,” “us” and “our” or similar terms are to Alpha and its consolidated
subsidiaries in reference to dates subsequent to the Merger and to Old Alpha and its consolidated
subsidiaries in reference to dates prior to the Merger.
Overview
We are one of America’s premier coal suppliers, ranked third largest among publicly-traded
U.S. coal producers as measured by combined Old Alpha and Foundation 2009 and 2008 pro forma
revenues of $3.4 billion and $4.0 billion, respectively (see Note 20 to the Consolidated Financial
Statements included elsewhere in this Annual Report on Form 10-K). We are the nation’s leading
supplier and exporter of metallurgical coal for use in the steel-making process and a major
supplier of thermal coal to electric utilities and manufacturing industries across the country. We
operate 61 mines and 14 coal preparation and load-out facilities in Northern and Central Appalachia
and the Powder River Basin, with approximately 6,400 employees.
We produce, process, and sell steam and metallurgical coal from six business units located
throughout Virginia, West Virginia, Kentucky, Pennsylvania, and Wyoming. We also sell coal produced
by others, the majority of which we process and/or blend with coal produced from our mines prior to
resale, providing us with a higher overall margin for the blended product than if we had sold the
coals separately. Our sales of steam coal in 2009 and 2008 accounted for approximately 83% and 58%,
respectively, of our annual coal sales volume, and our sales of metallurgical coal in 2009 and
2008, which generally sells at a premium over steam coal, accounted for approximately 17% and 42%,
respectively, of our annual coal sales volume. The effect of the Merger on the relative percentages
of coal sales volumes for 2009 is discussed below in Results of Operations-Year ended December 31,
2009 Compared to Year Ended December 31, 2008.
Our sales of steam coal during 2009 and 2008 were made primarily to large utilities and
industrial customers throughout the United States, and our sales of metallurgical coal during 2009
and 2008 were made primarily to steel companies in the Northeastern and Midwestern regions of the
United States and in several countries in Europe, Asia and South America. Approximately 32% and 53%
of our coal revenues combined with freight and handling revenues in 2009 and 2008, respectively,
were derived from sales made outside the United States, primarily in Brazil, Italy, Belgium,
Canada, Spain, Egypt, Turkey and Russia.
In addition, we generate other revenues from equipment and parts sales and repair, Dry Systems
Technologies equipment and filters, road construction, rentals, commissions, coal handling,
terminal and processing fees, coal and environmental analysis fees, royalties, override royalty
payments from a coal supply agreement now fulfilled by another producer, fees to transload coal
through our Rivereagle facility on the Big Sandy River and the sale of coalbed methane and natural
gas. We also record revenue for freight and handling charges incurred in delivering coal to certain
customers, for which we are reimbursed by our
customers. As such, freight and handling revenues are offset by equivalent freight and
handling costs and do not contribute to our profitability.
Our primary expenses are for operating supply costs, repair and maintenance expenditures, cost
of purchased coal, royalties, current wages and benefits, postretirement and post employment
benefits, freight and handling costs, and taxes incurred in selling our coal. Historically, our
cost of coal sales per ton is lower for sales of our produced and processed coal than for sales of
purchased coal that we do not process prior to resale.
We are the surviving corporation of the Merger between Old Alpha and Foundation. Prior to the
Merger, Old Alpha, together with its affiliates, was a leading supplier of high-quality Appalachian
coal to the steel industry, electric utilities and other industries, with mining operations in
Virginia, West Virginia, Kentucky and Pennsylvania. Old Alpha was also the nation’s largest
supplier and exporter of metallurgical coal, a key ingredient in steel manufacturing. Prior to the
Merger, Foundation, together with its affiliates, was a major U.S. coal producer operating mines
and associated processing and loading facilities in Pennsylvania, West Virginia and Wyoming.
Foundation primarily supplied steam coal to U.S. utilities for use in generating electricity and
also sold steam coal to industrial plants and metallurgical coal to steel companies.
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Prior to the Merger, Old Alpha had one reportable segment, Coal Operations. As a result of the
Merger, we changed our organizational structure and now have two reportable segments, Eastern Coal
Operations and Western Coal Operations. Eastern Coal Operations consists of our operations in
Northern and Central Appalachia, our coal brokerage activities and our road construction business.
Western Coal Operations consists of two Powder River Basin mines in Wyoming. Our All Other category
includes an idled underground mine in Illinois; expenses associated with closed mines; Dry Systems
Technologies; Coal Gas Recovery; equipment sales and repair operations; terminal services; the
leasing of mineral rights and general corporate overhead. All prior period segment information has
been reclassified to conform to the current year presentation.
On January 1, 2009, Old Alpha adopted Accounting Standards Codification (“ASC”) 470-20, Debt
with Conversion and other Options (“ASC 470-20”). ASC 470-20 has been retrospectively applied as of
the issuance date of April 7, 2008 for our outstanding 2.375% convertible senior notes due 2015
(“the Convertible Notes”). ASC 470-20 requires issuers of convertible debt instruments that may be
settled wholly or partially in cash upon conversion to separately account for the liability and
equity components in a manner reflective of the issuers’ nonconvertible debt borrowing rate.
Adoption of the standard resulted in the following balance sheet impacts at December 31, 2008: (1)
a reduction of debt by $87.8 million and an increase in paid in capital of $69.9 million, (2) an
increase to deferred loan costs of $5.3 million, (3) a net reduction to deferred tax assets of
$23.1 million ($36.3 million reduction in deferred tax assets, offset by a $13.1 million change in
the valuation allowance), and (4) a net increase in retained earnings of $0.2 million. The
deferred loan fees and debt discount are being amortized and accreted, respectively, over the term
of the convertible notes, which are due in 2015. Interest expense of $11.7 million and $8.3
million was recorded for the years ended December 31, 2009 and 2008, respectively, related to
amortization of the deferred loan fees and accretion of the debt discount.
The presentation and disclosure requirements of ASC 810, Consolidation, were adopted January
1, 2009, which require a non-controlling interest to be included in the Consolidated Balance Sheets
as a separate component within shareholders’ equity separate from the parent’s equity; and
consolidated net income to be reported in the Consolidated Statements of Operations as a
consolidated amount and as amounts separately attributable to the parent and non-controlling
interest. The presentation requirements have been applied retrospectively to all periods presented.
Business Developments
In
addition to the Merger completed on July 31, 2009, recent business
developments included the following:
Excelven Pty Ltd. During 2008, Old Alpha recorded an impairment charge of $4.5 million to
write off the total remaining value of our 24.5% interest in Excelven Pty Ltd. (“Excelven”) because
it had exhausted
all reasonable efforts to obtain a mining permit from the Venezuelan government and concluded
that it is no longer reasonable to assume that a permit will be granted. Excelven, through its
subsidiaries, controls the rights to the Las Carmelitas mining venture in Venezuela.
Kingwood Mining Company, LLC. During 2008, Old Alpha announced the permanent closure of the
Whitetail Kittanning Mine, an adjacent coal preparation plant and other ancillary facilities. The
mine stopped producing coal in early January 2009 and Kingwood ceased equipment recovery operations
in April 2009. The decision resulted from adverse geologic conditions and regulatory requirements
that rendered the coal seam unmineable at this location. During 2008, Old Alpha recorded a charge
of $30.2 million, which includes asset impairment charges of $21.2 million, write-off of advance
mining royalties that were deemed unrecoverable of $3.8 million, severance and other employee
benefit costs of $3.6 million and increased reclamation obligations of $1.9 million. The results of
operations for Kingwood have been reported as discontinued operations for all periods presented.
Cliffs Natural Resources, Inc. Proposed Merger. During 2008, Old Alpha entered into a
definitive merger agreement pursuant to which, and subject to the terms and conditions thereof,
Cliffs Natural Resources Inc. (formerly known as Cleveland Cliffs Inc.) (“Cliffs”) would acquire
all of its outstanding shares. On November 3, 2008, Old Alpha commenced litigation against Cliffs
by filing an action in the Delaware Court of Chancery to obtain an order requiring Cliffs to hold
its shareholder meeting as scheduled. On November 17, 2008, Old Alpha and Cliffs mutually
terminated the merger agreement and settled the litigation. The terms of the settlement agreement
included a $70.0 million payment from Cliffs to Old Alpha which, net of transaction costs, resulted
in a gain of $56.3 million in 2008.
Sale of Mineral Reserves. During 2008, Old Alpha sold approximately 17.6 million tons of
underground coal reserves at its Enterprise operations to a private coal producer for approximately
$13.0 million in cash. Old Alpha recognized a gain of $12.9 million from the sale in 2008.
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Gallatin Materials LLC. During, 2008, Old Alpha sold its interest in Gallatin for cash in
the amount of $45.0 million and recorded a gain on the sale of $13.6 million. The proceeds were
used in part to repay the Gallatin loan facility outstanding with NedBank Limited in the amount of
$18.2 million. An escrow balance of $4.5 million was established and Old Alpha agreed to indemnify
and guarantee the buyer against breaches of representations and warranties in the sale agreement
and contingencies that may have existed at closing and materialize within one year from the date of
the sale. As of December 31, 2009, all outstanding obligations had been satisfied and the balance
of the escrow account had been released. The results of operations for Gallatin have been reported
as discontinued operations for all periods presented.
Mingo Logan Acquisition. During 2007, Old Alpha completed the acquisition of certain coal
mining assets in western West Virginia known as Mingo Logan from Arch Coal, Inc. for $43.9 million.
The Mingo Logan purchase consisted of coal reserves, one active deep mine and a load-out and
processing plant, which is managed by our Callaway operations.
Dominion Terminal Associates (DTA). During 2008, Old Alpha’s subsidiary, Alpha Terminal
Company, LLC, increased its equity ownership position in DTA from approximately 33% to
approximately 41% by making an additional investment of $2.8 million. DTA is a 20 million-ton
annual capacity coal export terminal located in Newport News, Virginia. Our coal export and
terminal capacity through DTA is approximately 8.0 million tons annually.
Common Stock and Convertible Debt Offering. During 2008, Old Alpha completed concurrent
public offerings of 4,181,817 shares of common stock at $41.25 per share and $287.5 million
aggregate principal amount of Convertible Notes. The aggregate net proceeds from the common stock
offering and the notes offering were $443.3 million after commissions and expenses. Old Alpha used
the net proceeds from the offerings in part to repurchase $175.0 million aggregate principal amount
of the 10% senior notes due 2012, co-issued by ANR LLC and Alpha Natural Resources Capital Corp.
As a result, Old Alpha recorded a loss relating to the early extinguishment of debt of $14.7
million, consisting of $10.7 million in tender offer consideration and $4.0 million in write-off of
unamortized deferred debt issuance costs. The convertible notes are classified as long-term debt in
the Consolidated Balance Sheets. In the event the
convertible notes become convertible, the outstanding principal amount will be classified as a
current liability.
Coal Pricing Trends, Uncertainties and Outlook
Our long-term outlook for the coal markets in the U.S. remains positive. The Energy
Information Administration (“EIA”) in its 2010 Annual Energy Outlook forecasts that coal-fired
electrical generation will increase by an average annual growth rate of 1.6% through 2015. In 2009,
however, the EIA estimates that electric power generation from coal decreased by nearly 9% compared
to 2008 as overall U.S. demand for electricity declined dramatically and competing fuels became
competitively priced. Long-term demand for coal and coal-based electricity generation in the U.S.
will likely be driven by various factors such as the economy, increasing population, increasing
demand to power residential electronics and plug-in hybrid electric vehicles, public demands for
affordable electricity, the inability of renewable energy sources such as wind and solar to become
the base load source of electric power, geopolitical risks associated with importing large
quantities of global oil and natural gas resources, increasing demand for coal outside the U.S.
resulting in increased exports and the relatively abundant steam coal reserves located within the
United States. Despite the recent downturn to the U.S. and global economies, the International
Monetary Fund’s January 2010 World Economic Outlook forecasts U.S. annual GDP to grow 2.7% and 2.4%
in 2010 and 2011, respectively.
According to the National Energy Technology Laboratory’s (NETL) October 2009 report on new
coal-fired power plants, there are 14,936 MW of new coal-fired electrical generation under
construction in the United States and 882 megawatts of new coal-fired electrical generation
capacity near construction. This total new capacity will increase the annual coal consumption for
electrical generation by an estimated fifty million tons, much of which is expected to be supplied
from the Powder River Basin in Wyoming. Additionally, approximately 4,180 megawatts of coal-fired
electrical generation are in the permitting phase and 27,011 megawatts of coal-fired electrical
generation have been announced and are in the early stages of permitting and development.
