Annual Report — Form 10-K Filing Table of Contents
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(Exact
name of registrant as specified in its charter)
____________
Delaware
95-0740960
(State
or other jurisdiction of incorporation or organization)
(I.R.S.
Employer Identification Number)
4
North 4th Street, Richmond, Virginia
23219
(Address
of principal executive offices)
(Zip
Code)
Registrant’s
telephone number, including area code: (804) 788-1800
Securities
registered pursuant to Section 12(b) of the Act:
Title
of each class
Name
of each exchange on which registered
Common
Stock, $0.625 par value
New
York Stock Exchange
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 x No ¨
Indicate
by check mark if the registrant is not required to file reports pursuant to
Section 13 or Section 15(d) of the Act. Yes ¨ No x
Indicate
by check mark whether the registrant (1) has filed all reports required to be
filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the
preceding 12 months (or for such shorter period that the registrant was required
to file such reports), and (2) has been subject to such filing requirements for
the past 90 days. Yes x No ¨
Indicate
by check mark if disclosure of delinquent filers pursuant to Item 405 of
Regulation S-K (§229.405 of this chapter) is not contained herein, and will not
be contained, to the best of registrant’s knowledge, in definitive proxy or
information statements incorporated by reference in Part III of this Form 10-K
or any amendment to this Form 10-K. ¨
Indicate
by check mark whether the registrant is a large accelerated filer, an
accelerated filer, a non-accelerated filer or a smaller reporting company. See
the definitions of “large accelerated filer,”“accelerated filer,”“non-accelerated filer” and “smaller reporting company” in Rule 12b-2 of the
Exchange Act (Check One):
Large
accelerated filer x Accelerated
filer ¨
Non-accelerated filer ¨ (Do not check if a
smaller reporting company) Smaller reporting company ¨
Indicate
by check mark whether the registrant is a shell company (as defined in Rule
12b-2 of the Exchange Act). Yes ¨ No x
The
aggregate market value of the common stock held by non-affiliates of the
registrant on June 30, 2008, was $7,571,508,750 based on the last sales price
reported that date on the New York Stock Exchange of $93.75 per share. In
determining this figure, the Registrant has assumed that all of its directors
and executive officers are affiliates. Such assumptions should not be deemed to
be conclusive for any other purpose.
Common
stock, $0.625 par value (“Common Stock”), outstanding as of February 17, 2009 —
85,492,888 shares.
Part III
incorporates certain information by reference from the registrant’s definitive
proxy statement for the 2009 Annual Meeting of Stockholders, which proxy
statement will be filed no later than 120 days after the close of the
registrant’s fiscal year ended December 31, 2008.
Forward
Looking Statements
From time
to time, Massey Energy Company, which includes its direct and wholly owned
subsidiary, A. T. Massey Coal Company, Inc, and its direct and indirect wholly
owned subsidiaries (“we,”“our,”“us”), makes certain comments and disclosures
in reports, including this report, or through statements made by our officers
that may be forward-looking in nature. Examples include statements related to
our future outlook, anticipated capital expenditures, projected cash flows and
borrowings and sources of funding. We caution readers that forward-looking
statements, including disclosures that use words such as “believe,”“anticipate,”“expect,”“estimate,”“intend,”“may,”“plan,”“project,”“will”
and similar words or statements are subject to certain risks, trends and
uncertainties that could cause actual cash flows, results of operations,
financial condition, cost reductions, acquisitions, dispositions, financing
transactions, operations, expansion, consolidation and other events to differ
materially from the expectations expressed or implied in such forward-looking
statements. Any forward-looking statements are also subject to a number of
assumptions regarding, among other things, future economic, competitive and
market conditions. These assumptions are based on facts and conditions, as they
exist at the time such statements are made as well as predictions as to future
facts and conditions, the accurate prediction of which may be difficult and
involve the assessment of circumstances and events beyond our control. We
disclaim any intent or obligation to update these forward-looking statements
unless required by securities law, and we caution the reader not to rely on them
unduly.
We have
based any forward-looking statements we have made on our current expectations
and assumptions about future events and circumstances that are subject to risks,
uncertainties and contingencies that could cause results to differ materially
from those discussed in the forward-looking statements, including, but not
limited to:
(i)
our
cash flows, results of operation or financial
condition;
(ii)
the
successful completion of acquisition, disposition or financing
transactions and the effect thereof on our business;
(iii)
governmental
policies, laws, regulatory actions and court decisions affecting the coal
industry or our customers’ coal usage;
(iv)
legal
and administrative proceedings, settlements, investigations and claims and
the availability of insurance coverage related thereto;
(v)
inherent
risks of coal mining beyond our control, including weather and geologic
conditions or catastrophic weather-related damage;
(vi)
our
production capabilities to meet market expectations and customer
requirements;
(vii)
our
ability to obtain coal from brokerage sources or contract miners in
accordance with their contracts;
(viii)
our
ability to obtain and renew permits necessary for our existing and planned
operations in a timely manner;
(ix)
the
cost and availability of transportation for our produced
coal;
(x)
our
ability to expand our mining capacity;
(xi)
our
ability to manage production costs, including labor
costs;
(xii)
adjustments
made in price, volume or terms to existing coal supply
agreements;
(xiii)
the
worldwide market demand for coal, electricity and
steel;
(xiv)
environmental
concerns related to coal mining and combustion and the cost and perceived
benefits of alternative sources of energy such as natural gas and nuclear
energy;
(xv)
competition
among coal and other energy producers, in the United States and
internationally;
(xvi)
our
ability to timely obtain necessary supplies and
equipment;
(xvii)
our
reliance upon and relationships with our customers and
suppliers;
(xviii)
the
creditworthiness of our customers and suppliers;
(xix)
our
ability to attract, train and retain a skilled workforce to meet
replacement or expansion needs;
(xx)
our
assumptions and projections concerning economically recoverable coal
reserve estimates;
(xxi)
our
failure to enter into anticipated new contracts;
(xxii)
future
economic or capital market conditions;
(xxiii)
foreign
currency fluctuations;
(xxiv)
the
availability and costs of credit, surety bonds and letters of credit that
we require;
(xxv)
the
lack of insurance against all potential operating
risks;
(xxvi)
our
assumptions and projections regarding pension and other post-retirement
benefit liabilities;
(xxvii)
our
interpretation and application of accounting literature related to mining
specific issues; and
(xxviii)
the
successful implementation of our strategic plans and objectives for future
operations and expansion or
consolidation.
We are including this cautionary
statement in this document to make applicable and take advantage of the safe
harbor provisions of the Private Securities Litigation Reform Act of 1995 for
any forward-looking statements made by, or on behalf, of us. Any forward-looking
statements should be considered in context with the various disclosures made by
us about our businesses, including without limitation the risk factors more
specifically described below in Item 1A. Risk Factors of this Annual Report on
Form 10-K.
i
2008
ANNUAL REPORT ON FORM 10-K
TABLE
OF CONTENTS
Page
PART I
Item
1.
Business
1
Item
1A.
Risk
Factors
22
Item
1B.
Unresolved
Staff Comments
31
Item
2.
Properties
32
Item
3.
Legal
Proceedings
32
Item
4.
Submission
of Matters to a Vote of Security Holders
33
PART
II
Item
5.
Market
for Registrant’s Common Equity, Related Stockholder Matters and Issuer
Purchases of Equity Securities
34
Item
6.
Selected
Financial Data
36
Item
7.
Management’s
Discussion and Analysis of Financial Condition and Results of
Operations
38
Item
7A.
Quantitative
and Qualitative Disclosures about Market Risk
53
Item
8.
Financial
Statements and Supplementary Data
55
Item
9.
Changes
in and Disagreements with Accountants on Accounting and Financial
Disclosure
95
Item
9A.
Controls
and Procedures
95
Item
9B.
Other
Information
96
PART III
Item
10.
Directors,
Executive Officers and Corporate Governance
97
Item
11.
Executive
Compensation
99
Item
12.
Security
Ownership of Certain Beneficial Owners and Management and Related
Stockholder Matters
99
Item
13.
Certain
Relationships and Related Transactions, and Director
Independence
99
Item
14.
Principal
Accountant Fees and Services
99
PART IV
Item
15.
Exhibits
and Financial Statement Schedules
100
SIGNATURES
104
Annual
Shareholders Meeting
Our 2009
Annual Meeting of Shareholders will be held at 9:00 a.m. EDT on Tuesday, May 19,2009 at The Jefferson Hotel, 101 West Franklin Street, Richmond, Virginia23220.
ii
Part
I
Because
certain terms used in the coal industry may be unfamiliar to many investors, we
have provided a Glossary of Selected Terms beginning on page 19 at
the end of Item 1. Business.
Item
1. Business
Business
Overview
We are
one of the premier coal producers in the United States. In terms of produced
coal revenue in 2007, we are the fourth largest United States coal company in
terms of produced coal revenue, according to Energy Ventures Analysis, Inc.
(“EVA”). According to EVA, we are the largest coal company in Central
Appalachia, our primary region of operation, in terms of tons produced and
total coal reserves in 2007.
We
produce, process and sell bituminous coal of various steam and metallurgical
grades, primarily of a low sulfur content, through our 23 processing and
shipping centers (“Resource Groups”), many of which receive coal from multiple
mines. At January 31, 2009, we operated 66 mines, including 46 underground mines
(two of which employ both room and pillar and longwall mining) and 20 surface
mines (with eleven highwall miners in operation) in West Virginia, Kentucky and
Virginia. The number of mines that we operate may vary from time to
time depending on a number of factors, including the existing demand for and
price of coal, exhaustion of economically recoverable reserves and availability
of experienced labor.
Customers
for our steam coal product include primarily electric power utility companies
who use our coal as fuel for their steam-powered
generators. Customers for our metallurgical coal include primarily
steel producers who use our coal to produce coke, which is in turn used as a raw
material in the steel manufacturing process.
Key
statistics for 2008 include:
·
Produced
coal revenues increased by 25% from $2.1 billion in 2007 to $2.6 billion
in 2008 on produced coal sales of 41.0 million
tons.
·
Reserve
base of approximately 2.3 billion tons at December 31,2008.
A.T.
Massey was originally incorporated in Richmond, Virginia in 1920 as a coal
brokering business. In the late 1940s, A.T. Massey expanded its business to
include coal mining and processing. In 1974, St. Joe Minerals acquired a
majority interest in A.T. Massey. In 1981, St. Joe Minerals was acquired by
Fluor Corporation. A.T. Massey was wholly owned by Fluor Corporation from 1987
until November 30, 2000. On November 30, 2000, we completed a reverse spin-off
(the “Spin-Off”) which separated Fluor Corporation into two
entities: the “new” Fluor Corporation (“New Fluor”) and Fluor
Corporation which retained our coal-related businesses and was subsequently
renamed Massey Energy Company. Massey Energy Company has been a
separate, publicly traded company since December 1, 2000.
Industry
Overview
Coal
accounted for 24% of the energy consumed (excluding
certain alternative fuels including wind, geothermal and solar power generators)
by the United States and 29% of energy consumed globally in 2007,
according to the BP Statistical Review of World Energy (“BP”). In 2007, coal was
the fuel source of 49% of the electricity generated nationwide, as reported
by the Energy
Information Administration (“EIA”), a statistical agency of the United States
Department of Energy.
According
to BP, in 2007, the United
States was the second largest coal producer in the world, exceeded only by
China. Other leading coal producers include Australia, India, South Africa, the
Russian Federation and Indonesia. According to BP, the United States has
the largest coal reserves in the world, with proved reserves totaling 243
billion tons. The Russian Federation ranks second in proved coal reserves with
157 billion tons, followed by China with 115 billion tons, according to
BP.
United States coal
reserves are more plentiful than oil or natural gas with 234 years of supply at
current production rates. Proved United States reserves of oil amount to 12
years of supply at current production rates and proved United States
reserves of natural gas amount to 11 years of supply at current levels of
consumption, as reported by BP.
1
United
States coal production has more than doubled over the last 40 years. In 2008,
total United States coal production, as estimated by the EIA, was 1.2 billion
tons. The primary producing regions by tons were as follows:
Region
% of Total
Powder
River Basin
46%
Central
Appalachia
20%
West
(other than Powder River Basin)
11%
Northern
Appalachia
11%
Midwest
9%
All
other
3%
Total
100%
The EIA
estimated that approximately 69% of United States coal was produced by surface
mining methods in 2007. The remaining 31% was produced by underground mining
methods, which include room and pillar mining and longwall mining (more fully
described in Item 1. Business, under the heading “Mining Methods”).
Coal is
used in the United States by utilities to generate electricity, by steel
companies to make steel products, and by a variety of industrial users to
produce heat and to power foundries, cement plants, paper mills, chemical plants
and other manufacturing and
processing facilities. Significant quantities of coal are also exported from
both East and Gulf Coast terminals. The breakdown of United States coal
consumption for the first ten months of 2008 as estimated by the EIA, is
as follows:
End
Use
% of Total
Electric
Power
93%
Other
Industrial
5%
Coke
2%
Residential
and Commercial
<1%
Total
100%
Coal has
long been favored as an electricity generating fuel because of its basic
economic advantage. The largest cost component in electricity generation is
fuel. This fuel cost is typically lower for coal than competing fuels such as
oil and natural gas on a Btu-comparable basis. The EIA estimates the
average cost of various fossil
fuels for generating electricity in the first 11 months of 2008 was as
follows:
Electricity
Generation Source
Average Cost
per million BTU
Petroleum
Liquids
$ 16.56
Natural
Gas
$ 9.34
Coal
$ 2.06
Petroleum
Coke
$ 1.85
There are
factors other than fuel cost that influence each utility’s choice of electricity
generation mode, including facility construction cost, access to fuel
transportation infrastructure, environmental restrictions, and other factors.
The breakdown of United States electricity generation by fuel source in 2007, as
estimated by EIA, is as follows:
Electricity
Generation Source
%
of Total
Electricity Generation
Coal
49%
Natural
Gas
21%
Nuclear
19%
Hydroelectric
6%
Oil
and other (solar, wind, etc.)
5%
Total
100%
2
Demand
for electricity has historically been driven by United States economic growth
but it can fluctuate from year to year depending on weather patterns. In 2008,
electricity consumption in the United States decreased 0.4% from 2007,
but the average growth rate in the past decade was approximately 1.3% per
year according to EIA estimates. Because coal-fired generation is used in
most cases to meet base load requirements, coal consumption has generally grown
at the pace of electricity demand growth.
According
to the World Coal Institute (“WCI”), in 2007 the United States ranked seventh
among worldwide exporters of coal. Australia was the largest exporter, with
other major exporters including Indonesia, the Russian Federation, Columbia,
South Africa and China. According to EVA, United States exports increased by 37%
from 2007 to 2008. The usage breakdown for 2008 United States coal exports of 80
million tons was 47% for electricity generation and 53% for steel production. In
2008, United States coal exports were shipped to more than 30 countries. The
largest purchaser of United States exported utility coal in 2008 continued to be
Canada, which took 19.1 million tons or 50% of total utility coal exports. This
was up 31% compared to the 14.6 million tons exported to Canada in 2007. Overall
steam coal exports increased 43% in 2008 compared to 2007. The largest
purchasers of United States exported metallurgical coal were Brazil, which
imported approximately 5.9 million tons, or 14%, and Canada, which imported 3.7
million tons, or 9%. In total, metallurgical coal exports increased 31% in 2008
compared to 2007.
Depending
on the relative strength of the United States dollar versus currencies in other
coal producing regions of the world, United States producers may export more or
less coal into foreign countries as they compete on price with other foreign
coal producing sources. Likewise, the domestic coal market may be impacted due
to the relative strength of the United States dollar to other currencies, as
foreign sources could be cost-advantaged based on a coal producing region’s
relative currency position.
Since 2003, the global
marketplace for coal has experienced swings in the demand/supply
balance. In periods of supply shortfall, as occurred from 2003 to
early 2006 and again in late 2007 through late 2008,
the prices for coal reached record highs in the United States. The increased
worldwide demand was primarily driven by higher prices for oil and natural gas
and economic expansion, particularly in China, India and elsewhere in Asia. At
the same time, infrastructure and regulatory limitations in China contributed to
a tightening of worldwide coal supply, affecting global prices of coal. The
growth in China and India caused an increase in worldwide demand for raw
materials and a disruption of expected coal exports from China to Japan, Korea
and other countries. Since mid-2008, the United States and world
economies have been in an economic recession and financial credit crisis,
significantly reducing the demand for coal.
Metallurgical grade coal
is distinguished by special quality characteristics that include high carbon
content, volatile matter, low expansion pressure, low sulfur content, and
various other chemical attributes. High vol met coal is also high in heat
content (as measured in Btus), and therefore is desirable to utilities as fuel
for electricity generation. Consequently, high vol met coal producers have the
ongoing opportunity to select the market that provides maximum revenue
and profitability. The premium price offered by steel makers for the
metallurgical quality attributes is typically higher than the price offered by
utility coal buyers that value only the heat content. The primary concentration
of United States metallurgical coal reserves is located in the Central
Appalachian region. EVA estimates that the Central Appalachian region supplied
89% of domestic metallurgical coal and 76% of United States exported
metallurgical coal during 2007.
For
utility coal buyers, the primary goal is to maximize heat content, with other
specifications like ash content, sulfur content, and size varying considerably
among different customers. Low sulfur coals, such as those produced in the
western United States and in Central Appalachia, generally demand a higher price
due to restrictions on sulfur emissions imposed by the Federal Clean Air Act, as
amended, and implementing regulations (“Clean Air Act”) and the volatility in
sulfur dioxide (“SO2 “)
allowance prices that occurred in recent years when the demand for all
specifications of coal increased. SO2 allowances
permit utilities to emit a higher level of SO2 than
otherwise required under the Clean Air Act regulations. The demand and premium
price for low sulfur coal is expected to diminish as more utilities install
scrubbers at their coal-fired plants.
Coal
shipped for North American consumption is typically sold at the mine loading
facility with transportation costs being borne by the purchaser. Offshore export
shipments are normally sold at the ship-loading terminal, with the purchaser
paying the ocean freight. According to the National Mining Association (“NMA”),
approximately two-thirds of United States coal shipments in recent years
were transported via railroads. Final delivery to consumers often involves more
than one transportation mode. A significant portion of United States production
is delivered to customers via barges on the inland waterway system and ships
loaded at Great Lakes ports.
Neither
we nor any of our subsidiaries are affiliated with or have any investment in BP,
EIA, EVA, Platts or WCI. We are a member of the NMA.
3
Mining
Methods
We
produce coal using four distinct mining methods: underground room and pillar,
underground longwall, surface and highwall mining, which are explained as
follows:
In the
underground room and pillar method of mining, continuous miners cut three to
nine entries into the coal bed and connect them by driving crosscuts, leaving a
series of rectangular pillars, or columns of coal, to help support the mine roof
and control the flow of air. Generally, openings are driven 20 feet wide and the
pillars are 40 to 100 feet wide. As mining advances, a grid-like pattern of
entries and pillars is formed. When mining advances to the end of a panel,
retreat mining may begin. In retreat mining, as much coal as is feasible is
mined from the pillars that were created in advancing the panel, allowing the
roof to fall upon retreat. When retreat mining is completed to the mouth of the
panel, the mined panel is abandoned.
In
longwall mining (which is a type of underground mining), a shearer (cutting
head) moves back and forth across a panel of coal typically about 1,000 feet in
width, cutting a slice approximately 3.5 feet deep. The cut coal falls onto a
flexible conveyor for removal. Longwall mining is performed under hydraulic roof
supports (shields) that are advanced as the seam is cut. The roof in the mined
out areas falls as the shields advance.
Surface
mining is used to extract coal deposits found close to the surface. This method
involves removal of overburden (earth and rock covering coal) with heavy earth
moving equipment, including large shovels and draglines, and explosives,
followed by extraction of coal from coal seams. After extraction of coal,
disturbed parcels of land are reclaimed by replacing overburden and
reestablishing vegetation and plant life.
Highwall
mining is used in connection with surface mining. A highwall mining system
consists of a remotely controlled continuous miner, which extracts coal and
conveys it via augers or belt conveyors to the portal. The cut is typically a
rectangular, horizontal opening in the highwall (the unexcavated face of exposed
overburden and coal in a surface mine) 11-feet wide and reaching depths of up to
1,000 feet. Multiple, parallel openings are driven into the highwall, separated
by narrow pillars that extend the full depth of the hole.
Use of
continuous miners in the room and pillar method of underground mining
represented approximately 43% of our 2008 coal production. Production from
underground longwall mining operations constituted approximately 3% of our 2008
production. Surface mining represented approximately 47% of our 2008 coal
production. Surface mines also use highwall mining systems to produce coal from
high overburden areas. Highwall mining represented approximately 7% of our 2008
coal production.
Mining
Operations
We
currently have 23 distinct Resource Groups, including seventeen in West
Virginia, five in Kentucky and one in Virginia. These complexes blend, process
and ship coal that is produced from one or more mines, with a single complex
handling the coal production of as many as ten distinct underground or surface
mines. Our mines have been developed at strategic locations in close proximity
to our preparation plants and rail shipping facilities.
We
currently operate solely in the Central Appalachian region, which is the
principal source of low sulfur bituminous coal in the United States, used for
power generation, metallurgical coke production and industrial boilers. Central
Appalachian coal accounted for 20% of 2008 United States coal production
according to EIA.
4
The
following map provides the location of our operations within the Central
Appalachian region:
5
The
following table provides key operational information on our Resource Groups in
2008:
For
purposes of this table, coal production has been allocated to the Resource
Group where the coal is mined, rather than the Resource Group where the
coal is processed and shipped. Production amounts above represent coal
extracted from the ground.
(3)
For
purposes of this table, coal shipments have been allocated to the Resource
Group from where the coal is processed and shipped, rather than the
Resource Group where the coal is
mined.
S –
surface mine
U –
underground mine
HW
– highwall miners operated in conjunction with surface
mines
LW –
longwall mine
DL –
dragline
NS –
Norfolk Southern Railway Company
CSX
– CSX Transportation
The
following descriptions of the Resource Groups are current as of January 31,2009.
West
Virginia Resource Groups
Black Castle. The Black
Castle complex includes a large surface mine, a highwall miner, the Homer III
direct-ship loadout, a stoker plant, and the Omar preparation plant. Some of the
surface mine coal is trucked to the stoker plant where the coal is crushed and
screened. The stoker product is trucked to river docks for barge delivery or
trucked directly to customers. A portion of the coal is trucked to the Omar
plant, where it is crushed and shipped to customers or, if the coal needs
processing, it is belted to the preparation plant at the Independence Resource
Group for processing and shipment. The direct-ship facility at the preparation
plant can crush 500 tons per hour and the preparation plant can process 800 tons
per hour. The Omar preparation plant serves CSX rail system customers with unit
train shipments of up to 110 railcars. Coal is also trucked to the Homer III
loadout where it is crushed and shipped to customers by rail, trucked to river
docks for barge delivery, or trucked directly to customers. The Homer III
loadout serves CSX rail system customers with unit train shipments of up to 100
railcars. The Omar preparation plant was not utilized for processing coal in
2008.
6
Delbarton. The Delbarton
complex includes one underground room and pillar mine and a preparation plant.
Production from the mine is transported to the Delbarton preparation plant via
overland conveyor. The Delbarton preparation plant also processes coal from two
surface mines of the Logan County Resource Group. The Delbarton preparation
plant can process 600 tons per hour. The clean coal product is shipped to
customers via the Norfolk Southern railway in unit trains of up to 110
railcars.
Edwight. The Edwight complex
includes a surface mine, a highwall miner and the Goals preparation plant.
Production from all of the mines is transported via conveyor system to the Goals
preparation plant. The Goals preparation plant can process 800 tons per hour.
The rail loading facility serves CSX railway customers with unit trains of up to
100 railcars.
Elk Run. The Elk Run complex
produces coal from four underground room and pillar mines and the Logans Fork
longwall. All of the room and pillar mines belt coal to the Elk Run preparation
plant, while the longwall belts coal to the preparation plant of the Marfork
Resource Group. Additionally, Elk Run processes coal produced by surface mines
of the Progress Resource Group and transported via underground conveyor system.
The Elk Run preparation plant has a processing capacity of 2,200 tons per hour.
Elk Run also operates a 200 ton per hour stoker facility that produces screened,
small dimension coal for certain of our industrial customers. Customer shipments
are loaded on the CSX rail system in unit trains of up to 150
railcars.
Endurance. The Endurance
complex includes a surface mine, highwall miner and a direct-ship loadout. A
portion of the production from the surface mine is loaded for shipment to
customers at the direct ship loadout and the remainder is trucked to the
preparation plant at the Independence Resource Group for
processing.
Green Valley. The Green
Valley complex includes three underground room and pillar mines and a
preparation plant. The Green Valley preparation plant, which has a processing
capacity of 600 tons per hour, receives coal from the mines via trucks. The rail
loading facility services customers on the CSX rail system with unit train
shipments of up to 75 railcars.
Guyandotte. The Guyandotte
complex includes one underground room and pillar mine. The mine belts coal to a
third-party preparation plant for washing and shipment to customers via the
Norfolk Southern railway system.
Independence. The
Independence complex includes the Revolution longwall mine, two underground room
and pillar mines and a preparation plant. Production from the underground mines
is transported via overland conveyor system to the Independence preparation
plant. The surface mine at the Black Castle Resource Group belts coal and the
surface mine at the Endurance Resource Group trucks coal requiring processing to
the Independence preparation plant . The Independence plant has a processing
capacity of 2,200 tons per hour. Customers are served via rail shipments on the
CSX rail system in unit trains of up to 150 railcars.
Inman. The Inman complex
includes one underground room and pillar mine and a preparation plant.
Production from the underground mine is transported via overland conveyor system
to the preparation plant. The Inman plant has a processing capacity of 800 tons
per hour. Coal processed at the preparation plant is transported via conveyor
belt to Black Castle Resource Group’s Homer III loadout, which serves customers
via rail shipments on the CSX rail system in unit trains of up to 100
railcars.
Logan County. The Logan
County complex includes six surface mines, two highwall miners and three
underground room and pillar mines, plus the Bandmill preparation plant and the
Feats loadout, all on the CSX rail system. Four surface mines deliver coal to
the Bandmill plant via truck and conveyor system, two surface mines truck coal
to Edwight Resource Group’s Goals preparation plant, and the underground mines
belt coal directly to the Bandmill plant. The Feats loadout can service
customers via the CSX rail system with unit train shipments of up to 80 cars.
The Bandmill preparation plant has a processing capacity of 1,800 tons per hour.
The Bandmill rail loading facility services customers via the CSX rail system
with unit train shipments of up to 150 railcars.
Mammoth. The Mammoth complex
operates four underground room and pillar mines and a preparation plant. Coal is
transported to the preparation plant using a conveyor system. The plant has a
1,200 tons per hour processing facility capacity with barge loading capabilities
on the upper Kanawha River and a rail loading facility that services customers
on the Norfolk Southern railway with unit trains of up to 130
railcars.
Marfork. The Marfork complex
includes eight underground room and pillar mines and a preparation plant.
Production from one of the mines is trucked and from five of the mines is belted
directly to the Marfork preparation plant while production from the remaining
two mines is belted to Edwight Resource Group’s Goals preparation plant. The
Marfork preparation plant has a capacity of 2,400 tons per hour. Customers are
served via the CSX rail system with unit trains of up to 150
railcars.
7
Nicholas Energy. The Nicholas
Energy complex includes one underground room and pillar mine, two surface mines,
two highwall miners and a preparation plant. Coal from the underground mine is
transported to the preparation plant for processing via conveyor system. Coal
from the highwall miners and the portion of surface mined coal requiring
processing is transported to the preparation plant using off-road trucks.
Coal not requiring processing is transported via off-road trucks to a conveyor
system that moves the coal directly to a rail loadout facility. The plant has a
processing capacity of 1,200 tons per hour. Coal shipments are loaded into rail
cars for delivery via the Norfolk Southern railway in unit trains of up to 140
railcars, or are transported via on-highway trucks to the Mammoth Resource
Group’s barge loading facility.
Progress. The Progress
complex includes the large Twilight MTR surface mine. A dragline is also
utilized at the Twilight MTR surface mine. Production from the Twilight MTR
surface mine is transported via underground conveyor to the Elk Run Resource
Group for processing and rail shipment.
Rawl. The Rawl complex
includes three underground room and pillar mines and a preparation plant.
Production from the mines is transported via truck to the preparation plant of
the Stirrat Resource Group. The Rawl plant, which was idled in December 2006,
has a throughput capacity of 1,450 tons per hour. Customers can be served by the
Rawl plant via the Norfolk Southern railway with unit trains of up to 150
railcars.
Republic Energy. The Republic
Energy complex consists of two surface mines. Direct-ship coal is trucked using
on-highway trucks to various docks on the Kanawha River for barge delivery to
customers and to the Marfork Resource Group for rail delivery to
customers. Coal requiring processing is trucked using on-highway
trucks to Mammoth Resource Group’s preparation plant for processing and barge or
train delivery to customers.
Stirrat. The Stirrat complex
includes one surface mine, a preparation plant and the Superior loadout. The
surface mine trucks coal directly to two 12,500 ton silos at the Superior
loadout. The Superior loadout serves CSX railway customers with unit trains of
up to 100 railcars. The Stirrat preparation plant cleans coal from three
adjacent underground room and pillar mines of the Rawl Resource Group. The plant
has a rated capacity of 600 tons per hour. Customers are served via the CSX rail
system with unit trains of up to 100 railcars.
Kentucky
Resource Groups
Coalgood Energy. The Coalgood
Energy complex includes one underground room and pillar mine, one surface mine,
one highwall miner and a direct-ship loadout. The coal from the surface mine is
trucked off-road to the loadout, which serves CSX railway customers with unit
trains of up to 100 railcars. The production from the underground
mine is being stockpiled until construction is completed on an 800 tons per hour
preparation plant, which is projected to be in service by April
2009. Coal from this preparation plant will be loaded onto trains
from the existing loadout.
Long Fork. The Long Fork
preparation plant processes coal produced by two underground room and pillar
mines of the Sidney Resource Group. All production is transported via conveyor
system to the Long Fork preparation plant for processing and shipping to
customers. The Long Fork plant has a rated capacity of 1,500 tons per hour. The
rail loading facility services customers on the Norfolk Southern railway with
unit trains of up to 150 railcars.
Martin County. The Martin
County complex includes two underground room and pillar mine, two surface mines
and a preparation plant. Direct-ship coal production from the surface
mines is shipped to river docks via truck. Surface mine coal requiring
processing and production from the underground mines is transported by conveyor
belt or truck to the preparation plant. Martin County’s preparation plant has a
throughput capacity of 1,500 tons per hour, although the throughput capacity is
limited due to decreased impoundment availability. The coal from the preparation
plant can be shipped either via the Norfolk Southern railway in unit trains of
up to 125 railcars or to river docks via truck.
New Ridge. The New Ridge
complex loads clean coal that is transported via truck from the preparation
plant of the Sidney Resource Group and coal trucked directly from Sidney’s
surface mine. The New Ridge preparation plant has a capacity of 800 tons per
hour. The preparation plant is currently idle but may be reactivated from time
to time during 2009 as needed. All coal is loaded for shipment to customers via
the CSX rail system in unit trains of up to 100 railcars.
Sidney. The Sidney complex includes nine
underground room and pillar mines, one surface mine, a highwall miner and a
preparation plant. Two of the underground mines transport coal via underground
conveyor system to the Long Fork Resource Group for processing and shipment, and
the remainder of the underground mines transport production via underground
conveyor system or truck to Sidney’s preparation plant. A portion of the coal
from Sidney’s preparation plant and coal from the surface mines are trucked to
the New Ridge Resource Group for loading into railroad cars. Sidney’s
preparation plant has a capacity of 1,500 tons per hour. The rail loading
facility at the preparation plant serves customers on the Norfolk Southern rail
system with unit trains of up to 140 railcars.
8
Virginia
Resource Group
Knox Creek. The Knox Creek
complex includes one underground room and pillar mine, one surface mine, two
highwall miners and a preparation plant. Production from the underground mine is
belted by conveyor system to the preparation plant, while coal requiring
processing from the surface mine is trucked to the preparation plant. The
preparation plant has a feed capacity of 650 tons per hour. The preparation
plant serves customers on the Norfolk Southern rail system with unit trains of
up to 100 railcars.
Coal
Reserves
We
estimate that, as of December 31, 2008, we had total recoverable reserves of
approximately 2.3 billion tons consisting of both proven and probable reserves.
“Reserves” are defined by the SEC Industry Guide 7 as that part of a mineral
deposit, which could be economically and legally extracted or produced at the
time of the reserve determination. “Recoverable” reserves means coal that is
economically recoverable using existing equipment and methods under federal and
state laws currently in effect. Approximately 1.5 billion tons of reserves are
classified as proven reserves. “Proven (measured) reserves” are defined by the
SEC Industry Guide 7 as reserves for which (a) quantity is computed from
dimensions revealed in outcrops, trenches, workings or drill holes; grade and/or
quality are computed from the results of detailed sampling and (b) the sites for
inspection, sampling and measurement are spaced so closely and the geologic
character is so well defined that size, shape, depth and mineral content of
reserves are well-established. The remaining approximately 0.8 billion tons of
our reserves are classified as probable reserves. “Probable reserves” are
defined by the SEC Industry Guide 7 as reserves for which quantity and grade
and/or quality are computed from information similar to that used for proven
(measured) reserves, but the sites for inspection, sampling, and measurement are
farther apart or are otherwise less adequately spaced. The degree of assurance,
although lower than that for proven (measured) reserves, is high enough to
assume continuity between points of observation.
Information
about our reserves consists of estimates based on engineering, economic and
geological data assembled and analyzed by our internal engineers, geologists and
finance associates. Reserve estimates are updated annually using geologic data
taken from drill holes, adjacent mine workings, outcrop prospect openings and
other sources. Coal tonnages are categorized according to coal quality, seam
thickness, mineability and location relative to existing mines and
infrastructure. In accordance with applicable industry standards, proven
reserves are those for which reliable data points are spaced no more than 2,700
feet apart. Probable reserves are those for which reliable data points are
spaced 2,700 feet to 7,900 feet apart. Further scrutiny is applied using
geological criteria and other factors related to profitable extraction of the
coal. These criteria include seam height, roof and floor conditions, yield and
marketability.
As with
most coal-producing companies in Central Appalachia, the majority of our coal
reserves are controlled pursuant to leases from third-party landowners. The
leases are generally long-term in nature (original term five to fifty years or
until the mineable and merchantable coal reserves are exhausted), and
substantially all of the leases contain provisions that allow for automatic
extension of the lease term as long as mining continues. These leases convey
mining rights to the coal producer in exchange for a per ton or percentage of
gross sales price royalty payment to the lessor. However, approximately 17% of
our reserve holdings are owned and require no royalty or per ton payment to
other parties. Royalty expense for coal reserves from our producing properties
(owned and leased) was approximately 4.4% of Produced coal revenue for the year
ended December 31, 2008.
9
hss
The
following table provides proven and probable reserve data by “status” (i.e.,
location, owned or leased, assigned or unassigned, etc.) as of December 31,2008:
Recoverable Reserves (1)
Resource
Group
Location (2)
Total
Proven
Probable
Assigned (3)
Unassigned (3)
Owned
Leased
(In
Thousands of Tons)
West
Virginia
Black Castle
Boone
County
86,132
59,402
26,730
39,362
46,770
538
85,594
Delbarton
Mingo
County
286,237
120,440
165,797
140,739
145,498
25
286,212
Edwight
Raleigh
County
7,796
7,796
-
7,796
-
-
7,796
Elk
Run
Boone
County
108,782
75,615
33,167
59,488
49,294
4,660
104,122
Endurance
Boone
County
23,007
23,007
-
23,007
-
22,602
405
Green Valley
Nicholas
County
9,973
9,973
-
9,973
-
-
9,973
Guyandotte
Wyoming
County
45,564
17,366
28,198
2,100
43,464
330
45,234
Independence
Boone
County
44,466
43,156
1,310
31,487
12,979
9,482
34,984
Inman
Boone
County
49,473
47,958
1,515
17,066
32,407
-
49,473
Logan County
Logan
County
72,805
65,721
7,084
55,081
17,724
2,388
70,417
Mammoth
Kanawha
County
86,425
66,086
20,339
73,108
13,317
42,421
44,004
Marfork
Raleigh
County
133,399
105,262
28,137
74,976
58,423
815
132,584
Nicholas
Energy
Nicholas
County
88,795
48,186
40,609
46,379
42,416
35,517
53,278
Progress
Boone
County
17,262
17,262
-
17,262
-
-
17,262
Rawl
Mingo
County
108,849
81,087
27,762
74,852
33,997
1,333
107,516
Republic
Energy
Raleigh
County
56,208
49,688
6,520
56,208
-
-
56,208
Stirrat
Logan
County
11,745
7,778
3,967
5,078
6,667
-
11,745
Kentucky
Coalgood
Energy
Harlan
County
21,261
12,357
8,904
-
21,261
2,704
18,557
Long
Fork
Pike
County
4,964
2,764
2,200
264
4,700
-
4,964
Martin County
Martin
County
48,181
31,492
16,689
2,783
45,398
1,336
46,845
New
Ridge
Pike
County
-
-
-
-
-
-
-
Sidney
Pike
County
124,211
70,173
54,038
124,211
-
7,028
117,183
Virginia
Knox
Creek
Tazewell
County
60,675
44,586
16,089
32,605
28,070
4,552
56,123
Subtotal
1,496,210
1,007,155
489,055
893,825
602,385
135,731
1,360,479
Land Management Companies: (4)
Black
King
Boone
County, WV
53,144
40,762
12,382
734
52,410
-
53,144
Raleigh
County, WV
Boone
East
Boone
County, WV
141,976
102,853
39,123
5,169
136,807
63,547
78,429
Kanawha
County, WV
Boone
West
Lincoln
County, WV
242,308
92,201
150,107
10,496
231,812
65,553
176,755
Logan
County, WV
Ceres Land
Raleigh
County, WV
33,351
24,220
9,131
-
33,351
-
33,351
Rostraver Energy (5)
Various
counties, PA
94,086
44,449
49,637
-
94,086
79,907
14,179
Lauren
Land
Mingo
County, WV
167,671
107,301
60,370
11,175
156,496
18,011
149,660
Logan
County, WV
Various
counties, KY
New
Market Land
Wyoming
County, WV
5,884
2,690
3,194
-
5,884
102
5,782
Raven
Resources
Raleigh
County, WV
18,978
18,978
-
-
18,978
-
18,978
Boone
County, WV
Tennessee
Consolidated Coal
Various
counties, TN
26,907
1,332
25,575
-
26,907
24,054
2,853
Subtotal
Land Management
784,305
434,786
349,519
27,574
756,731
251,174
533,131
Other
N/A
57,733
29,680
28,053
12,740
44,993
3,112
54,621
Total
2,338,248
1,471,621
866,627
934,139
1,404,109
390,017
1,948,231
__________________________
(1)
Recoverable
reserves represent the amount of proven and probable reserves that can
actually be recovered from the reserve base taking into account all mining
and preparation losses involved in producing a saleable product using
existing methods under current law.
(2)
All
of the recoverable reserves listed are in Central Appalachia, except for
the Rostraver reserves, which are located in Northern Appalachia and
Lauren Land reserves, a portion of which are located in the Illinois
Basin. The reserve numbers of each Resource Group contain a moisture
factor specific to the particular reserves of that Resource Group. The
moisture factor represents the average moisture present in our delivered
coal.
(3)
Assigned
Reserves represent recoverable reserves that are dedicated to a specific
permitted mine; otherwise, the reserves are considered Unassigned. For
Land Management Companies, Assigned Reserves have been leased to a
third-party and are dedicated to a specific permitted mine of the
lessee.
(4)
Land
management companies are our subsidiaries whose primary purposes are to
acquire and hold our reserves.
(5)
Previously
known as Duncan Fork.
10
The
categorization of the “quality” (i.e., sulfur content, Btu, coal type,
etc.) of coal reserves is as
follows:
Recoverable Reserves (1)
Recoverable
Sulfur
Content
Avg.
