UNITED
STATES
SECURITIES
AND EXCHANGE COMMISSION
WASHINGTON,
D.C. 20549
FORM
10-K
(Mark
One)
x
|
ANNUAL
REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF
1934
|
OR
¨
|
TRANSITION
REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF
1934
|
For
the transition period from
to
MASSEY
ENERGY COMPANY
(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, 2007, was $2,162,792,929 based on the last sales price
reported that date on the New York Stock Exchange of $26.65 per share. In
determining this figure, the Registrant has assumed that all of its directors
and executive officers are affiliates. Such assumptions should not be deemed to
be conclusive for any other purpose.
Common
Stock, $0.625 par value, outstanding as of February 15, 2008 — 80,491,644
shares.
Part
III incorporates certain information by reference from the registrant’s
definitive proxy statement for the 2008 Annual Meeting of Shareholders, which
proxy statement will be filed no later than 120 days after the close of the
registrant’s fiscal year ended December 31, 2007.
Forward
Looking Statements
From time
to time, Massey Energy Company, which includes its direct and wholly owned
subsidiary, A.T. Massey Coal Company, Inc, and its direct and indirect wholly
owned subsidiaries (“we,” “our,” “us”), makes certain comments and disclosures
in reports, including this report, or through statements made by our officers
that may be forward-looking in nature. Examples include statements related to
our future outlook, anticipated capital expenditures, projected cash flows and
borrowings, and sources of funding. We caution readers that forward-looking
statements, including disclosures that use words such as “believe,”
“anticipate,” “expect,” “estimate,” “intend,” “may,” “plan,” “project,” “will”
and similar statements are subject to certain risks, trends and uncertainties
that could cause actual cash flows, results of operations, financial condition,
cost reductions, acquisitions, dispositions, financing transactions, operations,
expansion, consolidation and other events to differ materially from the
expectations expressed or implied in such forward-looking statements. Any
forward-looking statements are also subject to a number of assumptions
regarding, among other things, future economic, competitive and market
conditions. These assumptions are based on facts and conditions, as they exist
at the time such statements are made as well as predictions as to future facts
and conditions, the accurate prediction of which may be difficult and involve
the assessment of circumstances and events beyond our control. We disclaim any
obligation to update these forward-looking statements unless required by
securities law, and we caution the reader not to rely on them
unduly.
We have
based any forward-looking statements we have made on our current expectations
and assumptions about future events and circumstances that are subject to risks,
uncertainties and contingencies that could cause results to differ materially
from those discussed in the forward-looking statements, including, but not
limited to:
(i)
|
|
our
cash flows, results of operation or financial
condition;
|
(ii)
|
|
the
consummation of acquisition, disposition or financing transactions and the
effect thereof on our business;
|
(iii)
|
|
governmental
policies and regulatory actions affecting the coal
industry;
|
(iv)
|
|
legal
and administrative proceedings, settlements, investigations and claims and
the availability of insurance coverage related thereto;
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(v)
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|
weather
conditions or catastrophic weather-related damage;
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(vi)
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|
our
ability to produce coal 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)
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|
the
availability of transportation for our produced coal;
|
(x)
|
|
the
expansion of 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
market demand for coal, electricity and steel;
|
(xiv)
|
|
concerns
about the environmental impact of coal 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, at home and
abroad;
|
(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)
|
|
future
economic or capital market conditions and foreign currency
fluctuations;
|
(xxii)
|
|
the
availability and costs of credit, surety bonds and letters of credit that
we require;
|
(xxiii)
|
|
the
lack of insurance against all potential operating
risks;
|
(xxix)
|
|
our
assumptions and projections regarding pension and other post-retirement
benefit liabilities;
|
(xxx)
|
|
our
interpretation and application of accounting literature to mining specific
issues; and
|
(xxxi)
|
|
the
successful implementation of our strategic plans and objectives, including
our announced expansion
plans.
|
Any forward-looking statements should
be considered in context with the various disclosures made by us about our
businesses, including without limitation the risk factors more specifically
described below in Item 1A. Risk Factors of this Annual Report on Form 10-K. We
are including this cautionary statement in this document to make applicable and
take advantage
of the safe harbor provisions of the Private Securities Litigation Reform Act of
1995 for any forward-looking statements made by, or on behalf, of
us.
2007 ANNUAL REPORT ON FORM
10-K
TABLE
OF CONTENTS
|
|
|
|
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Page
|
PART I
|
|
|
Item
1.
|
Business
|
1
|
Item
1A.
|
Risk
Factors
|
22
|
Item
1B.
|
Unresolved
Staff Comments
|
28
|
Item
2.
|
Properties
|
29
|
Item
3.
|
Legal
Proceedings
|
29
|
Item
4.
|
Submission
of Matters to a Vote of Security Holders
|
30
|
|
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|
PART
II
|
|
|
Item
5.
|
Market
for Registrant’s Common Equity, Related Stockholder Matters and Issuer
Purchases of Equity Securities
|
31
|
Item
6.
|
Selected
Financial Data
|
33
|
Item
7.
|
Management’s
Discussion and Analysis of Financial Condition and Results of
Operations
|
35
|
Item
7A.
|
Quantitative
and Qualitative Disclosures about Market Risk
|
47
|
Item
8.
|
Financial
Statements and Supplementary Data
|
49
|
Item
9.
|
Changes
in and Disagreements with Accountants on Accounting and Financial
Disclosure
|
84
|
Item
9A.
|
Controls
and Procedures
|
84
|
Item
9B.
|
Other
Information
|
85
|
|
|
|
PART III
|
|
|
Item
10.
|
Directors,
Executive Officers and Corporate Governance
|
86
|
Item
11.
|
Executive
Compensation
|
87
|
Item
12.
|
Security
Ownership of Certain Beneficial Owners and Management and Related
Stockholder Matters
|
88
|
Item
13.
|
Certain
Relationships and Related Transactions, and Director
Independence
|
88
|
Item
14.
|
Principal
Accountant Fees and Services
|
88
|
|
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PART IV
|
|
|
Item
15.
|
Exhibits
and Financial Statement Schedules
|
88
|
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SIGNATURES
|
93
|
Annual
Shareholders Meeting
Our 2008
Annual Meeting of Shareholders will be held at 9:00 a.m. EDT on Tuesday, May 13,
2008 at The Jefferson Hotel, 101 West Franklin Street, Richmond, Virginia
23220.
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. As measured by 2007
revenue, Energy Ventures Analysis, Inc. (“EVA”) ranks us as the fourth largest
United States coal company in terms of coal revenue. We are the largest coal
company in Central Appalachia, our primary region of operation, in terms of
revenue, tons produced and total coal reserves.
We
produce, process and sell bituminous coal of various steam and metallurgical
grades, primarily of a low sulfur content, through our 22 processing and
shipping centers (“Resource Groups”), many of which receive coal from multiple
mines. At January 31, 2008, we operated 47 mines, including 35 underground (one
of which employs both room and pillar and longwall mining) and 12 surface (with
eight highwall miners in operation) in West Virginia, Kentucky and
Virginia. The number of mines that we operate may vary from time to
time depending on a number of factors, including the existing demand for and
price of coal, exhaustion of economically recoverable reserves and availability
of experienced labor.
Customers
for our steam coal product include primarily electric power utility companies
who use our coal as fuel for their steam-powered
generators. Customers for our metallurgical coal include primarily
steel producers who use our coal to produce coke, which is in turn used as a raw
material in the steel manufacturing process.
Key
statistics for 2007 include:
|
·
|
Produced
coal revenues increased by 8% to $2.1 billion on produced coal sales of
39.9 million tons.
|
|
·
|
Net
income increased by 130% to $94.1
million.
|
|
·
|
Reserve
base of 2.3 billion tons.
|
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 is
the second most widely used form of energy in the United
States, accounting for nearly one-fourth of the nation’s total energy
consumption, according to the BP Statistical Review of World Energy (“BP”), June
2007. In 2006, coal was the fuel source of 50% of the electricity generated
nationwide, as reported by the Energy Information Administration (“EIA”), a
statistical agency of the United States Department of Energy.
The
United States is the second largest coal producer in the world, exceeded only by
China. Other leading coal producers include India, Australia, South Africa,
Russia and Indonesia. The United States has the largest coal reserves in the
world, with proved reserves totaling 247 billion tons. Russia ranks second in
proved coal reserves with 157 billion tons, followed by China with 115 billion
tons, according to BP.
United
States coal reserves are more plentiful than oil or natural gas with 234 years
of supply at current consumption rates. Proved United States reserves of oil
amount to 12 years of supply at current production
rates and proved United States reserves of natural gas amount to 11 years of
supply at current levels of consumption, as reported by the BP
study.
United
States coal production has more than doubled over the last 40 years. In 2006,
total United
States coal production, as estimated by the EIA, was 1.2 billion tons.
The primary producing regions by tons were as follows:
|
|
|
|
Region
|
|
% of Total
|
|
Powder
River Basin
|
|
|
41 |
% |
Central
Appalachia
|
|
|
20 |
% |
West
(other than Powder River Basin)
|
|
|
13 |
% |
Midwest
|
|
|
13 |
% |
Northern
Appalachia
|
|
|
12 |
% |
All
other
|
|
|
1 |
% |
|
|
|
|
|
Total
|
|
|
100 |
% |
|
|
|
|
|
The EIA
estimated that approximately 69% of United States coal was produced by surface
mining methods. The remaining 31% was produced by underground mining methods,
which include room and pillar mining and longwall mining (more fully described
in Item 1. Business, under the heading “Mining Methods”).
Coal is
used in the United States by utilities to generate electricity, by steel
companies to make steel products, and by a variety of industrial users to
produce heat and to power foundries, cement plants, paper mills, chemical plants
and other manufacturing and processing facilities. Significant quantities of
coal are also exported from both East and Gulf Coast terminals. The breakdown of
2006 United
Statescoal consumption, as estimated by the EIA, is as
follows:
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. Platts, which provides global
commodity news and information, estimated the average total production costs of
electricity, using coal and competing generation alternatives in 2006 as
follows:
|
|
|
|
Electricity
Generation Source
|
|
Cost per million
Kilowatt
Hours
|
|
Oil
|
|
$ |
14.69 |
|
Natural
Gas
|
|
$ |
7.97 |
|
Coal
|
|
$ |
2.19 |
|
Nuclear
|
|
$ |
1.84 |
|
There are
factors other than fuel cost that influence each utility’s choice of electricity
generation mode, including facility construction cost, access to fuel
transportation infrastructure, environmental restrictions, and other factors.
The breakdown of United States electricity generation by fuel source in 2006, as
estimated by EIA, is as follows:
|
|
|
|
Electricity
Generation Source
|
|
%
of Total
Electricity Generation
|
|
Coal
|
|
|
50 |
% |
Nuclear
|
|
|
20 |
% |
Natural
Gas
|
|
|
19 |
% |
Hydroelectric
|
|
|
7 |
% |
Oil
and other (solar, wind, etc.)
|
|
|
4 |
% |
Total
|
|
|
100 |
% |
|
|
|
|
|
Demand
for electricity has historically been driven by United States economic growth
but it can fluctuate from year to year depending on weather patterns. In 2006,
electricity consumption in the United States increased
0.2%but the average growth rate in the past decade was approximately
1.5%
per year according to EIA estimates. Because coal-fired generation is used in
most cases to meet base load requirements, coal consumption has generally grown
at the pace of electricity demand growth.
According
to the World Coal Institute (“WCI”), in 2006 the United States ranked seventh
among worldwide exporters of coal. Australia was the largest exporter, with
other major exporters including Indonesia, China, South Africa, Russia, Columbia
and Canada. According to EVA, United States exports increased by 19% from 2006
to 2007. The usage breakdown for 2007
United States exports of 59 million tons was 45% for electricity generation and
55% for steel production. In 2007, United States coal exports were shipped to
more than 30 countries. The largest purchaser of United States exported utility
coal in 2007 continued to be Canada, which took 14.6 million tons or 55% of
total utility coal exports. This was down 4% compared to the 15.2 million tons
exported to Canada in 2006. Overall steam coal exports increased 22% in 2007
compared to 2006. The
largest purchasers of United States exported metallurgical coal were Brazil,
which imported approximately 6.5 million tons, or 20%, and Canada, which
imported 3.7 million tons, or 12%. In total, metallurgical coal exports
increased 16% in 2007 compared to 2006.
Depending
on the relative strength of the United States dollar versus currencies in other
coal producing regions of the world, United States producers may export more or
less coal into foreign countries as they compete on price with other foreign
coal producing sources. Likewise, the domestic coal market may be impacted due
to the relative strength of the United States dollar to other currencies, as
foreign sources could be cost-advantaged based on a coal producing region’s
relative currency position. During 2007, the United States dollar weakened,
making imported coal less competitive with United States produced coal, and
positively impacting the competitiveness of United
States exports in some overseas markets.
From 2003
to February 2008, the global marketplace for coal experienced swings in the
demand/supply balance. In periods of supply shortfall, as
occurred from 2003 to early 2006 and again in late 2007 through February 2008,
the prices for coal reached record highs in the United States. Increased
worldwide demand has been primarily driven by higher prices for oil and natural
gas and economic expansion, particularly in China, India and elsewhere in Asia.
At the same time, infrastructure and regulatory limitations in China contributed
to a tightening of worldwide coal supply, affecting global prices of coal. The
growth in China and India caused an increase in worldwide demand for raw
materials and a disruption of expected coal exports from China to Japan, Korea
and other countries.
Metallurgical
grade coal is distinguished by special quality characteristics that include high
carbon content, volatile matter, low expansion pressure, low sulfur content, and
various other chemical attributes. High vol met coal is also high in heat
content (as measured in Btus), and therefore is desirable to utilities as fuel
for electricity generation. Consequently, high vol met coal producers have the
ongoing opportunity to select the market that provides maximum revenue and
profitability. The premium price offered by steel makers for the metallurgical
quality attributes is typically higher than the price offered by utility coal
buyers that value only the heat content. The primary concentration of United
States metallurgical coal reserves is located in the Central Appalachian region.
EVA estimates that the Central Appalachian region supplied 89% of domestic
metallurgical coal and 73% of United States exported metallurgical coal during
2006.
For
utility coal buyers, the primary goal is to maximize heat content, with other
specifications like ash content, sulfur content, and size varying considerably
among different customers. Low sulfur coals, such as those produced in the
western United States and in Central Appalachia, generally demand a higher price
due to restrictions on sulfur emissions imposed by the Clean Air Act of 1963
(“Clean Air Act”) and the volatility in SO2 allowance
prices that occurred in recent years when the
demand
for all specifications of coal increased. SO2 allowances
permit utilities to emit a higher level of SO2 than
otherwise required under the Clean Air Act regulations. The demand and premium
price for low sulfur coal is expected to diminish as more utilities install
scrubbers at their coal-fired plants.
Coal
shipped for North American consumption is typically sold at the mine loading
facility with transportation costs being borne by the purchaser. Offshore export
shipments are normally sold at the ship-loading terminal, with the purchaser
paying the ocean freight. According to the National Mining Association (“NMA”),
approximately two-thirds of United States coal production in recent years was
shipped via railroads. Final delivery to consumers often involves more than one
transportation mode. A significant portion of United States production is
delivered to customers via barges on the inland waterway system and ships loaded
at Great Lakes ports.
Neither
we nor any of our subsidiaries are affiliated with or have any investment in BP,
EIA, EVA, Platts or WCI. We are a member of the NMA.
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 mining machines cut
three to nine entries into the coal bed and connect them by driving crosscuts,
leaving a series of rectangular pillars, or columns of coal, to help support the
mine roof and control the flow of air. Generally, openings are driven 20 feet
wide and the pillars are 40 to 100 feet wide. As mining advances, a grid-like
pattern of entries and pillars is formed. When mining advances to the end of a
panel, retreat mining may begin. In retreat mining, as much coal as is feasible
is mined from the pillars that were created in advancing the panel, allowing the
roof to fall upon retreat. When retreat mining is completed to the mouth of the
panel, the mined panel is abandoned.
In
longwall mining (which is a type of underground mining), a shearer (cutting
head) moves back and forth across a panel of coal typically about 1,000 feet in
width, cutting a slice approximately 3.5 feet deep. The cut coal falls onto a
flexible conveyor for removal. Longwall mining is performed under hydraulic roof
supports (shields) that are advanced as the seam is cut. The roof in the mined
out areas falls as the shields advance.
Surface
mining is used to extract coal deposits found close to the surface. This method
involves removal of overburden (earth and rock covering coal) with heavy earth
moving equipment, including large shovels and draglines, and explosives,
followed by extraction of coal from coal seams. After extraction of coal,
disturbed parcels of land are reclaimed by replacing overburden and
reestablishing vegetation and plant life.
Highwall
mining is used in connection with surface mining. A highwall mining system
consists of a remotely controlled continuous mining machine, which extracts coal
and conveys it via augers or belt conveyors to the portal. The cut is typically
a rectangular, horizontal opening in the highwall (the unexcavated face of
exposed overburden and coal in a surface mine) 11-feet wide and reaching depths
of up to 1,000 feet. Multiple, parallel openings are driven into the highwall,
separated by narrow pillars that extend the full depth of the hole.
Use of
continuous mining machines in the room and pillar method of underground mining
represented approximately 41% of our 2007 coal production. Production from
underground longwall mining operations constituted approximately 6% of our 2007
production. Surface mining represented approximately 47% of our 2007 coal
production. Surface mines also use highwall mining systems to produce coal from
high overburden areas. Highwall mining represented approximately 6% of our 2007
coal production.
Mining
Operations
We
currently have 22 distinct Resource Groups, including sixteen in West Virginia,
five in Kentucky and one in Virginia. These complexes blend, process and ship
coal that is produced from one or more mines, with a single complex handling the
coal production of as many as seven distinct underground or surface mines. Our
mines have been developed at strategic locations in close proximity to our
preparation plants and rail shipping facilities.
We operate
solely in the Central Appalachian region, which is the principal source of low
sulfur bituminous coal in the United
States, used for power generation, metallurgical coke production and
industrial boilers. Central Appalachian coal accounted for 20%
of 2007 United States coal production according to EIA.
The
following map provides the location of our operations within the Central
Appalachian region:
The
following table provides key operational information on our Resource Groups in
2007:
Resource Group
Name
|
Location
(County)
|
Active/
Inactive
|
|
Mine
Type
|
|
|
Active
Mine Count (4)
|
|
Mining
Equipment
|
Transportation
|
|
2007
Production (1)
|
|
|
2007
Shipments (2)
|
|
Year
Established or Acquired
|
|
|
|
|
|
|
|
|
|
|
|
|
(Thousands
of Tons)
|
|
|
West
Virgina Resource Groups
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Black
Castle
|
Boone
|
Active
|
|
|
S |
|
|
|
1 |
|
HW
|
truck,
barge
|
|
|
3,549 |
|
|
|
2,104 |
|
1987
|
Delbarton
|
Mingo
|
Active
|
|
|
U |
|
|
|
1 |
|
|
NS
|
|
|
801 |
|
|
|
905 |
|
1999
|
Edwight
|
Raleigh
|
Active
|
|
|
S/U |
|
|
|
2 |
|
HW
|
CSX
|
|
|
1,572 |
|
|
|
- |
|
2003
|
Elk
Run
|
Boone
|
Active
|
|
|
U |
|
|
|
5 |
|
LW
|
CSX
|
|
|
2,274 |
|
|
|
1,398 |
|
1978
|
Endurance
|
Boone
|
Active
|
|
|
S |
|
|
|
1 |
|
HW
|
CSX
|
|
|
1,368 |
|
|
|
727 |
|
2001
|
Green
Valley
|
Nicholas
|
Active
|
|
|
U |
|
|
|
2 |
|
|
CSX
|
|
|
759 |
|
|
|
808 |
|
1996
|
Guyandotte
(3)
|
Wyoming
|
Active
|
|
|
U |
|
|
|
1 |
|
|
NS
|
|
|
14 |
|
|
|
14 |
|
2006
|
Independence
|
Boone
|
Active
|
|
|
U |
|
|
|
3 |
|
LW
|
CSX
|
|
|
1,755 |
|
|
|
4,159 |
|
1994
|
Logan
County
|
Logan
|
Active
|
|
|
S/U |
|
|
|
6 |
|
HW
|
CSX
|
|
|
3,783 |
|
|
|
3,722 |
|
1998
|
Mammoth
|
Kanawha
|
Active
|
|
|
U |
|
|
|
3 |
|
|
barge
|
|
|
1,431 |
|
|
|
2,039 |
|
2004
|
Marfork
|
Raleigh
|
Active
|
|
|
U |
|
|
|
7 |
|
|
CSX
|
|
|
3,817 |
|
|
|
6,656 |
|
1993
|
Nicholas
Energy
|
Nicholas
|
Active
|
|
|
S/U |
|
|
|
2 |
|
HW
|
NS
|
|
|
3,362 |
|
|
|
3,039 |
|
1997
|
Progress
|
Boone
|
Active
|
|
|
S |
|
|
|
1 |
|
|
CSX
|
|
|
5,125 |
|
|
|
4,529 |
|
1998
|
Rawl
|
Mingo
|
Active
|
|
|
U |
|
|
|
2 |
|
|
NS
|
|
|
1,044 |
|
|
|
104 |
|
1974
|
Republic
Energy
|
Raleigh
|
Active
|
|
|
S |
|
|
|
1 |
|
|
truck
|
|
|
1,564 |
|
|
|
1,150 |
|
2004
|
Stirrat
|
Logan
|
Active
|
|
|
S |
|
|
|
1 |
|
|
CSX
|
|
|
1,359 |
|
|
|
1,890 |
|
1993
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Kentucky
Resource Groups
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Coalgood
Energy
|
Harlan
|
Inactive
|
|
|
|
|
|
|
|
|
|
CSX
|
|
|
2 |
|
|
|
13 |
|
2005
|
Long
Fork
|
Pike
|
Active
|
|
|
|
|
|
|
|
|
|
NS
|
|
|
- |
|
|
|
1,641 |
|
1991
|
Martin
County
|
Martin
|
Inactive
|
|
|
|
|
|
|
|
|
|
NS
|
|
|
242 |
|
|
|
270 |
|
1969
|
New
Ridge
|
Pike
|
Active
|
|
|
|
|
|
|
|
|
|
CSX
|
|
|
- |
|
|
|
504 |
|
1992
|
Sidney
|
Pike
|
Active
|
|
|
S/U |
|
|
|
7 |
|
HW
|
NS
|
|
|
4,932 |
|
|
|
3,457 |
|
1984
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Virginia
Resource Group
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Knox
Creek
|
Tazewell
|
Active
|
|
|
U |
|
|
|
1 |
|
|
NS
|
|
|
706 |
|
|
|
724 |
|
1997
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
|
|
|
|
|
47 |
|
|
|
|
|
39,459 |
|
|
|
39,853 |
|
|
__________________________
(1)
|
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.
|
(2)
|
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.
|
(3)
|
Previously
known as Kepler.
|
|
HW
– highwall miners operated in conjunction with surface
mines
|
|
NS –
Norfolk Southern Railway Company
|
The
following descriptions of the Resource Groups are current as of January 31,
2008.
West
Virginia Resource Groups
Black Castle. The Black
Castle complex includes a large surface mine, two highwall miners, the Homer III
direct-ship loadout, a stoker plant, and the Omar preparation plant. Some of the
surface mine coal is trucked to the stoker plant where the coal is crushed and
screened. The stoker product is trucked to river docks for barge delivery or
trucked directly to customers. A portion
of the coal is transported to the Omar plant via an underground belt conveyor
system, where it is crushed and
shipped
to customers or, if the coal needs processing, it is belted to the preparation
plant at the Independence Resource Group for processing and shipment. The Omar
preparation plant was not utilized for processing coal in 2006. The direct-ship
facility at the preparation plant can crush 500 tons per hour and the
preparation plant can process 800 tons per hour. The Omar preparation plant
serves CSX rail system customers with unit train shipments of up to 110
railcars. Coal is also trucked to the Homer III loadout where it is crushed and
shipped to customers by rail, trucked to river docks for barge delivery, or
trucked directly to customers. The Homer III loadout serves CSX rail system
customers with unit train shipments of up to 100
railcars.
Delbarton. The Delbarton
complex includes one underground room and pillar mine and a preparation plant.
Production from the mine is transported to the Delbarton preparation plant via
overland conveyor. The Delbarton preparation plant also processes coal from two
surface mines of the Logan County Resource Group. The Delbarton preparation
plant can process 600 tons per hour. The clean coal product is shipped to
customers via the Norfolk Southern railway in unit trains of up to 110
railcars.
Edwight. The Edwight complex
includes one underground room and pillar mine, a surface mine, a highwall miner
and the Goals preparation plant. Production from all of the mines is transported
via conveyor system to the Goals preparation plant. The Goals preparation plant
can process 800 tons per hour. The rail loading facility serves CSX railway
customers with unit trains of up to 100 railcars.
Elk Run. The Elk Run complex
produces coal from four underground room and pillar mines and the Logans Fork
longwall. All of the room and pillar mines belt coal to the Elk Run preparation
plant, while the longwall belts coal to the preparation plant of the Marfork
Resource Group. Additionally, Elk Run processes coal produced by surface mines
of the Progress Resource Group and transported via underground conveyor system.
The Elk Run preparation plant has a processing capacity of 2,200 tons per hour.
Elk Run also operates a 200 ton per hour stoker facility that produces screened,
small dimension coal for certain of our industrial customers. Customer shipments
are loaded on the CSX rail system in unit trains of up to 150
railcars.
Endurance. The Endurance
complex includes a surface mine, highwall miner and a direct-ship loadout. A
portion of the production from the surface mine is loaded for shipment to
customers at the direct ship loadout and the remainder is trucked to a conveyor
system, which transports the coal to the preparation plant at the Independence
Resource Group for processing.
Green Valley. The Green
Valley complex includes two underground room and pillar mines and a preparation
plant. The Green Valley preparation plant, which has a processing capacity of
600 tons per hour, receives coal from the mines via trucks. The rail loading
facility services customers on the CSX rail system with unit train shipments of
up to 75 railcars.
Guyandotte. The Guyandotte
complex, formerly known as Kepler, includes one underground room and pillar
mine. The mine trucks coal to a third-party preparation plant for washing and
shipment to customers via the Norfolk Southern railway system.
