e10vk
UNITED STATES
SECURITIES AND EXCHANGE
COMMISSION
Washington, D.C.
20549
Form 10-K
|
|
|
þ
|
|
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
|
|
|
For the Fiscal Year Ended December 31, 2007
|
or
|
o
|
|
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
|
Commission File Number 1-16463
Peabody Energy
Corporation
(Exact name of registrant as
specified in its charter)
|
|
|
Delaware
|
|
13-4004153
|
(State or other jurisdiction of
incorporation or organization)
|
|
(I.R.S. Employer Identification
No.)
|
701 Market Street, St. Louis, Missouri
|
|
63101
|
(Address of principal executive
offices)
|
|
(Zip Code)
|
(314) 342-3400
Registrants telephone
number, including area code
Securities Registered Pursuant to Section 12(b) of the
Act:
|
|
|
Title of Each Class
|
|
Name of Each Exchange on Which Registered
|
|
Common Stock, par value $0.01 per share
|
|
New York Stock Exchange
|
Preferred Share Purchase Rights
|
|
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 þ No o
Indicate by check mark if the registrant is not required to file
reports pursuant to Section 13 or Section 15(d) of the
Act. Yes o No þ
Indicate by check mark whether the registrant (1) has filed
all reports required to be filed by Section 13 or 15(d) of
the Securities Exchange Act of 1934 during the preceding
12 months (or for such shorter period that the registrant
was required to file such reports) and (2) has been subject
to such filing requirements for the past
90 days. Yes þ No o
Indicate by check mark if disclosure of delinquent filers
pursuant to Item 405 of
Regulation S-K
is not contained herein, and will not be contained, to the best
of registrants knowledge, in definitive proxy or
information statements incorporated by reference in
Part III of this
Form 10-K
or any amendment to this
Form 10-K. þ
Indicate by check mark whether the registrant is a large
accelerated filer, an accelerated filer, a non-accelerated filer
or a smaller reporting company. See the definitions of
large accelerated filer, accelerated
filer and smaller reporting company in
Rule 12b-2
of the Exchange Act. (Check one):
|
|
|
|
|
|
|
Large accelerated
filer þ
|
|
Accelerated
filer o
|
|
Non-accelerated
filer o
|
|
Smaller reporting
company o
|
|
|
|
|
(Do not check if a 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 o No þ
Aggregate market value of the voting stock held by
non-affiliates (shareholders who are not directors or executive
officers) of the Registrant, calculated using the closing price
on June 29, 2007: Common Stock, par value $0.01 per share,
$12.8 billion.
Number of shares outstanding of each of the Registrants
classes of Common Stock, as of February 15, 2008: Common
Stock, par value $0.01 per share, 271,009,658 shares
outstanding.
DOCUMENTS
INCORPORATED BY REFERENCE
Portions of the Companys Proxy Statement to be filed with
the Securities and Exchange Commission in connection with the
Companys 2008 Annual Meeting of Stockholders (the
Companys 2008 Proxy Statement) are incorporated by
reference into Part III hereof. Other documents
incorporated by reference in this report are listed in the
Exhibit Index of this
Form 10-K.
CAUTIONARY
NOTICE REGARDING FORWARD-LOOKING STATEMENTS
This report includes statements of our expectations, intentions,
plans and beliefs that constitute forward-looking
statements within the meaning of Section 27A of the
Securities Act of 1933 and Section 21E of the Securities
Exchange Act of 1934 and are intended to come within the safe
harbor protection provided by those sections. These statements
relate to future events or our future financial performance,
including, without limitation, the section captioned
Outlook. We use words such as
anticipate, believe, expect,
may, project, should,
estimate, or plan or other similar words
to identify forward-looking statements.
Without limiting the foregoing, all statements relating to our
future outlook, anticipated capital expenditures, future cash
flows and borrowings, and sources of funding are forward-looking
statements and speak only as of the date of this report. These
forward-looking statements are based on numerous assumptions
that we believe are reasonable, but are subject to a wide range
of uncertainties and business risks and actual results may
differ materially from those discussed in these statements.
Among the factors that could cause actual results to differ
materially are:
|
|
|
|
|
ability to renew sales contracts;
|
|
|
|
reductions of purchases by major customers;
|
|
|
|
transportation performance and costs, including demurrage;
|
|
|
|
geology, equipment and other risks inherent to mining;
|
|
|
|
impact of weather on demand, production and transportation;
|
|
|
|
legislation, regulations and court decisions or other government
actions;
|
|
|
|
new environmental requirements affecting the use of coal,
including mercury and carbon dioxide related limitations;
|
|
|
|
availability, timing of delivery and costs of key supplies,
capital equipment or commodities such as diesel fuel, steel,
explosives and tires;
|
|
|
|
replacement of coal reserves;
|
|
|
|
price volatility and demand, particularly in higher-margin
products and in our trading and brokerage businesses;
|
|
|
|
performance of contractors, third-party coal suppliers or major
suppliers of mining equipment or supplies;
|
|
|
|
negotiation of labor contracts, employee relations and workforce
availability;
|
|
|
|
availability and costs of credit, surety bonds and letters of
credit;
|
|
|
|
credit and performance risks associated with customers,
suppliers, trading and financial counterparties;
|
|
|
|
the effects of acquisitions or divestitures, including the
spin-off of Patriot Coal Corporation;
|
|
|
|
economic strength and political stability of countries in which
we have operations or serve customers;
|
|
|
|
risks associated with our Btu conversion or generation
development initiatives;
|
|
|
|
risks associated with the conversion of our information systems;
|
|
|
|
growth of U.S. and international coal and power markets;
|
|
|
|
coals market share of electricity generation;
|
|
|
|
the availability and cost of competing energy resources;
|
|
|
|
future worldwide economic conditions;
|
|
|
|
changes in postretirement benefit and pension obligations;
|
i
|
|
|
|
|
successful implementation of business strategies;
|
|
|
|
the effects of changes in currency exchange rates, primarily the
Australian dollar;
|
|
|
|
inflationary trends, including those impacting materials used in
our business;
|
|
|
|
interest rate changes;
|
|
|
|
litigation, including claims not yet asserted;
|
|
|
|
terrorist attacks or threats;
|
|
|
|
impacts of pandemic illnesses; and
|
|
|
|
other factors, including those discussed in Legal Proceedings,
set forth in Item 3 of this report and Risk Factors, set
forth in Item 1A of this report.
|
When considering these forward-looking statements, you should
keep in mind the cautionary statements in this document and in
our other Securities and Exchange Commission (SEC) filings.
These forward-looking statements speak only as of the date on
which such statements were made, and we undertake no obligation
to update these statements except as required by federal
securities laws.
ii
TABLE OF
CONTENTS
|
|
|
|
|
|
|
|
|
|
|
|
|
Page
|
|
PART I.
|
|
Item 1.
|
|
|
Business
|
|
|
2
|
|
|
Item 1A.
|
|
|
Risk Factors
|
|
|
27
|
|
|
Item 1B.
|
|
|
Unresolved Staff Comments
|
|
|
37
|
|
|
Item 2.
|
|
|
Properties
|
|
|
37
|
|
|
Item 3.
|
|
|
Legal Proceedings
|
|
|
42
|
|
|
Item 4.
|
|
|
Submission of Matters to a Vote of Security Holders
|
|
|
45
|
|
|
|
|
|
Executive Officers of the Company
|
|
|
45
|
|
|
PART II.
|
|
Item 5.
|
|
|
Market for Registrants Common Equity, Related Stockholder
Matters and Issuer Purchases of Equity Securities
|
|
|
47
|
|
|
Item 6.
|
|
|
Selected Financial Data
|
|
|
48
|
|
|
Item 7.
|
|
|
Managements Discussion and Analysis of Financial Condition
and Results of Operations
|
|
|
51
|
|
|
Item 7A.
|
|
|
Quantitative and Qualitative Disclosures About Market Risk
|
|
|
74
|
|
|
Item 8.
|
|
|
Financial Statements and Supplementary Data
|
|
|
76
|
|
|
Item 9.
|
|
|
Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure
|
|
|
77
|
|
|
Item 9A.
|
|
|
Controls and Procedures
|
|
|
77
|
|
|
Item 9B.
|
|
|
Other Information
|
|
|
79
|
|
|
PART III.
|
|
Item 10.
|
|
|
Directors, Executive Officers and Corporate Governance
|
|
|
79
|
|
|
Item 11.
|
|
|
Executive Compensation
|
|
|
79
|
|
|
Item 12.
|
|
|
Security Ownership of Certain Beneficial Owners and Management
and Related Stockholder Matters
|
|
|
79
|
|
|
Item 13.
|
|
|
Certain Relationships and Related Transactions, and Director
Independence
|
|
|
79
|
|
|
Item 14.
|
|
|
Principal Accounting Fees and Services
|
|
|
79
|
|
|
PART IV.
|
|
Item 15.
|
|
|
Exhibits and Financial Statement Schedules
|
|
|
80
|
|
1
|
|
|
|
Note:
|
The words we, our,
Peabody or the Company as used in this
report, refer to Peabody Energy Corporation or its applicable
subsidiary or subsidiaries. Unless otherwise noted herein,
disclosures in this Annual Report on
Form 10-K
relate only to our continuing operations. Our discontinued
operations, which were spun-off to stockholders in the fourth
quarter of 2007, consist of portions of our Eastern
U.S. Mining operations business segment.
|
PART I
Overview
We are the largest private-sector coal company in the world.
During the year ended December 31, 2007, we sold
237.8 million tons of coal. During this period, we sold
coal to over 340 electricity generating and industrial plants in
19 countries. Our coal products fuel approximately 10% of all
U.S. electricity generation and 2% of worldwide electricity
generation. At December 31, 2007, we had 9.3 billion
tons of proven and probable coal reserves.
We own majority interests in 31 coal mining operations located
in the U.S and Australia. Additionally, we own a minority
interest in one Venezuelan operating mine through a joint
venture arrangement. We shipped 192.3 million tons from our
20 U.S. mining operations and 21.4 million tons from
our 11 Australia operations in 2007. We shipped 84% of our
U.S. mining operations coal sales volume from the
western United States during the year ended December 31,
2007 and the remaining 16% from the eastern United States. Most
of our production in the western United States is low-sulfur
coal from the Powder River Basin. Our overall Western
U.S. coal production has increased from 128.4 million
tons in 2002 to 161.5 million tons during 2007, a
compounded annual growth rate of 4.7%. In the West, we own and
operate mines in Arizona, Colorado, New Mexico and Wyoming. In
the East, we own and operate mines in Illinois and Indiana. We
own six mines in Queensland, Australia, and five mines in New
South Wales, Australia. Our Australian production includes both
low-sulfur domestic and export thermal coal and metallurgical
coal. The export thermal and metallurgical coal is predominantly
shipped to customers in the Asia-Pacific region. We generated
89% of our global production for the year ended
December 31, 2007 from non-union mines.
For the year ended December 31, 2007, 85% of our sales (by
volume) were to U.S. electricity generators, 13% were to
customers outside the United States and 2% were to the
U.S. industrial sector. Approximately 94% of our coal sales
during the year ended December 31, 2007 were under
long-term (one year or greater) contracts. Our sales backlog,
including backlog subject to price reopener
and/or
extension provisions, was nearly one billion tons as of
December 31, 2007, representing more than four years of
current production in backlog. Contracts in backlog have
remaining terms ranging from one to 17 years. We are
targeting 2008 production of 220 to 240 million tons and
total sales volume of 240 to 260 million tons, including 8
to 10 million tons of metallurgical coal. As of
December 31, 2007, our unpriced 2008 volumes for planned
produced tonnage were 5 to 10 million U.S. tons and 9
to 10 million Australia tons. Our total unpriced planned
production for 2009 is approximately 80 to 90 million tons
in the United States and 17 to 20 million tons in Australia.
Our mining operations consist of three principal operating
segments: Western U.S. Mining, Eastern U.S. Mining,
and Australian Mining. In addition to our mining operations, we
market, broker and trade coal through our Trading and Brokerage
Operations segment. Our total tons traded were
166.5 million for the year ended December 31, 2007. In
response to growing international markets, we established an
international trading group in 2006 and added a trading
operations office in Europe in early 2007. We also have a
business development, sales and marketing office in Beijing,
China to pursue potential long-term growth opportunities there.