Btu as
Resource
Group
Reserves
+1% (2)
-1% (2)
Compliance (2)
Received (3)
Coal Type (4)
(In
Thousands of Tons Except Average Btu as Received)
West
Virginia
Black Castle
86,132
34,116
52,016
22,167
12,700
Utility
and Industrial
Delbarton
286,237
111,954
174,283
127,073
13,350
High
Vol Met, Utility, and Industrial
Edwight
7,796
1,622
6,174
5,987
12,550
High
Vol Met, Utility, and Industrial
Elk
Run
108,782
47,027
61,755
51,407
13,700
High
Vol Met, Utility, and Industrial
Endurance
23,007
4,952
18,055
10,047
11,850
Utility
and Industrial
Green Valley
9,973
471
9,502
3,853
13,100
High
Vol Met, Utility, and Industrial
Guyandotte
45,564
-
45,564
45,564
13,850
Low
Vol Met
Independence
44,466
19,425
25,041
-
12,650
High
Vol Met, Utility, and Industrial
Inman
49,473
32,667
16,806
16,895
12,650
High
Vol Met and Utility
Logan County
72,805
22,346
50,459
39,009
12,050
High
Vol Met, Utility, and Industrial
Mammoth
86,425
5,216
81,209
41,706
12,150
Utility
and Industrial
Marfork
133,399
41,679
91,720
34,931
14,050
High
Vol Met, Utility, and Industrial
Nicholas
Energy
88,795
39,959
48,836
24,705
12,450
Utility
and Industrial
Progress
17,262
6,021
11,241
11,241
12,350
High
Vol Met, Utility, and Industrial
Rawl
108,849
28,061
80,788
59,614
12,350
High
Vol Met, Utility, and Industrial
Republic
56,208
11,014
45,194
31,238
12,450
High
Vol Met and Utility
Stirrat
11,745
223
11,522
7,663
12,300
High
Vol Met, Utility, and Industrial
Kentucky
Coalgood
Energy
21,261
4,712
16,549
11,680
13,100
High
Vol Met, Utility, and Industrial
Long
Fork
4,964
3,500
1,464
-
12,850
Utility
and Industrial
Martin County
48,181
33,900
14,281
5,120
12,500
Utility
and Industrial
New
Ridge
-
-
-
-
-
N/A
Sidney
124,211
47,878
76,333
52,545
13,200
High
Vol Met, Utility, and Industrial
Virginia
Knox
Creek
60,675
7,022
53,653
40,250
12,350
High
Vol Met, Utility, and Industrial
Subtotal
1,496,210
503,765
992,445
642,695
Land Management Companies: (5)
Black
King
53,144
99
53,045
36,508
12,150
High
Vol Met and Utility
Boone
East
141,976
34,939
107,037
36,789
12,500
High
Vol Met, Utility, and Low Vol Met
Boone
West
242,308
130,063
112,245
79,369
13,350
High
Vol Met and Utility
Ceres Land
33,351
5,991
27,360
12,740
12,700
High
Vol Met and Utility
Rostraver Energy
(6)
94,086
94,086
-
-
14,050
High
Vol Met, Utility, and Industrial
Lauren
Land
167,671
85,346
82,325
62,628
12,700
High
Vol Met and Utility
New
Market Land
5,884
-
5,884
5,884
12,700
High
Vol Met and Low Vol Met
Raven
Resources
18,978
7,449
11,529
1,369
12,100
High
Vol Met and Utility
Tennessee
Consolidated Coal
26,907
20,353
6,554
4,816
13,000
High
Vol Met, Utility and Industrial
Subtotal
Land Management
784,305
378,326
405,979
240,103
Other
57,733
6,638
51,095
45,947
12,800
Various
Total
2,338,248
888,729
1,449,519
928,745
__________________________
(1)
The
reserve numbers of each Resource Group contain a moisture factor specific
to the particular reserves of that Resource Group. The moisture factor
represents the average moisture present in our delivered
coal.
(2)
+1%
or -1% refers to sulfur content as a percentage in coal by weight.
Compliance coal is less than 1% sulfur content by weight and is included
in the -1% column.
(3)
Represents
an estimate of the average Btu per pound present in our coal, as it is
received by the customer.
(4)
Reserve
holdings include metallurgical coal reserves. Although these metallurgical
coal reserves receive the highest selling price in the current coal market
when marketed to steel-making customers, they can also be marketed as an
ultra high Btu, low sulfur utility coal for electricity
generation.
(5)
Land
management companies are our subsidiaries whose primary purposes are to
acquire and hold our reserves.
(6)
Previously
known as Duncan Fork.
11
Compliance
compared to non-compliance coal
Coals are
sometimes characterized as compliance or non-compliance coal. The phrase
compliance coal, as it is commonly used in the coal industry, refers to
compliance only with sulfur dioxide emissions standards imposed by Title IV of
the Clean Air Act and indicates that when burned, the coal will produce
emissions that will meet the current standard without further cleanup. A coal
that is considered a compliance coal for meeting sulfur dioxide standards may
not meet an emission standard for a different pollutant such as mercury.
Moreover, the term compliance coal is always used with reference to the then
current regulatory limit. Clean air regulations that further restrict sulfur
dioxide emissions will likely reduce significantly the amount of coal that can
be labeled compliance. Currently, coal classified as compliance will meet the
power plant emission standard of 1.2 pounds of sulfur dioxide per million Btu’s
of fuel consumed. At December 31, 2008, approximately 0.9 billion tons, or 40%,
of our coal reserves met the current standard as compliance coal.
Distribution
We employ
transportation specialists who negotiate freight and terminal agreements with
various providers, including railroads, barge lines, ocean-going vessels, bulk
motor carriers and terminal facilities. Transportation specialists also
coordinate with customers, mining facilities and transportation providers to
establish shipping schedules that meet each customer’s needs.
Our 2008
shipments of 41.0 million tons were loaded from 23 mining complexes. Rail
shipments constituted 91% of total shipments, with 26% loaded on Norfolk
Southern trains and 65% loaded on CSX trains. The balance was shipped from
mining complexes via truck or barge.
Approximately
22% of production was ultimately delivered via the inland waterway system. Coal
is loaded directly into barges, or is transported by rail or truck to docks on
the Ohio, Big Sandy and Kanawha Rivers and then ultimately transported by barge
to electric utilities, integrated steel producers and industrial consumers
served by the inland waterway system. We also moved approximately 2% of our
production to Great Lakes’ ports for transport to various United States and
Canadian customers.
We have
coal supply commitments with a wide range of electric utilities, steel
manufacturers, industrial customers and energy traders and brokers. By offering
coal of both steam and metallurgical grades, we are able to serve a diverse
customer base. This market diversity allows us to adjust to changing market conditions and
sustain high sales volumes. The majority of our customers purchase coal for
terms of one year or longer, but we also supply coal on a spot basis for some
customers. At
December 31, 2008, approximately 75%, 13% and 12% of Trade receivables
represents amounts due from utility customers, metallurgical customers and
industrial customers, respectively, compared with 56%, 28% and 16%,
respectively, as of December 31, 2007. During 2008, we had 25 separate,
active agreements with our largest customer, Constellation Energy Commodities
Group, Inc. (“Constellation”), with terms ranging from one month to two years
which, in the aggregate accounted for 11% of our fiscal year 2008 Produced coal
revenue. The largest of the 25 agreements represented less than 2% of our fiscal
year 2008 Produced coal revenue. As a result, we do not consider our business to
be substantially dependent upon any of these agreements, individually or
in the aggregate. No other customer accounted for 10% or more of fiscal year
2008 Produced coal revenue or produced tons. For fiscal year 2009, our
contracted sales under separate agreements to Constellation currently represent
approximately 26% of our projected produced coal tonnage and 18% of our
projected Produced coal revenue. There are no other customers to whom we expect
to sell 10% or more of produced tons or to account for 10% or more of
Produced coal revenue in 2009.
As is
customary in the coal industry, we enter into long-term contracts (one year or
more in duration) with many of our customers. These arrangements allow customers
to secure a supply for their future needs and provide us with greater
predictability of sales volume and sales prices. Long-term contracts are a
result of extensive negotiations with customers. As a result, the terms of these
contracts vary with respect to price adjustment mechanisms, pricing terms,
permitted sources of supply, force majeure provisions, quality adjustments and
other parameters. Some of the contracts contain price adjustment mechanisms that
allow for changes to prices based on statistics from the United States
Department of Labor. Coal quality specifications may be especially stringent for
steel customers.
For the
year ended December 31, 2008, approximately 97% of coal sales volume was
pursuant to long-term contracts. We anticipate that in 2009, coal sales volume
percentage pursuant to long-term arrangements will be comparable to 2008. As of
February 19, 2009, we had contractual sales commitments of approximately 101
million tons, including commitments subject to price reopener and/or optional
tonnage provisions. Remaining contractual terms of our sales commitments range
from one to eleven years with an average volume-weighted remaining term of
approximately 3.1 years. Sixty-five percent of our total contracted sales tons
are priced. As of February 19, 2009, we have committed most of our expected 2009
production. In addition, we purchase coal from third-party coal producers from
time to time to supplement production and resell this coal to
customers.
12
Suppliers
The main types of goods we purchase are
mining equipment and replacement parts, explosives, fuel, tires, steel-related
(including roof control) products and lubricants. Although we have many
well-established, strategic relationships with our key suppliers, we do not
believe that we are dependent on any of our individual suppliers, except as
noted below. The supplier base providing mining materials has been relatively
consistent in recent years, although there continues to be some consolidation.
Consolidation of suppliers of explosives has limited the number of sources for
these materials. Although our current supply of explosives is concentrated with
one supplier, some alternative sources are available to us in the regions where
we operate. Further consolidation of underground equipment suppliers has
resulted in a situation where purchases of certain underground mining equipment
are concentrated with one principal supplier; however, supplier competition
continues to develop. In recent years, demand for certain surface and
underground mining equipment and off-the-road tires has increased. As a result,
lead times for certain items have generally increased, although no material
impact is currently expected to our cash flows, results of operations or
financial condition.
Competition
The coal
industry in the United States and overseas is highly competitive, with numerous
producers selling into all markets that use coal. We compete against large and
small producers in the United States and overseas. The NMA estimated that
in 2007 there were 25 coal companies in the United States with annual production
of 5 million or more tons, which together account for approximately 85% of
United States production. According to the EIA, we were the sixth largest coal
company in terms of tons produced in 2007, exceeded by Peabody Energy
Corporation (“Peabody”), Rio Tinto Energy America, Inc., Arch Coal, Inc.
(“Arch”), Foundation Coal Holdings Inc. (“Foundation”) and CONSOL Energy Inc.
(“CONSOL”). However, in terms of produced coal revenue in 2007, EVA ranks
us as the fourth largest United States coal company, exceeded by only
Peabody, CONSOL and Arch.
We
compete with other producers primarily on the basis of price, coal quality,
transportation cost and reliability of supply. Continued demand for coal is also
dependent on factors outside of our control, including demand for electricity
and steel, general economic conditions, environmental and governmental
regulations, weather, technological developments, and the availability and cost
of alternative fuel sources. We sell coal to foreign electricity generators and
to the more specialized metallurgical coal market, both of which are
significantly affected by international demand and competition.
Historically,
global coal markets have responded to increased demand and higher prices for
coal by increasing production and supply. In recent years, however, capacity
expansion has been somewhat limited by the increased costs of mining, high
capital requirements, coal seam degradation, reserve depletion, labor shortages,
transportation issues related to rail, barge and truck shipments, higher costs
related to compliance with new and increasingly stringent regulations, the
difficulty of obtaining permits and bonding and other factors. While these
constraints persist in major coal producing countries and regions, periods of
supply and demand imbalance may be extended and increased pricing volatility may
result.
Other
Related Operations
We have
other related operations and activities in addition to our normal coal
production and sales business. The following business activities are included in
this category:
Coal Handling Joint Venture.
We hold a 50% interest in a joint venture that owns and operates third-party
end-user coal handling facilities. Certain of our subsidiaries currently operate
the coal handling facilities for the joint venture.
Gas Operations. We hold
interests in operations that produce, gather and market natural gas from shallow
reservoirs in the Appalachian Basin. In the eastern United States, conventional
natural gas reservoirs are located in various types of sedimentary formations at
depths ranging from 2,000 to 15,000 feet. The depths of the reservoirs drilled
and operated by us range from 2,500 to 5,800 feet.
Nearly
all of our gas production is from operations in southern West Virginia. In this
region, we own and operate approximately 160 wells, 200 miles of gathering line,
and various small compression facilities. Our southern West Virginia operations
control approximately 27,000 acres of drilling rights. In addition, we own a
majority working interest in 50 wells operated by others, and minority
working interests in approximately 13 wells operated by others. The
December 2008 average daily production, from the 228 wells owned or
controlled, was 2.0 million cubic feet per day. We do not consider our current
gas production level, revenues or costs to be material to our cash flows,
results of operations or financial condition.
13
Other. From time to time, we
also engage in the sale of certain non-strategic assets such as timber, oil and
gas rights, surface properties and reserves. In addition, we have established
several contractual arrangements with customers where services other than coal
supply are provided on an ongoing basis. None of these contractual arrangements
is considered to be material. Examples of such other services include
arrangements with several metallurgical and industrial customers to coordinate
shipment of coal to their stockpiles, maintain ownership of the coal inventory
on their property and sell tonnage to them as it is consumed. We work closely
with customers to provide other services in response to the current needs of
each individual customer.
Marketing
and Sales
Our
marketing and sales force, based in the corporate office in Richmond, Virginia,
includes sales managers, distribution/traffic managers and administrative
personnel.
During
the year ended December 31, 2008, we sold 41.0 million tons of produced coal for
total Produced coal revenue of $2.6 billion. The breakdown of produced tons sold
by market served was 66% utility, 24% metallurgical and 10% industrial. Sales
were concluded with over 100 customers. Export shipment revenue totaled
approximately $756.3 million, representing approximately 30% of 2008
Produced coal revenue. In 2008, we exported shipments to customers in 17
countries across the globe, which included destinations in Europe, Asia, Africa,
South America and North America. Sales are made in United States dollars, which
minimizes foreign currency risk.
Employees
and Labor Relations
As of
December 31, 2008, we had 6,743 employees, including 124 employees affiliated
with the United Mine Workers of America (“UMWA”). Relations with employees are
generally good, and there have been no material work stoppages in the past ten
years.
Environmental,
Safety and Health Laws and Regulations
The coal
mining industry is subject to regulation by federal, state and local authorities
on matters such as the discharge of materials into the environment, employee
health and safety, permitting and other licensing requirements, reclamation and
restoration of mining properties after mining is completed, management of
materials generated by mining operations, surface subsidence from underground
mining, water pollution, water appropriation and legislatively mandated benefits
for current and retired coal miners, air quality standards, protection of
wetlands, endangered plant and wildlife protection, limitations on land use, and
storage of petroleum products and substances that are regarded as hazardous
under applicable laws. The possibility exists that new legislation or
regulations may be adopted that could have a significant impact on our mining
operations or on our customers’ ability to use coal.
Numerous
governmental permits and approvals are required for mining operations.
Regulations provide that a mining permit or modification can be delayed, refused
or revoked if an officer, director or a stockholder with a 10% or greater
interest in the entity is affiliated with or is in a position to control another
entity that has outstanding permit violations. Thus, past or ongoing violations
of federal and state mining laws by individuals or companies no longer
affiliated with us could provide a basis to revoke existing permits and to deny
the issuance of addition permits. We are required to prepare and present to
federal, state or local authorities data and/or analysis pertaining to the
effect or impact that any proposed exploration for or production of coal may
have upon the environment, public and employee health and safety. All
requirements imposed by such authorities may be costly and time-consuming and
may delay commencement or continuation of exploration or production operations.
Accordingly, the permits we need for our mining and gas operations may not be
issued, or, if issued, may not be issued in a timely fashion. Permits we need
may involve requirements that may be changed or interpreted in a manner that
restricts our ability to conduct our mining operations or to do so profitably.
Future legislation and administrative regulations may increasingly emphasize the
protection of the environment, health and safety and, as a consequence, our
activities may be more closely regulated. Such legislation and regulations, as
well as future interpretations of existing laws, may require substantial
increases in equipment and operating costs, delays, interruptions or a
termination of operations, the extent of which cannot be predicted.
14
While it
is not possible to quantify the expenditures we incur to maintain compliance
with all applicable federal and state laws, those costs have been and are
expected to continue to be significant. We post surety performance bonds or
letters of credit pursuant to federal and state mining laws and regulations for
the estimated costs of reclamation and mine closing, often including the cost of
treating mine water discharge when necessary. Compliance with these laws has
substantially increased the cost of coal mining for all domestic coal producers.
We endeavor to conduct our mining operations in compliance with all applicable
federal, state and local laws and regulations. However, even with our
substantial efforts to comply with extensive and comprehensive regulatory
requirements, violations during mining operations occur from time to time. In
2007, EPA filed suit against us and twenty-seven of our subsidiaries alleging
violations of the Federal Clean Water Act. In January 2008, we announced that we
had agreed with EPA to settle the lawsuit for a payment of $20 million in
penalties. In 2008, we spent approximately $16.2 million to comply with
environmental laws and regulations, of which $7.8 million was for reclamation,
including $5.0 million for final reclamation. None of these expenditures were
capitalized. We anticipate spending approximately $42.8 million and $34.8
million in such non-capital expenditures in 2009 and 2010, respectively. Of
these expenditures, $31.4 million and $23.1 million for 2009 and 2010,
respectively, are anticipated to be for final reclamation.
Emission Control Technology.
We own a majority interest in Coalsolv, LLC (“Coalsolv”), which holds the United
States marketing rights for the coal-fired plant emission control technologies
developed by Cansolv Technologies, Inc. (“Cansolv”). Cansolv’s technologies
remove sulfur dioxide (SO2), nitrogen
oxide (NOx), mercury,
carbon dioxide (CO2), and
other greenhouse gases from flue gas emissions. The Cansolv process has been
utilized at various industrial facilities around the world, with additional
projects underway in China and Canada. Through Coalsolv, we contributed funds
for a pilot plant that has been utilized in the United States and Canada for the
testing and piloting of the Cansolv SO2, NOX, mercury,
and CO2 capture
technology on coal-fired power plants.
Mine
Safety and Health
Stringent
health and safety standards have been in effect since Congress enacted the
Federal Coal Mine Health and Safety Act of 1969. The Federal Coal Mine Safety
and Health Act of 1977 significantly expanded the enforcement of safety and
health standards and imposed safety and health standards on all aspects of
mining operations. A further expansion occurred in June 2006 with the enactment
of the Mine Improvement and New Emergency Response Act of 2006 (“MINER
Act”).
The MINER
Act and related Mine Safety and Health Administration (“MSHA”) regulatory action
require, among other things, improved emergency response capability, increased
availability of emergency breathable air, enhanced communication and tracking
systems, more available mine rescue teams, increased mine seal strength and
monitoring of sealed areas in underground mines, as well as larger penalties by
MSHA for noncompliance by mine operators. Coal producing states, including West
Virginia and Kentucky, passed similar legislation. The bituminous coal mining
industry was actively engaged throughout 2008 in activities to achieve
compliance with these new requirements. These compliance efforts will continue
into 2009.
In
2008, MSHA published final rules implementing Section 4 of the MINER Act that
addressed mine rescue, sealing of abandoned areas, refuge alternatives, fire
prevention and detection, use of air from the belt entry and civil penalty
assessments. MSHA also provided guidance on wireless communication
and electronic tracking systems and new requirements for the plugging of coal
bed methane wells with horizontal branches in coal seams. Two
additional regulations were also published related to measures to achieve
alcohol and drug free mines and the use of coal mine dust personal monitors. In
February 2009, the United States Court of Appeals for the District of Columbia
Circuit held that the 2008 rules were not sufficient to satisfy the requirements
of the Miner Act in certain respects, and remanded those portions of the rules
to MSHA for reconsideration. New rules issued by the MSHA will likely contain
more stringent provisions regarding training of rescue teams.
All of
the states in which we operate have state programs for mine safety and health
regulation and enforcement. Collectively, federal and state safety and health
regulation in the coal mining industry is perhaps the most comprehensive and
pervasive system for protection of employee health and safety affecting any
segment of industry in the United States. While regulation has a significant
effect on our operating costs, our United States competitors are subject to the
same regulation.
We
measure our success in this area primarily through the use of occupational
injury and illness frequency rates. We believe that a superior safety and health
regime is inherently tied to achieving productivity and financial goals, with
overarching benefits for our shareholders, the community and the
environment.
Black Lung. Under federal
black lung benefits legislation, each coal mine operator is required to make
payments of black lung benefits or contributions to: (i) current and former coal
miners totally disabled from black lung disease; and (ii) certain survivors of a
miner who dies from black lung disease. The Black Lung Disability Trust Fund, to
which we must make certain tax payments based on tonnage sold, provides for the
payment of medical expenses to claimants whose last mine employment was before
January 1, 1970 and to claimants employed after such date, where no responsible
coal mine operator has been identified for claims or where the responsible coal
mine operator has defaulted on the payment of such benefits. In addition to
federal acts, we are also liable under various state statutes for black lung
claims. Federal benefits are offset by any state benefits paid.
15
Workers’ Compensation. We are
liable for workers’ compensation benefits for traumatic injuries under state
workers’ compensation laws in the states in which we have operations. Workers’
compensation laws are administered by state agencies with each state having its
own set of rules and regulations regarding compensation owed to an employee
injured in the course of employment.
Coal Industry Retiree
Health Benefit Act of 1992 and Tax Relief and Retiree Health Care Act of
2006. The Coal Industry Retiree Health Benefit Act of 1992 (“Coal Act”)
provides for the funding of health benefits for certain UMWA retirees. The Coal
Act established the Combined Benefit Fund (“CBF”) into which “signatory
operators” and “related persons” are obligated to pay annual premiums for
covered beneficiaries. The Coal Act also created a second benefit fund, the 1992
Benefit Plan, for miners who retired between July 21, 1992 and September 30,1994 and whose former employers are no longer in business. On December 20, 2006,
President Bush signed the Tax Relief and Retiree Health Care Act of 2006. This
legislation includes important changes to the Coal Act that impacts all
companies required to contribute to the CBF. Effective October 1, 2007, the SSA
revoked all beneficiary assignments made to companies that did not sign a 1988
UMWA contract (“reachback companies”), but phased-in their premium relief. As a
pre-1988 signatory, Massey related reachback companies received the applicable
premium relief. Effective October 1, 2007, reachback companies will pay only 55%
of their plan year 2008 assessed premiums, 40% of their plan year 2009 assessed
premiums, and 15% of their plan year 2010 assessed premiums. General United
States Treasury money will be transferred to the CBF to make up the difference.
After 2010, reachback companies will have no further obligations to the CBF, and
transfers from the United States Treasury will cover all of the health care
costs for retirees and dependents previously assigned to reachback
companies.
Pension Protection Act. The
Pension Protection Act of 2006 (“Pension Act”) has simplified and transformed
the rules governing the funding of defined benefit plans, accelerated funding
obligations of employers, made permanent certain provisions of the Economic
Growth and Tax Relief Reconciliation Act of 2001, made permanent the
diversification rights and investment education provisions for plan participants
and encouraged automatic enrollment in defined contribution 401(k) plans.
In general, most provisions of the Pension Act took effect for plan years
beginning on or after December 31, 2007. Plans generally are required to
set a funding target of 100% of the present value of accrued benefits and
sponsors are required to amortize unfunded liabilities over a 7-year period. The
Pension Act included a funding target phase-in provision consisting of a 92%
funding target in 2008, 94% in 2009, 96% in 2010, and 100% thereafter. Plans
with a funded ratio of less than 80%, or less than 70% using special
assumptions, are deemed to be “at risk” and are subject to additional funding
requirements. As of December 31, 2008, our pension plan was underfunded by $63
million. We currently expect to make contributions in 2009 of
approximately $10 million. The funded status at the end of fiscal year 2009, and
the need for additional future required contributions, will depend primarily on
the actual return on assets during the year and the discount rate at the end of
the year.
Environmental
Laws
Surface Mining Control and
Reclamation Act. The Surface Mining Control and Reclamation Act,
(“SMCRA”), which is administered by the Office of Surface Mining Reclamation and
Enforcement (“OSM”), establishes mining, environmental protection and
reclamation standards for all aspects of surface mining as well as many aspects
of deep mining. The SMCRA and similar state statutes require, among other
things, the restoration of mined property in accordance with specified standards
and an approved reclamation plan. In addition, the Abandoned Mine Land Fund,
which is part of the SMCRA, imposes a fee on all current mining operations, the
proceeds of which are used to restore mines closed before 1977. The maximum tax
is $0.315 per ton on surface-mined coal and $0.135 per ton on deep-mined coal. A
mine operator must submit a bond or otherwise secure the performance of its
reclamation obligations. Mine operators must receive permits and permit renewals
for surface mining operations from the OSM or, where state regulatory agencies
have adopted federally approved state programs under the act, the appropriate
state regulatory authority. We accrue for reclamation and mine-closing
liabilities in accordance with Statement of Financial Accounting Standard
(“SFAS”) No. 143, “Accounting for Asset Retirement Obligations” (“SFAS 143”)
(see Note 9 to the Notes to Consolidated Financial Statements).
Clean Water Act. Section 301
of the Clean Water Act prohibits the discharge of a pollutant from a point
source into navigable waters of the United States except in accordance with a
permit issued under either Section 402 or Section 404 of the Clean Water Act.
Navigable waters are broadly defined to include streams, even those that are not
navigable in fact, and may include wetlands. All mining operations in Appalachia
generate excess material, which are typically placed in fills in adjacent
valleys and hollows. Likewise, coal refuse disposal areas and coal processing
slurry impoundments are located in valleys and hollows. These areas frequently
contain intermittent or perennial streams, which are considered navigable waters
under the Clean Water Act. An operator must secure a Clean Water Act permit
before filling such streams. For approximately the past twenty-five years,
operators have secured Section 404 fill permits that authorize the filling of
navigable waters with material from various forms of coal mining. Operators have
also obtained permits under Section 404 for the construction of slurry
impoundments. Discharges from these structures require permits under Section 402
of the Clean Water Act. Section 402 discharge permits are generally not suitable
for authorizing the construction of fills in navigable waters.
16
Clean Air Act. Coal contains
impurities, including sulfur, mercury, chlorine, nitrogen oxide and other
elements or compounds, many of which are released into the air when coal is
burned. The Clean Air Act and corresponding state laws extensively regulate
emissions into the air of particulate matter and other substances, including
sulfur dioxide, nitrogen oxide and mercury. Although these regulations apply
directly to impose certain requirements for the permitting and operation of our
mining facilities, by far their greatest impact on us and the coal industry
generally is the effect of emission limitations on utilities and other
customers. Owners of coal-fired power plants and industrial boilers have been
required to expend considerable resources to comply with these air pollution
standards. The United States Environmental Protection Agency (“EPA”) has imposed
or attempted to impose tighter emission restrictions in a number of areas, some
of which are currently subject to litigation. The general effect of such tighter
restrictions could be to reduce demand for coal. This in turn may result in
decreased production and a corresponding decrease in revenue and profits.
National Ambient Air Quality
Standards. Ozone is produced by a combination of two precursor
pollutants: volatile organic compounds and nitrogen oxide, a by-product of coal
combustion. Particulate matter is emitted by sources burning coal as fuel,
including coal fired power plants. States are required to submit to EPA
revisions to their State Implementation Plans (“SIPs”) that demonstrate the
manner in which the states will attain National Ambient Air Quality Standards
(“NAAQS”) every time a NAAQS is revised by EPA. In 2006, EPA adopted a new NAAQS
for fine particulate matter, which a
number of states and environmental advocacy groups challenged as not
sufficiently stringent to satisfy Clean Air Act requirements; in February 2009,
the United States Court of Appeals for the District of Columbia Circuit agreed
that EPA had inadequately explained its decision regarding several aspects of
the NAAQS and remanded those to EPA for reconsideration, a process that could
lead to more stringent NAAQS for fine particulate matter. EPA also
adopted a more stringent ozone NAAQS on March 27, 2008. Revised SIPs for both
ozone and fine particulates could require electric power generators to further
reduce particulate, nitrogen oxide and sulfur dioxide emissions. In addition to
the SIP process, the Clean Air Act permits states to assert claims against
sources in other “upwind” states alleging that emission sources including coal
fired power plants in the upwind states are preventing the “downwind” states
from attaining a NAAQS. The new NAAQS for ozone and fine particulates, as
well as claims by affected states, could result in additional controls being
required of coal fired power plants and we are unable to predict the effect on
markets for our coal.
Acid Rain Control Provisions.
The acid rain control provisions promulgated as part of the Clean Air Act
Amendments of 1990 in Title IV of the Clean Air Act (“Acid Rain program”)
required reductions of sulfur dioxide emissions from power plants. The Acid Rain
program is now a mature program and we believe that any market impacts of the
required controls have likely been factored into the price of coal in the
national coal market.
Regional Haze Program. EPA
promulgated a regional haze program designed to protect and to improve
visibility at and around so-called Class I Areas, which are generally National
Parks, National Wilderness Areas and International Parks. This program may
restrict the construction of new coal-fired power plants whose operation may
impair visibility at and around the Class I Areas. Moreover, the program
requires certain existing coal-fired power plants to install additional control
measures designed to limit haze-causing emissions, such as sulfur dioxide,
nitrogen oxide and particulate matter. States were required to submit Regional
Haze SIPs to EPA by December 17, 2007. Many states did not meet the December 17,2007, deadline and we are unable to predict the impact on the coal market of the
failure to submit Regional Haze SIPs by the deadline or of any subsequent
submissions deadlines.
New Source Review Program.
Under the Clean Air Act, new and modified sources of air pollution must meet
certain new source standards (“New Source Review Program”). In the late 1990s,
EPA filed lawsuits against many coal-fired plants in the eastern United States
alleging that the owners performed non-routine maintenance, causing increased
emissions that should have triggered the application of these new source
standards. Some of these lawsuits have been settled, with the owners agreeing to
install additional pollution control devices in their coal-fired plants. The
remaining litigation and the uncertainty around the New Source Review Program
rules could adversely impact utilities’ demand for coal in general or coal with
certain specifications, including the coal we produce.
Multi-Pollutant Strategies.
In March 2005, EPA issued two closely related rules designed to significantly
reduce levels of sulfur dioxide, nitrogen oxide and mercury: the Clean Air
Interstate Rule (“CAIR”) and the Clean Air Mercury Rule (“CAMR”). CAIR sets a
“cap-and-trade” program in 28 states and the District of Columbia to establish
emissions limits for sulfur dioxide and nitrogen oxide, by allowing utilities to
buy and sell credits to assist in achieving compliance with the NAAQS for 8-hour
ozone and fine particulates. CAMR as promulgated will cut mercury emissions
nearly 70% by 2018 through a “cap-and-trade” program. Both rules were challenged
in numerous lawsuits and the United States Court of Appeals for the District of
Columbia Circuit vacated CAMR and remanded it to EPA for reconsideration on
February 8, 2008. In February 2009, EPA announced its intention to develop a
technology-based standard under Section 112 of the Clean Air Act to address
mercury emissions rather than pursue the “cap-and-trade” approach of CAMR. The
same court vacated the CAIR on July 11, 2008, but subsequently revised its
remedy to a remand to EPA for reconsideration on December 23, 2008. EPA is
preparing its response to the remand, but the court did not impose a response
date. Regardless of the outcome of litigation on either rule, stricter controls
on emissions of SO2, NOX and
mercury are
likely in some form. Any such controls may have an impact on the demand for our
coal.
17
Global
Climate Change
The
United States has not implemented the 1992 Framework Convention on Global
Climate Change (“Kyoto Protocol”), which became effective for many countries on
February 16, 2005. The Kyoto Protocol was intended to limit or reduce emissions
of greenhouse gases, such as carbon dioxide. The United States has
not ratified the emission targets of the Kyoto Protocol or any other greenhouse
gas agreement among parties.
Nevertheless,
global climate change continues to attract considerable public and scientific
attention and a considerable amount of legislative attention in the United
States is being paid to global climate change and the reduction of greenhouse
gas emissions, particularly from coal combustion by power
plants. Enactment of laws and passage of regulations regarding
greenhouse gas emissions by the United States or some of its states, or other
actions to limit carbon dioxide emissions, could result in electric generators
switching from coal to other fuel sources.
Permitting
and Compliance
Our
operations are principally regulated under surface mining permits issued
pursuant to the SMCRA and state counterpart laws. Such permits are issued for
terms of five years with the right of successive renewal. We currently have over
500 surface mining permits. In conjunction with the surface mining permits, most
operations hold national pollutant discharge elimination system permits pursuant
to the Clean Water Act and state counterpart water pollution control laws for
the discharge of pollutants to waters. These permits are issued for terms of
five years. Additionally, the Clean Water Act requires permits for operations
that fill waters of the United States. Valley fills and refuse impoundments are
authorized under permits issued under the Clean Water Act by the United States
Army Corps of Engineers. Additionally, certain surface mines and preparation
plants have permits issued pursuant to the Clean Air Act and state counterpart
clean air laws allowing and controlling the discharge of air pollutants. These
permits are primarily permits allowing initial construction (not operation) and
they do not have expiration dates.
We
believe we have obtained all permits required for current operations under the
SMCRA, Clean Water Act and Clean Air Act and corresponding state laws. We
believe that we are in compliance in all material respects with such permits,
and routinely correct violations in a timely fashion in the normal course of
operations. The expiration dates of the permits are largely immaterial as the
law provides for a right of successive renewal. The cost of obtaining surface
mining, clean water and air permits can vary widely depending on the scientific
and technical demonstrations that must be made to obtain the permits. However,
our cost of obtaining a permit is rarely more than $500,000 and our cost of
obtaining a renewal is rarely more than $5,000. It is impossible to predict the
full impact of future judicial, legislative or regulatory developments on our
operations, because the standards to be met, as well as the technology and
length of time available to meet those standards, continue to develop and
change.
We
believe, based upon present information available to us, that accruals with
respect to future environmental costs are adequate. For further discussion of
our costs, see Note 9 to the Notes to Consolidated Financial Statements.
However, the imposition of more stringent requirements under environmental laws
or regulations, new developments or changes regarding site cleanup costs or the
allocation of such costs among potentially responsible parties, or a
determination that we are potentially responsible for the release of hazardous
substances at sites other than those currently identified, could result in
additional expenditures or the provision of additional accruals in expectation
of such expenditures.
Comprehensive
Environmental Response, Compensation and Liability Act
The
Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”),
and similar state laws affect coal mining operations by, among other things,
imposing cleanup requirements for threatened or actual releases of hazardous
substances that may endanger public health or welfare or the environment. Under
CERCLA and similar state laws, joint and several liability may be imposed on
waste generators, site owners and lessees and others regardless of fault or the
legality of the original disposal activity. Although EPA excludes most wastes
generated by coal mining and processing operations from the hazardous waste
laws, such wastes can, in certain circumstances, constitute hazardous substances
for the purposes of CERCLA. In addition, the disposal, release or spilling of
some products used by coal companies in operations, such as chemicals, could
implicate the liability provisions of the statute. Under EPA’s Toxic Release
Inventory process, companies are required annually to report the use,
manufacture or processing of listed toxic materials that exceed defined
thresholds, including chemicals used in equipment maintenance, reclamation,
water treatment and ash received for mine placement from power generation
customers. Our current and former coal mining operations incur, and will
continue to incur, expenditures associated with the investigation and
remediation of facilities and environmental conditions under
CERCLA.
18
Endangered
Species Act
The federal
Endangered Species Act and counterpart state legislation protect species
threatened with possible extinction. Protection of 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. Based on the
species that have been identified on our properties to date and the current
application of applicable laws and regulations, 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.
Available
Information
We make
available, free of charge through our Internet website, www.masseyenergyco.com,
our annual report, quarterly reports, current reports, proxy statements, Section
16 reports and other information (and any amendments thereto) as soon as
practicable after filing or furnishing the material to the SEC, in addition to,
our Corporate Governance Guidelines, codes of ethics and the charters of the
Audit, Compensation, Executive, Finance, Governance and Nominating, and Safety,
Environmental, and Public Policy Committees. These materials also may be
requested at no cost by telephone at (866) 814-6512 or by mail at: Massey Energy
Company, Post Office Box 26765, Richmond, Virginia23261, Attention: Investor
Relations.
Incorporated
by reference into this Part I is the information set forth in Part III, Item 10
under the caption “Executive Officers of the Registrant” (included herein
pursuant to Item 401(b) of Regulation S-K).
********************
GLOSSARY
OF SELECTED TERMS
Ash. Impurities consisting of
iron, aluminum 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.
Bituminous coal. The most
common type of coal with moisture content less than 20% by weight and heating
value of 10,500 to 14,000 Btu per pound.
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).
Central Appalachia. Coal
producing states and regions of eastern Kentucky, eastern Tennessee, western
Virginia and southern West Virginia.
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. Described in
Item 1. Business, under the heading “Coal Reserves.”
Continuous miner. A mining
machine with a continuously rolling cutting cylinder used in underground and
highwall mining to cut coal from the seam and load it onto conveyors or into
shuttle cars in a continuous operation.
Direct-ship coal. Coal that
is shipped without first being processed in a preparation plant.
Deep mine. An underground
coal mine.
Dragline. A large machine
used in the surface mining process to remove the overburden, or layers of earth
and rock covering a coal seam. The dragline has a large bucket suspended from
the end of a long boom. The bucket, which is suspended by cables, is able to
scoop up substantial amounts of overburden as it is dragged across the
excavation area.
19
Fossil fuel. Fuel such as
coal, petroleum or natural gas formed from the fossil remains of organic
material.
Highwall mining. Described in
Item 1. Business, under the heading “Mining Methods.”
High vol met coal. Coal that
averages approximately 35% volatile matter. Volatile matter refers to the
impurities that become gaseous when heated to certain temperatures.
Illinois Basin. The Illinois
Basin consists of the coal producing areas in Illinois, Indiana and western
Kentucky.
Industrial coal. Coal used by
industrial steam boilers to produce electricity or process steam. It generally
is lower in Btu heat content and higher in volatile matter than metallurgical
coal.
Longwall mining. Described in
Item 1. Business, under the heading “Mining Methods.”
Low vol met coal. Coal that
averages approximately 20% volatile matter. Volatile matter refers to the
impurities that become gaseous when heated to certain temperatures.
Metallurgical coal. The
various grades of coal suitable for carbonization to make coke for steel
manufacture. Also known as “met” coal, it possesses four important qualities:
volatility, which affects coke yield; the level of impurities, which affects
coke quality; composition, which affects coke strength; and basic
characteristics, which affect coke oven safety. Met coal has a particularly high
Btu heat content, but low ash content.
Mine. A mine consists of
those operating assets necessary to produce coal from surface or underground
locations.
Nitrogen oxide (NOx).
Nitrogen oxide is produced as a gaseous by-product of coal
combustion.
Northern Appalachia. Northern
Appalachia consists of the bituminous coal producing areas in the states of
Pennsylvania, Ohio and Maryland and in the northern part of West
Virginia.
Overburden. Layers of earth
and rock covering a coal seam. In surface mining operations, overburden is
removed prior to coal extraction.
Overburden ratio. The amount
of overburden that must be removed to excavate a given quantity of coal. It is
commonly expressed in cubic yards per ton of coal or as a ratio comparing the
thickness of the overburden with the thickness of the coal bed.
Pillar. An area of coal left
to support the overlying strata in an underground mine, sometimes left
permanently to support surface structures.
Powder River Basin. The
Powder River Basin consists of the coal producing areas in southeast Montana and
northeast Wyoming.
Preparation plant. A
preparation plant is a facility for crushing, sizing and washing coal to remove
rock and other impurities to prepare it for use by a particular customer.
Preparation plants are usually located on a mine site, although one plant may
serve several mines. The washing process has the added benefit of removing some
of the coal’s sulfur content.
Probable
reserves. Described in
Item 1. Business, under the heading “Coal Reserves.”
Proven reserves. Described in
Item 1. Business, under the heading “Coal Reserves.”
Reclamation. The process of
restoring land and the environment to their approximate 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.
Reserve. Described in Item 1.
Business, under the heading “Coal Reserves.”
20
Resource Group. An
organizational unit, generally located within a specific geographic locale, that
contains one or more of the following operations related to the mining,
processing or shipping of coal: underground mine, surface mine,
preparation plant or load-out facility.
Roof. The stratum of rock or
other mineral above a coal seam; the overhead surface of a coal working
place.
Room and pillar mining.
Described in Item 1. Business, under the heading “Mining Methods.”
Scrubber (flue gas desulfurization
unit). Any of several forms of chemical/physical devices that operate to
neutralize sulfur and other greenhouse gases 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 or process steam. It generally is lower in Btu
heat content and higher in volatile matter than metallurgical coal. Also known
as utility coal.
Stoker coal. Coal that is
sized to a specific, standard range. Stoker coal is typically one quarter inch
by one and one quarter to one and three quarter inch.
Sulfur. One of the elements
present in varying quantities in coal that reacts with air when coal is burned
to form sulfur dioxide.
Sulfur content. Coal is
commonly described by its sulfur content due to the importance of sulfur in
environmental regulations. “Low sulfur” coal has a variety of definitions, but
typically is used to describe coal consisting of 1.0% or less
sulfur.
Sulfur dioxide (SO2). Sulfur dioxide is produced
as a gaseous by-product of coal combustion.
Surface mining. Described in
Item 1. Business, under the heading “Mining Methods.”
Tons. A “short” or net ton is
equal to 2,000 pounds. A “long” or British ton is approximately 2,240 pounds; a
“metric” ton is approximately 2,205 pounds. The short ton is the unit of measure
referred to in this Annual Report on Form 10-K.
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 or conveyor to the surface.
Unit train. A railroad train
of a specified number of railroad cars carrying only coal. A typical unit train
can carry at least 10,000 tons of coal in a single shipment.
Utility coal. Coal used by
power plants to produce electricity or process steam. It generally is lower in
Btu heat content and higher in volatile matter than metallurgical coal. Also
known as steam coal.
********************
21
Item
1A. Risk Factors
We are
subject to a variety of risks, including, but not limited to, those risk factors
set forth below and those referenced herein to other Items contained in this
Annual Report on Form 10-K, including Item 1. Business, under the headings
“Customers and Coal Contracts,”“Competition,”“Environmental, Safety and Health
Laws and Regulations,” Item 3. Legal Proceedings and Item 7. Management’s
Discussion and Analysis of Financial Condition and Results of Operations
(“MD&A”), under the headings “Critical Accounting Estimates and
Assumptions,”“Certain Trends and Uncertainties” and elsewhere in
MD&A.
We
could be negatively impacted by the competitiveness of the markets in which we
compete and declines in the market demand for coal.
We
compete with coal producers in various regions of the United States and overseas
for domestic and international sales. Continued domestic demand for our coal and
the prices that we will be able to obtain primarily will depend upon coal
consumption patterns of the domestic electric utility industry and the domestic
steel industry. Consumption by the domestic utility industry is affected by the
demand for electricity, environmental and other governmental regulations,
technological developments and the price of competing coal and alternative fuel
supplies including nuclear, natural gas, oil and renewable energy sources,
including hydroelectric power. Consumption by the domestic steel industry is
primarily affected by economic growth and the demand for steel used in
construction as well as appliances and automobiles. In recent years and until a
worldwide financial crisis developed in mid-2008, the competitive environment
for coal was impacted by sustained growth in a number of the largest markets in
the world, including the United States, China, Japan and India, where demand for
both electricity and steel supported pricing for steam and metallurgical coal.
The financial crisis has reduced demand and increased competition in supplying
these markets. The cost of ocean transportation and the value of the United
States dollar in relation to foreign currencies significantly impact the
relative attractiveness of our coal as we compete on price with other foreign
coal producing sources. Increased competition by competing coal producers or
producers of alternate fuels in the markets in which we serve could cause a
decrease in demand and/or pricing for our coal, adversely impacting our cash
flows, results of operations or financial condition.