Independence. The
Independence complex includes the Revolution longwall mine, two underground room
and pillar mines and a preparation plant. Production from the underground mines
is transported via overland conveyor system to the Independence preparation
plant. The Black Castle surface mine and highwall miner and the surface mine at
the Endurance Resource Group transport coal requiring processing to the
Independence preparation plant via conveyor system. The Independence plant has a
processing capacity of 2,200 tons per hour. Customers are served via rail
shipments on the CSX rail system in unit trains of up to 150
railcars.
Logan County. The Logan
County complex includes four surface mines, one highwall miner and two
underground room and pillar mines, plus the Bandmill preparation plant and the
Feats loadout, all on the CSX rail system. The surface mines and the highwall
miners deliver coal to the Bandmill plant via truck and conveyor system, while
both underground mines belt coal directly to this plant. The Feats loadout can
service customers via the CSX rail system with unit train shipments of up to 80
cars. The Bandmill preparation plant has a processing capacity of 1,800 tons per
hour. The Bandmill rail loading facility services customers via the CSX rail
system with unit train shipments of up to 150 railcars.
Mammoth. The Mammoth complex
operates three underground room and pillar mines and a preparation plant. Coal
is transported to the preparation plant, with two mines using on-highway trucks
and one mine using a conveyor system. The plant has a 1,200 tons per hour
processing facility capacity with barge loading capabilities on the upper
Kanawha River.
Marfork. The Marfork complex
includes seven underground room and pillar mines and a preparation plant.
Production from six of the mines is belted directly to the preparation plant via
conveyor while the remainder is trucked on private haul
roads to the preparation plant. The Marfork preparation plant has a
capacity of 2,400 tons per hour. Customers are served via the CSX rail system
with unit trains of up to 150 railcars.
Nicholas Energy. The Nicholas
Energy complex includes an underground room and pillar mine, a large surface
mine, two highwall miners and a preparation plant. Coal from the underground
mine is transported to the preparation plant for processing via conveyor system.
Coal from the highwall miners and the portion of surface mined coal requiring
processing is transported to the preparation plant using off-road trucks. Coal
not requiring processing is transported via off road trucks to a conveyor system
that moves the coal directly to a rail loadout facility. The plant has a
processing capacity of 1,200 tons per hour. Coal shipments are loaded into rail
cars for delivery via the Norfolk Southern railway in unit trains of up to 140
railcars, or are transported via on-highway trucks to the Mammoth Resource
Group’s barge loading facility.
Progress. The Progress
complex includes the large Twilight MTR surface mine. A dragline is also
utilized at the Twilight MTR surface mine. Production from the Twilight MTR
surface mine is transported via underground conveyor to the Elk Run Resource
Group for processing and rail shipment.
Rawl. The Rawl complex
includes two underground room and pillar mines and a preparation plant.
Production from the mines is transported via truck to the preparation plant of
the Stirrat Resource Group. The Rawl plant, which was idled in December 2006,
has a throughput capacity of 1,450 tons per hour. Customers are served via the
Norfolk Southern railway with unit trains of up to 150 railcars.
Republic Energy. The Republic
Energy complex consists of one surface mine. Direct-ship coal is trucked using
on-highway trucks to various docks on the Kanawha River for barge delivery to
customers and to the Marfork Resource Group for rail delivery to
customers. Coal requiring processing is trucked using on-highway
trucks to Mammoth Resource Group’s preparation plant for processing and barge
delivery to customers.
Stirrat. The Stirrat complex
includes one surface mine, a preparation plant and the Superior loadout. The
surface mine belts coal directly to two 12,500 ton silos at the Superior
loadout. The Superior loadout serves CSX railway customers with unit trains of
up to 100 railcars. The Stirrat preparation plant cleans coal from two adjacent
underground room and pillar mines of the Rawl Resource Group. The plant has a
rated capacity of 600 tons per hour. Customers are served via the CSX rail
system with unit trains of up to 100 railcars.
Coalgood Energy. The Coalgood
Energy complex, which was idled in January 2007, includes one surface mine and a
direct-ship loadout. When in operation, the coal is trucked off-road to the
loadout, which serves CSX railway customers with unit trains of up to 75
railcars. Although no firm plans have been made, we continue to
evaluate options for the complex, which may include a resumption of operations,
allowing it to remain idle or pursuing disposal alternatives.
Long Fork. The Long Fork
preparation plant processes coal produced by two underground room and pillar
mines of the Sidney Resource Group. All production is transported via conveyor
system to the Long Fork preparation plant for processing and shipping to
customers. The Long Fork plant has a rated capacity of 1,500 tons per hour. The
rail loading facility services customers on the Norfolk Southern railway with
unit trains of up to 150 railcars.
Martin County. The Martin
County complex, which was idled in January 2007, has historically produced coal
from underground and surface mines. Direct-ship coal production from the surface
mines was shipped to river docks via truck. Coal requiring processing was
transported by conveyor belt or truck to the preparation plant. Martin County’s
preparation plant has a throughput capacity of 1,500 tons per hour, although the
throughput capacity is limited due to decreased impoundment availability. The
coal from the preparation plant can be shipped either via the Norfolk Southern
railway in unit trains of up to 125 railcars or to river docks via
truck. Although no firm plans have been made, we continue to evaluate
options for the complex, which may include a resumption of operations, allowing
it to remain idle or pursuing disposal alternatives.
New Ridge. The New Ridge
complex loads clean coal that is transported via truck from the preparation
plant of the Sidney Resource Group and coal trucked directly from Sidney’s
surface mine. The New Ridge preparation plant has a capacity of 800 tons per
hour. The preparation plant is currently idle but may be reactivated from time
to time during 2008 as needed. All coal is loaded for shipment to customers via
the CSX rail system in unit trains of up to 100 railcars.
Sidney. The Sidney complex
includes six underground room and pillar mines, one surface mine, a highwall
miner and a preparation plant. Two of the underground mines transport coal via
underground conveyor system to the Long Fork Resource Group for processing and
shipment, and the remainder of the underground mines transport production via
underground conveyor system or truck to Sidney’s preparation plant. A portion of
the coal from Sidney’s preparation plant and coal from the surface mines are
trucked to the New Ridge Resource Group for loading into railroad cars. Sidney’s
preparation plant has
a
capacity of 1,500 tons per hour. The rail loading facility at the preparation
plant serves customers on the Norfolk Southern rail system with unit trains of
up to 140 railcars.
Knox Creek. The Knox Creek
complex includes one underground room and pillar mine and a preparation plant.
Production from the mine is belted by conveyor system to the preparation plant.
The preparation plant has a feed capacity of 650 tons per hour. The preparation
plant serves customers on the Norfolk Southern rail system with unit trains of
up to 100 railcars.
Coal
Reserves
We
estimate that, as of December 31, 2007, we had total recoverable reserves of
approximately 2.3 billion tons consisting of both proven and probable reserves.
“Reserves” are defined by the SEC Industry Guide 7 as that part of a mineral
deposit, which could be economically and legally extracted or produced at the
time of the reserve determination. “Recoverable” reserves means coal that is
economically recoverable using existing equipment and methods under federal and
state laws currently in effect. Approximately 1.5 billion tons of reserves are
classified as proven reserves. “Proven (measured) reserves” are defined by the
SEC Industry Guide 7 as reserves for which (a) quantity is computed from
dimensions revealed in outcrops, trenches, workings or drill holes; grade and/or
quality are computed from the results of detailed sampling and (b) the sites for
inspection, sampling and measurement are spaced so closely and the geologic
character is so well defined that size, shape, depth and mineral content of
reserves are well-established. The remaining 0.8 billion tons of our reserves
are classified as probable reserves. “Probable reserves” are defined by the SEC
Industry Guide 7 as reserves for which quantity and grade and/or quality are
computed from information similar to that used for proven (measured) reserves,
but the sites for inspection, sampling, and measurement are farther apart or are
otherwise less adequately spaced. The degree of assurance, although lower than
that for proven (measured) reserves, is high enough to assume continuity between
points of observation.
Information
about our reserves consists of estimates based on engineering, economic and
geological data assembled and analyzed by our internal engineers, geologists and
finance associates. Reserve estimates are updated annually using geologic data
taken from drill holes, adjacent mine workings, outcrop prospect openings and
other sources. Coal tonnages are categorized according to coal quality, seam
thickness, mineability and location relative to existing mines and
infrastructure. In accordance with applicable industry standards, proven
reserves are those for which reliable data points are spaced no more than 2,700
feet apart. Probable reserves are those for which reliable data points are
spaced 2,700 feet to 7,900 feet apart. Further scrutiny is applied using
geological criteria and other factors related to profitable extraction of the
coal. These criteria include seam height, roof and floor conditions, yield and
marketability.
As with
most coal-producing companies in Central Appalachia, the majority of our coal
reserves are controlled pursuant to leases from third party landowners. These
leases convey mining rights to the coal producer in exchange for a per ton or
percentage of gross sales price royalty payment to the lessor. However,
approximately 18% of our reserve holdings are owned and require no royalty or
per ton payment to other parties. Royalty expense for coal reserves from our
producing properties (owned and leased) was approximately 4.1% of Produced coal
revenue for the year ended December 31, 2007.
The
following table provides proven and probable reserve data by “status” (i.e.,
location, owned or leased, assigned or unassigned, etc.) as of December 31,
2007:
|
|
Resource
Group
|
Location
(2)
|
|
Total
|
|
|
Proven
|
|
|
Probable
|
|
|
Assigned
(3)
|
|
|
Unassigned
(3)
|
|
|
Owned
|
|
|
Leased
|
|
(In
Thousands of Tons)
|
|
West
Virginia
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Black
Castle
|
Boone
County
|
|
|
88,756 |
|
|
|
61,609 |
|
|
|
27,147 |
|
|
|
41,490 |
|
|
|
47,266 |
|
|
|
1,920 |
|
|
|
86,836 |
|
Delbarton
|
Mingo
County
|
|
|
286,747 |
|
|
|
120,442 |
|
|
|
166,305 |
|
|
|
141,249 |
|
|
|
145,498 |
|
|
|
25 |
|
|
|
286,722 |
|
Edwight
|
Raleigh
County
|
|
|
8,870 |
|
|
|
8,870 |
|
|
|
- |
|
|
|
8,870 |
|
|
|
- |
|
|
|
- |
|
|
|
8,870 |
|
Elk
Run
|
Boone
County
|
|
|
162,767 |
|
|
|
125,451 |
|
|
|
37,316 |
|
|
|
58,403 |
|
|
|
104,364 |
|
|
|
4,660 |
|
|
|
158,107 |
|
Endurance
|
Boone
County
|
|
|
25,126 |
|
|
|
25,126 |
|
|
|
- |
|
|
|
24,998 |
|
|
|
128 |
|
|
|
24,560 |
|
|
|
566 |
|
Green
Valley
|
Nicholas
County
|
|
|
7,135 |
|
|
|
7,135 |
|
|
|
- |
|
|
|
7,135 |
|
|
|
- |
|
|
|
- |
|
|
|
7,135 |
|
Guyandotte
|
Wyoming
County
|
|
|
43,603 |
|
|
|
15,266 |
|
|
|
28,337 |
|
|
|
- |
|
|
|
43,603 |
|
|
|
330 |
|
|
|
43,273 |
|
Independence
|
Boone
County
|
|
|
43,311 |
|
|
|
42,001 |
|
|
|
1,310 |
|
|
|
29,852 |
|
|
|
13,459 |
|
|
|
9,482 |
|
|
|
33,829 |
|
Logan
County
|
Logan
County
|
|
|
73,529 |
|
|
|
68,881 |
|
|
|
4,648 |
|
|
|
49,883 |
|
|
|
23,646 |
|
|
|
- |
|
|
|
73,529 |
|
Mammoth
|
Kanawha
County
|
|
|
87,558 |
|
|
|
67,224 |
|
|
|
20,334 |
|
|
|
74,244 |
|
|
|
13,314 |
|
|
|
42,844 |
|
|
|
44,714 |
|
Marfork
|
Raleigh
County
|
|
|
121,721 |
|
|
|
109,411 |
|
|
|
12,310 |
|
|
|
79,125 |
|
|
|
42,596 |
|
|
|
815 |
|
|
|
120,906 |
|
Nicholas
Energy
|
Nicholas
County
|
|
|
92,303 |
|
|
|
52,461 |
|
|
|
39,842 |
|
|
|
49,897 |
|
|
|
42,406 |
|
|
|
38,514 |
|
|
|
53,789 |
|
Progress
|
Boone
County
|
|
|
22,446 |
|
|
|
22,446 |
|
|
|
- |
|
|
|
22,446 |
|
|
|
- |
|
|
|
- |
|
|
|
22,446 |
|
Rawl
|
Mingo
County
|
|
|
96,369 |
|
|
|
68,600 |
|
|
|
27,769 |
|
|
|
59,270 |
|
|
|
37,099 |
|
|
|
1,333 |
|
|
|
95,036 |
|
Republic
Energy
|
Raleigh
County
|
|
|
38,209 |
|
|
|
34,387 |
|
|
|
3,822 |
|
|
|
38,209 |
|
|
|
- |
|
|
|
- |
|
|
|
38,209 |
|
Stirrat
|
Logan
County
|
|
|
5,293 |
|
|
|
3,476 |
|
|
|
1,817 |
|
|
|
412 |
|
|
|
4,881 |
|
|
|
- |
|
|
|
5,293 |
|
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
|
|
|
42,554 |
|
|
|
25,865 |
|
|
|
16,689 |
|
|
|
2,783 |
|
|
|
39,771 |
|
|
|
1,336 |
|
|
|
41,218 |
|
New
Ridge
|
Pike
County
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
Sidney
|
Pike
County
|
|
|
127,055 |
|
|
|
73,055 |
|
|
|
54,000 |
|
|
|
101,938 |
|
|
|
25,117 |
|
|
|
7,028 |
|
|
|
120,027 |
|
Virginia
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Knox
Creek
|
Tazewell
County
|
|
|
45,087 |
|
|
|
32,942 |
|
|
|
12,145 |
|
|
|
29,354 |
|
|
|
15,733 |
|
|
|
- |
|
|
|
45,087 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Subtotal
|
|
|
|
1,444,664 |
|
|
|
979,769 |
|
|
|
464,895 |
|
|
|
819,822 |
|
|
|
624,842 |
|
|
|
135,551 |
|
|
|
1,309,113 |
|
Land
Management Companies: (4)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Black
King
|
Boone
County, WV
|
|
|
32,666 |
|
|
|
32,666 |
|
|
|
- |
|
|
|
1,155 |
|
|
|
31,511 |
|
|
|
17,428 |
|
|
|
15,238 |
|
|
Raleigh
County, WV
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Boone
East
|
Boone
County, WV
|
|
|
132,145 |
|
|
|
96,131 |
|
|
|
36,014 |
|
|
|
6,180 |
|
|
|
125,965 |
|
|
|
64,721 |
|
|
|
67,424 |
|
|
Kanawha
County, WV
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Boone
West
|
Lincoln
County, WV
|
|
|
252,332 |
|
|
|
98,556 |
|
|
|
153,776 |
|
|
|
10,346 |
|
|
|
241,986 |
|
|
|
65,553 |
|
|
|
186,779 |
|
|
Logan
County, WV
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ceres
Land
|
Raleigh
County, WV
|
|
|
33,351 |
|
|
|
24,220 |
|
|
|
9,131 |
|
|
|
- |
|
|
|
33,351 |
|
|
|
- |
|
|
|
33,351 |
|
Duncan
Fork
|
Various
counties, PA
|
|
|
94,086 |
|
|
|
44,449 |
|
|
|
49,637 |
|
|
|
- |
|
|
|
94,086 |
|
|
|
79,907 |
|
|
|
14,179 |
|
Lauren
Land
|
Mingo
County, WV
|
|
|
181,247 |
|
|
|
119,729 |
|
|
|
61,518 |
|
|
|
11,175 |
|
|
|
170,072 |
|
|
|
18,011 |
|
|
|
163,236 |
|
|
Logan
County, WV
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Various
counties, KY
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
New
Market Land
|
Wyoming
County, WV
|
|
|
7,984 |
|
|
|
4,790 |
|
|
|
3,194 |
|
|
|
- |
|
|
|
7,984 |
|
|
|
102 |
|
|
|
7,882 |
|
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
|
|
|
|
779,696 |
|
|
|
440,851 |
|
|
|
338,845 |
|
|
|
28,856 |
|
|
|
750,840 |
|
|
|
269,776 |
|
|
|
509,920 |
|
Other
|
N/A
|
|
|
59,000 |
|
|
|
38,303 |
|
|
|
20,697 |
|
|
|
24,140 |
|
|
|
34,860 |
|
|
|
1,288 |
|
|
|
57,712 |
|
Total
|
|
|
|
2,283,360 |
|
|
|
1,458,923 |
|
|
|
824,437 |
|
|
|
872,818 |
|
|
|
1,410,542 |
|
|
|
406,615 |
|
|
|
1,876,745 |
|
__________________________
(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 Duncan Fork 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.
|
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
|
|
|
|
|
|
|
Reserves
|
|
|
|
+1%
|
(2) |
|
|
-1%
|
(2) |
|
Compliance
|
|
|
Received
(3)
|
|
|
Coal
Type (4)
|
|
|
|
(In
Thousands of Tons Except Average Btu as Received)
|
|
|
|
|
Resource
Groups:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
West
Virginia
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Black
Castle
|
|
|
88,756 |
|
|
|
35,404 |
|
|
|
53,352 |
|
|
|
22,921 |
|
|
|
12,000 |
|
|
Utility
and Industrial
|
|
Delbarton
|
|
|
286,747 |
|
|
|
111,954 |
|
|
|
174,793 |
|
|
|
127,073 |
|
|
|
12,500 |
|
|
High
Vol Met, Utility, and Industrial
|
|
Edwight
|
|
|
8,870 |
|
|
|
1,555 |
|
|
|
7,315 |
|
|
|
7,315 |
|
|
|
12,800 |
|
|
High
Vol Met, Utility, and Industrial
|
|
Elk
Run
|
|
|
162,767 |
|
|
|
80,695 |
|
|
|
82,072 |
|
|
|
73,177 |
|
|
|
13,400 |
|
|
High
Vol Met, Utility, and Industrial
|
|
Endurance
|
|
|
25,126 |
|
|
|
4,952 |
|
|
|
20,174 |
|
|
|
10,047 |
|
|
|
12,500 |
|
|
Utility
and Industrial
|
|
Green
Valley
|
|
|
7,135 |
|
|
|
921 |
|
|
|
6,214 |
|
|
|
6,214 |
|
|
|
13,100 |
|
|
High
Vol Met, Utility, and Industrial
|
|
Guyandotte
|
|
|
43,603 |
|
|
|
- |
|
|
|
43,603 |
|
|
|
43,603 |
|
|
|
13,800 |
|
|
Low
Vol Met
|
|
Independence
|
|
|
43,311 |
|
|
|
14,958 |
|
|
|
28,353 |
|
|
|
3,046 |
|
|
|
13,100 |
|
|
High
Vol Met, Utility, and Industrial
|
|
Logan
County
|
|
|
73,529 |
|
|
|
21,665 |
|
|
|
51,864 |
|
|
|
41,920 |
|
|
|
12,500 |
|
|
High
Vol Met, Utility, and Industrial
|
|
Mammoth
|
|
|
87,558 |
|
|
|
5,216 |
|
|
|
82,342 |
|
|
|
41,706 |
|
|
|
12,000 |
|
|
Utility
and Industrial
|
|
Marfork
|
|
|
121,721 |
|
|
|
54,597 |
|
|
|
67,124 |
|
|
|
42,808 |
|
|
|
13,150 |
|
|
High
Vol Met, Utility, and Industrial
|
|
Nicholas
Energy
|
|
|
92,303 |
|
|
|
41,683 |
|
|
|
50,620 |
|
|
|
31,957 |
|
|
|
11,800 |
|
|
Utility
and Industrial
|
|
Progress
|
|
|
22,446 |
|
|
|
2,316 |
|
|
|
20,130 |
|
|
|
17,809 |
|
|
|
12,400 |
|
|
High
Vol Met, Utility, and Industrial
|
|
Rawl
|
|
|
96,369 |
|
|
|
31,128 |
|
|
|
65,241 |
|
|
|
42,416 |
|
|
|
12,600 |
|
|
High
Vol Met, Utility, and Industrial
|
|
Republic
|
|
|
38,209 |
|
|
|
6,154 |
|
|
|
32,055 |
|
|
|
22,352 |
|
|
|
12,400 |
|
|
High
Vol Met and Utility
|
|
Stirrat
|
|
|
5,293 |
|
|
|
- |
|
|
|
5,293 |
|
|
|
5,293 |
|
|
|
13,800 |
|
|
High
Vol Met, Utility, and Industrial
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Kentucky
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Coalgood
Energy
|
|
|
21,261 |
|
|
|
4,712 |
|
|
|
16,549 |
|
|
|
11,680 |
|
|
|
11,900 |
|
|
High
Vol Met, Utility, and Industrial
|
|
Long
Fork
|
|
|
4,964 |
|
|
|
3,500 |
|
|
|
1,464 |
|
|
|
- |
|
|
|
12,500 |
|
|
Utility
and Industrial
|
|
Martin
County
|
|
|
42,554 |
|
|
|
31,939 |
|
|
|
10,615 |
|
|
|
4,629 |
|
|
|
12,000 |
|
|
Utility
and Industrial
|
|
New
Ridge
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
N/A |
|
Sidney
|
|
|
127,055 |
|
|
|
49,933 |
|
|
|
77,122 |
|
|
|
54,177 |
|
|
|
12,500 |
|
|
High
Vol Met, Utility, and Industrial
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Virginia
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Knox
Creek
|
|
|
45,087 |
|
|
|
- |
|
|
|
45,087 |
|
|
|
45,087 |
|
|
|
13,300 |
|
|
High
Vol Met, Utility, and Industrial
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Subtotal
|
|
|
1,444,664 |
|
|
|
503,282 |
|
|
|
941,382 |
|
|
|
655,230 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Land
Management Companies: (5)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Black
King
|
|
|
32,666 |
|
|
|
15,570 |
|
|
|
17,096 |
|
|
|
13,799 |
|
|
|
13,300 |
|
|
High
Vol Met and Utility
|
|
Boone
East
|
|
|
132,145 |
|
|
|
33,250 |
|
|
|
98,895 |
|
|
|
32,978 |
|
|
|
13,100 |
|
|
High
Vol Met, Utility, and Low Vol Met
|
|
Boone
West
|
|
|
252,332 |
|
|
|
133,849 |
|
|
|
118,483 |
|
|
|
79,369 |
|
|
|
13,100 |
|
|
High
Vol Met and Utility
|
|
Ceres
Land
|
|
|
33,351 |
|
|
|
5,991 |
|
|
|
27,360 |
|
|
|
12,740 |
|
|
|
13,000 |
|
|
High
Vol Met and Utility
|
|
Duncan
Fork
|
|
|
94,086 |
|
|
|
94,086 |
|
|
|
- |
|
|
|
- |
|
|
|
13,600 |
|
|
High
Vol Met, Utility, and Industrial
|
|
Lauren
Land
|
|
|
181,247 |
|
|
|
85,460 |
|
|
|
95,787 |
|
|
|
72,787 |
|
|
|
12,400 |
|
|
High
Vol Met and Utility
|
|
New
Market Land
|
|
|
7,984 |
|
|
|
- |
|
|
|
7,984 |
|
|
|
7,984 |
|
|
|
13,600 |
|
|
High
Vol Met and Low Vol Met
|
|
Raven
Resources
|
|
|
18,978 |
|
|
|
7,449 |
|
|
|
11,529 |
|
|
|
1,369 |
|
|
|
13,100 |
|
|
High
Vol Met and Utility
|
|
Tennessee
Consolidated Coal
|
|
|
26,907 |
|
|
|
20,353 |
|
|
|
6,554 |
|
|
|
4,816 |
|
|
|
12,800 |
|
|
High
Vol Met, Utility and Industrial
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Subtotal
Land Management
|
|
|
779,696 |
|
|
|
396,008 |
|
|
|
383,688 |
|
|
|
225,842 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
|
|
|
59,000 |
|
|
|
6,638 |
|
|
|
52,362 |
|
|
|
47,214 |
|
|
|
13,000 |
|
|
Various
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
2,283,360 |
|
|
|
905,928 |
|
|
|
1,377,432 |
|
|
|
928,286 |
|
|
|
|
|
|
|
|
|
__________________________
(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.
|
Compliance
compared to non-compliance coal
Coals are
sometimes characterized as compliance or non-compliance coal. The phrase
compliance coal, as it is commonly used in the coal industry, refers to
compliance only with sulfur dioxide emissions standards imposed by Title IV of
the Clean Air Act and indicates that when burned, the coal will produce
emissions that will meet the current standard without further cleanup. A coal
that is considered a compliance coal for meeting sulfur dioxide standards may
not meet an emission standard for a different pollutant such as mercury.
Moreover, the term compliance coal is always used with reference to the
then-current regulatory limit. Clean air regulations that further restrict
sulfur dioxide emissions will likely reduce significantly the amount of coal
that can be labeled compliance. Currently, coal classified as compliance will
meet the power plant emission standard of 1.2 pounds of sulfur dioxide per
million Btu’s of fuel consumed. At December 31, 2007, approximately
0.9 billion tons, or 41%, of our coal reserves met the current standard
as compliance coal.
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 2007
shipments of 39.9 million tons were loaded from 22 mining complexes. Rail
shipments constituted 90% of total shipments, with 25% loaded on Norfolk
Southern trains and 65% loaded on CSX trains. The balance was shipped from
mining complexes via truck or barge.
Approximately
20% of production was ultimately delivered via the inland waterway system. Coal
is loaded directly into barges, or is transported by rail or truck to docks on
the Ohio, Big Sandy and Kanawha Rivers and then ultimately transported by barge
to electric utilities, integrated steel producers and industrial consumers
served by the inland waterway system. We also moved approximately 4% of our
production to Great Lakes’ ports for transport to various United States and
Canadian customers.
We have
coal supply commitments with a wide range of electric utilities, steel
manufacturers, industrial customers and energy traders and brokers. By offering
coal of both steam and metallurgical grades, we are able to serve a diverse
customer base. This market diversity allows us to adjust to changing market
conditions and sustain high sales volumes. The majority of our customers
purchase coal for terms of one year or longer, but we also supply coal on a spot
basis for some customers. Our largest customer, American Electric Power Company,
Inc. and its affiliates, accounted for 11% of total fiscal year 2007 Produced
coal revenue.