Coal exports from the U.S. decreased from approximately 82 million tons in 2008 to
approximately 60 million tons in 2009 in response to the worldwide economic downturn. Despite the
decline in US export coal in 2009, export volumes were similar to 2007 levels due to the number of
committed tons under contract. According to the EIA’s 2009 International Energy Outlook (“IEO”),
global primary energy demand will grow by 33% between 2010 and 2030, with coal demand rising most
in absolute terms and fossil fuels accounting for most of the increase in demand between now and
2030. China and India have contributed more than half the increase in global demand for energy, and
over 80% for coal, since 2000. The IEO estimates these two growing economies will contribute more
than 50% of the increase in global energy demand and nearly 80% of the increase in global coal
demand through 2030. The IEO has reached a general conclusion that dependence on coal for power
rises strongly in countries with emerging economies and relatively large coal reserves, while it
stagnates in the more developed nations and nations with smaller coal reserves.
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Ultimately, the global demand for and use of coal may be limited by any global treaties which
place restrictions on carbon dioxide emissions. As part of the United Nations Framework Convention
on Climate Change, representatives from 187 nations, including the U.S., met in Bali, Indonesia in
December 2007 to discuss a program to limit greenhouse gas emissions after 2012. The convention
adopted the “Bali Road Map” that detailed a two-year process to finalizing a binding agreement in
Copenhagen in 2009. In December 2009 participants gathered in Copenhagen to develop a framework for
climate change mitigation beyond 2012. The principal output of the Copenhagen summit was the
Copenhagen Accord, a document that is neither legally binding nor voted upon nor signed, but was
simply “noted” by the 194 participating countries. Although the results from the Copenhagen summit
were considered modest by many participants, the ultimate outcome of future summits, and any treaty
or other arrangement ultimately adopted by the United States or other countries, may have a
material adverse impact on the global demand for and supply of coal. This is particularly true if
cost effective technology for the capture and storage of carbon dioxide is not sufficiently
developed.
Proposed coal-fired electric generating facilities that do not include technologies to capture
and store carbon dioxide are facing increasing opposition from environmental groups as well as
state and local governments who are concerned with global climate change and uncertain financial
impacts of potential greenhouse gas regulations. Coal-fired generating plants incorporating carbon
dioxide capture and storage technologies will be more expensive to build than conventional
pulverized coal generating plants and the technologies are still in the developmental stages. This
dynamic may cause power generating companies to cut back on plans to build coal-fired plants in the
near term. Nevertheless, the desire to attain U.S. energy independence suggests the construction of
new coal-fired generating facilities is likely to remain a viable option. This desire, coupled with
heightened interest in coal gasification and coal liquefaction, is a potential indicator of
increasing demand for coal in the United States.
Based on weekly production reporting through December 31, 2009 from the EIA, year-over-year
Appalachian production had declined by approximately 10.9% due to decreasing coal demand. Compared
to 2008, Western coal production had decreased by approximately 7.8% in 2009. In Central
Appalachia, delays with respect to permits to construct valley fills at surface mines are likely to
slow the permitting process for surface mining in that region with resultant uncertainties for
producers. Average spot market prices for 2009 for Central Appalachian and Northern Appalachian
coals decreased by roughly 51% and 50%, respectively, compared to 2008 prices. Average spot market
prices for Powder River Basin coal are down approximately 21% from the previous year, with the
basin offering the least expensive fossil fuel on a dollar per Btu basis. Long-term, the delicate
balance of coal supply and increasing coal demand is expected to result in strong, but potentially
volatile fundamentals for the U.S. coal industry.
Our revenues depend on the price at which we are able to sell our coal. The pricing
environment for U.S. steam coal production in 2009 has fallen significantly below the high levels
seen during 2008. However, recent steam coal market conditions indicate that supply and demand have
largely come into balance and the forecasted upswing in demand may result in improved prices for
suppliers. Prices for high quality metallurgical coal, used to manufacture coke for steelmaking,
had deteriorated in 2009 in response to decreased worldwide demand for steel. However, strong
global demand for steel, particularly in China and limited metallurgical coal supply, have created
market conditions that may signal increasing prices in 2010.
The worldwide economic slowdown and the volatility and uncertainty in the credit markets have
had an impact on the demand for and price of coal. Global energy fundamentals, including the
relative decline in demand and prices for both natural gas and crude oil have driven spot prices of
coal lower in the marketplace. Steel manufacturers had shut-in significant capacity in the early
part of 2009 due to the lack of near-term visibility around demand for steel for construction,
automobile manufacturing and other down-stream products. Steel manufacturers appear to have
completed destocking their inventories and steel plant utilization has steadily increased since the
early part of 2009, which may signal strengthening demand for metallurgical coal in 2010. The
relatively low price of natural gas is creating further competitive pressure on the demand for
steam coal. A weak economic recovery could slacken demand for metallurgical and steam coals and
could negatively influence pricing in the near-term. Longer-term, coal industry fundamentals remain
intact. Coal has been the fastest growing fossil fuel for six consecutive years, and significant
additional growth is expected worldwide. Seaborne coal has grown to nearly 1 billion tons annually,
and U.S. exports will be needed to meet worldwide demand. In addition, the idling of coal mines due
to weakened market conditions, and the resulting decrease in production, particularly in Central
Appalachia, should better match production to demand. These factors should lead to a tighter market
for coal, both globally and in the United States, in the coming years.
Our results of operations are dependent upon the prices we obtain for our coal as well as our
ability to improve productivity and control costs. Principal goods and services include maintenance
and repair parts and services, electricity, fuel, roof control and support items, explosives,
tires, conveyance structure, ventilation supplies and lubricants.
Our management continues to aggressively control costs and strives to improve operating
performance to mitigate external cost pressures. As is common in the current economic environment,
we are experiencing volatility in operating costs related to fuel, explosives, steel, tires,
contract services and
healthcare and have taken measures to mitigate the increases in these costs at all operations.
We have a centralized sourcing group for major supplier contract negotiation and administration,
for the negotiation and purchase of major capital goods, and to support the business units. The
supplier base has been relatively stable for many years, but there has been some consolidation. We
are not dependent on any one supplier in any region. We promote competition between suppliers and
seek to develop relationships with suppliers that focus on lowering our costs. We seek suppliers
who identify and concentrate on implementing continuous improvement opportunities within their area
of expertise. To the extent upward pressure on costs exceeds our ability to realize sales
increases, or if we experience unanticipated operating or transportation difficulties, our
operating margins would be negatively impacted. Employee labor costs have historically increased
primarily due to the demands associated with attracting and retaining a workforce; however, recent
stability in the marketplace has helped ease this situation. We may also continue to experience
difficult geologic conditions, delays in obtaining permits, labor shortages, unforeseen equipment
problems and shortages of critical materials such as tires and explosives that may result in
adverse cost increases and limit our ability to produce at forecasted levels.
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For additional information regarding some of the risks and uncertainties that affect our
business, see Item 1A “Risks Factors.”
Results of Operations
As noted previously, the financial results for the year ended December 31, 2009 include only
five months of operations related to the acquired operations of Foundation due to the timing of the
closing of the Merger on July 31, 2009 and therefore, the year-over-year results are not
comparable. To help understand the operating results for the full year, the term “Foundation
operations” refers to the results of Foundation on a stand-alone basis for the five month period
from August 1, 2009 through December 31, 2009 and the term “legacy Alpha operations” refers to the
results of Old Alpha on a stand-alone basis for the year ended December 31, 2009. Additionally, the
calculation of Selling, general and administrative expenses for both companies are not comparable
calculations to the expenses that would have been calculated as separate entities due to certain
intercompany allocations of the combined company. Unless specifically indicated otherwise, all
amounts discussed in the following analysis of results of operations relate to amounts from
continuing operations and do not include any amounts related to Gallatin or Kingwood unless
specifically identified.
EBITDA from continuing operations is calculated as follows:
Year Ended December 31, 2009 Compared to Year Ended December 31, 2008
Summary
Total revenues increased $26.8 million, or 1% for the year ended December 31, 2009 compared to
the year ended December 31, 2008. The increase in total revenues consisted of the addition of
$716.8 million
in revenues from the Foundation operations, largely offset by a decrease of $690.0 million in
revenues from the legacy Alpha operations. The decrease in revenues from the legacy Alpha
operations was due to a decrease in coal revenues of $614.6 million, or 29%, and a $90.2 million
decrease in freight and handling revenues, which are offset by an equivalent decrease in freight
and handling costs, partially offset by an increase in other revenues of $14.8 million, or 31%.
Coal revenues increased $70.3 million, or 3% for the year ended December 31, 2009 compared to
the year ended December 31, 2008. The increase in coal revenues consisted of the addition of $684.9
million in coal revenues from the Foundation operations, largely offset by a decrease in coal
revenues of $614.6 million from the legacy Alpha operations. The decrease in coal revenues of
$614.6 million from the legacy Alpha operations was a result of lower metallurgical coal sales
volumes in addition to lower metallurgical coal sales realization per ton due to lower demand and
lower contract pricing as a result of the economic recession experienced through much of 2009,
partially offset by higher average steam coal sales realization per ton.
Income from continuing operations decreased $131.8 million, or 66% for the year ended December
31, 2009 compared to the year ended December 31, 2008. The decrease was primarily due to an
increase in operating costs and expenses of $155.0 million and other non-operating expenses of
$88.9 million, partially offset by an increase in revenues as explained above of $26.8 million and
a decrease in income tax expense of $85.3 million. The increase in operating costs and expenses of
$155.0 million consisted of the addition of $737.1 million in operating costs and expenses from the
Foundation operations; partially offset by a decrease of $582.1 million in operating costs and
expenses related to the legacy Alpha operations. The decrease in operating costs and expenses of
$582.1 million related to the legacy Alpha operations was due to decreased cost of coal sales of
$478.6 million; decreased freight and handling expenses of $90.1 million which are offset by an
equivalent decrease in freight and handling revenue; decreased other expenses of $63.2 million and
decreased depreciation, depletion and amortization expenses of $14.0 million, partially offset by
increased selling, general and administrative expenses of $63.8 million. Operating costs and
expenses related to the Foundation operations consisted of $467.5 million of cost of coal sales,
$127.6 million of amortization of acquired coal supply agreements, $101.4 million of depreciation,
depletion and amortization expenses, $34.7 million of selling, general and administrative expenses,
$5.7 million of other miscellaneous expenses and $0.2 million of freight and handling expenses.
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We sold 47.2 million tons of coal during the year ended December 31, 2009 compared to 26.9
million tons during the year ended December 31, 2008, an increase of 20.3 million tons, or 75%. The
47.2 million tons sold during the year ended December 31, 2009 consisted of 28.2 million tons from
the Foundation operations and 19.0 million tons from the legacy Alpha operations. Total coal sales
volume from the legacy Alpha operations decreased 7.9 million tons, or 29%, during the year ended
December 31, 2009 compared to the year ended December 31, 2008. The decrease in coal sales volume
from the legacy Alpha operations consisted of a decrease in steam coal sales volume of 4.0 million
tons, or 26%, and a decrease in metallurgical coal sales volume of 3.9 million tons, or 34%. The
28.2 million tons sold by the Foundation operations included 20.8 million tons of steam coal from
our Western Coal Operations and 6.8 million tons of steam coal and 0.6 million tons of
metallurgical coal from our Eastern Coal Operations.
The consolidated weighted average coal sales realization per ton for the year ended December
31, 2009 was $46.84 compared to $79.58 for the year ended December 31, 2008. The decrease was
largely attributable to the inclusion of the Foundation operations. The weighted average coal sales
realization per ton for the legacy Alpha operations was $80.35 for the year ended December 31, 2009
compared to $79.58 for the year ended December 31, 2008. The increase in average coal sales
realization per ton for the legacy Alpha operations reflected higher sales prices on steam coal
sales volumes, $70.22 per ton for 2009 compared to $51.80 per ton for 2008, which were mostly
offset by lower sales prices on metallurgical coal sales volumes, $95.83 per ton for 2009 compared
to $117.50 per ton for 2008. The weighted average coal sales realization per ton for the year ended
December 31, 2009 for the Foundation operations was $24.28, which reflects a high proportion of
coal sales volumes from the Western Coal Operations at an average coal sales realization per ton of
$10.47. Coal sales realization per ton for eastern steam coal was $57.06 and coal sales realization
per ton for eastern metallurgical coal was $125.57 for the Foundation operations for the year ended
December 31, 2009.