Our other energy-related commercial activities include the
development of mine-mouth coal-fueled generating plants, the
management of our vast coal reserve and real estate holdings,
and Btu Conversion technologies, which are designed to convert
coal to natural gas and transportation fuels.
2
For financial information regarding each of our operating
segments, see Note 24 to our consolidated financial
statements.
Discontinued
Operations
On October 31, 2007, we spun-off portions of our Eastern
U.S. Mining operations business segment to
form Patriot Coal Corporation (Patriot). We distributed
Patriot stock to our stockholders at a ratio of one share of
Patriot stock for every 10 shares of Peabody stock held on
the record date of October 22, 2007. Our results for all
periods presented reflect Patriot as a discontinued operation.
The spin-off included eight company-operated mines, two
majority-owned joint venture mines, and numerous contractor
operated mines serviced by eight coal preparation facilities
along with 1.2 billion tons of proven and probable coal
reserves. Prior to the spin-off, we received necessary
regulatory approvals including a private letter ruling on the
tax-free nature of the transaction from the Internal Revenue
Service.
History
Peabody, Daniels and Co. was founded in 1883 as a retail coal
supplier, entering the mining business in 1888 as
Peabody & Co. with the opening of our first coal mine
in Illinois. In 1926, Peabody Coal Company was listed on the
Chicago Stock Exchange and, beginning in 1949, on the New York
Stock Exchange.
In 1955, Peabody Coal Company, primarily an underground mine
operator, merged with Sinclair Coal Company, a major surface
mining company. Peabody Coal Company was acquired by Kennecott
Copper Company in 1968. The company was then sold to Peabody
Holding Company in 1977, which was formed by a consortium of
companies.
During the 1980s, Peabody grew through expansion and
acquisition, opening the North Antelope Mine in Wyomings
coal-rich Powder River Basin in 1983 and the Rochelle Mine in
1985.
In July 1990, Hanson, PLC acquired Peabody Holding Company. In
the 1990s, Peabody continued to grow through expansion and
acquisitions. In February 1997, Hanson spun off its
energy-related businesses, including Eastern Group and Peabody
Holding Company, into The Energy Group, plc. The Energy Group
was a publicly traded company in the United Kingdom and its
American Depository Receipts (ADRs) were publicly traded on the
New York Stock Exchange.
In May 1998, Lehman Brothers Merchant Banking Partners II
L.P. and affiliates (Merchant Banking Fund), an affiliate of
Lehman Brothers Inc. (Lehman Brothers), purchased Peabody
Holding Company and its affiliates, Peabody Resources Limited
and Citizens Power LLC in a leveraged buyout transaction that
coincided with the purchase by Texas Utilities of the remainder
of The Energy Group. In August 2000, Citizens Power, our
subsidiary that marketed and traded electric power and
energy-related commodity risk management products, was sold to
Edison Mission Energy and in January 2001, we sold our Peabody
Resources Limited (in Australia) operations to Coal &
Allied, a subsidiary of Rio Tinto Limited.
In April 2001, we changed our name to Peabody Energy
Corporation, reflecting our position as a premier energy
supplier. In May 2001, we completed an initial public offering
of common stock, and our shares began trading on the New York
Stock Exchange under the ticker symbol BTU, the
globally recognized symbol for energy.
In April 2004, we acquired coal operations from RAG Coal
International AG, expanding our presence in both Australia and
Colorado. In December 2004, we completed the purchase of a 25.5%
equity interest in Carbones del Guasare from RAG Coal
International, S.A. Carbones del Guasare, a joint venture with
Anglo American plc and a Venezuelan governmental partner,
operates Venezuelas largest coal mine, the Paso Diablo
Mine in northwestern Venezuela. In October 2006, we expanded our
presence in Australia with the acquisition of Excel Coal Limited
(Excel), an independent coal company in Australia. The Excel
acquisition included operating and development-stage mines,
along with proven and probable coal reserves of up to
500 million tons.
3
On October 31, 2007, we spun-off portions of our Eastern
U.S. Mining operations business segment to
form Patriot Coal Corporation as noted above. The spin-off
included eight company-operated mines, two majority-owned joint
venture mines, and numerous contractor operated mines serviced
by eight coal preparation facilities along with 1.2 billion
tons of proven and probable coal reserves.
We have transformed in recent years from a high-sulfur,
high-cost coal company to a predominately low sulfur, low-cost
coal producer, marketer / trader of coal and manager
of vast natural resources through organic growth, acquisitions
and strategic operational restructuring. We operate under four
core strategies to achieve growth. These include executing the
basics of
best-in-class
safety, operations and marketing; capitalizing on organic growth
opportunities; expanding in high-growth global markets; and
participating in new generation and Btu Conversion technologies
to convert coal into natural gas, liquids and hydrogen. Through
these strategies, in 2008, we are focused on several key areas
to enhance shareholder value amid the multiple markets we
operate: 1) improving productivity and costs, utilizing
prior-year investments and ongoing operations improvement
programs; 2) expanding access to high-growth, high-margin
markets; 3) improving capital efficiency; 4) pursuing
long-term operating, trading and joint-venture opportunities in
China, Mongolia and Mozambique; and 5) advancing clean coal
projects, including Btu Conversion initiatives.
Mining
Operations
We conduct our mining business through three principal mining
operating segments: Western U.S. Mining, Eastern
U.S. Mining, and Australian Mining. Our Western
U.S. Mining Operations consist of our Powder River Basin,
Southwest and Colorado operations, and our Eastern
U.S. Mining Operations consist of our Midwest operations.
The principal business of our U.S. Mining segments is the
mining, preparation and sale of steam coal, sold primarily to
electric utilities. Internationally, we operate metallurgical
and steam coal mines in Queensland, Australia and New South
Wales, Australia and have a 25.5% investment in a Venezuelan
mine. All of our operating segments are discussed in
Note 24 to our consolidated financial statements.
4
The following describes the operating characteristics of the
principal mines and reserves of each of our business units and
affiliates. The maps below show mine locations as of
December 31, 2007. The U.S. map does not include our
El Segundo Mine in New Mexico, which is expected to begin
operations in mid-2008. All of our mining operations are owned
and managed by our subsidiaries. The subsidiary that manages a
particular mining operation is not necessarily the same as the
subsidiary or subsidiaries which own the assets utilized in that
mining operation. Unless otherwise indicated, we own 100% of the
subsidiary that manages the respective mining operations or owns
the related assets.
U.S.
Mining Operations
Powder
River Basin Operations
We control approximately 3.3 billion tons of proven and
probable coal reserves in the Southern Powder River Basin, the
largest and fastest growing major U.S. coal-producing
region. We manage three low-sulfur, non-union surface mining
complexes in Wyoming that sold 139.8 million tons of coal
during the year ended December 31, 2007, or approximately
59% of our total coal sales volume. The North Antelope Rochelle
and Caballo Mines are serviced by both major western railroads,
the Burlington Northern Santa Fe (BNSF) Railway and the
Union Pacific Railroad. The Rawhide Mine is serviced by the BNSF
Railway.
Our Wyoming Powder River Basin reserves are classified as
surface mineable, subbituminous coal with seam thickness varying
from 60 to 115 feet. The sulfur content of the coal in
current production ranges from 0.2% to 0.4% and the heat value
ranges from 8,300 to 8,800 Btus per pound.
North
Antelope Rochelle Mine
The North Antelope Rochelle Mine is located 65 miles south
of Gillette, Wyoming. This mine is the largest in the world,
selling 91.5 million tons of compliance coal (defined as
having sulfur dioxide content of 1.2 pounds or less per million
Btu) during 2007. The North Antelope Rochelle Mine produces
premium quality coal with a sulfur content averaging 0.2% and a
heat value ranging from 8,600 to 8,800 Btu per pound. The North
Antelope Rochelle Mine produces the lowest sulfur coal in the
United States, using three draglines along with five overburden
truck-and-shovel
fleets. During 2007 we erected a new dragline and completed an
in-pit crusher/conveyor at North Antelope Rochelle. These
projects, combined with the completion of new blending and
loading facilities in the first half of 2008, are designed to
lower our cost structure by reducing reliance on truck fleets,
while also increasing capacity.
5
Caballo
Mine
The Caballo Mine is located 20 miles south of Gillette,
Wyoming. During 2007, it sold 31.2 million tons of
compliance coal. Caballo is a cast/dozer/truck-and-shovel assist
operation with a coal handling system that includes two
12,000-ton silos and two 11,000-ton silos. The Caballo Mine
produces compliance coal with a sulfur content averaging 0.36%
and a heat value averaging 8,500 Btu per pound.
Rawhide
Mine
The Rawhide Mine is located 10 miles north of Gillette,
Wyoming. During 2007, it sold 17.1 million tons of
compliance coal. Rawhide is a cast/dozer-push/truck-and-shovel
assist operation with a coal handling system that includes two
12,000-ton silos and four 11,000-ton silos. The Rawhide Mine
produces compliance coal with a sulfur content averaging 0.37%
and a heat value averaging 8,300 Btu per pound.
Southwest
Operations
We own four coal mines in our Southwest operations, two in
Arizona and two in New Mexico. Kayenta, in Arizona, and Lee
Ranch, in New Mexico, are both in operation. The Black Mesa Mine
in Arizona suspended operations as of December 31, 2005 and
the El Segundo Mine in New Mexico is scheduled to begin
production in mid-2008. We control 1.0 billion tons of
proven and probable coal reserves in our Southwest operations.
Kayenta
Mine
The Kayenta Mine, located on the Navajo Nation and Hopi Tribe
lands in Arizona, uses four draglines in three mining areas. It
sold approximately 7.9 million tons of coal during 2007 and
supplies primarily bituminous compliance coal under a long-term
coal supply agreement to an electricity generating station in
the region. The Kayenta Mine coal is crushed, then carried
17 miles by conveyor belt to storage silos where it is
loaded onto a private rail line and transported 83 miles to
the Navajo Generating Station, operated by the Salt River
Project near Page, Arizona. The mine and railroad were designed
to deliver coal exclusively to the power plant, which has no
other source of coal. The Navajo coal supply agreement extends
until 2011. Hourly workers at this mine are members of the
United Mine Workers of America (UMWA) under a contract that
extends through 2013.
Lee
Ranch Mine
The Lee Ranch Mine, located near Grants, New Mexico, sold
approximately 5.8 million tons of subbituminous medium
sulfur coal during 2007. Lee Ranch shipped the majority of its
coal to two customers in Arizona and New Mexico under coal
supply agreements extending until 2020 and 2014, respectively.
Lee Ranch is a non-union surface mine that uses a combination of
dragline and
truck-and-shovel
mining techniques and ships coal to its customers via the BNSF
Railway.
El
Segundo Mine
The El Segundo Mine, located near Grants, New Mexico, is
currently under development and is expected to start producing
subbituminous medium sulfur coal in mid-2008. We executed a
19 year coal supply agreement that serves as the
mines base-load contract. El Segundo is expected to be a
non-union surface mine that uses
truck-and-shovel
mining techniques and ships coal to its customers via the BNSF
Railway.
Colorado
Operations
We control approximately 0.2 billion tons of proven and
probable coal reserves and currently have one operating mine in
the Colorado Region.
6
Twentymile
Mine
The Twentymile Mine is located in Routt County, Colorado, and
sold 7.9 million tons of compliance, low-sulfur, steam coal
to customers throughout the United States during 2007. This mine
uses both longwall and continuous mining equipment. Our
Twentymile Mine is non-union and has been one of the largest
underground mines in the United States. Approximately 75% of all
coal shipped is loaded on the Union Pacific railroad; the
remainder is hauled by truck to the nearby Hayden Generating
Station, operated by the Public Service of Colorado, under a
coal supply agreement that extends until 2011.
Midwest
Operations
Our Midwest operations consist of 13 mines in the Illinois
Basin. We control approximately 3.7 billion tons of proven
and probable coal reserves in the Midwest. In 2007, these
operations collectively sold 30.9 million tons of coal,
more than any other Midwestern coal producer. We ship coal from
these mines primarily to electricity generators in the Midwest
and to industrial customers for power generation.