As is
customary in the coal industry, we enter into long-term contracts (one year or
more in duration) with many of our customers. These arrangements allow customers
to secure a supply for their future needs and provide us with greater
predictability of sales volume and sales prices. Long-term contracts are a
result of extensive negotiations with customers. As a result, the terms of these
contracts vary with respect to price adjustment mechanisms, pricing terms,
permitted sources of supply, force majeure provisions, quality adjustments and
other parameters. Some of the contracts contain price adjustment mechanisms that
allow for changes to prices based on statistics from the United
States Department of Labor. Coal quality specifications may be especially
stringent for steel customers.
For the
year ended December 31, 2007, approximately 95% of coal sales volume was
pursuant to long-term contracts. We anticipate that in 2008, coal sales volume
percentage pursuant to long-term arrangements will be comparable to 2007. As of
February 14, 2008, we had contractual sales commitments of approximately 123
million tons, including commitments subject to price reopener and/or optional
tonnage provisions. Remaining contractual terms of our sales commitments range
from one to 12 years with an average volume-weighted remaining term of
approximately 2.3 years. Eighty-four percent of the contracted sales tons are
priced. As of February 14, 2008, we have committed most of our expected 2008
production. In addition, we purchase coal from third-party coal producers from
time to time to supplement production and resell this coal to
customers.
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
2006 there were 25 coal companies in the United States with annual production in
excess of 5 million tons, which together account for approximately 84% of United
States production. According to the EIA, we were the sixth largest coal company
in terms of tons produced in 2006, exceeded by Peabody Energy Corporation
(“Peabody”), Rio Tinto Energy America, Inc., Arch Coal, Inc. (“Arch”), CONSOL
Energy Inc. (“CONSOL”), and Foundation Coal Holdings Inc. (“Foundation”) .
However, according to company reports, we were the fourth largest United States
coal company in terms of revenue in 2006,
exceeded by Peabody, CONSOL and Arch.
We
compete with other producers primarily on the basis of price, coal quality,
transportation cost and reliability of supply. Continued demand for coal is also
dependent on factors outside of our control, including demand for electricity
and steel, general economic conditions, environmental and governmental
regulations, weather, technological developments, and the availability and cost
of alternative fuel sources. We sell coal to foreign electricity generators and
to the more specialized metallurgical coal market, both of which are
significantly affected by international demand and competition.
Historically,
global coal markets have responded to increased demand and higher prices for
coal by increasing production and supply. In recent years, however, capacity
expansion has been somewhat limited by the increased costs of mining, high
capital requirements, coal seam degradation, reserve depletion, labor shortages,
transportation issues related to rail, barge and truck shipments, higher costs
related to compliance with new and increasingly stringent regulations, the
difficulty of obtaining permits and bonding, and other factors. While these
constraints persist in major coal producing countries and regions, periods of
supply and demand imbalance may be extended and increased pricing volatility,
particularly upward, may result.
Other
Related Operations
We have
other related operations and activities in addition to our normal coal
production and sales business. The following business activities are included in
this category:
Coal Handling Joint Venture.
We hold a 50% interest in a joint venture that owns and operates third-party
end-user coal handling facilities. Certain subsidiaries currently operate the
coal handling facilities for the joint venture.
Gas Operations. We hold
interests in operations that produce, gather and market natural gas from shallow
reservoirs in the Appalachian Basin. In the eastern United
States, conventional natural gas reservoirs are located in various types
of sedimentary formations at depths ranging from 2,000 to 15,000 feet. The
depths of the reservoirs drilled and operated by us range from 2,500 to 5,600
feet.
Nearly
all of our gas production is from operations in southern West Virginia. In this
region, we own and operate approximately 188 wells, 200 miles of gathering line,
and various small compression facilities. Our southern West Virginia operations
control approximately 27,000 acres of drilling rights. In addition, we own a
majority working interest in 48 wells operated by others, and minority working
interests in approximately 30 wells operated by others. The December 2007
average daily production, from the 236
wells owned or controlled, was 1.9 million cubic feet per day. We do not
consider our current gas production level, revenues or costs to be material to
our cash flows, results of operations or financial condition.
Other. From time to time, we
also engage in the sale of certain non-strategic assets such as timber, oil and
gas rights, surface properties and reserves. In addition, we have established
several contractual arrangements with customers where services other than coal
supply are provided on an ongoing basis. None of these contractual arrangements
is considered to be material. Examples of such other services include
arrangements with several metallurgical and industrial customers to coordinate
shipment of coal to their stockpiles, maintain ownership of the coal inventory
on their property and sell tonnage to them as it is consumed. We work closely
with customers to provide other services in response to the current needs of
each individual customer.
Marketing
and Sales
Our
marketing and sales force, based in the corporate office in Richmond, Virginia,
includes sales managers, distribution/traffic managers and administrative
personnel.
During
the year ended December 31, 2007, we sold 39.9 million tons of produced coal for
total Produced coal revenue of $2.1 billion. The breakdown of produced tons sold
by market served was 69% utility, 21% metallurgical and 10%
industrial.
Sales were concluded with over 100 customers. Export shipment revenue totaled
approximately $330.7 million, representing approximately 16.1% of 2007 Produced
coal revenue. In 2007, we exported shipments to customers in 12 countries across
the globe, which included Brazil, Canada, Egypt, Finland, Germany, India, Japan,
Italy, Netherlands, South Korea, Spain and Sweden. Sales are made in United
States dollars, which minimizes foreign currency risk.
Employees
and Labor Relations
As of
December 31, 2007, we had 5,407 employees, including 108 employees affiliated
with the United Mine Workers of America (“UMWA”). Relations with employees are
generally good, and there have been no material work stoppages in the past ten
years.
Environmental,
Safety and Health Laws and Regulations
The coal
mining industry is subject to regulation by federal, state and local authorities
on matters such as the discharge of materials into the environment, employee
health and safety, permitting and other licensing requirements, reclamation and
restoration of mining properties after mining is completed, management of
materials generated by mining operations, surface subsidence from underground
mining, water pollution, water appropriation and legislatively mandated benefits
for current and retired coal miners, air quality standards, protection of
wetlands, endangered plant and wildlife protection, limitations on land use, and
storage of petroleum products and substances that are regarded as hazardous
under applicable laws. The possibility exists that new legislation or
regulations may be adopted that could have a significant impact on our mining
operations or on our customers’ ability to use coal.
Numerous
governmental permits and approvals are required for mining operations.
Regulations provide that a mining permit or modification can be delayed, refused
or revoked if an officer, director or a stockholder with a 10% or greater
interest in the entity is affiliated with or is in a position to control another
entity that has outstanding permit violations. Thus, past or ongoing violations
of federal and state mining laws by individuals or companies no longer
affiliated with us could provide a basis to revoke existing permits and to deny
the issuance of addition permits. We are required to prepare and present to
federal, state or local authorities data and/or analysis pertaining to the
effect or impact that any proposed exploration for or production of coal may
have upon the environment, public and employee health and safety. All
requirements imposed by such authorities may be costly and time-consuming and
may delay commencement or continuation of exploration or production operations.
Accordingly, the permits we need for our mining and gas operations may not be
issued, or, if issued, may not be issued in a timely fashion. Permits we need
may involve requirements that may be changed or interpreted in a manner that
restricts our ability to conduct our mining operations or to do so profitably.
Future legislation and administrative regulations may increasingly emphasize the
protection of the environment, health and safety and, as a consequence, our
activities may be more closely regulated. Such legislation and regulations, as
well as future interpretations of existing laws, may require substantial
increases in equipment and operating costs, delays, interruptions or a
termination of operations, the extent of which cannot be predicted.
While it
is not possible to quantify the expenditures we incur to maintain compliance
with all applicable federal and state laws, those costs have been and are
expected to continue to be significant. We post surety performance bonds or
letters of credit pursuant to federal and state mining laws and regulations for
the estimated costs of reclamation and mine closing, often including the cost of
treating mine water discharge when necessary. Compliance with these laws has
substantially increased the cost of coal mining for all domestic coal producers.
We endeavor to conduct our mining operations in compliance with all applicable
federal, state and local laws and regulations. However, even with our
substantial efforts to comply with extensive and comprehensive regulatory
requirements, violations during mining operations occur from time to time. In
2007, the EPA filed suit against us and twenty-seven of our subsidiaries
alleging violations of the Federal Clean Water Act. In January 2008, we
announced that we had agreed with the EPA to settle the lawsuit for a payment of
$20 million in penalties (see Note 17 to the Notes to Consolidated Financial
Statements). In 2007, we spent approximately $23.1 million to comply with
environmental laws and regulations, of which $13.8 million was for reclamation,
including $11.1 million for final reclamation. None of these expenditures were
capitalized. We anticipate spending approximately $38.8 million and $31.7
million in such non-capital expenditures in 2008 and 2009, respectively. Of
these expenditures, $29.3 million and $22.0 million for 2008 and 2009,
respectively, are anticipated to be for reclamation.
Emission Control Technology.
We own a majority interest in Coalsolv, LLC, which holds the United States
marketing rights for the coal-fired plant emission control technologies
developed by Cansolv Technologies, Inc., in which we hold a minority interest.
Cansolv’s technologies remove sulfur dioxide (SO2), nitrogen
oxide (NOx), mercury,
carbon dioxide (CO2), and
other greenhouse gases from flue gas emissions. The Cansolv process has been
utilized at various industrial facilities around the world, with additional
projects underway in China and Canada. Through Coalsolv, we contributed funds
for a pilot plant that has been utilized in the United States and Canada for the
testing and piloting of the Cansolv SO2, NOX, mercury,
and CO2 capture
technology on coal-fired power plants.
Mine
Safety and Health
Stringent
health and safety standards have been in effect since Congress enacted the
Federal Coal Mine Health and Safety Act of 1969. The Federal Coal Mine Safety
and Health Act of 1977 significantly expanded the enforcement of safety and
health standards and imposed safety and health standards on all aspects of
mining operations. A further expansion occurred in June 2006 with the enactment
of the Mine Improvement and New Emergency Response Act of 2006 (“MINER
Act”).
The MINER
Act and related Mine Safety and Health Administration (“MSHA”)
regulatory action require, among other things, improved emergency response
capability, increased availability of emergency breathable air, enhanced
communication and tracking systems, more available mine rescue teams, increased
mine seal strength and monitoring of sealed areas in underground mines, as well
as larger penalties by MSHA for noncompliance by mine operators. Coal producing
states, including West Virginia and Kentucky, passed similar legislation.
The
bituminous coal mining industry was actively engaged throughout 2007 in
activities to achieve compliance with these new requirements. These compliance
efforts will continue into 2008.
On
February 8, 2008, MSHA published a final rule that revises existing standards
for mine rescue teams for underground coal mines. This final rule implements
Section 4 of the MINER Act to improve overall mine rescue capability, mine
emergency response time and mine rescue team effectiveness. It also calls for
increased quantity and quality of mine rescue team training. Additional
substantive legislation is also possible in 2008 with the passage by the United
States House of Representatives in January 2008 of the Supplementary Mine
Improvement and New Emergency Response Act, (“S-MINER Act”). The House
legislation augments portions of the MINER Act and proposes changes to retreat
mining practices, study of substance abuse issues and the use of coal dust
monitors to reduce miner respirable dust exposure.
All of
the states in which we operate have state programs for mine safety and health
regulation and enforcement. Collectively, federal and state safety and health
regulation in the coal mining industry is perhaps the most comprehensive and
pervasive system for protection of employee health and safety affecting any
segment of industry in the United States. While regulation has a significant
effect on our operating costs, our United States competitors are subject to the
same degree of regulation.
Our goal
is sustainable excellence in our safety and health performance. We are committed
to doing our best, and then learning to do even better. We recognize each
employee’s contributions to our collective safety and health efforts and reward
outstanding performance. We measure our success in this area primarily through
the use of occupational injury and illness frequency rates. We believe that a
superior safety and health regime is inherently tied to achieving productivity
and financial goals, with overarching benefits for our shareholders, the
community and the environment.
Black Lung. Under federal
black lung benefits legislation, each coal mine operator is required to make
payments of black lung benefits or contributions to: (i) current and former coal
miners totally disabled from black lung disease; and (ii) certain survivors of a
miner who dies from black lung disease. The Black Lung Disability Trust Fund, to
which we must make certain tax payments based on tonnage sold, provides for the
payment of medical expenses to claimants whose last mine employment was before
January 1, 1970 and to claimants employed after such date, where no responsible
coal mine operator has been identified for claims or where the responsible coal
mine operator has defaulted on the payment of such benefits. In addition to
federal acts, we are also liable under various state statutes for black lung
claims. Federal benefits are offset by any state benefits paid.
Workers’ Compensation. We are
liable for workers’ compensation benefits for traumatic injuries under state
workers’ compensation laws in which we have operations. Workers’ compensation
laws are administered by state agencies with each state having its own set of
rules and regulations regarding compensation owed to an employee injured in the
course of employment.
Coal Industry Retiree Health Benefit
Act of 1992 and Tax Relief and Retiree Health Care Act of 2006. The Coal
Industry Retiree Health Benefit Act of 1992 (“Coal Act”) provides for the
funding of health benefits for certain UMWA retirees. The Coal Act established
the Combined Benefit Fund (“CBF”) into which “signatory operators” and “related
persons” are obligated to pay annual premiums for covered beneficiaries. The
Coal Act also created a second benefit fund, the 1992 Benefit Plan, for miners
who retired between July 21, 1992 and September 30, 1994 and whose former
employers are no longer in business. On December 20, 2006, President Bush signed
the Tax Relief and Retiree Health Care Act of 2006. This legislation includes
important changes to the Coal Act that impacts all companies required to
contribute to the CBF. Effective
October 1, 2007, the SSA revoked all beneficiary assignments made to companies
that did not sign a 1988 UMWA contract (“reachback companies”), but phased-in
their premium relief. As a pre-1988 signatory, Massey related reachback
companies will receive the applicable premium relief. Effective October 1,
2007, reachback companies will pay only 55% of their plan year 2008 assessed
premiums, 40% of their plan year 2009 assessed premiums, and 15% of their plan
year 2010 assessed premiums. General United States Treasury money will be
transferred to the CBF to make up the difference. After
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”) will simplify and transform rules
governing the funding of defined benefit plans, accelerate funding obligations
of employers, make permanent certain provisions of the Economic Growth and Tax
Relief Reconciliation Act of 2001, make permanent the diversification rights and
investment education provisions for plan participants and encourage automatic
enrollment in defined contribution 401(k) plans. In general, most
provisions of the Pension Act will take effect for plan years beginning on or
after December 31, 2007. Plans generally will be required to set a funding
target of 100% of the present value of accrued benefits and sponsors will be
required to amortize unfunded liabilities over a 7-year period. The Pension Act
includes a funding target phase-in provision consisting of a 92% funding target
in 2008, 94% in 2009, 96% in 2010, and 100% thereafter. Plans with a funded
ratio of less than 80%, or less than 70% using special assumptions, will be
deemed to be “at risk” and will be subject to additional funding requirements.
Our qualified pension plans are currently fully funded.
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 must be placed in fills in adjacent valleys and
hollows. Likewise, coal refuse disposal areas and coal processing slurry
impoundments are located in valleys and hollows. Almost all of these areas
contain intermittent or perennial streams, which are considered navigable waters
under the Clean Water Act. An operator must secure a Clean Water Act permit
before filling such streams. For approximately the past twenty-five years,
operators have secured Section 404 fill permits that authorize the filling of
navigable waters with material from various forms of coal mining. Operators have
also obtained permits under Section 404 for the construction of slurry
impoundments although the use of these impoundments, including discharges from
them, requires permits under Section 402. Section 402 discharge permits are
generally not suitable for authorizing the construction of fills in navigable
waters.
Clean Air
Act. Coal contains
impurities, including sulfur, mercury, chlorine, nitrogen oxide and other
elements or compounds, many of which are released into the air when coal is
burned. The Clean Air Act and corresponding state laws extensively regulate
emissions into the air of particulate matter and other substances, including
sulfur dioxide, nitrogen oxide and mercury. Although these regulations apply
directly to impose certain requirements for the permitting and operation of our
mining facilities, by far their greatest impact on us and the coal industry
generally is the effect of emission limitations on utilities and other
customers. Owners of coal-fired power plants and industrial boilers have been
required to expend considerable resources in an effort to comply with these air
pollution standards. The United States Environmental Protection Agency (“EPA”)
has imposed or attempted to impose tighter emission restrictions in a number of
areas, some of which are currently subject to litigation. The general effect of
such tighter restrictions could be to reduce demand for coal. This in turn may
result in decreased production and a corresponding decrease in revenue and
profits.
National Ambient Air
Quality Standards. In 1997, EPA adopted a new National Ambient Air
Quality Standard (“NAAQS”) for very fine particulate matter and a more stringent
NAAQS for ozone. Ozone is produced by a combination of two precursor pollutants:
volatile organic compounds and nitrogen oxide, a by-product of coal combustion.
States were required to submit to EPA revisions to their State Implementation
Plans (“SIPs”) that demonstrate the manner in which the states will attain the
fine particulate NAAQS by December 18, 2007. The ozone NAAQS has been
the subject of litigation and, during the course of this litigation, EPA
has proposed revisions to the ozone NAAQS that are more stringent
than the standards being litigated. EPA intends to begin the
promulgation process for the new, more stringent ozone NAAQS in the Spring of
2008. Revised SIPs could require electric power generators to further reduce
nitrogen oxide and sulfur dioxide emissions. In addition to the SIP process, the
Clean Air Act permits states to assert claims against sources in other “upwind”
states alleging that emission sources including coal fired power plants in the
upwind states are preventing the “downwind”
states
from attaining a NAAQS. All these actions could result in additional
controls being required on coal fired power plants and we are unable to predict
the effect on coal production.
Acid Rain Control Provisions.
The acid rain control provisions promulgated as part of the Clean Air Act
Amendments of 1990 in Title IV of the Clean Air Act (“Acid Rain program”)
required reductions of sulfur dioxide emissions from power plants. The Acid Rain
program is now a mature program and we believe that any market impacts of the
required controls have likely been factored into the price of coal in the
national coal market.
Regional Haze Program. EPA
promulgated a regional haze program designed to protect and to improve
visibility at and around so-called Class I Areas, which are generally National
Parks, National Wilderness Areas and International Parks. This program may
restrict the construction of new coal-fired power plants whose operation may
impair visibility at and around the Class I Areas. Moreover, the program
requires certain existing coal-fired power plants to install additional control
measures designed to limit haze-causing emissions, such as sulfur dioxide,
nitrogen oxide and particulate matter. States were required to submit Regional
Haze SIPs to EPA by December 17, 2007. Many
states did not meet the December 17, 2007, deadline and we are unable to predict
the impact on the coal market of the failure to submit Regional Haze SIPs by the
deadline.
New Source Review Program.
Under the Clean Air Act, new and modified sources of air pollution must meet
certain new source standards (“New Source Review Program”). In the late 1990s,
the EPA filed lawsuits against many coal-fired plants in the eastern United
States alleging that the owners performed non-routine maintenance, causing
increased emissions that should have triggered the application of these new
source standards. Some of these lawsuits have been settled, with the owners
agreeing to install additional pollution control devices in their coal-fired
plants. The remaining litigation and the uncertainty around the New Source
Review Program rules could adversely impact utilities’ demand for coal in
general or coal with certain specifications, including the coal produced by
us.
Multi-Pollutant Strategies.
In March 2005, EPA issued two closely related rules designed to significantly
reduce levels of sulfur dioxide, nitrogen oxide and mercury: the Clean Air
Interstate Rule and the Clean Air Mercury Rule. The Clean Air Interstate Rule
sets a cap-and-trade program in 28 states and the District of Columbia to
establish emissions limits for sulfur dioxide and nitrogen oxide, by allowing
utilities to buy and sell credits to assist in achieving compliance with the
NAAQS for 8-hour ozone and fine particulates. The Clean Air Mercury Rule as
promulgated will cut mercury emissions nearly 70% by 2018 through a
cap-and-trade program. Both rules were challenged in numerous lawsuits. Portions
of each of these rules are still in litigation, and on February 8, 2008, the
United
States Court of Appeals for the District of Columbia Circuit vacated the
entire mercury rule and remanded it to EPA for reconsideration. Immediately
following the decision, EPA announced that it has not decided how to respond.
Regardless of the outcome of litigation on either rule, a form of each of the
rules will likely be promulgated and ultimately directly affect coal producers,
suppliers and utilities in the eastern and western regions of the United States,
by requiring revisions to the SIPs in many eastern states. Any such controls may
have an impact on the demand for our coal and possibly give the users of western
sub-bituminous coal a significant competitive advantage over eastern bituminous
coal users.
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,
the cost of obtaining a permit is rarely more than $500,000 and the 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 on
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 the 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 the 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.
Endangered
Species Act
The federal Endangered Species Act and
counterpart state legislation protects 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 file
our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports
on Form 8-K, proxy statements and other information with the Securities and
Exchange Commission (“SEC”). Our SEC filings are available to the public over
the Internet at the SEC’s website at www.sec.gov. You may also read and copy any
document we file at the SEC’s public reference room at 100 F Street, N.E.,
Washington, D.C. 20549. Please call the SEC at 1-800-SEC-0330 for further
information on the public reference room. 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, Virginia 23261, Attention: Investor
Relations.
Incorporated by reference into this
Part I is the information set forth in Part III, Item 10 under the caption
“Directors and 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. It is dense and black and often has
well-defined bands of bright and dull material.
British thermal unit, or
“Btu.” A measure of the thermal energy required to raise the temperature
of one pound of pure liquid water one degree Fahrenheit at the temperature at
which water has its greatest density (39 degrees Fahrenheit).
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.
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.
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.”
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.
Same as “top.”
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. A majority
of our Appalachian reserves are of low sulfur grades.
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” tonne 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.
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
are impacted by the competitiveness of the markets in which we compete and
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, the
competitive environment for coal has been 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 have supported
pricing for steam and metallurgical coal. The cost of ocean transportation and
the valuation 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. See Item 1. Business, under the
heading “Competition,” for further discussion.
Portions
of our coal reserves possess quality characteristics that enable us to mine,
process and market them as either metallurgical coal or high quality steam coal,
depending on the prevailing conditions in the metallurgical and steam coal
industries. 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.
If demand for metallurgical coal declined to the point where we could earn a
more attractive return marketing the coal as steam coal, there could be a
material impact on 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
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,
2008, we operated 35 active underground mines, including two longwall mines, and
12 active surface mines, with 8 highwall miners. See Item 1. Business, under the
headings “Mining Methods,” “Mining Operations” and “Competition” for further
discussion.
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 announced plans to increase their capacity to
import 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 country if the costs of transporting coal from the west were significantly
reduced and rail capacity was increased. See Item 1. Business, under
the heading “Competition,” for further discussion.
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, could cause 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.
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 reach expiration, 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. 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 during 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. See Item 1. Business, under the heading “Customers
and Coal Contracts” for further discussion.
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
February 28, 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 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, 2007, we had $1,104.5 million of total indebtedness outstanding,
which represented 58.5% of our total book capitalization. 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.
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.
The
covenants in our credit facility and the indentures governing debt instruments
impose restrictions that may limit our operating and financial
flexibility.
Our asset
based loan credit facility and the indentures governing our notes contain a
number of significant restrictions and covenants that may 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 lien or
security interests in any real property or equipment; (viii) engage in sale and
leaseback transactions; and (ix) restrict distributions from
subsidiaries.
Operating
results below current levels or other adverse factors, including a significant
increase in interest rates, could result in us being unable to comply with
certain debt covenants. 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. 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
holders of the 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
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.
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: (i) geological conditions; (ii) historical production from
the area compared with production from other producing areas; (iii) the effects
of regulations and taxes by governmental agencies; (iv) future prices; and (v)
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 these 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. We have announced plans to increase
our coal production by approximately 20% over the next three years. Several of
our competitors have also announced plans for increases in production capacity
over the next several years. 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. See Item 1. Business, under the heading “Competition,” for further
discussion.
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 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 is dependent upon the reliability of the supply, 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 and tires could decrease our
profitability.
Our
operations are dependant on reliable supplies of mining equipment, replacement
parts, explosives, diesel fuel, tires, 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. In
recent years, mining industry demand growth has exceeded supply growth for
certain surface and underground mining equipment and heavy equipment
tires.
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 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.
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
and state 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. We may also incur costs and liabilities
resulting from claims for damages to property or injury to persons arising from
our operations. See Item 1. Business, under the heading “Environmental, Safety
and Health Laws and Regulations” for further discussion of this
risk.
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 EPA
has undertaken broad initiatives aimed at increasing compliance with emissions
standards and to provide incentives to our customers for decreasing emissions,
often by switching to an alternative fuel source or by installing scrubbers 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 regulations may require significant emissions control expenditures
for many coal-fired power plants to comply with applicable ambient air quality
standards. 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.
Global
climate change continues to attract considerable public and scientific
attention. Widely publicized scientific reports in 2007, such as the Fourth
Assessment Report of the Intergovernmental Panel on Climate Change, have also
engendered widespread concern about the impacts of human activity, especially
fossil fuel combustion, on global climate change. A considerable amount of
legislative 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 EIA, “Emissions of Greenhouse Gases in
the United States 2006,” coal accounts for 30% of greenhouse gas emissions in
the United States. Legislation was introduced in Congress in 2006 and 2007 to
reduce greenhouse gas emissions in the United States and
additional
legislation has been proposed and is likely to be introduced in the future. In
addition, a growing number of states in the United States are taking steps to
reduce greenhouse gas emissions from coal-fired power plants. The United
States Supreme Court’s recent decision in Massachusetts v.
Environmental Protection Agency ruled that the EPA improperly declined to
address carbon dioxide impacts on climate change in a recent rulemaking.
Although the specific rulemaking related to new motor vehicles, the reasoning of
the decision could affect other federal regulatory programs, including those
that directly relate to coal use. 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.
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. See Item 1. Business, under the heading “Environmental, Safety and
Health Laws and Regulations” for further discussion of this
risk.
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 an 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 and can result in restrictions on our
operations.
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. Additionally, the
Clean Water Act requires permits for operations that fill waters of the United
States. Valley fills and refuse impoundments are typically authorized under
nationwide permits that are revised and renewed periodically 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. 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 the commencement or
continuation of development or production operations. See Item 1. Business,
under the heading “Environmental, Safety and Health Laws and Regulations” for
further discussion.
The
loss of key personnel or the failure to attract qualified personnel could affect
our ability to operate our 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.