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 markets for metallurgical and
steam coal. 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,
potentially reducing the price we could obtain for this coal and adversely
impacting our cash flows, results of operations or financial
condition.
Demand
for our coal depends on its price and quality and the cost of transporting it to
our customers.
Coal
prices are influenced by a number of factors and may vary dramatically by
region. The two principal components of the price of coal are the price of coal
at the mine, which is influenced by mine operating costs and coal quality, and
the cost of transporting coal from the mine to the point of use. The cost of
mining the coal is influenced by geologic characteristics such as seam
thickness, overburden ratios and depth of underground reserves. Underground
mining is generally more expensive than surface mining as a result of higher
costs for labor (including reserves for future costs associated with labor
benefits and health care) and capital costs (including costs for mining
equipment and construction of extensive ventilation systems). As of January 31,2009, we operated 46 active underground mines, including two which employ both
room and pillar and longwall mining, and 20 active surface mines, with 11
highwall miners.
Transportation
costs represent a significant portion of the delivered cost of coal and, as a
result, the cost of delivery is a critical factor in a customer’s purchasing
decision. Increases in transportation costs could make coal a less competitive
source of energy. Such increases could have a material impact on our ability to
compete with other energy sources and on our cash flows, results of operations
or financial condition. Conversely, significant decreases in transportation
costs could result in increased competition from coal producers in other parts
of the country or the world, including coal imported into the United States
(several United States ports have recently increased or announced plans to
increase their capacity to handle imported coal). For instance, coal mines in
the western United States could become an increasingly attractive source of coal
to consumers in the eastern part of the United States if the costs of
transporting coal from the west were significantly reduced and/or rail capacity
was increased.
A
significant decline in coal prices in general could adversely affect our
operating results and cash flows.
Our
results are highly dependent upon the prices we receive for our coal. Decreased
demand for coal, both domestically and internationally, is causing spot prices
and the prices we are able to negotiate on long-term contracts to decline. The
lower prices could negatively affect our cash flows, results of operations or
financial condition, if we are unable to increase productivity and/or decrease
costs in order to maintain our margins.
22
We
depend on continued demand from our customers.
Reduced
demand from or the loss of our largest customers could have an adverse impact on
our ability to achieve projected revenue. Decreases in demand may result from,
among other things, a reduction in consumption by the electric generation
industry and/or the steel industry, the availability of other sources of fuel at
cheaper costs and a general slow-down in the economy. When our contracts with
customers expire, there can be no assurance that the customers either will
extend or enter into new long-term contracts or, in the absence of long-term
contracts, that they will continue to purchase the same amount of coal as they
have in the past or on terms, including pricing terms, as favorable as under
existing arrangements. For example, our largest customer, Constellation,
accounted for 11% of fiscal year 2008 Produced coal revenue. For fiscal year
2009, our contracted sales to Constellation currently represent approximately
26% of our projected produced coal tonnage and 18% of our
projected Produced coal revenue. There are
no other customers to whom we expect to sell 10% or more of produced tons or to
account for 10% or more of Produced coal revenue in 2009. In the
event that a large customer account is lost or a long-term contract is not
renewed, profits could suffer if alternative buyers are not willing to purchase
our coal on comparable terms.
There
may be adverse changes in price, volume or terms of our existing coal supply
agreements.
Many of
our coal supply agreements contain provisions that permit the parties to adjust
the contract price upward or downward at specified times. These contracts may be
adjusted based on inflation or deflation and/or changes in the factors affecting
the cost of producing coal, such as taxes, fees, royalties and changes in the
laws regulating the mining, production, sale or use of coal. In a limited number
of contracts, failure of the parties to agree on a price under those provisions
may allow either party to terminate the contract. Coal supply agreements also
typically contain force majeure provisions allowing temporary suspension of
performance by us or the customer for the duration of specified events beyond
the control of the affected party. Most 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.
Our
financial condition may be adversely affected if we are required by some of our
customers to provide performance assurances for certain below-market sales
contracts.
Contracts
covering a significant portion of our contracted sales tons contain provisions
that could require us to provide performance assurances if we experience a
material adverse change or, under certain other contracts, if the customer
believes our creditworthiness has become unsatisfactory. Generally, under such
contracts, performance assurances are only required if the contract price per
ton of coal is below the current market price of the coal. Certain of the
contracts limit the amount of performance assurance to a per ton amount in
excess of the contract price, while others have no limit. The performance
assurances are generally provided by the posting of a letter of credit, cash
collateral, other security, or a guaranty from a creditworthy guarantor. As of
December 31, 2008, we have not received any requests from any of our customers
to provide performance assurances. If we are required to post performance
assurances on some or all of our contracts with performance assurances
provisions, there could be a material adverse impact on our cash flows, results
of operations or financial condition.
The
level of our indebtedness could adversely affect our ability to grow and compete
and prevent us from fulfilling our obligations under our contracts and
agreements.
At
December 31, 2008, we had $1,465.6 million of total indebtedness outstanding,
which represented 58.6% of our total book capitalization. During 2008, we issued
$690 million of 3.25% convertible senior notes due 2015 (“3.25% Notes”) and
tendered for and retired $313.1 million of our 6.625% senior notes due 2010
(“6.625% Notes”). We have significant debt, lease and royalty
obligations. Our ability to satisfy debt service, lease and royalty obligations
and to effect any refinancing of indebtedness will depend upon future operating
performance, which will be affected by prevailing economic conditions in the
markets that we serve as well as financial, business and other factors, many of
which are beyond our control. We may be unable to generate sufficient cash flow
from operations and future borrowings, or other financings may be unavailable in
an amount sufficient to enable us to fund our debt service, lease and royalty
payment obligations or our other liquidity needs.
23
Our
relative amount of debt could have material consequences to our business,
including, but not limited to: (i) making it more difficult to satisfy debt
covenants and debt service, lease payments and other obligations; (ii) making it
more difficult to pay quarterly dividends as we have in the past; (iii)
increasing our vulnerability to general adverse economic and industry
conditions; (iv) limiting our ability to obtain additional financing to fund
future acquisitions, working capital, capital expenditures or other general
corporate requirements; (v) reducing the availability of cash flows from
operations to fund acquisitions, working capital, capital expenditures or other
general corporate purposes; (vi) limiting our flexibility in planning
for, or reacting to, changes in the business and the industry in which we
compete; or (vii) placing us at a competitive disadvantage with competitors with
relatively lower amounts of debt. Any of the above-listed factors could have an
adverse effect on our business, financial condition and results of operations
and our ability to meet our debt payment obligations.
The
covenants in our credit facility and the indentures governing debt instruments
impose restrictions that may limit our operating and financial
flexibility.
Our $175
million asset-based loan credit facility (“ABL Facility”) contains a number of
significant restrictions and covenants that may limit our ability and our
subsidiaries’ ability to, among other things: (1) incur additional indebtedness;
(2) increase common stock dividends above specified levels; (3) make loans and
investments; (4) prepay, redeem or repurchase debt; (5) engage in mergers,
consolidations and asset dispositions; (6) engage in affiliate transactions; (7)
create any lien or security interest in any real property or equipment; (8)
engage in sale and leaseback transactions; and (9) make distributions from
subsidiaries. A decline in our operating results or other adverse factors,
including a significant increase in interest rates, could result in us being
unable to comply with certain covenants contained in the ABL Facility, which
become operative only when our Average Excess Availability (as defined in the
ABL Facility) is less than $30 million. These financial covenants include a
Minimum Consolidated Fixed Charge Ratio of 1.00 to 1.00 and a minimum
Consolidated Net Worth of $550 million under the terms of the ABL Facility (currently
approximately $400 million as adjusted for Accounting
Changes).
The
indentures governing certain of our senior notes also contain a number of
significant restrictions and covenants that may limit our ability and our
subsidiaries’ ability to, among other things: (1) incur additional indebtedness;
(2) subordinate indebtedness to other indebtedness unless such subordinated
indebtedness is also subordinated to the notes; (3) pay dividends or make other
distributions or repurchase or redeem our stock or subordinated indebtedness;
(4) make investments; (5) sell assets and issue capital stock of restricted
subsidiaries; (6) incur liens; (7) enter into agreements restricting our
subsidiaries’ ability to pay dividends; (8) enter into sale and leaseback
transactions; (9) enter into transactions with affiliates; and (10) consolidate,
merge or sell all or substantially all of our assets. If we violate these
covenants and are unable to obtain waivers from our lenders, our debt under
these agreements would be in default and could be accelerated by the lenders
and, in the case of an event of default under our ABL Facility, it could permit
the lenders to foreclose on our assets securing the loans under the ABL
Facility. If the indebtedness is accelerated, we may not be able to repay our
debt or borrow sufficient funds to refinance it. Even if we are able to obtain
new financing, it may not be on commercially reasonable terms or on terms that
are acceptable to us. If our debt is in default for any reason, our cash flows,
results of operations or financial condition could be materially and adversely
affected. In addition, complying with these covenants may also cause us to take
actions that are not favorable to our shareholders and holders of our senior
notes and may make it more difficult for us to successfully execute our business
strategy and compete against companies that are not subject to such
restrictions.
We
are subject to being adversely affected by the potential inability to renew or
obtain surety bonds.
Federal
and state laws require bonds to secure our obligations to reclaim lands used for
mining, to pay federal and state workers’ compensation and to satisfy other
miscellaneous obligations. These bonds are typically renewable annually. Surety
bond issuers and holders may not continue to renew the bonds or may demand
additional collateral upon those renewals. We are also subject to increases in
the amount of surety bonds required by federal and state laws as these laws
change or the interpretation of these laws changes. Our failure to maintain, or
inability to acquire, surety bonds that are required by state and federal law
would have a material adverse impact on us, possibly by prohibiting us from
developing properties that we desire to develop. That failure could result from
a variety of factors including the following: (i) lack of availability,
higher expense or unfavorable market terms of new bonds; (ii) restrictions
on availability of collateral for current and future third-party surety bond
issuers under the terms of our senior notes or revolving credit facilities;
(iii) our inability to meet certain financial tests with respect to a
portion of the post-mining reclamation bonds; and (iv) the exercise by
third-party surety bond issuers of their right to refuse to renew or issue new
bonds.
We
depend on our ability to continue acquiring and developing economically
recoverable coal reserves.
A key
component of our future success is our ability to continue acquiring coal
reserves for development that have the geological characteristics that allow
them to be economically mined. Replacement reserves may not be available or, if
available, may not be capable of being mined at costs comparable to those
characteristics of the depleting mines. An inability to continue acquiring
economically recoverable coal reserves could have a material impact on our cash
flows, results of operations or financial condition.
24
We
face numerous uncertainties in estimating economically recoverable coal
reserves, and inaccuracies in estimates could result in lower than expected
revenues, higher than expected costs and decreased
profitability.
There are numerous
uncertainties inherent in estimating quantities and values of economically
recoverable coal reserves, including many factors 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 and analyzed by us. Some of
the factors and assumptions that impact economically recoverable reserve
estimates include: (1) geological conditions; (2) historical
production from the area compared with production from other producing areas;
(3) the effects of regulations and taxes by governmental agencies;
(4) future prices; and (5) future operating costs.
Each of
these factors may 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 may vary
substantially. As a result, our estimates may not accurately reflect our actual
reserves. Actual production, revenues and expenditures with respect to reserves
will likely vary from estimates, and these variances may be
material.
Defects
in title or loss of any leasehold interests in our properties could limit our
ability to mine our properties or result in significant unanticipated
costs.
A
significant portion of our mining operations occurs on properties that we lease.
Title defects or the loss of leases could adversely affect our ability to mine
the reserves covered by those leases. Our current practice is to obtain a title
review from a licensed attorney prior to leasing property. We generally have not
obtained title insurance in connection with acquisitions of coal reserves. In
some cases, the seller or lessor warrants property title. Separate title
confirmation sometimes is not required when leasing reserves where mining has
occurred previously. Our right to mine some of our reserves may be adversely
affected if defects in title or boundaries exist. In order to obtain leases to
conduct our mining operations on property where these defects exist, we may have
to incur unanticipated costs. In addition, we may not be able to successfully
negotiate new leases for properties containing additional reserves, or maintain
our leasehold interests in properties where we have not commenced mining
operations during the term of the lease.
If
the coal industry experiences overcapacity in the future, our profitability
could be impaired.
An
increase in the demand for coal could attract new investors to the coal
industry, which could spur the development of new mines, and result in added
production capacity throughout the industry. During 2008 we increased our coal
production having added 19 additional coal mines in the last twelve months. By
the end of 2008, our expansion work was continuing and was largely complete.
Further expansion plans for 2009 have been deferred or cancelled in light of the
changes in market conditions. Several of our competitors have also been
increasing their production capacity; however, the recent global financial
crisis has caused some of these competitors to announce delays in their
expansion projects. Higher price levels of coal could further encourage the
development of expanded capacity by new or existing coal producers. Any
resulting increases in capacity could further reduce coal prices and reduce our
margins.
An
inability of brokerage sources or contract miners to fulfill the delivery terms
of their contracts with us could reduce our profitability.
We
sometimes obtain coal from brokerage sources and contract miners to fulfill
deliveries under our coal supply agreements. Some of our brokerage sources
and contract miners may experience adverse geologic mining, escalated operating
costs and/or financial difficulties that make their delivery of coal to us at
the contracted price difficult or uncertain. Our profitability or exposure to
loss on transactions or relationships such as these may be affected based upon
the reliability of the supply or the ability to substitute, when economical,
third-party coal sources, with internal production or coal purchased in the
market and other factors.
Decreased
availability or increased costs of key equipment, supplies or commodities such
as diesel fuel, steel, explosives, magnetite and tires could decrease our
profitability.
Our
operations are dependant on reliable supplies of mining equipment, replacement
parts, explosives, diesel fuel, tires, magnetite and steel-related products
(including roof bolts). If the cost of any mining equipment or key supplies
increases significantly, or if they should become unavailable due to higher
industry-wide demand or less production by suppliers, there could be an adverse
impact on our cash flows, results of operations or financial condition. The
supplier base providing mining materials and equipment has been relatively
consistent in recent years, although there continues to be consolidation. This
consolidation has resulted in a situation where purchases of explosives and
certain underground mining equipment are concentrated with single suppliers. In
recent years, mining industry demand growth has exceeded supply growth for
certain surface and underground mining equipment and heavy equipment tires. As a
result, lead times for certain items have generally increased.
25
Transportation
disruptions could impair our ability to sell coal.
We are dependent on
our transportation providers to provide access to markets. Disruption of
transportation services because of weather-related problems, strikes, lockouts,
fuel shortages or other events could temporarily impair our ability to supply
coal to customers. Our ability to ship coal could be negatively impacted by a
reduction in available and timely rail service. Lack of sufficient resources to
meet a rapid increase in demand, a greater demand for transportation to export
terminals and rail line congestion all could contribute to a disruption and
slowdown in rail service. We continue to experience rail service delays and
disruptions in service which are negatively impacting our ability to deliver
coal to customers and which may adversely affect our results of
operations.
Severe
weather may affect our ability to mine and deliver coal.
Severe
weather, including flooding and excessive ice or snowfall, when it occurs, can
adversely affect our ability to produce, load and transport coal, which may
negatively impact our cash flows, results of operations or financial
condition.
Federal,
state and local laws and government regulations applicable to operations
increase costs and may make our coal less competitive than other coal
producers.
We incur
substantial costs and liabilities under increasingly strict federal, state and
local environmental, health and safety and endangered species laws, regulations
and enforcement policies. Failure to comply with these laws and regulations may
result in the assessment of administrative, civil and criminal penalties, the
imposition of cleanup and site restoration costs and liens, the issuance of
injunctions to limit or cease operations, the suspension or revocation of
permits and other enforcement measures that could have the effect of limiting
production from our operations. The costs of compliance with applicable
regulations and liabilities assessed for compliance failure could have a
material adverse impact on our cash flows, results of operations or financial
condition.
New
legislation and new regulations may be adopted which could materially adversely
affect our mining operations, cost structure or our customers’ ability to use
coal. New legislation and new regulations may also require us, as well as our
customers, to change operations significantly or incur increased costs. The
United States Environmental Protection Agency (the “EPA”) has undertaken broad
initiatives to increase compliance with emissions standards and to provide
incentives to our customers to decrease their emissions, often by switching to
an alternative fuel source or by installing scrubbers or other expensive
emissions reduction equipment at their coal-fired plants.
Concerns
about the environmental impacts of coal combustion, including perceived impacts
on global climate change, are resulting in increased regulation of coal
combustion in many jurisdictions, and interest in further regulation, which
could significantly affect demand for our products.
The Clean
Air Act and similar state and local laws extensively regulate the amount of
sulfur dioxide, particulate matter, nitrogen oxides and other compounds emitted
into the air from electric power plants, which are the largest end-users of our
coal. Such regulation may require significant emissions control expenditures for
many coal-fired power plants. As a result, the generators may switch to other
fuels that generate less of these emissions or install more effective pollution
control equipment, possibly reducing future demand for coal and the construction
of coal-fired power plants. 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.
26
Global
climate change continues to attract considerable public and scientific
attention. Widely publicized scientific reports, such as the Fourth Assessment
Report of the Intergovernmental Panel on Climate Change released in 2007, have
also engendered widespread concern about the impacts of human activity,
especially fossil fuel combustion, on global climate change. A considerable and
increasing amount of attention in the United States is being paid to global
climate change and to reducing greenhouse gas emissions, particularly from coal
combustion by power plants. According to the EIA report, “Emissions of
Greenhouse Gases in the United States 2007,” coal combustion accounts for 30% of
man-made greenhouse gas emissions in the United States. Legislation was
introduced in Congress in the past several years to reduce greenhouse gas
emissions in the United States and, although no bills to reduce such emissions
have yet passed either house of Congress, bills to reduce such emissions remain
pending and others are likely to be introduced. President Obama campaigned in
favor of a “cap-and-trade” program to require mandatory greenhouse gas emissions
reductions and since his election has continued to express support for such
legislation, contrary to the previous administration. The United
States Supreme Court’s 2007 decision in Massachusetts v. Environmental
Protection Agency ruled that EPA improperly declined to address carbon
dioxide impacts on climate change in a rulemaking related to new motor vehicles.
The reasoning of the court decision could affect other federal regulatory
programs, including those that directly relate to coal use. In July 2008, EPA
published an Advanced Notice of Proposed Rulemaking (ANPR) seeking comments
regarding the regulation of greenhouse gas emissions; and in February 2009 the
newly appointed administrator of EPA granted a petition by environmental
advocacy groups to reconsider an interpretive memorandum by her predecessor in
December 2008 that concluded the Clean Air Act’s Prevention of
Significant Deterioration program does not extend to carbon dioxide
emissions, a decision that could lead to carbon dioxide emissions from
coal-fired power plants being a consideration in permitting decisions. In
addition, a growing number of states in the United States are taking steps to
require greenhouse gas emissions reductions from coal-fired power plants. Enactment of laws and
promulgation of regulations regarding greenhouse gas emissions by the United
States or some of its states, or other actions to limit carbon dioxide
emissions, could result in electric generators switching from coal to other fuel
sources.
As part
of the United Nations Framework Convention on Climate Change, representatives
from 187 nations met in Bali, Indonesia in December 2007 to discuss a program to
limit greenhouse gas emissions after 2012. The United States participated in the
conference. The convention adopted what is called the “Bali Action Plan.” The
Bali Action Plan contains no binding commitments, but concludes that “deep cuts
in global emissions will be required” and provides a timetable for two years of
talks to shape the first formal addendum to the 1992 United Nations Framework
Convention on Climate Change treaty since the Kyoto Protocol. The ultimate
outcome of the Bali Action Plan, and any treaty or other arrangement ultimately
adopted by the United States or other countries, may have a material adverse
impact on the global supply and demand for coal. This is particularly true if
cost effective technology for the capture and sequestration of carbon dioxide is
not sufficiently developed. Technologies that may significantly reduce emissions
into the atmosphere of greenhouse gases from coal combustion, such as carbon
capture and sequestration (which captures carbon dioxide at major sources such
as power plants and subsequently stores it in nonatmospheric reservoirs such as
depleted oil and gas reservoirs, unmineable coal seams, deep saline formations,
or the deep ocean) have attracted and continue to attract the attention of
policy makers, industry participants, and the public. For example, in July 2008
EPA proposed rules that would establish, for the first time, requirements
specifically for wells used to inject carbon dioxide into geologic formations.
Considerable uncertainty remains, not only regarding rules that may become
applicable to carbon dioxide injection wells but also concerning liability for
potential impacts of injection, such as groundwater contamination or seismic
activity. In addition, technical, environmental, economic, or other factors may
delay, limit, or preclude large-scale commercial deployment of such
technologies, which could ultimately provide little or no significant reduction
of greenhouse gas emissions from coal combustion.
Further
developments in connection with legislation, regulations or other limits on
greenhouse gas emissions and other environmental impacts from coal combustion,
both in the United States and in other countries where we sell coal, could have
a material adverse effect on our cash flows, results of operations or financial
condition.
Our
operations may adversely impact the environment which could result in material
liabilities to us.
The processes required
to mine coal may cause certain impacts or generate certain materials that might
adversely affect the environment from time to time. The mining processes we use
could cause us to become subject to claims for toxic torts, natural resource
damages and other damages as well as for the investigation and clean up of soil,
surface water, groundwater, and other media. Such claims may arise, for example,
out of conditions at sites that we currently own or operate, as well as at sites
that we previously owned or operated, or may acquire. 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.
Certain coal that we
mine needs to be cleaned at preparation plants, which generally require coal
refuse areas and/or slurry impoundments. Such areas and impoundments are subject
to extensive regulation and monitoring. Slurry impoundments have been known to
fail, releasing large volumes of coal slurry into nearby surface waters and
property, resulting in damage to the environment and natural resources, as well
as injuries to wildlife. We maintain coal refuse areas and slurry impoundments
at a number of our mining complexes. If one of our impoundments were to
fail, we could be subject to substantial claims for the resulting environmental
impact and associated liability, as well as for fines and
penalties.
27
Drainage flowing from or caused by mining activities can be acidic
with elevated levels of dissolved metals, a condition referred to as acid mine
drainage (“AMD”). Although we do not currently face material costs
associated with AMD, it is possible that we could incur significant costs in the
future.
These and
other similar unforeseen impacts that our operations may have on the
environment, as well as exposures to certain substances or wastes associated
with our operations, could result in costs and liabilities that could materially
and adversely affect us and could have a material adverse impact on our cash
flows, results of operations or financial condition.
The
Mine Safety and Health Administration (“MSHA”) or other federal or state
regulatory agencies may order certain of our mines to be temporarily or
permanently closed, which could adversely affect our ability to meet our
customers’ demands.
MSHA or
other federal or state regulatory agencies may order certain of our mines to be
temporarily or permanently closed. Our customers may challenge our issuance of
force majeure notices in connection with such closures. If these challenges
are successful, we may have to purchase coal from third-party sources to satisfy
those challenges; negotiate settlements with customers, which may include price
reductions, the reduction of commitments or the extension of the time for
delivery, terminate customers’ contracts or face claims initiated by our
customers against us. The resolution of these challenges could have a material
adverse impact on our cash flows, results of operations or financial
condition.
We
must obtain governmental permits and approvals for mining operations, which can
be a costly and time-consuming process, can result in restrictions on our
operations, and is subject to litigation that may delay or prevent us from
obtaining necessary permits.
Our
operations are principally regulated under surface mining permits issued
pursuant to the Surface Mining Control and Reclamation Act (the “SMCRA”) and
state counterpart laws. Such permits are issued for terms of five years with the
right of successive renewal. Additionally, the Clean Water Act requires permits
for operations that discharge into waters of the United States. Valley fills and
refuse impoundments are authorized under permits issued by the United States
Army Corps of Engineers. Such permitting under the Clean Water Act has been a
frequent subject of litigation by environmental advocacy groups that has
resulted in periodic declines in such permits issued by the United States Army
Corps of Engineers. Additionally, certain surface mines and preparation plants
have permits issued pursuant to the Clean Air Act and state counterpart laws
allowing and controlling the discharge of air pollutants. Regulatory authorities
exercise considerable discretion in the timing of permit issuance. Requirements
imposed by these authorities may be costly and time-consuming and may result in
delays in, or in some instances preclude, the commencement or continuation of
development or production operations. Adverse outcomes in lawsuits challenging
permits or failure to comply with applicable regulations could result in the
suspension, denial or revocation of required permits, which could have a
material adverse impact on our cash flows, results of operations or financial
condition.
The
loss of key personnel or the failure to attract qualified personnel could affect
our ability to operate the Company effectively.
The
successful management of our business is dependent on a number of key personnel.
Our future success will be affected by our continued ability to attract and
retain highly skilled and qualified personnel. There are no assurances that key
personnel will continue to be employed by us or that we will be able to attract
and retain qualified personnel in the future. Failure to retain or attract key
personnel could have an adverse affect on our cash flows, results of operations
or financial condition.
Shortages of skilled labor in the
Central Appalachian coal industry may pose a risk in achieving high levels of
productivity at competitive costs.
Coal
mining continues to be a labor-intensive industry. In recent years, we have
encountered a shortage of experienced mine workers when the demand and prices
for all specifications of coal we mine increased appreciably. The hiring of
these less experienced workers has negatively impacted our productivity and cash
costs. A continued lack of skilled miners could continue to have an adverse
impact on our labor productivity and cost and our ability to meet current
production requirements to fulfill existing sales commitments or to expand
production to meet the increased demand for coal.
Union
represented labor creates an increased risk of work stoppages and higher labor
costs.
At
December 31, 2008, approximately 1.8% of our total workforce was represented by
the United Mine Workers of America (the “UMWA”). Our unionized workforce is
spread out amongst five of our coal preparation plants and one smaller surface
mine. In 2008, these preparation plants handled approximately 29.3% of our coal
production. We are currently in the process of negotiating successor collective
bargaining agreements for ones that have expired. In connection with these
negotiations and with respect to our unionized operations generally, there may
be an increased risk of strikes and other labor disputes, as well as higher
labor costs. If some or all of our current open shop operations were to become
unionized, we could be subject to additional risk of work stoppages, other labor
disputes and higher labor costs, which could adversely affect the stability of
production and reduce net income.
28
Legislation has been
proposed to the United States Congress to enact a law allowing for workers to
choose union representation solely by signing election cards (“Card Check”),
which would eliminate the use of secret ballots to elect union representation.
While the impact is uncertain, if Card
Check legislation is enacted into law, it will be administratively easier for
the UMWA to unionize coal mines and may lead to more coal mines becoming
unionized.
Inflationary
pressures on supplies and labor may adversely affect our profit
margins.
Although
inflation in the United States has been relatively low in recent years, over the
course of the last two to three years, we have been significantly impacted by
price inflation in many of the components of our cost of produced coal
revenue, such as fuel, steel and labor. If the prices for which we sell
our coal do not increase in step with rising costs or if these costs do not
decline sufficiently, our profit margins would be reduced and our cash flows,
results of operations or financial condition would be adversely
affected.
We
are subject to various legal proceedings, which may have a material effect on
our business.
We are
parties to a number of legal proceedings incident to normal business activities.
Some of the allegations brought against us are with merit, while others are not.
There is always the potential that an individual matter or the aggregation of
many matters could have a material adverse effect on our cash flows, results of
operations or financial position. See Note 18 of the Notes to Consolidated
Financial Statements.
We
have significant reclamation and mine closure obligations. If the assumptions
underlying our accruals are materially inaccurate, we could be required to
expend greater amounts than anticipated.
SMCRA
establishes operational, reclamation and closure standards for all aspects of
surface mining as well as most aspects of deep mining. Estimates of our total
reclamation and mine-closing liabilities are based upon permit requirements and
our engineering expertise related to these requirements. The estimate of
ultimate reclamation liability is reviewed periodically by management and
engineers. The estimated liability can change significantly if actual costs vary
from assumptions or if governmental regulations change
significantly.
Our
future expenditures for postretirement benefit and pension obligations could be
materially higher than we have predicted if our underlying assumptions are
incorrect.
We are
subject to long-term liabilities under a variety of benefit plans and other
arrangements with current and former employees. These obligations have been
estimated based on actuarial assumptions, including actuarial estimates, assumed
discount rates, estimates of life expectancy, expected returns on pension plan
assets and changes in healthcare costs.
If our
assumptions relating to these benefits change in the future or are incorrect, we
may be required to record additional expenses, which would reduce our
profitability. 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 impact on our cash flows, results of
operations or financial condition. See also Notes 5, 10 and 11 of the Notes to
Consolidated Financial Statements for
further discussion.
Our
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 a qualified non-contributory defined benefit pension plan, which covers
substantially all administrative and non-union employees. We
currently expect to make contributions in 2009 of approximately $10 million. If
the performance of the assets in our pension plans does not meet our
expectations, or if other actuarial assumptions are modified, our contributions
could be higher than we expect.
The value
of the assets held in our pension plans has been adversely affected by the
recent disruptions in the financial markets, and the applicable discount rates
applied in determining our pension liabilities have also been negatively
affected by the crisis in the financial markets. As a result, as of
December 31, 2008, our annual measurement date, our pension plan was
underfunded by $63 million (based on the actuarial assumptions used for SFAS
No. 158, Employers’
Accounting for Defined Benefit Pension and Other Postretirement Plans—an
amendment of FASB Statements No. 87, 88, 106, and 132(R) (“SFAS
No. 158”)). Our 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 pension plan is terminated for any reason while
the plan is underfunded, we will incur a liability to the PBGC that may be equal
to the entire amount of the underfunding.
29
Provisions
in our restated certificate of incorporation and restated bylaws, the agreements
governing our indebtedness and Delaware law may discourage a takeover attempt
even if doing so might be beneficial to our shareholders.
Provisions
contained in our restated certificate of incorporation and restated bylaws could
impose impediments to the ability of a third-party to acquire us even if a
change of control would be beneficial to you. Provisions of our restated
certificate of incorporation and restated bylaws impose various procedural and
other requirements, which could make it more difficult for stockholders to
effect certain corporate actions. For example, our restated 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 Common
Stock. We are also subject to provisions of Delaware law that prohibit us from
engaging in any business combination with any “interested stockholder,”
meaning, generally, that a stockholder who beneficially owns more than 15% of
Common Stock cannot acquire us for a period of three years from the date this
person became an interested stockholder unless various conditions are met, such
as approval of the transaction by our board of directors. 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 Common Stock.
If a
“fundamental change” (as defined in the indenture governing the 3.25%
convertible senior notes due 2015 (“3.25% Notes”)) occurs, holders of the 3.25%
Notes will have the right, at their option, either to convert their 3.25% Notes
or require us to repurchase all or a portion of their 3.25% Notes, and holders
of the 4.75% convertible senior notes due 2023 and 2.25% convertible senior
notes due 2024 will have the right to require us to repurchase all or a portion
of their notes. In the event of a “make-whole fundamental change” (as defined in
the indenture governing the 3.25% Notes), we also may be required to increase
the conversion rate applicable to any 3.25% Notes surrendered for conversion. In
addition, the indentures for the convertible notes prohibit 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 convertible notes.
Certain of our debt instruments impose 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
you.
We
may not realize all or any of the anticipated benefits from acquisitions we
undertake, as acquisitions entail a number of inherent risks.
From time
to time we expand our business and reserve position through acquisitions of
businesses and assets, mergers, joint ventures or other transactions. Such
transactions involve various inherent risks, such as:
§
uncertainties
in assessing the value, strengths and potential profitability of, and
identifying the extent of all weaknesses, risks, contingent and other
liabilities (including environmental liabilities) of, acquisition or other
transaction candidates;
§
the
potential loss of key customers, management and employees of an acquired
business;
§
the
ability to achieve identified operating and financial synergies
anticipated to result from an acquisition or other
transaction;
§
problems
that could arise from the integration of the acquired
business;
§
the
risk of obtaining mining permits for acquired coal assets;
and
§
unanticipated
changes in business, industry or general economic conditions that affect
the assumptions underlying the acquisition or other transaction
rationale.
Any one
or more of these and other factors could cause us not to realize the benefits
anticipated to result from the acquisition of businesses or assets or could
result in unexpected liabilities associated with these
acquisitions.
Foreign
currency fluctuations could adversely affect the competitiveness of our coal
abroad.
We rely
on customers in other countries for a portion of our sales, with shipments to
countries in North America, South America, Europe, Asia and Africa. We compete
in these international markets against coal produced in other countries. Coal is
sold internationally in United States dollars. As a result, mining costs in
competing producing countries may be reduced in United States dollar terms based
on currency exchange rates, providing an advantage to foreign coal producers.
Currency fluctuations among countries purchasing and selling coal could
adversely affect the competitiveness of our coal in international
markets.
30
Terrorist
attacks and threats, escalation of military activity in response to such attacks
or acts of war may negatively affect our cash flows, results of operations or
financial condition.
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 United States targets, rumors or threats
of war, actual conflicts involving the United States or its allies, or military
or trade disruptions affecting customers may materially adversely affect
operations. As a result, there could be delays or losses in transportation and
deliveries of coal to customers, decreased sales of coal and extension of time
for payment of accounts receivable from 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, such disruption may lead to
significant increases in energy prices that could result in
government-imposed price controls. It is possible that any, or a combination, of
these occurrences could have a material impact on cash flows, results of
operations or financial condition.
Coal
mining is subject to inherent risks, some for which we maintain third-party
insurance and some for which we self-insure.
Our
operations are subject to certain events and conditions that could disrupt
operations, including fires and explosions, accidental mine water discharges,
coal slurry releases and impoundment failures, natural disasters, equipment
failures, maintenance problems and flooding. We maintain insurance policies that
provide limited coverage for some, but not all, of these risks. Even where
insurance coverage applies, there can be no assurance that these risks would be
fully covered by insurance policies and insurers may contest their obligations
to make payments. Failures by insurers to make payments could have a material
adverse effect on our cash flows, results of operations or financial condition.
We self-insure our highwall miners and underground equipment, including our
longwalls. We do not currently carry business interruption
insurance.
An
accounting change for cash settled convertible debt instruments applicable to
our 3.25%
Notes will likely cause our reported interest expense to
increase.
In
May 2008, the
FASB issued FASB Staff Position APB 14-1, “Accounting for Convertible Debt
Instruments That May Be Settled in Cash upon Conversion (Including Partial Cash
Settlement),” reflecting new rules that would change the accounting for certain
convertible debt instruments, which includes our 3.25% Notes.
Under these new rules, which are effective for financial statements issued for
fiscal years beginning after December 15, 2008 and interim periods within
those fiscal years, an issuer of a convertible debt instrument that may be
settled entirely or partially in cash upon conversion will be required to
account for the liability and equity components of the instrument separately.
The debt component will be recorded at an estimated fair value, as of the
issuance date, of a similar debt instrument without the conversion feature, and
the difference between the proceeds for the convertible debt and the amount
reflected as a debt
liability will be recorded as additional paid-in capital. As a result, the debt
will be treated as if it had been issued at a discount and will subsequently be
accreted through
interest expense to its par value over its expected life, with a rate of
interest that reflects the issuer’s nonconvertible debt borrowing rate.
Due to the requirement to
accrete the debt to its par value, which increases the debt component on which
interest expense is computed, we expect to incur approximately $18 million of
additional, non-cash interest charges in 2009, increasing to approximately $28
million in 2014.
Item
1B. Unresolved Staff Comments
None.
31
Item
2. Properties
We own
and lease properties totaling approximately 1 million acres in West Virginia,
Kentucky, Virginia, Pennsylvania and Tennessee. In addition, certain of our
owned or leased properties are leased or subleased to third-party tenants. Our
current practice is to obtain a title review from a licensed attorney prior to
purchasing or leasing property. We generally have not obtained title insurance
in connection with acquisitions of coal reserves. In some cases, the seller or
lessor warrants property title. We have not required title confirmation in
certain cases under long-standing lease agreements where we are now the current
lessor and the lease covers property where mining has occurred
previously. We currently own or lease the equipment that is utilized
in mining operations. The following table describes the location and general
character of our major existing facilities, exclusive of mines, coal preparation
plants and their adjoining offices.
Administrative
Offices:
Richmond,
Virginia
Owned
Massey
Corporate Headquarters
Julian,
West Virginia
Owned
Massey
Operational Headquarters
For a
description of mining properties, see Item 1. Business, under the heading
“Mining Operations” and “Coal Reserves.”
Item
3. Legal Proceedings
Shareholder
Suits
On July2, 2007, Manville Personal Injury Trust (“Manville”) filed a suit in the Circuit
Court of Kanawha County, West Virginia (the “Circuit Court”), which suit was
amended on December 14, 2007, styled as a shareholder derivative action
asserting that it was a shareholder acting on our behalf. We were named as a
nominal defendant. Each of the then members of our Board of Directors, certain
of our officers and certain of our former directors and officers were named as
defendants (“Manville Defendants”). The complaint alleged breach of
fiduciary duties to us arising out of the Manville Defendants’ alleged failure
to cause us to comply with applicable state and federal environmental and
worker-safety laws and regulations. The complaint sought to recover unspecified
damages in favor of us, appropriate equitable relief and an award to Manville,
respectively, of the costs and expenses associated with these actions. On
September 7, 2007, Mr. Vernon Mercier filed a similar action in the United
States District Court, Southern District of West Virginia (the “District
Court”), styled as a shareholder derivative action asserting that he is a
shareholder acting on our behalf (the “Vernon Mercier Action”). We are named as
a nominal defendant. Each of the then members of our Board of Directors and
certain of our officers and one former officer were named as defendants
(“Original Vernon Mercier Defendants”).
On May20, 2008, the Circuit Court entered an order preliminarily approving a
settlement agreement in the Manville action. A final settlement hearing was held
on June 25, 2008, and, rejecting the objections of Mr. Mercier, on June 30,2008, the Circuit Court entered a final order approving the settlement and
dismissing the Manville action with prejudice. The settlement agreement requires
us to make certain corporate governance changes and pay Manville’s counsel fees
and expenses in the amount of $2,700,000 as compensation for professional
services rendered and expenses incurred in the prosecution of the litigation.
This payment was made on July 15, 2008. Mr. Mercier declined to appeal this
ruling.
On
December 5, 2008, Mr. Mercier filed an Amended Complaint in the District Court,
adding new members of our Board of Directors and additional employees to the
Original Vernon Mercier Defendants (collectively, the “Vernon Mercier
Defendants”), restating his original claim and adding claims for breach of
fiduciary duty in connection with approval of the settlement of the Manville
action and our CEO’s compensation package and a purported failure to comply with
the terms of the settlement of the Manville action. On February 27, 2009, the
Vernon Mercier Defendants jointly moved to dismiss the Amended Complaint,
contending that the settlement in the Manville action bars Mr. Mercier
from continuing to prosecute his federal court action and that Mr. Mercier’s
claims otherwise lack merit.
We and
the Vernon Mercier Defendants have insurance coverage applicable to these
matters. We believe these matters will be resolved without a material adverse
impact on our cash flows, results of operations or financial
condition.
32
Other
Legal Proceedings
Certain
information regarding other legal proceedings required by this Item 3 is
contained in Note 18, “Contingencies” to the Notes to Consolidated Financial
Statements in this Annual Report on Form 10-K and is incorporated herein by
reference.
We are
parties to a number of other legal proceedings, incident to our normal business
activities. These matters include, but are not limited to, contract disputes,
personal injury, property damage and employment matters. While we cannot predict
the outcome of these proceedings, based on our current estimates, 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. However, it is reasonably possible
that the ultimate liabilities in the future with respect to these lawsuits and
claims may be material to our cash flows, results of operations or financial
condition.
We are
also party to lawsuits and other legal proceedings related to the non-coal
businesses previously conducted by Fluor Corporation (renamed Massey Energy
Company) but now conducted by New Fluor. Under the terms of the Distribution
Agreement entered into by New Fluor and us as of November 30, 2000, in
connection with the Spin-Off of New Fluor, New Fluor agreed to indemnify us with
respect to all such legal proceedings and has assumed their
defense.
Item
4. Submission of Matters to a Vote of Security Holders
There
were no matters submitted to a vote of security holders through a solicitation
of proxies or otherwise during the fourth quarter of the fiscal year ended
December 31, 2008.
33
Part
II
Item
5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer
Purchases of Equity Securities
Common
Stock
Common
Stock is listed on the New York Stock Exchange (“NYSE”) and trades under the
symbol MEE. As of February 17, 2009, there were 85,492,888 shares outstanding
and approximately 6,866 shareholders of record of Common Stock.
The
following table sets forth the high and low sales prices per share of Common
Stock on the NYSE for the past two years, based upon published financial
sources, and the dividends declared on each share of Common Stock for the
quarter indicated.
Our
current dividend policy anticipates the payment of quarterly dividends in the
future. Our Board of Directors increased the regular quarterly dividend to $0.06
per share in the fourth quarter of 2008. The ABL Facility and our 6.875% senior
notes due 2013 (the “6.875% Notes”) contain provisions that restrict us from
paying dividends in excess of certain amounts. The ABL Facility limits the
payment of dividends to $50 million annually on Common Stock. The 6.875% Notes
limit the payment of dividends to $25 million annually on Common Stock, plus the
availability in the Restricted Payments Baskets (as defined in the Indenture
governing the 6.875% Notes). In addition, dividends can be paid only so long as
no default exists under the ABL Facility or the 6.875% Notes, as the case may
be, or would result thereunder from paying such dividend. There are no other
restrictions, other than those set forth under the corporate laws of the State
of Delaware, where we are incorporated, on our ability to declare and pay
dividends. The declaration and payment of dividends to holders of Common Stock
will be at the discretion of the Board of Directors and will be dependent upon
our future earnings, financial condition, and capital requirements.
Convertible
Debt Securities
Our 4.75%
convertible senior notes due 2023 (the “4.75% Notes”) are convertible by holders
into shares of Common Stock during certain periods under certain circumstances.