Gateway
Mine
The Gateway Mine is a non-union underground mine located in
Randolph County, Illinois. During 2007, the Gateway Mine sold
2.7 million tons of steam coal.
Air
Quality Mine
The Air Quality Mine is an underground mine located near Monroe
City, Indiana that sold 2.0 million tons of compliance coal
in 2007. The Air Quality Mine has a non-union workforce.
Farmersburg
Mine
The Farmersburg Mine is a surface mine located in Vigo and
Sullivan counties in Indiana that sold 3.5 million tons of
medium sulfur coal in 2007. The Farmersburg Mine has a non-union
workforce.
Francisco
Mine Complex
The Francisco Mine Complex, which has both an underground and
surface mine, is located in Gibson County, Indiana and sold
3.0 million tons of medium sulfur coal in 2007. The
Francisco Mine Complex has a non-union workforce.
Somerville
Mine Complex
The Somerville Mine Complex consists of three surface mines
located in Gibson County, Indiana. These mines collectively sold
8.5 million tons of medium sulfur coal in 2007. The
Somerville Mine Complex has a non-union workforce.
Viking
Mine
The Viking Mine is a surface mine located in Indiana that sold
1.7 million tons of medium sulfur coal in 2007. The Viking
Mine has a non-union workforce.
Miller
Creek Mine
The Miller Creek Mine is a surface mine located in Indiana that
sold 1.6 million tons of medium sulfur coal in 2007. The
Miller Creek Mine has a non-union workforce.
Vermilion
Grove-Riola Mine Complex
Vermilion Grove is a portal of the Riola Mine, an underground
mine located in east central Illinois that sold 1.4 million
tons of medium sulfur coal in 2007. Vermilion Grove has a
non-union workforce.
7
Wildcat
Hills Mine Complex
The Wildcat Hills Mine Complex, which has both an underground
and surface mine, is located in Gallatin and Saline counties in
southern Illinois. During 2007, these mines sold
2.9 million tons of medium sulfur coal that is primarily
shipped by barge to downriver utility plants. The Wildcat Hills
Mine Complex has a non-union workforce.
Willow
Lake Mine
The Willow Lake Mine is an underground mine in Southern
Illinois. During 2007, the mine sold 3.6 million tons of
medium sulfur coal that is primarily shipped by barge to
downriver utility plants. The hourly workforce at the Willow
Lake Mine is represented under an International Brotherhood of
Boilermakers labor agreement. A new labor agreement was signed
in 2007, which will expire April 15, 2011.
Australian
Mining Operations
We manage six mines in Queensland, Australia, and five mines in
New South Wales, Australia. During 2007, our Australian
operations sold 21.4 million tons of coal,
8.7 millions tons of which were metallurgical coal. Coal
from the Queensland mines is shipped via rail and truck from the
mine to the Dalrymple Bay Coal Terminal and the Ports of
Gladstone and Brisbane, where the coal is loaded onto
ocean-going vessels. Coal from the New South Wales mines is
shipped via rail and truck from the mine to domestic customers
and to the Ports of Newcastle and Kembla. The majority of sales
from our Australian mines are denominated in U.S. dollars.
Our Australian mines operate with site-specific collective
bargaining labor agreements. Our Australian operations control
1.1 billion tons of proven and probable coal reserves.
Wilkie
Creek Mine
The Wilkie Creek Mine, located in Queensland, Australia, is a
surface,
truck-and-shovel
operation. In 2007, the Wilkie Creek Mine sold 2.4 million
tons of steam coal, all of which was sold to the Asia export
market through the Port of Brisbane.
8
Burton
Mine
The Burton Mine, located in Queensland, Australia, is a surface
mine using the
truck-and-shovel
terrace mining technique. We own 95% of the Burton operation and
the remaining 5% interest is owned by the contract miner that
operates on reserves we control. During 2007, we sold
3.0 million tons of metallurgical coal and 0.2 million
tons of steam coal from the Burton Mine through the Dalrymple
Bay Coal Terminal.
Millennium
Mine
The Millennium Mine, located in Queensland, Australia, is a new
surface operation utilizing
truck-and-shovel
mining methods which began operations in early 2007. We own an
85% interest in the Millennium Mine and manage the operations
utilizing a contract miner. In January 2008, we formed a joint
venture that provides an additional 35 million tons of high
quality metallurgical coal reserves and grants to our joint
venture partner a 50% ownership position in our preparation
facility and associated infrastructure assets. During 2007, the
Millennium Mine sold 1.0 million tons of metallurgical coal
through the Dalrymple Bay Coal Terminal.
North
Goonyella Mine
The North Goonyella Mine, located in Queensland, Australia, is a
longwall underground operation. The North Goonyella Mine
operates in a difficult geologic environment and produces a
high-quality metallurgical coal product. During 2007, the North
Goonyella Mine sold 1.3 million tons of metallurgical coal
through the Dalrymple Bay Coal Terminal.
Eaglefield
Mine
The Eaglefield Mine, located in Queensland, Australia, is a
surface operation utilizing
truck-and-shovel
mining methods. It is adjacent to, and fulfills contract
tonnages in conjunction with the North Goonyella underground
mine. Coal is mined by a contractor from reserves that we
control. During 2007, the Eaglefield Mine sold 1.2 million
tons of metallurgical coal through the Dalrymple Bay Coal
Terminal.
Baralaba
Mine
The Baralaba Mine, located in Queensland, Australia, is a
surface operation utilizing
truck-and-shovel
mining methods. The mine produces primarily pulverized coal
injection (PCI) product, a substitute for metallurgical coal
used primarily by steel makers. During 2007, the Baralaba Mine
sold 0.4 million tons of PCI product. We own a 62.5%
interest in the Baralaba Mine and manage the operations
utilizing a contract miner.
Wambo
Open-Cut Mine
The Wambo Open-Cut Mine, located in New South Wales, Australia,
is a surface operation utilizing
truck-and-shovel
mining methods. During 2007, the Wambo Open-Cut Mine sold
4.4 million tons of steam coal. The coal from this mine was
shipped through the Port of Newcastle. We own a 75% interest in
the Wambo Open-Cut Mine and manage the operations utilizing a
contract miner.
North
Wambo Underground Mine
The North Wambo Underground Mine, located in New South Wales,
Australia, is a longwall underground mine which was commissioned
in the fourth quarter of 2007. During 2007, the North Wambo
Underground Mine sold 0.3 million tons of steam coal. The
coal from this mine was shipped through the Port of Newcastle.
We own a 75% interest in the Wambo Underground Mine.
9
Metropolitan
Mine
The Metropolitan Mine, located in New South Wales, Australia, is
a longwall underground operation. In 2007, the Metropolitan Mine
sold 1.6 million tons of hard and semi-hard metallurgical
coal. Coal shipments from this mine are to export customers
through Port Kembla and to an Australian customer.
Wilpinjong
Mine
The Wilpinjong Mine, located in New South Wales, Australia, is a
new open-cut mine that was commissioned in late 2006. The mine
produces thermal coal for export customers through the Port of
Newcastle in addition to serving an Australian electricity
generator. Coal is mined by a contractor from reserves that we
control. During 2007, the Wilpinjong Mine sold 5.1 million
tons of steam coal.
Chain
Valley Mine
The Chain Valley Mine located in New South Wales, Australia, is
a room and pillar underground operation. The Chain Valley Mine
produces thermal coal which is sold locally to power authorities
and to export customers through the Port of Newcastle. During
2007, the Chain Valley Mine sold 0.6 million tons of
thermal coal for the year. We own 80% of the Chain Valley Mine.
Venezuelan
Mining Operations
Our Venezuelan Operations consist of two joint ventures,
including one operating mine and one coal mine development
project.
Pasa
Diablo Mine
We own a 25.5% interest in Carbones del Guasare, S.A., a joint
venture that includes Anglo American plc and a Venezuelan
governmental partner. Carbones del Guasare operates the Paso
Diablo Mine in Venezuela. The Paso Diablo Mine is a surface
operation in northwestern Venezuela that produces approximately
6 to 8 million tons of steam coal annually for export
primarily to the United States and Europe. We are responsible
for marketing our pro-rata share of sales from Paso Diablo; the
joint venture is responsible for production, processing and
transportation of coal to ocean-going vessels for delivery to
customers.
Las
Carmelitas Coal Mine Project
We own a 51.0% interest in Excelven Pty Ltd., which holds a
96.7% interest in Cosila Complejo Siderurgico Del Lago S.A.
(Cosila). Cosila owns the Las Carmelitas Coal Mine Project,
which has approximately 46 million tons of reserves in
Venezuela. The other partners in this project include Alpha
Natural Resources and Triangle Resource Fund. This project is
currently in the exploratory stage. This interest was acquired
in October 2006 as part of the Excel acquisition.
10
Export
Facilities
We own a 30% interest in Dominion Terminal Associates, a coal
transloading facility in Newport News, Virginia. The facility
has a rated throughput capacity of approximately 20 million
tons of coal per year and ground storage capacity of
approximately 1.7 million tons. The facility exports both
metallurgical and steam coal to primarily European and Brazilian
markets. The terminal does not currently operate at its capacity.
We own a 17.7% interest in the Newcastle Coal Infrastructure
Group (NCIG), which is currently constructing a coal
transloading facility in New South Wales, Australia. The
facility, which is expected to be completed in 2010, will have
an initial stage capacity of 30 million tonnes per annum of
which our share is 5.3 million tonnes, with expansion
capacity of up to 60 million tonnes per annum.
Resource
Management
We hold approximately 9.3 billion tons of proven and
probable coal reserves and more than 475,000 acres of
surface property. Our resource development group constantly
reviews these reserves for opportunities to generate revenues
through the sale of non-strategic coal reserves and surface
land. In addition, we generate revenue through royalties from
coal reserves and oil and gas rights leased to third parties,
coalbed methane production and farm income from surface land
under third-party contracts.
Trading
and Brokerage Operations
Through our Trading and Brokerage Operations segment, we sell
coal produced by our diverse portfolio of operations, broker
coal sales of other coal producers both as principal and agent,
trade coal, and trade freight contracts and provide
transportation-related services in support of our coal trading
strategy. As of December 31, 2007, we had 90 employees
in our sales, trading, brokerage, marketing and transportation
operations, including personnel dedicated to performing market
research and contract administration.
International
Expansion
In response to growing international markets, we expanded our
international trading group in 2006 and added a trading
operations office in Europe in 2007. The sales and marketing
operations include our COALTRADE Australia operation that
brokers coal in the Australia and Pacific Rim markets, and is
based in Newcastle, Australia. We also have a business
development, sales and marketing office in Beijing, China to
pursue potential long-term growth opportunities in this market.
Long-Term
Coal Supply Agreements
We currently have a sales backlog of almost one billion tons of
coal, including backlog subject to price reopener
and/or
extension provisions, representing more than four years of
current production in backlog. Contracts in backlog have
remaining terms ranging from one to 17 years. In the same
period in 2006, we had a sales backlog in excess of one billion
tons of coal. For 2007, we sold approximately 94% of our sales
volume under long-term coal supply agreements. In 2007, we sold
coal to over 340 electricity generating and industrial plants in
19 countries. Our primary customer base is in the United States,
although customers in the Pacific Rim and other international
locations represent an increasing portion of our revenue stream.
We expect to continue selling a significant portion of our coal
under long-term supply agreements. Our strategy is to
selectively renew, or enter into new, long-term coal supply
contracts when we can do so at prices we believe are favorable.
Long-term contracts are attractive for regions where market
prices are expected to remain stable, for cost-plus arrangements
serving captive electricity generating plants and for the sale
of high-sulfur coal to scrubbed generating plants.
To the extent we do not renew or replace expiring long-term coal
supply agreements, our future sales will be subject to market
fluctuations.
In January 2006, we signed a
19-year,
65-million-ton
coal supply agreement with Arizona Public Service Company (APS).
The contract is expected to generate revenue in excess of
$1 billion. When our planned 6 million ton per year El
Segundo Mine begins production in mid-2008, it will serve
APSs Cholla Generating
11
Station near Joseph City, Arizona, and other customers. In
December 2006, we signed a
10-year coal
supply agreement with Tennessee Valley Authority to supply
6 million tons per year of Illinois Basin coal, some of
which will be supplied by Patriot under contract with us. Coal
sales under the first five years of the agreement are expected
to be in excess of $1 billion. We also have a long-term
coal supply agreement with Macquarie Generation in Australia,
which runs through 2025 and will supply approximately
127 million tons in total.