Consolidated coal margin percentage, calculated as consolidated coal revenues less
consolidated cost of coal sales, divided by consolidated coal revenues, was 27% for the year ended
December 31, 2009 compared to 24% for the year ended December 31, 2008. Coal margin percentage for
the Foundation operations was 32% and coal margin percentage for the legacy Alpha operations was
25% for the year ended December 31, 2009. Consolidated coal margin per ton, calculated as
consolidated coal sales realization per ton less consolidated cost of coal sales per ton, was
$12.58 for the year ended December 31, 2009 compared to $19.05 for the year ended December 31,
2008. Coal margin per ton for the Foundation operations was $7.71 per ton and coal margin per ton
for the legacy Alpha operations was $19.82 per ton for the year ended December 31, 2009.
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Revenues
Coal revenues. Coal revenues increased $70.3 million, or 3% for the year ended December 31,
2009 compared to the year ended December 31, 2008. The increase in coal revenues consisted of the
addition of $684.9 million related to the Foundation operations, largely offset by a decrease of
$614.6 million related to the legacy Alpha operations. The decrease of $614.6 million, or 29%, in
coal revenues related to the legacy Alpha operations was due to a $615.9 million decrease in
metallurgical coal revenue partially offset by a $1.3 million increase in eastern steam coal
revenue. The decrease in metallurgical coal revenue related to the legacy Alpha operations was due
to a decline in metallurgical coal sales volumes of 3.8 million tons and an 18% decrease in
metallurgical coal sales realization per ton, reflecting lower market pricing and lower demand for
metallurgical coal from steel producers due to the economic recession experienced through much of
2009 compared to 2008. Eastern steam coal revenues related to legacy Alpha operations increased
$1.3 million despite a 4.0 million ton decrease in eastern steam coal sales volumes due to a 36%
increase in coal sales realization per ton related to shipments on higher priced contracts that
were executed in 2008. The $684.9 million in coal revenues from the Foundation operations included
$390.6 million in eastern steam coal revenues, $217.2 million in western steam coal revenues and
$77.1 million in metallurgical coal revenues. Our sales mix of metallurgical coal and steam coal
based on volume for the year ended December 31, 2009 was 17% and 83%, respectively, compared with
42% and 58%, respectively, for the year ended December 31, 2008. The sales mix of metallurgical
coal and steam coal for the legacy Alpha operations in 2009 was 40% and 60%, respectively, and 2%
and 98%, respectively, for the Foundation operations. In 2009, approximately 36% of coal revenues
were derived from the sale of metallurgical coal compared with 62% in 2008.
Freight and handling revenues. Freight and handling revenues were $189.9 million for the year
ended December 31, 2009, a decrease of $90.0 million compared to the year ended December 31, 2008
due to lower export shipments combined with lower rates. These revenues are primarily related to
the legacy Alpha operations and are offset by equivalent costs and do not contribute to our
profitability.
Other revenue. Other revenue increased $46.5 million, or 96% for the year ended December 31,
2009 compared to the year ended December 31, 2008. The increase in other revenue consisted of the
addition of $31.7 million from the Foundation operations and an increase of $14.8 million from the
legacy Alpha operations. The increase of $14.8 million from the legacy Alpha operations was due to
increased terminal fees; mark-to-market gains on derivative coal contracts and increased revenues
related to our road construction business, partially offset by lower coal processing fees, lower
parts and equipment sales from our Maxxim Rebuild business and lower royalty income. Other revenues
of $31.7 million from the Foundation operations consisted of revenues related to our Dry Systems
Technology and Coal Gas Recovery businesses and $18.1 million related to a coal supply agreement
modification.
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Costs and Expenses
Cost of coal sales. Cost of coal sales decreased $11.1 million, or 1% in the year ended
December 31, 2009 compared to the year ended December 31, 2008. The decrease in cost of coal sales
in 2009 compared to 2008 consisted of a decrease of $478.6 million from the legacy Alpha
operations; largely offset by the inclusion of $467.5 million from the Foundation operations. The
decrease of $478.6 million in cost of coal sales related to the legacy Alpha operations was
primarily due to a decrease in purchased coal expense related to 3.4 million fewer tons purchased,
lower repairs and maintenance, lower operating supplies and a decrease in other variable expenses
due to lower coal production as a result of the global recession experienced during most of 2009.
The weighted average total cost of coal sales per ton was $34.26 for the year ended December 31,
2009, a decrease of 43% compared to $60.53 for the year ended December 31, 2008. Cost of coal sales
per ton for the legacy Alpha operations remained virtually unchanged at $60.54 despite the 7.9
million ton decrease in coal sales volumes. This is primarily due to fixed operating costs being
spread over a lower amount of tons produced, which offset the reduction in variable production
expenses.
The weighted average cost of coal sales per ton for the year ended December 31, 2009 for the
Foundation operations was $16.57, which reflects a high proportion of coal sales volumes from the
Western Coal Operations, which had an average cost of coal sales per ton of $8.30. Cost of coal
sales per ton for the Eastern Coal Operations related to the Foundation operations was $39.58 for
the year ended December 31, 2009.
Gain on sale of coal reserves. Gain on sale of coal reserves of $12.9 million for the year
ended December 31, 2008 related to the sale of a portion of our Kentucky May underground coal
reserves.
Freight and handling costs. Freight and handling costs were $189.9 million for the year ended
December 31, 2009, a decrease of $90.0 million compared to the year ended December 31, 2008 due to
lower export shipments combined with lower rates. These costs are primarily related to the legacy
Alpha operations and are offset by equivalent revenue and do not contribute to our profitability.
Other expenses. Other expenses decreased $70.4 million, or 77% for the year ended December 31,
2009 compared to the year ended December 31, 2008. The decrease consisted of a $76.1 million
decrease in other expenses related to the legacy Alpha operations, partially offset by the addition
of $5.7 million of other expenses from the Foundation operations. The decrease in other expenses
related to the legacy Alpha operations was primarily due to decreased expenses related to coal
contract buy-out transactions and net mark-to-market gains on derivative swap contracts recorded
during the year ended December 31, 2009 compared to net mark-to-market losses recorded during the
year ended December 31, 2008. Other expenses of $5.7 million related to the Foundation operations
consisted of mark-to-market gains on our derivative swap agreements and expenses for our Dry
Systems Technology and Coal Gas Recovery businesses.
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Depreciation, depletion and amortization. Depreciation, depletion, and amortization increased
$87.4 million, or 53% for the year ended December 31, 2009 compared to the year ended December 31,
2008. The increase consisted of $101.4 million of depreciation, depletion and amortization expense
from the Foundation operations, partially offset by a $14.0 million decrease in depreciation,
depletion and amortization expense from the legacy Alpha operations. The decrease of $14.0 million
from the legacy Alpha operations was due to decreased depletion expense due to lower tons produced,
partially offset by a decreased credit to amortization expense related to the amortization of
miscellaneous intangibles. Depreciation, depletion, and amortization of $101.4 million related to the Foundation
operations consisted of $61.5 million of depreciation amortization of property, equipment and
mine development costs and $39.9 million of depletion expense.
Amortization of acquired coal supply agreements, net. Application of acquisition accounting in
connection with the Merger resulted in the recognition of a significant asset for above
market-priced coal supply agreements and a liability for below market-priced coal supply agreements
on the date of the acquisition. The coal supply agreement assets and liabilities are being
amortized over the actual amount of tons shipped under each contract. Amortization of acquired coal
supply agreements, net was $127.6 million for the year ended December 31, 2009. Amortization of
acquired coal supply agreements, net for future periods is expected to be $255.2 million in 2010,
$91.1 million in 2011, $31.7 million in 2012 and a credit to expense of ($1.7 million) in 2013.
Selling, general and administrative expenses. Selling, general and administrative expenses
increased $98.5 million, or 137% for the year ended December 31, 2009 compared to the year ended
December 31, 2008. The increase in selling, general and administrative expenses consisted of $34.7
million in expenses from the Foundation operations and an increase of $63.8 million related to the
legacy Alpha operations. The increase of $63.8 million related to the legacy Alpha operations was
due to legal and professional fees of $43.1 million primarily related to transaction, consulting
and integration costs related to the Merger, increased employee compensation of $18.3 million,
including a $15.7 million increase in non-cash stock-based compensation and $2.4 million of other
miscellaneous expenses. Consolidated selling, general and administrative expenses for 2009 included
approximately $59.0 million of expenses related to the Merger.
Interest expense. Interest expense increased $43.0 million, or 108% during the year ended
December 31, 2009 compared to the year ended December 31, 2008. The increase in interest expense
consisted of the addition of $21.4 million from the Foundation operations and an increase of $21.6
million from the legacy Alpha operations. The increase of $21.6 million from the legacy Alpha
operations was primarily due to $24.2 million of interest expense related to the reclassification
of unrealized losses into interest expense from accumulated other comprehensive income (loss) and
subsequent changes in fair value related to an interest rate swap that was de-designated as a cash
flow hedge as a result of paying off a term loan related to the legacy Alpha operations shortly
after the Merger. Interest expense related to the Foundation operations consisted of interest
expense from the outstanding term loan due 2011, the outstanding 7.25% notes due 2014 and accretion
of debt discount.
Interest income. Interest income decreased by $5.6 million, or 76% for the year ended December
31, 2009 compared to the twelve months ended December 31, 2008 primarily due to lower interest
rates realized on our invested cash as well as a lower average cash balance for the comparable
period.
Loss on early extinguishment of debt. Loss on early extinguishment of debt was $5.6 million
for the year ended December 31, 2009 and was related to the write-off of unamortized deferred debt
issuance costs for a term loan related to the legacy Alpha operations that was paid off shortly
after the Merger. Loss on early extinguishment of debt was $14.7 million for the year ended
December 31, 2008 and consisted of $10.7 million in tender offer consideration payment for the
repurchase of Old Alpha’s $175.0 million 10% senior notes and the write-off of the related
unamortized deferred debt issuance costs of $4.0 million.
Net gain on termination of Cliffs’ merger. Net gain on termination of Cliffs’ merger was $56.3
million for the year ended December 31, 2008 and consisted of a $70.0 million fee Old Alpha
received from Cliffs upon termination of the planned merger less $13.7 million in transaction
costs, including fees paid for financial, legal and other professional fees.
Miscellaneous income (expense), net. Miscellaneous income (expense), net was $3.2 million for
the year ended December 31, 2009 and ($3.8 million) for the year ended December 31, 2008.
Miscellaneous expense in 2008 was primarily related to the impairment charge of $4.5 million
related to Old Alpha’s equity investment in the Excelven joint venture in Venezuela.
Income tax expense (benefit). Income tax benefit from continuing operations for the year ended
December 31, 2009 was $33.0 million as compared to income tax expense of $52.2 million for the year
ended December 31, 2008. The income tax benefit for 2009 was due primarily to the tax benefits associated with percentage depletion and the reversal of
$22.2 million of valuation allowance that was triggered by our movement from a net deferred tax
asset position to a net deferred tax liability position on our consolidated balance sheet as a
result of the Merger, partially offset by non-deductible transaction costs and the impact from the
interest rate swap.
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Our effective tax rate of 20.8% for 2008 was lower than the statutory federal tax rate due
primarily to the tax benefits associated with percentage depletion, the domestic production
activities deduction, and the change in the valuation allowance, partially offset by state income
taxes.
The effective tax rate for 2009 was lower than the effective tax rate for 2008 mainly due to
the benefits of the valuation allowance reversal and percentage depletion being larger in relation
to pre-tax income. As a result of the Merger, a significant amount of the book depreciation,
depletion and amortization expense does not impact the percentage depletion calculation. Due to
being in a net liability position, no valuation allowances were established against the minimum tax
credit carryforwards and the federal net operating loss, much of which is created from the
percentage depletion deduction.