None of the 4.75% Notes were eligible for conversion at December 31,2008. If all of the notes outstanding at December 31, 2008 had been
eligible and were converted, we would have been required to issue 3,610 shares
of Common Stock. In addition, holders of the 4.75% Notes may require us to
purchase all or a portion of their 4.75% Notes on May 15, 2009, May 15, 2013,
and May 15, 2018. For purchases on May 15, 2013 or May 15, 2018, we may, at our
option, choose to pay the purchase price in cash or in shares of Common Stock or
any combination thereof. In June 2008, $660,000 of principal amount of the 4.75%
Notes was converted into 34,037 shares of Common Stock. No other conversions
occurred during the year. See Note 6 to the Notes to Consolidated Financial
Statements for further discussion of the conversion and redemption features of
the 4.75% Notes.
34
Our 2.25%
convertible senior notes due 2024 (the “2.25% Notes”) are convertible by holders
into shares of Common Stock during certain periods under certain circumstances.
None of the 2.25% Notes were eligible for conversion at December 31,
2008. If all of the notes outstanding at December 31, 2008 had been eligible and
were converted, we would have been required to issue 287,113 shares of Common
Stock. No conversions occurred during the year. See Note 6 to the Notes to
Consolidated Financial Statements for further discussion of conversion features
of the 2.25% Notes.
The 3.25%
Notes are convertible under certain circumstances and during certain periods
into (i) cash, up to the aggregate principal amount of the 3.25% Notes
subject to conversion and (ii) cash, Common Stock or a combination thereof,
at our election in respect to the remainder (if any) of our conversion
obligation. As of December 31, 2008, the price per share of Common Stock had not
reached the specified threshold for conversion. No conversions occurred during
the year. See Note 6 to the Notes to Consolidated Financial Statements for
further discussion of conversion features of the 3.25% Notes.
Repurchase
Program
On
November 14, 2005, our Board of Directors authorized a stock repurchase program
(the “Repurchase Program”), authorizing us to repurchase shares of Common Stock.
We may repurchase Common Stock from time to time,
as determined by authorized officers, up to an aggregate amount not to exceed
$500 million (excluding commissions) with free cash flow as existing financing
covenants may permit. Existing covenants currently allow for up to approximately
$611 million of share repurchases. As of
December 31, 2008, we had $420 million available under the current
authorization. The stock repurchases may be conducted on the open market,
through privately negotiated transactions, through derivative transactions or
through purchases made in accordance with Rule 10b5-1 of the Securities Exchange
Act of 1934, as amended (“Exchange Act”), in compliance with the SEC’s
regulations and other legal requirements. The Repurchase Program does not
require us to acquire any specific number of shares and may be terminated at any
time. Through December 31, 2008, 2,874,800 shares have been repurchased at an
average price of $27.80 per share and classified as Treasury stock. All of the
2,874,800 shares held as Treasury stock were issued as part of the 4,370,000
shares of Common Stock which we publicly offered and sold in August 2008. No
additional share repurchases have been made since that time.
Common Stock Offering
Program
On
February 3, 2009, pursuant to Rule 424(b)(5),we filed a prospectus supplement
with the Securities and Exchange Commission (“SEC”) allowing
us to sell up to 5.0 million shares of Common Stock from time
to time in our discretion. The
proceeds from any shares of Common Stock sold will be used for general
corporate purposes, which may include funding for acquisitions or investments in
business, products, technologies, and repurchases and repayment of our
indebtedness.
Transfer
Agent and Registrar
The
transfer agent and registrar for Common Stock is Wells Fargo Shareowner
Services, 161 North Concord Exchange, South St. Paul, Minnesota55075, toll free
(800) 689-8788.
(In
millions, except per share, per ton, and number of employees
amounts)
CONSOLIDATED
STATEMENT OF INCOME DATA:
Produced
coal revenue
$
2,559.9
$
2,054.4
$
1,902.3
$
1,777.7
$
1,456.7
Total
revenue
2,989.8
2,413.5
2,219.9
2,204.3
1,766.6
Income
(Loss) before interest and income taxes
133.2
179.7
111.0
(20.9
)
46.2
Income
(Loss) before cumulative effect of accounting change
56.2
94.1
41.6
(101.6
)
13.9
Net
income (loss)
56.2
94.1
41.0
(101.6
)
13.9
Income
(Loss) per share - Basic (1)
Income
(Loss) before cumulative effect of accounting change
$
0.69
$
1.17
$
0.51
$
(1.33
)
$
0.18
Net
income (loss)
$
0.69
$
1.17
$
0.50
$
(1.33
)
$
0.18
Income
(Loss) per share - Diluted (1)
Income
(Loss) before cumulative effect of accounting change
$
0.68
$
1.17
$
0.51
$
(1.33
)
$
0.18
Net
income (loss)
$
0.68
$
1.17
$
0.50
$
(1.33
)
$
0.18
Dividends
declared per share
$
0.21
$
0.17
$
0.16
$
0.16
$
0.16
CONSOLIDATED
BALANCE SHEET DATA:
Working
capital
$
731.3
$
522.6
$
445.2
$
670.8
$
458.4
Total
assets
3,675.8
2,860.7
2,740.7
2,986.5
2,650.9
Long-term
debt
1,463.6
1,102.7
1,102.3
1,102.6
900.2
Shareholders'
equity (2)
1,036.6
784.0
697.3
841.0
776.9
OTHER
DATA:
EBIT
(3)
$
133.2
$
179.7
$
111.0
$
(20.9
)
$
46.2
EBITDA
(3)
$
390.6
$
425.7
$
341.5
$
213.6
$
270.8
Average
cash cost per ton sold (4)
$
48.53
$
43.10
$
42.33
$
35.62
$
30.50
Produced
coal revenue per ton sold
$
62.50
$
51.55
$
48.71
$
42.02
$
36.02
Capital
expenditures
$
736.5
$
270.5
$
298.1
$
346.6
$
347.2
Produced
tons sold
41.0
39.9
39.1
42.3
40.4
Tons
produced
41.1
39.5
38.6
43.1
42.0
Number
of employees
6,743
5,407
5,517
5,709
5,034
__________________________
(1)
In
accordance with accounting principles generally accepted in the United
States (“GAAP”), the effect of certain dilutive securities was excluded
from the calculation of the diluted income (loss) per common share for the
years ended December 31, 2008, 2007, 2006, 2005, and 2004, as such
inclusion would result in
antidilution.
(2)
Certain
accounting pronouncements adopted in 2007 and 2006 affect the
comparability of the 2007 and 2006 financial statements to prior years.
The adoption of FASB Interpretation No. 48, “Accounting for Uncertainty in
Income Taxes – an interpretation of FASB Statement No. 109” on January 1,2007 increased equity by $5.2 million (see Note 7 to the Notes to
Consolidated Financial Statements for more information). The adoption of
Emerging Issues Task Force Issue No. 04-6, “Accounting for Stripping Costs
Incurred During Production in the Mining Industry” on January 1, 2006
decreased equity by $93.8 million and the adoption of SFAS No. 158,
“Employer’s Accounting for Defined Benefit Pension and Other
Postretirement Plans, an amendment of FASB Statements No. 87, 88, 106, and
132(R)” on December 31, 2006 decreased equity by $40.2 million (see Notes
5, 10 and 11 to the Notes to Consolidated Financial Statements for more
information).
36
(3)
EBIT
is defined as Income (Loss) before interest and taxes. EBITDA is defined
as Income (Loss) before interest and taxes before deducting Depreciation,
depletion, and amortization (“DD&A”). Although neither EBIT nor EBITDA
are measures of performance calculated in accordance with GAAP, we believe
that both measures are useful to an investor in evaluating us because they
are widely used in the coal industry as measures to evaluate a company’s
operating performance before debt expense and as a measure of its cash
flow. Neither EBIT nor EBITDA purport to represent operating income, net
income or cash generated by operating activities and should not be
considered in isolation or as a substitute for measures of performance
calculated in accordance with GAAP. In addition, because neither EBIT nor
EBITDA are calculated identically by all companies, the presentation here
may not be comparable to other similarly titled measures of other
companies. The table below reconciles the GAAP measure of Net income to
EBIT and to EBITDA.
Cumulative
effect of accounting change, net of tax
-
-
0.6
-
-
Income
tax expense( benefit)
4.1
35.4
3.4
26.2
(19.5
)
Net
interest
expense and loss on short-term investment
72.9
50.2
66.0
54.5
51.8
EBIT
133.2
179.7
111.0
(20.9
)
46.2
Depreciation,
depletion and amortization
257.4
246.0
230.5
234.5
224.6
EBITDA
$
390.6
$
425.7
$
341.5
$
213.6
$
270.8
(4)
Average
cash cost per ton is calculated as the sum of Cost of produced coal
revenue and Selling, general and administrative expense (“SG&A”)
(excluding DD&A), divided by the number of produced tons sold.
Although Average cash cost per ton is not a measure of performance
calculated in accordance with GAAP, we believe that it is useful to
investors in evaluating us because it is widely used in the coal industry
as a measure to evaluate a company’s control over its cash costs. Average
cash cost per ton should not be considered in isolation or as a substitute
for measures of performance in accordance with GAAP. In addition, because
Average cash cost per ton is not calculated identically by all companies,
the presentation here may not be comparable to other similarly titled
measures of other companies. The table below reconciles the GAAP measure
of Total costs and expenses to Average cash cost per
ton.
Less:
Net change in fair value of derivative instruments
22.6
-
-
-
-
Average
cash cost
$
1,987.9
$48.53
$
1,717.7
$43.10
$
1,653.0
$42.33
$
1,506.8
$35.62
$
1,233.4
$30.50
37
Item
7. Management’s Discussion and Analysis of Financial Condition and Results of
Operations
The
following Management’s Discussion and Analysis of Financial Condition and
Results of Operations (“MD&A”) is intended to help the reader understand
Massey Energy Company, our operations and our present business environment.
MD&A is provided as a supplement to, and should be read in conjunction with,
our consolidated financial statements and the accompanying notes thereto
contained in Item 8 of this report. From time to time, we may make statements
that may constitute “forward-looking statements” within the meaning of the
“safe-harbor” provisions of the Private Securities Litigation Reform Act of
1995. These statements are based on our then current expectations and are
subject to a number of risks and uncertainties that could cause actual results
to differ materially from those addressed in the forward-looking statements.
Please see “Forward-Looking Statements” on page i hereto and are incorporated
herein and the risk factors that may cause such a difference, which are set
forth in Item 1A. Fisk Factors and are incorporated herein.
Executive
Overview
We
operate coal mines and processing facilities in Central Appalachia, which
generate revenues and cash flow through the mining, processing and selling of
steam and metallurgical grade coal, primarily of low sulfur content. We also
generate income and cash flow through other coal-related businesses. Other
revenue is obtained from royalties, rentals, gas well revenues, gains on the
sale of non-strategic assets and miscellaneous income.
We
reported net income for the year ended December 31, 2008 of $56.2 million, or
$0.68 per diluted share, compared to net income for 2007 of $94.1 million, or
$1.17 per diluted share. Net income in 2008 included pre-tax charges of $250.1
million related to the litigation with Wheeling-Pittsburgh Steel Corporation
(“Wheeling-Pittsburgh”), pre-tax gains totaling $32.4 million related to asset
and reserve exchanges with third-parties and a $22.6 million non-cash pre-tax
charge to recognize the net unrealized losses on certain coal contracts that
qualify as derivatives. Net income in 2007 included pre-tax gains totaling
approximately $10.3 million related to a reserve exchange with a third-party,
$33.6 million related to a favorable decision on our appeal of the previous jury
decision in the Harman lawsuit and $6.7 million on the sale of a mineral rights
override, offset by a $20.0 million non-tax deductible penalty related to a
settlement with EPA.
Produced
tons sold were 41.0 million in 2008, compared to 39.9 million in 2007. Shipments
of metallurgical coal improved significantly in 2008 over 2007 as demand for
this type of coal, especially in the export market, increased during 2008,
allowing certain quality coal to be shifted from the utility to the
metallurgical market. Production increased as new mines were started in 2008 as
part of our expansion plan. We produced 41.1 million tons during 2008, compared
to 39.5 million tons produced in 2007.
During
2008, Produced coal revenue increased by 25% over the prior year as we benefited
from higher coal sales prices for both domestic and export sales secured in new
coal sales agreements as lower-priced contracts expired and we shipped a larger
percentage of higher-priced metallurgical tons in 2008. Our average Produced
coal revenue per ton sold in 2008 increased by 21.2% to $62.50 compared to
$51.55 in 2007 and by 73.5% over a five-year period compared to $36.02 in 2004.
Our average Produced coal revenue per ton in 2008 for metallurgical tons sold
increased by 33.9% to $97.07 from $72.49 in 2007.
We
experienced a significant increase in costs during the past 5-year period, with
Average cash cost per ton sold increasing from $30.50 in fiscal 2004 to $48.53
in fiscal 2008 (a reconciliation of these non-GAAP figures is presented in
footnote 4 of Item 6. Selected Financial Data). The increased cost level is
primarily due to indirect costs associated with compliance with new safety
regulations, increased sales-related costs from the growth in average per ton
realization, higher labor costs, mining supplies costs and litigation
settlements.
Since we
first announced our expansion and cost reduction plans in October 2007, we have
opened 19
new mines and added 10 new underground miner sections at existing
mines. In all, we have expanded production at 14 of our existing
resource groups, started up the Inman Resource Group, re-started the Martin
County and Coalgood Resource Groups, and provided new jobs for more than 1,300
additional members. By the end of 2008, our expansion work was continuing
and was largely complete. A few projects that were initiated in 2008
remain to be completed in the first half of 2009, including the construction of
a new processing plant at our Coalgood Resource Group and the addition of two
new Superior highwall miners. Further expansion plans for 2009 have been
deferred or cancelled in light of the changes in market conditions.
In
November 2007, the Supreme Court of Appeals of West Virginia (“WV Supreme
Court”) reversed a jury decision in the Harman lawsuit, finding in favor of us
and reversing the jury award. Subsequently, on January 24, 2008, the
WV Supreme Court decided to rehear the case, which was re-argued on March 12,2008. On April 3, 2008, the WV Supreme Court again reversed the judgment against
certain of our subsidiaries and remanded the case with direction to enter an
order dismissing the case, with prejudice, in its entirety. The Harman
plaintiffs petitioned the United States Supreme Court to review the WV Supreme
Court’s dismissal of their claims. In December 2008, the United States Supreme
Court (“U.S.
38
Supreme
Court”) agreed to review the case. Oral argument before the U.S.
Supreme Court is scheduled for March 3, 2009. The U.S. Supreme Court
could affirm the dismissal of the case by the WV Supreme Court or direct the WV
Supreme Court to rehear the case. If the WV Supreme Court, which is
comprised of five justices, rehears the case, the matter would not be heard by
the same five justices who heard the matter in April 2008. The justices of the
reconfigured WV Supreme Court could dismiss the plaintiffs’ claims again, or
reach some different result, including a reinstatement of the original verdict
against us with interest.
On May22, 2008, the WV Supreme Court decided not to hear an appeal of the verdicts
against us or our subsidiary Central West Virginia Energy Company (“CWVE”) that
awarded damages in favor of Wheeling-Pittsburgh and Mountain State Carbon, LLC
in the amount of $219.9 million, comprising $119.9 million compensatory and $100
million punitive damages (plus an additional $24 million of pre-judgment
interest). On December 1, 2008, the United States Supreme Court declined to
accept the petitions for certiorari filed on behalf of us and CWVE. On December4, 2008, we paid the total amount of $267.4 million, which represented the
entire judgment against us and CWVE, including all applicable interest
payments.
On August12, 2008, we issued in a registered underwritten public offering $690 million of
3.25% convertible senior notes due 2015, resulting in net proceeds of
approximately $674.1 million. The 3.25% Notes are our fully registered,
unsecured obligations, rank equally with all of our other unsecured senior
indebtedness and are guaranteed by substantially all of our current and future
operating subsidiaries. Interest is payable semiannually on August 1 and
February 1 of each year. Also on August 12, 2008, we completed a
registered underwritten public offering of 4,370,000 shares of Common Stock
(which included the re-issuance of 2,874,800 Treasury stock shares) at a public
offering price of $61.50 per share, resulting in net proceeds of $258.2
million. We used the proceeds from the concurrent Common Stock and
the convertible notes offerings to purchase a portion of our 6.625% Notes in
connection with the 6.625% Notes consent solicitation and tender offer and for
general corporate purposes.
On August19, 2008, we settled with holders of $311.5 million of the $335 million
outstanding of the 6.625% Notes, representing approximately 93% of the
outstanding 6.625% Notes, who tendered their 6.625% Notes pursuant to our tender
offer for the 6.625% Notes. As a result of the receipt of consents of
approximately 93% of the outstanding 6.625% Notes, we received the requisite
consents to execute a supplemental indenture relating to the 6.625% Notes, which
eliminated substantially all of the restrictive covenants in the 6.625% Notes’
indenture. On September 3, 2008, we settled with holders of an additional $1.6
million of the 6.625% Notes, who tendered their 6.625% Notes after the consent
solicitation deadline.
On
September 16, 2008, The Reserve Primary Fund (“Primary Fund”) reported a net
asset value of $0.97 per share as a result of the Primary Fund’s valuing at zero
its holdings of debt securities issued by Lehman Brothers Holdings, Inc., which
filed for bankruptcy on September 15, 2008. The Primary Fund
suspended redemptions and subsequently announced that it would be
liquidated. As of September 16, 2008, we had an investment in the
Primary Fund of $217.9 million. Based on our assessment of the
Primary Fund’s net asset value, the planned disbursement schedule of the Primary
Fund’s cash and the underlying securities, we determined that the approximate
fair value of our investment as of September 30, 2008 was $211.4 million, and
recorded a loss of $6.5 million. On October 31, 2008 and December 3, 2008, the
Primary Fund made distributions to us of $110.7 million and $61.3 million,
respectively, leaving an investment balance of $39.4 million. Subsequent to
December31, 2008, on February 20, 2009, the Primary Fund made an additional
distribution to us of $14.5 million. We are currently unable to access our
remaining cash invested with the Primary Fund. While we expect to receive
substantially all of our remaining holdings in the Primary Fund during 2009, we
cannot predict when this will occur or the actual amount we will eventually
receive.
The
continuing recession, credit crisis and related turmoil in the global financial
system has had and may continue to have a negative impact on our business,
financial condition and liquidity. We may face significant future
challenges if conditions in the financial markets do not improve or continue to
worsen. Worldwide demand for coal has been adversely impacted, particularly for
our metallurgical grade coals, which we expect will have a negative effect on
our revenues. The competitiveness of coal exported from the United
States has been negatively impacted by strengthening of the U.S. dollar and the
decline of freight costs of ocean going vessels allowing coal produced in more
distant countries, such as Australia, to compete with U.S. exports in the
Atlantic Basin. Moreover, volatility and disruption of financial markets could
affect the creditworthiness of our customers and/or limit our customers’ ability
to obtain adequate financing to maintain operations and result in a further
decrease in sales volume that could have a negative impact on our cash flows,
results of operations or financial condition.
39
Results
of Operations
2008
Compared with 2007
Revenues
Year
Ended
December
31,
Increase
%
Increase
(In
thousands)
2008
2007
(Decrease)
(Decrease)
Revenues
Produced
coal revenue
$
2,559,929
$
2,054,413
$
505,516
25
%
Freight
and handling revenue
306,397
167,641
138,756
83
%
Purchased
coal revenue
30,684
108,191
(77,507
)
(72
)%
Other
revenue
92,779
83,278
9,501
11
%
Total
revenues
$
2,989,789
$
2,413,523
$
576,266
24
%
The
following is a breakdown, by market served, of the changes in produced tons sold
and average produced coal revenue per ton sold for 2008 compared to
2007:
Year
Ended
December
31,
(In
millions, except per ton amounts)
2008
2007
Increase
(Decrease)
%
Increase (Decrease)
Produced tons sold:
Utility
27.0
27.4
(0.4
)
(1
)%
Metallurgical
9.9
8.5
1.4
16
%
Industrial
4.1
4.0
0.1
2
%
Total
41.0
39.9
1.1
3
%
Produced coal revenue per ton
sold:
Utility
$
49.92
$
45.18
$
4.74
10
%
Metallurgical
97.07
72.49
24.58
34
%
Industrial
61.78
50.82
10.96
22
%
Weighted
average
62.50
51.55
10.95
21
%
Shipments
of metallurgical coal increased in 2008 compared to 2007, as demand for this
type of coal, especially in the export market, increased during 2008, allowing
certain quality coal to be shifted from the utility to the metallurgical market.
Production increased as new mines were started in 2008 as part of our expansion
plan. The average per ton sales price for utility coal continued to
improve in 2008, attributable to prices contracted during a period of increased
demand for utility coal in the United States. The higher demand resulted in
shortages of certain quality utility coal, increasing the market prices of this
coal, and allowing us to negotiate agreements containing higher-priced terms as
lower-priced contracts expired.
Freight
and handling revenue increased due to an increase in export tons sold from 4.8
million tons in 2007 to 8.1 million tons in 2008. In addition, during 2008 there
was a significant increase in freight rates, including fuel surcharges during a
large portion of the year.
Purchased
coal revenue decreased mainly due to a decrease in purchased tons sold from 2.1
million in 2007 to 0.5 million in 2008.
Other
revenue includes refunds on railroad agreements, royalties related to coal lease
agreements, gas well revenue, gains on the sale of non-strategic assets and
reserve exchanges, joint venture revenue and other miscellaneous revenue. Other
revenue for 2008 includes a pre-tax gain of $32.4 million on an exchange of coal
reserves and other assets. In addition, railroad refund income was
higher in 2008 than in 2007, offset by lower royalty earnings in 2008 compared
to 2007. Other revenue for 2007 includes a pre-tax gain of $10.3 million on an
exchange of coal reserves and $6.7 million on the sale of mineral rights
override (see Note 4 in the Notes to Consolidated Financial Statements for
further discussion).
40
Costs
Year
Ended
December
31,
Increase
%
Increase
(In
thousands)
2008
2007
(Decrease)
(Decrease)
Costs
and expenses
Cost
of produced coal revenue
$
1,910,953
$
1,641,774
$
269,179
16
%
Freight
and handling costs
306,397
167,641
138,756
83
%
Cost
of purchased coal revenue
28,517
95,241
(66,724
)
(70
)%
Depreciation,
depletion and amortization, applicable to:
-
Cost
of produced coal revenue
253,737
242,755
10,982
5
%
Selling,
general and administrative
3,590
3,280
310
9
%
Selling,
general and administrative
77,015
75,845
1,170
2
%
Other
expense
3,207
7,308
(4,101
)
(56
)%
Litigation
charge
250,061
-
250,061
100
%
Loss
on financing transactions
538
-
538
100
%
Net
change in fair value of derivative instruments
22,552
-
22,552
100
%
Total
costs and expenses
$
2,856,567
$
2,233,844
$
622,723
28
%
Cost of produced coal
revenue increased due to increased sales-related costs on higher produced coal
revenues including production royalties and severance taxes, increased supplies
costs including diesel fuel and explosives, higher labor costs, litigation
settlements and higher indirect costs associated with compliance with new safety
regulations. Supplies costs increased both due to a commodity driven
inflationary increase and overall usage as the volume of produced tons sold
increased from 39.9 million tons in 2007 to 41.0 million tons in
2008.
Freight and
handling costs increased due to an increase in export tons sold from 4.8 million
tons in 2007 to 8.1 million tons in 2008. In addition, during 2008 there was a
significant increase in freight rates, including fuel surcharges during a large
portion of the year.
Cost of
purchased coal revenue decreased due to a decrease in purchased tons sold from
2.1 million in 2007 to 0.5 million in 2008.
Depreciation,
depletion and amortization applicable to Cost of produced coal revenue increased
due to impact of various of our capital projects which went into service during
2008.
Litigation
charge represents the court award and associated interest for the
Wheeling-Pittsburgh matter (see Note 18 in the Notes to Consolidated Financial
Statements for further discussion).
Loss on
financing transactions relates to $9.1 million fees incurred for the tender
offer for our 6.625% Notes, offset by an $8.6 million gain recognized from the
purchase of $19.0 million of our 3.25% Notes on the open market during 2008 (see
Note 6 in the Notes to Consolidated Financial Statements for further
discussion).
Net change in
fair value of derivative instruments represents net unrealized losses of $22.6
million related to purchase and sales contracts that qualify as derivatives (see
Note 15 in the Notes to Consolidated Financial Statements for further
discussion).
41
Interest
Interest
income remained comparable to prior year at $23.6 million as the current year
decline in interest rates on Cash and cash equivalents was offset by higher cash
balances on hand from August 2008 onward due to the debt and equity issuances in
the third quarter and the recording of $7.0 million of interest income on the
black lung excise tax refund. Interest expense primarily increased due to 2007
including a credit to interest expense of $11.4 million relating to interest
which had previously been accrued on the Harman matter which was overturned by
the WV Supreme Court in 2007 (see Note 18 in the Notes to Consolidated Financial
Statements for further discussion). The remainder of the increase can be
attributed $6.1 million included in interest expense for the write-off of debt
issuance costs and the related interest rate swap balance due to the repurchase
of the 6.625% Notes (see Note 6 in the Notes to Consolidated Financial
Statements for further discussion).
Loss
on short-term investment
Loss on
short-term investment represents a pro rata share of the
estimated loss in our investment in the Primary Fund of $6.5 million (see Note
16 to the Notes to Condensed Consolidated Financial Statements for further
discussion).
Income
Taxes
Income tax
expense was $4.1 million for 2008 compared with a tax expense of $35.4 million
for 2007. The income tax rates for 2008 and 2007 were favorably impacted by
percentage depletion allowances and the usage of net operating loss
carryforwards. The income tax rate in 2008 was negatively impacted by
nondeductible penalties and an increase in deferred tax asset valuation
allowances related principally to federal net operating losses. Also impacting
the 2008 income tax rate were favorable adjustments in connection with the
election to forego bonus depreciation and claim a refund for alternative minimum
tax credits. The income tax rate in 2007 was negatively impacted by a
nondeductible EPA settlement and an increase in deferred tax asset valuation
allowances related principally to federal net operating losses. The 2007 rate
was also favorably impacted by the adjustment of reserves in connection with the
closing of a prior period audit by the IRS. Because of the discrete tax events
occurring in 2008, the tax rate for 2008 may not be indicative of future tax
rates.
2007
Compared with 2006
Revenues
Year
Ended
December
31,
Increase
%
Increase
(In
thousands)
2007
2006
(Decrease)
(Decrease)
Revenues
Produced
coal revenue
$
2,054,413
$
1,902,259
$
152,154
8
%
Freight
and handling revenue
167,641
156,531
11,110
7
%
Purchased
coal revenue
108,191
70,636
37,555
53
%
Other
revenue
83,278
90,428
(7,150
)
(8
)%
Total
revenues
$
2,413,523
$
2,219,854
$
193,669
9
%
42
The
following is a breakdown, by market served, of the changes in produced tons sold
and average produced coal revenue per ton sold for 2007 compared to
2006:
Year
Ended
December
31,
(In
millions, except per ton amounts)
2007
2006
Increase
(Decrease)
%
Increase (Decrease)
Produced tons sold:
Utility
27.4
27.7
(0.3
)
(1
)%
Metallurgical
8.5
7.8
0.7
9
%
Industrial
4.0
3.6
0.4
11
%
Total
39.9
39.1
0.8
2
%
Produced coal revenue per ton
sold:
Utility
$
45.18
$
42.37
$
2.81
7
%
Metallurgical
72.49
69.20
3.29
5
%
Industrial
50.82
53.13
(2.31
)
(4
)%
Weighted
average
51.55
48.71
2.84
6
%
Shipments
of metallurgical and industrial coal increased in 2007 compared to 2006, mainly
due to improved productivity at underground room and pillar mines resulting from
lower turnover and a more stable workforce, and improved performance from the
railroads shipping this coal. The average per ton sales price for utility coal
continued to improve in 2007, attributable to prices contracted during a period
of increased demand for utility coal in the United States. The higher demand
resulted in shortages of certain quality utility coal, increasing the market
prices of this coal, and allowed us to negotiate agreements containing higher
price terms as lower-priced contracts expired. The decrease in average per ton
sales price for the industrial market is mainly attributable to lower pricing on
sales contracted for 2007 shipments.
Purchased
coal revenue increased mainly due to an increase in purchased tons sold from 1.3
million in 2006 to 2.1 million in 2007, offset by a 4% decrease in revenue per
ton. We purchase varying amounts of coal to supplement produced coal
sales.
Other
revenue includes refunds on railroad agreements, royalties related to coal lease
agreements, gas well revenue, gains on the sale of non-strategic assets and
reserve exchanges, earnings from the sale and operation of a synfuel plant,
joint venture revenue and other miscellaneous revenue. Other revenue for 2007
includes a pre-tax gain of $10.3 million on an exchange of coal reserves and
$6.7 million on the sale of a mineral rights override. In addition,
railroad refunds and royalty income were higher in 2007 than in 2006, offset by
lower synfuel earnings in 2007 compared to 2006. Other revenue for 2006 includes
a pre-tax gain of $30.0 million on the sale of our Falcon reserves (see Note 4
in the Notes to Consolidated Financial Statements for further discussion).
Costs
Year
Ended
December
31,
Increase
%
Increase
(In
thousands)
2007
2006
(Decrease)
(Decrease)
Costs
and expenses
Cost
of produced coal revenue
$
1,641,774
$
1,599,092
$
42,682
3
%
Freight
and handling costs
167,641
156,531
11,110
7
%
Cost
of purchased coal revenue
95,241
62,613
32,628
52
%
Depreciation,
depletion and amortization, applicable to:
Cost
of produced coal revenue
242,755
227,279
15,476
7
%
Selling,
general and administrative
3,280
3,259
21
1
%
Selling,
general and administrative
75,845
53,834
22,011
41
%
Other
expense
7,308
6,240
1,068
17
%
Total
costs and expenses
$
2,233,844
$
2,108,848
$
124,996
6
%
43
Cost of produced coal revenue increased
due to increased sales-related costs on higher produced coal revenues including
production royalties and severance taxes, increased supplies costs including
diesel fuel and explosives, and higher indirect costs associated with compliance
with new safety regulations. Supplies costs increased both due to a
commodity driven inflationary increase and overall usage as the volume of
produced tons sold increased from 39.1 million tons in 2006 to 39.9 million tons
in 2007.
Cost of
purchased coal revenue increased due to an increase in purchased tons sold from
1.3 million in 2006 to 2.1 million in 2007, offset by a 4% decrease in average
cost of purchased coal per ton.
Selling,
general and administrative expenses increased due to higher stock-based and
performance-based compensation expenses due to increased stock price value in
2007 and attainment of more performance based compensation targets versus
2006.
Interest
Interest
income increased due to higher cash and interest-bearing deposit balances during
2007 as compared to 2006. Interest expense decreased due to 2007 including a
credit to interest expense of $11.4 million relating to the Harman matter (see
Note 18 in the Notes to Consolidated Financial Statements for further
discussion).
Income
Taxes
Income
tax expense was $35.4 million for 2007 compared with a tax expense of $3.4
million for 2006. The income tax rates for 2007 and 2006 were favorably impacted
by percentage depletion allowances and the usage of net operating loss
carryforwards. The income tax rate for 2007 was negatively impacted by a
nondeductible EPA settlement and an increase in deferred tax asset valuation
allowances related principally to federal net operating losses. Also impacting
the 2007 income tax rate were favorable adjustments in connection with the
closing of a prior period audit by the IRS. The income tax rate in 2006 was also
favorably impacted by the adjustment of reserves in connection with the closing
of a prior period audit by the IRS.
Liquidity
and Capital Resources
At December31, 2008, our available liquidity was $706.5 million, comprised of Cash and cash
equivalents of $607.0 million and $99.5 million of availability from our
asset-based revolving credit facility. We also have a $39.4 million investment
in the Primary Fund, which is recorded in Short-term investment (see Note 16 in
the Notes to Consolidated Financial Statements for further discussion). Our total debt-to-book
capitalization ratio was 58.6% at December 31, 2008.
See Note
6 in the Notes to Consolidated Financial Statements for further discussion of
our debt and debt-related covenants.
44
Asset-Based Credit
Facility
We
maintain an asset-based revolving credit agreement, which provides for available
borrowings, including letters of credit, of up to $175 million, depending on the
level of eligible inventory and accounts receivable. The facility expires on May15, 2010; however if the 6.625% Notes have been refinanced, defeased, or paid in
full by May 15, 2010, the expiration date is extended to August 15, 2011. As of
December 31, 2008, there were $75.5 million of letters of credit issued and
there were $0 outstanding borrowings under this facility.
Debt
Ratings
Moody’s
Investors Service (“Moody’s”) and Standard & Poor’s Rating Services
(“S&P”) rate our long-term debt. As of December 31, 2008, our S&P
outlook rating is Stable. Moody’s outlook on all of our notes is Stable; our
Long-Term Corporate Family Rating is B1.
Current Ratings:
Moody’s
S&P
6.875%
Notes
B2
BB-
3.25%
Notes
NR
BB-
6.625%
Notes
B2
NR
2.25%
Notes
B2
BB-
4.75%
Notes
B3
NR
__________________________
NR - Not
separately rated
Financing
Transactions
On August5, 2008, we commenced a consent solicitation and cash tender offer for any and
all of the outstanding $335 million of 6.625% Notes and concurrently we
commenced registered underwritten public offerings of convertible senior notes
(the 3.25% Notes) and shares of Common Stock and announced our intention to use
the proceeds of the offerings to purchase some or all of the 6.625% Notes in the
tender offer and for general corporate purposes.
On August19, 2008, we settled with holders of $311.5 million of the 6.625% Notes,
representing approximately 93% of the outstanding 6.625% Notes, who tendered
their 6.625% Notes pursuant to our consent solicitation and tender offer for the
6.625% Notes. The total consideration for these 6.625% Notes was $1,026.57 per
$1,000 principal amount of the 6.625% Notes. The total consideration included a
consent payment of $25 per $1,000 principal amount of the 6.625% Notes. In
addition to the total consideration, holders also received interest which was
accrued and unpaid since the previous interest payment date.
As a
result of the consents of approximately 93% of the outstanding 6.625% Notes, we
received the requisite consents to execute a supplemental indenture relating to
the 6.625% Notes, which eliminated substantially all of the restrictive
covenants in the 6.625% Notes’ indenture. On September 3, 2008, we
settled with holders of an additional $1.6 million of the 6.625% Notes, who
tendered their 6.625% Notes after the consent solicitation deadline. The total
consideration for these 6.625% Notes was $1,001.57 per $1,000 principal amount
of the 6.625% Notes. In addition to the total consideration, holders also
received interest which was accrued and unpaid since the previous interest
payment date.
3.25%
Notes
On August12, 2008, we issued $690 million of 3.25% Notes in a registered underwritten
public offering, resulting in net proceeds to us of approximately $674.1
million. The 3.25% Notes are guaranteed on a senior unsecured basis by
substantially all of our current and future operating subsidiaries (the
“Guarantors”). The 3.25% Notes and the guarantees rank equally with all of our
and the Guarantors’ existing and future senior unsecured indebtedness and rank
senior to all of our and the Guarantors’ indebtedness that is expressly
subordinated to the 3.25% Notes and the guarantees, but are effectively
subordinated to all of our and the Guarantors’ existing and future senior
secured indebtedness to the extent of the value of the assets securing the
indebtedness and to all liabilities of our subsidiaries that are not
Guarantors.
The 3.25%
Notes bear interest at a rate of 3.25% per annum, payable semi-annually in
arrears on August 1 and February 1 of each year, beginning on February 1, 2009.
The 3.25% Notes will mature on August 1, 2015, unless earlier repurchased by us
or converted.
The 3.25%
Notes are convertible in certain circumstances during certain periods at an
initial conversion rate of 11.4106 shares of Common Stock per $1,000 principal
amount of 3.25% Notes (which represented an initial conversion price of
approximately $87.64 per share), subject to adjustment in certain
circumstances.
The 3.25%
Notes are convertible under certain circumstances and during certain periods
into (i) cash, up to the aggregate principal amount of the 3.25% Notes
subject to conversion and (ii) cash, shares of Common Stock or a
combination thereof, at our election in respect to the remainder (if any) of our
conversion obligation. Subject to earlier repurchase, the 3.25% Notes
will be convertible only in the following circumstances and to the following
extent:
· during
any calendar quarter, if the closing sale price of our shares of Common Stock
for each of 20 or more trading days in a period of 30 consecutive trading days
ending on the last trading day of the immediately preceding calendar quarter
exceeds 130% of the conversion price in effect on the last trading day of the
immediately preceding calendar quarter;
· during
the five consecutive business days immediately after any five consecutive
trading day period (the “note measurement period”) in which the average trading
price per $1,000 principal amount of 3.25% Notes was equal to or less than 97%
of the average conversion value of the 3.25% Notes during the note measurement
period;
· if we
make certain distributions on our shares of Common Stock or engage in certain
transactions; and
· at any
time from, and including, February 1, 2015 until the close of business on the
second business day immediately preceding August 1, 2015.
45
The indenture governing the 3.25% Notes
contains customary terms and covenants, including that upon certain events of
default occurring and continuing, either the trustee for the 3.25% Notes or the
holders of not less than 25% in aggregate principal amount of the 3.25% Notes
then outstanding may declare the unpaid principal of the 3.25% 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 us, the principal amount of the 3.25% Notes together with any accrued and
unpaid interest thereon will automatically become and be immediately due and
payable.
Open
Market Debt Repurchase
On November6, 2008, we concluded an open market purchase, retiring $19.0 million of
principal amount of the 3.25% Notes at a cost of $10.4 million, plus accrued
interest resulting in a gain of $8.6 million recorded in Loss on financing
transactions. Depending on market conditions and covenant restrictions, we may
continue to make debt repurchases from time to time through open market
purchases, private transactions or otherwise.
Common
Stock Issuance
On
August 12, 2008, we completed a registered underwritten public offering of
4,370,000 shares of Common Stock, which included re-issuing 2,874,800 shares of
our Treasury stock, at a public offering price of $61.50 per share, resulting in
proceeds to us of $258.2 million, net of underwriting fees. As discussed in Note
17 to the Notes to Consolidated Financial Statements, we used these proceeds and
the proceeds of the concurrent 3.25% Notes offering to purchase a portion of the
6.625% Notes in connection with the 6.625% Notes consent solicitation and tender
offer and for general corporate purposes.
Fair
Value Hedge Adjustment
On
December 9, 2005, we exercised our right to terminate our interest rate swap
agreement, which was hedged against a portion of the 6.625% Notes. We paid a
$7.9 million termination payment to the swap counterparty on December 13, 2005.
The termination payment, which is reflected in the table above at December 31,2007, as Fair value hedge adjustment, was being amortized into Interest expense
through November 15, 2010, the maturity date of the 6.625% Notes. As discussed
in Note 6 to the Notes to Consolidated Financial Statements under Financing
Transactions, on August 19, 2008, we settled with holders of approximately 93%
of the outstanding 6.625% Notes that were tendered pursuant to our consent
solicitation and tender offer for the 6.625% Notes. As a result of
the acceptance of the consent solicitation and tender offer of the 6.625% Notes,
the remaining balance of the Fair value hedge adjustment ($4.2 million) was
written off to Interest expense.
Cash
Flow
Net cash
provided by operating activities was $385.1 million for 2008 compared to $396.0
million for 2007. Cash provided by operating activities reflects Net income
adjusted for non-cash charges and changes in working capital
requirements.
Net cash
utilized by investing activities was $776.5 million and $242.3 million for 2008
and 2007, respectively. The cash used in investing activities reflects capital
expenditures in the amount of $736.5 million and $270.5 million for 2008 and
2007, respectively. These capital expenditures are for replacement of mining
equipment, the expansion of mining and shipping capacity, and projects to
improve the efficiency of mining operations. Included in these capital
expenditures are $3.0 million of cash spent for the buyout of operating leases
in both 2008 and 2007. Additionally, 2008 and 2007 included $6.0 million and
$28.1 million, respectively, of proceeds provided by the sale of assets (see
Note 4 to the Notes to Consolidated Financial Statements for further
discussion).
Net cash
provided by financing activities was $633.2 million for 2008 compared to net
cash utilized of $27.7 million for 2007, respectively. Financing activities
reflect changes in debt levels, common stock offerings, exercising of stock
options, payments of dividends and cash receipts generated from sale-leaseback
transactions. Financing activities for 2008 primarily reflects the $674.1
million of proceeds provided by the issuance of the 3.25% Notes, $258.2 million
of proceeds provided by the issuance of Common Stock, $322.1 million utilized
for the tender payment for the 6.625% Notes, and the $10.4 million utilized for
the purchase of our 3.25% Notes on the open market discussed
above. Financing activities for 2007 included $30 million for the
repurchases of 1.5 million shares of Common Stock under the share repurchase
program discussed below. We also generated $41.3 million from several
sale-leaseback (operating leases) transactions of certain mining equipment in
2008, compared to $13.1 million of sale-leasebacks in 2007.
46
We
believe that cash on hand, cash generated from operations and our borrowing
capacity will be sufficient to meet our working capital requirements, scheduled
debt payments, potential share repurchases and debt repurchases, anticipated
dividend payments, expected settlements and final awards of outstanding
litigation and anticipated capital expenditures including planned expansions
(other than major acquisitions) for at least the next twelve months.
Nevertheless, our ability to satisfy our debt service obligations, repurchase
shares and debt, pay dividends, pay settlements and final awards of outstanding
litigation, or fund planned capital expenditures including planned expansions,
will substantially depend upon our future operating performance, which will be
affected by prevailing economic conditions in the coal industry, debt covenants
and financial, business and other factors, some of which are beyond our control.