Typically, customers enter into coal supply agreements to secure
reliable sources of coal at predictable prices, while we seek
stable sources of revenue to support the investments required to
open, expand and maintain or improve productivity at the mines
needed to supply these contracts. The terms of coal supply
agreements result from competitive bidding and extensive
negotiations with customers. Consequently, the terms of these
contracts vary significantly in many respects, including price
adjustment features, price reopener terms, coal quality
requirements, quantity parameters, permitted sources of supply,
treatment of environmental constraints, extension options, force
majeure, and termination and assignment provisions.
Each contract sets a base price. Some contracts provide for a
predetermined adjustment to the base price at times specified in
the agreement. Base prices may also be adjusted quarterly,
annually or at other periodic intervals for changes in
production costs
and/or
changes due to inflation or deflation. Changes in production
costs may be measured by defined formulas that may include
actual cost experience at the mine as part of the formula. The
inflation/deflation adjustments are measured by public indices,
the most common of which for U.S. coal is the implicit
price deflator for the gross domestic product as published by
the U.S. Department of Commerce. In most cases, the
components of the base price represented by taxes, fees and
royalties which are based on a percentage of the selling price
are also adjusted for any changes in the base price and passed
through to the customer. Some contracts allow the base price to
be adjusted to reflect the cost of capital.
Most contracts contain provisions to adjust the base price due
to new statutes, ordinances or regulations that impact our cost
of performance under the agreement. Additionally, most contracts
contain provisions that allow for the recovery of costs impacted
by the modifications or changes in the interpretation or
application of any existing statute by local, state or federal
government authorities. Some agreements provide that if the
parties fail to agree on a price adjustment caused by cost
increases due to changes in applicable laws and regulations,
either party may terminate the agreement.
Price reopener provisions are present in many of our multi-year
coal contracts. These provisions may allow either party to
commence a renegotiation of the contract price at various
intervals. In a limited number of agreements, if the parties do
not agree on a new price, the purchaser or seller has an option
to terminate the contract. Under some contracts, we have the
right to match prices offered to our customers by other
suppliers.
Quality and volumes for the coal are stipulated in coal supply
agreements, and in some limited instances buyers have the option
to vary annual or monthly volumes if necessary. Variations to
the quality and volumes of coal may lead to adjustments in the
contract price. Most coal supply agreements contain provisions
requiring us to deliver coal within certain ranges for specific
coal characteristics such as heat (Btu), sulfur, and ash
content, and for grindability and ash fusion temperature.
Failure to meet these specifications can result in economic
penalties, suspension or cancellation of shipments or
termination of the contracts. Coal supply agreements typically
stipulate procedures for quality control, sampling and weighing.
In the eastern United States, some of our customers require that
the coal is sampled and weighed at the destination, whereas in
the western United States samples and weights are usually taken
at the shipping source.
Contract provisions in some cases set out mechanisms for
temporary reductions or delays in coal volumes in the event of a
force majeure, including events such as strikes, adverse mining
conditions or serious transportation problems that affect the
seller or unanticipated plant outages that may affect the buyer.
More recent contracts stipulate that this tonnage can be made up
by mutual agreement. Buyers often negotiate similar clauses
covering changes in environmental laws. We often negotiate the
right to supply coal that complies with a new environmental
requirement to avoid contract termination. Coal supply
agreements typically contain termination clauses if either party
fails to comply with the terms and conditions of the contract,
although most termination provisions provide the opportunity to
cure defaults.
12
In some of our contracts, we have a right of substitution,
allowing us to provide coal from different mines, including
third-party production, as long as the replacement coal meets
the contracted quality specifications and will be sold at the
same delivered cost per million Btu.
Transportation
Coal consumed in the U.S. is usually sold at the mine and
transportation costs are borne by the purchaser. Export coal is
usually sold at the loading port, with purchasers paying ocean
freight. Producers usually pay shipping costs from the mine to
the port, including any demurrage costs (fees paid to
third-party shipping companies for loading time that exceeded
the stipulated time).
The majority of our sales volume is shipped by rail in the U.S.,
but a portion of our production is shipped by other modes of
transportation, including barge, truck and ocean-going vessels.
Our transportation department manages the loading of coal via
these transportation modes.
Our Australian export volume (17 to 20 million tons
annually) is shipped via ocean going vessels to customers. The
majority of this coal reaches the loading port via rail. Our
Australian domestic volume (4 to 6 million tons annually)
is shipped via rail.
Approximately 12,000 unit trains are loaded each year to
accommodate the coal shipped by our mines overall. A unit train
generally consists of 100 to 150 cars, each of which can hold
100 to 120 tons of coal. We believe we have good relationships
with rail carriers and barge companies due, in part, to our
modern coal-loading facilities and the experience of our
transportation coordinators.
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
U.S. 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 financial condition, results of
operations or cash flows.
Technical
Innovation
To support the continued growth and globalization of our
businesses, we have completed the U.S. implementation of a
project to convert our existing information systems across the
major business processes to an integrated Enterprise Resource
Planning (ERP) information technology system provided by SAP AG.
The project establishes a single global information platform for
us and will enable standard processes and real-time capabilities
in Finance, Materials, Maintenance, Human Resources, Sales,
Production, Transportation and Quality across all of our
U.S. operations. A future conversion of all of our
Australian systems onto the same single global platform is
planned for 2009.
We continue to place great emphasis on the application of
technical innovation to improve new and existing equipment
performance. This research and development effort is typically
undertaken and funded by equipment manufacturers using our input
and expertise. Our engineering, maintenance and purchasing
personnel work together with manufacturers to design and produce
equipment that we believe will add value to the business.
13
During 2007, we continued to make progress toward the
improvement to the performance of our dragline systems. The
dragline improvement effort includes more efficient bucket
design, faster cycle times, improved swing motion controls to
increase component life and better monitors to enable increased
payloads. Draglines were refurbished and upgraded in Wyoming and
Arizona with many new design features. All draglines are
equipped with stress and performance monitoring equipment.
Technology to quickly capture, analyze and transfer information
regarding safety, performance and maintenance conditions at our
operations is a priority. A wireless data acquisition system has
been installed at the North Antelope Rochelle Mine to more
efficiently dispatch mobile equipment and monitor performance
and condition of all major mining equipment on a real-time
basis. Plans are underway to rollout the system to other mining
operations. Proprietary software for hand-held Personal Digital
Assistant (PDA) devices was developed in-house, and is being
used for safety observations and safety audits and underground
front-line supervisor reports in the U.S.
World-class maintenance standards based on reliability centered
maintenance practices are being implemented at all operations.
Use of these techniques is expected to allow us to increase
equipment utilization and reduce maintenance and capital
spending by extending the equipment life, while minimizing the
risk of premature failures. Optimized equipment strategies are
being developed to define the appropriate preventative and
predictive maintenance activities emphasizing work being
scheduled on condition rather than time. Benefits from
sophisticated analysis derived from lubrication, vibration and
infrared technologies typically include lower lubrication
consumption, optimum equipment performance and extended
component life. Specialized maintenance reliability software was
installed in 2007 to better support the definition of these
equipment strategies, predict equipment condition and aid
analysis necessary for better decision making for such issues as
component replacement timing.
Our mines use sophisticated software to schedule and monitor
trains, mine and pit blending, quality and customer shipments.
This integrated software was developed in-house and provides a
competitive tool to differentiate our reliability and product
consistency. Our new preparation plant at the Twentymile Mine in
Colorado utilizes the latest concepts in low profile design and
high capacity equipment for improved maintenance practices and
overall plant utilization. The process circuitry uses the
current
state-of-the-art
large diameter heavy media cyclones and two stage fine coal
cleaning with water-only cyclones and spirals to enhance process
performance and yield. A number of safety and monitoring
features have been incorporated in the plant including an
internet-accessible camera system.
We are also involved in the commercial development and
advancement of Btu Conversion technologies (see the Btu
Conversion discussion that follows for more details).
Competition
The markets in which we sell our coal are highly competitive.
According to the National Mining Associations 2006
Coal Producer Survey, the top 10 coal companies in the
United States produced approximately 68% of total U.S. coal
in 2006. Our principal U.S. competitors are other large
coal producers, including Arch Coal, Inc., Rio Tinto Energy
America, CONSOL Energy Inc, Foundation Coal Corporation, Patriot
Coal Corporation and Massey Energy Company, which collectively
accounted for approximately 49% of total U.S. coal
production in 2006. Major international competitors include Rio
Tinto,
Anglo-American
PLC, BHP Billiton, Shenhua Group, China Coal and Xstrata PLC.
A number of factors beyond our control affect the markets in
which we sell our coal. Continued demand for our coal and the
prices obtained by us depend primarily on the coal consumption
patterns of the electricity generation and steel industries in
the United States, China, India and elsewhere around the world;
the availability, location, cost of transportation and price of
competing coal; and other electricity generation and fuel supply
sources such as natural gas, oil, nuclear and hydroelectric.
Coal consumption patterns are affected primarily by the demand
for electricity, environmental and other governmental
regulations, and technological developments. We compete on the
basis of coal quality, delivered price, customer service and
support, and reliability.
14
Generation
Development
To maximize our coal assets and land holdings for long-term
growth, we continue to pursue the development of coal-fueled
generating projects in areas of the U.S. where electricity
demand is strong and where there is access to land, water,
transmission lines and low-cost coal. The projects involve
mine-mouth generating plants using our surface lands and coal
reserves. Our ultimate role in these projects could take
numerous forms, including, but not limited to, equity partner,
contract miner or coal lessor. The projects we are currently
pursuing, as further detailed below, include the 1,600
plus-megawatt Prairie State Energy Campus in Washington County,
Illinois and the 1,500-megawatt Thoroughbred Energy Campus in
Muhlenberg County, Kentucky.
Because coal costs just a fraction of natural gas, mine-mouth
generating plants can provide low-cost electricity to satisfy
growing baseload generation demand. The plants will be designed
to comply with all current clean air standards using advanced
emissions control technologies. The plants, assuming all
necessary permits and financing are obtained and following
selection of partners and sale of a majority of the output of
each plant, could be operational following a four-year
construction phase.
Prairie
State Energy Campus
The Prairie State Energy Campus (Prairie State), of which we own
5.06%, is a 1,600 plus-megawatt coal-fueled electricity
generation project under construction in Washington County,
Illinois. Prairie State will be fueled by over six million tons
of coal each year produced from adjacent underground mining
operations. In September 2007, a group of Midwest rural electric
cooperatives and municipal joint action agencies entered into
definitive agreements with our affiliate and acquired
approximately 72% of the project, and in December 2007 our
affiliate sold an additional 23% of Prairie State. The plant
could begin generating electricity in the 2011 to 2012 timeframe.
In January 2005, the State of Illinois issued the final air
permit for the electric generating station and adjoining coal
mine. In August 2007, the U.S. Court of Appeals for the
Seventh Circuit unanimously affirmed the issuance of Prairie
States air permit and in October 2007 the Court
unanimously rejected a request for a rehearing of its prior
decision. Because there was no appeal of the Courts
decision, that decision upholding the permit is now final.
Thoroughbred
Energy Campus
The 1,500-megawatt Thoroughbred Energy Campus (Thoroughbred) in
Muhlenberg County, Kentucky is a development stage electric
generating station that has received a conditional construction
certificate from the Commonwealth of Kentucky. We and the
Commonwealth of Kentucky defended the air permit granted to
Thoroughbred in 2002 against challenges by various environmental
advocacy groups, and in April 2006 we received a decision
affirming the Thoroughbred air permit. Certain parties
subsequently challenged the favorable decision in Kentucky state
court. On August 6, 2007 the Franklin Circuit Court
remanded the permit back to the Kentucky permitting agency. On
August 28, 2007 we and the Commonwealth of Kentucky filed
an appeal of the remand with the Kentucky Court of Appeals and
on September 24, 2007 the Court granted Kentuckys
motion to expedite the appeal. A decision on the appeal is
expected in 2008.