Discontinued operations. Loss from discontinued operations for the year ended December 31,
2009 was $8.8 million, net of tax, compared to a loss from discontinued operations of $32.9
million, net of tax, for the year ended December 31, 2008. The loss from discontinued operations of
$8.8 million in 2009 was primarily related to expenses incurred for Kingwood. The $32.9 million
loss in 2008 consists of losses from Kingwood of $37.1 million and income from Gallatin of $4.2
million. The $37.1 million loss from Kingwood consists of loss from operations of $49.8 million
including $30.2 million in mine closure and asset impairment charges, partially offset by an income
tax benefit of $12.7 million. The $4.2 million of income from Gallatin consists of a gain on the
sale of Gallatin of $13.6 million, offset by losses from the operation of Gallatin of $7.8 million,
net of non-controlling interest and income tax expense of $1.6 million.
Segment Analysis
The price of coal is influenced by many factors that vary by region. Such factors include, but
are not limited to: (1) coal quality, which includes energy (heat content), sulfur, ash, volatile
matter and moisture content; (2) transportation costs; (3) regional supply and demand; (4)
available competitive fuel sources such as natural gas, nuclear or hydro; and (5) production costs,
which vary by mine type, available technology and equipment utilization, productivity, geological
conditions, and mine operating expenses.
The energy content or heat value of coal is a significant factor influencing coal prices as
higher energy coal is more desirable to consumers and typically commands a higher price in the
market. The heat value of coal is commonly measured in British thermal units or the amount of heat
needed to raise the temperature of one pound of water by one degree Fahrenheit. Coal from the
Eastern and Midwest regions of the United States tends to have a higher heat value than coal found
in the Western United States.
Powder River Basin coal, with its lower energy content, lower production cost and often
greater distance to travel to the consumer, typically sells at a lower price than Northern and
Central Appalachian coal that has a higher energy content and is often located closer to the end
user.
Western Coal Operations — Our Western Coal Operations are located in the southern Powder River
Basin of Wyoming and were acquired in the Merger and therefore, we do not have reported comparative
results. We operate two large open-pit mines at Belle Ayr and Eagle Butte and produce steam coal
for shipment primarily to utilities. EBITDA from continuing operations for our Western Coal Operations was $39.3 million for
the year ended December 31, 2009, which included $217.2 million in coal revenues and $172.2 million
in cost of coal sales. Coal sales realization per ton was $10.47 and coal sales volumes were 20.8
million tons. Coal
revenues and tons shipped from the Western Coal Operations have been generally affected in
2009 by weak demand in the marketplace and transportation delays in the region.
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Eastern Coal Operations — Our Eastern Coal Operations are located in Pennsylvania, West
Virginia, Virginia and Kentucky and produce steam coal that is sold primarily to electric utilities
and industrial customers. Our Eastern Coal Operations also produces metallurgical coal that is sold
primarily to steel producers. Steam coal sales volumes from our Eastern Coal Operations increased
2.8 million tons, or 18%, for the year ended December 31, 2009 compared to the year ended December
31, 2008. The increase in steam coal sales volumes consisted of 6.8 million tons from the
Foundation operations, partially offset by a decrease of 4.0 million tons from the legacy Alpha
operations. The 4.0 million decrease in steam coal sales volumes from the legacy Alpha operations
is primarily due to lower brokered coal activity and lower production due to the economic recession
experienced during 2009 and to a lesser extent, severe weather conditions experienced in the fourth
quarter of 2009. The Foundation operations shipped 6.8 million tons of steam coal for the year
ended December 31, 2009, which included 5.4 million tons from our Pennsylvania Services business
unit and 1.4 million tons from the Foundation mines included in our Northern West Virginia business
unit.
Steam coal sales realization per ton at our Eastern Coal Operations increased $13.50, or 26%,
for the year ended December 31, 2009 compared to the year ended December 31, 2008. The increase was
primarily due to an increase in steam coal sales realization per ton for the legacy Alpha
operations, partially offset by lower relative steam coal sales realization per ton from the
Foundation operations. Steam coal sales realization per ton for the legacy Alpha operations was
$70.22, an increase of $18.42 per ton, or 36%, for the year ended December 31, 2009 compared to the
year ended December 31, 2008. The increase was due to shipments on higher priced contracts that
were executed primarily during a period in 2008 when market prices for steam coal were more
favorable as compared to the pricing in the contracts included in the 2008 coal sales volumes. The
average coal sales realization per ton for the Foundation operations was $57.06 per ton, which
included coal sales realization per ton of $53.24 from our Pennsylvania Services business unit and
$72.17 from the Foundation mines included in our Northern West Virginia business unit.
Metallurgical coal sales volumes from our Eastern Coal Operations decreased 3.2 million tons,
or 29%, for the year ended December 31, 2009 compared to the year ended December 31, 2008. The
decrease in metallurgical coal sales volumes consisted of a decrease of 3.8 million tons from the
legacy Alpha operations, partially offset by 0.6 million tons shipped from the Foundation
operations. The 3.8 million decrease in metallurgical coal sales volumes from the legacy Alpha
operations is due primarily to lower demand for coking coal from steel producers due to the
economic recession experienced during 2009. The Foundation operations shipped 0.6 million tons for
the year ended December 31, 2009, all of which was shipped from Foundation mines included in our
Northern West Virginia business unit.
Metallurgical coal sales realization per ton at our Eastern Coal Operations decreased $19.42,
or 17%, for the year ending December 31, 2009 compared to the year ending December 31, 2008. The
decrease was due to a decrease in coal sales realization per ton for the legacy Alpha operations,
partially offset by higher relative coal sales realization per ton from the Foundation operations.
Coal sales realization per ton for the legacy Alpha operations was $95.83, a decrease of $21.67 per
ton, or 18%, for the year ended December 31, 2009 compared to the year ended December 31, 2008. The
decrease was due to lower market prices realized on coal sales volumes as a result of reduced
demand for coking coal from steel producers experienced for the year ending December 31, 2009
compared to the year ending December 31, 2008. The average coal sales realization per ton for the
Foundation operations was $125.57 per ton.
EBITDA from continuing operations for our Eastern Coal Operations increased $102.5 million, or
24% compared to the prior year period. The increase was primarily due to lower total costs and
expenses of $306.0 million and higher miscellaneous income of $2.2 million, which were partially
offset by lower total revenues of $205.7 million. The decrease in total costs and expenses was largely
attributable to a $189.1 million decrease in cost of coal sales related to lower purchased coal
volumes and lower variable production costs; a decrease in other expenses of $70.5 million
primarily related to net mark-to-market gains on derivative swap contracts and lower expenses
associated with coal contract settlements; decreased freight and handling costs that are offset by
a corresponding decrease in freight and handling revenues of $90.0 million; higher Selling, general
and administrative expenses of $28.1 million and lower gains on asset sales of $15.0 million.
The decrease in total revenues of $205.7 million was the result of lower metallurgical coal
sales revenues of $538.9 million that were partially offset by higher steam coal sales revenues of
$391.9 million. The decrease in metallurgical coal sales revenues consisted of a decrease of $615.9
million related to the legacy Alpha operations as a result of the factors described above; which
was partially offset by the addition of $77.0 million of metallurgical coal sales revenue from the
Foundation operations.
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Year Ended December 31, 2008 Compared to Year Ended December 31, 2007
Summary
For the year ended December 31, 2008, Old Alpha recorded total revenues from continuing
operations of $2,468.8 million compared to $1,806.2 million for the year ended December 31, 2007,
an increase of $662.6 million. Net income attributable to Alpha Natural Resources, Inc. increased
from $27.7 million in 2007 to $165.7 million in 2008 and income from continuing operations
increased $165.7 million from $32.9 million to $198.6 million. Coal margin, which we define as
coal revenues less cost of coal sales, divided by coal revenues, increased from 17.6% in 2007 to
23.9% in 2008.
Revenues
Coal revenues. Coal revenues increased for the year ended December 31, 2008 by $581.7 million
or 37%, to $2,140.4 million, as compared to the year ended December 31, 2007. This increase was due
primarily to a $21.66 increase in the average sales price per ton. Tons sold were 26.9 million tons
in 2008 and 2007. Met coal realization per ton increased by 62% from $72.59 per ton to $117.50 per
ton, and steam coal realization per ton increased by 7% from $48.59 per ton to $51.80 per ton.
Included in steam coal revenues for 2008 is a charge of $12.3 million related to a settlement of a
liability incurred under the default provisions of a coal contract, which reduced steam coal
realization per ton by $0.79. The increase in met coal realizations during 2008 was mainly
attributable to strong global demand for hard coking coals coupled with supplier production and
logistics issues in Eastern Europe and Australia. During the fourth quarter of 2008, global demand
for coal significantly declined due to the global economic slowdown. Old Alpha’s sales mix of met
coal and steam coal based on volume in 2008 was 42% and 58%, respectively, compared with 39% and
61%, respectively, in 2007. In 2008, approximately 62% of coal revenues were derived from the sale
of metallurgical coal compared with only 49% in 2007.
Freight and handling revenues. Freight and handling revenues increased to $279.9 million for
the year ended December 31, 2008, an increase of $74.8 million compared to the year ended December
31, 2007
due to an increase in freight costs, arising primarily from vessel freight and fuel
surcharges. These revenues are offset by equivalent costs and do not contribute to Old Alpha’s
profitability.
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Other revenues. Other revenues increased for the year ended December 31, 2008 by $6.1 million,
or 14%, to $48.5 million, as compared to the same period for 2007. The increase in other revenues
related to increased revenues from the largest ongoing road construction project from our road
construction business of $12.9 million, higher terminal fees earned of $3.9 million due to higher
volumes; increased revenues from Maxxim Rebuild of $3.7 million due to higher equipment sales and a
$1.2 million increase in royalties, partially offset by mark-to-market losses of $15.6 million.
Costs and expenses
Cost of coal sales. Cost of coal sales increased by $343.1 million, ($12.79 per ton), from
$1,284.8 million, ($47.74 per ton) for the year ended December 31, 2007 to $1,628.0 million,
($60.53 per ton), for the year ended December 31, 2008. Cost of coal sales per ton for produced and
processed coal was $57.28 per ton in 2008 as compared to $47.20 per ton in 2007. This increase is
attributable mainly to increases in the price of coal purchases at the plants, diesel fuel, labor
and benefits, supplies and maintenance and royalties and severance taxes. The cost of coal sales
per ton of purchased coal was $75.13 per ton in 2008 and $50.74 per ton in 2007. This increase in
costs is mainly due to market conditions, which exerted upward pricing pressures due to a decrease
in market supply and an increase in market demand for coal, both domestically and internationally.
Approximately 65% of purchased coal sold during 2008 was blended with produced and processed coal
prior to resale.
Gain on sale of coal reserves. Gain on sale of coal reserves of $12.9 million relates to the
sale of a portion of the Kentucky May underground coal reserves.
Freight and handling costs. Freight and handling costs increased $74.8 million to $279.9
million during 2008 as compared to 2007 due to an increase in export tons and freight costs,
arising primarily from vessel freight and fuel surcharges. These costs were offset by an equivalent
amount of freight and handling revenue.
Other Expenses. Other expenses increased $68.7 million, or 302%, to $91.5 million for the
year ended December 31, 2008 as compared to 2007 primarily due to mark-to-market losses in 2008 on
derivative swap contracts and contract buy-out expenses of $50.4 million and increases in costs
from coal processing and terminal operations, road construction operations, and Maxxim Rebuild of
$7.5 million, $6.8 million, and $4.0 million, respectively.
Depreciation, depletion and amortization. Depreciation, depletion, and amortization increased
$11.0 million, or 7%, to $165.0 million for the year ended December 31, 2008 as compared to 2007.
Depreciation, depletion and amortization attributable to the Eastern Coal Operations segment were
$157.1 million in 2008 and $146.7 million in 2007. Depreciation, depletion and amortization per
ton sold for produced and processed coal from the Eastern Coal Operations segment continuing
operations increased from $6.44 per ton for the year ended December 31, 2007 to $7.13 per ton in
the same period of 2008. The increase was mainly due to acquisitions, an increased depletion
expense due to higher production at Old Alpha’s mines which also had an increase in depletion rate
per ton due to a change in estimated recoverable coal reserves in the third quarter of 2007, and an
increase due to capital additions.
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Selling, general and administrative expenses. Selling, general and administrative expenses
(SG&A) increased $13.4 million, or 23%, to $71.9 million for the year ended December 31, 2008
compared to 2007 primarily due to increases in stock-based compensation expense of $2.6 million,
incentive compensation of $4.8 million, wages and benefits of $3.6 million and travel and
entertainment of $0.6 million. SG&A expenses as a percentage of total revenues decreased from 3.2%
in 2007 to 2.9% in 2008.