(See also “Concentration of Credit Risk and Major Customers” in Note 14 in the
Notes to Consolidated Financial Statements.) We frequently evaluate potential
acquisitions. In the past, we have funded acquisitions primarily with cash
generated from operations. As a result of the cash needs we have described above
and possible acquisition opportunities, in the future we may consider a variety
of financing sources, including debt or equity financing. Currently, other than
our asset-based revolving credit facility, we have no commitments for any
additional financing. We cannot be certain that we can obtain
additional financing on terms that we find acceptable, if at all, through the
issuance of equity securities or the incurrence of additional
debt. Additional equity financing may dilute our stockholders, and
debt financing, if available, and may, among other things, restrict our ability
to repurchase Common Stock, declare and pay dividends and raise future
capital. If we are unable to obtain additional needed financing, it
may prohibit us from making acquisitions, capital expenditures and/or
investments, which could materially and adversely affect our prospects for
long-term growth.
Common Stock Offering
Program
On February3, 2009, pursuant to Rule 424(b)(5),we filed a prospectus supplement with the
Securities and Exchange Commission (“SEC”) allowing us to sell up to 5.0 million
shares of Common Stock from time to time in our discretion. The proceeds
from any shares of Common Stock sold will be used for general corporate
purposes, which may include funding for acquisitions or investments in business,
products, technologies, and repurchases and repayment of our
indebtedness.
Share
Repurchases
The Board of Directors has
authorized a total of $500 million (excluding commissions) to repurchase our
common stock under our share repurchase program. Through December 31, 2008,
2,874,800 shares have been repurchased at an average price of $27.80 per share
and classified as Treasury stock. All of the 2,874,800 shares held as Treasury
stock were re-issued as part of the 4,370,000 shares of Common Stock which were
offered and sold in an underwritten public offering in August 2008. As of
December 31, 2008, we had $420 million available under the current
authorization. We may repurchase shares of Common Stock from time to
time in compliance with the SEC’s regulations and other legal requirements, and
subject to market conditions and other factors. The share repurchase program
does not require us to acquire any specific number of shares and may be
terminated at any time.
The following table summarizes information about shares of Common Stock that
were purchased during the fourth quarter of 2008.
Period
Total
Number of Shares Purchased
Average
Price Paid per Share
Total
Number of Shares Purchased as Part of Publicly Announced Plans or
Programs
Maximum
Number of Shares that May Yet Be Purchased Under the Plan
October
1 through October 31
-
-
-
-
November
1 through November 30
-
-
-
-
December
1 through December 31
-
-
-
-
Total
-
-
27,667,984
(1)
__________________________
(1)
Calculated
using $420 million that may yet be purchased under our share repurchase
program and $15.18, the closing price of Common Stock as reported on the
New York Stock Exchange on January 31,2009.
47
Contractual
Obligations
We have
various contractual obligations that are recorded as liabilities within the
Consolidated Financial Statements in this Annual Report on Form 10-K. Other
obligations, such as certain purchase commitments, operating lease agreements,
and other executory contracts are not recognized as liabilities within the
Consolidated Financial Statements but are required to be disclosed. The
following table is a summary of our significant obligations as of December 31,2008 and the future periods in which such obligations are expected to be settled
in cash. The table does not include current liabilities accrued within the
Consolidated Financial Statements, such as Accounts payable and Payroll and
employee benefits.
Payments
Due by Period (In Thousands)
Total
Within 1
Year
1-3
Years
3-5
Years
Beyond 5
Years
Long-term
debt (1)
$
1,875,465
$
75,732
$
171,838
$
908,556
$
719,339
Capital
lease obligations
(2)
7,415
2,285
5,082
25
23
Operating
lease obligations (3)
292,595
71,237
126,677
75,831
18,850
Coal
lease obligations (4)
159,960
18,906
36,379
31,806
72,869
Purchased
coal obligations (5)
145,419
145,419
-
-
-
Other
purchase obligations (6)
333,095
323,290
7,555
2,250
-
Total
Obligations
$
2,813,949
$
636,869
$
347,531
$
1,018,468
$
811,081
__________________________
(1)
Long-term
debt obligations reflect the future interest and principal payments of our
fixed rate senior unsecured notes outstanding as of December 31, 2008. See
Note 6 to the Notes to Consolidated Financial Statements for additional
information.
(2)
Capital
lease obligations include the amount of imputed interest over the terms of
the leases. See Note 13 to the Notes to Consolidated Financial Statements
for additional information.
(3)
See
Note 13 to the Notes to Consolidated Financial Statements for additional
information.
(4)
Coal
lease obligations include minimum royalties paid on leased coal rights.
Certain coal leases do not have set expiration dates but extend until
completion of mining of all merchantable and mineable coal reserves. For
purposes of this table, we have generally assumed that minimum royalties
on such leases will be paid for a period of 20 years.
(5)
Purchased
coal obligations represent commitments to purchase coal from external
production sources under firm contracts as of December 31,2008.
(6)
Other
purchase obligations primarily include capital expenditure commitments for
surface mining and other equipment as well as purchases of materials and
supplies. We have purchase agreements with vendors for most types of
operating expenses. However, our open purchase orders (which are not
recognized as a liability until the purchased items are received) under
these purchase agreements, combined with any other open purchase orders,
are not material and are excluded from this table. Other purchase
obligations also include contractual commitments under transportation
contracts. Since the actual tons to be shipped under these contracts are
not set and will vary, the amount included in the table reflects the
minimum payment obligations required by the
contracts.
Additionally,
we have liabilities relating to pension and other postretirement benefits, work
related injuries and illnesses, and mine reclamation and closure. As of December31, 2008, payments related to these items are estimated to be:
Payments
Due by Years (In Thousands)
Within
1
Year
1
- 3
Years
3
- 5
Years
$50,880
$81,670
$99,148
Our
determination of these noncurrent liabilities is calculated annually and is
based on several assumptions, including then-prevailing conditions, which may
change from year to year. In any year, if our assumptions are inaccurate, we
could be required to expend greater amounts than anticipated. Moreover, in
particular for periods after 2008, the estimates may change from the amounts
included in the table, and may change significantly, if assumptions change to
reflect changing conditions. These assumptions are discussed in the Notes to
Consolidated Financial Statements and in Critical Accounting Estimates and
Assumptions of this Management’s Discussion and Analysis of Financial Condition
and Results of Operations section.
48
Off-Balance
Sheet Arrangements
In the
normal course of business, we are a party to certain off-balance sheet
arrangements including 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 the consolidated balance sheets, and, except
for the operating leases, which are discussed in Note 13 to the Notes to
Consolidated Financial Statements, we do not expect any material impact on our
cash flows, results of operations or financial condition to result from these
off-balance sheet arrangements.
From time to
time we use bank letters of credit to secure our obligations for workers’
compensation programs, various insurance contracts and other obligations. At
December 31, 2008, we had $120.5 million of letters of credit outstanding of
which $45.0 million was collateralized by $46.0 million of cash deposited in
restricted, interest bearing accounts pledged to issuing banks and $75.5 million
was issued under our asset based lending arrangement. No claims were outstanding
against those letters of credit as of December 31, 2008.
On
January 22, 2008, a settlement was reached regarding our previously reported
disagreement and protest of a new actuarial methodology being applied by the
Office of Workers’ Claims (“OWC”) for the Commonwealth of Kentucky in
determining levels of surety against potential future claims. The
settlement resulted in the dismissal of our cases pending in the Franklin County
Circuit Court of Kentucky and required us to post additional surety of $11.5
million for the 2006 and 2007 assessments against potential claims. That
additional surety requirement was satisfied with the posting of a letter of
credit issued under our asset-based lending arrangement.
We use
surety bonds to secure reclamation, workers’ compensation, wage payments, and
other miscellaneous obligations. As of December 31, 2008, we had $330.2 million
of outstanding surety bonds. These bonds were in place to secure obligations as
follows: post-mining reclamation bonds of $321.1 million, and other
miscellaneous obligation bonds of $9.1 million. Outstanding surety bonds of
$46.1 million are secured with letters of credit. In addition, in December 2008,
a $50.0 million appeal bond in the Wheeling-Pittsburgh legal matter was used to
pay the plaintiff following the U.S. Supreme Court decision to not hear our
appeal of the matter (see Note 18 to Notes to Consolidated Financial Statements
for further discussion).
Generally,
the availability and market terms of surety bonds continue to be challenging. If
we are unable to meet certain financial tests applicable to some of our surety
bonds, or to the extent that surety bonds otherwise become unavailable, we would
need to replace the surety bonds or seek to secure them with letters of credit,
cash deposits, or other suitable forms of collateral.
Certain Trends and
Uncertainties
Our
inability to satisfy contractual obligations may adversely affect
profitability.
From time
to time, we have disputes with customers over the provisions of sales agreements
relating to, among other things, coal pricing, quality, quantity, delays and
force majeure declarations. Our inability to satisfy contractual obligations
could result in the purchase of coal from third-party sources to satisfy those
obligations, the negotiation of settlements with customers, which may include
price reductions, the reduction of commitments or the extension of the time for
delivery, and customers terminating contracts, declining to do future business
with us, or initiating claims against us. Recently, several of our customers
have notified us of losses they have allegedly incurred due to alleged
shortfalls in contracted coal shipments. We believe that factors beyond our
control or responsibility account for most or all of the shortfalls. However, we
may not be able to resolve all of these disputes, or other disputes with
customers over sales agreements, in a satisfactory manner, which could result in
the payment of substantial damages or otherwise harm our reputation and our
relationships with our customers (see Note 18 to the Notes to Consolidated
Financial Statements for further discussion).
49
The
global financial crisis may have an impact on our business, financial condition
and liquidity in ways that we currently cannot predict.
The
continuing credit crisis and related turmoil in the global financial markets has
had and may continue to have an impact on our business, financial condition and
liquidity.
We are
currently unable to access our remaining cash invested with the Primary Fund, a
money market fund that has suspended redemptions and is being liquidated. We had
invested $217.9 million in this fund, which had a fair value of
$211.4 million at September 30, 2008. On October 31, 2008 and December 3,2008, the Primary Fund made distributions to us of $110.7 million and $61.3
million, respectively, leaving an investment balance of $39.4 million.
Subsequent to December31, 2008, on February 20, 2009, the Primary Fund made an additional
distribution to us of $14.5 million. While we expect to receive substantially
all of our remaining holdings in this fund during 2009, we cannot predict when
this will occur or the actual amount we will eventually
receive.
The
current difficult economic market environment is causing contraction in the
availability of credit in the marketplace. In addition to the impact
that the global financial crisis has already had on us, we may face significant
challenges if conditions in the financial markets do not improve or continue to
worsen. For example, an extension of the credit crisis to other industries could
adversely impact overall demand, particularly for our metallurgical grade coals,
which could have a negative effect on our revenues. In addition, our ability to
access the capital markets may be severely restricted at a time when we
would like, or need, to access these markets, which could have an impact on our
flexibility to react to changing economic and business conditions and could
potentially reduce our sources of liquidity. Moreover, volatility and
disruption of financial markets could limit customers’ ability to obtain
adequate financing to maintain operations and result in a decrease in sales
volume that could have a negative impact on our cash flows, results of
operations or financial condition.
Capital
and credit market volatility may affect our costs of borrowing.
While we
maintain business relationships with a diverse group of financial institutions,
their continued viability is not certain. Difficulties at one or more such
financial institutions could lead them not to honor their contractual credit
commitments under our ABL Facility or to renew their extensions of credit or
provide new sources of credit. Recently, the capital and credit
markets have been highly volatile as a result of adverse conditions that have
caused the failure and near failure of a number of large financial services
companies. If the capital and credit markets continue to experience
volatility and the availability of funds remains limited, we may incur increased
costs associated with borrowings. While we believe that recent
governmental and regulatory actions should reduce the risk of a further
deterioration or systemic contraction of capital and credit markets, there can
be no certainty that our liquidity will not be negatively impacted by
adverse conditions in the capital and credit markets.
We
may be adversely affected by a decline in the financial condition and
creditworthiness of our customers.
In an
effort to mitigate credit-related risks in all customer classifications, we
maintain a credit policy, which requires scheduled reviews of customer
creditworthiness and continuous monitoring of customer news events that might
have an impact on their financial condition. Negative credit performance or
events may trigger the application of tighter terms of sale, requirements for
collateral or guarantees or, ultimately, a suspension of credit privileges. The
creditworthiness of customers can limit who we can do business with and at what
price. For the year ended December 31, 2008, approximately 97% of coal
sales volume was pursuant to long-term contracts. We anticipate that in
2009, the percentage of our sales pursuant to long-term contracts will be
comparable with the percentage of our sales for 2008. For 2009, approximately
60% of our projected sales tons are contracted to be sold to our 10 largest
customers, with our largest customer currently contracted to purchase
approximately 26% of our projected 2009 sales. Many of our customers,
including many of our large customers, are experiencing lower demand and weaker
financial performance due to the economic downturn. If one or more of our larger
customers fails to make payment for our sales to them, there could be an adverse
effect on our cash flows, results of operations or financial
condition.
We have
contracts to supply coal to energy trading and brokering companies who resell
the coal to the ultimate users. We are subject to being adversely affected by
any decline in the financial condition and creditworthiness of these energy
trading and brokering companies. In addition, as one of the largest suppliers of
metallurgical coal to the United States steel industry and a significant
exporter to foreign users, we are subject to being adversely affected by any
decline in the financial condition or production volume of both United States
and foreign steel producers.
50
Some
of our customers may be unwilling to take all of their contracted tonnage or may
request a price lower than their contracted price.
Many of
our customers are experiencing lower demand for their products and services due
to the current severe economic downturn, particularly customers in the steel
industry. Several of our steel customers have announced production cutbacks in
excess of 30% of their normal operating capacity and some
of our utility and industrial customers have announced smaller
cutbacks. The lower demand for our customers’ products results
in lower demand for the coal used in their manufacturing
process. Some of our customers have requested and others may request
deferrals of shipments, reduction of contracted sales tonnages and/or reduction
of the contracted sales price. If we believe it is in our best interests to
agree to any reduction in contracted price and/or tons from our customers, there
could be an adverse effect on our cash flows, results of operations or financial
condition.
Critical Accounting Estimates and
Assumptions
The
preparation of financial statements in conformity with GAAP requires management
to make estimates and assumptions that affect reported amounts. These estimates
and assumptions are based on information available as of the date of the
financial statements. Significant changes to the estimates and assumptions used
in determining certain liabilities described below could introduce substantial
volatility to our costs. The following critical accounting estimates and
assumptions were used in the preparation of the financial
statements:
Defined Benefit Pension
Plans
The
estimated cost and benefits of non-contributory defined benefit pension plans
are determined by independent actuaries, who, with management’s review and
approval, use various actuarial assumptions, including discount rate, future
rate of increase in compensation levels and expected long-term rate of return on
pension plan assets. The discount rate is an estimate of the current interest
rate at which the applicable liabilities could be effectively settled as of the
measurement date. In estimating the discount rate, forecasted cash flows were
discounted using each year’s associated spot interest rate on high quality fixed
income investments. At December 31, 2008 and 2007, the discount rate used to
determine defined benefit pension liability was 6.10% and 6.50%, respectively.
The impact of lowering the discount rate 0.25% for 2008 would have increased the
2008 net periodic pension expense by approximately $1.8 million. The rate of
increase in compensation levels is determined based upon our long-term plans for
such increases. The rate of increase in compensation levels used was 4.0% for
the years ended December 31, 2008 and 2007. The expected long-term rate of
return on pension plan assets is based on long-term historical return
information and future estimates of long-term investment returns for the target
asset allocation of investments that comprise plan assets. The expected
long-term rate of return on plan assets used to determine expense in each period
was 8.0% for each of the years ended December 31, 2008, 2007 and 2006,
respectively. A 0.5% decrease in the expected long-term rate of return
assumption would have increased the 2008 net periodic pension expense by
approximately $1.4 million. We expect our 2009 pension costs related to our
qualified non-contributory pension plan to significantly increase as a result of
investment
losses on the pension assets during 2008. The actuarial assumptions we
use may differ materially from actual results due to changing market and
economic conditions, higher or lower withdrawal rates or longer or shorter life
spans of participants. While we believe that the assumptions used are
appropriate, differences in actual experience or changes in assumptions might
materially affect our financial position or results of operations. See Note 5 to
the Notes to Consolidated Financial Statements for further discussion on our
pension plans.
We have
an internal investment committee (“Investment Committee”) that sets investment
policy for the pension assets, selects and monitors investment managers and
monitors asset allocation. In January 2009, the Investment Committee revised the
target pension assets allocation for an interim period given the recent
volatility and uncertainty in the equity securities markets. The targeted
asset allocation for equity securities was revised to 25% of current plan assets
compared to 54.2% of the pension assets invested in equity securities at
December 31, 2008, with the balance of plan assets now to be invested in cash,
cash equivalents and debt securities. The plan asset portfolio has been
rebalanced consistent with the revised targeted asset allocation
strategy. The rebalancing will not impact the 2009 pension expense,
however the investment returns on pension assets from this rebalancing could
materially impact pension expense in future periods.
Coal
Workers’ Pneumoconiosis
We are
responsible under the Federal Coal Mine Health and Safety Act of 1969, as
amended, and various states’ statutes, for the payment of medical and disability
benefits to eligible recipients resulting from occurrences of coal workers’
pneumoconiosis disease (black lung). An annual evaluation is prepared by
independent actuaries, who, after review and approval by management, use various
assumptions regarding disability incidence, medical costs trend, cost of living
trend, mortality, death benefits, dependents and interest rates. We record
expense related to this obligation using the service cost method. At December31, 2008 and December 31, 2007, the discount rate used to determine the black
lung liability was 6.10% and 6.50%, respectively. Included in Note 11 to the
Notes to Consolidated Financial Statements is a medical cost trend and cost of
living trend sensitivity analysis.
51
Workers’
Compensation
Our
operations have workers’ compensation coverage through a combination of either
self-insurance, participation in a state run program, or commercial insurance.
We accrue for the self-insured liability by recognizing cost when it is probable
that the liability has been incurred and the cost can be reasonably estimated.
To assist in the determination of this estimated liability we utilize the
services of third-party administrators who derive claim reserves from historical
experience. These third parties provide information to independent actuaries,
who after review and consultation with management with regards to actuarial
assumptions, including discount rate, prepare an evaluation of the self-insured
liabilities. At December 31, 2008 and December 31, 2007, the discount rate used
to determine the self-insured workers’ compensation liability obligation was
5.00%. A decrease in the assumed discount rate increases the workers’
compensation self-insured liability and related expense. Actual experience in
settling these liabilities could differ from these estimates, which could
increase our costs. See Note 11 to the Notes to Consolidated Financial
Statements for further discussion on workers’ compensation.
Other
Postretirement Benefits
Our
sponsored health care plans provide retiree health benefits to eligible union
and non-union retirees who have met certain age and service requirements.
Depending on year of retirement, benefits may be subject to annual deductibles,
coinsurance requirements, lifetime limits, and retiree contributions. These
plans are not funded. We pay costs as incurred by participants. The estimated
cost and benefits of the retiree health care plans are determined by independent
actuaries, who, after review and approval by management, use various actuarial
assumptions, including discount rate, expected trend in health care costs and
per capita claims costs. At December 31, 2008 and December 31, 2007, the
discount rate used to determine the other postretirement benefit liability was
6.10% and 6.50%, respectively. The impact of lowering the discount rate 0.25%
for 2008 would have increased the 2008 net periodic postretirement benefit cost
by approximately $0.3 million. At December 31, 2008, assumptions of our health
care plans’ cost trend were projected at annual rates of 8.5% for pre-Medicare
claims, 8.8% for Medicare-eligible claims and 7.0% for Medicare supplemental
plans, all ranging down to 5.0% by 2019 and remaining level
thereafter. The impact of increasing the health care cost trend rate
by 1.0% would have increased the 2008 net periodic postretirement benefit cost
by approximately $3.2 million. Included in Note 10 to the Notes to Consolidated
Financial Statements is a sensitivity analysis on the health care trend rate
assumption.
Reclamation
and Mine Closure Obligations
The SMCRA
establishes operational, reclamation and closure standards for all aspects of
surface mining as well as most aspects of deep mining. Total reclamation and
mine-closing liabilities are based upon permit requirements and engineering
estimates related to these requirements. We account for our reclamation
liabilities under SFAS 143. SFAS 143 requires that asset retirement obligations
be recorded as a liability based on fair value, which is calculated as the
present value of the estimated future cash flows. Management and engineers
periodically review the estimate of ultimate reclamation liability and the
expected period in which reclamation work will be performed. In estimating
future cash flows, we considered the estimated current cost of reclamation and
applied inflation rates and a third-party profit, as necessary. The third-party
profit is an estimate of the approximate markup that would be charged by
contractors for work performed on our behalf. The discount rate applied is based
on the rates of treasury bonds with maturities similar to the estimated future
cash flow, adjusted for our credit standing. The estimated liability can
change significantly if actual costs vary from assumptions or if governmental
regulations change significantly.
Contingencies
We are
parties to a number of legal proceedings, incident to our normal business
activities. These matters include contract disputes, personal injury, property
damage and employment matters. While we cannot predict the outcome of these
proceedings, based on our current estimates, 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. However, it is reasonably possible that the ultimate
liabilities in the future with respect to these lawsuits and claims may be
material to our cash flows, results of operations or financial condition. See
Item 3. Legal Proceedings and Note 18 to the Notes to Consolidated Financial
Statements for further discussion on our contingencies.
Income
Taxes
We
account for income taxes in accordance with SFAS No. 109, “Accounting for Income
Taxes” (“SFAS 109”), as interpreted by FASB Interpretation No. 48, “Accounting
for Uncertainty in Income Taxes – an interpretation of FASB Statement No. 109”
(“FIN 48”), which requires that deferred tax assets and liabilities be
recognized using enacted tax rates for the effect of temporary differences
between the book and tax bases of recorded assets and liabilities. SFAS 109 also
requires that deferred tax assets be reduced by a valuation allowance if it is
more likely than not that some portion of the deferred tax asset will not be
realized. In evaluating the need for a valuation allowance, we take into account
various factors, including tax attribute carrybacks, the future reversals of
existing taxable temporary differences, the expected level of future taxable
income and available tax planning strategies. If actual results differ from the
assumptions made in the evaluation of our valuation allowance, we record a
change in valuation allowance through income tax expense in the period such
determination is made.
52
Under FIN
48, we are required
to establish reserves based upon management’s assessment of exposure
associated with tax positions taken relative to temporary and permanent tax
differences and tax credits, plus penalties and interest, if any, on
the accrued uncertain tax positions. The tax reserves are analyzed
periodically and adjustments are made as events occur to warrant adjustment to
the reserves. Management believes that we have adequately provided for any
income taxes that may ultimately be paid with respect to all open tax
years.
Coal
Reserve Values
There are
numerous uncertainties inherent in estimating quantities and values of
economically recoverable coal reserves. Many of these uncertainties 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 and
analyzed by our internal engineers, geologists and financial associates. Some of
the factors and assumptions that impact economically recoverable reserve
estimates include: (i) geological conditions; (ii) historical production from
similar areas with similar conditions; (iii) the assumed effects of regulations
and taxes by governmental agencies; (iv) assumptions governing future prices;
and (v) future operating costs.
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, revenue and
expenditures with respect to reserves will likely vary from estimates, and these
variances may be material. Variances would affect both the Consolidated
Statements of Income, in the form of revenue and expenditures, as well as the
Consolidated Balance Sheets, in the form of valuation of coal reserves,
depletion rates and potential impairment.
Derivative
Instruments
We evaluate each of our coal
sales and coal purchase forward contracts under SFAS No. 133, “Accounting for
Derivative Instruments and Hedging Activities (as amended)” (“SFAS 133”) to
determine if they qualify for the normal purchase normal sale ("NPNS")
exception
prescribed by SFAS 133. The majority of our forward contracts do qualify
for the NPNS exception based on management's intent and ability to physically
deliver or take physical delivery of the coal. For those contracts that do not
qualify for NPNS, the contracts are required to be accounted
for as derivative instruments in accordance with SFAS 133, which requires
all derivative instruments that do not qualify for teh NPNS exception to be
recognized as assets or liabilities and to be measured at fair
value. To establish fair
values for these contracts, we use bid/ask price quotations obtained
from independent third-party brokers. The net fair value change
in our contracts deemed derivatives under SFAS 133 at December 31, 2008, was
recognized as an unrealized loss in the current period earnings. We
could experience difficulty in valuing our derivative instruments if the number
of third-party brokers should decrease or
market liquidity is reduced. See Note 15 to the Notes to Consolidated
Financial Statements for further discussion of our derivative
instruments.
Recent Accounting
Pronouncements
Refer to
Note 1 in the Notes to Consolidated Financial Statements for information
concerning the effect of recent accounting pronouncements.
Item
7A. Quantitative and Qualitative Discussions about Market Risk
Our net
interest expense is currently not sensitive to changes in the general level of
short-term interest rates. At December 31, 2008, all of the outstanding $1,465.6
million of our debt was under fixed-rate instruments. However, if it should
become necessary to borrow under our asset-based revolving credit facility,
those borrowings would be made at a variable rate. Interest income is sensitive
to changes in short-term interest rates. Assuming that Cash and cash equivalents
was fixed at the December 31, 2008 level of $607.0 million, a hypothetical 100
basis point decrease in money market interest rates would result in a decrease
of approximately $6.1 million in Interest income.
In 2008,
we primarily managed market price risk for coal through the use of long-term
coal supply agreements, which are contracts with a term of one year or more in
duration, rather than through the use of derivative instruments. We estimate
that the percentage of tons sold pursuant to these long-term contracts was 97%
for our fiscal year ended December 31, 2008. We anticipate that in 2009, the
percentage of our tons sold pursuant to long-term contracts will be comparable
with the percentage of our sales for 2008. The prices for coal shipped under
long-term contracts may be below the current market price for similar types of
coal at any given time. As a consequence of the substantial volume of our sales
that are subject to these long-term agreements, we have less coal available with
which to capitalize on stronger coal prices if and when they arise. In addition,
because long-term contracts may allow the customer to elect volume flexibility
based on requirements, our ability to realize the higher prices that may be
available in the spot market may be restricted when customers elect to purchase
higher volumes under such contracts, or our exposure to market-based pricing may
be increased should customers elect to purchase fewer tons.
53
From time
to time we may also purchase coal directly from third parties to supplement our
produced and processed coal in order to provide coal to meet customer
requirements under sales contracts. Certain of our purchase and sale
contracts meet the definition of a derivative instrument under SFAS 133.
The use of purchase and sales contracts which are accounted for as derivative
instruments could materially affect our results of operations as a result of the
requirement to mark them to market at the end of each reporting period in
accordance with SFAS 133.
These
transactions give rise to commodity price risk, which represents the potential
gain or loss that can be caused by an adverse change in the price of coal.
Outstanding purchase and sales contracts at December 31, 2008, that are
accounted for as derivative instruments in accordance with SFAS 133 are
summarized as follows:
As of
December 31, 2008, a hypothetical increase of 10% in the forward market
price would result in an additional fair value loss recorded for these
derivative instruments of $2.8 million. A hypothetical decrease of
10% in the forward market price would result in a reduction in the fair value
loss recorded for these derivative instruments of $2.8
million.
54
Item
8. Financial Statements and Supplementary Data
REPORT
OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board
of Directors and Shareholders of Massey Energy Company
We have
audited the accompanying consolidated balance sheets of Massey Energy Company as
of December 31, 2008 and 2007, and the related consolidated statements of
income, shareholders' equity, and cash flows for each of the three years in the
period ended December 31, 2008. Our audits also included the financial statement
schedule listed in Item 15(a). These financial statements and schedule are the
responsibility of the Company’s management. Our responsibility is to express an
opinion on these financial statements and schedule 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 financial statements referred to above present fairly, in all
material respects, the consolidated financial position of Massey Energy Company
at December 31, 2008 and 2007, and the consolidated results of its operations
and its cash flows for each of the three years in the period ended December 31,2008, in conformity with U.S. generally accepted accounting principles. Also, in
our opinion, the related financial statement schedule, when considered in
relation to the basic financial statements taken as a whole, presents fairly in
all material respects the information set forth therein.
As
discussed in Note 7 to the consolidated financial statements, in 2007 the
Company changed its method for accounting for income taxes to comply with the
accounting provisions of Financial Accounting Standards Board Interpretation No.
48, Accounting for Uncertainty
in Income Taxes - an interpretation of FASB Statement No. 109. As
discussed in Note 1 to the consolidated financial statements, in 2006 the
Company changed its method of accounting for post-production stripping costs to
comply with the accounting provisions of Emerging Issues Task Force No. 04-6,
Accounting for Stripping Costs
Incurred During Production in the Mining Industry. As discussed in Note 1
to the consolidated financial statements, in 2006 the Company changed its method
of accounting for defined benefit pension and other post-retirement plans to
comply with the accounting provisions of Financial Accounting Standards Board
Statement No. 158, Employer’s
Accounting for Defined Benefit Pension and Other Postretirement Plans – an
Amendment of FASB Statement Nos. 87, 77, 106, and 132(R). As discussed in
Note 1 to the consolidated financial statements, in 2006 the Company changed its
method of accounting for stock-based compensation to comply with the accounting
provisions of Financial Accounting Standards Board Statement No. 123(R), Share-Based
Payment.
We also
have audited, in accordance with the standards of the Public Company Accounting
Oversight Board (United States), Massey Energy Company’s internal control over
financial reporting as of December 31, 2008, based on criteria established in
Internal Control-Integrated Framework issued by the Committee of Sponsoring
Organizations of the Treadway Commission and our report dated February 27, 2009
expressed an unqualified opinion thereon.
The
accompanying consolidated financial statements include the accounts of Massey
Energy Company (“we”, “our”, or “us”), its wholly owned and sole, direct
operating subsidiary A.T. Massey Coal Company, Inc. (“A.T. Massey”) and A.T.
Massey’s wholly owned direct and indirect subsidiaries. Inter-company
transactions and accounts are eliminated in consolidation. We have no
independent assets or operations. We do not have a controlling interest in any
separate independent operations. Investments in business entities in which we do
not have control, but have the ability to exercise significant influence over
the operating and financial policies, are accounted for under the equity
method.
A.T.
Massey fully and unconditionally guarantees our obligations under the 6.625%
senior notes due 2010 (“6.625% Notes”), the 6.875% senior notes due 2013
(“6.875% Notes”), the 3.25% convertible senior notes due 2015 (“3.25% Notes”),
the 4.75% convertible senior notes due 2023 (“4.75% Notes”) and the 2.25%
convertible senior notes due 2024 (“2.25% Notes”). In addition, the 6.625%
Notes, the 6.875% Notes, the 3.25% Notes and the 2.25% Notes are fully and
unconditionally, jointly and severally guaranteed by A.T. Massey and
substantially all of our indirect operating subsidiaries, each such subsidiary
being indirectly 100% owned by us. The subsidiaries not providing a guarantee of
the 6.625% Notes, the 6.875% Notes, the 3.25% Notes and the 2.25% Notes are
minor (as defined under Securities and Exchange Commission (“SEC”) Rule
3-10(h)(6) of Regulation S-X). See Note 6 for a more complete discussion of
debt.
Reclassifications
To maintain
consistency and comparability, certain amounts from previously reported
consolidated financial statements have been reclassified to conform to current
year presentation. These reclassifications had no effect on previously reported
consolidated operating income, net earnings or shareholders’
equity.
Use
of Estimates
The
preparation of the financial statements in conformity with accounting principles
generally accepted in the United States requires management to make estimates
and assumptions that affect reported amounts. These estimates are based on
information available as of the date of the financial statements. Therefore,
actual results could differ from those estimates. The most significant estimates
used in the preparation of the consolidated financial statements are related to
defined benefit pension plans, coal workers’ pneumoconiosis (“black lung”),
workers’ compensation, other postretirement benefits, reclamation and mine
closure obligations, contingencies, income taxes, coal reserve estimates, stock
options and derivative instruments.
Revenue
Recognition
Produced
coal revenue is realized and earned when title passes to the customer. Coal
sales are made to our customers under the terms of coal supply agreements, most
of which are long-term (one year or greater). Under the typical terms of these
coal supply agreements, title and risk of loss transfer to the customer at the
mine, dock, or port, where coal is loaded to the rail, barge, ocean-going
vessel, truck or other transportation source(s) that serves each of our mines.
We incur certain “add-on” taxes and fees on coal sales. Coal sales reported in
Produced coal revenues include these “add-on” taxes and fees charged by various
federal and state governmental bodies.
Freight
and handling revenue consists of shipping and handling costs invoiced to coal
customers and paid to third-party carriers. These revenues are directly offset
by Freight and handling costs.
Purchased
coal revenue represents revenue recognized from the sale of coal purchased from
third-party production sources. We take title to the purchased coal, which we
then resell to our customers. Typically, title and risk of loss transfer to the
customer at the mine, dock or port, where coal is loaded to the rail, barge,
ocean-going vessel, truck or other transportation source(s).
Other
revenue includes refunds on railroad agreements, royalties related to coal lease
agreements, gas well revenue, gains on the sale of non-strategic assets and
reserve exchanges, joint venture revenue and other miscellaneous revenue.
Royalty income generally results from the lease or sublease of mineral rights to
third parties, with payments based upon a percentage of the selling price or an
amount per ton of coal produced. Certain agreements require minimum lease
payments regardless of the extent to which minerals are produced from the
leasehold. The terms of these agreements generally range from specified periods
of 5 to 10 years, or can be for an unspecified period until all reserves are
depleted.
60
Derivative
Instruments
We evaluate
each of our coal sales and coal purchase forward contracts under SFAS No. 133,
“Accounting for Derivative Instruments and Hedging Activities” (“SFAS 133”) to
determine if they qualify for the normal purchase normal sale ("NPNS") exception
prescribed by SFAS 133. The majority of our forward contracts do qualify
for the NPNS exception based on management's intent and ability to physically
deliver or take physical delivery of the coal. For those contracts that do not
qualify for NPNS, the contracts are required to be accounted for as derivative
instruments in accordance with SFAS 133, which requires all derivative
instruments to be recognized as assets or liabilities and to be measured at fair
value. Those contracts that have been identified as derivatives have not been
designated as cash flow or fair value hedges and, accordingly, the net change in
fair value is recorded in current period earnings. We record changes in
derivative assets and liabilities subject to mark-to-market accounting on a net
basis in Net change in fair value of derivative instruments in our Consolidated
Statements of Income.
Cash
and Cash Equivalents
Cash and
cash equivalents are stated at cost, which approximates fair value. Cash
equivalents are primarily invested in money market funds, which consist of
highly liquid investments. At December 31, 2008, we maintained $607.0 million
in Cash and cash equivalents. These balances include $305.0 million invested in
shares of seven institutional money market funds, all of which carry AAA/Aaa
ratings from Standard & Poor’s (“S&P”) and Moody’s Investors Service
(“Moody’s”), respectively. In addition, $265.0 million was invested in shares of
institutional money funds which invest substantially all of their funds in
securities supported by obligations of the United States Treasury and carry an
AAA/Aaa rating from S&P and Moody’s, respectively. All of these money funds
participate in the U.S. Treasury Temporary Guarantee Program for Money Market
Funds. The remaining $37.0 million is invested in other liquid interest
and non-interest bearing accounts.
Short-Term
Investment
Short-term
investment is comprised of an investment in The Reserve Primary Fund (“Primary
Fund”), a money market fund that has suspended redemptions and is being
liquidated. We have determined that our investment in the Primary Fund no longer
meets the definition of a security within the scope of Statement of Financial
Accounting Standards (“SFAS”) No. 115, “Accounting for Certain Investments in
Debt and Equity Securities” (“SFAS 115”) since the equity investment no longer
has a readily determinable fair value. Therefore, the investment has been
classified as a short-term investment subject to the cost method of accounting,
and therefore reflected at the lower of cost or net realizable value. This
classification as a short-term investment is based on our assessment of each of
the individual securities that make up the underlying portfolio holdings in the
Primary Fund, which primarily consisted of commercial paper and discount notes
having maturity dates within the next 12 months, and the stated notifications
from the Primary Fund that they expect to liquidate all of their holdings and
make distributions within a year. Accordingly, we have reclassified our
investment in the Primary Fund from Cash and cash equivalents to Short-term
investment on our Consolidated Balance Sheet as of December 31,2008. See Note 16 in the Notes to Consolidated Financial Statements
for additional information.
Trade
Receivables
Trade
accounts receivable are recorded at the invoiced amount and are non-interest
bearing. We maintain a bad debt reserve based upon the expected collectibility
of our accounts receivable. The reserve includes specific amounts for accounts
that are likely to be uncollectible, as determined by such variables as customer
creditworthiness, the age of the receivables, bankruptcies and disputed amounts.
Account balances are charged off against the reserve after all means of
collection have been exhausted and the potential for recovery is considered
remote.
Inventories
Produced
coal and supplies inventories generally are stated at the lower of average cost
or net realizable value. Coal inventory costs include labor, supplies,
equipment, operating overhead and other related costs. Purchased coal
inventories are stated at the lower of cost, computed on the first-in, first-out
method, or net realizable value.
Prior to
2006, we accounted for the costs of removing overburden and waste materials
(stripping costs) incurred during the production phase of a mine as a component
of surface mining inventory costs. As overburden was removed, the stripping
costs were captured in inventory costs and attributed to the proven reserves
benefited. On January 1, 2006, we adopted Emerging Issues Task Force (“EITF”)
Issue No. 04-6, “Accounting for Stripping Costs Incurred During Production in
the Mining Industry” (“EITF 04-6”). This consensus limits accounting for
production-related stripping costs as a component of inventory to those costs
associated with extracted or saleable inventories. Therefore, stripping costs in
2008, 2007 and 2006 are recorded as Cost of produced coal revenue while 2005
stripping costs were shown in Inventories as Advance stripping
costs.
61
Surface
mine stripping costs
We
account for the costs of removing overburden and waste materials (stripping
costs) at surface mines differently, depending upon whether the costs are
incurred prior to producing coal (pre-production) versus after a more than de
minimis amount of shippable product is produced (post-production).
Production-related stripping costs are only included as a component of inventory
if they are associated with extracted or saleable
inventories. Pre-production stripping costs are capitalized in mine
development and amortized over the life of the developed pit consistent with
coal industry practices. Post-production stripping costs are expensed
as incurred and recorded as Cost of produced coal revenue.
Pre-production
stripping costs – At existing surface operations, additional pits may be added
to increase production capacity in order to meet customer requirements. These
expansions may require significant capital to purchase additional equipment,
expand the workforce, build or improve existing haul roads and create the
initial pre-production box cut to remove overburden (i.e. advance stripping
costs) for new pits at existing operations. If these pits operate in a separate
and distinct area of the mine, the costs associated with initially uncovering
coal (i.e. advance stripping costs incurred for the initial box cuts) for
production are capitalized in mine development and amortized over the life of
the developed pit consistent with coal industry practices.
Post-production
stripping costs – Where new pits are routinely developed as part of a contiguous
mining sequence, we expense such costs as incurred. The development of a
contiguous pit typically reflects the planned progression of an existing pit,
thus maintaining production levels from the same mining area utilizing the same
employee group and equipment.
Income
Taxes
We
account for income taxes in accordance with Statement of Financial Accounting
Standards (“SFAS”) No. 109, “Accounting for Income Taxes” (“SFAS 109”), which
requires that deferred tax assets and liabilities be recognized using enacted
tax rates for the effect of temporary differences between the book and tax bases
of recorded assets and liabilities. SFAS 109 also requires that deferred tax
assets be reduced by a valuation allowance if it is more likely than not that
some portion of the deferred tax asset will not be realized. In evaluating the
need for a valuation allowance, we take into account various factors, including
carrybacks, the expected level of future taxable income and available tax
planning strategies. If actual results differ from the assumptions made in the
evaluation of our valuation allowance, we record a change in valuation allowance
through income tax expense in the period such determination is
made.
In June
2006, the Financial Accounting Standards Board (“FASB”) issued Interpretation
No. 48, “Accounting for Uncertainty in Income Taxes – an interpretation of FASB
Statement No. 109” (“FIN 48”) to create a single model to address accounting for
uncertainty in income tax positions. FIN 48 clarifies the accounting for income
taxes by prescribing a minimum recognition threshold that a tax position is
required to meet before being recognized in the financial statements. FIN 48
also provides guidance on derecognition, measurement, classification, interest
and penalties, accounting in interim periods, disclosure and transition. We
adopted FIN 48 effective January 1, 2007. We accrue interest and penalties, if
any, related to unrecognized tax benefits in Other noncurrent liabilities
and recognize the related expense in Income tax expense.
Property,
Plant and Equipment
Property,
plant and equipment are carried at cost and stated net of accumulated
depreciation. Expenditures that extend the useful lives of existing buildings
and equipment are capitalized. Maintenance and repairs are expensed as incurred.
Coal exploration costs are expensed as incurred. Costs incurred to maintain
current production capacity at a mine and exploration expenditures are charged
to operating costs as incurred, including costs related to drilling and study
costs incurred to convert or upgrade mineral resources to reserves. Development
costs, including pre-production stripping costs, applicable to the opening of
new coal mines and certain mine expansion projects are capitalized until
production begins. When properties are retired or otherwise disposed, the
related cost and accumulated depreciation are removed from the respective
accounts and any profit or loss on disposition is credited or charged to Other
revenue.
Our coal
reserves are controlled either through direct ownership or through leasing
arrangements. Mining properties owned in fee represent owned coal properties
carried at cost. Leased mineral rights represent leased coal properties carried
at the cost of acquiring those leases. The leases are generally long-term in
nature (original term five to fifty years or until the mineable and merchantable
coal reserves are exhausted), and substantially all of the leases contain
provisions that allow for automatic extension of the lease term as long as
mining continues.
62
Depreciation
of buildings, plants and equipment is calculated on the straight-line method
over their estimated useful lives or lease terms as follows:
Years
Buildings
and plants
20
to 30
Equipment
3
to 20
Capital
leases
4
to 7
Ownership
of assets under capital leases transfers to us at the end of the lease term.
Depreciation of assets under capital leases is included within Depreciation,
depletion and amortization.
Amortization
of development costs is computed using the units-of-production method over the
estimated proven and probable reserve tons.