Clean
Coal Technology and Btu Conversion
Through our technology investments, we are taking a leading
position in advancing clean coal and Btu Conversion
technologies. We are involved in the following initiatives.
FutureGen
Industrial Alliance
We are a founding member of the FutureGen Industrial Alliance
(FutureGen), a non-profit company that is partnering with the
U.S. Department of Energy (DOE) to facilitate the design,
construction and operation of the worlds first near-zero
emissions coal-fueled power plant. In January 2008, DOE
announced plans to
15
reconfigure FutureGen as a project with multiple carbon capture
and storage sites, while some members of Congress argued in
favor of the original project.
GreenGen
In December 2007, we became the only non-Chinese equity partner
in GreenGen, a development-stage project in China to
build a near-zero emissions coal-fueled power plant with carbon
capture and storage. The US$1 billion GreenGen project is
expected to use advanced coal-based technologies to generate
electricity. It would be capable of hydrogen production and will
advance carbon dioxide capture and storage technologies.
Coal21
Fund
We have committed to contribute for a five-year period to the
Australian COAL21 Fund, which is a voluntary coal industry fund
to support clean coal technology demonstration projects and
research in Australia. All major coal companies in Australia
have committed to this fund. The Clean Coal Technology Special
Agreement Act 2007 (Queensland) provides that the amount
contributed in relation to Queensland production will be
expended on Queensland or National Clean Coal Technology
Projects. The Act establishes a Clean Coal Council to make
recommendations to the Premier on the Projects which should be
funded.
National
Clean Coal Fund
The Federal Labor Government has stated that it will establish a
$500 million Clean Coal Fund to develop clean coal
technologies in Australia. This includes funding for clean coal
research, a pilot coal gasification plant, the demonstration of
carbon capture and storage and a national carbon mapping and
infrastructure plan. We are not contributing to this fund.
Btu
Conversion
With the increase in U.S. demand for natural gas and oil
based commodities, we are determining how to best participate in
technologies to economically convert our coal resources to
natural gas as well as liquids such as diesel fuel, gasoline and
jet fuel. Our initiatives include:
|
|
|
|
|
An agreement with ConocoPhillips to explore development of a
commercial scale
coal-to-substitute
natural gas (SNG) facility in the Midwest;
|
|
|
|
A minority investment in GreatPoint Energy, Inc., which is
commercializing its proprietary
bluegastm
technology that converts coal, petroleum coke and biomass into
ultra-clean pipeline quality natural gas while enabling carbon
capture and storage;
|
|
|
|
An agreement to acquire a 30% interest in Econo-Power
International Corporation
(EPICtm),
which uses air-blown gasifiers to convert coal into a synthetic
gas that is ideal for industrial applications; and
|
|
|
|
A joint development agreement with Rentech, Inc. to evaluate
sites in the Midwest and Montana for
coal-to-liquids
projects that would transform coal into diesel and jet fuel
using Rentechs proprietary Fischer-Tropsch
coal-to-liquids
process.
|
Certain
Liabilities
We have long-term liabilities for reclamation (also called asset
retirement obligations), pensions and retiree health care. In
addition, one labor contract with the UMWA (the Western Surface
Agreement) and voluntary arrangements with non-union employees
include long-term benefits, notably health care coverage for
retired employees and future retirees and their dependents. The
majority of our existing liabilities relate to our past
operations, including operations spun-off with Patriot.
Asset Retirement Obligations. Asset retirement
obligations primarily represent the present value of future
anticipated costs to restore surface lands to productivity
levels equal to or greater than pre-mining conditions, as
required by applicable laws and regulations. Expense from
continuing operations (which includes liability accretion and
asset amortization) for the years ended December 31, 2007,
2006 and 2005
16
was $25.6 million, $15.8 million, and
$20.3 million, respectively. As of December 31, 2007,
our asset retirement obligations of $369.5 million included
$337.0 million related to locations with active mining
operations and $32.5 million related to locations that are
closed or inactive.
Pension-Related Provisions. Pension-related
costs represent the actuarially-estimated cost of pension
benefits. Annual minimum contributions to the pension plans are
determined by consulting actuaries based on the minimum funding
standards of the Employee Retirement Income Security Act of
1974, as amended (ERISA), and an agreement with the Pension
Benefit Guaranty Corporation (PBGC). Beginning on
January 1, 2008, new minimum funding standards will be
required by the Pension Protection Act of 2006. Net
pension-related liabilities were $45.8 million as of
December 31, 2007, $1.3 million of which was a current
liability. Expense for the years ended December 31, 2007,
2006 and 2005 was $19.6 million, $26.3 million and
$38.7 million, respectively.
Retiree Health Care. Consistent with Statement
of Financial Accounting Standard (SFAS) No. 106,
Employers Accounting for Postretirement Benefits
Other Than Pensions we record a liability representing the
estimated cost of providing retiree health care benefits to
current retirees and active employees who will retire in the
future. Provisions for active employees represent the amount
recognized to date, based on their service to date; additional
amounts are accrued periodically so that the total estimated
liability is accrued when the employee retires. Our retiree
health care liabilities were $855.8 million as of
December 31, 2007, $70.1 million of which was a
current liability. The Patriot spin-off reduced our health care
liabilities by $617.0 million. Health care expense related
to the spin-off of Patriot for the years ended December 31,
2007, 2006 and 2005 was $46.6 million, $41.4 million
and $35.4 million, respectively, and was included in
Discontinued operations.
Under the terms of the spin-off separation agreement, Patriot is
primarily liable for all obligations related to the Combined
Fund, 1992 Benefit Fund and 1993 Benefit Fund. The Combined Fund
and the 1992 Fund were created by federal law in 1992. These
multi-employer funds provide health care benefits to a class of
retirees who meet the statutory criteria. A third fund, the 1993
Benefit Fund, was established through collective bargaining and
provides certain retiree health care benefits. A portion of the
Combined Fund retirees was included within our Eastern
U.S. Mining operations business segment and became the
responsibility of Patriot in conjunction with the related
spin-off. The actuarially determined liability representing the
amounts anticipated to be due to the Combined Fund also became
the responsibility of Patriot in the spin-off and totaled
$38.4 million as of October 31, 2007. As of
December 31, 2006, this obligation was $30.8 million
and was reflected within liabilities of discontinued operations
in the consolidated balance sheets. Expense of
$2.7 million, $2.5 million and $0.9 million was
recognized related to the Combined Fund for the years ended
December 31, 2007, 2006 and 2005, respectively, and was
included in Discontinued operations.
The Surface Mining Control and Reclamation Act Amendments of
2006 (the 2006 Act) authorizes a specified amount of federal
funds to pay for these programs on a phased-in basis and other
programs. To the extent that (i) the annual retiree health
care funding requirement exceeds the specified amount of federal
funds, (ii) Congress does not allocate additional funds to
cover the shortfall, and (iii) Patriots subsidiaries
do not pay their share of the shortfall, some of our
subsidiaries would be responsible for the additional costs.
Employees
As of December 31, 2007, we had approximately
7,000 employees. As of such date, approximately 27% of our
hourly employees were represented by organized labor unions and
generated 10% of the 2007 coal production. Relations with our
employees and, where applicable, organized labor are important
to our success.
We opened training centers in the midwest and western regions of
the United States under our Workforce of the Future
initiative. Due to our current employee demographics, a
significant portion of our current hourly employees will retire
over the next decade. Our training centers are educating our
workforce, particularly our most recent hires, in our rigorous
safety standards, the latest in mining techniques and equipment,
and the centers disseminate mining best practices across all of
our operations. Our training efforts exceed minimum government
standards for safety and technical expertise with the intent of
developing and retaining a world-class workforce. Additionally,
we are implementing a supervisor training program through our
training centers
17
to develop both new and current supervisors, in an effort to
ensure the replenishment of our operating management workforce
over the next decade.
United
States Labor Relations
The UMWA, under the Western Surface Agreement, represented
approximately 6% of our U.S. subsidiaries hourly
employees, who generated 4% of our U.S. production during
the year ended December 31, 2007. An additional 7% of our
U.S. subsidiaries hourly employees are represented by
labor unions other than the UMWA. These employees generated 2%
of our U.S. production during the year ended
December 31, 2007. Hourly workers at our subsidiarys
operating mine in Arizona are represented by the UMWA under the
Western Surface Agreement, which is effective through
September 2, 2013. Hourly workers at our Willow Lake Mine
in Illinois are represented by the International Brotherhood of
Boilermakers under a labor agreement that was signed in 2007 and
that expires April 15, 2011.
Australia
Labor Relations
The Australian coal mining industry is unionized and the
majority of workers employed at our Australian Mining operations
are members of trade unions. The Construction Forestry Mining
and Energy Union represents our Australian subsidiarys
hourly production employees. As of December 31, 2007, our
Australian subsidiarys hourly employees were approximately
26% of our Australian hourly workforce and generated 29% of our
total Australian production in the year then ended. Our
remaining hourly workforce is employed through contract mining
relationships. The labor agreements at our Metropolitan Mine
were renewed in July and October 2007 and those agreements
expire in 2010. The Wambo mine coal handling plant labor
agreement is under negotiation and the North Goonyella Mine
operates under an agreement due to expire in March 2008.
Regulatory
Matters United States
Federal, state and local authorities regulate the U.S. coal
mining industry with respect to matters such as employee health
and safety, permitting and licensing requirements, air quality
standards, water pollution, plant and wildlife protection, the
reclamation and restoration of mining properties after mining
has been completed, the discharge of materials into the
environment, surface subsidence from underground mining and the
effects of mining on groundwater quality and availability. In
addition, the industry is affected by significant legislation
mandating certain benefits for current and retired coal miners.
Numerous federal, state and local governmental permits and
approvals are required for mining operations. We believe that we
have obtained all permits currently required to conduct our
present mining operations.
We endeavor to conduct our mining operations in compliance with
all applicable federal, state and local laws and regulations.
However, because of extensive and comprehensive regulatory
requirements, violations during mining operations occur from
time to time in the industry. None of the violations to date or
the monetary penalties assessed has been material.
Mine
Safety and Health
Our vision is to provide a workplace that is incident free. We
believe that it is our responsibility to our employees to
provide a superior safety and health environment. We seek to
implement this goal by: training employees in safe work
practices; openly communicating with employees; establishing,
following and improving safety standards; involving employees in
safety processes; and recording, reporting and investigating all
accidents, incidents and losses to avoid reoccurrence. A portion
of the annual performance incentives for our operating units is
tied to their safety performance.
Our safety performance in 2007, as measured by injury incidence
rates, was 35% better than the U.S. average for our
industry. During 2007, we achieved our vision of zero incidents
for the whole year at five of our facilities, which contributed
to our second best year ever in safety. We received multiple
safety awards during the year, including the Sentinels of Safety
at Farmersburg as the safest large surface coal mine in the
country. Our training centers educate our employees in safety
best practices and reinforce our company-wide belief that
productivity and profitability follow when safety is a
cornerstone of all of our operations.
18
Stringent health and safety standards have been in effect since
Congress enacted the Coal Mine Health and Safety Act of 1969.
The Federal 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. Congress enacted The Mine Improvement and New
Emergency Response Act of 2006 (The Miner Act) as a result of
the increase in fatal accidents primarily at
U.S. underground mines. Among the new requirements, each
miner must have at least two,
one-hour
Self Contained Self Rescue (SCSR) devices for their use in the
event of an emergency (each miner had at least one SCSR device
prior to The Miner Act) and additional caches of SCSRs in the
escape routes leading to the surface. Our progress in meeting
these requirements has continued, and we anticipate full
compliance with the new regulations in the first half of 2008 as
we await shipment of new materials. The Miner Act also requires
installation of wireless, two-way communication systems for
miners following an accident, and mine operators must have the
ability to locate each miners location at all times. Since
these technologies are not yet available, we are working with
the National Institute for Occupational Safety and Health and
several manufacturers to develop new systems.
Most of the states in which we operate have inspection programs
for mine safety and health. 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 U.S. industry.