Interest expense. Interest expense for 2008 was $39.8 million, slightly down from interest
expense of $40.4 million in 2007. Included in interest expense for 2008 is $7.6 million of
accretion of the discount on convertible debt incurred in connection with the issuance of Old
Alpha’s $287.5 million aggregate principal amount of convertible notes, which was offset by the
reduction in interest rates on the debt as a result of the repayment of the $175.0 million
outstanding principal amount of Old Alpha’s 10% senior notes due 2012.
Interest income. Interest income increased by $5.1 million for the year ended December 31,
2008 compared to 2007. The increase is mainly due to a significant increase in invested cash from
the concurrent public offerings of $287.5 million aggregate principal amount of the convertible
notes and $172.5 million common stock, as well as cash generated from operations.
Loss on early extinguishment of debt. Loss on early extinguishment of debt of $14.7 million
consists of $10.7 million in tender offer consideration payment for the repurchase of Old Alpha’s
$175.0 million 10% senior notes and the write-off of the unamortized deferred debt issuance costs
of $4.0 million.
Net gain on termination of Cliffs’ merger. Net gain on termination of Cliffs’ merger of $56.3
million consists of the $70.0 million fee Old Alpha received from Cliffs upon termination of the
planned merger less $13.7 million in transaction costs, including financial, legal and other
professional fees.
Miscellaneous expense, net. Miscellaneous expense, net of $3.8 million in 2008 is primarily
related to the impairment charge of $4.5 million related to Old Alpha’s equity investment in the
Excelven joint venture in Venezuela.
Income tax expense (benefit). Income tax expense from continuing operations for the year ended
December 31, 2008 was $52.2 million as compared to income tax expense of $10.0 million for the year
ended December 31, 2007. The effective tax rates from continuing operations for the year ended
December 31, 2008 and 2007 were 20.8% and 23.3%, respectively. The effective tax rate for 2008 was
lower than the statutory federal tax rate due primarily to the tax benefits associated with
percentage depletion and the domestic production activities deduction, partially offset by state
income taxes, and the change in the valuation allowance.
The effective tax rate for 2007 was lower than the statutory federal tax rate due primarily to
the tax benefits associated with percentage depletion, partially offset by state income taxes,
change in the valuation allowance, and stock-based compensation charges which are not deductible
for tax purposes.
The effective tax rate for 2008 was lower than the effective tax rate for 2007 mainly due to a
benefit from utilization of tax basis on assets sold, utilization of other deferred tax assets, and
an increase in the manufacturing deduction, offset in part by a smaller benefit from the percentage
depletion deduction.
In the second quarter of 2008, Old Alpha recognized a benefit for a portion of the valuation
allowance that existed at the beginning of the year, based on positive evidence regarding the
ability to realize the deferred tax assets in the future. In the fourth quarter of 2008, due to
significant changes in the economic landscape and projections of the Alternative Minimum Tax
liability, Old Alpha reestablished the previous valuation allowance on deferred tax assets.
Discontinued operations. Loss from discontinued operations attributable to Alpha Natural
Resources, Inc. for the year ended December 31, 2008 was $32.9 million as compared to a loss from
discontinued operations of $5.1 million for the year ended December 31, 2007. Mine closure/asset
impairment charges of $30.2 million relating to the permanent closure of the Whitetail Kittanning
Mine were recorded in 2008.
The $32.9 million loss in 2008 consists of losses from Kingwood of $37.1 million and income
from Gallatin of $4.2 million. The $37.1 million loss from Kingwood consists of loss from
operations of $49.8 million, partially offset by an income tax benefit of $12.7 million, compared
to a loss from Kingwood of $2.9 million in 2007. The $4.2 million of income from Gallatin consists
of a gain on the sale of Old Alpha’s interest in Gallatin of $13.6 million, offset by losses from
the operation of Gallatin of $7.8 million, net of non-controlling interest, and income tax expense
of $1.6 million, compared to a loss from Gallatin of $2.2 million in 2007.
Segment Analysis
None of Old Alpha’s operations in the years ended December 31, 2008 or 2007, were attributable
to the Western Coal Operations segment, which was added as a result of the inclusion of Foundation
operations subsequent to the Merger.
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Eastern Coal Operations - EBITDA from continuing operations increased $182.1 million, or 76%
for the year ended December 31, 2008 compared to the year ended December 31, 2007. The increase in
EBITDA from continuing operations was the result of increased revenues $654.9 million and a gain of
$12.9 million gain on sale of coal reserves in 2008, partially offset by increases in costs of coal
sales of $343.4 million; freight and handling costs of $74.8 million; other expenses $61.6 million and
increased selling, general and administrative expenses of $5.9 million. The increase in revenues
was primarily
attributable to increased metallurgical coal sales volumes, which increased 0.9 million tons,
or 9%, and higher metallurgical coal sales realization per ton, which increased $44.91, or 62% for
the year ended December 31, 2008 compared to the prior year, mainly attributable to strong global
demand for hard coking coals coupled with supplier production and logistics issues in Eastern
Europe and Australia.
Liquidity and Capital Resources
Our primary liquidity and capital resource requirements stem from the cost of our coal
production and purchases, our annual capital expenditures, our income taxes, and our debt service
and reclamation obligations. Our primary sources of liquidity have been from sales of our coal
production; borrowings under our credit facility (see “—Credit Agreement and Long-Term Debt”),
note issuances, sales of our common stock; and to a much lesser extent, sales of purchased coal to
customers, cash from sales of non-core assets and miscellaneous revenues.
We believe that cash on hand, cash generated from our operations and borrowings available
under our credit facility will be sufficient to meet our working capital requirements, anticipated
capital expenditures, debt service requirements and reclamation obligations for at least the next
twelve months.
At December 31, 2009, we had available liquidity of $1,121.3 million, including cash and cash
equivalents of $465.9 million, marketable securities of $119.0 million and $536.4 million of unused
revolving credit facility commitments available under the Alpha Credit Facility (after giving
effect to $113.6 million of letters of credit outstanding as of December 31, 2009), subject to
limitations described in that agreement. Our total long-term debt, including discount, was $790.3
million at December 31, 2009, see “—Credit Agreement and Long-Term Debt.”
We sponsor pension plans in the United States for salaried and non-union hourly employees. For
these plans, the Pension Protection Act of 2006 (“Pension Act”) requires a funding target of 100%
of the present
value of accrued benefits. The Pension Act includes a funding target phase-in provision that
establishes a funding target of 92% in 2008, 94% in 2009, 96% in 2010 and 100% thereafter for
defined benefit pension plans. Generally, any such plan with a funding ratio of less than 80% will
be deemed at risk and will be subject to additional funding requirements under the Pension Act.
Annual funding contributions to the plans are made as recommended by consulting actuaries based
upon the ERISA funding standards. Plan assets consist of equity and fixed income funds, real estate
funds, private equity funds and alternative investment funds. We are required to measure plan
assets and benefit obligations as of the date of our fiscal year-end statement of financial
position and recognize the overfunded or underfunded status of a defined benefit pension and other
postretirement plans (other than a multi-employer plan) as an asset or liability in its statement
of financial position and recognize changes in that funded status in the year in which the changes
occur through other comprehensive (loss) income. As of December 31, 2009, our annual measurement
date, our salaried and hourly pension plans were underfunded by $86.5 million. The recent economic
environment and continued uncertainty in the equity markets have caused investment income and the
value of investment assets held in our pension trust to decline. These investment assets have not
yet fully recovered from the loss in value experienced in the fourth fiscal quarter of 2008. As a
result, we may be required to increase the amount of cash contributions into the pension trust in
order to comply with the funding requirements of the Pension Act.
In 2010 we expect to contribute approximately $30.0 million to our defined benefit retirement
plans and pay approximately $29.5 million of retiree health care benefits, gross of Medicare Part D
subsidies.
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In connection with the Merger, we assumed the obligations for a federal coal lease, which
contains an estimated 224.0 million tons of proven and probable coal reserves in the Powder River
Basin. The original lease bonus bid was $180.5 million, payable in five equal annual installments
of $36.1 million. The first
two installments were paid in 2009 and 2008 by Foundation. The three remaining annual
installments of $36.1 million each are due on May 1, the anniversary date of the lease.
With respect to global economic events, there continues to be uncertainty in the financial
markets and this uncertainty brings potential liquidity risks to the Company. Such risks include
additional declines in our stock value, less availability and higher costs of additional credit,
potential counterparty defaults and further commercial bank failures. Although the majority of the
financial institutions in our bank credit facility appear to be strong, there are no assurances of
their continued existence. However, we have no current indication that any such uncertainties would
impact our current credit facility. The credit worthiness of our customers is constantly monitored
by us. We believe that our current group of customers are sound and represent no abnormal business
risk.
Accounts Receivable Securitization
On March 25, 2009, Old Alpha and certain subsidiaries became parties to an $85.0 million
accounts receivable securitization facility with a third party financial institution (the “A/R
Facility”) by forming ANR Receivables Funding, LLC (the “SPE”), a special-purpose,
bankruptcy-remote subsidiary, wholly-owned indirectly by Old Alpha. The sole purpose of the SPE is
to purchase trade receivables generated by certain of our operating and sales subsidiaries, without
recourse (other than customary indemnification obligations for breaches of specific representations
and warranties), and then transfer senior undivided interests in up to $85.0 million of those
accounts receivable to a financial institution for the issuance of letters of credit or for cash
borrowings for our ultimate benefit.
The SPE is consolidated into our financial statements, and therefore the purchase and sale of
trade receivables by the SPE from our operating and sales receivables has no impact on our
consolidated financial statements. The assets of the SPE, however, are not available to the
creditors of us or any other subsidiary. The SPE pays facility fees, program fees and letter of
credit fees (based on amounts of outstanding letters of credit), as defined in the definitive
agreements for the A/R Facility. Available borrowing capacity is based on the amount of eligible
accounts receivable as defined under the terms of the definitive agreements for the A/R Facility
and varies over time. Unless extended by the parties, the receivables purchase agreement supporting
the borrowings under the A/R Facility expires on December 9, 2015, or earlier upon the occurrence
of certain events customary for facilities of this type, including the
failure for any reason by liquidity providers to the A/R Facility’s financial institutions to
renew their commitments not less often than annually.
On December 9, 2009, the receivables purchase agreement was amended to increase the A/R
Facility from $85.0 million to $150.0 million.
As of December 31, 2009, letters of credit in the amount $143.5 million were outstanding under
the A/R Facility and no cash borrowing transactions had taken place. If outstanding letters of
credit exceed borrowing capacity, we are required to provide additional collateral in the form of
restricted cash to secure outstanding letters of credit. Under the A/R Facility, the SPE is
subject to certain affirmative, negative and financial covenants customary for financings of this
type, including restrictions related to, among other things, liens, payments, merger or
consolidation and amendments to the agreements underlying the receivables pool. Alpha Natural
Resources, Inc. has agreed to guarantee the performance by its subsidiaries, other than the SPE, of
their obligations under the A/R Facility. We do not guarantee repayment of the SPE’s debt under the
A/R Facility. The financial institution, which is the administrator, may terminate the A/R Facility
upon the occurrence of certain events that are customary for facilities of this type (with
customary grace periods, if applicable), including, among other things, breaches of covenants,
inaccuracies of representations and warranties, bankruptcy and insolvency events, changes in the
rate of default or delinquency of the receivables above specified levels, a change of control and
material judgments. A termination event would permit the administrator to terminate the program and
enforce any and all rights and remedies, subject to cure provisions, where applicable.
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Cash Flows
Cash and cash equivalents decreased by $210.3 million for the year ended December 31, 2009,
and increased $621.8 million for the year ended December 31, 2008. The net change in cash and cash
equivalents was attributable to the following:
Our primary sources of liquidity have been from sales of our coal production; borrowings under
our credit facility (see “—Credit Agreement and Long-Term Debt”), sales of our common stock, and
to a much lesser extent, sales of purchased coal to customers, sales of non-core assets and
miscellaneous revenues.