Union
represented labor creates an increased risk of work stoppages and higher labor
costs.
At
December 31, 2007, 2.0% of our total workforce was represented by the UMWA.
During 2007, six of our coal preparation plants and one smaller surface mine had
a workforce represented by the UMWA. In 2007, these preparation plants handled
approximately 28% of our coal production. There may be an increased risk of
strikes and other related work actions, in addition to higher labor costs,
associated with these operations. If some or all of our current open shop
operations were to become union represented, we could be subject to additional
risk of work stoppages and higher labor costs, which could adversely affect the
stability of production and reduce net income.
We
are subject to being 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, 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, 2007, approximately 95%
of coal sales volume was pursuant to long-term contracts. We
anticipate that in 2008, the percentage of our sales pursuant to long-term
contracts will be comparable with the percentage of our sales for 2007 and
almost 60% of our projected 2008 sales is contracted to be
sold to
our 10 largest customers. If one or more of our largest customers
experiences financial difficulties and 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 the largest supplier of
metallurgical coal to the American steel industry, we are subject to being
adversely affected by any decline in the financial condition or production
volume of American steel producers. See Item 1. Business, under the heading
“Customers and Coal Contracts” for further discussion.
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 an adverse effect on our cash flows, results of operations or
financial position. See Item 3. Legal Proceedings and Note 17 to the Notes to
Consolidated Financial Statements for further discussion.
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.
The 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. See Item
1. Business, under the heading “Environmental, Safety and Health Laws and
Regulations” for further discussion.
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 impact on our cash flows, results of operations or
financial condition. For a further discussion, see Item 7. Management’s
Discussion and Analysis of Financial Condition and Results of Operations under
the heading “Critical Accounting Estimates and Assumptions” and Notes 5 and 10
to the Notes to Consolidated Financial Statements.
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;
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.
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 of which we insure against and some of
which we self-insure.
Our
operations are subject to certain events and conditions that could disrupt
operations, including fires and explosions, accidental minewater discharges,
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. We self-insure
our highwall miners and underground equipment, including our longwalls. We do
not currently carry business interruption insurance.
Diversity
in interpretation and application of accounting literature in the mining
industry may impact our reported financial results.
The
mining industry has limited industry specific accounting literature and, as a
result, we understand diversity in practice exists in the interpretation and
application of accounting literature to mining specific issues. As diversity in
mining industry accounting is addressed, we may need to restate our reported
results if the resulting interpretations differ from our current accounting
practices (for additional information regarding our accounting policies, please
see Results of Operations — Critical Accounting Estimates and Assumptions and
Note 1 to the Notes to Consolidated Financial Statements).
Item
1B. Unresolved Staff Comments
None.
Item
2. Properties
We own
and lease properties totaling more than 988,000
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
|
Charleston,
West Virginia
|
Leased
|
Massey
Coal Services Office
|
Chapmanville,
West Virginia
|
Leased
|
Massey
Coal Services Field
Office
|
In 2008, we
plan to complete construction of our new Massey Coal Services office building,
located in Boone County, West Virginia. The building will combine the
Charleston and Chapmanville offices.
For a
description of mining properties, see Item 1. Business, under the heading
“Mining Operations” and “Coal Reserves.”
Item 3. Legal
Proceedings
Martin
County Impoundment Discharge
On
October 11, 2000, a partial failure of the coal refuse impoundment of Martin
County Coal Corporation, one of our subsidiaries, released approximately 250
million gallons of coal slurry into two tributary streams of the Big Sandy River
in eastern Kentucky. On May 30, 2006, the Federal Mine Safety and Health Review
Commission remanded citations and penalties issued by MSHA initially totaling
approximately $110,000, subsequently reduced to $5,500 by an administrative law
judge (“ALJ”), to a new ALJ for further consideration. On November 13, 2007, the
new ALJ dismissed the citations and penalties entirely. We do not intend to
report on this matter in the future, absent unexpected material
developments.
Shareholder
Suits
On July
2, 2007, Manville Personal Injury Trust (“Manville”) filed a suit in the Circuit
Court of Kanawha County, West Virginia, which suit was amended on December 14,
2007, styled as a shareholder derivative action asserting that it is a
shareholder acting on our behalf. We are named as a nominal defendant. Each of
the members of our Board of Directors, certain of our officers, and certain of
our former directors and officers are named as defendants (“Manville
Defendants”). The Manville Defendants filed motions to dismiss the complaint
with the Circuit Court, which Manville has opposed.
On
September 7, 2007, Vernon Mercier filed a similar action in the United States
District Court, Southern District of West Virginia, styled as a shareholder
derivative action asserting that he is a shareholder acting on our behalf. We
are named as a nominal defendant. Each of the members of our Board of Directors
and certain of our officers and one former officer are named as defendants
(“Vernon Mercier Defendants”). On January 25, 2008, the Vernon Mercier
Defendants filed motions to dismiss the action with the United States District
Court, and alternatively to stay the action pending resolution of the Manville
case.
Each of
these complaints alleges breach of fiduciary duties to us arising out of either
the Manville Defendants’ or the Vernon Mercier Defendants' alleged failure to
cause us to comply with applicable state and federal environmental and
worker-safety laws and regulations. Both of the complaints seek to recover
unspecified damages in favor of us, appropriate equitable relief, and an award
to Manville and Vernon Mercier, respectively, of the costs and expenses
associated with these actions.
We
believe we, the Manville Defendants and the Vernon Mercier Defendants have
insurance coverage applicable to these matters. We believe these matters will be
resolved without a material impact on our cash flows, results of operations or
financial condition.
Other
Legal Proceedings
Certain
information regarding other legal proceedings required by this Item 3 is
contained in Note 17, “Contingencies and Commitments,” 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, 2007.
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 15, 2008, there were 80,491,644
shares outstanding and approximately 6,833
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.
|
|
High
|
|
|
Low
|
|
|
Dividends
|
|
Fiscal
Year 2006
|
|
|
|
|
|
|
|
|
|
|
|
$ |
41.53 |
|
|
$ |
33.10 |
|
|
$ |
0.04 |
|
|
|
$ |
44.34 |
|
|
$ |
32.15 |
|
|
$ |
0.04 |
|
|
|
$ |
37.05 |
|
|
$ |
18.77 |
|
|
$ |
0.04 |
|
|
|
$ |
28.00 |
|
|
$ |
19.31 |
|
|
$ |
0.04 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fiscal
Year 2007
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
26.35 |
|
|
$ |
21.55 |
|
|
$ |
0.04 |
|
|
|
$ |
30.73 |
|
|
$ |
23.97 |
|
|
$ |
0.04 |
|
|
|
$ |
26.80 |
|
|
$ |
16.01 |
|
|
$ |
0.04 |
|
|
|
$ |
37.99 |
|
|
$ |
21.49 |
|
|
$ |
0.05 |
|
Dividends
Our
current dividend policy anticipates the payment of quarterly dividends in the
future. Our asset-based revolving credit facility (the “ABL Facility”), our
6.625% senior notes due 2010 (the “6.625% Notes”) 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 6.625% Notes and 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 Indentures to the 6.625% Notes and 6.875% Notes). In addition, dividends can
be paid only so long as no default exists under the ABL Facility, the 6.625%
Notes, 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.
As of December 31, 2007, the price of Common Stock had reached the specified
threshold for conversion. Consequently, the 4.75% Notes are convertible until
March 31, 2008, the last day of our first quarter. The 4.75% Notes may be
convertible beyond this date if the specified threshold for conversion is met in
subsequent quarters. No conversions occurred during 2007. If all of the notes
outstanding at December 31, 2007 had been converted, we would have been required
to issue 37,649 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. See Note 6 to the Notes to
Consolidated Financial Statements for further discussion of the conversion and
redemption features of the 4.75% Notes.
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, 2007. If
all of the notes outstanding at December 31, 2007 had been eligible and were
converted, we would have been required to issue 287,113 shares of Common Stock.
See Note 6 to the Notes to Consolidated Financial Statements for further
discussion of conversion features of the 2.25% 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 $27.5 million of share repurchases. 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. On April 24, 2006,
our Board of Directors amended the program to allow share repurchases of up to
$50 million using cash currently on hand. Share repurchases of $50 million using
cash on hand were completed on June 8, 2006, with the purchase of 1,299,000
shares of Common Stock at an average price of $38.47 per share. In August 2007,
1,575,800 shares of Common Stock were purchased at an average price of $19.01
per share. No additional share repurchases have been made since that time. All
shares repurchased under the program have been recorded as Treasury
stock.
Transfer
Agent and Registrar
The
transfer agent and registrar for Common Stock is Wells Fargo Shareowner
Services, 161 North Concord Exchange, South St. Paul, Minnesota 55075, toll free
(800) 689-8788.
Item
6. Selected Financial Data
SELECTED
FINANCIAL DATA(1)
|
|
|
|
|
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
2003
|
|
|
|
(In
millions, except per share, per ton, and number of employees
amounts)
|
|
CONSOLIDATED
STATEMENT OF INCOME DATA:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Produced
coal revenue
|
|
$ |
2,054.4 |
|
|
$ |
1,902.3 |
|
|
$ |
1,777.7 |
|
|
$ |
1,456.7 |
|
|
$ |
1,262.1 |
|
Total
revenue
|
|
|
2,413.5 |
|
|
|
2,219.9 |
|
|
|
2,204.3 |
|
|
|
1,766.6 |
|
|
|
1,571.4 |
|
Income
(Loss) before interest and income taxes
|
|
|
179.7 |
|
|
|
111.0 |
|
|
|
(20.9 |
) |
|
|
46.2 |
|
|
|
(17.5 |
) |
Income
(Loss) before cumulative effect of accounting change
|
|
|
94.1 |
|
|
|
41.6 |
|
|
|
(101.6 |
) |
|
|
13.9 |
|
|
|
(32.3 |
) |
Net
income (loss)
|
|
|
94.1 |
|
|
|
41.0 |
|
|
|
(101.6 |
) |
|
|
13.9 |
|
|
|
(40.2 |
) |
Income
(Loss) per share - Basic (1)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
(Loss) before cumulative effect of accounting
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
change
|
|
$ |
1.17 |
|
|
$ |
0.51 |
|
|
$ |
(1.33 |
) |
|
$ |
0.18 |
|
|
$ |
(0.43 |
) |
Net
income (loss)
|
|
$ |
1.17 |
|
|
$ |
0.50 |
|
|
$ |
(1.33 |
) |
|
$ |
0.18 |
|
|
$ |
(0.54 |
) |
Income
(Loss) per share - Diluted (1)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
(Loss) before cumulative effect of accounting
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
change
|
|
$ |
1.17 |
|
|
$ |
0.51 |
|
|
$ |
(1.33 |
) |
|
$ |
0.18 |
|
|
$ |
(0.43 |
) |
Net
income (loss)
|
|
$ |
1.17 |
|
|
$ |
0.50 |
|
|
$ |
(1.33 |
) |
|
$ |
0.18 |
|
|
$ |
(0.54 |
) |
Dividends
declared per share
|
|
$ |
0.17 |
|
|
$ |
0.16 |
|
|
$ |
0.16 |
|
|
$ |
0.16 |
|
|
$ |
0.16 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CONSOLIDATED
BALANCE SHEET DATA:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Working
capital
|
|
$ |
522.6 |
|
|
$ |
445.2 |
|
|
$ |
670.8 |
|
|
$ |
458.4 |
|
|
$ |
443.2 |
|
Total
assets
|
|
|
2,860.7 |
|
|
|
2,740.7 |
|
|
|
2,986.5 |
|
|
|
2,650.9 |
|
|
|
2,376.7 |
|
Long-term
debt
|
|
|
1,102.7 |
|
|
|
1,102.3 |
|
|
|
1,102.6 |
|
|
|
900.2 |
|
|
|
784.3 |
|
Shareholders'
equity (2)
|
|
|
784.0 |
|
|
|
697.3 |
|
|
|
841.0 |
|
|
|
776.9 |
|
|
|
759.0 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OTHER
DATA:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EBIT
(3)
|
|
$ |
179.7 |
|
|
$ |
111.0 |
|
|
$ |
(20.9 |
) |
|
$ |
46.2 |
|
|
$ |
(17.5 |
) |
EBITDA
(3)
|
|
$ |
425.7 |
|
|
$ |
341.5 |
|
|
$ |
213.6 |
|
|
$ |
270.8 |
|
|
$ |
179.0 |
|
Average
cash cost per ton sold (4)
|
|
$ |
43.10 |
|
|
$ |
42.33 |
|
|
$ |
35.62 |
|
|
$ |
30.50 |
|
|
$ |
28.23 |
|
Produced
coal revenue per ton sold
|
|
$ |
51.55 |
|
|
$ |
48.71 |
|
|
$ |
42.02 |
|
|
$ |
36.02 |
|
|
$ |
30.79 |
|
Capital
expenditures
|
|
$ |
270.5 |
|
|
$ |
298.1 |
|
|
$ |
346.6 |
|
|
$ |
347.2 |
|
|
$ |
164.4 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Produced
tons sold
|
|
|
39.9 |
|
|
|
39.1 |
|
|
|
42.3 |
|
|
|
40.4 |
|
|
|
41.0 |
|
Tons
produced
|
|
|
39.5 |
|
|
|
38.6 |
|
|
|
43.1 |
|
|
|
42.0 |
|
|
|
41.0 |
|
Number
of employees
|
|
|
5,407 |
|
|
|
5,517 |
|
|
|
5,709 |
|
|
|
5,034 |
|
|
|
4,428 |
|
(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, 2007, 2006, 2005, 2004, and 2003, 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).
|
(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. For the year ended December 31, 2005, EBIT and EBITDA
include charges related to our capital restructuring of $212.4
million.
|
|
|
|
|
|
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
2003
|
|
|
|
(In
millions)
|
|
Net
income (loss)
|
|
$ |
94.1 |
|
|
$ |
41.0 |
|
|
$ |
(101.6 |
) |
|
$ |
13.9 |
|
|
$ |
(40.2 |
) |
Cumulative
effect of accounting change, net of tax
|
|
|
- |
|
|
|
0.6 |
|
|
|
- |
|
|
|
- |
|
|
|
7.9 |
|
Income
tax expense( benefit)
|
|
|
35.4 |
|
|
|
3.4 |
|
|
|
26.2 |
|
|
|
(19.5 |
) |
|
|
(28.3 |
) |
Net
interest expense
|
|
|
50.2 |
|
|
|
66.0 |
|
|
|
54.5 |
|
|
|
51.8 |
|
|
|
43.1 |
|
EBIT
|
|
|
179.7 |
|
|
|
111.0 |
|
|
|
(20.9 |
) |
|
|
46.2 |
|
|
|
(17.5 |
) |
Depreciation,
depletion and amortization
|
|
|
246.0 |
|
|
|
230.5 |
|
|
|
234.5 |
|
|
|
224.6 |
|
|
|
196.5 |
|
EBITDA
|
|
$ |
425.7 |
|
|
$ |
341.5 |
|
|
$ |
213.6 |
|
|
$ |
270.8 |
|
|
$ |
179.0 |
|
(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.
|
|
|
|
|
|
|
|
2006
|
|
2005
|
|
2004
|
|
2003
|
|
|
(In
millions, except per ton amounts)
|
|
|
|
$
|
|
per
ton
|
|
|
$
|
|
per
ton
|
|
|
$
|
|
per
ton
|
|
|
$
|
|
per
ton
|
|
|
$
|
|
per
ton
|
Total
costs and expenses
|
|
$ |
2,233.8 |
|
|
|
$ |
2,108.8 |
|
|
|
$ |
2,225.2 |
|
|
|
$ |
1,720.4 |
|
|
|
$ |
1,588.9 |
|
|
Less:
Freight and handling costs
|
|
|
167.6 |
|
|
|
|
156.5 |
|
|
|
|
150.9 |
|
|
|
|
148.8 |
|
|
|
|
109.7 |
|
|
Less:
Cost of purchased coal revenue
|
|
|
95.2 |
|
|
|
|
62.6 |
|
|
|
|
112.6 |
|
|
|
|
104.1 |
|
|
|
|
117.3 |
|
|
Less:
Depreciation, depletion and amortization
|
|
|
246.0 |
|
|
|
|
230.5 |
|
|
|
|
234.5 |
|
|
|
|
224.6 |
|
|
|
|
196.5 |
|
|
Less:
Other expense
|
|
|
7.3 |
|
|
|
|
6.2 |
|
|
|
|
8.0 |
|
|
|
|
9.5 |
|
|
|
|
9.8 |
|
|
Less:
Loss on capital restructuring
|
|
|
- |
|
|
|
|
- |
|
|
|
|
212.4 |
|
|
|
|
- |
|
|
|
|
- |
|
|
Average
cash cost
|
|
$ |
1,717.7 |
|
$ 43.10
|
|
$ |
1,653.0 |
|
$ 42.33
|
|
$ |
1,506.8 |
|
$ 35.62
|
|
$ |
1,233.4 |
|
$ 30.50
|
|
$ |
1,155.6 |
|
$ 28.23
|
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 ii 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.
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, 2007 of $94.1 million, or
$1.17 per basic share, compared to net income for 2006 of $41.0 million, or
$0.50 per basic share. 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 the EPA. Net income in 2006 included pre-tax gains totaling
approximately $30 million related to the sale of our Falcon
reserves.
Produced
tons sold were 39.9 million in 2007, compared to 39.1 million in 2006. Shipments
of metallurgical and industrial coal improved significantly in 2007 over 2006 as
productivity improved at underground room and pillar mines because of lower
turnover and a more stable workforce, and as performance improved from the
railroads shipping this coal. Shipments in 2006 were negatively affected by
productivity issues at underground mines, including the loss of six months of
production from our Logan County resource group’s Aracoma longwall mine due to a
fire in January 2006 and geological difficulties at several underground mines,
especially at the
longwall mines located at our Independence and Sidney resource groups. In 2006,
we also experienced railroad congestion due to heightened coal demand and a lack
of rail cars as well as a tight labor market that lead to high turnover and
inexperienced workers. We produced 39.5 million tons during 2007,
compared to 38.6 million tons produced in 2006.
During
2007, Produced coal revenue increased by 8% over the prior year as we benefited
from higher utility coal sales prices secured in new coal sales agreements as
lower-priced contracts expired and we shipped a larger percentage of
higher-priced metallurgical tons in 2007. Our average Produced coal revenue per
ton sold in 2007 increased by 5.8% to $51.55 compared to $48.71 in 2006 and by
67.4% over a five-year period compared to $30.79 in 2003. Our average Produced
coal revenue per ton in 2007 for metallurgical tons sold increased by 4.8% to
$72.49 from $69.20 in 2006.
We
experienced a significant increase in costs during the past 5-year period, with
Average cash cost per ton sold increasing from $28.23 in fiscal 2003 to $43.10
in fiscal 2007 (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.
In June 2006, the MINER Act was enacted
into law, which, among other things, requires mine-specific emergency response
plans, enhanced communication systems, and more available mine rescue teams and
provides for larger penalties by MSHA for noncompliance by mine operators. In
December 2006, MSHA passed its final rule on Emergency Mine Evacuation, which
includes requirements for increased availability and storage of SCSRs; improved
emergency evacuation drills and SCSR training and the installation and
maintenance of lifelines in underground coal mines. Coal producing states,
including West Virginia and Kentucky, passed similar legislation in 2006. While
the full cost of compliance remains unknown, we expect to spend a total of $30
million to $40 million from 2006 to 2009 to fully comply with these laws. The
growth in cost estimate is a result of further development of regulations plus
our proposed expansion, described
below. Costs for safety equipment are capitalized in Net Property, Plant and
Equipment. Additional substantive legislation is also possible in 2008 with the
passage by the United
States House of Representatives in January 2008 of the S-MINER Act. The
House legislation augments portions of the MINER Act and proposes changes to
retreat mining practices, study of substance abuse issues and the use of coal
dust monitors to reduce miner respirable dust exposure.
On May
10, 2007, the United States, on behalf of the Administrator of the EPA, filed
suit against us and twenty-seven of our subsidiaries in the United States
District Court for the Southern District of West Virginia (“District
Court”). The suit alleged that a number of our subsidiaries violated
the Federal Clean Water Act on thousands of occasions by
discharging
pollutants in excess of monthly and daily permit limits from 2000 to
2006. On January 17, 2008, a proposed settlement reached with the EPA
was filed with the District Court. The settlement, which requires District Court
approval, requires us to pay $20 million in penalties and make improvements in
our environmental processes. We expect the settlement to be approved by the
District Court in the first or second quarter of 2008. We recorded the $20
million in Cost of produced coal revenue in 2007.
On July
2, 2007, a jury awarded damages in favor of Wheeling-Pittsburgh Steel
Corporation and Mountain State Carbon, LLC in the amount of $219.9 million,
comprised of $119.9 million compensatory and $100 million punitive damages. On
July 30, 2007, the court awarded an additional $24 million of pre-judgment
interest. We have appealed this decision to the West Virginia Supreme
Court of Appeals. We believe that we have raised strong legal
arguments in our appeal to the West Virginia Supreme Court of Appeals that
create significant uncertainty regarding the ultimate outcome of this
matter. Ultimately, we believe it is unlikely any punitive damages
will be assessed in this matter. We further believe there is a strong
possibility that the West Virginia Supreme Court of Appeals will remand the
compensatory damages claim for retrial or significantly reduce the amount of the
compensatory damages awarded by the jury.
We
believe the range of possible loss in this matter is from $16 million to $244
million, prior to post-judgment interest or other costs. The minimum loss we
expect to incur upon final settlement or adjudication is the amount of excess
costs incurred by WPS to acquire coal required but not delivered under the
contract (plus pre-judgment interest) adjusted for performance excused by events
of force majeure. Amounts in excess of this amount may ultimately be awarded if
the West Virginia Supreme Court of Appeals upholds the circuit court’s
decisions, in whole or in part, or if the West Virginia Supreme Court of Appeals
remands the case for retrial and a jury awards the plaintiffs an amount in
excess of what we have accrued. 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 on appeal
and, therefore, the minimum amount in the range has been accrued (included in
Other current liabilities). It is reasonably possible that our
judgments regarding these matters could change in the near term, resulting in
the recording of additional material losses that would affect our operating
results and financial position. We posted a $50 million appeal bond
with the Court on October 25, 2007, which stays this matter pending disposition
of our appeal. Refer to Note 17 to the Notes to Consolidated Financial
Statements for further details.
In
November 2007, the West Virginia 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 Court approved a motion
to rehear the Harman case. We remain confident, however, that the Court
will ultimately uphold the November decision as we believe nothing has changed
the facts or the law that the Court will consider in reaching its final
decision. Reflected in our fourth quarter 2007 results are a positive
$22.0 million pre-tax impact recorded in Cost of produced coal revenue and a
positive pre-tax impact of $11.6 million recorded in Interest
expense stemming from the reversal of accruals that had been previously
established in conjunction with the Harman case.
In
October 2007, we announced plans to expand production at our Central Appalachian
coal mining operations during the next two years. Our two-year
internal expansion and cost reduction plan, which began in the fourth quarter of
2007, anticipates developing net additional annual production of 8 million tons
in 2010 versus 2007, with the ramp up expected to occur during 2008 and 2009.
Additionally, these new tons will be weighted towards metallurgical coal
production, which we believe will be cost advantaged versus existing comparable
quality competitor production. We expect to fund all of our expansion projects
out of existing liquidity and operating cash flow generated in 2008 and 2009,
although some equipment may be acquired under operating or capital
leases.
Results
of Operations
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 |
% |
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 |
% |
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.
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. Because of the discrete tax events occurring
in 2007, the tax rate for 2007 may not be indicative of future tax
rates.
2006
Compared with 2005
Revenues
|
|
Year
Ended
|
|
|
|
|
|
|
|
|
|
December
31,
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Increase
|
|
|
%
Increase
|
|
(In
thousands)
|
|
2006
|
|
|
2005
|
|
|
(Decrease)
|
|
|
(Decrease)
|
|
Revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
Produced
coal revenue
|
|
$ |
1,902,259 |
|
|
$ |
1,777,724 |
|
|
$ |
124,535 |
|
|
|
7 |
% |
Freight
and handling revenue
|
|
|
156,531 |
|
|
|
150,898 |
|
|
|
5,633 |
|
|
|
4 |
% |
Purchased
coal revenue
|
|
|
70,636 |
|
|
|
132,320 |
|
|
|
(61,684 |
) |
|
|
(47 |
)% |
Other
revenue
|
|
|
90,428 |
|
|
|
143,316 |
|
|
|
(52,888 |
) |
|
|
(37 |
)% |
Total
revenues
|
|
$ |
2,219,854 |
|
|
$ |
2,204,258 |
|
|
$ |
15,596 |
|
|
|
1 |
% |
The
following is a breakdown, by market served, of the changes in produced tons sold
and average produced coal revenue per ton sold for 2006 compared to
2005:
|
|
Year
Ended December 31,
|
|
|
|
|
|
|
|
(In
millions, except per ton amounts)
|
|
2006
|
|
|
2005
|
|
|
Increase
(Decrease)
|
|
|
%
Increase (Decrease)
|
|
Produced tons
sold:
|
|
|
|
|
|
|
|
|
|
|
|
|
Utility
|
|
|
27.7 |
|
|
|
29.2 |
|
|
|
(1.5 |
) |
|
|
(5 |
)% |
Metallurgical
|
|
|
7.8 |
|
|
|
9.4 |
|
|
|
(1.6 |
) |
|
|
(17 |
)% |
Industrial
|
|
|
3.6 |
|
|
|
3.7 |
|
|
|
(0.1 |
) |
|
|
(3 |
)% |
Total
|
|
|
39.1 |
|
|
|
42.3 |
|
|
|
(3.2 |
) |
|
|
(8 |
)% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Produced coal revenue
per ton sold:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Utility
|
|
$ |
42.37 |
|
|
$ |
36.66 |
|
|
$ |
5.71 |
|
|
|
16 |
% |
Metallurgical
|
|
|
69.20 |
|
|
|
54.19 |
|
|
|
15.01 |
|
|
|
28 |
% |
Industrial
|
|
|
53.13 |
|
|
|
53.19 |
|
|
|
(0.06 |
) |
|
|
0 |
% |
Weighted
average
|
|
|
48.71 |
|
|
|
42.02 |
|
|
|
6.69 |
|
|
|
16 |
% |
Shipments
in 2006 were negatively affected by productivity issues at underground mines,
including the loss of six months of production from our Logan County resource
group’s Aracoma longwall mine due to a fire in January 2006 and geological
difficulties at several underground mines, especially at our Revolution and
Rockhouse longwall mines. In 2006, we also experienced railroad
congestion due to heightened coal demand and a lack of rail cars and a tight
labor market that lead to high turnover and inexperienced workers.