Depletion
of mining properties owned in fee and leased mineral rights is computed using
the units-of-production method over the estimated proven and probable reserve
tons (as adjusted for recoverability factors). As of December 31, 2008,
approximately $152.2 million of costs associated with mining properties owned in
fee and leased mineral rights are not currently subject to depletion as mining
has not begun or production has been temporarily idled on the associated coal
reserves.
We
capitalize certain costs incurred in the development of internal-use software,
including external direct material and service costs, in accordance with the
American Institute of Certified Public Accountants’ Statement of Position 98-1,
“Accounting for the Costs of Computer Software Developed for or Obtained for
Internal Use.” All costs capitalized are amortized using the straight-line
method over the estimated useful life not to exceed 7 years.
Impairment
of Long-Lived Assets
Impairment
of long-lived assets is recorded when indicators of impairment are present and
the undiscounted cash flows estimated to be generated by those assets are less
than the assets’ carrying value. The carrying value of the assets is then
reduced to their estimated fair value, which is usually measured based on an
estimate of future discounted cash flows. There were no material impairment
losses recorded during the periods covered by the consolidated financial
statements.
Advance
Mining Royalties
Coal
leases that require minimum annual or advance payments and are recoverable from
future production are generally deferred and charged to expense as the coal is
subsequently produced. At December 31, 2008 and 2007, advance mining royalties
included in Other noncurrent assets totaled $35.3 million and $37.0 million, net
of an allowance of $14.7 million and $16.2 million, respectively.
Reclamation
We
account for reclamation liabilities in accordance with SFAS No. 143, “Accounting
for Asset Retirement Obligations” (“SFAS 143”). SFAS 143 requires that asset
retirement obligations (“ARO”) be recorded as a liability based on fair value,
which is calculated as the present value of the estimated future cash flows, in
the period in which it is incurred. Management and engineers periodically review
the estimate of ultimate reclamation liability and the expected period in which
reclamation work will be performed. In estimating future cash flows, we consider
the estimated current cost of reclamation and apply inflation rates and a
third-party profit, as necessary. The third-party profit is an estimate of the
approximate markup that would be charged by contractors for work performed on
our behalf. When the liability is initially recorded, the offset is capitalized
by increasing the carrying amount of the related long-lived asset. Over time,
the liability is accreted to its present value each period, and the capitalized
cost is depreciated over the useful life of the related asset. Accretion expense
is included in Cost of produced coal revenue. To settle the liability, the
obligation is paid, and to the extent there is a difference between the
liability and the amount of cash paid, a gain or loss upon settlement is
incurred. Additionally, we perform a certain amount of required reclamation of
disturbed acreage as an integral part of our normal mining process; these costs
are expensed as incurred. See Note 9 for a more complete discussion of our
reclamation liability.
Pension
Plans
We
sponsor a noncontributory defined benefit pension plan covering substantially
all administrative and non-union employees. Our policy is to annually fund the
defined benefit pension plan at or above the minimum amount required by law. We
also sponsor a nonqualified supplemental benefit pension plan for certain
salaried employees, which is unfunded.
63
We account
for our defined benefit pension plans in accordance with SFAS No.
87 “Employers'
Accounting
for Pensions” (“SFAS 87”), which requires the costs of benefits to be
provided to be accrued over the employees’ estimated remaining service life.
These costs are determined on an actuarial basis. SFAS No. 158 “Employer’s
Accounting for Defined Benefit Pension and Other Postretirement Plans, an
amendment of FASB Statements No. 87, 88, 106, and 132(R)” (“SFAS 158”)
amended SFAS 87, and requires
us to recognize the funded status of our benefit plans in our Consolidated
Balance Sheet and to recognize as a component of Accumulated other comprehensive
loss, net of tax, the gains or losses and prior service costs or credits that
arise during the period but are not recognized as components of net periodic
benefit cost. These amounts will be adjusted as they are subsequently recognized
as components of net periodic benefit cost. We adopted SFAS 158 as of December31, 2006. As a result of adoption, we recognized the funded status of the
qualified defined benefit pension plan and the nonqualified supplemental benefit
pension plan in the Consolidated Balance Sheet, decreasing the Pension asset by
$53.2 million for the qualified defined benefit pension plan and increasing
Other noncurrent liabilities by $199,000 for the nonqualified supplemental
benefit pension plan. The $53.4 million, net of the deferred tax effect of $20.8
million, was recorded in Accumulated other comprehensive loss. See Note 5 for a
more complete discussion of our pension plans.
Black
Lung Benefits
We are responsible
under the Federal Coal Mine Health and Safety Act of 1969, as amended, and under
various states’ statutes for the payment of medical and disability benefits to
employees and their dependents resulting from occurrences of black lung. We
provide for federal and state black lung claims principally through a
self-insurance program.
We
account for our accumulated black lung obligations in accordance with SFAS
No. 112 “Employers'
Accounting for Postemployment Benefits—an amendment of FASB Statements No. 5 and
43” (“SFAS 112”), which requires the costs of benefits to be provided to
be accrued over the employees’ estimated remaining service life. These costs are
determined on an actuarial basis. SFAS No. 158 amended SFAS 112, and
requires us to recognize the funded status of our black lung obligations
in our Consolidated Balance Sheet and to recognize as a component of Accumulated
other comprehensive loss, net of tax, the gains or losses and prior service
costs or credits that arise during the period but are not recognized as
components of net periodic benefit cost. We use the service cost
method to account for our self-insured black lung obligation. The liability
measured under the service cost method represents the discounted future
estimated cost for former employees either receiving or projected to receive
benefits, and the portion of the projected liability relative to prior service
for active employees projected to receive benefits. Expense for black lung under
the service cost method represents the service cost, which is the portion of the
present value of benefits allocated to the current year, interest on the
accumulated benefit obligation, and amortization of unrecognized actuarial gains
and losses. We amortize unrecognized actuarial gains and losses over a five-year
period.
We
adopted SFAS 158 as of December 31, 2006. As a result of adoption, we
recognized the accumulated black lung obligation in the Consolidated Balance
Sheet, decreasing the black lung liability by $16.6 million to $53.3 million
($50.3 million in Other noncurrent liabilities and $3.0 million in Other current
liabilities at December 31, 2006). The $16.6 million decrease, net of the
deferred tax of $6.5 million, was recorded in Accumulated other comprehensive
loss. See Note 11 for a more complete discussion of black lung
benefits.
Workers’
Compensation
We are liable
for workers’ compensation benefits for traumatic injuries under state workers’
compensation laws in states in which we have operations. Our operations have
workers’ compensation coverage through a combination of either a self-insurance
program, or commercial insurance through a deductible or first dollar insurance
policy. We record our self-insured liability on a discounted actuarial basis
using various assumptions, including discount rate and future cost trends. See
Note 11 for a more complete discussion of workers’ compensation
benefits.
Postretirement
Benefits Other than Pensions
We sponsor
defined benefit health care plans that provide postretirement medical benefits
to eligible union and non-union members. Postretirement benefits other than
pensions are accounted for in accordance with FAS
No. 106
“Employers'
Accounting for Postretirement Benefits Other Than Pensions” (“SFAS 106”),
which requires the costs of benefits to be provided to be accrued over the
employees’ estimated remaining service life. These costs are determined on an
actuarial basis. SFAS 158 amended SFAS 106, and requires us to
recognize the funded status of our benefit plans in our Consolidated Balance
Sheet and to recognize as a component of Accumulated other comprehensive loss,
net of tax, the gains or losses and prior service costs or credits that arise
during the period but are not recognized as components of net periodic benefit
cost. These amounts will be adjusted as they are subsequently recognized as
components of net periodic benefit cost.
We adopted
SFAS 158 as of December 31, 2006. As a result of adoption, we recognized
the funded status of the postretirement medical benefit plans in the
Consolidated Balance Sheet, increasing Other noncurrent liabilities by $29.4
million. The $29.4 million, net of the deferred tax effect of $11.5 million, was
recorded in Accumulated other comprehensive loss.
64
Under the
Coal Industry Retiree Health Benefits Act of 1992 (the “Coal Act”), coal
producers are required to fund medical and death benefits of certain retired
union coal workers based on premiums assessed by the United Mine Workers of
America (“UMWA”) Benefit Funds. We treat our obligation under the Coal Act as
participation in a multi-employer plan as permitted by EITF No. 92-13,
“Accounting for Estimated Payments in Connection with the Coal Industry Retiree
Health Benefit Act of 1992,” and record the cost of our obligation as expense as
payments are assessed. See Note 10 for a more complete discussion of
postretirement benefits other than pensions.
Stock-based
Compensation
Prior to
2006, we accounted for stock-based compensation using the intrinsic value method
prescribed by Accounting Principles Board Opinion No. 25, “Accounting for Stock
Issued to Employees,” (“APB No. 25”) and related interpretations. On January 1,2006, we adopted FASB Statement No. 123(R), “Share-Based Payments” (“SFAS 123R”)
using the modified-prospective method. The modified-prospective method requires
us to recognize compensation cost of equity instruments based on their
grant-date fair value. Results from prior periods have not been restated. A
cumulative effect of a change in accounting principle of $0.6 million loss (net
of $0.4 million tax) was recognized in 2006 to reflect a change to the fair
value method for those liability awards previously accounted for using the
intrinsic value method and to reflect the impact of estimated forfeitures. We
use the Black-Scholes option-pricing model to determine the fair value of stock
options as of the date of grant and certain liability awards with option
characteristics (i.e., stock appreciation rights, or “SARs”). For periods after
the adoption date, compensation cost for both equity and liability awards have
been measured and recorded in accordance with the provisions of SFAS 123R. The
benefits of tax deductions in excess of recognized compensation cost are
reported as a financing cash flow, rather than as an operating cash flow as
required under previous literature. See Note 12 for a more complete discussion
of stock-based compensation.
Earnings
per Share
The
number of shares used to calculate basic earnings per share is based on the
weighted average number of our outstanding common shares during the respective
periods. The number of shares used to calculate diluted earnings per share is
based on the number of common shares used to calculate basic earnings per share
plus the dilutive effect of stock options and other stock-based instruments held
by our employees and directors during each period and debt securities currently
convertible into our common stock, $0.625 par value (“Common Stock”) during the
period. In accordance with accounting principles generally accepted in the
United States, the effect of dilutive securities in the amount
of 0.01 million, 0.8 million and 2.0 million for the years ended
December 31, 2008, 2007 and 2006, respectively, was excluded from the
calculation of the diluted earnings per common share as such inclusion would
result in antidilution.
65
The
computation for basic and diluted earnings per share is based on the following
per share information:
Income
before cumulative effect of accounting change - numerator for
basic
$
56,248
$
94,098
$
41,616
Cumulative
effect of accounting change, net of tax
-
-
(639
)
Effect
of convertible notes
188
200
-
Net
income - numerator for diluted
$
56,436
$
94,298
$
40,977
Denominator:
Weighted
average shares - denominator for basic
81,816
80,123
80,847
Effect
of stock options/restricted stock
772
207
539
Effect
of convertible notes
307
324
-
Adjusted
weighted average shares - denominator for diluted
82,895
80,654
81,386
Income
per share:
Basic:
Before
cumulative effect of accounting change
$
0.69
$
1.17
$
0.51
Cumulative
effect of accounting change
-
-
(0.01
)
Net
income
$
0.69
$
1.17
$
0.50
Diluted:
Before
cumulative effect of accounting change
$
0.68
$
1.17
$
0.51
Cumulative
effect of accounting change
-
-
(0.01
)
Net
income
$
0.68
$
1.17
$
0.50
Accounting
Pronouncements
In
September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements” (“SFAS
157”). In February 2008, the FASB issued FASB Staff Position 157-2, Partial
Deferral of the Effective Date of SFAS 157, which delayed the effective date of
SFAS 157 for all nonrecurring fair value measurements of nonfinancial assets and
nonfinancial liabilities. We adopted SFAS 157 effective January 1,2008 for financial assets and financial liabilities. The adoption of SFAS
157 for financial assets and liabilities did not have a material impact on our
financial position or results of operations. We do not believe that
the adoption of SFAS 157 for non-financial assets and non-financial liabilities
will significantly impact our financial position and results of
operations. See Note 16 to the Notes to Consolidated Financial
Statements for more information on SFAS 157.
In
October 2008, the FASB issued Staff Position No. FAS 157-3, “Determining the
Fair Value of a Financial Asset When the Market for That Asset is Not Active”
(“FSP 157-3”). FSP 157-3 clarifies the application of SFAS 157 for financial
assets and liabilities in cases where a market is not active. We
determined the guidance provided by FSP 157-3 in its estimation of fair values
as of December 31, 2008 did not have an effect on our results of operations or
financial position.
In
February 2007, the FASB issued SFAS No. 159, “Fair Value Option for Financial
Assets and Liabilities – Including an amendment of FASB Statement No. 115”
(“SFAS 159”). SFAS 159 permits entities to choose to measure certain
financial assets and liabilities at fair value (the “fair value
option”). Unrealized gains and losses, arising subsequent to the
election of the fair value option, are reported in earnings. We
adopted SFAS 159 effective January 1, 2008. We have not elected the
fair value option for existing assets or liabilities upon adoption. Therefore,
the implementation of SFAS 159 did not have an effect on our results of
operations or financial position.
66
In March
2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments
and Hedging Activities—an amendment of FASB Statement No. 133” (“SFAS 161”)
which is effective for fiscal years beginning after November 15, 2008. SFAS 161
amends the disclosure requirements of SFAS No. 133, “Accounting for Derivative
Instruments and Hedging Activities” to provide an enhanced
understanding of how and why derivative instruments are used, how they are
accounted for and their effect on an entity’s financial condition,
performance and cash flows. We adopted SFAS 161 effective January 1, 2009, which
will require additional disclosures to our Consolidated Financial Statements
starting with our Form 10-Q filing for March 31, 2009.
In
May 2008, the FASB issued FASB Staff Position APB 14-1 (“FSP APB 14-1”),
“Accounting for Convertible Debt Instruments That May Be Settled in Cash upon
Conversion (Including Partial Cash Settlement),” which applies to all
convertible debt instruments that have a ‘‘net settlement feature,’’ which means
that such convertible debt instruments, by their terms, may be settled either
wholly or partially in cash upon conversion. FSP APB 14-1 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. FSP APB
14-1 requires that an entity determine the estimated fair value of a similar
debt instrument as of the date of the issuance without the conversion feature
but inclusive of any other embedded features and assign that value to the debt
component of the instrument, which would result in a discount being recorded.
The debt would subsequently be accreted through
interest expense to its par value over its expected life using the market
rate at the date of issuance. The residual value between the initial
proceeds and the value allocated to the debt would be reflected in equity as
additional paid in capital. FSP APB 14-1 is effective for financial statements
issued for fiscal years beginning after December 15, 2008 and interim
periods within those fiscal years. Early adoption is not permitted
and retroactive application to all periods presented is required. FSP
APB 14-1 is applicable to our 3.25% Notes. Due to
the requirement to accrete the debt to its par value, which increases the debt
component on which interest expense is computed, we expect to incur
approximately $18 million of additional, non-cash interest charges in 2009,
increasing to approximately $28 million in 2014.
Saleable
coal represents coal ready for sale, including inventories designated for
customer facilities under consignment arrangements of $50.7 million and $62.1
million at December 31, 2008 and 2007, respectively. Raw coal represents coal
that generally requires further processing prior to shipment to the
customer.
3.
Other Current Assets
Other current
assets are comprised of the following:
Deposits consist
primarily of funds placed in restricted accounts with financial institutions to
collateralize letters of credit that support workers’ compensation requirements,
insurance and other obligations. Deposits at December 31, 2008 included $46.0
million of funds pledged as collateral to support $45.0 million of outstanding
letters of credit. Deposits at December 31, 2007 included $96.0 million of funds
pledged as collateral to support $45.1 million of outstanding letters of credit
and a $50.0 million appeal bond which was used to pay Wheeling-Pittsburgh Steel
Corporation (“Wheeling-Pittsburgh“) during 2008 following the U.S. Supreme Court
decision to not hear our appeal of the matter (see Note 18 to Notes to
Consolidated Financial Statements for additional details). In addition, at
December 31, 2008 and 2007 there were $13.0 million of United States Treasury
securities supporting various regulatory obligations (see Note 6 for further
discussion).
4.
Property, Plant and Equipment
Property,
plant and equipment is comprised of the following:
Mining
properties owned in fee and leased mineral rights
779,932
704,547
Mine
development
1,054,631
863,303
Total
property, plant and equipment
4,373,325
3,649,853
Less
accumulated depreciation, depletion and amortization
(2,075,629
)
(1,855,933
)
Net
property, plant and equipment
$
2,297,696
$
1,793,920
Land,
buildings and equipment includes gross assets under capital leases of $17.3
million at December 31, 2008 and 2007.
During
2008, we exchanged coal reserves and other assets with various third parties,
recognizing a gain in Other revenue of $32.4 million (pre-tax) in accordance
with Statement of Financial Accounting Standards (“SFAS”) No 153, “Exchanges of
Nonmonetary Assets, an Amendment of APB No. 29, Accounting for Nonmonetary
Transactions.” The acquired coal reserves and other assets were recorded in
Property, plant and equipment at the fair value of the reserves and other assets
surrendered.
During
2007, we exchanged coal reserves with a third-party, recognizing a gain in Other
revenue of $10.3 million (pre-tax) in accordance with SFAS No 153. The gain
included a $1.0 million cash payment. The acquired coal reserves were recorded
in Property, plant and equipment at the fair value of the reserves surrendered,
less the $1.0 million payment received.
During
2008 and 2007, we sold and leased-back certain mining equipment in several
transactions for net proceeds of $41.3 million and $13.1 million, respectively.
See Note 13 for further details.
5.
Pension Plans
Defined
Benefit Pension Plans
We sponsor a
qualified non-contributory defined benefit pension plan, which covers
substantially all administrative and non-union employees. Based on a
participant’s entrance date to the plan, the participant may accrue benefits
based on one of four benefit formulas. Two of the formulas provide pension
benefits based on the employee’s years of service and average annual
compensation during the highest five consecutive years of service. The third
formula credits certain eligible employees with flat dollar contributions based
on years of service with Massey and years of service under the UMWA 1974 Pension
Plan. The fourth formula provides benefits under a cash balance formula with
contribution credits based on hours worked. This last formula has a guaranteed
rate of return on contributions of 4% for all contributions after December 31,2003. Funding for the plan is generally at the minimum contribution level
required by applicable regulations. We made voluntary contributions of $0.4
million to the qualified plan during 2007. No contributions were made during
2008.
An
independent trustee holds the plan assets for the qualified defined benefit
pension plan. The plan’s assets include cash and cash equivalents, corporate and
government bonds, preferred and common stocks and an investment in a group
annuity contract. There were no investments in Common Stock held by the plan at
December 31, 2008 or 2007. We have an internal investment committee (“Investment
Committee”) that sets investment policy, selects and monitors investment
managers and monitors asset allocation. Diversification of assets is employed to
reduce risk. The target asset allocation is 65% for equity securities (including
50% domestic and 15% international) and 35% for cash and interest bearing
securities. The investment policy is based on the assumption that the overall
portfolio volatility will be similar to that of the target allocation. Given the
volatility of the capital markets, strategic adjustments in various asset
classes may be required to rebalance asset allocation back to its target policy.
Investment fund managers are not permitted to invest in certain securities and
transactions as outlined by the investment policy statements specific to each
investment category without prior Investment Committee
approval.
68
To develop
the expected long-term rate of return on assets assumption, we considered the
historical returns and the future expectations for returns for each asset class,
as well as the target asset allocation of the pension portfolio. This resulted
in the selection of the 8.0% long-term rate of return on assets assumption for
the year ended December 31, 2008.
The fair
value of the major categories of qualified defined benefit pension plan assets
includes the following:
Other
(includes cash, cash equivalents and a group annuity
contract)
25,080
12.1
%
31,891
11.0
%
Total
fair value of plan assets
$
207,750
100.0
%
$
291,747
100.0
%
In January
2009, the Investment Committee revised the target asset allocation for an
interim period given the recent volatility and uncertainty in the equity
securities markets. The targeted asset allocation for equity securities
was set at 25% of current plan assets, with the balance of plan assets to be
invested in cash, cash equivalents and debt securities. The plan asset
portfolio has been rebalanced consistent with the revised targeted asset
allocation strategy.
In addition
to the qualified defined benefit pension plan noted above, we sponsor a
nonqualified supplemental benefit pension plan for certain salaried employees.
Participants in this nonqualified supplemental benefit pension plan accrue
benefits under the same formula as the qualified defined benefit pension plan,
however, where the benefit is capped by Internal Revenue Service (“IRS”)
limitations, this nonqualified supplemental benefit pension plan compensates for
benefits in excess of the IRS limit. This supplemental benefit pension plan is
unfunded, with benefit payments made by us.
The following
table sets forth the change in benefit obligation, plan assets and funded status
of both the qualified defined benefit pension plan and nonqualified supplemental
benefit pension plan:
Qualified
defined benefit pension plan, included in Pension (obligation)
assets
$
(63,304
)
$
47,323
Nonqualified
supplemental benefit pension plan, included in Other noncurrent
liabilities
(9,074
)
(7,813
)
Accrued
pension (obligation) assets recognized, net
$
(72,378
)
$
39,510
The
nonqualified supplemental benefit pension plan had an accumulated benefit
obligation of $8.6 million and $7.2 million as of December 31, 2008 and 2007,
respectively.
69
The table
below details the changes to Accumulated other comprehensive loss related to
defined benefit pension plans in accordance with SFAS 158:
2008
2007
(In
Thousands)
Net
loss
Prior
service cost
Net
loss
Prior
service cost
January
1 beginning balance
22,482
60
32,821
84
Changes
to Accumulated other comprehensive loss
66,778
(26
)
(10,339
)
(24
)
December
31 ending balance
$
89,260
$
34
$
22,482
$
60
We expect the
estimated net loss and prior service cost for the defined benefit pension plan
that will be amortized from accumulated other comprehensive income into net
periodic benefit cost over the next fiscal year to be $17.0 million and $41,000,
respectively.
The
assumptions used in determining pension benefit obligations for both the
qualified defined benefit pension plan and nonqualified supplemental benefit
pension plan are as follows:
Net
periodic pension expense for both the qualified defined benefit pension plan and
nonqualified supplemental benefit pension plan includes the following
components:
The
assumptions used in determining pension expense for both the qualified defined
benefit pension plan and nonqualified supplemental benefit pension plan are as
follows:
We expect
that contributions will be required in 2009 for the qualified defined benefit
pension plan, estimated to be $10 million. We expect to voluntarily
contribute approximately $300,000 for benefit payments to participants in 2009
for the nonqualified supplemental benefit pension plan.
70
The
following benefit payments from both the qualified defined benefit pension plan
and the nonqualified supplemental benefit pension plan, which reflect expected
future service, as appropriate, are expected to be paid from the
plans:
Benefit
Payments
(In
Thousands)
2009
$
12,421
2010
12,960
2011
13,514
2012
14,360
2013
15,069
Years
2014 to 2018
90,027
Multi-Employer
Pension
Under
labor contracts with the UMWA, certain operations make payments into two
multi-employer defined benefit pension plan trusts established for the benefit
of certain union employees. The contributions are based on tons of coal produced
and hours worked. Such payments aggregated less than $600,000 in the year ended
December 31, 2008, less than $400,000 in the year ended December 31, 2007 and
less than $100,000 in the year ended December 31, 2006.
Defined
Contribution Plan
We
currently sponsor a defined contribution pension plan for certain union
employees. The plan is non-contributory and our contributions are based on hours
worked. Contributions to this plan were approximately $50,000 for the years
ended December 31, 2008 and 2007, and $100,000 for the year ended December 31,2006.
Salary
Deferral and Profit Sharing (401(K)) Plan
We also
sponsor a salary deferral and profit sharing plan covering substantially all
administrative and non-union employees. The maximum salary deferral rate is 75%
of eligible pay, subject to IRS limitations. We contribute a fixed
match on employee contributions on up to 10% of eligible pay. Our contributions
aggregated approximately $4.6 million, $3.6 million and $3.9 million for the
years ended December 31, 2008, 2007 and 2006, respectively.
The
weighted average effective interest rate of the outstanding borrowings was 5.2%
and 7.0% at December 31, 2008 and 2007, respectively, after giving effect to the
amortization of the Fair value hedge adjustment.
71
Financing
Transactions
On August 5,2008, we commenced a consent solicitation and tender offer for any and all of
the outstanding $335 million of 6.625% Notes and concurrently we commenced
registered underwritten public offerings of convertible senior notes (the 3.25%
Notes) and shares of Common Stock and announced our intention to use the
proceeds of the offerings to purchase some or all of the 6.625% Notes in the
tender offer and for general corporate purposes.
On August 19,2008, we settled with holders of $311.5 million of the 6.625% Notes,
representing approximately 93% of the outstanding 6.625% Notes, who tendered
their 6.625% Notes pursuant to our consent solicitation and tender offer for the
6.625% Notes. The total consideration for these 6.625% Notes was $1,026.57 per
$1,000 principal amount of the 6.625% Notes. The total consideration included a
consent payment of $25 per $1,000 principal amount of the 6.625% Notes. In
addition to the total consideration, holders also received interest which was
accrued and unpaid since the previous interest payment date.
As a result
of the consents of approximately 93% of the outstanding 6.625% Notes, we
received the requisite consents to execute a supplemental indenture relating to
the 6.625% Notes, which eliminated substantially all of the restrictive
covenants in the 6.625% Notes’ indenture.
On September3, 2008, we settled with holders of an additional $1.6 million of the 6.625%
Notes, who tendered their 6.625% Notes after the consent solicitation deadline.
The total consideration for these 6.625% Notes was $1,001.57 per $1,000
principal amount of the 6.625% Notes. In addition to the total consideration,
holders also received interest which was accrued and unpaid since the previous
interest payment date.
We recognized
charges totaling $15.2 million, including $1.9 million for the write-off of
unamortized financing fees and $4.2 million for the unamortized interest rate
swap termination payment (as discussed below) recorded in Interest expense, and
$9.1 million for the debt consent solicitation and tender offer recorded in Loss
on financing transactions.
6.875%
Notes
The
6.875% Notes are unsecured obligations ranking equally with all other unsecured
senior indebtedness of ours and are guaranteed by substantially all of our
current and future subsidiaries, (the “Guarantors”). Interest on the 6.875%
Notes is payable on December 15 and June 15 of each year. We may redeem the
6.875% Notes, in whole or in part, for cash at any time on or after December 15,2009 at a redemption price equal to 100% of the principal amount plus a premium
declining ratably to par, plus accrued and unpaid interest. The guarantees are
full and unconditional obligations of the Guarantors and are joint and several
among the Guarantors. The subsidiaries not providing a guarantee of the 6.875%
Notes are minor (as defined under SEC Rule 3-10(h)(6) of Regulation
S-X).
The
6.875% Notes contain a number of significant restrictions and covenants that
limit our ability and our subsidiaries’ ability to, among other things: (i)
incur liens and debt or provide guarantees in respect of obligations of any
other person; (ii) increase Common Stock dividends above specified levels; (iii)
make loans and investments; (iv) prepay, redeem or repurchase debt; (v) engage
in mergers, consolidations and asset dispositions; (vi) engage in affiliate
transactions; (vii) create any lien or security interest in any real property or
equipment; (viii) engage in sale and leaseback transactions; and (ix) restrict
distributions from subsidiaries. We are currently in compliance with all
covenants.
3.25%
Notes
On August 12,2008, we issued $690 million of 3.25% convertible senior notes due 2015 in a
registered underwritten public offering, resulting in net proceeds to us of
approximately $674.1 million. The 3.25% Notes are guaranteed on a senior
unsecured basis by the Guarantors. The subsidiaries not providing a guarantee of
the 3.25% Notes are minor (as defined under SEC Rule 3-10(h)(6) of Regulation
S-X). The guarantees are full and unconditional obligations of the Guarantors
and are joint and several among the Guarantors. The 3.25% Notes and the
guarantees rank equally with all of our and the Guarantors’ existing and future
senior unsecured indebtedness and rank senior to all of our and the Guarantors’
indebtedness that is expressly subordinated to the 3.25% Notes and the
guarantees, but are effectively subordinated to all of our and the Guarantors’
existing and future senior secured indebtedness to the extent of the value of
the assets securing the indebtedness and to all liabilities of our subsidiaries
that are not Guarantors.
The 3.25%
Notes bear interest at a rate of 3.25% per annum, payable semi-annually in
arrears on August 1 and February 1 of each year, beginning on February 1, 2009.
The 3.25% Notes will mature on August 1, 2015, unless earlier repurchased by us
or converted.
72
The 3.25%
Notes are convertible in certain circumstances during certain periods at an
initial conversion rate of 11.4106 shares of Common Stock per $1,000 principal
amount of 3.25% Notes (which represented an initial conversion price of
approximately $87.64 per share), subject to adjustment in certain
circumstances.
The 3.25%
Notes are convertible under certain circumstances and during certain periods
into (i) cash, up to the aggregate principal amount of the 3.25% Notes
subject to conversion and (ii) cash, shares of Common Stock or a
combination thereof, at our election in respect to the remainder (if any) of our
conversion obligation. Subject to earlier repurchase, the 3.25% Notes
will be convertible only in the following circumstances and to the following
extent:
·
during
any calendar quarter, if the closing sale price of our shares of Common
Stock for each of 20 or more trading days in a period of 30 consecutive
trading days ending on the last trading day of the immediately preceding
calendar quarter exceeds 130% of the conversion price in effect on the
last trading day of the immediately preceding calendar
quarter;
·
during
the five consecutive business days immediately after any five consecutive
trading day period (the “note measurement period”) in which the average
trading price per $1,000 principal amount of 3.25% Notes was equal to or
less than 97% of the average conversion value of the 3.25% Notes during
the note measurement period;
·
if
we make certain distributions on our shares of Common Stock or engage in
certain transactions; and
·
at
any time from, and including, February 1, 2015 until the close of business
on the second business day immediately preceding August 1,2015.
None of the
3.25% Notes are currently eligible for conversion.
The indenture
governing the 3.25% Notes contains customary terms and covenants, including that
upon certain events of default occurring and continuing, either the trustee for
the 3.25% Notes or the holders of not less than 25% in aggregate principal
amount of the 3.25% Notes then outstanding may declare the unpaid principal of
the 3.25% 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 us, the principal amount of the 3.25% Notes together
with any accrued and unpaid interest thereon will automatically become and be
immediately due and payable.
Open
Market Debt Repurchase
On November6, 2008, we concluded an open market purchase, retiring $19.0 million of
principal amount of the 3.25% Notes at a cost of $10.4 million, plus accrued
interest resulting in a gain of $8.6 million recorded in Loss on financing
transactions.
6.625%
Notes
The 6.625%
senior notes due 2010 are unsecured obligations of ours and rank equally with
all other unsecured senior indebtedness. Interest is payable semiannually on May
15 and November 15 of each year. We may redeem the 6.625% Notes, in whole or in
part, at any time on or after November 15, 2007 at a redemption price equal to
100% of the principal amount plus a premium declining ratably to par, plus
accrued and unpaid interest. The 6.625% Notes are guaranteed by the Guarantors.
The guarantees are full and unconditional obligations of the Guarantors and are
joint and several among the Guarantors. The subsidiaries not providing a
guarantee of the 6.625% Notes are minor (as defined under SEC Rule 3-10(h)(6) of
Regulation S-X).
2.25% Notes
The 2.25%
convertible senior notes due 2024 are unsecured obligations of ours, rank
equally with all other unsecured senior indebtedness and are guaranteed by the
Guarantors. The guarantees are full and unconditional obligations of the
Guarantors and are joint and several among the Guarantors. The subsidiaries not
providing a guarantee of the 2.25% Notes are minor (as defined under SEC Rule
3-10(h)(6) of Regulation S-X). Interest is payable semiannually on April 1 and
October 1 of each year. We registered the 2.25% Notes with the SEC for
resale.
Holders of
the 2.25% Notes may require us to purchase all or a portion of their notes for
cash on April 1, 2011, 2014, and 2019, at a purchase price equal to 100% of the
principal amount of the notes to be redeemed, plus any accrued and unpaid
interest. In addition, if we experience certain specified types of fundamental
changes on or before April 1, 2011, the holders may require us to purchase the
notes for cash. We may redeem all or a portion of the 2.25% Notes for cash at
any time on or after April 6, 2011, at a redemption price equal to 100% of the
principal amount of the notes to be redeemed, plus any accrued and unpaid
interest.
73
The 2.25%
Notes are convertible during certain periods by holders into shares of Common
Stock initially at a conversion rate of 29.7619 shares of Common Stock per
$1,000 principal amount of 2.25% Notes (subject to adjustment upon certain
events) under the following circumstances: (i) if the price of Common Stock
issuable upon conversion reaches specified thresholds; (ii) if we redeem the
2.25% Notes; (iii) upon the occurrence of certain specified corporate
transactions; or (iv) if the credit ratings assigned to the 2.25% Notes decline
below certain specified levels. Regarding the thresholds in (i) above, holders
may convert each of their notes into shares of Common Stock during any calendar
quarter (and only during such calendar quarter) if the last reported sale price
of Common Stock for at least 20 trading days during the period of 30 consecutive
trading days ending on the last trading day of the previous calendar quarter is
greater than or equal to 120% of the conversion price per share of Common Stock.
The conversion price is $33.60 per share. None of the 2.25% Notes are currently
eligible for conversion. As of December 31, 2008, if all of the notes
outstanding were eligible and were converted, we would have needed to issue
287,113 shares of Common Stock.
4.75%
Notes
The 4.75%
convertible senior notes due 2023 are unsecured obligations of ours, rank
equally with all other unsecured senior indebtedness and are guaranteed by our
wholly owned subsidiary, A.T. Massey, which together with our subsidiaries
accounts for substantially all of our assets and all of our revenues. Interest
is payable semiannually on May 15 and November 15 of each year. We registered
the 4.75% Notes with the SEC for resale.
We may be
required by the holders of the 4.75% Notes to purchase all or a portion of their
notes on May 15, 2009, 2013, and 2018. For purchases on May 15, 2009, we must
pay cash for all 4.75% Notes so purchased. For purchases on May 15, 2013 or
2018, we may, at our option, choose to pay the purchase price for such 4.75%
Notes in cash, in shares of Common Stock or any combination thereof. We may
redeem some or all of the 4.75% Notes at any time on or after May 20, 2009, at a
redemption price equal to 100% of the principal amount of the notes to be
redeemed, plus any accrued and unpaid interest.
The 4.75%
Notes are convertible during certain periods by holders into shares of Common
Stock initially at a conversion rate of 51.573 shares of Common Stock per $1,000
principal amount of 4.75% Notes (subject to adjustment upon certain events)
under the following circumstances: (i) if the price of Common Stock issuable
upon conversion reaches specified thresholds; (ii) if we redeem the 4.75% Notes;
(iii) upon the occurrence of certain specified corporate transactions; or (iv)
if the credit ratings assigned to the 4.75% Notes decline below specified
levels. Regarding the thresholds in (i) above, holders may convert each of their
notes into shares of Common Stock during any calendar quarter (and only during
such calendar quarter) if the last reported sale price of Common Stock for at
least 20 trading days during the period of 30 consecutive trading days ending on
the last trading day of the previous calendar quarter is greater than or equal
to 120% of the conversion price per share of Common Stock. The conversion price
is $19.39 per share.
As of December 31, 2008, the price of
Common Stock had not reached the specified threshold for conversion. As of
December 31, 2008, if all of the notes outstanding were eligible and were
converted, we would have needed to issue 3,610 shares of Common
Stock.
In June
2008, $660,000 of principal amount of the 4.75% Notes was converted into 34,037
shares of Common Stock. No other conversions occurred during the
year.
Fair
Value Hedge Adjustment
On
December 9, 2005, we exercised our right to terminate our interest rate swap
agreement, which was designated as a hedge against a portion of the 6.625%
Notes. We paid a $7.9 million termination payment to the swap counterparty on
December 13, 2005. The termination payment, which is reflected in the table
above at December 31, 2007, as Fair value hedge adjustment, was being amortized
into Interest expense through November 15, 2010, the maturity date of the 6.625%
Notes. As discussed in this Note under Financing Transactions above, on August19, 2008, we settled with holders of approximately 93% of the outstanding 6.625%
Notes that were tendered pursuant to our consent solicitation and tender offer
for the 6.625% Notes. As a result of the acceptance of the consent
solicitation and tender offer of the 6.625% Notes, the remaining balance of the
Fair value hedge adjustment of $4.2 million was written off to Interest
expense. For the twelve months ended December 31, 2008, $5.1 million
of the Fair value hedge adjustment was recorded in Interest
expense.
74
Asset-Based
Lending Arrangement
On August15, 2006, we entered into an amended and restated asset-based revolving credit
facility, which provides for available borrowings, including letters of credit
of up to $175 million, depending on the level of eligible inventory and accounts
receivables. As of December 31, 2008, this facility supported $75.5 million of
letters of credit and there were no outstanding borrowings under this facility.
Any future borrowings under this facility will be variable rate borrowings,
based on the applicable LIBOR rate for the specified rate reset period,
plus an applicable margin. As of December 31, 2008, the applicable margin to
LIBOR was 125 basis points.
The
facility is secured by our accounts receivable, eligible coal inventories
located at our facilities and on consignment at customers’ facilities, and other
intangibles. At December 31, 2008, total remaining availability was $99.5
million based on qualifying inventory and accounts receivable. The credit
facility expires on May 15, 2010; however if the 6.625% Notes have been
refinanced, defeased, or paid in full by May 15, 2010, the expiration date is
extended to August 15, 2011.
This facility contains a number of
significant restrictions and covenants that limit our ability to, among other
things: (i) incur liens and debt or provide guarantees in respect of obligations
of any other person; (ii) increase Common Stock dividends above specified
levels; (iii) make loans and investments; (iv) prepay, redeem or repurchase
debt; (v) engage in mergers, consolidations and asset dispositions; (vi) engage
in affiliate transactions; (vii) create any lien or security interest in any
real property or equipment; (viii) engage in sale and leaseback transactions;
and (ix) make distributions from subsidiaries. This facility also contains
financial covenants, which become operative only when our Average Excess
Availability (as defined in the facility documents) is less than $30
million. These financial covenants include a Minimum Consolidated
Fixed Charge Ratio of 1.00 to 1.00 and a minimum Consolidated Net Worth of $550
million under the terms of the ABL Facility (currently
approximately $400 million as adjusted for Accounting
Changes). We
are currently in compliance with all covenants.
Debt
Maturity
The
aggregate amounts of scheduled long-term debt maturities assuming convertible
notes are not eligible for conversion, including capital lease obligations,
subsequent to December 31, 2008 are as follows:
(In
Thousands)
2009
$
1,976
2010
24,167
2011
2,670
2012
13
2013
760,012
Beyond
2013*
680,740
__________________________
*
The
4.75% Notes and the 2.25% Notes in the amounts of $0.1 million and $9.6
million, respectively, included herein may be redeemed at the option of
the holders in 2009 and 2011,
respectively.
Total
interest paid for the years ended December 31, 2008, 2007 and 2006, was $114.2
million, $75.7 million and $75.0 million, respectively.
Off-Balance
Sheet Arrangements
In the
normal course of business, we are a party to certain off-balance sheet
arrangements including 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 the consolidated balance sheets, and, except
for the operating leases, which are discussed in Note 13 to the Notes to
Consolidated Financial Statements, we do not expect any material impact on our
cash flows, results of operations or financial condition to result from these
off-balance sheet arrangements.
From time
to time we use bank letters of credit to secure our obligations for worker’s
compensation programs, various insurance contracts and other obligations. At
December 31, 2008, we had $120.5 million of letters of credit outstanding of
which $45.0 million was collateralized by $46.0 million of cash deposited in
restricted, interest bearing accounts pledged to issuing banks and $75.5 million
was issued under our asset based lending arrangement. No claims were outstanding
against those letters of credit as of December 31, 2008.
On
January 22, 2008, a settlement was reached regarding our previously reported
disagreement and protest of a new actuarial methodology being applied by the
Office of Workers’ Claims (“OWC”) for the Commonwealth of Kentucky in
determining levels of surety against potential future claims. The settlement
resulted in the dismissal of our cases pending in the Franklin County Circuit
Court of Kentucky and required us to post additional surety of $11.5 million for
the 2006 and 2007 assessments against potential claims. That additional surety
requirement was satisfied with the posting of a letter of credit issued under
our asset-based lending arrangement.
75
We use
surety bonds to secure reclamation, workers’ compensation, wage payments, and
other miscellaneous obligations. As of December 31, 2008, we had $330.2 million
of outstanding surety bonds. These bonds were in place to secure obligations as
follows: post-mining reclamation bonds of $321.1 million and other miscellaneous
obligation bonds of $9.1 million. Outstanding surety bonds of $46.1 million are
secured with letters of credit. In addition, in December 2008, a $50.0 million
appeal bond in the Wheeling-Pittsburgh legal matter was used to pay the
plaintiff following the U.S. Supreme Court decision to not hear our appeal of
the matter (see Note 18 to Notes to Consolidated Financial Statements for
additional details).
Generally,
the availability and market terms of surety bonds continue to be challenging. If
we are unable to meet certain financial tests applicable to some of our surety
bonds, or to the extent that surety bonds otherwise become unavailable, we would
need to replace the surety bonds or seek to secure them with letters of credit,
cash deposits, or other suitable forms of collateral.
7.