Black
Lung
Under the Black Lung Benefits Revenue Act of 1977 and the Black
Lung Benefits Reform Act of 1977, as amended in 1981, each
U.S. coal mine operator must pay federal black lung
benefits and medical expenses to claimants who are current and
former employees and last worked for the operator after
July 1, 1973. Coal mine operators must also make payments
to a trust fund for the payment of benefits and medical expenses
to claimants who last worked in the coal industry prior to
July 1, 1973. Historically, less than 7% of the miners
currently seeking federal black lung benefits are awarded these
benefits. The trust fund is funded by an excise tax on
U.S. production of up to $1.10 per ton for deep-mined coal
and up to $0.55 per ton for surface-mined coal, neither amount
to exceed 4.4% of the gross sales price.
Environmental
Laws
We are subject to various federal and state environmental laws.
Some of these laws, discussed below, place many requirements on
our coal mining operations. Federal and state regulations
require regular monitoring of our mines and other facilities to
ensure compliance.
Surface
Mining Control and Reclamation Act
In the United States, the Surface Mining Control and Reclamation
Act of 1977 (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 U.S. surface mining as well as many aspects
of deep mining. Mine operators must obtain SMCRA permits and
permit renewals for mining operations from the OSM. Where state
regulatory agencies have adopted federal mining programs under
the act, the state becomes the regulatory authority. Except for
Arizona, states in which we have active mining operations have
achieved primary control of enforcement through federal
authorization. In Arizona, we mine on tribal lands and are
regulated by OSM because the tribes do not have SMCRA
authorization.
SMCRA permit provisions include requirements for coal
prospecting; mine plan development; topsoil removal, storage and
replacement; selective handling of overburden materials; mine
pit backfilling and grading; protection of the hydrologic
balance; subsidence control for underground mines; surface
drainage control; mine drainage and mine discharge control and
treatment; and re-vegetation.
The U.S. mining permit application process is initiated by
collecting baseline data to adequately characterize the pre-mine
environmental condition of the permit area. This work includes
surveys of cultural resources, soils, vegetation, wildlife,
assessment of surface and ground water hydrology, climatology
and wetlands. In conducting this work, we collect geologic data
to define and model the soil and rock structures and coal that
we will mine. We develop mine and reclamation plans by utilizing
this geologic data and
19
incorporating elements of the environmental data. The mine and
reclamation plan incorporates the provisions of SMCRA, the state
programs and the complementary environmental programs that
impact coal mining. Also included in the permit application are
documents defining ownership and agreements pertaining to coal,
minerals, oil and gas, water rights, rights of way and surface
land and documents required of the OSMs Applicant Violator
System.
Once a permit application is prepared and submitted to the
regulatory agency, it goes through a completeness and technical
review. Public notice of the proposed permit is given for a
comment period before a permit can be issued. Some SMCRA mine
permits take over a year to prepare, depending on the size and
complexity of the mine and often take six months to two years to
be issued. Regulatory authorities have considerable discretion
in the timing of the permit issuance and the public has the
right to comment on and otherwise engage in the permitting
process, including public hearings and through intervention in
the courts.
Before a SMCRA permit is issued, a mine operator must submit a
bond or other form of financial security to guarantee the
performance of reclamation obligations. The Abandoned Mine Land
Fund, which is part of SMCRA, requires a fee on all coal
produced in the U.S. The proceeds are used to rehabilitate
lands mined and left unreclaimed prior to August 3, 1977
and to pay health care benefit costs of orphan beneficiaries of
the Combined Fund. The fee is $0.35 per ton of surface-mined
coal and $0.15 per ton of deep-mined coal, effective through
September 30, 2007. Pursuant to the Tax Relief and Health
Care Act of 2006, from October 1, 2007 through
September 30, 2012, the fee will be $0.315 per ton of
surface-mined coal and $0.135 per ton of underground mined coal.
From October 1, 2012 through September 30, 2021, the
fee will be reduced to $0.28 per ton of surface-mined coal and
$0.12 per ton of underground mined coal.
SMCRA stipulates compliance with many other major environmental
programs. These programs include the Clean Air Act; Clean Water
Act; Resource Conservation and Recovery Act (RCRA); and
Comprehensive Environmental Response, Compensation, and
Liability Acts (CERCLA, commonly known as Superfund). Besides
OSM, other Federal regulatory agencies are involved in
monitoring or permitting specific aspects of mining operations.
The U.S. Environmental Protection Agency (EPA) is the lead
agency for States or Tribes with no authorized programs under
the Clean Water Act, RCRA and CERCLA. The U.S. Army Corps
of Engineers regulates activities affecting navigable waters and
the U.S. Bureau of Alcohol, Tobacco and Firearms (ATF)
regulates the use of explosive blasting.
We do not believe there are any matters that pose a material
risk to maintaining our existing mining permits or materially
hinder our ability to acquire future mining permits. It is our
policy to comply in all material respects with the requirements
of the SMCRA and the state and tribal laws and regulations
governing mine reclamation.
Clean
Air Act
The Clean Air Act and the corresponding state laws that regulate
the emissions of materials into the air affect U.S. coal
mining operations both directly and indirectly. Direct impacts
on coal mining and processing operations may occur through the
Clean Air Act permitting requirements
and/or
emission control requirements relating to particulate matter.
The Clean Air Act indirectly, but more significantly, affects
the coal industry by extensively regulating the air emissions of
sulfur dioxide, nitrogen oxide, mercury and other compounds
emitted by coal-based electricity generating plants.
The EPA promulgated the Clean Air Interstate Rule (CAIR) and the
Clean Air Mercury Rule (CAMR) in March 2005. CAIR requires
reduction of sulfur dioxide and nitrogen oxide emissions from
electricity generating plants in 28 states and the District
of Columbia. Substantial reductions in such emissions were
already made in 1995 and 2000 under requirements of
Title IV of the Clean Air Act. Once fully implemented over
two rounds in
2009-2010
and 2015, CAIR is projected to reduce sulfur dioxide from power
plants by approximately 73% and nitrogen oxide emissions by
approximately 61% from 2003 levels.
CAMR sought to permanently cap and reduce nationwide mercury
emissions from coal-fired power plants. When fully implemented
in 2018, the rule as promulgated would have reduced mercury
emissions by nearly 70% according to the EPA. CAMR contained
standards of performance limiting mercury emissions
20
from new and existing power plants and sought to create a
cap-and-trade
program. Some states have adopted rules that are more stringent
than the federal program and other states are considering such
rules.
On February 8, 2008, in a case brought by the State of New
Jersey and others against the EPA, the United States Court of
Appeals for the District of Columbia rendered a decision
effectively vacating CAMR. If the decision stands, the EPA will
have to revisit its standards regarding mercury emissions.
Implementation of CAIR, federal requirements regarding mercury
emissions and related state rules could cause our customers to
switch to other fuels to the extent it becomes economically
preferable for them to do so. CAIR is currently under review in
court on a number of grounds, including the assertion that the
regulations are insufficiently stringent.
In recent years Congress has considered legislation that would
require reductions in emissions of sulfur dioxide, nitrogen
oxide and mercury, greater and sooner than those required by
CAIR and CAMR. No such legislation has passed either house of
Congress. If enacted into law, such legislation could impact the
amount of coal supplied to electricity generating customers if
they decide to switch to other sources of fuel whose use would
result in lower emissions of sulfur dioxide, nitrogen oxide and
mercury.
In September 2006, the EPA promulgated new National Ambient Air
Quality Standards revising and updating the particulate matter
standards issued in July 1997. The new regulations made the
24-hour
standard for very fine particulate matter (PM2.5) more stringent
but left the annual PM2.5 standard unchanged. They also left the
24-hour
standard for PM10 (particulate matter equal to 10 microns or
more) unchanged and terminated the annual PM10 standard. The
change to the
24-hour
PM2.5 standard is expected to affect the use of coal for
electric generation, but we believe that effect cannot be
quantified at this time. Lawsuits seeking to compel the EPA to
adopt more stringent standards both for PM2.5 and PM10 have been
filed and are pending in court. We believe the outcome of those
lawsuits cannot be reliably predicted at this time. Under the
rule as currently promulgated, some states will be required to
change their existing implementation plans to attain and
maintain compliance with the new air quality standards. Our
mining operations and electricity generating customers are
likely to be directly affected when the revisions to the air
quality standards are implemented by the states. Such
implementation could also restrict our ability to develop new
mines or require us to modify our existing operations.
The Justice Department, on behalf of the EPA, has filed a number
of lawsuits since November 1999, alleging that a number of
electricity generators violated the new source review provisions
of the Clean Air Act Amendments (NSR) at power plants in the
midwestern and southern United States. Some electricity
generators announced settlements with the Justice Department
requiring the installation of additional control equipment on
selected generating units. If the remaining electricity
generators are found to be in violation, they could be subject
to civil penalties and could be required to install the required
control equipment or cease operations. In April 2007, the
U.S. Supreme Court ruled, in Environmental Defense v.
Duke Energy Corp., against a generator in an enforcement
proceeding, reversing the decision of the appellate court. This
decision could potentially expose numerous electricity
generators to government or citizen actions based on failure to
obtain NSR permits for changes to emissions sources and
effectively increase the costs to them of continuing to use
coal. Our customers are among the electricity generators subject
to enforcement actions and if found not to be in compliance, our
customers could be required to install additional control
equipment at the affected plants or they could decide to close
some or all of those plants. If our customers decide to install
additional pollution control equipment at the affected plants,
we believe we will have the ability to supply coal from the
regions in which we operate to meet any new coal requirements.
The U.S. Supreme Court ruled in April 2007 in a case
concerning the scope of the EPAs authority to regulate
carbon dioxide emissions as a pollutant under the
Clean Air Act. The decision, Massachusetts v. EPA, ruled in
the context of a petition to require the EPA to issue
regulations prescribing standards for carbon dioxide from new
motor vehicles, that the EPA does have such authority, and that
the EPAs rejection of the petition was based on
impermissible considerations. While the decision removes several
major arguments the EPA had used to decline to regulate carbon
dioxide emissions, it remains difficult to predict whether the
EPA will issue carbon dioxide regulations and, if so, when the
EPA will do so and the character of those regulations.
21
Clean
Water Act
The Clean Water Act of 1972 affects U.S. coal mining
operations by requiring effluent limitations and treatment
standards for waste water discharge through the National
Pollutant Discharge Elimination System (NPDES). Regular
monitoring, reporting requirements and performance standards are
requirements of NPDES permits that govern the discharge of
pollutants into water.
States are empowered to develop and enforce in
stream water quality standards. These standards are
subject to change and must be approved by the EPA. Discharges
must either meet state water quality standards or be authorized
through available regulatory processes such as alternate
standards or variances. In stream standards vary
from state to state. Additionally, through the Clean Water Act
section 401 certification program, states have approval
authority over federal permits or licenses that might result in
a discharge to their waters. States consider whether the
activity will comply with its water quality standards and other
applicable requirements in deciding whether or not to certify
the activity.
Section 404 under the Clean Water Act requires mining
companies to obtain U.S. Army Corps of Engineers permits to
place material in streams for the purpose of creating slurry
ponds, water impoundments, refuse areas, valley fills or other
mining activities. These permits have been the subject of
multiple recent court cases, the results of which may affect
permitting costs or result in permitting delays.
Total Maximum Daily Load (TMDL) regulations established a
process by which states designate stream segments as impaired
(not meeting present water quality standards). Industrial
dischargers, including coal mines, may be required to meet new
TMDL effluent standards for these stream segments. States are
also adopting anti-degradation regulations in which a state
designates certain water bodies or streams as high
quality/exceptional use. These regulations would restrict
the diminution of water quality in these streams. Waters
discharged from coal mines to high quality/exceptional use
streams may be required to meet additional conditions or provide
additional demonstrations
and/or
justification. In general, these Clean Water Act requirements
could result in higher water treatment and permitting costs or
permit delays, which could adversely affect our coal production
costs or efforts.
Resource
Conservation and Recovery Act
RCRA, which was enacted in 1976, affects U.S. coal mining
operations by establishing cradle to grave
requirements for the treatment, storage and disposal of
hazardous wastes. Typically, the only hazardous materials found
on a mine site are those contained in products used in vehicles
and for machinery maintenance. Coal mine wastes, such as
overburden and coal cleaning wastes, are not considered
hazardous waste materials under RCRA.