The
improvement in our average per ton sales price was attributable to prices
contracted during a period of increased demand for all grades of coal in the
United States and for metallurgical coal worldwide. The higher demand resulted
in shortages of certain coals, increasing the market prices of these coals, and
allowed us to negotiate agreements containing higher price terms as our
lower-priced sales contracts expired. Increased prices for alternative fuel
sources such as oil and natural gas also resulted in higher demand for certain
coals. Exports of metallurgical coal decreased by 1.0 million tons, or 19%, to
4.2 million tons for 2006 as compared to 2005 due to lower
production.
Purchased
coal revenue decreased mainly due to a decrease in purchased tons sold from 2.5
million in 2005 to 1.3 million in 2006, offset by a 3% increase in revenue per
ton. We purchase varying amounts of coal to supplement produced coal
sales.
Other
revenue consists of royalties, rentals, earnings associated with coal handling
facilities, gas well revenues, synfuel earnings, gains on the sale of
non-strategic assets, contract settlement payments, and miscellaneous income.
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). Other revenue for 2005 includes a pre-tax
gain of $45.9 million related to the sale of our ownership interest in Big Elk
Mining Company and a pre-tax gain of $38.2 million on a coal reserves exchange
(see Note 4 in the Notes to Consolidated Financial Statements for further
discussion).
Costs
|
|
Year
Ended
|
|
|
|
|
|
|
|
|
|
December
31,
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Increase
|
|
|
%
Increase
|
|
(In
thousands)
|
|
2006
|
|
|
2005
|
|
|
(Decrease)
|
|
|
(Decrease)
|
|
Costs
and expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost
of produced coal revenue
|
|
$ |
1,599,092 |
|
|
$ |
1,438,494 |
|
|
$ |
160,598 |
|
|
|
11 |
% |
Freight
and handling costs
|
|
|
156,531 |
|
|
|
150,898 |
|
|
|
5,633 |
|
|
|
4 |
% |
Cost
of purchased coal revenue
|
|
|
62,613 |
|
|
|
112,600 |
|
|
|
(49,987 |
) |
|
|
(44 |
)% |
Depreciation,
depletion and amortization, applicable to:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost
of produced coal revenue
|
|
|
227,279 |
|
|
|
230,545 |
|
|
|
(3,266 |
) |
|
|
(1 |
)% |
Selling,
general and administrative
|
|
|
3,259 |
|
|
|
4,020 |
|
|
|
(761 |
) |
|
|
(19 |
)% |
Selling,
general and administrative
|
|
|
53,834 |
|
|
|
68,254 |
|
|
|
(14,420 |
) |
|
|
(21 |
)% |
Other
expense
|
|
|
6,240 |
|
|
|
8,018 |
|
|
|
(1,778 |
) |
|
|
(22 |
)% |
Loss
on capital restructuring
|
|
|
- |
|
|
|
212,378 |
|
|
|
(212,378 |
) |
|
|
(100 |
)% |
Total
costs and expenses
|
|
$ |
2,108,848 |
|
|
$ |
2,225,207 |
|
|
$ |
(116,359 |
) |
|
|
(5 |
)% |
Cost of
produced coal revenue on a per ton of coal sold basis increased 19% in 2006
compared with 2005, resulting from a variety of factors including higher labor
and benefit costs, higher supply costs, including diesel fuel, explosives,
copper and steel prices, productivity issues at several underground mines,
including the Revolution and Rockhouse longwall mines, and difficulties
encountered in the restart of the Aracoma mine in July 2006. The Aracoma mine
experienced a fire in January 2006, which also contributed significantly to the
increase in Cost of produced coal revenue. Also negatively impacting Cost of
produced coal revenue were higher sales-related costs for production royalties
and taxes, and severance and black lung excise taxes associated with the
increase in average realized prices. Tons produced during 2006 were 38.6 million
compared to 43.1 million during 2005.
Cost of
purchased coal revenue decreased mainly due to a decrease in purchased tons sold
from 2.5 million in 2005 to 1.3 million in 2006, offset by a 7% increase in
average cost of purchased coal per ton.
Selling,
general and administrative expenses decreased primarily due to lower stock-based
compensation accruals due to changes in the price of the Company’s stock and
lower performance-linked executive compensation accruals in 2006.
Other
expense, which consists of costs associated with the generation of other
revenue, such as costs to operate the coal handling facilities, gas wells, and
other miscellaneous expenses, decreased due to decreases in operating costs of
the gas wells and synfuel facility, while senior note repurchase losses were
recognized in 2005.
Interest
Interest
income increased due to higher levels of cash reserves during 2006 and higher
interest rates received on investments during 2006. Interest expense increased
primarily a result of a debt restructuring that occurred in December 2005, which
increased debt levels in 2006 compared to 2005, and resulted in a higher
effective interest rate. Interest expense in 2005 included a $6.6 million
write-off of previously unamortized debt issuance costs related to our debt
restructuring.
Income
Taxes
The income
tax rate for 2006 was favorably impacted by percentage depletion allowances, the
usage of a net operating loss carryforward and the adjustment of reserves in
connection with the closing of a prior period audit by the IRS. The income tax
rate for 2005 was negatively impacted by the non-deductibility on the early
payout of deferred compensation ($7.5 million tax effect) and the
non-deductibility on our debt repurchases and exchange offers during the fourth
quarter. The tax rate for 2005 was favorably impacted by percentage depletion
allowances, the usage of a net operating loss carry forward, the adjustment of
reserves in connection with the closing of a prior period audit by state taxing
authorities and the IRS and the closing of a federal statutory period. Because
of the discrete tax events occurring in 2006 and 2005, the tax rates for 2006
and 2005 may not be indicative of future tax rates.
Liquidity
and Capital Resources
At
December 31, 2007, our available liquidity was $479.3 million, which consisted
of cash and cash equivalents of $365.2 million and $114.1 million availability
under the asset-backed liquidity facility.
Debt was
comprised of the following:
|
|
December
31,
|
|
|
|
|
|
|
|
|
|
2006
|
|
|
|
(In
Thousands)
|
|
6.875%
senior notes due 2013, net of discount
|
|
$ |
755,401 |
|
|
$ |
754,804 |
|
6.625%
senior notes due 2010
|
|
|
335,000 |
|
|
|
335,000 |
|
2.25%
convertible senior notes due 2024
|
|
|
9,647 |
|
|
|
9,647 |
|
4.75%
convertible senior notes due 2023
|
|
|
730 |
|
|
|
730 |
|
Capital
lease obligations
|
|
|
8,823 |
|
|
|
11,232 |
|
Fair
value hedge adjustment
|
|
|
(5,054 |
) |
|
|
(6,506 |
) |
Total
debt
|
|
|
1,104,547 |
|
|
|
1,104,907 |
|
Amounts
due within one year
|
|
|
(1,875 |
) |
|
|
(2,583 |
) |
Total
long-term debt
|
|
$ |
1,102,672 |
|
|
$ |
1,102,324 |
|
See Note
6 in the Notes to Consolidated Financial Statements for further discussion of
our debt and debt-related covenants.
Asset-Based Credit
Facility
On August
15, 2006, we amended and restated our 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 previous credit limit was $130 million, including a $100 million
sublimit for letters of credit. In addition, we achieved improved pricing and
extended the facility’s maturity to August 2011. As of December 31, 2007, there
were $60.9 million of letters of credit issued and there were no 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, 2007, our S&P
outlook rating is Stable. Moody’s outlook on all of our notes is Stable; our
Corporate Family Rating is B1.
Current
Ratings:
|
|
Moody’s
|
|
|
S&P
|
|
6.875%
Notes
|
|
|
B2 |
|
|
|
B |
+ |
6.625%
Notes
|
|
|
B2 |
|
|
|
B |
+ |
2.25%
Notes
|
|
|
B2 |
|
|
|
B |
+ |
4.75%
Notes
|
|
|
B3 |
|
|
|
B |
- |
Cash
Flow
Net cash
provided by operating activities was $396.0 million for 2007 compared to $214.5
million for 2006. Cash provided by operating activities reflects Net income
adjusted for non-cash charges and changes in working capital
requirements. Cash provided by operating activities for 2007 includes
$34.1 million of payments for income taxes.
Net cash
utilized by investing activities was $242.3 million and $246.7 million for 2007
and 2006, respectively. The cash used in investing activities reflects capital
expenditures in the amount of $270.5 million and $298.1 million for 2007 and
2006, 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 and $25.3 million of cash spent for the buyout of
operating leases in 2007 and 2006, respectively. Additionally, 2007 and 2006
included $28.1 million and $51.5 million, respectively, of proceeds provided by
the sale of assets. Proceeds from the sale of assets for 2006 included $30.8
million in cash related to the sale of our Falcon reserves (see Note 4 to the
Notes to Consolidated Financial Statements for further discussion).
Financing
activities primarily reflect changes in debt levels for 2007 and 2006, as well
as the exercising of stock options and payments of dividends. Net cash utilized
by financing activities was $27.7 million for 2007 compared to $48.0
million
for 2006. Financing activities for 2007 and 2006 included $30 million and $50
million, respectively, for the repurchase of 1.6 and 1.3 million shares,
respectively, of Common Stock under the share repurchase program discussed
below. We
generated $13.1 million from several sale-leaseback (operating leases)
transactions of certain mining equipment in 2007, compared to $21.8 million of
sale-leasebacks (operating leases) in 2006.
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, 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 few years. Nevertheless, our ability to
satisfy our debt service obligations, repurchase shares, 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. We frequently evaluate
potential acquisitions. In the past, we have funded acquisitions primarily with
cash generated from operations, but we may consider a variety of other sources,
depending on the size of any transaction, including debt or equity financing.
Additional capital resources may not be available to us on terms that we find
acceptable, or at all.
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. Share
repurchases of $50 million using cash on hand were completed on June 8, 2006,
with the purchase of 1,299,000 shares of Common Stock at an average price of
$38.47 per share. In August 2007, 1,575,800 shares of Common Stock were
purchased at an average price of $19.01 per share. As of December 31, 2007, we
had $420 million available under the current authorization. We may
repurchase our 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 2007.
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
|
|
|
- |
|
|
|
|
|
|
|
- |
|
|
|
11,339,093 |
|
(1)
|
__________________________
__________________________
(1)
|
|
Calculated
using $420 million that may yet be purchased under our share repurchase
program and $37.04, the closing price of Common Stock as reported on the
New York Stock Exchange on January 31,
2008.
|
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,
2007 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)
|
|
$ |
1,489,251 |
|
|
$ |
74,695 |
|
|
$ |
484,391 |
|
|
$ |
105,003 |
|
|
$ |
825,162 |
|
Capital
lease obligations
(2)
|
|
|
9,736 |
|
|
|
2,430 |
|
|
|
4,651 |
|
|
|
2,655 |
|
|
|
- |
|
Operating
lease obligations (3)
|
|
|
161,331 |
|
|
|
42,669 |
|
|
|
73,704 |
|
|
|
39,080 |
|
|
|
5,878 |
|
Coal
lease obligations (4)
|
|
|
188,129 |
|
|
|
16,788 |
|
|
|
30,974 |
|
|
|
25,104 |
|
|
|
115,263 |
|
Purchased
coal obligations (5)
|
|
|
127,389 |
|
|
|
67,749 |
|
|
|
59,640 |
|
|
|
- |
|
|
|
- |
|
Other
purchase obligations (6)
|
|
|
317,954 |
|
|
|
266,153 |
|
|
|
29,385 |
|
|
|
12,624 |
|
|
|
9,792 |
|
Total
Obligations
|
|
$ |
2,293,790 |
|
|
$ |
470,484 |
|
|
$ |
682,745 |
|
|
$ |
184,466 |
|
|
$ |
956,095 |
|
__________________________
(1)
|
Long-term
debt obligations reflect the future interest and principal payments of our
fixed rate senior unsecured notes outstanding as of December 31, 2007. 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,
2007.
|
(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 December
31, 2007, payments related to these items are estimated to be:
|
|
|
Payments
Due by Years (In Thousands)
|
Within
1
Year
|
1
- 3
Years
|
3
- 5
Years
|
|
|
|
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 2007, 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.
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, 2007, we had $106.0 million of letters of credit outstanding of
which $45.1 million was collateralized by $46.0 million of cash deposited in
restricted, interest bearing accounts pledged to issuing banks and $60.9 million
was issued under our asset based lending arrangement. No claims were outstanding
against those letters of credit as of December 31, 2007.
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, 2007, we had $364.1 million of
outstanding surety bonds. These bonds were in place to secure obligations as
follows: post-mining reclamation bonds of $304.7 million, an appeal bond of
$50.0 million, and other miscellaneous obligation bonds of $9.4 million.
Outstanding surety bonds of $46.1 million are secured with letters of credit. In
addition, in October 2007, we deposited $50.0 million into an interest bearing
account which is pledged to an insurance company that issued the $50.0 million
appeal bond in the Wheeling-Pitt legal matter (see Note 17 to Notes to
Consolidated Financial Statements for additional details). The $50.0
million is reported in Deposits within Other current assets.
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. We may not be able to resolve all of
these disputes in a satisfactory manner, which could result in the payment of
substantial damages or otherwise harm our relationships with our
customers.
The
planned expansion of our coal production involves a number of risks, any of
which could cause us not to realize the anticipated benefits.
In
October 2007, we announced plans to expand production at our Central Appalachian
coal mining operations during the next two years. Our two-year
internal expansion and cost reduction plan anticipates developing net additional
annual production of 8 million tons in 2010 versus 2007, with the ramp up
occurring during 2008 and 2009. Additionally, these new tons will be weighted
towards metallurgical coal production, which we believe will be cost advantaged
versus existing comparable quality competitor production. We expect to fund all
of our expansion projects out of existing liquidity and operating cash flow
generated in 2008 and 2009. If we are unable to successfully expand
our coal production, our profitability may decline and we could experience a
material adverse effect on our cash flows, results of operations or financial
condition. These expansion plans involve certain risks, including:
|
•
|
the
accuracy of our assumptions of the recoverability of the coal reserves to
be mined;
|
|
•
|
assumptions
about the availability of skilled labor to staff the new and expanded
mines;
|
|
•
|
assumptions
about the availability and cost of the capital equipment required for each
of the new and expanded mines; and
|
|
•
|
unanticipated
changes in business, industry or general economic conditions that affect
the assumptions underlying our rationale for expanding our
production.
|
Any one
or more of these factors could cause us not to realize the benefits anticipated
to result from our expansion plans. Our expansion plans could materially affect
our liquidity and capital resources and may require us to incur indebtedness,
seek equity, capital or both.
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 impact on us. 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.
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.
Inflationary
pressures on supplies and labor may adversely affect our profit
margins.
Generally,
inflation in the United
States has been relatively low in recent years. However, over the course
of the last two 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, copper and labor. For instance, the prices of diesel fuel and copper each
increased approximately 20% over the two-year period ending December 31, 2007.
If the prices for which we sell our coal do not increase in step with rising
costs, our profit margins will be reduced.
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, 2007 and 2006, the discount rate used to
determine defined benefit pension liability was 6.50% and 5.90%, respectively.
The impact of lowering the discount rate 0.25% for 2007 would have increased the
2007 net periodic pension expense by approximately $1.7 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, 2007 and 2006. 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, 2007, 2006 and 2005,
respectively. A 0.5% decrease in the expected long-term rate of return
assumption would have increased the 2007 net periodic pension expense by
approximately $1.4 million. 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.
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 December
31, 2007 and December 31, 2006, the discount rate used to determine the black
lung liability was 6.50% and 5.90%, respectively. Included in Note 11 to the
Notes to Consolidated Financial Statements is a medical cost trend and cost of
living trend sensitivity analysis.
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, 2007 and December 31, 2006, 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, 2007 and December 31, 2006, the
discount rate used to determine the other postretirement benefit liability was
6.50% and 5.90%, respectively. The impact of lowering the discount rate 0.25%
for 2007 would have increased the 2007 net periodic postretirement benefit cost
by approximately $0.4
million. At December 31, 2007, our assumptions of the company health care plans’
cost trend were projected at an annual rate of 8.5% ranging down to 5.0% by 2013
(8.2% ranging down to 5.0% by 2011 at December 31, 2006), and remaining level
thereafter. The impact of increasing the health care cost trend rate by 1.0%
would have increased the 2007 net periodic postretirement benefit cost by
approximately $2.0 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 17
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.
Under FIN
48, we 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 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. We
are currently under audit from the IRS for the calendar years ended December 31,
2003 and 2004. Management believes that we have adequately provided for any
income taxes and penalties and interest 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 effect 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.
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 sensitive to changes in the general level of short-term
interest rates. At December 31, 2007, the outstanding $1,104.5 million of our
debt was under fixed-rate instruments. Upon the termination of our $240 million
interest rate swap agreement in December 2005, our interest expense is no longer
sensitive to changes in the general level of short-term interest rates. 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, 2007 level of $365.2 million, a
hypothetical 100 basis point decrease in money market interest rates would
result in a decrease of approximately $3.7 million in Interest
income.
We manage
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
sales pursuant to these long-term contracts was 95% for our fiscal year ended
December 31, 2007. We anticipate that in 2008, the percentage of our sales
pursuant to long-term contracts will be comparable with the percentage of our
sales for 2007. 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 typically allow the customer to
elect volume flexibility, 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.
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, 2007 and 2006, and the related consolidated statements of
income, shareholders' equity, and cash flows for each of the three years in the
period ended December 31, 2007. 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, 2007 and 2006, and the consolidated results of its operations
and its cash flows for each of the three years in the period ended December 31,
2007, 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 FASB 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 Notes
5, 10 and 11 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 12 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, 2007, 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 28, 2008
expressed an unqualified opinion thereon.
Richmond,
Virginia
MASSEY
ENERGY COMPANY
|
|
CONSOLIDATED
STATEMENTS OF INCOME
|
|
(In
Thousands, Except Per Share Amounts)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year
Ended
|
|
|
|
|
December
31,
|
|
|
December
31,
|
|
|
|
|
|
|
|
|
|
|
2006
|
|
|
2005
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues
|
|
|
|
|
|
|
|
|
|
|
Produced
coal revenue
|
|
$ |
2,054,413 |
|
|
$ |
1,902,259 |
|
|
$ |
1,777,724 |
|
Freight
and handling revenue
|
|
|
167,641 |
|
|
|
156,531 |
|
|
|
150,898 |
|
Purchased
coal revenue
|
|
|
108,191 |
|
|
|
70,636 |
|
|
|
132,320 |
|
Other
revenue
|
|
|
83,278 |
|
|
|
90,428 |
|
|
|
143,316 |
|
|
Total
revenues
|
|
|
2,413,523 |
|
|
|
2,219,854 |
|
|
|
2,204,258 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Costs
and expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost
of produced coal revenue
|
|
|
1,641,774 |
|
|
|
1,599,092 |
|
|
|
1,438,494 |
|
Freight
and handling costs
|
|
|
167,641 |
|
|
|
156,531 |
|
|
|
150,898 |
|
Cost
of purchased coal revenue
|
|
|
95,241 |
|
|
|
62,613 |
|
|
|
112,600 |
|
Depreciation,
depletion and amortization, applicable to:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost
of produced coal revenue
|
|
|
242,755 |
|
|
|
227,279 |
|
|
|
230,545 |
|
|
Selling,
general and administrative
|
|
|
3,280 |
|
|
|
3,259 |
|
|
|
4,020 |
|
Selling,
general and administrative
|
|
|
75,845 |
|
|
|
53,834 |
|
|
|
68,254 |
|
Other
expense
|
|
|
7,308 |
|
|
|
6,240 |
|
|
|
8,018 |
|
Loss
on capital restructuring
|
|
|
- |
|
|
|
- |
|
|
|
212,378 |
|
|
Total
costs and expenses
|
|
|
2,233,844 |
|
|
|
2,108,848 |
|
|
|
2,225,207 |
|
Income
(Loss) before interest and taxes
|
|
|
179,679 |
|
|
|
111,006 |
|
|
|
(20,949 |
) |
Interest
income
|
|
|
|
23,969 |
|
|
|
20,094 |
|
|
|
12,603 |
|
Interest
expense
|
|
|
|
(74,145 |
) |
|
|
(86,076 |
) |
|
|
(67,064 |
) |
Income
(Loss) before taxes
|
|
|
129,503 |
|
|
|
45,024 |
|
|
|
(75,410 |
) |
Income
tax expense
|
|
|
(35,405 |
) |
|
|
(3,408 |
) |
|
|
(26,228 |
) |
Income
(Loss) before cumulative effect of accounting change
|
|
|
94,098 |
|
|
|
41,616 |
|
|
|
(101,638 |
) |
Cumulative
effect of accounting change, net of tax
|
|
|
- |
|
|
|
(639 |
) |
|
|
- |
|
Net
income (loss)
|
|
|
$ |
94,098 |
|
|
$ |
40,977 |
|
|
$ |
(101,638 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
(Loss) per share - Basic
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
(Loss) before cumulative effect of accounting change
|
|
$ |
1.17 |
|
|
$ |
0.51 |
|
|
$ |
(1.33 |
) |
Cumulative
effect of accounting change
|
|
|
- |
|
|
|
(0.01 |
) |
|
|
- |
|
Net
income (loss)
|
|
$ |
1.17 |
|
|
$ |
0.50 |
|
|
$ |
(1.33 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
(Loss) per share - Diluted
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
(Loss) before cumulative effect of accounting change
|
|
$ |
1.17 |
|
|
$ |
0.51 |
|
|
$ |
(1.33 |
) |
Cumulative
effect of accounting change
|
|
|
- |
|
|
|
(0.01 |
) |
|
|
- |
|
Net
income (loss)
|
|
$ |
1.17 |
|
|
$ |
0.50 |
|
|
$ |
(1.33 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Shares
used to calculate income per share
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
|
|
80,123 |
|
|
|
80,847 |
|
|
|
76,390 |
|
Diluted
|
|
|
|
80,654 |
|
|
|
81,386 |
|
|
|
76,390 |
|
See Notes
to Consolidated Financial Statements
|
|
CONSOLIDATED
BALANCE SHEETS
|
|
(In
Thousands, Except Share Amounts)
|
|
|
|
|
|
|
|
|
|
|
December
31,
|
|
|
|
|
|
|
|
|
|
2006
|
|
ASSETS
|
|
|
|
|
|
|
Current
Assets
|
|
|
|
|
|
|
Cash
and cash equivalents
|
|
$ |
365,220 |
|
|
$ |
239,245 |
|
Trade
and other accounts receivable, less allowance of $444 and
$576,
|
|
|
|
|
|
|
|
|
respectively
|
|
|
156,572 |
|
|
|
197,105 |
|
Inventories
|
|
|
183,360 |
|
|
|
191,056 |
|
Income
taxes receivable
|
|
|
16,302 |
|
|
|
- |
|
Other
current assets
|
|
|
165,940 |
|
|
|
172,322 |
|
Total
current assets
|
|
|
887,394 |
|
|
|
799,728 |
|
|
|
|
|
|
|
|
|
|
Net
Property, Plant and Equipment
|
|
|
1,793,920 |
|
|
|
1,776,781 |
|
Other
Noncurrent Assets
|
|
|
|
|
|
|
|
|
Pension
assets
|
|
|
47,323 |
|
|
|
34,974 |
|
Other
noncurrent assets
|
|
|
132,034 |
|
|
|
129,213 |
|
Total
other noncurrent assets
|
|
|
179,357 |
|
|
|
164,187 |
|
Total
assets
|
|
$ |
2,860,671 |
|
|
$ |
2,740,696 |
|
|
|
|
|
|
|
|
|
|
LIABILITIES
AND SHAREHOLDERS' EQUITY
|
|
|
|
|
|
|
|
|
Current
Liabilities
|
|
|
|
|
|
|
|
|
Accounts
payable, principally trade and bank overdrafts
|
|
$ |
148,206 |
|
|
$ |
117,157 |
|
Short-term
debt
|
|
|
1,875 |
|
|
|
2,583 |
|
Payroll
and employee benefits
|
|
|
46,512 |
|
|
|
40,380 |
|
Income
taxes payable
|
|
|
- |
|
|
|
19,412 |
|
Other
current liabilities
|
|
|
171,269 |
|
|
|
175,005 |
|
Total
current liabilities
|
|
|
367,862 |
|
|
|
354,537 |
|
Noncurrent
Liabilities
|
|
|
|
|
|
|
|
|
Long-term
debt
|
|
|
1,102,672 |
|
|
|
1,102,324 |
|
Deferred
income taxes
|
|
|
154,705 |
|
|
|
116,690 |
|
Other
noncurrent liabilities
|
|
|
451,428 |
|
|
|
469,854 |
|
Total
noncurrent liabilities
|
|
|
1,708,805 |
|
|
|
1,688,868 |
|
Total
liabilities
|
|
|
2,076,667 |
|
|
|
2,043,405 |
|
Shareholders’
Equity
|
|
|
|
|
|
|
|
|
Capital
stock
|
|
|
|
|
|
|
|
|
Preferred
– authorized 20,000,000 shares without par value; none
issued
|
|
|
- |
|
|
|
- |
|
Common
– authorized 150,000,000 shares of $0.625 par value;
issued
|
|
|
|
|
|
|
|
|
82,818,578
and 82,365,259 shares, respectively
|
|
|
51,743 |
|
|
|
51,458 |
|
Treasury
stock, 2,874,800 and 1,299,000 shares at cost,
respectively
|
|
|
(79,986 |
) |
|
|
(49,995 |
) |
Additional
capital
|
|
|
237,684 |
|
|
|
220,650 |
|
Retained
earnings
|
|
|
601,587 |
|
|
|
515,894 |
|
Accumulated
other comprehensive loss
|
|
|
(27,024 |
) |
|
|
(40,716 |
) |
Total
shareholders’ equity
|
|
|
784,004 |
|
|
|
697,291 |
|
Total
liabilities and shareholders’ equity
|
|
$ |
2,860,671 |
|
|
$ |
2,740,696 |
|
See Notes
to Consolidated Financial Statements.