Our primary uses of cash have been our cash production costs, capital expenditures, interest
costs, cash payments for employee benefit obligations such as retiree health care benefits, cash
payments related to our reclamation obligations and support of working capital requirements such as
coal inventories and trade accounts payable. Our ability to service debt and acquire new
productive assets for use in our operations has been and will be dependent upon our ability to
generate cash from our operations. We generally fund all of our capital expenditure requirements
with cash generated from operations. Historically, we have engaged in minimal financing of assets
such as through operating leases.
Net cash provided by operating activities, including discontinued operations, during 2009 was
$356.2 million, a decrease of $101.8 million from the $458.0 million of net cash provided by
operations during 2008. This decrease was driven by a decrease in our net income, mainly
attributable to increased selling, general and administrative expenses for consulting and
professional services fees, integration-related expenses and severance and relocation-related costs
associated with the Merger with Foundation. An increase in interest expense of $43.0 million in
2009 as compared to 2008 was primarily related to payments on our term loan and revolving line of
credit, the de-designation of the interest rate swap as a cash flow hedge, and amortization of
convertible debt. The increase in non-cash charges and credits of $160.9 million was mainly driven
by a $127.6 million increase in amortization of acquired coal supply agreements, net, and an $81.2
million increase in depreciation, depletion and amortization, which was partially offset by the
fair value of derivative instruments, mine closure charges and deferred income taxes. The decrease
in operating assets and liabilities in 2009 as compared to 2008 primarily related to the $38.6
million increase in prepaid expenses and other current assets, the decrease in trade accounts
payable of $41.1 million, pension and postretirement medical benefit obligations of $37.4 million,
and accrued expenses and other current liabilities of $36.2 million. Net cash provided by (used
in) operating activities from our discontinued operations during 2009 and 2008 was $1.6 million and
($10.8) million, respectively.
Net cash used in investing activities, including discontinued operations, during 2009 was
$281.8 million, an increase of $204.2 million from the $77.6 million of net cash used in investing
activities during 2008. The increase in 2009 was primarily due to the purchases of marketable
securities of $119.4 million, an increase in capital expenditures of $49.3 million, and the absence
of proceeds in 2009 that occurred in 2008 from the sale of Gallatin. The increase in net cash used
in investing activities was partially offset by the $23.5 million of cash acquired from the Merger
with Foundation. Cash provided by (used in) investing activities from our discontinued operations
during 2009 and 2008 was $0.3 million and ($13.4 million), respectively, which was primarily derived
from proceeds of the disposition of property, plant and equipment in 2009 and the outlay for
capital expenditures in 2008.
Net cash used in financing activities, including discontinued operations, during 2009 was
$284.7 million, compared to $241.4 million of net cash provided by financing activities in 2008.
This decrease was primarily due to the concurrent offerings in April 2008 of our common stock and
the convertible notes, offset by principal payments on our long-term debt and principal repayments
of our note payable. In 2009, shortly after the Merger, we voluntarily repaid our term loan in the
amount of $233.1 million.
Net cash provided by operating activities, including discontinued operations, during 2008 was
$458.0 million, an increase of $232.3 million from $225.7 million of net cash provided by
operations during 2007. This increase was driven by an increase in our net income attributable to
Alpha Natural Resources, Inc. of $138.0 million, an increase in the change from 2007 to 2008 in
non-cash charges and credits included in net income in the amount of $90.6 million and an increase
in cash provided from changes in operating assets and liabilities of $3.7
million. The increase in our net income was mainly due to an increase in our coal margin per
ton of $7.63 and a $56.3 million, pre-tax, merger termination fee received from Cliffs Natural
Resources. The increase in non-cash charges and credits was mainly driven by a $56.2 million
increase in the change in the fair value of derivative instruments from 2007 to 2008, and $34.7
million related to mine closure and asset impairment charges included in discontinued operations.
Net cash used in operating activities from our discontinued operations during 2008 and 2007 was
$10.8 million and $1.4 million, respectively, which is included within net cash provided by
operating activities in the consolidated statements of cash flows.
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In connection with the termination of the proposed merger with Cliffs in November 2008, Cliffs
paid Old Alpha a fee of $70.0 million. Net of fees paid to our financial advisor, legal and other
professional fees and expenses, the gain recognized on the termination fee of the Cliffs proposed
merger was approximately $56.3 million. This is included in our cash provided by operating
activities on our consolidated statements of cash flows for the year ended December 31, 2008. We
have not received any similar fees in recent prior years and do not anticipate receiving similar
fees in the future.
Net cash used in investing activities, including discontinued operations, during 2008 was
$77.6 million, a decrease of $87.6 million from the $165.2 million of net cash used in investing
activities during 2007. The decrease was primarily due to proceeds from the sale of Gallatin in
the amount of $45.0 million and a $10.5 million increase in proceeds from the disposal of property,
plant, equipment and investments over the prior year, primarily resulting from the Kentucky May
sale, partially offset by an increase in capital expenditures of $11.4 million and a decrease in
cash used to acquire Mingo Logan in 2007 of $43.9 million. Cash used in investing activities from
our discontinued operations during 2008 and 2007 was $13.4 million and $30.5 million, respectively,
which was primarily used for capital expenditures.
Net cash provided by financing activities, including discontinued operations, during 2008 was
$241.4 million, an increase of $280.8 million from the $39.4 million of net cash used in financing
activities during 2007. The increase was primarily due to the concurrent offerings of our common
stock and our convertible notes, which generated net proceeds of $443.3 million after commissions
and expenses, of which a portion was used to repurchase the $175.0 million aggregate principal
amount of 10% senior notes due 2012. Net cash (used in) provided by financing activities from our
discontinued operations during the year ended December 31, 2008 and 2007 were ($2.1) million, which
includes the $17.5 million for the repayment of our Gallatin loan facility, and $40.1 million,
respectively.
Credit Agreement and Long-term Debt
As of December 31, 2009, our total long-term indebtedness consisted of the following (in
thousands):
Old Alpha Credit Agreement
On July 31, 2009, in conjunction with the Merger, Old Alpha terminated its existing senior
secured credit facilities (the “Old Alpha Credit Agreement”), which consisted of a $250.0 million
term loan facility, of which $233.1 million was outstanding at July 31, 2009 (and due in 2012), and
a $375.0 million revolving credit facility. On July 31, 2009, we repaid the outstanding balance
under the term loan and recorded a $5.6 million loss on early extinguishment of debt to write off
the remaining balance of deferred loan costs.
Alpha Credit Facility
Prior to the Merger, Foundation had a credit facility (the “Foundation Credit Facility”),
consisting of a $500.0 million secured revolving credit line and a $335.0 million secured term
loan. Repayment of outstanding indebtedness owed under the Foundation Credit Facility includes
quarterly amortization of the term loan, which began in the third quarter of 2007, with both the
term loan and revolving credit line maturing July 7, 2011.
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In connection with the Merger, the Foundation Credit Facility was amended to add Alpha, Old
Alpha and substantially all of its subsidiaries as guarantors (“Alpha Credit Facility”). This
amendment also provides for an increase in the interest rate to 3.25 percentage points over the
London interbank offered rate (“LIBOR”) from 1.25 percentage points over LIBOR, subject, in the
case of revolving loans, to adjustment based on leverage ratios. Following the Merger and upon the
amendment becoming effective, limitations on annual capital expenditure amounts were eliminated and
the amount of the “accordion” feature of the Alpha Credit Facility, pursuant to which we may
request the lenders to provide incremental credit facilities under the Alpha Credit Facility, was
increased from $100.0 million to $200.0 million, of which $150.0 million was utilized to increase
the revolving credit line to $650.0 million. As of December 31, 2009, our term loan due 2011 under
the Alpha Credit Facility had an outstanding balance of $282.7 million, net of debt discount of
$2.0 million. The current portion of the term loan due in the next twelve months was $33.5 million
The Alpha Credit Facility places certain restrictions on us. See “—Analysis of Material Debt
Covenants.”
2.375% Convertible Senior Notes Due June 2015
Old Alpha issued its 2.375% convertible senior notes due 2015 with an aggregate principal
amount of $287.5 million (the “Convertible Notes”) under an indenture dated as of April 7, 2008, as
supplemented. Following completion of the Merger, we assumed Old Alpha’s obligations in respect of
the Convertible Notes by executing a supplemental indenture, dated as of July 31, 2009, among Old
Alpha, as issuer, Alpha, as successor issuer, and Union Bank of California (“UBOC”), as trustee.
As of December 31, 2009, we had $287.5 million aggregate principal amount of Convertible Notes
outstanding.
The Convertible Notes are our senior unsecured obligations and rank equally with all of our
existing and future senior unsecured indebtedness. The Convertible Notes are effectively
subordinated to all of our existing and future secured indebtedness and all existing and future
liabilities of our subsidiaries, including trade payables. The Convertible Notes bear interest at a
rate of 2.375% per annum, payable semi-annually in arrears on April 15 and October 15 of each year,
which began on October 15, 2008 and will mature on April 15, 2015, unless previously repurchased by
us or converted. The Convertible Notes are convertible in certain circumstances and in specified
periods at an initial conversion rate of 18.2962 shares of common stock per $1,000 principal amount
of Convertible Notes, subject to adjustment upon the occurrence of certain events set forth in the
Indenture. Upon conversion of the Convertible Notes, holders will receive cash up to the principal
amount of the notes to be converted, and any excess conversion value will be delivered in cash,
shares of common stock, or a combination thereof, at our election.
The indenture governing the Convertible Notes contains customary terms and covenants,
including that upon certain events of default occurring and continuing, either UBOC or the holders
of not less than 25% in aggregate principal amount of the Convertible Notes then outstanding may
declare the principal of Convertible Notes and any accrued and unpaid interest thereon immediately
due and payable. In the case of certain events of bankruptcy, insolvency or reorganization relating
to Alpha, the principal amount of the Convertible Notes together with any accrued and unpaid
interest thereon will automatically become due and immediately payable.
As a result of the Merger, the Convertible Notes became convertible at the option of the
holders beginning on June 18, 2009, and remained convertible through the 30th day after the
effective date of the Merger, which was July 31, 2009. However, no notes were converted during the
conversion period. The Convertible Notes were not convertible as of December 31, 2009 and as a
result have been classified as long-term debt.
7.25% Senior Notes Due August 1, 2014
In connection with the Merger, we assumed $298.3 million aggregate principal amount of 7.25%
senior notes guaranteed on a senior unsecured basis by Foundation Coal Corporation (“FCC”), an
indirect parent of the issuer, Foundation PA Coal Company, LLC (“Foundation PA”), and certain of
its subsidiaries. The notes pay interest semi-annually and are redeemable at the Company’s option,
at a redemption price equal to 103.625%, 102.417%, 101.208% and 100%
of the principal amount if redeemed during the twelve month periods
beginning August 1, 2009, 2010, 2011 and 2012, respectively, plus accrued interest. The notes mature
on August 1, 2014 (the “2014 Notes”). As a result of the Merger, Foundation PA and FCC became our
subsidiaries.
On July 31, 2009, in connection with the Merger, Alpha and certain of its subsidiaries
executed a supplemental indenture pursuant to which we assumed the obligations of FCC in respect of
the 2014 Notes and, along with such subsidiaries, became obligated as guarantors on the indenture
governing the 2014 Notes. On August 1, 2009, in connection with the Merger, FCC merged with and
into Alpha. As of December 31, 2009, the outstanding balance of the 2014 Notes was $297.0 million,
which is net of the debt discount of $1.3 million.
The indenture governing the 2014 Notes places certain restrictions on Alpha. See “—Analysis
of Material Debt Covenants.”
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Analysis of Material Debt Covenants
We were in compliance with all covenants under the Alpha Credit Facility and the indenture
governing the 2014 Notes as of December 31, 2009. A breach of the covenants in the Alpha Credit
Facility or the 2014 Notes, including the financial covenants under the Alpha Credit Facility that
measure ratios based on Adjusted EBITDA, could result in a default under the Alpha Credit Facility
or the 2014 Notes and the respective lenders and noteholders could elect to declare all amounts
borrowed due and payable. Any acceleration under either the Alpha Credit Facility or the 2014
Notes would also result in a default under the indenture governing our Convertible Notes.
Additionally, under the Alpha Credit Facility and the 2014 Notes, our ability to engage in
activities such as incurring additional indebtedness, making investments and paying dividends is
also tied to ratios based on Adjusted EBITDA.