Subtitle C of RCRA exempted fossil fuel combustion wastes from
hazardous waste regulation until the EPA completed a report to
Congress and made a determination on whether the wastes should
be regulated as hazardous. In a 1993 regulatory determination,
the EPA addressed some high volume-low toxicity coal combustion
materials generated at electric utility and independent power
producing facilities. In May 2000, the EPA concluded that coal
combustion materials do not warrant regulation as hazardous
under RCRA. The EPA is retaining the hazardous waste exemption
for these materials. The EPA is evaluating national
non-hazardous waste guidelines for coal combustion materials
placed at a mine. National guidelines for mine-fills may affect
the cost of ash placement at mines.
CERCLA
(Superfund)
CERCLA affects U.S. coal mining and hard rock operations by
creating liability for investigation and remediation in response
to releases of hazardous substances into the environment and for
damages to natural resources. Under Superfund, joint and several
liabilities may be imposed on waste generators, site owners or
operators and others regardless of fault. Under the EPAs
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.
22
The
Energy Policy Act of 2005
The Domenici-Barton Energy Policy Act of 2005 (EPACT) was signed
by President Bush in August 2005. EPACT contains tax incentives
and directed spending totaling an estimated $14.1 billion
intended to stimulate supply-side energy growth and increased
efficiency. In addition to rules affecting the leasing process
of federal coal properties, EPACT programs and incentives
include funding to demonstrate advanced coal technologies,
including coal gasification; grants and a loan guarantee program
to encourage deployment of advanced clean coal-based power
generation technologies, including integrated gasification
combined cycle (IGCC); a federal loan guarantee program for the
cost of advanced fossil energy projects, including coal
gasification; funding for energy research, development,
demonstration and commercial application programs relating to
coal and power systems; and tax incentives for IGCC, industrial
gasification and other advanced coal-based generation projects,
as well as for coal sold from Indian lands. Finally, certain
sections of EPACT are potentially applicable to the area of Btu
Conversion, such as the aforementioned fossil energy project
loan guarantee program as well as a provision allowing taxpayers
to capitalize 50% of the cost of refinery investments which
increase the total throughput of qualified fuels
including synthetic fuels produced from coal by at
least 25%. In addition, EPACT requires the Secretary of Defense
to develop a strategy to use fuel produced from coal, oil shale
and tar sands (covered fuel) to assist in meeting the fuel
requirements of the U.S. Department of Defense (DOD). The
law authorizes the DOD to enter into multi-year contracts to
procure a covered fuel to meet one or more of its fuel
requirements and to carry out an assessment of potential
locations for covered fuel sources.
Regulatory
Matters Australia
The Australian mining industry is regulated by Australian
federal, state and local governments with respect to
environmental issues such as land reclamation, water quality,
air quality, dust control, noise, planning issues (such as
approvals to expand existing mines or to develop new mines), and
health and safety issues. The Australian federal government
retains control over the level of foreign investment and export
approvals. Industrial relations are regulated under both federal
and state laws. Australian state governments also require coal
companies to post deposits or give other security against land
which is being used for mining, with those deposits being
returned or security released after satisfactory reclamation is
completed.
Native
Title and Cultural Heritage
Since 1992, the Australian courts have recognized that native
title to lands, as recognized under the laws and customs of the
Aboriginal inhabitants of Australia, may have survived the
process of European settlement. These developments are supported
by the Federal Native Title Act (NTA) which recognizes and
protects native title, and under which a national register of
native title claims has been established.
Native title rights do not extend to minerals; however, native
title rights can be affected by the mining process unless those
rights have previously been extinguished. Native title rights
can be extinguished either by a valid act of Government (as set
out in the NTA) or by the loss of connection between the land
and the group of Aboriginal peoples concerned.
The NTA provides that where native title rights still exist and
the mining project will affect those native title rights, it
will be necessary to consult with the relevant Aboriginal group
and to come to an agreement on issues such as the preservation
of sacred or important sites, the employment of members of the
group by the mine operator, and the payment of compensation for
the effect on native title of the mining project. In the absence
of agreement with the relevant Aboriginal group, there is an
arbitration provision in the NTA.
There is also federal and state legislation to prevent damage to
Aboriginal cultural heritage and archeological sites. The NTA
and laws protecting Aboriginal cultural heritage and
archeological sites have had no impact on our current operations.
23
Environmental
The federal system requires that approval is obtained for any
activity which will have a significant impact on a matter of
national environmental significance. Matters of national
environmental significance include listed endangered species,
nuclear actions, World Heritage areas, National Heritage areas,
and migratory species. An application for such an approval may
require public consultation and may be approved, refused or
granted subject to conditions. Otherwise, responsibility for
environmental regulation in Australia is primarily vested in the
states.
Each state and territory in Australia has its own environmental
and planning regime for the development of mines. In addition,
each state and territory also has a specific act dealing with
mining in particular, regulating the granting of mining licenses
and leases. The mining legislation in each state and territory
operates concurrently with environmental and planning
legislation. The mining legislation governs mining licenses and
leases, including the restoration of land following the
completion of mining activities. Apart from the grant of rights
to mine (which are covered by the mining statutes), all
licensing, permitting, consent and approval requirements are
contained in the various state and territory environmental and
planning statutes.
The particular provisions of the various state and territory
environmental and planning statutes vary depending upon the
jurisdiction. Despite variation in details, each state and
territory has a system involving at least two major phases.
First, obtaining the developmental application and, if that is
granted, obtaining the detailed operational pollution control
licenses, which authorize emissions up to a maximum level; and
second, obtaining pollution control approvals, which authorize
the installation of pollution control equipment and devices. In
the first regulatory phase, an application to a regulatory
authority is filed. The relevant authority will either grant a
conditional consent, an unconditional consent, or deny the
application based on the details of the application and on any
submissions or objections lodged by members of the public. If
the developmental application is granted, the detailed pollution
control license may then be issued and such license may regulate
emissions to the atmosphere; emissions in waters; noise impacts,
including impacts from blasting; dust impacts; the generation,
handling, storage and transportation of waste; and requirements
for the rehabilitation and restoration of land.
Each state and territory in Australia also has either a specific
statute or certain sections in other environmental and planning
statutes relating to the contamination of land and vesting
powers in the various regulatory authorities in respect of the
remediation of contaminated land. Those statutes are based on
varying policies the primary difference between the
statutes is that in certain states and territories, liability
for remediation is placed upon the occupier of the land,
regardless of the culpability of that occupier for the
contamination. In other states and territories, primary
liability for remediation is placed on the original polluter,
whether or not the polluter still occupies the land. If the
original polluter cannot itself carry out the remediation, then
a number of the statutes contain provisions which enable
recovery of the costs of remediation from the polluter as a debt.
Many of the environmental planning statutes across the states
and territories contain third-party appeal rights in
relation, particularly, to the first regulatory phase. This
means that any party has a right to take proceedings for a
threatened or actual breach of the statute, without first having
to establish that any particular interest of that person (other
than as a member of the public) stands to be affected by the
threatened or actual breach.
Accordingly, in most states and territories throughout
Australia, mining activities involve a number of regulatory
phases. Following exploratory investigations pursuant to a
mining lease, the activity proposed to be carried out must be
the subject of an application for the activity or development.
This phase of the regulatory process, as noted above, usually
involves the preparation of extensive documents to constitute
the application, addressing all of the environmental impacts of
the proposed activity. It also generally involves extensive
notification and consultation with other relevant statutory
authorities and members of the public. Once a decision is made
to allow a mine to be developed by the grant of a development
consent, permit or other approval, then a formal mining lease
can be obtained under the mining statute. In addition,
operational licenses and approvals can then be applied for and
obtained in relation to pollution control devices and emissions
to the atmosphere, to waters and for noise. The obtaining of
licenses and approvals, during the operational phase,
24
generally does not involve any extensive notification or
consultation with members of the public, as most of these issues
are anticipated to be resolved in the first regulatory phase.
Occupational
Health and Safety
The combined effect of various state and federal statutes
requires an employer to ensure that persons employed in a mine
are safe from injury by providing a safe working environment and
systems of work; safety machinery; equipment, plant and
substances; and appropriate information, instruction, training
and supervision.
In recognition of the specialized nature of mining and mining
activities, specific occupational health and safety obligations
have been mandated under state legislation that deals
specifically with the coal mining industry. Mining employers,
owners, directors and managers, persons in control of work
places, mine managers, supervisors and employees are all subject
to these duties.
It is mandatory for an employer to have insurance coverage with
respect to the compensation of injured workers; similar coverage
is in effect throughout Australia which is of a no fault nature
and which provides for benefits up to a prescribed level. The
specific benefits vary from jurisdiction to jurisdiction, but
generally include the payment of weekly compensation to an
incapacitated employee, together with payment of medical,
hospital and related expenses. The injured employee has a right
to sue his or her employer for further damages if a case of
negligence can be established.
National
Greenhouse and Energy Reporting Act 2007 (NGER
Act)
The NGER Act introduces a single national reporting system
relating to greenhouse gas emissions and energy production and
consumption, which will underpin a future emissions trading
scheme.
The NGER Act imposes requirements for certain corporations to
report greenhouse gas emissions and abatement actions, as well
as energy production and consumption, beginning July 1,
2008. Both foreign and local corporations that meet the
prescribed
CO2
and energy production of consumption limits in Australia
(controlling corporations) must comply with the NGER Act.
In the first reporting year,
2008-09, a
controlling corporation must register in the National Greenhouse
and Energy Register if its corporate group emits a carbon
dioxide equivalent of 125 kilotonnes or more. This threshold is
reduced progressively in the following reporting years. Once
registered, a corporation must report each financial year about
its greenhouse gas emissions and energy production and
consumption.
Kyoto
Protocol
The Federal Labor Government, which came to power in November
2007, ratified the Kyoto Protocol on December 3, 2007, with
the ratification to come into force in March 2008. Under the
treaty, Australia has a target of restricting greenhouse gas
emissions to 108% of 1990 levels during the
2008-2012
commitment period. It is likely that Australia will not meet its
target (current projected Australian emissions in 2010 will be
109% of 1990 levels). This may result in legislated restrictions
on
CO2
emissions before 2010, which could affect our Australian
customers.
Ratification of the treaty will also allow Australian companies
to begin participating in the Kyoto Protocol trading system
(CDMs etc). Other Labor Government policies include committing
to a target of reducing greenhouse gas emissions by 60% by 2050,
and setting a 20% renewable energy target by 2020.
Future
Cap and Trade System
The Federal Labor Government has announced that it will
establish a cap and trade emissions trading scheme by 2010.
Under such a system, total emissions will be capped,
permits allocated up to the cap, and trading will allow the
market to find the cheapest way to meet the cap. The Australian
Securities Exchange has announced that it will facilitate
emissions trading in a futures market for carbon emission
permits at the earliest opportunity.
25
Global
Climate Change
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. In
turn, considerable and increasing government 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.
Legislation was introduced in Congress in 2006 and 2007 to
reduce greenhouse gas emissions in the United States, and
additional legislation is likely to be introduced in the future.
Presently there are no federal mandatory greenhouse gas
reduction requirements. While it is possible that Congress will
adopt some form of mandatory greenhouse gas emission reduction
legislation in the future, the timing and specific requirements
of any such legislation are highly uncertain.
The U.S. Supreme Courts recent decision in
Massachusetts v. EPA 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.
A number of states in the United States have taken steps to
regulate greenhouse gas emissions. For example, 10 northeastern
states (Connecticut, Delaware, Maine, Maryland, Massachusetts,
New Hampshire, New Jersey, New York, Rhode Island and Vermont)
have formed the Regional Greenhouse Gas Initiative (RGGI), which
is a mandatory
cap-and-trade
program to reduce carbon dioxide emissions from power plants.
Seven western states (Arizona, California, Montana, New Mexico,
Oregon, Utah and Washington) and two Canadian provinces have
entered into the Western Climate Initiative to establish a
regional greenhouse gas reduction goal and develop market-based
strategies to achieve emissions reductions. In 2006, the
California legislature approved legislation allowing the
imposition of statewide caps on, and cuts in, carbon dioxide
emissions; and Arizonas governor signed an executive order
in September 2006 that calls for the state to reduce carbon
dioxide emissions. Similar legislation was adopted in 2007 in
Hawaii and New Jersey.