MASSEY
ENERGY COMPANY
|
|
CONSOLIDATED
STATEMENT OF CASH FLOWS
|
|
(In
Thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year
Ended
|
|
|
|
|
|
|
|
|
|
|
Cash
Flows from Operating Activities
|
|
|
|
|
|
|
|
|
|
Net
income (loss)
|
|
$ |
94,098 |
|
|
$ |
40,977 |
|
|
$ |
(101,638 |
) |
Adjustments
to reconcile Net income (loss) to Cash provided by
operating
|
|
|
|
|
|
|
|
|
|
|
|
|
activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Cumulative
effect of accounting change
|
|
|
- |
|
|
|
639 |
|
|
|
- |
|
Depreciation,
depletion and amortization
|
|
|
246,035 |
|
|
|
230,538 |
|
|
|
234,565 |
|
Share-based
compensation expense
|
|
|
19,299 |
|
|
|
7,350 |
|
|
|
- |
|
Deferred
income taxes
|
|
|
27,403 |
|
|
|
(17,381 |
) |
|
|
23,259 |
|
Gain
on disposal of assets
|
|
|
(6,751 |
) |
|
|
(46,557 |
) |
|
|
(63,879 |
) |
Gain
on reserve exchange
|
|
|
(10,284 |
) |
|
|
- |
|
|
|
(38,198 |
) |
Loss
on repurchase of senior notes
|
|
|
- |
|
|
|
- |
|
|
|
669 |
|
Loss
on debt restructuring
|
|
|
- |
|
|
|
- |
|
|
|
212,378 |
|
Writeoff
of deferred financing costs
|
|
|
- |
|
|
|
- |
|
|
|
6,648 |
|
Accretion
of asset retirement obligations
|
|
|
11,758 |
|
|
|
10,166 |
|
|
|
10,156 |
|
Changes
in operating assets and liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Decrease
(increase) in accounts receivable
|
|
|
19,253 |
|
|
|
(43,456 |
) |
|
|
13,559 |
|
Decrease
(increase) in inventories
|
|
|
7,696 |
|
|
|
(8,070 |
) |
|
|
(85,869 |
) |
Decrease
(increase) in other current assets
|
|
|
6,382 |
|
|
|
24,573 |
|
|
|
(4,695 |
) |
(Increase)
decrease in pension and other assets
|
|
|
(191 |
) |
|
|
1,165 |
|
|
|
(6,830 |
) |
Increase
(decrease) in accounts payable and bank overdrafts
|
|
|
31,049 |
|
|
|
(45,632 |
) |
|
|
26,917 |
|
(Decrease)
increase in accrued income taxes
|
|
|
(35,714 |
) |
|
|
42,638 |
|
|
|
15,320 |
|
(Decrease)
increase in other accrued liabilities
|
|
|
(558 |
) |
|
|
17,046 |
|
|
|
19,502 |
|
(Decrease)
increase in other noncurrent liabilities
|
|
|
(2,416 |
) |
|
|
4,712 |
|
|
|
12,140 |
|
Asset
retirement obligation payments
|
|
|
(11,061 |
) |
|
|
(4,205 |
) |
|
|
(3,858 |
) |
Cash
provided by operating activities
|
|
|
395,998 |
|
|
|
214,503 |
|
|
|
270,146 |
|
Cash
Flows from Investing Activities
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital
expenditures
|
|
|
(270,461 |
) |
|
|
(298,132 |
) |
|
|
(346,578 |
) |
Proceeds
from sale of assets
|
|
|
28,118 |
|
|
|
51,467 |
|
|
|
73,542 |
|
Cash
utilized by investing activities
|
|
|
(242,343 |
) |
|
|
(246,665 |
) |
|
|
(273,036 |
) |
Cash
Flows from Financing Activities
|
|
|
|
|
|
|
|
|
|
|
|
|
Repurchase
of senior notes
|
|
|
- |
|
|
|
- |
|
|
|
(19,890 |
) |
Stock
repurchase
|
|
|
(29,991 |
) |
|
|
(49,995 |
) |
|
|
- |
|
Repayments
of capital lease obligations
|
|
|
(2,409 |
) |
|
|
(10,214 |
) |
|
|
(19,370 |
) |
Proceeds
from issuance of 6.875% senior notes
|
|
|
- |
|
|
|
- |
|
|
|
742,847 |
|
Debt
restructuring
|
|
|
- |
|
|
|
- |
|
|
|
(562,608 |
) |
Early
termination of fair value hedge
|
|
|
- |
|
|
|
- |
|
|
|
(7,922 |
) |
Proceeds
from sale-leaseback transactions
|
|
|
13,146 |
|
|
|
21,819 |
|
|
|
71,697 |
|
Cash
dividends paid
|
|
|
(12,837 |
) |
|
|
(12,814 |
) |
|
|
(12,208 |
) |
Proceeds
from stock options exercised
|
|
|
4,001 |
|
|
|
2,142 |
|
|
|
7,231 |
|
Excess
income tax benefit from stock option exercises
|
|
|
410 |
|
|
|
1,051 |
|
|
|
- |
|
Cash
(utilized) provided by financing activities
|
|
|
(27,680 |
) |
|
|
(48,011 |
) |
|
|
199,777 |
|
Increase
(decrease) in cash and cash equivalents
|
|
|
125,975 |
|
|
|
(80,173 |
) |
|
|
196,887 |
|
Cash
and cash equivalents at beginning of period
|
|
|
239,245 |
|
|
|
319,418 |
|
|
|
122,531 |
|
Cash
and cash equivalents at end of period
|
|
$ |
365,220 |
|
|
$ |
239,245 |
|
|
$ |
319,418 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Supplemental
Cash Flow Information
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
paid during the period for income taxes
|
|
$ |
34,052 |
|
|
$ |
157 |
|
|
$ |
9,205 |
|
See Notes
to Consolidated Financial Statements.
|
|
CONSOLIDATED
STATEMENT OF SHAREHOLDERS' EQUITY
|
|
(In
Thousands, Except Per Share Amounts)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unamortized
|
|
|
|
|
|
Accumulated
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Executive
|
|
|
|
|
|
Other
|
|
|
|
|
|
Total
|
|
|
|
Common
Stock
|
|
|
Additional
|
|
|
Stock
Plan
|
|
|
Retained
|
|
|
Comprehensive
|
|
|
Treasury
|
|
|
Shareholders'
|
|
|
|
Shares
|
|
|
Amount
|
|
|
Capital
|
|
|
Expense
|
|
|
Earnings
|
|
|
Loss
|
|
|
Stock
|
|
|
Equity
|
|
|
|
|
76,431 |
|
|
$ |
47,769 |
|
|
$ |
39,925 |
|
|
$ |
(6,162 |
) |
|
$ |
695,492 |
|
|
$ |
(151 |
) |
|
$ |
- |
|
|
$ |
776,873 |
|
Net
loss
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(101,638 |
) |
|
|
|
|
|
|
|
|
|
|
(101,638 |
) |
Other
comprehensive loss, net of
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
deferred
tax of $171:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Minimum
pension liability
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
adjustment
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(318 |
) |
|
|
|
|
|
|
(318 |
) |
Comprehensive
loss
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(101,956 |
) |
Dividends
declared ($0.16 per share)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(12,233 |
) |
|
|
|
|
|
|
|
|
|
|
(12,233 |
) |
Exercise
of stock options
|
|
|
498 |
|
|
|
312 |
|
|
|
6,919 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
7,231 |
|
Stock
option tax benefit
|
|
|
|
|
|
|
|
|
|
|
2,563 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,563 |
|
Amortization
of stock plan expense
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,153 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,153 |
|
Issuance
of restricted stock, net
|
|
|
90 |
|
|
|
56 |
|
|
|
4,065 |
|
|
|
(4,121 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
- |
|
Issuance
of stock for debt conversion
|
|
|
4,921 |
|
|
|
3,076 |
|
|
|
162,277 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
165,353 |
|
|
|
|
81,940 |
|
|
$ |
51,213 |
|
|
$ |
215,749 |
|
|
$ |
(7,130 |
) |
|
$ |
581,621 |
|
|
$ |
(469 |
) |
|
$ |
- |
|
|
$ |
840,984 |
|
Net
income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
40,977 |
|
|
|
|
|
|
|
|
|
|
|
40,977 |
|
Other
comprehensive income, net of
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
deferred
tax of $(21):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Minimum
pension liability
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
adjustment
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
109 |
|
|
|
|
|
|
|
109 |
|
Comprehensive
income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
41,086 |
|
Adoption
of accounting standards:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Share-based
payments
|
|
|
|
|
|
|
|
|
|
|
(7,130 |
) |
|
|
7,130 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
- |
|
Post-production
stripping costs,
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
net
of deferred tax of $59,970
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(93,798 |
) |
|
|
|
|
|
|
|
|
|
|
(93,798 |
) |
Pension
and postretirement plans,
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
- |
|
net
of deferred tax of $25,801
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(40,356 |
) |
|
|
|
|
|
|
(40,356 |
) |
Dividends
declared ($0.16 per share)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(12,906 |
) |
|
|
|
|
|
|
|
|
|
|
(12,906 |
) |
Stock
option expense
|
|
|
|
|
|
|
|
|
|
|
6,112 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
6,112 |
|
Exercise
of stock options
|
|
|
185 |
|
|
|
115 |
|
|
|
2,027 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,142 |
|
Stock
option tax benefit
|
|
|
|
|
|
|
|
|
|
|
1,051 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,051 |
|
Restricted
stock
|
|
|
239 |
|
|
|
129 |
|
|
|
2,822 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,951 |
|
Share
repurchase
|
|
|
(1,299 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(49,995 |
) |
|
|
(49,995 |
) |
Issuance
of stock for debt conversion
|
|
|
1 |
|
|
|
1 |
|
|
|
19 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
20 |
|
|
|
|
81,066 |
|
|
$ |
51,458 |
|
|
$ |
220,650 |
|
|
$ |
- |
|
|
$ |
515,894 |
|
|
$ |
(40,716 |
) |
|
$ |
(49,995 |
) |
|
$ |
697,291 |
|
Net
income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
94,098 |
|
|
|
|
|
|
|
|
|
|
|
94,098 |
|
Other
comprehensive income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pension
and postretirement plans,
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
net
of deferred tax of $8,754
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
13,692 |
|
|
|
|
|
|
|
13,692 |
|
Comprehensive
income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
107,790 |
|
Adoption
of accounting standards:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Uncertainty
in income taxes
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
5,182 |
|
|
|
|
|
|
|
|
|
|
|
5,182 |
|
Dividends
declared ($0.17 per share)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(13,587 |
) |
|
|
|
|
|
|
|
|
|
|
(13,587 |
) |
Stock
option expense
|
|
|
|
|
|
|
|
|
|
|
8,308 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
8,308 |
|
Exercise
of stock options
|
|
|
299 |
|
|
|
188 |
|
|
|
3,813 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4,001 |
|
Stock
option tax benefit
|
|
|
|
|
|
|
|
|
|
|
410 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
410 |
|
Restricted
stock
|
|
|
155 |
|
|
|
97 |
|
|
|
4,503 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4,600 |
|
Share
repurchase
|
|
|
(1,576 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(29,991 |
) |
|
|
(29,991 |
) |
|
|
|
79,944 |
|
|
$ |
51,743 |
|
|
$ |
237,684 |
|
|
$ |
- |
|
|
$ |
601,587 |
|
|
$ |
(27,024 |
) |
|
$ |
(79,986 |
) |
|
$ |
784,004 |
|
See Notes
to Consolidated Financial Statements.
1.
Significant Accounting Policies
Basis
of Presentation
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 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 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 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.
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 and
stock options.
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, earnings from the sale and operation of a synfuel plant,
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. See Note 14 for a
discussion of the synfuel plant.
Cash
and Cash Equivalents
Cash and
cash equivalents are stated at cost, which approximates fair value. Cash
equivalents are primarily invested in two money market funds, which consist of
highly liquid investments with maturities of 90 days or less at the date of
purchase.
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.
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
2007 and 2006 are recorded as Cost of produced coal revenue while 2005 stripping
costs were shown in Inventories as Advance stripping costs.
Advance
stripping costs
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 – advance stripping costs related to post-production are
expensed as incurred. 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
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.
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, 2007,
approximately $65.8 million of costs associated with mining properties owned in
fee and leased mineral rights is 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, 2007 and 2006, advance mining royalties
included in Other noncurrent assets totaled $37.0 million and $35.1 million, net
of an allowance of $16.2 million and $17.8 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. We
account for our defined benefit pension plans in accordance with 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”). SFAS 158 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. Prior to the adoption of
SFAS 158, we accounted for our defined benefit pension plans in accordance with
SFAS No. 87, “Employers’ Accounting for Pension,” which required the cost to
provide benefits be accrued over the employees’ estimated remaining service
life. See Note 5 for a more complete discussion of our pension
plans.
Workers’
Compensation and Black Lung Benefits
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.
We are
also 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. Provisions for estimated benefits are
determined on an actuarial basis. 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. See
Note 11 for a more complete discussion of workers’ compensation and black lung
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 SFAS 158, which 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. Prior to the adoption of SFAS 158, we accounted for postretirement
benefits other than pensions in accordance with SFAS No. 106, “Employers’
Accounting for Postretirement Benefits Other Than Pensions,” which required the
cost to provide benefits be accrued over the employees’ remaining
service.
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 Financial Accounting Standards Board (“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 (loss) 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
(loss) per share is based on the number of common shares used to calculate basic
earnings (loss) 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 0.8 million, 2.0 million and 13.0 million
for the years ended December 31, 2007, 2006 and 2005, respectively, was excluded
from the calculation of the diluted earnings (loss) per common share as such
inclusion would result in antidilution.
The
computation for basic and diluted earnings (loss) per share is based on the
following per share information:
|
|
Year
Ended
|
|
|
|
December
31,
|
|
|
December
31,
|
|
|
|
|
|
|
|
|
|
2006
|
|
|
2005
|
|
|
|
(In
Thousands, Except Per Share Amounts)
|
|
Numerator:
|
|
|
|
|
|
|
|
|
|
Income
(Loss) before cumulative effect of accounting change - numerator for
basic
|
|
$ |
94,098 |
|
|
$ |
41,616 |
|
|
$ |
(101,638 |
) |
Cumulative
effect of accounting change, net of tax
|
|
|
- |
|
|
|
(639 |
) |
|
|
- |
|
Effect
of convertible notes
|
|
|
200 |
|
|
|
- |
|
|
|
- |
|
Net
income (loss) - numerator for diluted
|
|
$ |
94,298 |
|
|
$ |
40,977 |
|
|
$ |
(101,638 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Denominator:
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted
average shares - denominator for basic
|
|
|
80,123 |
|
|
|
80,847 |
|
|
|
76,390 |
|
Effect
of stock options/restricted stock
|
|
|
207 |
|
|
|
539 |
|
|
|
- |
|
Effect
of convertible notes
|
|
|
324 |
|
|
|
- |
|
|
|
- |
|
Adjusted
weighted average shares - denominator for diluted
|
|
|
80,654 |
|
|
|
81,386 |
|
|
|
76,390 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
(Loss) per share:
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic:
|
|
|
|
|
|
|
|
|
|
|
|
|
Before
cumulative effect of accounting change
|
|
$ |
1.17 |
|
|
$ |
0.51 |
|
|
$ |
(1.33 |
) |
Cumulative
effect of accounting change
|
|
|
- |
|
|
|
(0.01 |
) |
|
|
- |
|
Net
income (loss)
|
|
$ |
1.17 |
|
|
$ |
0.50 |
|
|
$ |
(1.33 |
) |
Diluted:
|
|
|
|
|
|
|
|
|
|
|
|
|
Before
cumulative effect of accounting change
|
|
$ |
1.17 |
|
|
$ |
0.51 |
|
|
$ |
(1.33 |
) |
Cumulative
effect of accounting change
|
|
|
- |
|
|
|
(0.01 |
) |
|
|
- |
|
Net
income (loss)
|
|
$ |
1.17 |
|
|
$ |
0.50 |
|
|
$ |
(1.33 |
) |
Accounting
Pronouncements
Fair
Value Measurements
In
September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements” (“SFAS
157”). SFAS 157 defines fair value, establishes a framework for measuring fair
value in accounting principles generally accepted in the United States, and
expands disclosures about fair value measurement. It does not require any new
fair value measurements. SFAS 157
is effective for fiscal years beginning after November 15, 2007 and interim
periods within those fiscal years for financial assets and liabilities, and for
fiscal years beginning after November 15, 2008 for nonfinancial assets and
liabilities. We are currently assessing the potential impact of the
statement on our financial position and results of operations.
2.
Inventories
Inventories
consisted of the following:
|
|
December
31,
|
|
|
|
|
|
|
|
|
|
2006
|
|
|
|
(In
Thousands)
|
|
Saleable
coal
|
|
$ |
120,343 |
|
|
$ |
124,816 |
|
Raw
coal
|
|
|
11,471 |
|
|
|
13,210 |
|
Subtotal
coal inventory
|
|
|
131,814 |
|
|
|
138,026 |
|
Supplies
inventory
|
|
|
51,546 |
|
|
|
53,030 |
|
Total
inventory
|
|
$ |
183,360 |
|
|
$ |
191,056 |
|
Saleable coal
represents coal ready for sale, including inventories designated for customer
facilities under consignment arrangements of $62.1 million and $61.0 million at
December 31, 2007 and 2006, 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:
|
|
December
31,
|
|
|
|
|
|
|
|
|
|
2006
|
|
|
|
(In
Thousands)
|
|
Longwall
panel costs
|
|
$ |
18,029 |
|
|
$ |
38,843 |
|
Deposits
|
|
|
118,944 |
|
|
|
106,833 |
|
Other
|
|
|
28,967 |
|
|
|
26,646 |
|
Total
other current assets
|
|
$ |
165,940 |
|
|
$ |
172,322 |
|
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, 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. In addition, there were $13.0 million of United
States Treasury securities supporting various regulatory obligations. Deposits
at December 31, 2006 included $105.1 million of funds pledged as collateral to
support $100.1 million of outstanding letters of credit (see Note 6 for further
discussion).
4.
Property, Plant and Equipment
Property,
plant and equipment is comprised of the following:
|
|
December
31,
|
|
|
|
|
|
|
|
|
|
2006
|
|
|
|
(In
Thousands)
|
|
Land,
buildings and equipment
|
|
$ |
2,082,003 |
|
|
$ |
2,005,029 |
|
Mining
properties owned in fee and leased mineral rights
|
|
|
704,547 |
|
|
|
690,687 |
|
Mine
development
|
|
|
863,303 |
|
|
|
781,834 |
|
Total
property, plant and equipment
|
|
|
3,649,853 |
|
|
|
3,477,550 |
|
Less
accumulated depreciation, depletion and amortization
|
|
|
(1,855,933 |
) |
|
|
(1,700,769 |
) |
Net
property, plant and equipment
|
|
$ |
1,793,920 |
|
|
$ |
1,776,781 |
|
Land,
buildings and equipment includes gross assets under capital leases of $17.3
million and $32.3 million at December 31, 2007 and 2006,
respectively.
During
the second quarter of 2007, we exchanged coal reserves with a third party,
recognizing a gain in Other revenue of $10.3 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 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
the third quarter of 2006, we sold our Falcon reserves, located in Boone County,
West Virginia, to a privately held coal company for total consideration of $30.8
million in cash. The sale consisted of approximately 5.5 million tons of coal
reserves. The total gain recognized in accordance with SFAS 153 on the sale was
$30.0 million (pre-tax), which is included within Other revenue for
2006.
During
2007 and 2006, we sold and leased-back certain mining equipment in several
transactions for net proceeds of $13.1 million and $21.8 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 and $18.1 million to the qualified plan during 2007 and 2006,
respectively.
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, 2007 or 2006. 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.
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, 2007.
The fair
value of the major categories of qualified defined benefit pension plan assets
includes the following:
|
|
December
31,
|
|
|
|
|
|
|
|
|
|
2006
|
|
|
|
(Dollars
In Thousands)
|
|
Equity
securities (domestic and international)
|
|
$ |
187,439 |
|
|
|
64.2 |
% |
|
$ |
186,695 |
|
|
|
65.4 |
% |
Debt
securities
|
|
|
72,417 |
|
|
|
24.8 |
% |
|
|
77,902 |
|
|
|
27.3 |
% |
Other
(includes cash, cash equivalents and a group annuity
contract)
|
|
|
31,891 |
|
|
|
11.0 |
% |
|
|
20,822 |
|
|
|
7.3 |
% |
Total
fair value of plan assets
|
|
$ |
291,747 |
|
|
|
100.0 |
% |
|
$ |
285,419 |
|
|
|
100.0 |
% |
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:
|
|
Year
Ended
|
|
|
|
December
31,
|
|
|
|
|
|
|
|
|
|
2006
|
|
|
|
(In
Thousands)
|
|
Change
in benefit obligation:
|
|
|
|
|
|
|
Benefit
obligation at the beginning of the period
|
|
$ |
256,925 |
|
|
$ |
242,400 |
|
Service
cost
|
|
|
9,716 |
|
|
|
9,230 |
|
Interest
cost
|
|
|
15,023 |
|
|
|
13,922 |
|
Actuarial
(gain) loss
|
|
|
(18,796 |
) |
|
|
957 |
|
Benefits
paid
|
|
|
(10,631 |
) |
|
|
(9,584 |
) |
Benefit
obligation at the end of the period
|
|
|
252,237 |
|
|
|
256,925 |
|
|
|
|
|
|
|
|
|
|
Change
in plan assets:
|
|
|
|
|
|
|
|
|
Fair
value at the beginning of the period
|
|
|
285,419 |
|
|
|
246,992 |
|
Actual
return on assets
|
|
|
16,512 |
|
|
|
29,873 |
|
Company
contributions
|
|
|
447 |
|
|
|
18,138 |
|
Benefits
paid
|
|
|
(10,631 |
) |
|
|
(9,584 |
) |
Fair
value of plan assets at end of period
|
|
|
291,747 |
|
|
|
285,419 |
|
|
|
|
|
|
|
|
|
|
Funded
status
|
|
$ |
39,510 |
|
|
$ |
28,494 |
|
|
|
|
|
|
|
|
|
|
Qualified
defined benefit pension plan, included in Pension assets
|
|
|
47,323 |
|
|
|
34,974 |
|
Nonqualified
supplemental benefit pension plan, included in Other noncurrent
liabilities
|
|
|
(7,813 |
) |
|
|
(6,480 |
) |
Accrued
pension assets recognized (net)
|
|
$ |
39,510 |
|
|
$ |
28,494 |
|
As
discussed in Note 1, we adopted SFAS 158 on December 31, 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.
The
nonqualified supplemental benefit pension plan had an accumulated benefit
obligation of $7.2 million and $6.3 million as of December 31, 2007 and 2006,
respectively.
The table
below details the changes to Accumulated other comprehensive loss related to
defined benefit pension plans in accordance with SFAS 158:
|
|
2007
|
|
|
2006
|
|
|
|
|
|
|
|
Net
loss
|
|
|
Prior
service cost
|
|
|
Net
loss
|
|
|
Prior
service cost
|
|
January
1 beginning balance
|
|
|
32,821 |
|
|
|
84 |
|
|
|
- |
|
|
|
- |
|
Changes
to Accumulated other comprehensive loss
|
|
|
(10,339 |
) |
|
|
(24 |
) |
|
|
32,821 |
|
|
|
84 |
|
December
31 ending balance
|
|
$ |
22,482 |
|
|
$ |
60 |
|
|
$ |
32,821 |
|
|
$ |
84 |
|
We expect
to recognize $41,545 of prior service cost and $1.0 million of net loss in
2008.
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:
|
|
December
31,
|
|
|
|
|
|
|
|
|
|
2006
|
|
Discount
rates
|
|
|
6.50 |
% |
|
|
5.90 |
% |
Rates
of increase in compensation levels
|
|
|
4.00 |
% |
|
|
4.00 |
% |
Net
periodic pension expense for both the qualified defined benefit pension plan and
nonqualified supplemental benefit pension plan includes the following
components:
|
|
Year
Ended
|
|
|
|
December
31,
|
|
|
December
31,
|
|
|
|
|
|
|
|
|
|
2006
|
|
|
2005
|
|
|
|
(In
Thousands)
|
|
Service
cost
|
|
$ |
9,716 |
|
|
$ |
9,230 |
|
|
$ |
9,324 |
|
Interest
cost
|
|
|
15,023 |
|
|
|
13,922 |
|
|
|
12,864 |
|
Expected
return on plan assets
|
|
|
(22,427 |
) |
|
|
(19,952 |
) |
|
|
(17,737 |
) |
Recognized
loss
|
|
|
4,068 |
|
|
|
6,226 |
|
|
|
3,607 |
|
Amortization
of prior service cost
|
|
|
39 |
|
|
|
39 |
|
|
|
40 |
|
Net
periodic pension expense
|
|
$ |
6,419 |
|
|
$ |
9,465 |
|
|
$ |
8,098 |
|
The
assumptions used in determining pension expense for both the qualified defined
benefit pension plan and nonqualified supplemental benefit pension plan are as
follows:
|
|
December
31,
|
|
|
December
31,
|
|
|
|
|
|
|
|
|
|
2006
|
|
|
2005
|
|
Discount
rates
|
|
|
5.90 |
% |
|
|
5.75 |
% |
|
|
5.75 |
% |
Rates
of increase in compensation levels
|
|
|
4.00 |
% |
|
|
4.00 |
% |
|
|
4.00 |
% |
Expected
long-term rate of return on plan assets
|
|
|
8.00 |
% |
|
|
8.00 |
% |
|
|
8.00 |
% |
We do not
expect that any contributions will be required in 2008 for the qualified defined
benefit pension plan. We expect to voluntarily contribute approximately $200,000
for benefit payments to participants in 2008 for the nonqualified supplemental
benefit pension plan.
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:
|
|
Expected
Pension
|
|
|
|
Benefit
Payments
|
|
|
|
(In
Thousands)
|
|
2008
|
|
$ |
11,635 |
|
2009
|
|
|
12,424 |
|
2010
|
|
|
13,049 |
|
2011
|
|
|
13,764 |
|
2012
|
|
|
14,665 |
|
Years
2013 to 2017
|
|
|
87,977 |
|
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 $400,000 in the year ended
December 31, 2007 and less than $100,000 in each of the years ended December 31,
2006 and 2005.
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 year ended
December 31, 2007 and $100,000 for each of the years ended December 31, 2006 and
2005.
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 $3.6 million, $3.9 million and $3.7 million for the
years ended December 31, 2007, 2006 and 2005, respectively.
6.