Income Taxes
Income
tax expense included in the Consolidated Statements of Income is as
follows:
Non-deductible refinancing and exchange offer costs
-
(4,809
)
-
Extraterritorial excluded income
-
-
(797
)
Valuation allowance adjustment
28,098
31,343
16,066
Uncertain tax positions
-
(2,325
)
(1,197
)
Alternative minimum tax credit refund, net of adjustment
(4,770
)
-
-
Refund from settlement of 2001 IRS audit
-
(4,609
)
-
Other, net
(1,661
)
(4,677
)
(263
)
Income
tax expense
$
4,085
$
35,405
$
3,408
76
Deferred
taxes reflect the tax effects of differences between the amounts recorded as
assets and liabilities for financial reporting purposes and the amounts recorded
for income tax purposes. The tax effects of temporary differences giving rise to
deferred tax assets and liabilities are as follows:
Total deferred tax assets, net of valuation allowance
303,423
250,651
Deferred
tax liabilities:
Plant,
equipment and mine development
(273,878
)
(275,362
)
Mining
property and mineral rights
(131,308
)
(117,609
)
Deferred
royalties
(9,863
)
(10,339
)
Other
(5,642
)
(2,046
)
Total deferred tax liablities
(420,691
)
(405,356
)
Deferred
income taxes
$
(117,268
)
$
(154,705
)
Deferred
tax assets include alternative minimum tax (“AMT”) credits of $104.8 million and
$119.7 million at December 31, 2008 and 2007, respectively, federal net
operating loss carryforwards of $331.1 million and $281.2 million as of December31, 2008 and 2007, respectively, and net state net operating loss (“NOL”)
carryforwards of $627.1 million and $704.8 million as of December 31, 2008 and
2007, respectively. The AMT credits have no expiration date. Federal NOL
carryforwards expire beginning in 2018 and ending in 2023. State NOL
carryforwards expire beginning in 2008 and ending in 2023. The NOL
carryforwards available at December 31, 2008 increased over the amount available
at the end of the prior year primarily due to 2008 taxable losses.
We have
recorded a valuation allowance for a portion of deferred tax assets that
management believes, more likely than not, will not be realized. These deferred
tax assets include AMT credits, federal NOL and state NOL carryforwards that
will likely not be realized at the maximum effective tax rate. The
valuation allowance increased for the year ended December 31, 2008 primarily as
a result of the increase in federal NOL carryforwards discussed
above.
In June
2006, the FASB issued Interpretation No. 48, “Accounting for Uncertainty in
Income Taxes – an interpretation of FASB Statement No. 109” (“FIN 48”) to create
a single model to address accounting for uncertainty in income tax positions.
FIN 48 clarifies the accounting for income taxes by prescribing a minimum
recognition threshold that a tax position is required to meet before being
recognized in the financial statements. FIN 48 also provides guidance on
derecognition, measurement, classification, interest and penalties, accounting
in interim periods, disclosure and transition. We increased Retained earnings by
$5.2 million for the cumulative effect of adoption of FIN 48 as of January 1,2007. We accrue interest and penalties, if any, related to unrecognized tax
benefits in Other noncurrent liabilities and recognize the related expense in
Income tax expense. We accrued $0.8 million and $3.1 million in
interest related to unrecognized tax benefits for the years December 31,2008 and 2007, respectively.
77
The
following table reconciles the total amount of unrecognized tax benefits,
including those identified in 2007 related to the disallowed ten-year carryback
claims:
2008
2007
(In
Thousands)
Balance
at January 1
$
-
$
2,325
Additions
based on tax positions related to the current year
-
-
Additions
for tax positions of prior years
-
49,130
Reductions
for tax positions of prior years
-
(2,325
)
Settlements
-
(49,130
)
Reductions
due to lapse of applicable statute of limitations
-
-
Balance
at December 31
$
-
$
-
Prior to
the adoption of FIN 48, we followed a methodology of establishing reserves for
tax contingencies when, despite the belief that our tax return positions were
fully supported, certain positions were likely to be challenged and might not be
fully sustained. We establish the reserves based upon management’s assessment of
exposure associated with permanent tax differences (i.e., tax depletion
expense), tax credits and interest expense applied to temporary difference
adjustments. The tax reserves were analyzed at least annually and adjustments
were made based upon changes in facts and circumstances, such as the progress of
federal and state audits, case law and emerging legislation. During 2006, we
reduced our tax reserve by $1.2 million, reflecting the reduction in exposure
due to the notification of no exceptions from the IRS of a prior statutory
period, partially offset by additional exposures identified for that tax year.
Payments for federal taxes and state taxes of $63,000 were applied against the
reserve during the year ended December 31, 2006, as a result of audits of prior
periods.
We file
income tax returns in the United States federal and various state jurisdictions,
including West Virginia, Kentucky and Virginia. The Internal Revenue Service
(“IRS”) has examined our federal income tax returns, or statutes of limitations
have expired for years through 2004. In the various states where we file state
income tax returns, the state tax authorities have examined our state returns,
or statutes of limitations have expired through 2004. Management
believes that we have adequately provided for any income taxes that may
ultimately be paid with respect to all open tax years. All unrecognized tax
benefits would affect the effective tax rate if we were to recognize
them.
8.
Other Noncurrent Liabilities
Other
noncurrent liabilities are comprised of the following:
Our
reclamation liabilities primarily consist of spending estimates related to
reclaiming surface land and support facilities at both surface and underground
mines in accordance with federal and state reclamation laws as defined by each
mine permit. The obligation and corresponding asset are recognized in the period
in which the liability is incurred.
We
estimate our ultimate reclamation liability based upon detailed engineering
calculations of the amount and timing of the future cash flows to perform the
required work. We consider the estimated current cost of reclamation and apply
inflation rates and a third-party profit, as necessary. The third-party profit
is an estimate of the approximate markup that would be charged by contractors
for work performed on our behalf. The discount rate applied is based on the
rates of treasury bonds with maturities similar to the estimated future cash
flow, adjusted for our credit standing.
78
The
following table describes all changes to our reclamation
liability:
Total
reclamation, included in Other noncurrent liabilities
$
154,823
$
142,213
10.
Other Postretirement Benefits
We
sponsor defined benefit health care plans that provide postretirement medical
benefits to eligible union and non-union employees. To be eligible, retirees
must meet certain age and service requirements. Depending on year of retirement,
benefits may be subject to annual deductibles, coinsurance requirements,
lifetime limits and retiree contributions. Service costs are accrued currently
based on an annual study prepared by independent actuaries. These plans are
unfunded.
Net
periodic postretirement benefit cost includes the following
components:
The
discount rate assumed to determine the net periodic postretirement benefit cost
was 6.50%, 5.90% and 5.75% for the years ended December 31, 2008, 2007 and 2006,
respectively.
The
following table sets forth the change in benefit obligation of our
postretirement benefit plans:
*
8.5% represents the initial trend rate for pre-medicare claims, 8.8% for
medicare-eligible, and
7.0%
for the medicare supplement plan
Assumed
health care cost trend rates have a significant effect on the amounts reported
for the medical plans. A one-percentage point change in assumed health care cost
trend rates would have the following aggregate effects:
1-Percentage
Point Increase
1-Percentage
Point Decrease
(In
Thousands)
Effect
on total of service and interest costs components
$
2,020
$
(1,626
)
Effect
on accumulated postretirement benefit obligation
$
25,502
$
(20,896
)
80
The following benefit
payments, which reflect expected future service, as appropriate, are expected to
be paid in the periods noted:
Expected
Benefit Payments
(In
Thousands)
2009
$
7,102
2010
7,835
2011
8,671
2012
9,313
2013
10,057
Years
2014 to 2018
55,528
Multi-Employer
Benefits
Under the
Coal Act, coal producers are required to fund medical and death benefits of
certain retired union coal workers based on premiums assessed by the UMWA
Benefit Funds. Based on available information at December 31, 2008, our
obligation under the Coal Act was estimated at approximately $19.2 million,
compared to our estimated obligation at December 31, 2007 of $19.8 million. The
obligation was discounted using a 5.00% rate each year. We treat our obligation
under the Coal Act as participation in a multi-employer plan and record the cost
of our obligation as expense as payments are assessed. The expense related to
this obligation for the years ended December 31, 2008, 2007 and 2006 totaled
$2.3 million, $1.3 million and $4.3 million, respectively. The $1.3 million
expense in 2007 was net of a $1.6 million refund from the UMWA Combined Benefit
Fund (“CBF”). The refund was a result of the Tax Relief and Retiree Health Care
Act of 2006 (“TRRHCA”) enacted on December 20, 2006, which is detailed
below.
The
TRRHCA included important changes to the Coal Act that impacts all companies
required to contribute to the CBF. Effective October 1, 2007, the Social
Security Administration (“SSA”) revoked all beneficiary assignments made to
companies that did not sign a 1988 UMWA contract (“reachback companies”) but
their premium relief is phased-in. The reachback companies paid their full
premium obligation in the current plan year that ended September 30, 2007.
However, they paid only 55% of their plan year 2008 assessed premiums. They will
pay only 40% of their plan year 2009 assessed premiums and 15% of their plan
year 2010 assessed premiums. General United States Treasury money will be
transferred to the CBF to make up the difference. After 2010, reachback
companies will have no further obligations to the CBF, and transfers from the
United States Treasury will cover all of the health care costs for retirees and
dependents previously assigned to reachback companies. Some of our subsidiaries
are considered reachback companies under the TRRHCA.
11.
Workers’ Compensation and Black Lung Benefits
Workers’
compensation and black lung benefit obligation consisted of the
following:
Total
accrued workers' compensation and black lung
114,911
112,200
Less
amount included in Other current liabilities
21,929
21,498
Workers'
compensation & black lung in Other noncurrent
liabilities
$
92,982
$
90,702
The
amount of workers' compensation (traumatic liability) related to self-insurance
was $59.1 million and $56.7 million at December 31, 2008 and 2007, respectively.
Weighted average actuarial assumptions used in the determination of the
self-insured portion of workers’ compensation (traumatic injury) liability
included a discount rate of 5.00% at December 31, 2008 and 2007, and the
accumulated black lung obligation included a discount rate of 6.10% and 6.50% at
December 31, 2008 and 2007, respectively.
81
A
reconciliation of changes in the self-insured black lung obligation is as
follows:
Payments for
benefits, premiums and other costs related to black lung and workers’
compensation liabilities were $24.0 million, $29.6 million and $33.2 million for
the years ended December 31, 2008, 2007 and 2006, respectively.
The actuarial
assumptions used in the determination of self-insured black lung benefits
expense included discount rates of 6.50%, 5.90% and 5.75% for the years ended
December 31, 2008, 2007 and 2006, respectively.
Our
self-insured black lung obligation is calculated using assumptions regarding
future medical cost increases and cost of living increases. Federal black lung
benefits are subject to cost of living increases. State benefits increase only
until disability, and then remain constant. We assume a 6.50% annual medical
cost increase and a 3.0% cost of living increase in determining our black lung
obligation and the annual black lung expense. Assumed medical cost and cost of
living increases significantly affect the amounts reported for our black lung
expense and obligation. A one-percentage point change in each of assumed medical
cost and cost of living trend rates would have the following
effects:
1-Percentage
Point Increase
1-Percentage
Point Decrease
Increase/decrease
in medical cost trend rate:
Effect
on total of service and interest costs components
$
183
$
(145
)
Effect
on accumulated black lung obligation
$
1,376
$
(1,119
)
Increase/decrease
in cost of living trend rate:
Effect
on total service and interest cost components
$
696
$
(558
)
Effect
on accumulated black lung obligation
$
5,548
$
(4,537
)
82
The
following benefit payments, which reflect expected future service, as
appropriate, are expected to be paid related to the self-insured black lung
obligation:
Expected
Benefit Payments
(In
Thousands)
2009
$
2,867
2010
3,024
2011
3,181
2012
3,332
2013
3,478
Years
2014 to 2018
19,412
12.
Stock Plans
We have stock
incentive plans to encourage employees and nonemployee directors to remain with
the Company and to more closely align their interests with those of our
shareholders.
Description
of Stock Plans
The Massey
Energy Company 2006 Stock and Incentive Compensation Plan (the “2006 Plan”),
which was approved by our shareholders and became effective on June 28, 2006
replaces the five stock-based compensation plans (the “Prior Plans”) we had in
place prior to the approval of the 2006 Plan, all of which had been approved by
our shareholders. The Prior Plans include the following:
·
Massey
Energy Company 1996 Executive Stock Plan, as amended and restated
effective November 30, 2000 (the “1996
Plan”),
·
Massey
Energy Company 1997 Stock Appreciation Rights Plan, as amended and
restated effective November 30, 2000 (the “SAR
Plan”),
·
Massey
Energy Company 1999 Executive Performance Incentive Plan, as amended and
restated effective November 30, 2000 (the “1999
Plan”),
·
Massey
Energy Company Stock Plan for Non-Employee Directors, as amended and
restated effective May 24, 2005 (the “1995 Plan”),
and
·
Massey
Energy Company 1997 Restricted Stock Plan for Non-Employee Directors, as
amended and restated effective May 24, 2005 (the “1997
Plan”).
Stock-based
compensation has been granted under the 2006 Plan and the Prior Plans in the
manner described below. Issued and outstanding stock-based compensation has been
granted to officers and certain key employees in accordance with the provisions
of the 1996 Plan, the SAR Plan, the 1999 Plan, and the 2006 Plan. Issued and
outstanding stock-based compensation has been granted to non-employee directors
in accordance with the provisions of the 1995 Plan, the 1997 Plan and the 2006
Plan. The Compensation Committee of the Board of Directors administers the 1996
Plan, the 1999 Plan, the SAR Plan and the 2006 Plan. A committee comprised of
non-participating board members administers the 1995 Plan and the 1997
Plan.
The 1996 Plan
provided for grants of stock options and restricted stock. The 1999 Plan
provided for grants of stock options, restricted stock, incentive awards and
stock units. The SAR Plan provided for grants of SARs. The 1995 Plan provided
for grants of restricted stock and restricted units. The 1997 Plan provided for
grants of restricted stock. As of June 28, 2006, grants can no longer be made
under the Prior Plans, except for the 1996 Plan, under which grants could no
longer be made as of March 2, 2006. All awards previously granted that are
outstanding under the Prior Plans will remain effective in accordance with the
terms of their grant.
The aggregate
number of shares of Common Stock that may be issued for future grant under the
2006 Plan as of December 31, 2008 was 1,362,752 shares, which was computed as
the 3,500,000 shares specifically authorized in the 2006 Plan, less grants made
in 2006, 2007 and 2008, plus the number of shares that (i) were represented by
restricted stock or unexercised vested or unvested stock options that previously
have been granted and were outstanding under the Prior Plans as of June 28, 2006
and (ii) expire or otherwise lapse, are terminated or forfeited, are settled in
cash, or are withheld or delivered to us for tax purposes at any time after June28, 2006. The 2006 Plan provides for grants of stock options, SARs, restricted
stock, restricted units, unrestricted stock and incentive awards.
83
Although we have not
expressed any intent to do so, we have the right to amend, suspend, or terminate
the 2006 Plan at any time by action of our board of directors. However, no
termination, amendment or modification of the 2006 Plan shall in any manner
adversely affect any award theretofore granted under the 2006 Plan, without the
written consent of the participant. If a change in control were to occur (as
defined in the plan documents), certain options may become immediately vested,
but only upon termination of the option holder’s service.
Accounting
for Stock-Based Compensation
Total
compensation expense recognized for stock-based compensation during the year
ended December 31, 2008, 2007 and 2006 was $10.5 million, $19.2 million and $7.3
million, respectively. The total income tax benefit recognized in the
consolidated statement of income for share based compensation arrangements
during the year ended December 31, 2008, 2007 and 2006 was approximately $4.1
million, $7.5 million and $2.8 million, respectively. We recognize compensation
expense on a straight-line basis over the vesting period for the entire award
for any awards with graded vesting.
As a result
of adopting FAS 123R, we recognized non-cash stock-based compensation expense
for stock options of approximately $6.1 million (pre-tax) in Selling, general
and administrative expense for the year ended December 31, 2006. The total
income tax benefit recognized on this compensation expense was approximately
$2.4 million. Income before income taxes, Net income and Earnings per share for
the year ended December 31, 2006 were $6.1 million, $3.7 million and $0.05
lower, respectively, than if we had continued to account for share-based
compensation under APB No. 25. As of December 31, 2008 and 2007, there was $8.4
million and $11.1 million, respectively, of total unrecognized compensation cost
related to stock options expected to be recognized over a weighted-average
period of approximately 1.8 years. In the years ended December 31, 2008 and
2007, we also reflected ($1.2) million and $0.4 million, respectively, of excess
tax benefits (expenses) as a financing cash flow in the consolidated statement
of cash flows resulting from the exercise of stock options.
Equity
instruments
We have
granted stock options to employees under the 2006 Plan, the 1999 Plan and the
1996 Plan. These options typically have a requisite service period of three to
four years, though there are some awards outstanding with requisite service
periods of one year up to four years. Vesting generally occurs ratably over the
requisite service period. The maximum contractual term of stock options granted
is 10 years.
We value
stock options using the Black-Scholes valuation model, which employs certain key
assumptions. We estimate volatility using both historical and market data over
the term of the options granted. The dividend yield is calculated on the current
annualized dividend payment and the stock price at the date of grant. The
expected option life is based on historical data and exercise behavior. The
risk-free interest rate is based on the zero-coupon Treasury bond rate in effect
at the date of grant. The fair value of options granted during the three years
ended December 31, 2008, 2007 and 2006 was calculated using the following
assumptions:
Years
Ended December 31,
Options
Granted
2008
2007
2006
Number
of shares underlying options
798,647
556,979
642,434
Contractual
term in years
10
10
10
Assumptions
used to estimate fair value:
Expected
volatility
50%
- 100%
46%
- 50%
46%
- 55%
Weighted
average volatility
71%
50%
46%
Expected
option life in years
1.3
- 4.3
1.2
- 4.3
1.2
- 5.0
Dividend
yield
0.4%
- 1.5%
0.6%
- 0.7%
0.4%
- 0.7%
Risk-free
interest rate
0.9%
- 3.1%
3.0%
- 4.7%
4.2%
- 4.8%
Weighted-average
fair value estimates at grant date:
In
thousands
$
6,820
$
5,542
$
5,192
Fair
value per share
$
8.54
$
9.95
$
8.08
84
A summary
of option activity under the plans for the year ended December 31, 2008 is
presented below:
Number
of
Options
Weighted
average
exercise
price
Weighted
average
contractual
term
(years)
Aggregate
Intrinsic
Value
(In
Thousands, Except Exercise Price and Contractual Term)
We received
$16.5 million, $4.0 million and $2.1 million in cash proceeds from the exercise
of stock options for the years ended December 31, 2008, 2007 and 2006,
respectively. The intrinsic value of stock options exercised was $18.4 million,
$4.5 million and $3.5 million for the years ended December 31, 2008, 2007 and
2006, respectively.
We have
granted restricted stock to our employees under the 2006 Plan and 1999 Plan and
to non-employee directors under the 1995 Plan and 1997 Plan. Restricted stock
awards are valued on the date of grant based on the closing value of our stock.
As of December 31, 2008, there was $11.3 million of unrecognized compensation
cost related to restricted stock expected to be recognized over the next three
years. With the adoption of FAS 123R, unearned compensation is recorded on a net
basis in Additional capital.
A summary of
the status of restricted stock at December 31, 2008, and changes for the year
then ended is presented below:
The fair
value of restricted stock vested during the years ended December 31, 2008, 2007
and 2006 was $6.7 million, $3.8 million and $3.6 million,
respectively.
Liability
instruments
We use the
fair value method to recognize compensation cost associated with SARs. At each
December 31, 2008, 2007 and 2006, there were 262,500 vested SARs outstanding and
exercisable. The weighted average exercise price of these SARs was $29.19 per
SAR; the weighted average contractual term was 4.8 years.
We also issue
stock incentive units, which are classified as liabilities. They are settled
with a cash payment for each unit vested, equal to the fair market value of
Common Stock on the vesting date.
We lease
certain mining and other equipment under various lease agreements. Certain of
these leases provide options for the purchase of the property at the end of the
initial lease term, generally at its then fair market value, or to extend the
terms at its then fair rental value. Certain of these leases contain financial
or other non-performance covenants that may require an accelerated buyout of the
lease if the covenants are violated. Rental expense for the years ended December31, 2008, 2007 and 2006 was $53.1 million, $39.7 million and $46.4 million,
respectively.
During 2008,
2007 and 2006 we sold and leased-back certain mining equipment. We received net
proceeds of $41.3 million, $13.1 million and $21.8 million, for the years ended
December 31, 2008, 2007 and 2006, respectively, resulting in net deferred gains
of $2.4 million and $1.2 million for the years ended December 31, 2008 and 2007,
respectively. No gain or loss was recognized on the sale and lease-back
transactions that occurred in the year ended December 31, 2006. The gains are
being recognized ratably over the term of the leases, which range from 3.5 to 7
years. At lease termination, the leases contain renewal and purchase options at
an amount approximating fair value. The leases are being accounted for as
operating leases.
The following
presents future minimum rental payments, by year, required under leases with
initial terms greater than one year, in effect at December 31,2008:
Capital
Leases
Operating
Leases
(In
Thousands)
2009
$
2,285
$
71,237
2010
2,412
70,150
2011
2,670
56,527
2012
13
46,177
2013
12
29,654
Beyond
2013
23
18,850
Total
minimum lease payments
7,415
$
292,595
Less
imputed interest
503
Present
value of minimum capital lease payments
$
6,912
14.
Concentrations of Credit Risk and Major Customers
We are
engaged in the production of coal for the utility industry, steel industry and
industrial markets. The following chart lists the percentage of each type of
Produced coal revenue generated by market:
Our
mining operations are conducted in southern West Virginia, eastern Kentucky and
western Virginia. We market
our produced and purchased coal to customers in the United States and in
international markets, including Canada and various European and Asian
countries. For the years ended December 31, 2008, 2007, and 2006
approximately 30%, 16%, and 15%, respectively, of Produced coal revenue was
attributable to sales to customers outside of the United
States.
For the
year ended December 31, 2008, approximately 11% of Produced coal revenue was
attributable to sales to Constellation Energy Commodities Group, Inc.
(“Constellation”). For both the years ended December 31, 2007 and 2006,
approximately 11% of Produced coal revenue was attributable to sales to
affiliates of American Electric Power Company, Inc. At December 31, 2008,
approximately 75%, 13% and 12% of Trade receivables represents amounts due from
utility customers, metallurgical customers and industrial customers,
respectively, compared with 56%, 28% and 16%, respectively, as of December 31,2007. For fiscal year 2009, our contracted sales to Constellation currently
represent approximately 26% of our projected produced coal tonnage and 18% of
our projected Produced coal revenue.
86
Our Trade
and other accounts receivable are subject to potential default by customers. In
prior years, certain of our customers have filed for bankruptcy resulting in bad
debt charges. In an effort to mitigate credit-related risks in all customer
classifications, we maintain a credit policy, which requires scheduled reviews
of customer creditworthiness and continuous monitoring of customer news events
that might have an impact on their financial condition. Negative credit
performance or events may trigger the application of tighter terms of sale,
requirements for collateral or guarantees or, ultimately, a suspension of credit
privileges. We establish bad debt reserves to specifically consider customers in
financial difficulty and other potential receivable losses. In establishing the
reserve, we consider the financial condition of individual customers and
probability of recovery in the event of default. We charge off uncollectible
receivables once legal potential for recovery is exhausted. See Note 18 for a discussion
of certain customer disputes.
15.
Derivative Instruments
We
evaluate each of our coal sales and coal purchase forward contracts under SFAS
133 to determine in they qualify for the NPNS exception
prescribed by SFAS 133. The majority of our forward contracts do qualify
for the NPNS exception based on management's intent and ability to physically
deliver or take physical delivery of the coal. For those contracts that
do not qualify for NPNS, the contracts are required to be accounted for
as derivative instruments in accordance with SFAS 133, which requires all
derivative instruments to be recognized as assets or liabilities and to be
measured at fair value. Those contracts that have been identified as derivatives
have not been designated as cash flow or fair value hedges and, accordingly, the
net change in fair value is recorded in current period earnings. As of
December 31, 2008, there were approximately 1.8 million and 2.2 million tons
outstanding under these coal purchase and coal sales contracts, respectively. We
have recorded net unrealized losses of $22.6 million related to coal sales and
purchase contracts that qualify as derivatives in the Consolidated Statements of
Income for the twelve months ending December 31, 2008 under the caption Net
change in fair value of derivative instruments. A liability of $22.6
million is included in Other current liabilities in the Consolidated Balance
Sheets as of December 31, 2008 as all of these contracts have terms of one year
or less.
16.
Fair Value of Financial Instruments
On
January 1, 2008, we adopted SFAS 157, which requires the categorization of
financial assets and liabilities based upon the level of judgments associated
with the inputs used to measure their fair value. Hierarchical levels
– defined by SFAS 157 and directly related to the amount of subjectivity
associated with the inputs used to determine the fair value of financial assets
and liabilities – are as follows:
•
Level
1 – Inputs are unadjusted, quoted prices in active markets for identical
assets or liabilities at the measurement
date.
•
Level
2 – Inputs (other than quoted prices included in Level 1) are either
directly or indirectly observable for the assets or liability through
correlation with market data at the measurement date and for the duration
of the instrument’s anticipated
life.
•
Level
3 – Inputs reflect management’s best estimate of what market participants
would use in pricing the asset or liability at the measurement
date. Consideration is given to the risk inherent in the
valuation technique and the risk inherent in the inputs to the
model.
Each
major category of financial assets and liabilities measured at fair value on a
recurring basis are categorized in the tables below based upon the lowest level
of significant input to the valuations.
All investments in money market
funds are cash equivalents or deposits pledged as collateral and are primarily
invested in seven money market funds and four Treasury-backed
funds. All fixed income securities are deposits, consisting of
obligations of the U.S. Treasury, supporting various regulatory
obligations. See Note 3 to the Notes to Consolidated Financial
Statements for more information on deposits.
87
Short-term investment
is comprised of an investment in the Primary Fund, a money market fund that has
suspended redemptions and is being liquidated. We have determined that our
investment in the Primary Fund no longer meets the definition of a security
within the scope of SFAS 115, since the equity investment no longer has a
readily determinable fair value. Therefore, the investment has been classified
as a short-term investment, subject to the cost method of accounting, on our
Consolidated Balance Sheet. This classification as a short-term investment is
based on our assessment of each of the individual securities that make up the
underlying portfolio holdings in the Primary Fund, which primarily consisted of
commercial paper and discount notes having maturity dates within the next 12
months, and the stated notifications from the Primary Fund that they expect to
liquidate substantially all of their holdings and make distributions within a
year.
Assets
Measured at Fair Value on a Recurring Basis Using Significant Unobservable
Inputs (Level 3):
The original
cost of our investment in the Primary Fund was $217.9 million. In
mid-September, the Primary Fund reported a net asset value of $0.97 per share as
a result of the Primary Fund’s valuing at zero its holdings of debt securities
issued by Lehman Brothers Holdings, Inc., which filed for bankruptcy on
September 15, 2008. Given that the Primary Fund is in liquidation, we
believe that other than temporary impairment is evident. Based on our assessment
of the Primary Fund’s net asset value, the planned disbursement schedule of the
Primary Fund’s cash and the underlying securities held by the Primary Fund, we
have determined that the approximate fair value of our investment as of
September 30, 2008 was $211.4 million, which represents our investment in the
Primary Fund at 97% of its cost. We have recorded a loss of $6.5 million which
represents the difference between cost and estimated fair value.
In September
2008, we requested the redemption of our investment in the Primary Fund. On
October 31, 2008 and December 3, 2008, the Primary Fund made distributions to us
of $110.7 million and $61.3 million, respectively, leaving an investment balance
of $39.4 million. Subsequent to December31, 2008, on February 20, 2009, the Primary Fund made an additional
distribution to us of $14.5 million. While we expect to receive substantially
all of our remaining holdings in the Primary Fund during 2009, we cannot predict
when this will occur or the actual amount we will eventually receive.
Accordingly, we have reclassified our investment from Cash and cash equivalents
to Short-term investment on our Consolidated Balance Sheet as of
December 31, 2008.
Certain
of our coal sales and coal purchase forward contracts are accounted for as
derivative instruments in accordance with SFAS 133. SFAS 133 requires all
derivative instruments to be recognized as assets or liabilities and to be
measured at fair value. To establish fair values for these contracts, we use
bid/ask price quotations obtained from independent third-party
brokers. We could experience difficulty in valuing our derivative
instruments if the number of third-party brokers should decrease or market
liquidity is reduced.
17.
Common Stock Issuance
On August 12, 2008, we completed a
registered underwritten public offering of 4,370,000 shares of Common Stock,
which included 2,874,800 shares of our Treasury stock, at a public offering
price of $61.50 per share, resulting in proceeds to us of $258.2 million, net of
underwriting fees. As discussed in Note 6, we used these proceeds and the
proceeds of the concurrent convertible notes offering to purchase a portion of
the 6.625% Notes in connection with the 6.625% Notes consent solicitation and
tender offer and for general corporate purposes.
88
18.
Contingencies
Wheeling-Pittsburgh
On April 27,2005, Wheeling-Pittsburgh sued our subsidiary, Central West Virginia Energy
Company (“CWVE”), in the Circuit Court of Brooke County, West Virginia, seeking
(a) an order requiring CWVE to specifically perform its obligations under a Coal
Supply Agreement (“CSA”) and (b) compensatory damages due to CWVE’s alleged
failure to perform under the CSA and for alleged damages to
Wheeling-Pittsburgh’s coke ovens. Wheeling-Pittsburgh later amended its
complaint to add Mountain State Carbon, LLC (“MSC”) as a plaintiff, us as a
defendant, and claims for bad faith, misrepresentation and punitive
damages. It is CWVE’s position that its failure to perform was
excused due to the occurrence of events that rendered performance commercially
impracticable and/or force
majeure events as defined by the parties in the CSA, including unforeseen
labor shortages, mining and geologic problems at certain of our coal mines,
railroad car shortages, transportation problems and other events beyond our
control.
On May 29,2007, the trial commenced. On July 2, 2007, the jury awarded damages
in favor of Wheeling-Pittsburgh and MSC in the amount of $219.9 million,
comprising $119.9 million compensatory damages for breach of contract and
misrepresentation and $100 million for punitive damages. On July 30, 2007, a
hearing was held by the trial court to review the punitive damages award, and to
consider pre-judgment interest and a counterclaim filed by CWVE related to
damages for non-payment of the escalated purchase price under the CSA for coal
delivered to MSC in November and December 2006. At the hearing,
the trial court awarded Wheeling-Pittsburgh and MSC pre-judgment interest of
approximately $24 million and awarded CWVE approximately $4.5 million (including
pre-judgment interest) on the counterclaim. On August 2, 2007, the
trial court entered the jury award of compensatory and punitive damages, which,
including the above mentioned pre-judgment interest of $24 million, totaled
approximately $240 million (net of the $4.5 million awarded to CWVE). On
September 26, 2007, the trial court held a hearing on the issue of security for
the judgment pending appeal to the Supreme Court of Appeals of West Virginia
(“WV Supreme Court”). On September 28, 2007, the trial court ordered that a bond
be posted in the amount of $50 million. The $50 million appeal bond
was posted with the trial court on October 25, 2007.
On December10, 2007, we and CWVE filed separate “Petitions for Appeal” with the WV Supreme
Court seeking, among other things, review of certain rulings made by the trial
court and reversal of the judgments against us. The arguments raised on appeal
included, among other things, (i) the propriety of allowing Wheeling-Pittsburgh
to proceed with both contract and tort claims where the tort arose out of
performance of the contract, (ii) the propriety of the punitive damages award,
(iii) whether Wheeling-Pittsburgh proved the elements of its misrepresentation
and contract claims and (iv) the correctness of certain evidentiary
rulings.
We believed,
in consultation with legal counsel, that we had strong legal arguments to raise
on appeal to the WV Supreme Court that created significant uncertainty regarding
the ultimate outcome of this matter. Given the size of the punitive
damages awarded, West Virginia case precedent, and the significant legal
questions the case presented for appeal, we believed it was probable that the WV
Supreme Court would agree to hear our appeal. Ultimately, we believed
it was unlikely any punitive damages would be assessed in this
matter. We further believed in consultation with legal counsel that
due to matters of law in the conduct of the trial, there was a strong
possibility that the WV Supreme Court would remand the compensatory damages
claim for retrial or significantly reduce the amount of the compensatory damages
awarded by the jury.
We believed
the range of possible loss in this matter was from $16 million to $244 million,
prior to post-judgment interest or other costs. The minimum loss we expected to
incur upon final settlement or adjudication was the amount of excess costs
incurred by Wheeling-Pittsburgh to acquire coal required but not delivered under
the CSA (plus pre-judgment interest) adjusted for performance excused by events
of force
majeure. We were unable to predict the ultimate outcome of
this matter and believed there was no amount in the range that was a better
estimate than any other amount given the various possible outcomes on
appeal. Included in these reasonably possible outcomes were reversal
of the compensatory damage and punitive awards, remand and retrial, or reduction
of some or all of the awards. As there was no amount in the range
that was a better estimate than any other amount, the minimum amount in the
range of $16.0 million (plus accrued interest) had been accrued as of March 31,2008.
On May 22,2008, the WV Supreme Court decided not to hear an appeal of the verdicts against
us or CWVE. In the second and third quarters of 2008, we increased our legal
accrual for this case by $245.3 and $5.8 million in the
Litigation charge line item on our Consolidated Income Statement,
respectively, for a total accrual as of September 30, 2008, of $268.5
million, including interest, recorded in Other current liabilities. On December1, 2008, the United States Supreme Court declined to accept the petitions for
certiorari filed on behalf of us and CWVE. On December 4, 2008, we paid the
total amount of $267.4 million (which included the release of a $50.0 million
appeal bond), which represented the entire judgment against us and CWVE,
including all applicable interest payments. On December 8, 2008, the
Circuit Court of Brooke County entered an Order finding satisfaction of the
judgment and discharging any and all liens in connection with that judgment. In
addition, on December 8, 2008, the Circuit Court of Brooke County released us
from any and all obligations under the appeal bond posted in connection with
this litigation.
89
We have notified our
insurance carriers pursuant to our insurance policies. We believe that we have a
valid claim for coverage for at least certain aspects of the underlying
litigation. However, we are not able at this time to predict with any degree of
certainty the amount of any insurance recovery.
Harman
In December 1997,
A.T. Massey’s then subsidiary, Wellmore Coal Corporation (“Wellmore”), declared
force majeure under its coal supply agreement with Harman Mining Corporation
(“Harman”) and reduced the amount of coal to be purchased from Harman. On
October 29, 1998, Harman and its sole shareholder sued A.T. Massey and five of
its other subsidiaries (the “Massey Defendants”) in the Circuit Court of Boone
County, West Virginia, alleging that the Massey Defendants tortiously interfered
with Wellmore’s agreement with Harman, causing Harman to go out of business. On
August 1, 2002, the jury awarded the plaintiffs $50 million in
compensatory and punitive damages. On October 24, 2006, the Massey Defendants
timely filed their Petition for Appeal to the WV Supreme Court. On
November 21, 2007, the WV Supreme Court issued a 3-2 majority opinion reversing
the judgment against the Massey Defendants and remanding the case to the Circuit
Court of Boone County with directions to enter an order dismissing the case,
with prejudice, in its entirety. The Harman plaintiffs filed motions
asking the WV Supreme Court to conduct a rehearing in the case. On January 24,2008, the WV Supreme Court decided to rehear the case, which was re-argued on
March 12, 2008. On April 3, 2008, the WV Supreme Court again reversed the
judgment against the Massey Defendants and remanded the case with direction to
enter an order dismissing the case, with prejudice, in its entirety. In July
2008, the Harman plaintiffs petitioned the United States Supreme Court to review
the WV Supreme Court’s dismissal of their claims.
In December 2008, the U.S.
Supreme Court agreed to review the case. The U.S. Supreme Court
granted review based on the question of whether a justice of the WV Supreme
Court should have recused himself from the appeal. Oral argument before the U.S
Supreme Court is scheduled for March 3, 2009. The U.S Supreme Court
could affirm the dismissal of the case by the WV Supreme Court or direct the WV
Supreme Court to rehear the case. If the WV Supreme Court, which is
comprised of five justices, rehears the case the matter would not be heard by
the same five justices who heard the matter in April 2008. The
justices of the reconfigured WV Supreme Court could dismiss the plaintiffs’
claims again, or reach some different result, including a reinstatement of the
original verdict against us with interest. We believe the range of possible loss
in this matter is from zero to $82 million as of December 31, 2008, including
post-judgment interest and other costs. We are unable to predict the ultimate
outcome of this matter and believe there is no amount in the range that is a
better estimate than any other amount given the various possible
outcomes. As there is no amount in the range that is a better
estimate than any other amount and the minimum amount in the range is zero, we
have not recorded an accrual for this matter. It is reasonably possible that our
judgments regarding these matters could change in the near term, resulting in
the recording of material losses that would affect our operating results and
financial position.
West
Virginia Flooding
Since
July 2001, we and nine of our subsidiaries have been sued in 17 consolidated
civil actions filed in the Circuit Courts of Boone, Fayette, Kanawha, McDowell,
Mercer, Raleigh and Wyoming Counties, West Virginia, for alleged property
damages and personal injuries arising out of flooding on or about July 8, 2001.
Along with 32 other consolidated cases not involving us or our subsidiaries,
these cases cover approximately 1,800 plaintiffs seeking unquantified
compensatory and punitive damages against approximately 100 defendants. The WV
Supreme Court transferred all 49 cases (the “Referred Cases”) to the Circuit
Court of Raleigh County, West Virginia, to be handled by a mass litigation
panel, which originally assigned three of its six judges to preside
(the “Panel”) over the litigation.
On
January 18, 2007, a panel judge dismissed all claims asserted by all plaintiffs
within the Coal River watershed in Raleigh County, West Virginia. Plaintiffs
filed a petition seeking appeal of this decision with the WV Supreme Court,
which was granted on October 24, 2007. The WV Supreme Court issued a decision on
June 26, 2008 reversing the lower court and in early September 2008 denied a
Motion for Rehearing and remanded the case to the Mass Litigation Panel for
further proceedings. We expect proceedings to resume in early to mid-2009. We
believe we have insurance coverage applicable to these items.
Since
August 2004, five of our subsidiaries have been sued in six civil actions filed
in the Circuit Courts of Boone, McDowell, Mingo, Raleigh, Summers and Wyoming
Counties, West Virginia, for alleged property damages and personal injuries
arising out of flooding on or about May 2, 2002. These complaints cover
approximately 350 plaintiffs seeking unquantified compensatory and punitive
damages from approximately 35 defendants.
Since May
2006, we and twelve of our subsidiaries have been sued in three civil actions
filed in the Circuit Courts of Logan and Mingo Counties, West Virginia, for
alleged property damages and personal injuries arising out of flooding between
May 30 and June 4, 2004. Four of our subsidiaries have been dismissed from one
of the Logan County cases. These complaints cover approximately 425 plaintiffs
seeking unquantified compensatory and punitive damages from approximately 52
defendants. Two of these cases (both in Logan County) were stayed pending appeal
of the Coal River watershed decision noted above. One case is now proceeding and
we expect the other case and the Mingo County case to resume soon.
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On April10, 2007, two of our subsidiaries were sued in a civil action filed in the
Circuit Court of Boone County, West Virginia, for alleged property damages and
personal injuries arising out of flooding on or about July 29, 2001. This
complaint covers 17 plaintiffs seeking unquantified compensatory and punitive
damages from five defendants. On November 6, 2007, we filed a motion to
dismiss, or in the alternative, to certify questions to the WV Supreme Court in
response to the complaint. Subsequently, we settled with 16 of 17 of the
plaintiffs. With respect to the remaining plaintiff, the trial court
granted a motion to withdraw filed by the plaintiff’s counsel and subsequently
dismissed the remaining plaintiff on the grounds initially asserted in the
motion to dismiss. The appeal period regarding the dismissal has run and this
case is now closed.
We
believe these matters will be resolved without a material adverse impact on our
cash flows, results of operations or financial condition.
West
Virginia Trucking
Since
January 2003, an advocacy group and residents in Boone, Kanawha, Mingo and
Raleigh Counties, West Virginia, filed 17 suits in the Circuit Courts of Kanawha
and Mingo Counties, West Virginia, against twelve of our subsidiaries.
Plaintiffs alleged that defendants illegally transported coal in overloaded
trucks, causing damage to state roads, thereby interfering with plaintiffs’ use
and enjoyment of their properties and their right to use the public roads.
Plaintiffs seek injunctive relief and compensatory and punitive damages. The WV
Supreme Court referred the consolidated lawsuits, and similar lawsuits against
other coal and transportation companies not involving our subsidiaries, to the
Circuit Court of Lincoln County, West Virginia, to be handled by a mass
litigation panel judge. Plaintiffs filed motions requesting class certification.
On June 7, 2007, plaintiffs voluntarily dismissed their public nuisance claims
seeking monetary damages for road and bridge repairs. Defendants filed a motion
requesting that the mass litigation panel judge recommend to the WV Supreme
Court that the cases be sent back to the circuit courts of origin for
resolution. That motion has not been ruled upon. Defendants moved to
dismiss any remaining public nuisance claims and to limit any damages for
nuisance to two years prior to the filing of any suit, and plaintiffs agreed to
an order limiting any damages for nuisance to two years prior to the filing of
any suit. The motion to dismiss any remaining public nuisance claims was
resisted by plaintiffs and argued at hearings on December 14, 2007 and June 25,2008. As of February 12, 2009, no date has been set for trial. We believe we
have insurance coverage applicable to these items and that they will be resolved
without a material adverse impact on our cash flows, results of operations or
financial condition.