Covenants and required levels set forth in the Alpha Credit Facility are:
Adjusted EBITDA is defined as EBITDA further adjusted to exclude certain non-cash items,
non-recurring items, and other adjustments permitted in calculating covenant compliance under the
Alpha Credit Facility. EBITDA, a measure used by management to evaluate its ongoing operations for
internal planning and forecasting purposes, is defined as net income (loss) from operations plus
interest expense, income tax expense, amortization of acquired coal supply agreements and
depreciation, depletion and amortization, less interest income and income tax benefit. EBITDA is
not a financial measure recognized under United States generally accepted accounting principles and
does not purport to be an alternative to net income as a measure of operating performance or to
cash flows from operating activities as a measure of liquidity. The amounts shown for EBITDA as
presented may differ from amounts calculated and may not be comparable to other similarly titled
measures used by other companies.
Certain non-cash items that may adjust EBITDA in the compliance calculation are: (a) accretion
on asset retirement obligations; (b) amortization of intangibles; (c) any long-term incentive plan
accruals or any non-cash compensation expense realized from grants of stock appreciation or similar
rights, stock options or other rights to officers, directors and employees; and (d) gains or losses
associated with the change in fair value of derivative instruments. Certain non-recurring items
that may adjust EBITDA in the compliance calculation are: (a) business optimization expenses or
other restructuring charges; (b) non-cash impairment charges; (c) certain non-cash expenses or
charges arising as a result of the application of acquisition accounting; (d) non-cash charges
associated with loss on early extinguishment of debt; and (e) charges associated with litigation,
arbitration, or contract settlements. Certain other items that may adjust EBITDA in the compliance
calculation are: (a) after-tax gains or losses from discontinued operations; (b) franchise taxes;
and (c) other non-cash expenses that do not represent an accrual or reserve for future cash
expense.
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The Alpha Credit Facility requires us to use pro forma results for the calculation of adjusted
EBITDA representative of a four quarter rolling total. The pro forma four quarter rolling EBITDA
total is comprised of the historical results of Old Alpha, adjusted for the pro forma EBITDA
results of Foundation calculated in accordance with the Alpha Credit Facility for the quarters
ended March 31, 2009 and June 30, 2009, plus EBITDA of Alpha for the quarters ended September 30,
2009 and December 31, 2009. Pro forma EBITDA is then adjusted for the items described above based
on the same pro forma methodology for EBITDA to derive adjusted EBITDA. The calculation of
adjusted EBITDA shown below is based on our pro-forma results of operations in accordance with the
Alpha Credit Facility and therefore, is different from EBITDA presented elsewhere in this Annual
Report on Form 10-K.
Cash interest is calculated in accordance with the Alpha Credit Facility and is equal to
interest expense less interest income and non-cash interest expense. Cash interest for the twelve
months ended December 31, 2009 has been calculated from the results of Old Alpha, adjusted for the
pro forma results of Foundation, for the quarters ended March 31, 2009 and June 30, 2009, and the
results of Alpha for the quarters ended September 30, 2009 and December 31, 2009.
Cash interest for the twelve months ended December 31, 2009 is calculated as follows (in thousands):
If certain circumstances exist where all of our $287.5 million aggregate principal amount of
Convertible Notes were converted at the option of the holders, we believe we would have adequate
liquidity to satisfy the obligations for the Convertible Notes and remain in compliance with any
required covenants
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Off-Balance Sheet Arrangements
In the normal course of business, we are a party to certain off-balance sheet arrangements.
These arrangements include guarantees, operating leases, indemnifications and financial instruments
with off-balance sheet risk, such as bank letters of credit and performance or surety bonds.
Liabilities related to these arrangements are not reflected in our Consolidated Balance Sheets.
However, the underlying obligations that they secure, such as asset retirement obligations,
self-insured workers’ compensation liabilities, royalty obligations and certain retiree medical
obligations, are reflected in our Consolidated Balance Sheets.
We are required to provide financial assurance in order to perform the post-mining reclamation
required by our mining permits, pay our federal production royalties, pay workers’ compensation
claims under self-insured workers’ compensation laws in various states, pay federal black lung
benefits, pay retiree health care benefits to certain retired UMWA employees and perform certain
other obligations.
In order to provide the required financial assurance, we generally use surety bonds for
post-mining reclamation and bank letters of credit for self-insured workers’ compensation
obligations and UMWA retiree health care obligations. Federal black lung benefits are paid from a
dedicated trust fund to which future contributions will be required. Bank letters of credit are
also used to collateralize a portion of the surety bonds.
We had outstanding surety bonds with a total face amount of $507.8 million as of December 31,
2009 to secure various obligations and commitments. In addition, we had $257.1 million of letters
of credit in place, of which $113.6 million was outstanding under the Alpha Credit Facility, and
$143.5 million was outstanding under our A/R Facility. These outstanding letters of credit served
as collateral for workers’ compensation bonds, reclamation surety bonds, secured UMWA retiree
health care obligations, and other miscellaneous obligations. In the event that additional surety
bonds become unavailable, we would seek to secure our obligations with letters of credit, cash
deposits or other suitable forms of collateral.
Other
As a regular part of our business, we review opportunities for, and engage in discussions and
negotiations concerning, the acquisition of coal mining assets and interests in coal mining
companies, and acquisitions of, or combinations with, coal mining companies. When we believe that
these opportunities are consistent with our growth plans and our acquisition criteria, we will make
bids or proposals and/or enter into letters of intent and other similar agreements. These bids or
proposals, which may be binding or nonbinding, are customarily subject to a variety of conditions
and usually permit us to terminate the discussions and any related agreement if, among other
things, we are not satisfied with the results of our due diligence investigation. Any acquisition
opportunities we pursue could materially affect our liquidity and capital resources and may require
us to incur indebtedness, seek equity capital or both. There can be no assurance that additional
financing will be available on terms acceptable to us, or at all.
Contractual Obligations
The following is a summary of our significant contractual obligations as of December 31, 2009
(in thousands):
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Additionally, we have long-term liabilities relating to asset retirement obligations,
postretirement, pension, workers’ compensation and black lung benefits. The table below reflects
the estimated undiscounted cash flows for these obligations (in thousands):
Critical Accounting Policies and Estimates
Our discussion and analysis of our financial condition, results of operations, liquidity and
capital resources is based upon our consolidated financial statements, which have been prepared in
accordance with U.S. generally accepted accounting principles (“GAAP”). GAAP requires that we make
estimates and judgments that affect the reported amounts of assets, liabilities, revenues and
expenses, and related disclosure of contingent assets and liabilities. On an ongoing basis, we
evaluate our estimates. We base our estimates on historical experience and on various other factors
and assumptions, including the current economic environment that we believe are reasonable under
the circumstances, the results of which form the basis for making judgments about the carrying
values of assets and liabilities that are not readily apparent from other sources. We adjust such
estimates and assumptions as facts and circumstances require. Illiquid credit markets, volatile
equity, foreign currency, and energy markets and declines in demand for steel products due to the
current economic environment have combined to increase the uncertainty inherent in such estimates
and assumptions. As future events and their effects cannot be determined with precision, actual
results may differ significantly from these estimates. Changes in these estimates resulting from
continuing changes in the economic environment will be reflected in the financial statements in
future periods.
Derivatives Instruments and Hedging Activities. We are subject to the risk of price volatility
for certain of the materials and supplies used in production, such as diesel fuel and explosives.
As a part of our risk management strategy, we enter into pay fixed, receive variable swap
agreements with financial institutions to mitigate the risk of price volatility for both diesel
fuel and explosives. Swap agreements are derivative instruments that we are required to recognize
as either assets or liabilities in the statement of financial position and measure those
instruments at fair value. The accounting requirements for derivatives are complex and judgment is
required in certain areas such as cash flow hedge accounting and hedge effectiveness testing. We
assess each swap agreement to determine whether or not it qualifies for special cash flow hedge
accounting. In performing the assessment, we make estimates and assumptions about the timing and
amounts of future cash flows related to the forecasted purchases of diesel fuel and explosives. We
update our assessments at least on a quarterly basis.
Reclamation. Our asset retirement obligations arise from the federal Surface Mining Control
and Reclamation Act of 1977 and similar state statutes, which require that mine property be
restored in accordance with specified standards and an approved reclamation plan. Significant
reclamation activities include reclaiming refuse and slurry ponds, reclaiming the pit and support
acreage at surface mines, and sealing portals at deep mines. We determine the future cash flows
necessary to satisfy our reclamation obligations on a mine-by-mine basis based upon current permit
requirements and various estimates and assumptions, including estimates of disturbed acreage, cost
estimates, and assumptions regarding productivity. Estimates of disturbed acreage are determined
based on approved mining plans and related engineering data. Cost estimates are based upon
third-party costs. Productivity assumptions are based on historical experience with the equipment
that is expected to be utilized in the reclamation activities. Our asset retirement obligations are
initially recorded at fair value, or the amount at which obligations could be settled in a current
transaction between willing third parties. In order to determine fair value, we must also estimate
a discount rate and third-party margin. Each is discussed further below:
On at least an annual basis, we review our entire reclamation liability and make necessary
adjustments for permit changes as granted by state authorities, additional costs resulting from
accelerated mine closures, and revisions to cost estimates and productivity assumptions, to reflect
current experience. At December 31, 2009, we had recorded asset retirement obligation liabilities
of $205.6 million, including amounts reported as current. While the precise amount of these future
costs cannot be determined with certainty, as of December 31, 2009, we estimate that the aggregate
undiscounted cost of final mine closures is approximately $381.5 million.
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Coal Reserves. There are numerous uncertainties inherent in estimating quantities of
economically recoverable coal reserves, many of which are beyond our control. As a result,
estimates of economically recoverable coal reserves are by their nature uncertain. Information
about our reserves consists of estimates based on engineering, economic and geological data
assembled by our internal engineers and geologists and reviewed by a third party consultant. Some
of the factors and assumptions that impact economically recoverable reserve estimates include:
Each of these factors may in fact vary considerably from the assumptions used in estimating
reserves. For these reasons, estimates of the economically recoverable quantities of coal
attributable to a particular group of properties, and classifications of these reserves based on
risk of recovery and estimates of future net cash flows, may vary substantially. Actual production,
revenues and expenditures with respect to reserves will likely vary from estimates, and these
variances may be material. Variances could affect our projected future revenues and expenditures,
as well as the valuation of coal reserves and depletion rates. At December 31, 2009, we had
1,268.6 million tons of proven and probable coal reserves assigned to our active operations.
Postretirement Medical Benefits. We have long-term liabilities for postretirement medical
benefit cost obligations. Detailed information related to these liabilities is included in Note 16
to the Consolidated Financial Statements included elsewhere in this Annual Report on Form 10-K.
Liabilities for postretirement benefit costs are not funded. The liability is actuarially
determined, and we use various actuarial assumptions, including the discount rate and future health
care cost trends, to estimate the costs and obligations for postretirement benefit costs. The
discount rate used to determine the net periodic benefit cost for postretirement benefits other
than pensions was 5.83% for Foundation and 6.17% for legacy Alpha for the year ended December 31,
2009. At December 31, 2009, we had total postretirement medical benefit obligations of $614.4
million.
Retirement Plans. We assumed two non-contributory defined benefit retirement plans from
the Merger covering certain of our salaried and non-union hourly employees. We also have an
unfunded non-qualified Supplemental Executive Retirement Plan covering certain eligible employees.
Benefits are based on either the employee’s compensation prior to retirement or stated amounts for
each year of service with us. Funding of the defined benefit retirement plans is in accordance with
the requirements of ERISA, which can be deducted for federal income tax purposes. We contributed
$22.7 million to our defined benefit retirement plans for the five months ended December 31, 2009.
For the five months ended December 31, 2009, we recorded pension expense of $4.7 million.
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The calculation of the net periodic benefits costs (pension expense) and projected benefit
obligation associated with our defined benefit pension plans requires the use of a number of
assumptions that we deem to be “critical accounting estimates.” These assumptions are used by our
independent actuaries to make the underlying calculations. Changes in these assumptions can result
in different pension expense and liability amounts, and actual experience can differ from the
assumptions.