Debt
Our debt
is comprised of the following:
|
|
December
31,
|
|
|
|
|
|
|
|
|
|
2006
|
|
|
|
(In
Thousands)
|
|
6.875%
senior notes due 2013, net of discount
|
|
$ |
755,401 |
|
|
$ |
754,804 |
|
6.625%
senior notes due 2010
|
|
|
335,000 |
|
|
|
335,000 |
|
2.25%
convertible senior notes due 2024
|
|
|
9,647 |
|
|
|
9,647 |
|
4.75%
convertible senior notes due 2023
|
|
|
730 |
|
|
|
730 |
|
Capital
lease obligations
|
|
|
8,823 |
|
|
|
11,232 |
|
Fair
value hedge adjustment
|
|
|
(5,054 |
) |
|
|
(6,506 |
) |
Total
debt
|
|
|
1,104,547 |
|
|
|
1,104,907 |
|
Amounts
due within one year
|
|
|
(1,875 |
) |
|
|
(2,583 |
) |
Total
long-term debt
|
|
$ |
1,102,672 |
|
|
$ |
1,102,324 |
|
The
weighted average effective interest rate of the outstanding borrowings was 7.0%
at December 31, 2007 and 2006. At December 31, 2007, our available liquidity was
$479.3 million, including $365.2 million of cash and cash equivalents and $114.1
million availability on our asset-based revolving credit facility.
Refinancing
Transactions
On
November 22, 2005, we commenced a cash tender offer for any and all of the
outstanding $220.1 million of 6.95% senior notes due 2007 (the “6.95% Notes”), a
cash tender offer for any and all of the outstanding $132.0 million of 4.75%
Notes and an exchange offer for any and all of our outstanding $175.0 million of
2.25% Notes.
On
December 9, 2005, we commenced a private offering of the 6.875% Notes and
announced our intention to use the proceeds of the offering to purchase the
6.95% Notes in connection with the 6.95% Notes tender offer, the redemption of
any of the 6.95% Notes that were not tendered in the 6.95% Notes tender offer,
the purchase of the 4.75% Notes in connection with the 4.75% Notes tender offer,
the cash payment related to the exchange offer for the 2.25% Notes and for
general corporate purposes.
On
December 21, 2005, we settled with holders of $189.5 million of the $220.1
million outstanding of the 6.95% Notes, representing approximately 86.0% of the
outstanding 6.95% Notes, who tendered their 6.95% Notes. On December 27, 2005,
we redeemed the remaining $30.6 million of the 6.95% Notes.
On
December 28, 2005, we accepted tender of 4.75% Notes from holders of $131.3
million, or 99.4%, of the outstanding 4.75% Notes.
On
December 28, 2005, under the terms of the 2.25% Notes exchange offer, we
exchanged shares of Common Stock and a cash payment for $165.4 million, or
94.5%, of the outstanding 2.25% Notes tendered by the holders.
We
recognized charges totaling $219.0 million (pre-tax), including $6.6 million
(pre-tax) for the write-off of unamortized financing fees, for the debt
repurchase and exchange offer as of December 31, 2005.
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. 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. At any time on or before December 15,
2008, we may redeem up to 35% of the principal amount of the 6.875% Notes with
the proceeds of qualified equity offerings at a redemption price of 106.875% of
the principal amount, plus accrued and unpaid interest. The 6.875% Notes are
guaranteed by A.T. Massey and substantially all of our current and future
operating subsidiaries (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 6.875% 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.
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).
The
6.625% 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.
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. 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.
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, 2007, 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, 2007, the price of Common Stock had reached the specified threshold
for conversion. Consequently, the 4.75% Notes are convertible until March 31,
2008, the last day of our first quarter. The 4.75% Notes may be convertible
beyond this date if the specified threshold for conversion is met in subsequent
quarters. As of December 31, 2007, if all of the notes outstanding were eligible
and were converted, we would have needed to issue 37,649 shares of Common
Stock.
Fair
Value Hedge Adjustment
On
November 10, 2003, we entered into a fixed interest rate to floating interest
rate swap agreement (the “Swap Agreement”) covering a notional amount of debt of
$240 million. We designated this swap as a fair value hedge of a portion of our
6.625% Notes. We used the Swap Agreement to reduce interest expense and modify
exposure to interest rate risk by converting our fixed rate debt to a floating
rate liability. The Swap Agreement was originally scheduled to terminate on
November 15, 2010, however, on December 9, 2005, we notified the swap
counterparty that we were exercising our right to terminate the Swap Agreement
because of anticipated increases in the variable interest rate component of the
swap. 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 as Fair value hedge adjustment, will be amortized into Interest expense
through November 15, 2010.
Asset-Based
Lending Arrangement
On August
15, 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, 2007, this facility supported $60.9 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, 2007, 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, 2007, total remaining availability was $114.1
million based on qualifying inventory and accounts receivable. The credit
facility expires in August 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. We
are currently in compliance with all covenants.
Debt
Maturity
The
aggregate amounts of scheduled long-term debt maturities, including capital
lease obligations, subsequent to December 31, 2007 are as follows:
|
|
(In
Thousands)
|
|
2008
|
|
$ |
1,875 |
|
2009
|
|
|
1,967 |
|
2010
|
|
|
337,218 |
|
2011
|
|
|
2,670 |
|
2012
|
|
|
13 |
|
Beyond
2012*
|
|
|
770,457 |
|
__________________________
*
|
The
4.75% Notes and the 2.25% Notes in the amounts of $0.7 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, 2007, 2006 and 2005, was $75.7
million, $75.0 million and $56.1 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, 2007, we had $106.0 million of letters of credit outstanding of
which $45.1 million was collateralized by $46.0 million of cash deposited in
restricted, interest bearing accounts pledged to issuing banks and $60.9 million
was issued under our asset based lending arrangement. No claims were outstanding
against those letters of credit as of December 31, 2007.
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, 2007, we had $364.1 million
of outstanding surety bonds. These bonds were in place to secure obligations as
follows: post-mining reclamation bonds of $304.7 million, an appeal bond of
$50.0 million, and other miscellaneous obligation bonds of $9.4 million. Outstanding
surety bonds of $46.1 million are secured with letters of credit. In
addition, in October 2007, we deposited $50.0 million into an interest bearing
account which is pledged to an insurance company that issued the $50.0 million
appeal bond in the Wheeling-Pitt legal matter (see Note 17 to Notes to
Consolidated Financial Statements for additional details). The $50
million is reported in Deposits within Other current assets.
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:
|
|
|
Year
Ended
|
|
|
|
|
December
31,
|
|
|
December
31,
|
|
|
|
|
|
|
|
|
|
|
2006
|
|
|
2005
|
|
|
|
|
(In
Thousands)
|
|
Current:
|
|
|
|
|
|
|
|
|
|
|
Federal
|
|
|
$ |
7,876 |
|
|
$ |
20,694 |
|
|
$ |
2,852 |
|
State
and local
|
|
|
|
126 |
|
|
|
95 |
|
|
|
117 |
|
|
|
|
|
8,002 |
|
|
|
20,789 |
|
|
|
2,969 |
|
Deferred:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Federal
|
|
|
|
24,593 |
|
|
|
(15,439 |
) |
|
|
21,773 |
|
State
and local
|
|
|
|
2,810 |
|
|
|
(1,942 |
) |
|
|
1,486 |
|
Total
deferred
|
|
|
27,403 |
|
|
|
(17,381 |
) |
|
|
23,259 |
|
Income
tax expense
|
|
|
$ |
35,405 |
|
|
$ |
3,408 |
|
|
$ |
26,228 |
|
A
reconciliation of Income tax expense calculated at the federal statutory rate of
35% to our Income tax expense on Net income is as follows:
|
|
Year
Ended
|
|
|
|
December
31,
|
|
|
December
31,
|
|
|
|
|
|
|
|
|
|
2006
|
|
|
2005
|
|
|
|
(In
Thousands)
|
|
U.S.
statutory federal tax expense (benefit)
|
|
$ |
45,326 |
|
|
$ |
15,758 |
|
|
$ |
(26,394 |
) |
Increase
(Decrease) resulting from:
|
|
|
|
|
|
|
|
|
|
|
|
|
State
taxes
|
|
|
(116 |
) |
|
|
(2,393 |
) |
|
|
1,322 |
|
Non-deductible
penalties
|
|
|
8,062 |
|
|
|
852 |
|
|
|
546 |
|
Percentage
depletion
|
|
|
(33,501 |
) |
|
|
(25,897 |
) |
|
|
(29,932 |
) |
Non-deductible
compensation
|
|
|
711 |
|
|
|
1,279 |
|
|
|
9,653 |
|
Non-deductible
refinancing and exchange offer costs
|
|
|
(4,809 |
) |
|
|
- |
|
|
|
71,737 |
|
Extraterritorial
excluded income
|
|
|
- |
|
|
|
(797 |
) |
|
|
(1,160 |
) |
Valuation
allowance adjustment
|
|
|
31,343 |
|
|
|
16,066 |
|
|
|
5,309 |
|
Uncertain
tax positions
|
|
|
(2,325 |
) |
|
|
(1,197 |
) |
|
|
(4,284 |
) |
Refund
from settlement of 2001 IRS audit
|
|
|
(4,609 |
) |
|
|
- |
|
|
|
- |
|
Other,
net
|
|
|
(4,677 |
) |
|
|
(263 |
) |
|
|
(569 |
) |
Income
tax expense
|
|
$ |
35,405 |
|
|
$ |
3,408 |
|
|
$ |
26,228 |
|
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:
|
|
|
Year
Ended
|
|
|
|
|
December
31,
|
|
|
|
|
|
|
|
|
|
|
2006
|
|
|
|
|
(In
Thousands)
|
|
Deferred
tax assets:
|
|
|
|
|
|
|
|
Postretirement
benefit obligations
|
|
$ |
66,235 |
|
|
$ |
68,555 |
|
Workers'
compensation
|
|
|
22,588 |
|
|
|
21,456 |
|
Reclamation
and mine closure
|
|
|
47,281 |
|
|
|
51,440 |
|
Alternative
minimum tax credit carryforwards
|
|
|
119,651 |
|
|
|
135,103 |
|
Accounting
change on post-production stripping costs
|
|
|
- |
|
|
|
59,970 |
|
Litigation
|
|
|
|
10,247 |
|
|
|
18,103 |
|
Deferred
compensation
|
|
|
24,660 |
|
|
|
17,812 |
|
Federal
net operating loss
|
|
|
98,434 |
|
|
|
21,892 |
|
State
net operating loss
|
|
|
28,194 |
|
|
|
30,682 |
|
Other
|
|
|
|
27,483 |
|
|
|
9,708 |
|
|
Total
deferred tax assets
|
|
|
444,773 |
|
|
|
434,721 |
|
Valuation
allowance for deferred tax assets
|
|
|
(194,122 |
) |
|
|
(163,656 |
) |
|
Total
deferred tax assets, net of valuation allowance
|
|
|
250,651 |
|
|
|
271,065 |
|
Deferred
tax liabilities:
|
|
|
|
|
|
|
|
|
|
Plant,
equipment and mine development
|
|
|
(275,362 |
) |
|
|
(270,693 |
) |
Mining
property and mineral rights
|
|
|
(117,609 |
) |
|
|
(107,267 |
) |
Deferred
royalties
|
|
|
|
(10,339 |
) |
|
|
(9,642 |
) |
Other
|
|
|
|
(2,046 |
) |
|
|
(153 |
) |
Total
deferred tax liablities
|
|
|
(405,356 |
) |
|
|
(387,755 |
) |
Deferred
income taxes
|
|
|
$ |
(154,705 |
) |
|
$ |
(116,690 |
) |
Deferred tax
assets include alternative minimum tax (“AMT”) credits of $119.7
million and $135.1 million at December 31, 2007 and 2006, respectively, federal
net operating loss carryforwards of $281.2 million and $63.2 million as of
December 31, 2007 and 2006, respectively, and net state net operating loss
(“NOL”) carryforwards of $704.8 million and $767.0 million as of December 31,
2007 and 2006, respectively. The AMT credits have no expiration date. Federal
NOL carryforwards expire beginning in 2018 and ending in 2020. State NOL
carryforwards expire beginning in 2008 and ending in 2020. The NOL
carryforwards available at December 31, 2007 increased over the amount available
at the end of the prior
year
primarily due to (i) adjustments related to disallowed ten-year carryback claims
that will be made based on an IRS audit of the December 31, 2003 and 2004 tax
years and (ii) an expected IRS approval of a tax method accounting change
related to the tax deductibility of advanced stripping costs.
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, 2007 primarily as
a result of the increase in federal NOL carryforwards discussed
above.
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
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
related to unrecognized tax benefits in Other noncurrent liabilities and
recognize the related expense in Income tax expense. No payments for interest
and penalties are included in Income tax expense for 2007 and we accrued $3.1
million for the payment of interest during December 31,
2007.
|
|
(In
Thousands)
|
|
|
|
$ |
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
|
|
|
- |
|
|
|
$ |
- |
|
The above
table reflects unrecognized tax benefits identified in 2007 related to the
disallowed ten-year carryback claims discussed above and agreed to with the IRS
prior to yearend.
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. During
2005, we reduced our tax reserve by $4.3 million, reflecting the reduction in
exposure due to the closing of prior period audits by state taxing authorities
and the closing of a federal statutory period, partially offset by additional
exposures identified for the 2005 tax year.
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 2000. Additionally, the IRS has sent
notification to us of no change for our calendar year ended December 31, 2002
tax return. We are currently under audit from the IRS for the
calendar years ended December 31, 2003 and 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
2001. Management believes that we have adequately provided for any
income taxes and interest and penalties 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. We anticipate a payment during
2008 of the entire current interest accrued for uncertain tax positions, due to
the anticipated settlement of the 2003-2004 IRS audit.
8.
Other Noncurrent Liabilities
Other
noncurrent liabilities are comprised of the following:
|
|
|
December
31,
|
|
|
|
|
|
|
|
|
|
|
2006
|
|
|
|
|
(In
Thousands)
|
|
Reclamation
(Note 9)
|
|
$ |
142,213 |
|
|
$ |
142,687 |
|
Other
postretirement benefits (Note 10)
|
|
|
141,087 |
|
|
|
138,109 |
|
Workers'
compensation and black lung (Note 11)
|
|
|
90,702 |
|
|
|
89,227 |
|
Other
|
|
|
|
77,426 |
|
|
|
99,831 |
|
Total
other noncurrent liabilities
|
|
|
$ |
451,428 |
|
|
$ |
469,854 |
|
9.
Reclamation
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.
The
following table describes all changes to our reclamation liability:
|
|
Year
Ended
|
|
|
|
December
31,
|
|
|
|
|
|
|
|
|
|
2006
|
|
|
|
(In
Thousands)
|
|
Reclamation
liability at beginning of period
|
|
$ |
171,954 |
|
|
$ |
156,776 |
|
Accretion
expense
|
|
|
11,758 |
|
|
|
10,166 |
|
Liability
assumed/incurred
|
|
|
2,168 |
|
|
|
3,627 |
|
Liability
disposed
|
|
|
(142 |
) |
|
|
- |
|
Revisions
in estimated cash flows
|
|
|
(6,036 |
) |
|
|
5,590 |
|
Payments
|
|
|
(11,061 |
) |
|
|
(4,205 |
) |
Reclamation
liability at end of period
|
|
|
168,641 |
|
|
|
171,954 |
|
Less
amount included in Other current liabilities
|
|
|
26,428 |
|
|
|
29,267 |
|
Total
reclamation, included in Other noncurrent liabilities
|
|
$ |
142,213 |
|
|
$ |
142,687 |
|
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:
|
|
Year
Ended
|
|
|
|
December
31,
|
|
|
December
31,
|
|
|
|
|
|
|
|
|
|
2006
|
|
|
2005
|
|
|
|
(In
Thousands)
|
|
Service
cost
|
|
$ |
3,668 |
|
|
$ |
3,758 |
|
|
$ |
3,607 |
|
Interest
cost
|
|
|
8,467 |
|
|
|
7,959 |
|
|
|
6,926 |
|
Amortization
of net loss
|
|
|
1,864 |
|
|
|
2,307 |
|
|
|
1,704 |
|
Amortization
of prior service credit
|
|
|
(750 |
) |
|
|
(750 |
) |
|
|
(2,651 |
) |
Net
periodic postretirement benefit cost
|
|
$ |
13,249 |
|
|
$ |
13,274 |
|
|
$ |
9,586 |
|
The
discount rate assumed to determine the net periodic postretirement benefit cost
was 5.90% for the year ended December 31, 2007 and 5.75% for each of the years
ended December 31, 2006 and 2005, respectively.
The
following table sets forth the change in benefit obligation of our
postretirement benefit plans:
|
|
Year
Ended
|
|
|
|
December
31,
|
|
|
|
|
|
|
|
|
|
2006
|
|
|
|
(In
Thousands)
|
|
Change
in benefit obligation:
|
|
|
|
|
|
|
Benefit
obligation at the beginning of the period
|
|
$ |
144,325 |
|
|
$ |
135,999 |
|
Service
cost
|
|
|
3,668 |
|
|
|
3,758 |
|
Interest
cost
|
|
|
8,467 |
|
|
|
7,959 |
|
Actuarial
(gain)/loss
|
|
|
(3,546 |
) |
|
|
1,985 |
|
Benefits
paid
|
|
|
(5,181 |
) |
|
|
(5,376 |
) |
Benefit
obligation at the end of the period
|
|
$ |
147,733 |
|
|
$ |
144,325 |
|
|
|
|
|
|
|
|
|
|
Accrued
postretirement benefit obligation
|
|
$
|
147,733 |
|
|
$
|
144,325 |
|
Amount
included in Payroll and employee benefits
|
|
|
6,646 |
|
|
|
6,216 |
|
Postretirement
benefit obligation, included in Other noncurrent
liabilities
|
|
$ |
141,087 |
|
|
$ |
138,109 |
|
As
discussed in Note 1, we adopted SFAS 158 on December 31, 2006. According to the
adoption provisions, 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.
The table
below details the changes to Accumulated other comprehensive loss related to
defined benefit pension plans in accordance with SFAS 158:
|
|
Year
Ended
|
|
|
|
2007
|
|
|
2006
|
|
|
|
(In
Thousands)
|
|
|
|
Net
loss
|
|
|
Prior
service credit
|
|
|
Net
loss
|
|
|
Prior
service credit
|
|
January
1 beginning balance
|
|
$ |
23,434 |
|
|
$ |
(5,521 |
) |
|
$ |
- |
|
|
$ |
- |
|
Changes
to Accumulated other comprehensive loss
|
|
|
(3,302 |
) |
|
|
458 |
|
|
|
23,434 |
|
|
|
(5,521 |
) |
December
31 ending balance
|
|
$ |
20,132 |
|
|
$ |
(5,063 |
) |
|
$ |
23,434 |
|
|
$ |
(5,521 |
) |
We expect
to recognize $0.8 million of prior service credit and $1.3 million of net
actuarial loss in 2008.
The
discount rates used to determine the benefit obligations were 6.50% and 5.90%
for the years ended December 31, 2007 and 2006 respectively.
The
assumed health care cost trend rates used to determine the benefit obligation as
of the end of each year are as follows:
|
|
December
31,
|
|
|
|
|
|
|
|
|
|
2006
|
|
Health
care cost trend rate for next year
|
|
|
8.50 |
% |
|
|
8.20 |
% |
Ultimate
trend rate
|
|
|
5.00 |
% |
|
|
5.00 |
% |
Year
that the rate reaches ultimate trend rate
|
|
2013
|
|
|
2011
|
|
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 effects:
|
|
1-Percentage
Point Increase
|
|
|
1-Percentage
Point Decrease
|
|
|
|
(In
Thousands)
|
|
Effect
on total of service and interest costs components
|
|
$ |
1,997 |
|
|
$ |
(1,609 |
) |
Effect
on accumulated postretirement benefit obligation
|
|
$ |
21,497 |
|
|
$ |
(17,661 |
) |
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)
|
|
2008
|
|
$ |
6,889 |
|
2009
|
|
|
7,589 |
|
2010
|
|
|
8,231 |
|
2011
|
|
|
8,969 |
|
2012
|
|
|
9,504 |
|
Years
2013 to 2017
|
|
|
52,371 |
|
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, 2007, our
obligation under the Coal Act was estimated at approximately $19.8 million,
compared to our estimated obligation at December 31, 2006 of $24.1 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, 2007, 2006 and 2005 totaled
$1.3 million, $4.3 million and $4.8 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 includes 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 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. 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:
|
|
December
31,
|
|
|
|
|
|
|
|
|
|
2006
|
|
|
|
(In
Thousands)
|
|
Accrued
self-insured black lung obligation
|
|
$ |
53,412 |
|
|
$ |
53,284 |
|
Workers'
compensation (traumatic injury)
|
|
|
58,788 |
|
|
|
56,042 |
|
Total
accrued workers' compensation and black lung
|
|
|
112,200 |
|
|
|
109,326 |
|
Less
amount included in Other current liabilities
|
|
|
21,498 |
|
|
|
20,099 |
|
Workers'
compensation & black lung in Other noncurrent
liabilities
|
|
$ |
90,702 |
|
|
$ |
89,227 |
|
The
amount of workers' compensation (traumatic liability) related to self-insurance
was $56.7 million and $52.3 million at December 31, 2007 and 2006, respectively.
Weighted average actuarial assumptions used in the determination of the
self-insured portion of workers’ compensation (traumatic injury) liability at
December 31, 2007 and 2006 included a discount rate of 5.00% and the accumulated
black lung obligation included a discount rate of 6.50% and 5.90% at December
31, 2007 and 2006, respectively.
A
reconciliation of changes in the self-insured black lung obligation is as
follows:
|
|
Year
Ended
|
|
|
|
December
31,
|
|
|
|
|
|
|
|
|
|
2006
|
|
|
|
(In
Thousands)
|
|
Beginning
of year accrued self-insured black lung obligation
|
|
$ |
53,284 |
|
|
$ |
50,779 |
|
Service
cost
|
|
|
2,495 |
|
|
|
2,619 |
|
Interest
cost
|
|
|
3,117 |
|
|
|
2,861 |
|
Actuarial
gain
|
|
|
(3,989 |
) |
|
|
(1,601 |
) |
Benefit
payments
|
|
|
(1,495 |
) |
|
|
(1,374 |
) |
Accrued
self-insured black lung obligation
|
|
$ |
53,412 |
|
|
$ |
53,284 |
|
As
discussed in Note 1, we adopted SFAS 158 on December 31, 2006. According to the
adoption provisions, 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 at December 31,
2006 and $3.0 million in Other current liabilities). The $16.6 million decrease,
net of the deferred tax of $6.5 million, was recorded in Accumulated other
comprehensive loss.
The table
below details the changes to Accumulated other comprehensive loss related to
black lung benefits in accordance with SFAS 158:
|
|
2007
|
|
|
2006
|
|
|
|
(In
Thousands)
|
|
|
|
Net
gain
|
|
|
Net
gain
|
|
January
1 beginning balance
|
|
$ |
(10,102 |
) |
|
$ |
- |
|
Changes
to Accumulated other comprehensive loss
|
|
|
(485 |
) |
|
|
(10,102 |
) |
December
31 ending balance
|
|
|
(10,587 |
) |
|
|
(10,102 |
) |
We expect
to recognize $3.5 million of net actuarial gain in 2008.
Expenses
for black lung benefits and workers’ compensation related benefits include the
following components:
|
|
Year
Ended
|
|
|
|
December
31,
|
|
|
December
31,
|
|
|
|
|
|
|
|
|
|
2006
|
|
|
2005
|
|
|
|
(In
Thousands)
|
|
Self-insured
black lung benefits:
|
|
|
|
|
|
|
|
|
|
Service
cost
|
|
$ |
2,495 |
|
|
$ |
2,619 |
|
|
$ |
2,392 |
|
Interest
cost
|
|
|
3,117 |
|
|
|
2,861 |
|
|
|
2,694 |
|
Amortization
of actuarial gain
|
|
|
(3,194 |
) |
|
|
(3,759 |
) |
|
|
(4,691 |
) |
|
|
|
2,418 |
|
|
|
1,721 |
|
|
|
395 |
|
Other
workers' compensation benefits
|
|
|
30,842 |
|
|
|
36,381 |
|
|
|
40,609 |
|
|
|
$ |
33,260 |
|
|
$ |
38,102 |
|
|
$ |
41,004 |
|
Payments
for benefits, premiums and other costs related to black lung and workers’
compensation liabilities were $29.6 million, $33.2 million and $39.9 million for
the years ended December 31, 2007, 2006 and 2005, respectively.
The
actuarial assumptions used in the determination of self-insured black lung
benefits expense included discount rates of 5.90% for the year ended December
31, 2007 and 5.75% for the years ended December 31, 2006 and 2005,
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
|
|
$ |
165 |
|
|
$ |
(133 |
) |
Effect
on accumulated black lung obligation
|
|
$ |
1,344 |
|
|
$ |
(1,101 |
) |
|
|
|
|
|
|
|
|
|
Increase/decrease
in cost of living trend rate:
|
|
|
|
|
|
|
|
|
Effect
on total service and interest cost components
|
|
$ |
655 |
|
|
$ |
(530 |
) |
Effect
on accumulated black lung obligation
|
|
$ |
5,526 |
|
|
$ |
(4,556 |
) |
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)
|
|
2008
|
|
$ |
3,299 |
|
2009
|
|
|
3,442 |
|
2010
|
|
|
3,576 |
|
2011
|
|
|
3,706 |
|
2012
|
|
|
3,836 |
|
Years
2013 to 2017
|
|
|
20,871 |
|
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”),
|
|
·
|
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, 2007 was 2,400,244 shares, which was
computed as the 3,500,000 shares specifically authorized in the 2006 Plan, less
grants made in 2006 and 2007, 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 June 28, 2006. The 2006 Plan provides for grants of
stock options, SARs, restricted stock, restricted units, unrestricted stock and
incentive awards.
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, 2007, 2006 and 2005 was $19.2 million, $7.3 million and $23.1
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, 2007, 2006 and 2005 was approximately $7.5
million, $2.8 million and $9 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, 2007 and 2006,
there was $11.1 million and $15 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 and 2.4 years, respectively.
In the years ended December 31, 2007 and 2006, we also reflected $0.4 million
and $1.1 million, respectively,
of excess
tax benefits as a financing cash flow in the consolidated statement of cash
flows resulting from the exercise of stock options.