Well
Water Contamination
Since
September 2004, approximately 710 plaintiffs have filed approximately 400 suits
against us and our subsidiary, Rawl Sales & Processing Co., in the Circuit
Court of Mingo County, West Virginia, for alleged property damage and personal
injuries arising out of slurry injection and impoundment practices allegedly
contaminating plaintiffs’ water wells. Subsequent to such filings, approximately
55 suits have either been voluntarily dismissed by the plaintiffs or dismissed
by the Circuit Court. Plaintiffs seek injunctive relief and compensatory damages
in excess of $170 million and unquantified punitive damages. Specifically,
plaintiffs are claiming that defendants’ activities during the period of 1978
through 1987 rendered their property valueless and request monetary damages to
pay, inter alia, the
value of their property and future water bills. In addition, many plaintiffs are
also claiming that their exposure to the contaminated well water caused
neurological injury or physical injury, including cancers, kidney problems and
gall stones. Finally, all plaintiffs are claiming entitlement to medical
monitoring for the next 30 years. Plaintiffs also request unliquidated
compensatory damages for pain and suffering, annoyance and inconvenience and
legal fees. The trial has been continued multiple times and is currently
scheduled for May 12, 2009. We do not believe there was any contamination caused
by our activities or that plaintiffs suffered any damage and, therefore, we do
not believe we have a probable loss related to this matter. We plan to
vigorously contest these claims. We believe that we have insurance coverage
applicable to these matters and have initiated litigation against our insurers
to establish that coverage. At this time, we believe that the litigation by the
plaintiffs will be resolved without a material adverse impact on our cash flows,
results of operations or financial condition.
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Surface
Mining Fills
Since
September 2005, three environmental groups sued the United States Army Corps of
Engineers (“Corps”) in the United States District Court for the Southern
District of West Virginia (the “District Court”), asserting the Corps unlawfully
issued permits to four of our surface mines to construct mining fills. The suit
alleges the Corps failed to comply with the requirements of both Section 404 of
the Clean Water Act and the National Environmental Policy Act, including
preparing environmental impact statements for individual permits. We intervened
in the suit to protect our interests. On March 23, 2007, the District Court
rescinded four of our subsidiaries’ permits, resulting in the temporary
suspension of mining at these surface mines. We appealed that ruling to the
United States Court of Appeals for the Fourth Circuit (the “Fourth Circuit
Court”). On April 17, 2007, the District Court partially stayed its ruling,
permitting mining to resume in certain fills that were already under
construction. On June 14, 2007, the District Court issued an additional ruling,
finding the Corps improperly approved placement of sediment ponds in streams
below fills on the four permits in question. The District Court
subsequently modified its ruling to allow these ponds to remain in place, as the
ponds and fills have already been constructed. The District Court’s
ruling could impact the issuance of permits for the placement of sediment ponds
for future operations. If the permits for the fills or sediment ponds are
ultimately held to be unlawfully issued, production could be affected at these
surface mines, and the process of obtaining new Corps permits for all surface
mines could become more difficult. We appealed both rulings to the Fourth
Circuit Court. A hearing on these appeals was held on September 23, 2008, and on
February 13, 2009, the Fourth Circuit Court reversed the prior rulings of the
District Court and remanded the matter for further proceedings. Given this
development, we do not expect any material adverse impact to our
operations.
Aracoma
Mine Fire
In
January 2006, one of our subsidiaries, Aracoma Coal Company, Inc. (“Aracoma”),
experienced a mine fire that resulted in the deaths of two miners. The estates
of the two miners had filed a lawsuit in the Circuit Court of Logan County
against us, A.T. Massey and Aracoma with respect to the incident. A trial in
that suit began on October 27, 2008. A settlement was reached and
paid in December 2008, with a portion of the settlement being paid through
insurance proceeds.
Additionally,
the United States Attorney’s Office in the Southern District of West Virginia
(“U.S. Attorney’s Office”) and the Federal Mine Safety and Health Administration
(“MSHA”) conducted separate investigations into the incident. As a
result of those investigations, Aracoma pleaded guilty to federal charges and
agreed to pay $2.5 million in criminal fines and reached a settlement with MSHA
in which Aracoma agreed to pay $1.7 million in administrative penalties. The
plea will be presented for final review and approval at a hearing scheduled for
April 15, 2009. These fines and penalties were fully accrued as of December 31,2008 and have now been paid. There will be no fines or penalties
imposed upon our affiliated companies for the incident.
Customer
Disputes
We have
customers who claim they did not receive, or did not timely receive, all of the
coal required to be shipped to them during 2008 (“unshipped tons”). In such
cases, it is typical for a customer and coal producer to agree upon a schedule
for shipping unshipped tons in subsequent years. However, a few of
our customers have notified us of claims or potential claims for cover damages,
which are equal to the difference between the contract price of the coal that
was not delivered and the market price of replacement coal or comparable quality
coal.
We believe we
have valid defenses to these claims or potential claims for cover
damages. In many cases, there was untimely or insufficient
delivery of railcars by the rail carrier or the customer. In other
cases, factors beyond our control caused production or shipment
problems. Additionally, we believe that certain customers previously
agreed to accept unshipped tons in subsequent years. We believe that
all of these factors, and other factors, provide defenses to claims or potential
claims for unshipped tons.
We are
currently in the process of arbitration and litigation over multiple claims for
cover by one customer. In October and November 2008, this customer failed to pay
approximately $35 million owed to us for several shipments of coal. The
customer notified us that it had offset the amounts from its required payments
in response to damages allegedly suffered due to alleged shortfalls that
occurred prior to September 30, 2008. We believe this offset was improper
and are pursuing collection of the amounts offset through a demand for
arbitration filed against the customer in December 2008 and through our response
to litigation initiated by the customer on a portion of the
shortfalls. Additionally, one other customer filed suit in
February 2009 seeking unspecified damages relating to alleged shortfalls and
other customers have notified us of claims or potential claims for cover damages
that have not yet resulted in litigation. Discussions with these
customers remain ongoing.
Separately,
we are currently in talks with a few other customers regarding disagreements
over other contract matters. Specifically, we have disputes with two
customers regarding whether or not binding contracts for the sale of coal were
reached. One of these customers has terminated a signed,
higher-priced contract and argues that it was only required to purchase coal
under an agreement reached by email. The other customer argues that it
reached agreement with us in the absence of a signed agreement and has brought
litigation against us for not honoring the alleged unsigned
agreement. We do not believe that we have failed to honor any binding
agreement with these customers.
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We believe
that we have strong defenses to these claims and potential claims and further
feel that many or all of these claims may be resolved without litigation. We
have recorded an accrual for our best estimate of probable losses related to
these matters. While we believe that all of these matters discussed above will
be resolved without a material adverse impact on our cash flows, results of
operations or financial condition, it is reasonably possible that our judgments
regarding some or all of these matters could change in the near term. The
aggregate exposure related to these claims in excess of our accrual is up to
$105 million of charges that would affect our future operating results and
financial position.
Spartan
Unfair Labor Practice Matter & Related Age Discrimination Class
Action
In 2005, the
UMWA filed an unfair labor practice charge with the National Labor Relations
Board (“NLRB”) alleging that Spartan Mining Company (“Spartan”) discriminated on
the basis of anti-union animus in its employment offers. The NLRB
issued a complaint and an NLRB Administrative Law Judge (“ALJ”) issued a
recommended decision making detailed findings that the Company committed a
number of unfair labor practice violations and awarding, among other relief,
backpay damages to union discriminatees. The ALJ’s decision is on
appeal to the NLRB. There is no insurance coverage applicable to the
unfair labor practice matter; however, its resolution is not expected to
materially impact our finances or operations.
On November 1, 2006,
a class action age discrimination civil case was filed in West Virginia’s
Fayette County Circuit Court. The suit alleges that Spartan
discriminated against employment applicants on the basis of age. The
class includes approximately 232 individuals, 85 of whom are also union
discriminatees at issue in the ALJ’s decision.
In the civil suit, the age
discrimination plaintiffs seek back pay, front pay, punitive damages, and other
compensatory damages, plus attorney
fees. We have insurance coverage applicable to the class action
and believe that it will be resolved without material impact on our cash
flows, results of operations or financial condition.
Other
Legal Proceedings
We are
parties to a number of other legal proceedings, incident to our normal business
activities. These include contract dispute, personal injury, property damage and
employment matters. While we cannot predict the outcome of these proceedings,
based on our current estimates we do not believe that any liability arising from
these matters individually or in the aggregate should have a material adverse
impact upon our consolidated cash flows, results of operations or financial
condition. It is possible, however, that the ultimate liabilities in the future
with respect to these lawsuits and claims, in the aggregate, may be materially
adverse to our cash flows, results of operations or financial
condition.
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19.
Quarterly Information (Unaudited)
The table below details our quarterly
financial information for the previous two fiscal years.
Income
for the first quarter of 2008 includes a $13.6 million pre tax gain on the
exchange of coal reserves.
(2)
Loss
for the second quarter of 2008 includes $245.3 million pre tax expense
related to the Wheeling-Pittsburgh lawsuit (see Note 18 for further
information) and a $15.3 million pre tax gain on the exchange of coal
reserves.
(3)
Income
for the third quarter of 2008 includes $5.8 million pre tax expense
related to the Wheeling-Pittsburgh lawsuit (see Note 18 for further
information), $9.1 million pre tax loss on financing transaction related
to fees incurred for the tender offer for our 6.625% Notes (see Note 6 for
further information), $3.6 million pre tax gain on the exchange of coal
reserves and other assets, and a $6.5 million pre tax loss on short-term
investment reflecting an impairment of our investment in the Primary Fund
(see Note 16 for further
information).
(4)
Income
for the fourth quarter of 2008 includes $12.9 million pre tax income
related to federal legislation passed that authorized refunds of black
lung excise taxes paid in years that had been statutorily closed, $8.6
million pre tax gain on financing transaction from the purchase of $19.0
million of our 3.25% Notes on the open market (see Note 6 for further
information), and a $22.6 million non-cash loss on the net change of
derivative instruments.
(5)
Income
for the second quarter of 2007 includes $5.0 million non-tax deductible
expense related to the settlement of a lawsuit filed by the Environmental
Protection Agency (“EPA lawsuit”) and a $10.3 million pre-tax gain on the
exchange of coal reserves.
(6)
Income
for the fourth quarter of 2007 includes $22.0 million reversal of the
accrual and $11.6 million reversal of accrued interest for the Harman
lawsuit (see Note 18 for further information), $15 million non-tax
deductible expense related to the settlement of the EPA lawsuit, and a
$6.7 million pre-tax gain on the sale of a mineral rights
override.
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Item
9. Changes in and Disagreements with Accountants on Accounting and Financial
Disclosure
There have been no
changes in, or disagreements with, accountants on accounting and financial
disclosure.
Item
9A. Controls and Procedures
Evaluation
of Disclosure Controls and Procedures and Changes in Internal Control Over
Financial Reporting
We have
established disclosure controls and procedures to ensure that information
relating to us, including our consolidated subsidiaries, required to be
disclosed in the reports that we file or submit under the Exchange Act, is
accumulated and communicated to management, including the principal executive
officer and principal financial officer, as appropriate, to allow timely
decisions regarding required disclosure.
Under the
supervision and with the participation of our management, including our
principal executive officer and principal financial officer, we conducted an
evaluation of the effectiveness of the design and operation of our disclosure
controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the
Exchange Act), as of the end of the period covered by this report.
Based on
our evaluation as of December 31, 2008, the principal executive officer and
principal financial officer have concluded that the disclosure controls and
procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act)
are effective to ensure that the information required to be disclosed in reports
that we file or furnish under the Exchange Act is recorded, processed,
summarized and reported within the time periods specified in SEC rules and
forms.
There has
been no change in our internal control over financial reporting during the
quarter ended December 31, 2008, that has materially affected, or is reasonably
likely to materially affect, our internal control over financial
reporting.
Management’s
Evaluation of Internal Control Over Financial Reporting
Pursuant
to Section 404 of the Sarbanes-Oxley Act of 2002, management is required to
include in this Form 10-K an internal control over financial reporting report
wherein management states its responsibility for establishing and maintaining
adequate internal control structure and procedures for financial reporting and
assesses the effectiveness of such structure and procedures. This management
report follows.
MANAGEMENT
REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
The
management of Massey Energy Company (“Massey”) is responsible for establishing
and maintaining adequate internal control over financial reporting as such term
is defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of
1934, as amended. Massey’s internal control over financial reporting is a
process designed to provide reasonable assurance regarding the reliability of
financial reporting and the preparation of financial statements for external
purposes in accordance with generally accepted accounting
principles.
Massey’s
internal control over financial reporting includes policies and procedures that
(1) pertain to the maintenance of records that, in reasonable detail, accurately
and fairly reflect transactions and dispositions of assets of Massey; (2)
provide reasonable assurance that transactions are recorded as necessary to
permit preparation of financial statements in accordance with generally accepted
accounting principles, and that receipts and expenditures are being made only in
accordance with authorizations of management and the directors of Massey; and
(3) provide reasonable assurance regarding prevention or timely detection of
unauthorized acquisition, use or disposition of Massey’s assets that could have
a material effect on the Company’s financial statements.
Because
of its inherent limitations, internal control over financial reporting may not
prevent or detect misstatements. Also, projections of any evaluation of
effectiveness to future periods are subject to the risk that controls may become
inadequate because of changes in conditions, or that the degree of compliance
with the policies or procedures may deteriorate.
Massey’s
management assessed the effectiveness of Massey’s internal control over
financial reporting as of December 31, 2008. In making this assessment, Massey
used the criteria in Internal
Control-Integrated Framework issued by the Committee of Sponsoring
Organizations of the Treadway Commission (COSO). Based on this assessment based
on those criteria, Massey’s management has concluded that, as of December 31,2008, internal control over financial reporting is effective.
The
effectiveness of our internal control over financial reporting as of December31, 2008, has been audited by Ernst & Young LLP, an independent registered
public accounting firm, as stated in their report, which follows immediately
hereafter.
95
REPORT
OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The
Board of Directors and Shareholders of Massey Energy Company
We
have audited Massey Energy Company’s internal control over financial reporting
as of December 31, 2008, based on criteria established in Internal
Control—Integrated Framework issued by the Committee of Sponsoring Organizations
of the Treadway Commission (the COSO criteria). Massey Energy Company’s
management is responsible for maintaining effective internal control over
financial reporting, and for its assessment of the effectiveness of internal
control over financial reporting included in the Management Report on Internal
Control over Financial Reporting. Our responsibility is to express an opinion on
the company’s internal control over financial reporting based on our
audit.
We
conducted our audit 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 effective
internal control over financial reporting was maintained in all material
respects. Our audit included obtaining an understanding of internal control over
financial reporting, assessing the risk that a material weakness exists, testing
and evaluating the design and operating effectiveness of internal control based
on the assessed risk, and performing such other procedures as we considered
necessary in the circumstances. We believe that our audit provides a reasonable
basis for our opinion.
A
company’s internal control over financial reporting is a process designed to
provide reasonable assurance regarding the reliability of financial reporting
and the preparation of financial statements for external purposes in accordance
with generally accepted accounting principles. A company’s internal control over
financial reporting includes those policies and procedures that (1) pertain to
the maintenance of records that, in reasonable detail, accurately and fairly
reflect the transactions and dispositions of the assets of the company; (2)
provide reasonable assurance that transactions are recorded as necessary to
permit preparation of financial statements in accordance with generally accepted
accounting principles, and that receipts and expenditures of the company are
being made only in accordance with authorizations of management and directors of
the company; and (3) provide reasonable assurance regarding prevention or timely
detection of unauthorized acquisition, use or disposition of the company’s
assets that could have a material effect on the financial
statements.
Because
of its inherent limitations, internal control over financial reporting may not
prevent or detect misstatements. Also, projections of any evaluation
of effectiveness to future periods are subject to the risk that controls may
become inadequate because of changes in conditions, or that the degree of
compliance with the policies or procedures may deteriorate.
In
our opinion, Massey Energy Company maintained, in all material respects,
effective internal control over financial reporting as of December 31, 2008,
based on the COSO criteria.
We
also have audited, in accordance with the standards of the Public Company
Accounting Oversight Board (United States), the 2008 consolidated financial
statements of Massey Energy Company and our report dated February 27, 2009
expressed an unqualified opinion thereon.
Mr.
Blankenship has been a director since 1996. He has been Chairman and Chief
Executive Officer since November 2000 and also held the position of President
from November 2000 until November 2008. He has been Chairman, Chief Executive
Officer and President of A.T. Massey Coal Company, Inc., our wholly owned and
sole, direct operating subsidiary, since 1992. Mr. Blankenship was formerly
President and Chief Operating Officer from 1990 to 1991 and President of our
subsidiary, Massey Coal Services, Inc., from 1989 to 1991. He joined our
subsidiary, Rawl Sales & Processing Co., in 1982. He is a director of the
Center for Energy and Economic Development, the National Mining Association and
the United States Chamber of Commerce.
Baxter
F. Phillips, Jr., Age 62
Mr.
Phillips has been a director since 2007. He has been President since
November 2008. Mr. Phillips previously served as Executive Vice President and
Chief Administrative Officer from November 2004 to November 2008, as Senior Vice
President and Chief Financial Officer from September 2003 to November 2004 and
as Vice President and Treasurer from 2000 to August 2003. Mr. Phillips joined us
in 1981 and has also served in the roles of Corporate Treasurer, Manager of
Export Sales and Corporate Human Resources Manager, among others.
J.
Christopher Adkins, Age 45
Mr.
Adkins has been Senior Vice President and Chief Operating Officer since July
2003. Mr. Adkins joined our subsidiary, Rawl Sales & Processing Co., in 1985
to work in underground mining. Since that time, he has served as section
foreman, plant supervisor, President and Vice President of several subsidiaries,
President of our Eagle Energy subsidiary, Director of Production of Massey Coal
Services, Inc. and Vice President of Underground Production.
Mark
A. Clemens, Age 42
Mr. Clemens has been Senior Vice
President, Group Operations since July 2007. From January 2003 to July 2007, Mr.
Clemens was President of Massey Coal Services, Inc. Mr. Clemens was formerly
President of Independence Coal Company, Inc., one of our operating subsidiaries,
from 2000 through December 2002 and our Corporate Controller from 1997 to 1999.
Mr. Clemens has held a number of other accounting positions and has been with us
since 1989.
Michael
K. Snelling, Age 52
Mr.
Snelling has been Vice President, Surface Operations of our subsidiary, Massey
Coal Services, Inc. since June 2005. Mr. Snelling was formerly Director of
Surface Mining of Massey Coal Services, Inc. from July 2003 until May 2005. Mr.
Snelling joined us in 2000 and has served us in a variety of capacities,
including President of our subsidiary, Nicholas Energy Co. Prior to joining us,
Mr. Snelling held various positions in the coal industry including engineer,
production supervisor, plant supervisor, general foreman, manager of contract
mining, superintendent, mine manager and vice president of
operations.
Michael
D. Bauersachs, Age 44
Mr.
Bauersachs has been Vice President, Planning since May 2005. Mr. Bauersachs
joined us in 1998, and served as Director of Acquisitions from 1998 until 2005.
Prior to joining us, Mr. Bauersachs held various positions with Zeigler Coal
Holding Company and Arch Mineral Corporation.
Jeffrey
M. Gillenwater, Age 44
Mr. Gillenwater has been Vice
President, Human Resources since January 2009. In October 1999, Mr. Gillenwater
became Director of Human Resources at our Massey Coal Services, Inc. subsidiary,
and held the position of Director of External Affairs &
Administration from October 2002 until January 2009. Prior to October 2002
he held the position of Human Resources Manager at several of our
subsidiaries.
97
Richard
R. Grinnan, Age 40
Mr.
Grinnan has been Vice President and Corporate Secretary since May 2006. He
served as Senior Corporate Counsel from July 2004 until May 2006. Prior to
joining us, Mr. Grinnan was a corporate and securities attorney at the law firm
of McGuireWoods LLP in Richmond, Virginia from August 2000 until July
2004.
M.
Shane Harvey, Age 39
Mr.
Harvey has been Vice President and General Counsel since January 2008. He served
as Vice President and Assistant General Counsel from November 2006 until January
2008 and as Corporate Counsel and Senior Corporate Counsel from April 2000 until
November 2006. Prior to joining us, Mr. Harvey was an attorney at the law firm
of Jackson Kelly PLLC in Charleston, West Virginia from May 1994 until April
2000.
Jeffrey
M. Jarosinski, Age 49
Mr.
Jarosinski has been Vice President, Finance since 1998 and Chief Compliance
Officer since December 2002. From 1998 through December 2002, Mr. Jarosinski was
Chief Financial Officer. Mr. Jarosinski was formerly Vice President, Taxation
from 1997 to 1998 and Assistant Vice President, Taxation from 1993 to 1997. Mr.
Jarosinski joined us in 1988.
John
M. Poma, Age 44
Mr. Poma
has been Vice President and Chief Administrative Officer since January
2009. Mr. Poma previously served as Vice President, Human Resources
from April 2003 to January 2009. Mr. Poma served as Corporate Counsel from 1996
until 2000 and as Senior Corporate Counsel from 2000 through March 2003. Prior
to joining us in 1996, Mr. Poma was an employment attorney with the law firms of
Midkiff & Hiner in Richmond, Virginia and Jenkins, Fenstermaker, Krieger,
Kayes & Farrell in Huntington, West Virginia.
Steve
E. Sears, Age 60
Mr. Sears
has been Vice President, Sales and Marketing, and President of our subsidiary
Massey Coal Sales Company, Inc. since December 2008. Mr. Sears served
as President of Massey Industrial and Utility Sales, a division of Massey Coal
Sales Company, Inc., from December 2006 to December 2008. Mr. Sears
has held various positions within the sales department. He joined us
in 1981.
Eric
B. Tolbert, Age 41
Mr.
Tolbert has been Vice President and Chief Financial Officer since November 2004.
Mr. Tolbert served as Corporate Controller from 1999 to 2004. He joined us in
1992 as a financial analyst and subsequently served as Director of Financial
Reporting. Prior to joining us, Mr. Tolbert worked for the public
accounting firm Arthur Andersen from 1990 to 1992.
David
W. Owings, Age 35
Mr.
Owings has been Corporate Controller and principal accounting officer since
November 2004. Mr. Owings previously served as Manager of Financial Reporting
since joining us in 2001. Prior to joining us, Mr. Owings worked at Ernst &
Young LLP, the Company’s independent registered public accounting firm, serving
as a manager from January 2001 through September 2001 and as a senior auditor
from October 1998 through January 2001 in the Assurance and Advisory Business
Services group.
The
following information is incorporated by reference from our definitive proxy
statement pursuant to Regulation 14A, which will be filed not later than 120
days after the close of Massey’s fiscal year ended December 31,2008:
•
Information
regarding the directors required by this item is found under the heading
Election of
Directors.
•
Information
regarding Massey’s Audit Committee required by this item is found under
the heading Committees
of the Board.
•
Information
regarding Section 16(a) Beneficial Ownership Reporting Compliance required
by this item is found under the heading Section 16(a) Beneficial
Ownership Reporting
Compliance.
•
Information
regarding Massey’s Code of Ethics required by this item is found under the
heading Code of
Ethics.
98
Because
Common Stock is listed on the NYSE, our chief executive officer
is required to make, and he has made, an annual certification to the NYSE
stating that he was not aware of any violation by us of the corporate governance
listing standards of the NYSE. Our chief executive officer
made his annual certification to that effect to the NYSE as of June 2, 2008. In
addition, we have filed, as exhibits to this annual report on Form 10-K, the
certifications of our principal executive officer and principal financial
officer required under Section 302 of the Sarbanes Oxley Act of 2002 to be filed
with the SEC regarding the quality of
our public disclosure.
Item
11. Executive Compensation
Information
required by this item is included in the Compensation Discussion and
Analysis, Compensation of Named Executive Officers, Compensation Committee
Interlocks and Insider Participation, and Compensation Committee Report on
Executive Compensation sections of the definitive proxy statement
pursuant to Regulation 14A, involving the election of directors, which is
incorporated herein by reference and will be filed not later than 120 days after
the close of our fiscal year ended December 31, 2008.
Item
12. Security Ownership of Certain Beneficial Owners and Management and Related
Stockholder Matters
Information
required by this item is included in the Stock Ownership of Directors and
Executive Officers and Stock Ownership of Certain
Beneficial Owners sections of the definitive proxy statement pursuant to
Regulation 14A, involving the election of directors, which is incorporated
herein by reference and will be filed not later than 120 days after the close of
our fiscal year ended December 31, 2008.
The following table sets forth as of
December 31, 2008, the number of shares of Common Stock authorized for issuance
under our equity compensation plan.
Plan
Category
(a)
Number of securities to be issued upon exercise of outstanding options,
warrants and rights (1),
(2)
(b)
Weighted-average per share exercise price of outstanding options, warrants
and rights (2)
(c)
Number of securities remaining available for future issuance under equity
compensation plans (excluding securities reflected in column
(a))
Equity
compensation plans approved by
shareholders
2,612,517
$
25.81
1,362,752
Equity
compensation plans not approved by
shareholders
(3)
-
-
-
Total
2,612,517
$
25.81
1,362,752
__________________________
(1)
There
are no outstanding warrants or
rights.
(2)
These
amounts do not include shares to be issued upon vesting of restricted
stock because they have no exercise
price.
(3)
We
do not have any equity compensation plans that have not been approved by
our shareholders.
Item
13. Certain Relationships and Related Transactions, and Director
Independence
Information
required by this item is included in the Certain Relationships and Related
Transactions and Director Independence
sections of the definitive proxy statement pursuant to Regulation 14A,
involving the election of directors, which is incorporated herein by reference
and will be filed not later than 120 days after the close of our fiscal year
ended December 31, 2008.
Item
14. Principal Accountant Fees and Services
Information
concerning principal accountant fees and services contained under the heading
The Audit Committee
Report in the definitive proxy statement pursuant to Regulation 14A,
which is incorporated by reference and will be filed not later than 120 days
after the close of our fiscal year ended December 31, 2008.
99
Part
IV
Item
15. Exhibits and Financial Statement Schedules
Consolidated
Statements of Shareholders’ Equity for the Fiscal Years Ended December 31,2008, 2007, and 2006
Notes
to Consolidated Financial Statements
2.Financial
Statement Schedules: Except as set forth below, all schedules have been
omitted since the required information is not present or not present in
amounts sufficient to require submission of the schedule, or because the
information required is included in the Consolidated Financial Statements
and Notes thereto.
Schedule
II—Valuation and Qualifying Accounts
3.Exhibits:
Exhibit
No.
Description
3.1
Certificate
of Ownership and Merger merging Massey Energy Company with and into Fluor
Corporation accompanied by Restated Certificate of Incorporation of Massey
Energy Company, as amended [filed as Exhibit 3.1 to Massey’s annual report
on Form 10-K for the fiscal year ended October 31, 2000 and incorporated
by reference]
Senior
Indenture, dated May 29, 2003, by and among Massey Energy Company,
subsidiaries of Massey Energy Company, as Guarantors and Wilmington Trust
Company, as Trustee, in connection with the Company’s 4.75% Convertible
Senior Notes [filed as Exhibit 4.1 to Massey’s current report on Form 8-K
filed May 30, 2003 and incorporated by reference]
4.2
First
Supplemental Indenture, dated May 29, 2003, by and among Massey Energy
Company, subsidiaries of Massey Energy Company, as Guarantors, and
Wilmington Trust Company, as Trustee, supplementing that certain Senior
Indenture dated May 29, 2003, in connection with the Company’s 4.75%
Convertible Senior Notes [filed as Exhibit 4.2 to Massey’s current report
on Form 8-K filed May 30, 2003 and incorporated by
reference]
First
Supplemental Indenture, dated August 19, 2008, by and among Massey Energy
Company, subsidiaries of Massey Energy Company, as Guarantors, and
Wilmington Trust Company, as Trustee, in connection with the Company’s
6.625% Senior Notes [filed as Exhibit 4.1 to Massey’s current report on
Form 8-K filed August 22, 2008 and incorporated by
reference]
4.5
Second
Supplemental Indenture, dated April 7, 2004, by and among Massey Energy
Company, subsidiaries of Massey Energy Company, as Guarantors, and
Wilmington Trust Company, as Trustee, supplementing that certain Senior
Indenture dated May 29, 2003, in connection with the Company’s 2.25%
Convertible Senior Notes [filed as Exhibit 4.1 to Massey’s current report
on Form 8-K filed April 4, 2004 and incorporated by
reference]
4.6
Indenture,
dated as of December 21, 2005, by and among Massey Energy
Company, subsidiaries of Massey Energy Company, as Guarantors, and
Wilmington Trust Company, as Trustee, in connection with the Company’s
6.875% Senior Notes [filed as Exhibit 4.1 to Massey’s current report on
Form 8-K filed December 21, 2005, and incorporated by
reference]
100
Exhibit
No.
Description
4.7
Senior
Indenture, dated as of August 12, 2008, by and among Massey Energy
Company, subsidiaries of Massey Energy Company, as Guarantors, and
Wilmington Trust Company, as Trustee, in connection with the Company’s
3.25% Senior Notes [filed as Exhibit 4.1 to Massey’s current report on
Form 8-K filed August 12, 2008, and incorporated by
reference]
4.8
First
Supplemental Indenture, dated as of August 12, 2008, by and
among Massey Energy Company, subsidiaries of Massey Energy Company, as
Guarantors, and Wilmington Trust Company, as Trustee, in connection with
the Company’s 3.25% Senior Notes [filed as Exhibit 4.2 to Massey’s current
report on Form 8–K filed August 12, 2008, and incorporated by
reference]
10.1
Amended
and Restated Credit Agreement dated as of August 15, 2006, among A. T.
Massey Coal Company, Inc. and certain of its subsidiaries, as Borrowers,
Massey Energy Company and certain of its subsidiaries, as Guarantors, Bank
of America, N. A., as Syndication Agent, General Electric Capital
Corporation, as Documentation Agent, The CIT Group/Business Credit, Inc.,
as Collateral Agent, UBS Securities LLC, as Arranger, UBS AG, Stamford
Branch, as Administrative Agent, and UBS Loan Finance LLC, as Swingline
Lender, and the lenders party thereto [filed as Exhibit 10.6 to Massey’s
current report on Form 8-K filed August 18, 2006 and incorporated by
reference]
Limited
Consent and Second Amendment to Amended and Restated Credit Agreement
dated July 19, 2007 [filed as Exhibit 10.1 to Massey’s quarterly report on
Form 10-Q filed August 9, 2007 and incorporated by
reference]
Equity
Distribution Agreement dated February 3, 2009 between Massey Energy
Company and UBS Securities LLC [filed as Exhibit 1.1 to Massey’s current
report on Form 8-K filed February 4, 2009 and incorporated by
reference]
10.7
Massey
Energy Company 1982 Shadow Stock Plan (as amended and restated effective
November 30, 2000) [filed as Exhibit 10.8 to Massey’s annual report on
Form 10-K for the fiscal year ended October 31, 2000 and incorporated by
reference]
10.8
Massey
Energy Company 1988 Executive Stock Plan (as amended and restated
effective November 30, 2000) [filed as Exhibit 10.6 to Massey’s annual
report on Form 10-K for the fiscal year ended October 31, 2000 and
incorporated by reference]
10.9
Massey
Energy Company 1996 Executive Stock Plan (as amended and restated,
effective January 1, 2009) [filed as Exhibit 10.14 to Massey’s current
report on Form 8-K filed December 24, 2008 and incorporated by
reference]
10.10
Massey
Energy Company 1997 Stock Appreciation Rights Plan (as amended and
restated, effective November 30, 2000) [filed as Exhibit 10.9 to Massey’s
annual report on Form 10-K for the fiscal year ended October 31, 2000 and
incorporated by reference]
10.11
Massey
Energy Company 1999 Executive Performance Incentive Plan (as amended and
restated, effective January 1, 2009) [filed as Exhibit 10.15 to Massey’s
current report on Form 8-K filed December 24, 2008 and
incorporated by reference]
10.12
Massey
Energy Company 2006 Stock and Incentive Compensation Plan (as amended and
restated, effective January 1, 2009) [filed as Exhibit 10.16 to Massey’s
current report on Form 8-K filed December 24, 2008 and incorporated by
reference]
10.13
Form
of Non-Employee Director Initial Restricted Stock Award Agreement under
the Massey Energy Company 2006 Stock and Incentive Compensation Plan
[filed as Exhibit 10.2 to Massey’s current report on Form 8-K filed
December 24, 2008 and incorporated by reference]
10.14
Form
of Non-Employee Director Initial Restricted Unit Award Agreement under the
Massey Energy Company 2006 Stock and Incentive Compensation Plan [filed as
Exhibit 10.3 to Massey’s current report on Form 8-K filed December 24,2008 and incorporated by reference]
10.15
Form
of Non-Employee Director Annual Restricted Stock Award Agreement under the
Massey Energy Company 2006 Stock and Incentive Compensation Plan [filed as
Exhibit 10.4 to Massey’s current report on Form 8-K filed December 24,2008 and incorporated by reference]
10.16
Form
of Non-Employee Director Annual Stock Option Award Agreement under the
Massey Energy Company 2006 Stock and Incentive Compensation Plan [filed as
Exhibit 10.2 to Massey’s current report on Form 8-K filed February 23,2009 and incorporated by
reference]
101
Exhibit
No.
Description
10.17
Form
of stock option agreement under the Massey Energy Company 2006 Stock and
Incentive Compensation Plan [filed as Exhibit 10.3 to Massey’s current
report on Form 8-K filed November 14, 2008 and incorporated by
reference]
10.18
Form
of restricted stock agreement under the Massey Energy Company 2006 Stock
and Incentive Compensation Plan [filed as Exhibit 10.4 to Massey’s current
report on Form 8-K filed November 14, 2008 and incorporated by
reference]
10.19
Form
of restricted unit agreement under the Massey Energy Company 2006 Stock
and Incentive Compensation Plan [filed as Exhibit 10.5 to Massey’s current
report on Form 8-K filed November 14, 2008 and incorporated by
reference]
10.20
Form
of cash incentive award agreement based on earnings before taxes under the
Massey Energy Company 2006 Stock and Incentive Compensation Plan [filed as
Exhibit 10.6 to Massey’s current report on Form 8-K filed November 14,2008 and incorporated by reference]
10.21
Form
of cash incentive award agreement based on earnings before interest,
taxes, deprecation and amortization under the Massey Energy Company 2006
Stock and Incentive Compensation Plan [filed as Exhibit 10.7 to Massey’s
current report on Form 8-K filed November 14, 2008 and incorporated by
reference]
A.T.
Massey Coal Company, Inc. Supplemental Benefit Plan (as amended and
restated as of January 1, 2009) [filed as Exhibit 10.20 to Massey’s
current report on Form 8-K filed December 24, 2008 and incorporated by
reference]
10.24
Massey
Executive Deferred Compensation Program (as amended and restated as of
January 1, 2009) [filed as Exhibit 10.17 to Massey’s current report on
Form 8-K filed December 24, 2008 and incorporated by
reference]
10.25
A.T.
Massey Coal Company, Inc. Executive Deferred Compensation Plan (as amended
and restated as of January 1, 2009) [filed as Exhibit 10.19 to Massey’s
current report on Form 8-K filed December 24, 2008 and incorporated by
reference]
10.26
Massey
Energy Company Executive Physical Program [filed as Exhibit 10.3 to
Massey’s annual report on Form 10-K for the fiscal year ended October 31,2000 and incorporated by reference]
10.27
Massey
Executives’ Supplemental Benefit Plan (as amended and restated effective
January 1, 2009) [filed as Exhibit 10.13 to Massey’s current report on
Form 8-K filed December 24, 2008 and incorporated by
reference]
10.28
Massey
Executives’ Supplemental Benefit Plan Agreement (effective as of January1, 2005) between Massey and Don L. Blankenship [filed as Exhibit 10.2 to
Massey’s current report on Form 8-K filed January 5, 2006 and incorporated
by reference]
10.29
Letter
Agreement dated November 13, 2007, between Massey Energy Company and Don
L. Blankenship [filed as Exhibit 10.32 to Massey’s annual report on Form
10-K filed February 29, 2008 and incorporated by
reference]
10.30
Letter
Agreement,
dated December 23, 2008, amending and restating Appendix A to the Letter
Agreement, originally dated November 13, 2007, as amended and
restated effective January 1, 2009, between Massey Energy Company and Don
L. Blankenship [filed as Exhibit 10.11 to Massey’s current report on Form
8-K filed December 24, 2008 and incorporated by
reference]
10.31
Retention
and Employment Agreement as amended and restated, effective January 1,2009, between Massey Energy Company and John Christopher Adkins [filed as
Exhibit 10.10 to Massey’s current report on Form 8-K filed December 24,2008 and incorporated by reference]
10.32
Employment
Agreement as amended and restated, effective January 1, 2009 between
Massey Energy Company and Michael K. Snelling [filed as Exhibit 10.12 to
Massey’s current report on Form 8-K filed December 24, 2008 and
incorporated by reference]
10.33
Special
Successor and Development Retention Program between Fluor Corporation and
Don L. Blankenship dated as of September 1998 [filed as Exhibit 10.21 to
Fluor’s annual report on Form 10-K for the fiscal year ended October 31,1998 and incorporated by reference]
10.34
Amendment
to Special Successor and Development Retention Program between Massey
(formerly Fluor Corporation) and Don L. Blankenship, effective January 1,2009 [filed as Exhibit 10.23 to Massey’s current report on Form 8-K filed
December 24, 2008]
10.35
Employment
and Change in Control Agreement dated November 10, 2008 between Massey
Energy Company and Baxter F. Phillips, Jr. [filed as Exhibit 10.2 to
Massey’s current report on Form 8-K filed November 14, 2008 and
incorporated by reference]
102
Exhibit
No.
Description
10.36
Form
of Change in Control Severance Agreement for Tier 1 Participants [filed
herewith]
10.37
Form
of Change in Control Severance Agreement for Tier 2 Participants [filed
herewith]
10.38
Form
of Change in Control Severance Agreement for Tier 3 Participants [filed
herewith]
10.39
Change
in Control Severance Agreement (as amended and restated) dated as of
December 23, 2008 between Massey Energy Company and Don L. Blankenship
[filed as Exhibit 10.24 to Massey’s current report on Form 8-K filed
December 24, 2008 and incorporated by reference]
10.40
Change
in Control Severance Agreement (as amended and restated) dated as of
December 23, 2008 between Massey Energy Company and J. Christopher Adkins
[filed as Exhibit 10.25 to Massey’s current report on Form 8-K filed
December 24, 2008 and incorporated by reference]
10.41
Change
in Control Severance Agreement (as amended and restated) dated as of
December 23, 2008 between Massey Energy Company and Eric B. Tolbert [filed
as Exhibit 10.26 to Massey’s current report on Form 8-K filed December 24,2008 and incorporated by reference]
10.42
Change
in Control Severance Agreement (as amended and restated) dated as of
December 23, 2008 between Massey Energy Company and Michael K. Snelling
[filed as Exhibit 10.27 to Massey’s current report on Form 8-K filed
December 24, 2008 and incorporated by reference]
Massey
Energy Company 2009 Bonus Program as reported on Massey’s current report
on Form 8-K [filed November 14, 2008 and incorporated by
reference]
10.45
Base
salary amounts set for Massey’s named executive officers as reported on
Massey’s current report on Form 8-K [filed November 14, 2008 and
incorporated by reference]
10.46
Massey
Energy Company Non-Employee Directors
Compensation Summary (as amended and restated effective February17, 2009) [filed as Exhibit 10.1 to Massey’s current report on Form 8-K
filed February 23, 2009 and incorporated by reference]
10.47
Massey
Energy Company Stock Plan for Non-Employee Directors (as amended and
restated, effective January 1, 2009) [filed as Exhibit 10.21 to Massey’s
current report on Form 8-K filed December 24, 2008 and incorporated by
reference]
10.48
Massey
Energy Company 1997 Restricted Stock Plan for Non-Employee Directors (as
amended and restated, effective January 1, 2009) [filed as Exhibit 10.22
to Massey’s current report on Form 8-K filed December 24, 2008 and
incorporated by reference]
10.49
Massey
Energy Company Deferred Directors’ Fees Program (amended and restated,
effective January 1, 2009) [filed as Exhibit 10.18 to Massey’s current
report on Form 8-K filed December 24, 2008 and incorporated by
reference]
10.50
Distribution
Agreement between Fluor Corporation and Massey Energy Company dated as of
November 30, 2000 [filed as Exhibit 10.1 to Massey’s current report on
Form 8-K filed December 15, 2000 and incorporated by this
reference]
10.51
Tax
Sharing Agreement between Fluor Corporation, Massey Energy Company and
A.T. Massey Coal Company, Inc. dated as of November 30, 2000 [filed as
Exhibit 10.2 to Massey’s current report on Form 8-K filed December 15,2000 and incorporated by this reference]
16.1
Letter
from Arnett and Foster to the Securities and Exchange Commission, dated
November 16, 2007 [filed as Exhibit 16.1 to Massey’s current report on
Form 8-K filed November 17, 2007 and incorporated by
reference]
Consent
of Independent Registered Public Accounting Firm [filed
herewith]
24
Manually
signed Powers of Attorney executed by Massey directors [filed
herewith]
31.1
Certification
of Chief Executive Officer, as adopted pursuant to Section 302 of the
Sarbanes-Oxley Act of 2002 [filed herewith]
31.2
Certification
of Chief Financial Officer, as adopted pursuant to Section 302 of the
Sarbanes-Oxley Act of 2002 [filed herewith]
32.1
Certification
of Chief Executive Officer pursuant to 18 U.S.C., Section 1350, as adopted
pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 [furnished
herewith]
32.2
Certification
of Chief Financial Officer pursuant to 18 U.S.C., Section 1350, as adopted
pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 [furnished
herewith]
103
SIGNATURES
Pursuant
to the requirements of Section 13 or 15(d) of the Securities Exchange Act of
1934, the registrant has duly caused this report to be signed on its behalf by
the undersigned, thereunto duly authorized.
Pursuant
to the requirements of the Securities Exchange Act of 1934, this report has been
signed below by the following persons on behalf of the registrant and in the
capacities and on the dates indicated.
Manually
signed Powers of Attorney authorizing Eric B. Tolbert., Richard R. Grinnan
and Jeffrey M. Jarosinski, and each of them, to sign the annual report on
Form 10-K for the fiscal year ended December 31, 2008 and any amendments
thereto as attorneys-in-fact for certain directors and officers of the
registrant are included herein as Exhibits
24.