Workers’ Compensation. Workers’ compensation is a system by which individuals who sustain
personal injuries due to job-related accidents are compensated for their disabilities, medical
costs, and on some occasions, for the costs of their rehabilitation, and by which the survivors of
workers who suffer fatal injuries receive compensation for lost financial support. The workers’
compensation laws are administered by state agencies with each state having its own set of rules
and regulations regarding compensation that is owed to an employee who is injured in the course of
employment. Our operations are covered through a combination of a self-insurance program and
insurance policies. We accrue for any self-insured liability by recognizing costs when it is
probable that a covered liability has been incurred and the cost can be reasonably estimated. Our
estimates of these costs are adjusted based upon actuarial studies. Actual losses may differ from
these estimates, which could increase or decrease our costs. At December 31, 2009, we had workers’
compensation obligations of $43.9 million.
Coal Workers’ Pneumoconiosis. We are required by federal and state statutes to provide
benefits to employees for awards related to coal workers’ pneumoconiosis disease (black lung). Old
Alpha subsidiaries are insured for workers’ compensation and black lung obligations by a
third-party insurance provider in all locations with the exception of West Virginia, where certain
Old Alpha subsidiaries are self-insured for workers’ compensation and state black lung obligations.
Due to the Merger, the Company assumed the workers’ compensation and black lung obligations of the
Foundation subsidiaries (the “Foundation subsidiaries”). The Foundation subsidiaries acquired in
the Merger are self-insured for black lung benefits and fund benefit payments through a Section
501(c)(21) tax-exempt trust fund. Provisions are made for estimated benefits based on annual
evaluations prepared by independent actuaries. The Foundation subsidiaries are also self-insured
for worker’s compensation benefits with the exception of Wyoming where the Company participates in
a compulsory state-run fund.
Charges are made to operations for self-insured black lung claims, as determined by an
independent actuary at the present value of the actuarially computed liability for such benefits
over the employee’s applicable term of service. As of December 31, 2009, we had black lung
obligations of $30.3 million, which are net of assets of $4.3 million that are held in a tax exempt
trust fund.
Business Combinations. We account for our business combinations under the acquisition method
of accounting. The total cost of acquisitions is allocated to the underlying identifiable net
tangible and intangible assets, based on their respective estimated fair values. Determining the
fair value of assets acquired and liabilities assumed requires management’s judgment, and the
utilization of independent valuation experts, and often involves the use of significant estimates
and assumptions with respect to the timing and amounts of future cash inflows and outflows,
discount rates, market prices and asset lives, among other items.
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Income Taxes. We recognize deferred tax assets and liabilities using enacted tax rates for the
effect of temporary differences between the book and tax bases of recorded assets and liabilities.
Deferred tax assets are reduced by a valuation allowance if it is more likely than not that some
portion or all of the deferred tax asset will not be realized. In evaluating the need for a
valuation allowance, we analyze both positive and negative evidence. Such evidence includes
objective evidence obtained from our historical earnings, future sales commitments, outlooks on the
coal industry by us and third parties, expected level of future earnings (with sensitivities on
expectations considered), timing of temporary difference reversals, ability or inability to meet
forecasted earnings, unsettled industry circumstances, ability to carry back and utilize a future
tax loss (if a loss were to occur), available tax planning strategies, limitations on deductibility
of temporary differences, and the impact the alternative minimum tax has on utilization of deferred
tax assets. The valuation allowance is monitored and reviewed quarterly. If our
conclusions change in the future regarding the realization of a portion or all of our net
deferred tax assets, we may record a change to the valuation allowance through income tax expense
in the period the determination is made, which may have a material impact on our results. As of
December 31, 2009, we were in a net deferred tax liability position with tax computed at regular
tax rates on the gross temporary differences. Federal tax attributes related to minimum tax credit
carry-forwards and federal and state net operating losses offset the tax effect of the temporary
differences somewhat. A valuation allowance of $10.9 million has been provided on certain state
net operating losses not expected to provide future tax benefits.
Goodwill. Goodwill represents the excess of the purchase price over the fair value of the net
assets of acquired companies. We estimate the fair value of goodwill using a number of factors,
including the application of multiples and discounted cash flow estimates. Goodwill is not
amortized; instead, it is tested for impairment annually or more frequently if indicators of
impairment exist. On an ongoing basis, absent any impairment indicators, we perform our goodwill
impairment testing as of August 31 of each year.
We test consolidated goodwill for impairment using a fair value approach at the reporting unit
level. We perform our goodwill impairment test in two steps. Step one compares the fair value of
each reporting unit to its carrying amount. If step one indicates that an impairment potentially
exists, the second step is performed to measure the amount of impairment, if any. Goodwill
impairment exists when the estimated fair value of goodwill is less than its carrying value.
For purposes of our step one analysis, our estimate of fair value for each reporting unit is
based on discounted cash flows (the income approach). Under the income approach, the fair value of
each reporting unit is based on the present value of estimated future cash flows. The income
approach is dependent on a number of significant management assumptions including markets, sales
volumes and prices, costs to produce, capital spending, working capital changes and the discount
rate. The discount rate is commensurate with the risk inherent in the projected cash flows and
reflects the rate of return required by an investor in the current economic conditions.
Goodwill was $357.9 million as of December 31, 2009 and of that amount, $337.3 million was
acquired on July 31, 2009 in connection with the Merger (Note 20). Due to the short period of time
between the Merger and the annual impairment testing date and the absence of any impairment
indicators between the date of acquisition and August 31, 2009 related to the goodwill acquired,
the Company did not test the newly acquired goodwill for impairment. The Company’s annual goodwill
impairment review performed on August 31, 2009 for the remaining $20.5 million supported its
carrying value.
New Accounting Pronouncements Issued and Not Yet Adopted
In June 2009, the FASB issued Statement of Financial Accounting Standards No. 167, Amendments
to FASB Interpretation No. 46(R), which modifies how a company determines when an entity that is
insufficiently capitalized or is not controlled through voting (or similar rights) should be
consolidated. The guidance clarifies that the determination of whether a company is required to
consolidate an entity is based on, among other things, an entity’s purpose and design and a
company’s ability to direct the activities of the entity that most significantly impact the
entity’s economic performance. The guidance requires an ongoing reassessment of whether a company
is the primary beneficiary of a variable interest entity. It also requires additional disclosures
about a company’s involvement in variable interest entities and any significant changes in risk
exposure due to that involvement. The guidance is applicable for annual periods beginning after
November 15, 2009 (January 1, 2010 for the Company). The Company is currently evaluating the
effect, if any, the guidance will have on its results of operations and financial condition.
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Commodity Price Risk
We manage our commodity price risk for coal sales through the use of long-term coal supply
agreements. As of February 8, 2010, we had sales commitments for approximately 97% of planned
shipments for 2010. Uncommitted and unpriced tonnage was 3%, 25% and 62% for 2010, 2011 and 2012,
respectively. The discussion below presents the sensitivity of the market value of selected
financial instruments to selected changes in market rates and prices. The range of changes reflects
our view of changes that are reasonably possible over a one-year period. Market values are the
present value of projected future cash flows based on the market rates and prices chosen.
We have exposure to price risk for supplies that are used directly or indirectly in the normal
course of production such as diesel fuel, steel and other items such as explosives. We manage our
risk for these items through strategic sourcing contracts in normal quantities with our suppliers
and may use derivative instruments from time to time, primarily swap contracts with financial
institutions, for a certain percentage of our monthly requirements. Swap agreements essentially fix
the price paid for our diesel fuel and explosives by requiring us to pay a fixed price and receive
a floating price.
We expect to use approximately 40,051 tons of explosives in 2010. Through our derivative swap
contracts, we have fixed prices for approximately 71% of our expected explosive needs 2010,
respectively. If the price of natural gas were to decrease in 2010, our expense resulting from our
natural gas derivatives would increase, which would be largely offset by a decrease in the cost of
our physical explosive purchases.
We expect to use approximately 46,504,033 gallons and 46,963,628 gallons of diesel fuel in
2010 and 2011, respectively. Through our derivative swap contracts, we have fixed prices for
approximately 73% and 43% of our expected diesel fuel needs for 2010 and 2011, respectively. If the
price of diesel fuel were to decrease in 2010, our expense resulting from our diesel fuel
derivative swap contracts would increase, which would be offset by a decrease in the cost of our
physical diesel fuel purchases.
Credit Risk
Our credit risk is primarily with electric power generators and steel producers. Our policy is
to independently evaluate each customer’s creditworthiness prior to entering into transactions and
to constantly monitor outstanding accounts receivable against established credit limits. When
appropriate (as determined by our credit management function), we have taken steps to reduce our
credit exposure to customers that do not meet our credit standards or whose credit has
deteriorated. These steps include obtaining letters of credit or cash collateral, requiring
prepayments for shipments or establishing customer trust accounts held for our benefit in the event
of a failure to pay.
Interest Rate Risk
Our objectives in managing exposure to interest rate changes are to limit the impact of
interest rate changes on earnings and cash flows and to lower overall borrowing costs. As we
continue to monitor the interest rate environment in concert with our risk mitigation objectives,
consideration is being given to future interest rate risk reduction strategies.
We have exposure to changes in interest rates through our Alpha Credit Facility, which has a
variable interest rate of 3.25 percentage points over the London interbank offered rate (“LIBOR”),
subject, in the case of the revolving credit line, to adjustment based on leverage ratios. As of
December 31, 2009, our term loan due 2011 under the Alpha Credit Facility had an outstanding
balance of $282.7 million, net of debt discount of $2.0 million. The current portion of the term
loan due in the next twelve months was $33.5 million. A 50 basis point increase or decrease in
interest rates would increase or decrease our interest expense by $0.6 million, which is partially offset by our interest rate swap.
To achieve risk mitigation objectives, we have in the past managed our interest rate exposure
through the use of interest rate swaps. To reduce our exposure to rising interest rates, effective
May 22, 2006 we entered into an interest rate swap to reduce the risk that changing interest rates
could have on our operations. The swap initially qualified for cash flow hedge accounting and
changes in fair value were recorded as a component of equity; however, the debt instrument was
subsequently paid and the swap no longer qualified for cash flow hedge accounting. The amounts that
were previously recorded in equity of $17.7 million were recognized in our Consolidated Statements
of Operations in 2009. Subsequent changes in fair value of the interest rate swap will be recorded
in earnings. If interest rates were to decrease in 2010, our expense resulting from our interest
rate swap would increase, which would be partially offset by a decrease in the amount of actual
interest paid on our Alpha Credit Facility.
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Report of Independent Registered Public Accounting Firm
The Board of Directors and Stockholders
Alpha Natural Resources, Inc.: We have audited the accompanying consolidated
balance sheets of Alpha Natural Resources, Inc. and subsidiaries (the Company) as of December 31, 2009 and
2008, and the related consolidated statements of operations, stockholders’ equity and comprehensive income,
and cash flows for each of the years in the three-year period ended December 31, 2009. These consolidated
financial statements are the responsibility of the Company’s management. Our responsibility is to express an
opinion on these consolidated financial statements based on our audits.
We conducted our audits in accordance with the
standards of the Public Company Accounting Oversight Board (United States). Those standards require that
we plan and perform the audit to obtain reasonable assurance about whether the financial statements are
free of material misstatement. An audit includes examining, on a test basis, evidence supporting the
amounts and disclosures in the financial statements. An audit also includes assessing the accounting
principles used and significant estimates made by management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial
statements referred to above present fairly, in all material respects, the financial position of
Alpha Natural Resources, Inc. and subsidiaries as of December 31, 2009 and 2008, and the results
of their operations and their cash flows for each of the years in the three-year period ended
December 31, 2009, in conformity with U.S. generally accepted accounting principles.
As discussed in Note 1 to the consolidated
financial statements, the Company changed its methods of accounting for noncontrolling
interests and convertible debt instruments due to the adoption of new accounting
requirements effective January 1, 2009 and retroactively adjusted all periods
presented in the consolidated financial statements for these changes.
Also as discussed in Note 2 to the consolidated financial statements, the
Company changed its method of accounting for business combinations due to
the adoption of new accounting requirements effective January 1, 2009.
We also have audited,
in accordance with the standards of the Public Company Accounting Oversight Board
(United States), the Company’s internal control over financial reporting
as of December 31, 2009, based on criteria established in Internal Control — Integrated Framework issued
by the Committee of Sponsoring Organizations of the Treadway Commission (COSO),
and our report dated March 1, 2009 expressed an unqualified opinion on the effectiveness
of the Company’s internal control over financial reporting.
In conducting the evaluation of the effectiven | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||