Prior to
the adoption of FAS 123R, we accounted for stock options in accordance with APB
No. 25, under which no compensation expense was recorded because the exercise
price of stock options equaled the market price of the underlying stock on the
date of grant. Had we adopted FAS 123R in prior periods, the impact of that
statement would have approximated the impact of FASB Statement No. 123,
“Accounting for Stock-based Compensation” (as if the fair-value-based
recognition provisions of that statement had been applied) as shown in the
following table:
|
|
Year
Ended
|
|
|
|
|
|
|
|
|
|
|
|
(In
Thousands, Except Per Share Amounts)
|
|
Net
loss, as reported
|
|
$ |
(101,638 |
) |
Deduct:
Total stock-based employee compensation expense
|
|
|
|
|
for
stock options determined under Black-Scholes option
|
|
|
|
|
pricing
model (net of tax)
|
|
|
(3,959 |
) |
Pro
forma net loss
|
|
$ |
(105,597 |
) |
Loss
per share:
|
|
|
|
|
Basic
- as reported
|
|
$ |
(1.33 |
) |
Basic
- pro forma
|
|
$ |
(1.38 |
) |
Diluted
- as reported
|
|
$ |
(1.33 |
) |
Diluted
- pro forma
|
|
$ |
(1.38 |
) |
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 a
three or four-year period, though some stock options fully vest upon the earlier
to occur of meeting certain performance criteria or four years from the date of
grant. 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 contractual 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 term 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, 2007. 2006 and 2005 was calculated using the following
estimated weighted average assumptions:
|
|
Years
Ended December 31,
|
|
Options
Granted
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
Number
of shares underlying options
|
|
|
556,979 |
|
|
|
642,434 |
|
|
|
842,222 |
|
Contractual
term in years
|
|
|
10 |
|
|
|
10 |
|
|
|
10 |
|
Assumptions
used to estimate fair value:
|
|
|
|
|
|
|
|
|
|
|
|
|
Expected
dividend yield
|
|
|
0.6%
- 0.7 |
% |
|
|
0.4%
- 0.7 |
% |
|
|
0.3%
- 0.4 |
% |
Expected
volatility
|
|
|
46%
- 50 |
% |
|
|
46%
- 55 |
% |
|
|
53%
- 55 |
% |
Risk-free
interest rate
|
|
|
3.00%
- 4.74 |
% |
|
|
4.82%
- 4.85 |
% |
|
|
3.82%
- 4.41 |
% |
Expected
term in years
|
|
|
1.2
- 4.25 |
|
|
|
1.2
- 5 |
|
|
|
1.3
- 5 |
|
Weighted-average
fair value estimates at grant date:
|
|
|
|
|
|
|
|
|
|
|
|
|
In
thousands
|
|
$ |
5,542 |
|
|
$ |
5,192 |
|
|
$ |
14,309 |
|
Fair
value per share
|
|
$ |
9.95 |
|
|
$ |
8.08 |
|
|
$ |
16.99 |
|
A summary
of option activity under the plans for the year ended December 31, 2007 is
presented below:
|
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
|
Weighted
|
|
average
|
|
|
|
Number
of
|
|
|
average
exercise
|
|
contractual
|
Aggregate
|
|
|
Options
|
|
|
price
|
|
term
(years)
|
Intrinsic
Value
|
|
|
(In
Thousands, Except Exercise Price and Contractual Term)
|
|
|
|
2,795 |
|
|
$ |
19.83 |
|
|
|
Granted
|
|
|
557 |
|
|
|
29.46 |
|
|
|
Exercised
|
|
|
(300 |
) |
|
|
13.33 |
|
|
|
Forfeited/expired
|
|
|
(378 |
) |
|
|
34.05 |
|
|
|
|
|
|
2,674 |
|
|
$ |
26.39 |
|
7.6
|
$ 26,656
|
|
|
|
1,217 |
|
|
$ |
21.25 |
|
6.5
|
$ 18,350
|
We
received $4.0 million, $2.1 million and $7.2 million in cash proceeds from the
exercise of stock options for the years ended December 31, 2007, 2006 and 2005,
respectively. The intrinsic value of stock options exercised was $4.5 million,
$3.5 million and $12.8 million for the years ended December 31, 2007, 2006 and
2005, 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, 2007, there was $10.3 million of unrecognized compensation
cost related to restricted stock expected to be recognized over the next four
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, 2007, and changes for the year
then ended is presented below:
|
|
|
|
|
Weighted
average
|
|
|
|
|
|
|
grant
date
|
|
(Shares
In Thousands)
|
|
Shares
|
|
|
fair
value
|
|
|
|
|
516 |
|
|
$ |
27.71 |
|
Granted
|
|
|
209 |
|
|
$ |
28.48 |
|
Vested
|
|
|
(148 |
) |
|
$ |
25.60 |
|
Forfeited
|
|
|
(62 |
) |
|
$ |
27.99 |
|
|
|
|
515 |
|
|
$ |
28.64 |
|
The fair
value of restricted stock vested during the years ended December 31, 2007, 2006
and 2005 was $3.8 million, $3.6 million and $7.6 million,
respectively.
Liability
instruments
We use
the fair value method to recognize compensation cost associated with SARs. At
each December 31, 2007, 2006 and 2005, 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 5.8
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.
|
|
|
|
|
|
|
|
|
2006
|
|
Awarded
|
|
|
310,900 |
|
|
|
411,372 |
|
Settled
|
|
|
81,461 |
|
|
|
80,261 |
|
Settlement
amount (in millions)
|
|
$ |
2.3 |
|
|
$ |
2.1 |
|
13.
Lease Obligations
We lease
two office buildings and 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 covenants that may require
an accelerated buyout of the lease if the covenants are violated. Rental expense
for the years ended December 31, 2007, 2006 and 2005 was $39.7 million, $46.4
million and $42.4 million, respectively.
During
2007, we sold and leased-back certain mining equipment. We received net proceeds
of $13.1 million, resulting in net gains of $1.2 million, which we
deferred. The gains are being recognized ratably over the term of the
leases, which range from 5 to 5.5 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.
During
2006, we sold and leased-back certain mining equipment. We received net proceeds
of $21.8 million with no resulting gain or loss on the transaction. 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.
During
2005, we sold and leased-back certain mining and other equipment in several
transactions. We received net proceeds of $71.7 million, resulting in net gains
of $4.1 million, which were deferred. The gains are being recognized ratably
over the term of the leases, which range from 3.5 to 8 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,
2007:
|
|
Capital
Leases
|
|
|
Operating
Leases
|
|
|
|
(In
Thousands)
|
|
2008
|
|
$ |
2,430 |
|
|
$ |
42,669 |
|
2009
|
|
|
2,256 |
|
|
|
39,920 |
|
2010
|
|
|
2,395 |
|
|
|
33,784 |
|
2011
|
|
|
2,655 |
|
|
|
23,020 |
|
2012
|
|
|
- |
|
|
|
16,060 |
|
Beyond
2012
|
|
|
- |
|
|
|
5,878 |
|
Total
minimum lease payments
|
|
|
9,736 |
|
|
$ |
161,331 |
|
Less
imputed interest
|
|
|
913 |
|
|
|
|
|
Present
value of minimum capital lease payments
|
|
$ |
8,823 |
|
|
|
|
|
14.
Appalachian Synfuel, LLC
Appalachian
Synfuel, LLC (“Appalachian Synfuel”) was formed in 1997. As a provider of
synthetic fuel, Appalachian Synfuel generates tax credits pursuant to Section
45K (formerly Section 29) of the IRC for its owners; however, because of our tax
position we are unable to utilize the tax credits generated by Appalachian
Synfuel. In order to monetize the value of our investment, we sought to sell an
interest in Appalachian Synfuel to an entity that could benefit currently from
the tax credits generated. In order to facilitate such a transaction, the
synfuel operating agreement was amended to divide the ownership interest in
three tranches, Series A, Series B and Series C.
Under the
amended Appalachian Synfuel agreement, the Series A owner generally is entitled
to the risks and rewards of the first 475,000 tons of production, including the
right to the related tax credits. The Series B owner is generally entitled to
the risks and rewards of all excess production up to the rated capacity of 1.2
million tons. The Series C owner is responsible for providing recourse working
capital loans to Appalachian Synfuel going forward at a specified indexed
interest rate. As a result, the Series C owner will fund the daily operations of
Appalachian Synfuel. The Series C owner also has the responsibility at the end
of the term of the Appalachian Synfuel agreement to wind up the affairs of
Appalachian Synfuel, disposing of all assets and settling
liabilities.
We sold
99% of the Series A and Series B interest in Appalachian Synfuel in 2001 and
2002 and received cash of $7.2 million, a recourse promissory note for $34.6
million that was paid in quarterly installments of $1.9 million including
interest, and a contingent promissory note that was paid on a cents per Section
45 credit dollar earned based on synfuel tonnage shipped. The agreement provides
that the payments under the contingent promissory note may be reduced or
eliminated if the price of oil remains above a certain threshold price set by
the IRS (the “threshold price”). Once the threshold price is reached, the
Section 45K credits will be phased out ratably over an approximate $16.00 per
barrel range above the
threshold
price. The threshold price for 2007 is expected to be set by the IRS in April
2008. For fiscal year 2007, the average price of West Texas Intermediate crude
oil was approximately $72.19 per barrel. At this price level a portion of the
Section 45K credits for 2007 will likely be phased out, which reduced the amount
of income we accrued in 2007 from payments to be received under the contingent
promissory note. To the extent that the estimated phase-out amount is different
than the actual phase-out
amount, we will recognize an adjustment in the first quarter of 2008. Our
subsidiary, Marfork Coal Company, Inc., managed the facility under an operating
agreement, which was terminated as of December 31, 2007.
15.
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:
|
|
|
|
|
|
|
|
|
2006
|
|
|
2005
|
|
Utility
coal
|
|
|
60 |
% |
|
|
62 |
% |
|
|
60 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
Metallurgical
coal
|
|
|
30 |
% |
|
|
28 |
% |
|
|
29 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
Industrial
coal
|
|
|
10 |
% |
|
|
10 |
% |
|
|
11 |
% |
Our
mining operations are conducted in southern West Virginia, eastern Kentucky and
western Virginia. Our coal is marketed primarily in the United
States.
For the
years ended December 31, 2007, 2006 and 2005, approximately 11%, 11% and 13%,
respectively, of Produced coal revenue was attributable to sales to affiliates
of American Electric Power Company, Inc. For the year ended December 31, 2005
approximately 12% of Produced coal revenue was attributable to sales to
affiliates of DTE Energy Corporation. At December 31, 2007, approximately 56%,
28% and 16% of Trade receivables represents amounts due from utility customers,
metallurgical customers and industrial customers, respectively, compared with
55%, 28% and 17%, respectively, as of December 31, 2006.
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, 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.
16.
Fair Value of Financial Instruments
We used
the following methods and assumptions to estimate our fair value disclosures for
financial statements as of December 31, 2007 and 2006:
Cash and cash equivalents:
The carrying value approximates the fair value due to the short maturity of
these instruments.
Long-term debt: At
December 31, 2007, the combined fair value estimate of our 6.875% Notes, 6.625%
Notes, 2.25% Notes and 4.75% Notes outstanding was $1,050.1 million based on
available market information. At December 31, 2006, the combined fair value
estimate of our 6.875% Notes, 6.625% Notes, 2.25% Notes and 4.75% Notes
outstanding was $1,063.8 million based on available market information at that
date.
17.
Contingencies
Wheeling-Pittsburgh
Steel
On April
27, 2005, Wheeling-Pittsburgh Steel Corporation (“WPS”) 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 WPS’s coke ovens. WPS 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. With respect to the
claims based upon alleged bad faith and misrepresentation, and the request for
the imposition of punitive damages, it is the position of CWVE and us
that no independent tort claim, separate and apart from the breach of contract
claims had been alleged against either CWVE or us and, as such, no damages,
whether compensatory or punitive, were recoverable. It is also the position of
CWVE and us that no acts of bad faith or misrepresentation
occurred.
On May
29, 2007, the trial commenced. On July 2, 2007, the jury awarded
damages in favor of WPS and MSC in the amount of $219.9 million, comprised of
$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 WPS 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, totals 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 West Virginia Supreme Court of Appeals. 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 Court
on October 25, 2007, which stays this matter pending disposition of our
appeal.
On
December 10, 2007, we and CWVE filed separate “Petitions for Appeal” with the
West Virginia Supreme Court of Appeals (the “Court”) seeking, among other
things, review of certain rulings made by the trial court and reversal of the
judgments against them. The points raised on appeal included, among other
things, (i) the propriety of allowing WPS 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 WPS proved the elements
of its misrepresentation and contract claims, and (iv) correctness of certain
evidentiary rulings.
We
believe, in consultation with legal counsel, that we have strong legal arguments
to raise on appeal to the West Virginia Supreme Court of Appeals that create
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 presents for
appeal, we believe it is probable that the West Virginia Supreme Court of
Appeals will agree to hear our appeal. Ultimately, we believe it is
unlikely any punitive damages will be assessed in this matter. We
further believe in consultation with legal counsel that due to matters of law in
the conduct of the recently completed trial, there is a strong possibility that
the West Virginia Supreme Court of Appeals will remand the compensatory damages
claim for retrial or significantly reduce the amount of the compensatory damages
awarded by the jury.
We
believe the range of possible loss in this matter is from $16 million to $244
million, prior to post-judgment interest or other costs. The minimum loss we
expect to incur upon final settlement or adjudication is the amount of excess
costs incurred by WPS to acquire coal required but not delivered under the CSA
(plus pre-judgment interest) adjusted for performance excused by events of force
majeure. Amounts in excess of this amount may ultimately be
awarded if the West Virginia Supreme Court of Appeals upholds the circuit
court’s decisions, in whole or in part, or if the West Virginia Supreme Court of
Appeals remands the case for retrial and a jury awards the plaintiffs an amount
in excess of what we have accrued. 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 on
appeal. Included in these reasonably possible outcomes are reversal
of the compensatory damage and punitive awards, remand and retrial, or reduction
of some or all of the awards. As there is no amount in the range that
is a better estimate than any other amount, the minimum amount in the range has
been accrued (included in Other current liabilities). It is
reasonably possible that our judgments regarding these matters could change in
the near term, resulting in the recording of additional material losses that
would affect our operating results and financial position.
Our
insurance carriers are in the early stages of their investigation and handling
of this matter. 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 the amount of any insurance recovery. Potential
recoveries from our insurance carriers for any losses that may eventually arise
from this matter have not been taken into consideration in determining our
accrual for this matter.
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 (“Harman
plaintiffs”) sued A.T. Massey and five of its subsidiaries (“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 April 5, 2007, the West
Virginia
Supreme Court of Appeals accepted the Massey Defendants’ Petition for Appeal.
Oral arguments were held on October 10, 2007. On November 21, 2007, the 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 Court to
conduct a rehearing in the case. On January 24, 2008, the Court decided to
rehear the case, which will be re-argued on March 12, 2008. We do not expect the
Court to change its November 21, 2007 ruling, but such a result, while remote,
is possible. If the Harman plaintiffs are unsuccessful, as expected the Harman
plaintiffs may then petition the United States Supreme Court to review the West
Virginia Supreme Court’s dismissal of their claims. We believe that
the United States Supreme Court will refuse to hear their appeal. The contingent
letter of credit of $55 million securing the appeal bond has been cancelled and
we reversed the accrual of $22 million previously recorded in Cost of produced
coal revenue. We also reversed the $11.6 million accrual for interest in
Interest expense.
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 4,300 plaintiffs seeking unquantified
compensatory and punitive damages from approximately 200 defendants. The West
Virginia Supreme Court of Appeals transferred all 49 cases (the “Referred
Cases”) to the Circuit Court of Raleigh County, West Virginia, to be handled by
a mass litigation panel of three judges. The panel judges will hold multiple
trials, each relating to all or part of a watershed. On January 18, 2007, a
panel judge dismissed all claims asserted by all plaintiffs within the Coal
River watershed, which directly involves approximately 400 plaintiffs and we
believe impacts another 800 plaintiffs. Plaintiffs filed a petition seeking
appeal of this decision with the West Virginia Supreme Court of Appeals, which
was heard and granted on October 24, 2007. The appeal will likely be heard and
decided in 2008. We believe we have insurance coverage applicable to these
matters.
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 355 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) have been
stayed pending appeal of the Coal River watershed decision noted above. In the
Mingo County case, a motion to stay pending appeal of the Coal River watershed
decision has been made.
On April
10, 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 West Virginia
Supreme Court of Appeals in response to the Complaint. Subsequently, we
settled with 16 of 17 of the Plaintiffs. With respect to the remaining
Plaintiff, the Court granted a motion to withdraw filed by her counsel and she
has yet to notify the Court as to whether she intends to prosecute her
claims. We are pursuing dismissal on the grounds initially asserted in the
pending motion to dismiss.
We
believe these matters will be resolved without a material 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 us and 15 of our subsidiaries. The
claims against us and three of our subsidiaries were dismissed. Plaintiffs
alleged that we and our subsidiaries named in the suit 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 unquantified compensatory and punitive damages. The West Virginia
Supreme Court of Appeals referred the consolidated lawsuits, and three similar
lawsuits against other coal and transportation companies not involving us or our
subsidiaries, to the Circuit Court of Lincoln County, West Virginia, to be
handled by a mass litigation panel of one 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 West Virginia Supreme Court of Appeals that the cases be sent
back to the circuit courts of origin for resolution. The Court has not ruled on
that motion. Defendants have 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. Prior to the hearing on those motions, 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 a hearing on December 14, 2007. The
Court has set a hearing on plaintiffs’ motion for class certification for March
21, 2008. No date has been set for a trial. We believe we
have insurance coverage applicable to these matters and that they will be
resolved without a material impact on our cash flows, results of operations or
financial condition.
Well
Water Contamination
Since
September 2004, approximately 710 plaintiffs 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 Court. Plaintiffs
seek injunctive relief and unquantified compensatory and 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 thirty (30) years. While we have not received
damage amounts for all plaintiffs at this time, we estimate that plaintiffs will
claim in excess of $50 million in special damages. Plaintiffs also request
unliquidated compensatory damages for pain and suffering, annoyance and
inconvenience. Trial is scheduled to commence on May 27, 2008. We
believe we have strong defenses to these claims. While we have disputes with
some of our insurers, we believe we have insurance coverage applicable to these
matters and that they will be resolved without a material impact on our cash
flows, results of operations or financial condition.
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 “trial 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 trial
Court rescinded four of our 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. On April 17, 2007, the trial Court
partially stayed its ruling, permitting mining to resume in certain fills that
were already under construction. On June 14, 2007, the trial 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
trial Court subsequently modified its ruling to allow these ponds to remain in
place, as the ponds and fills have already been constructed. The
trial 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 do not expect any material impact
to our financial statements through 2008 and will continue to monitor
developments in the matter.
Virginia Electric and Power
Company
On
December 30, 2005, Virginia Electric and Power Company (“VEPCO”) filed suit in
the Circuit Court of the City of Richmond, Virginia against A.T. Massey and
Massey Coal Sales Company, Inc. (“MCS”). On April 11, 2007, A.T. Massey and MCS
filed their Answer, Affirmative Defenses and Counterclaim. On October 8, 2007,
the parties entered into a confidential settlement agreement to settle the
lawsuit and counterclaim for complete releases and a dismissal with prejudice.
The dismissal order was entered by the Richmond circuit court on October 10,
2007. The financial impact of the settlement was included in the third quarter
in Cost of produced coal revenue. This matter was resolved without a material
impact on our cash flows, results of operations or financial
condition.
Clean
Water Act
On May
10, 2007, the United States, on behalf of the Administrator of the United States
Environmental Protection Agency (“EPA”), filed suit against us and twenty-seven
of our subsidiaries in the United States District Court for the Southern
District of West Virginia (“District Court”). The suit alleged that a
number of our subsidiaries violated the Federal Clean Water Act on thousands of
occasions by discharging pollutants in excess of monthly and daily permit limits
from 2000 to 2006. On January 17, 2008, a proposed settlement reached
with the EPA was filed with the District Court. The settlement, which
requires District Court approval, requires us to pay $20 million in penalties
and make improvements in our environmental processes. We expect the settlement
to be approved by the District Court in the first or second quarter of 2008. We
recorded the $20 million in Cost of produced coal revenue in 2007.
Aracoma
Mine Fire
In
January 2006, one of our subsidiaries, Aracoma Coal Company, experienced a mine
fire that resulted in the deaths of two miners. The estates of the two miners
have filed a lawsuit in the Circuit Court of Logan County against us and two of
our subsidiaries with respect to the incident. A trial in that suit is scheduled
for October 2008. We believe we have insurance coverage applicable to this
matter.
The
federal Mine Safety and Health Administration conducted an investigation into
the causes of the fatalities and subsequently issued citations seeking $1.5
million in fines relating to the fatalities. Aracoma Coal Company has appealed
those citations.
Additionally,
the United States Attorney’s Office in the Southern District of West Virginia is
conducting a federal grand jury investigation of the incident. Such an
investigation could result in criminal fines for Aracoma or other subsidiaries
of ours.
While we
believe we have sufficient legal reserves for these matters, it is possible that
the actual outcome of the matters could vary significantly from those amounts.
We will continue to review the amount of our accrual and any adjustment required
to increase or decrease the accrual based on development of the matters will be
made in the period determined. We believe these matters will be resolved without
a 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 impact
upon our consolidated cash flows, results of operations or financial condition.
It is reasonably possible, however, that the ultimate liabilities in the future
with respect to these lawsuits and claims, in the aggregate, may be material to
our cash flows, results of operations or financial condition.
18.
Quarterly Information (Unaudited)
The table below details our quarterly
financial information for the previous two fiscal years.
|
|
Three
Months Ended
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(In
Thousands, Except Per Share Amounts)
|
|
Total
revenue
|
|
$ |
607,320 |
|
|
$ |
617,802 |
|
|
$ |
603,441 |
|
|
$ |
584,960 |
|
Income
before interest and taxes
|
|
|
55,557 |
|
|
|
60,127 |
|
|
|
35,343 |
|
|
|
28,652 |
|
Income
before taxes
|
|
|
39,531 |
|
|
|
45,316 |
|
|
|
20,478 |
|
|
|
24,178 |
|
Net
income
|
|
|
32,607 |
|
|
|
34,938 |
|
|
|
21,408 |
|
|
|
5,145 |
|
Income
per share (basic and diluted):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
income
|
|
$ |
0.40 |
|
|
$ |
0.43 |
|
|
$ |
0.27 |
|
|
$ |
0.06 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three
Months Ended
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(In
Thousands, Except Per Share Amounts)
|
|
Total
revenue
|
|
$ |
559,469 |
|
|
$ |
556,116 |
|
|
$ |
555,897 |
|
|
$ |
548,372 |
|
Income
before interest and taxes
|
|
|
24,290 |
|
|
|
20,337 |
|
|
|
46,614 |
|
|
|
19,765 |
|
Income
before taxes
|
|
|
7,617 |
|
|
|
3,882 |
|
|
|
30,197 |
|
|
|
3,328 |
|
Income
before cumulative effect of accounting change
|
|
|
6,250 |
|
|
|
3,225 |
|
|
|
24,156 |
|
|
|
7,985 |
|
Net
income
|
|
|
5,611 |
|
|
|
3,225 |
|
|
|
24,156 |
|
|
|
7,985 |
|
Income
per share (basic and diluted):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
before cumulative effect of accounting change
|
|
$ |
0.08 |
|
|
$ |
0.04 |
|
|
$ |
0.30 |
|
|
$ |
0.10 |
|
Net
income
|
|
$ |
0.07 |
|
|
$ |
0.04 |
|
|
$ |
0.30 |
|
|
$ |
0.10 |
|
(1) Income
for the second quarter of 2007 includes a $5 million non-tax deductible expense
related to the EPA lawsuit (see Note 17 for further information) and $10.3
million on the exchange of coal reserves.
(2) Income
for the fourth quarter of 2007 includes a $22 million reversal of the accrual
and $11.6
million reversal of accrued interest for the Harman lawsuit (see Note 17
for further information), $15 million non-tax deductible expense related to the
settlement of an EPA lawsuit (see Note 17 for further information) and $6.7
million pre-tax gain on the sale of a mineral rights override .
(3) During
January 2006, our Logan County resource group’s Aracoma longwall mine
experienced a fire. The mine returned to operational status in July 2006. Costs
related to the fire were approximately $5.3 million in the first quarter and
$6.4 million in the second quarter.
(4) Income
for the third quarter of 2006 includes a $30 million pre-tax gain for the sale
of our Falcon reserves (see Note 4 for further information).
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, 2007, 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, 2007, 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, 2007. 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,
2007, internal control over financial reporting is effective.
The
effectiveness of our internal control over financial reporting as of December
31, 2007, has been audited by Ernst & Young LLP, an independent registered
public accounting firm, as stated in their report, which follows immediately
hereafter.
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, 2007, 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, 2007, based on the COSO criteria.
We also
have audited, in accordance with the standards of the Public Company Accounting
Oversight Board (United States), the 2007 consolidated financial statements of
Massey Energy Company and our report dated February 28, 2008 expressed an
unqualified opinion thereon.
/s/ Ernst
& Young LLP
Richmond,
Virginia
Item
9B. Other Information
None.
Part
III
Item
10. Directors, Executive Officers and Corporate Governance
Don
L. Blankenship, Age 57
Mr.
Blankenship has been a director since 1996. He has been Chairman, Chief
Executive Officer and President since November 30, 2000. 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 61
Mr.
Phillips has been Executive Vice President and Chief Administrative Officer
since November 2004. Mr. Phillips previously served 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 44
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 41
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 51
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 43
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.
Richard
R. Grinnan, Age 39
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 38
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 48
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 43
Mr. Poma
has been Vice President, Human Resources since April 2003. 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.
Eric
B. Tolbert, Age 40
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.
Roger
T. Williams, Age 35
Mr.
Williams has been Vice President, Sales since November 2006. Mr. Williams
previously served as Assistant to the Office of the Chairman since July 2005.
Prior to joining us, Mr. Williams worked for Deutsche Bank Group as an
investment banker in the energy sector from July 2002 to March 2005, after
attending Columbia Business School from January 2001 to June 2002.
David
W. Owings, Age 34
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,
2007:
|
•
|
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.
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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.
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Information
regarding Massey’s Code of Ethics required by this item is found under the
heading Code of
Ethics.
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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 May 29, 2007. 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, 2007.
Item
12. Security Ownership of Certain Beneficial Owners and Management and Related
Stockholder Matters