In December 1997, in Kyoto, Japan, the signatories to the 1992
Framework Convention on Climate Change, which addresses
emissions of greenhouse gases, established a binding set of
emission targets for developed nations. The United States has
signed the Kyoto Protocol, but it has not been ratified by the
U.S. Senate and the Bush Administration has withdrawn
support for this treaty. As noted previously, Australia ratified
the Kyoto Protocol in December 2007 and will become a full
member in March 2008.
We continue to support clean coal technology development and
voluntary initiatives addressing global climate change through
our participation as a founding member of the FutureGen Alliance
and through our participation in the Power Systems Development
Facility, the PowerTree Carbon Company LLC, and the Asia-Pacific
Partnership for Clean Development and Climate. In addition, we
are the only non-Chinese equity partner in GreenGen, the first
near-zero emissions coal-fueled power plant with carbon capture
and storage (CCS) which is under development in China.
Enactment of laws and passage of regulations regarding
greenhouse gas emissions by the United States or some of its
states or by other countries, or other actions to limit carbon
dioxide emissions, could result in electric generators switching
from coal to other fuel sources.
Additional
Information
We file annual, quarterly and current reports, and our
amendments to those reports, proxy statements and other
information with the Securities and Exchange Commission (SEC).
You may access and read our SEC filings free of charge through
our website, at www.peabodyenergy.com, or the SECs
website, at www.sec.gov. Information on such websites does not
constitute part of this document. You may also read and copy any
document we file at the SECs public reference room located
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.
26
You may also request copies of our filings, free of charge, by
telephone at
(314) 342-3400
or by mail at: Peabody Energy Corporation, 701 Market Street,
Suite 900, St. Louis, Missouri 63101, attention:
Investor Relations.
The risk factors discussed herein relate specifically to the
risks associated with our continuing operations.
We may
not be able to achieve some or all of the strategic objectives
that we expected to achieve in connection with the spin-off of
Patriot Coal Corporation in October 2007.
We may not be able to completely achieve the financial and
strategic objectives of our spin-off of Patriot Coal Corporation
or such objectives may be delayed in their realization if they
ever occur.
If a
substantial portion of our long-term coal supply agreements
terminate, our revenues and operating profits could suffer if we
are unable to find alternate buyers willing to purchase our coal
on comparable terms to those in our contracts.
Most of our sales are made under coal supply agreements, which
are important to the stability and profitability of our
operations. The execution of a satisfactory coal supply
agreement is frequently the basis on which we undertake the
development of coal reserves required to be supplied under the
contract. For the year ended December 31, 2007, 94% of our
sales volume was sold under long-term coal supply agreements. At
December 31, 2007, our sales backlog, including backlog
subject to price reopener and/or extension provisions, was
nearly one billion tons, representing more than four years of
current production in backlog. Contracts in backlog have
remaining terms ranging from one to 17 years.
Many of our coal supply agreements contain provisions that
permit the parties to adjust the contract price upward or
downward at specified times. We may adjust these contract prices
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. We sometimes experience a reduction in
coal prices in new long-term coal supply agreements replacing
some of our expiring contracts. 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. Moreover, some of these agreements permit the
customer to terminate the contract if transportation costs,
which our customers typically bear, increase substantially. In
addition, some of these contracts allow our customers to
terminate their contracts in the event of changes in regulations
affecting our industry that increase the price of coal beyond
specified limits.
The operating profits we realize from coal sold under supply
agreements depend on a variety of factors. In addition, price
adjustment and other provisions may increase our exposure to
short-term coal price volatility provided by those contracts. If
a substantial portion of our coal supply agreements were
modified or terminated, we could be materially adversely
affected to the extent that we are unable to find alternate
buyers for our coal at the same level of profitability. Market
prices for coal vary by mining region and country. As a result,
we cannot predict the future strength of the coal market overall
or by mining region and cannot assure you that we will be able
to replace existing long-term coal supply agreements at the same
prices or with similar profit margins when they expire. In
addition, one of our largest coal supply agreements is the
subject of ongoing litigation and arbitration.
27
The
loss of, or significant reduction in, purchases by our largest
customers could adversely affect our revenues.
For the year ended December 31, 2007, we derived 23% of our
total coal revenues from sales to our five largest customers. At
December 31, 2007, we had 125 coal supply agreements and
trading transactions with these customers expiring at various
times from 2008 to 2014. We are currently discussing the
extension of existing agreements or entering into new long-term
agreements with some of these customers, but these negotiations
may not be successful and those customers may not continue to
purchase coal from us under long-term coal supply agreements. If
a number of these customers significantly reduce their purchases
of coal from us, or if we are unable to sell coal to them on
terms as favorable to us as the terms under our current
agreements, our financial condition and results of operations
could suffer materially.
If
transportation for our coal becomes unavailable or uneconomic
for our customers, our ability to sell coal could
suffer.
Transportation costs represent a significant portion of the
total cost of coal and the cost of transportation is a critical
factor in a customers purchasing decision. Increases in
transportation costs and the lack of sufficient rail and port
capacity could lead to reduced coal sales. As of
December 31, 2007, certain coal supply agreements, which
account for less than 5% of our tons sold, permit the customer
to terminate the contract if the cost of transportation
increases by an amount over specified levels in any given
12-month
period.
Coal producers depend upon rail, barge, trucking, overland
conveyor and ocean-going vessels to deliver coal to markets.
While our coal customers typically arrange and pay for
transportation of coal from the mine or port to the point of
use, disruption of these transportation services because of
weather-related problems, infrastructure damage, strikes,
lock-outs, lack of fuel or maintenance items, transportation
delays or other events could temporarily impair our ability to
supply coal to our customers and thus could adversely affect our
results of operations. For example, two primary railroads serve
the Powder River Basin mines. Due to the high volume of coal
shipped from all Powder River Basin mines, the loss of access to
rail capacity could create temporary congestion on the rail
systems servicing that region. In Australia we currently ship
coal through the ports of Dalrymple Bay, Gladstone, Brisbane,
Newcastle and Port Kembla. In most instances, we rail coal to
these ports. The Australian coal supply chains (rail and port)
can be impacted by a number of factors including weather events,
breakdown or underperformance of the port and rail
infrastructure, congestion and balancing systems which are
imposed to manage vessel queuing and demurrage. We are also
susceptible to increased costs or lost sales due to Australian
coal chain problems. In 2007, we experienced high demurrage
costs (fees paid to third-party shipping companies for loading
time that exceeded the stipulated time) and increased vessel
wait times due to these problems and the high demand for
Australian coal.
Risks
inherent to mining could increase the cost of operating our
business.
Our mining operations are subject to conditions that can impact
the safety of our workforce, or delay coal deliveries or
increase the cost of mining at particular mines for varying
lengths of time. These conditions include fires and explosions
from methane gas or coal dust; accidental minewater discharges;
weather, flooding and natural disasters; unexpected maintenance
problems; key equipment failures; variations in coal seam
thickness; variations in the amount of rock and soil overlying
the coal deposit; variations in rock and other natural materials
and variations in geologic conditions. We maintain insurance
policies that provide limited coverage for some of these risks,
although there can be no assurance that these risks would be
fully covered by our insurance policies. Despite our efforts,
significant mine accidents could occur and have a substantial
impact.
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.
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
28
Change, have also engendered widespread concern about the
impacts of human activity, especially fossil fuel combustion, on
global climate change. In turn, considerable and increasing
government 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. Legislation
was introduced in Congress in 2006 and 2007 to reduce greenhouse
gas emissions in the United States and additional legislation 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
U.S. Supreme Courts recent decision in
Massachusetts v. EPA 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.
Concerns about other adverse environmental effects from coal
combustion have also led to increased regulation. For example,
in the United States, CAIR and CAMR, both issued by the EPA in
March 2005, impose increasingly stringent requirements on
coal-fired power plants in order to reduce emissions of sulfur
dioxide, nitrogen oxide, and mercury. Each of the regulations
takes effect in two phases, the first phase requiring certain
reductions in overall emissions by
2009-10, the
second requiring additional reductions in overall emissions by
2015 under CAIR and 2018 under CAMR. Both rules have been the
subject of legal challenges by environmental advocacy groups
that seek larger cuts sooner. On February 2, 2008, the
Court of Appeals for the District of Columbia rendered a
decision effectively vacating CAMR. If the decision stands, the
EPA will have to revisit its standards regarding mercury
emissions. Some states have independently established
requirements imposing larger cuts sooner. Such requirements, in
varying degrees, increase the costs of coal utilization for our
customers and our prospective customers.
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 results of operations, cash flows
and financial condition.
Our
mining operations are extensively regulated, which imposes
significant costs on us, and future regulations and developments
could increase those costs or limit our ability to produce
coal.
Federal, state and local authorities regulate the coal mining
industry with respect to matters such as employee health and
safety, permitting and licensing requirements, air quality
standards, water pollution, plant and wildlife protection,
reclamation and restoration of mining properties after mining is
completed, the discharge of materials into the environment,
surface subsidence from underground mining and the effects that
mining has on groundwater quality and availability. Numerous
governmental permits and approvals are required for mining
operations. We are required to prepare and present to federal,
state or local authorities data pertaining to the effect or
impact that any proposed exploration for or production of coal
may have upon the environment. The costs, liabilities and
requirements associated with these regulations may be costly and
time-consuming and may delay commencement or continuation of
exploration or production. The possibility exists that new
legislation
and/or
regulations and orders related to the environment or employee
health and safety may be adopted and may materially adversely
affect our mining operations, our cost structure
and/or our
customers ability to use coal. New legislation or
administrative regulations (or judicial interpretations of
existing laws and regulations), including proposals related to
the protection of the environment that would further regulate
and tax the coal industry, may also require us or our customers
to change operations significantly or incur increased costs.
Some 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
purchasers plant or results in specified increases in the
cost of coal or its use. These factors and legislation, if
enacted, could have a material adverse effect on our financial
condition and results of operations.
29
A number of laws, including in the U.S. the Comprehensive
Environmental Response, Compensation and Liability Act (CERCLA
or Superfund), impose liability relating to contamination by
hazardous substances. Such liability may involve the costs of
investigating or remediating contamination and damages to
natural resources, as well as claims seeking to recover for
property damage or personal injury caused by hazardous
substances. Such liability may arise from conditions at formerly
as well as currently owned or operated properties, and at
properties to which hazardous substances have been sent for
treatment, disposal, or other handling. Liability under CERCLA
and similar state statutes is without regard to fault, and
typically is joint and several, meaning that a person may be
held responsible for more than its share, or even all of, the
liability involved. Our mining operations involve some use of
hazardous materials. In addition, we have accrued for liability
arising out of contamination associated with Gold Fields Mining,
LLC (Gold Fields), a dormant, non-coal-producing subsidiary of
ours that was previously managed and owned by Hanson PLC, or
with Gold Fields former affiliates. A predecessor owner of
ours, Hanson PLC transferred ownership of Gold Fields to us in
the February 1997 spin-off of its energy business. Gold Fields
is currently a defendant in several lawsuits and has received
notices of several other potential claims arising out of lead
contamination from mining and milling operations it conducted in
northeastern Oklahoma. Gold Fields is also involved in
investigating or remediating a number of other contaminated
sites. Although we have accrued for many of these liabilities
known to us, the amounts of other potential losses cannot be
estimated. Significant uncertainty exists as to whether claims
will be pursued against Gold Fields in all cases, and where they
are pursued, the amount of the eventual costs and liabilities,
which could be greater or less than our accrual. Although we
believe many of these liabilities are likely to be resolved
without a material adverse effect on us, future developments,
such as new information concerning areas known to be or
suspected of being contaminated for which we may be responsible,
the discovery of new contamination for which we may be
responsible, or the inability to share costs with other parties
that may be responsible for the contamination, could have a
material adverse effect on our financial condition or results of
operations.
Our
expenditures for postretirement benefit and pension obligations
could be materially higher than we have predicted if our
underlying assumptions prove to be incorrect.
We provide postretirement health and life insurance benefits to
eligible union and non-union employees. We calculated the total
accumulated postretirement benefit obligation under
SFAS No. 106, Employers Accounting for
Postretirement Benefits Other Than Pensions, which we
estimate had a present value of $855.8 million as of
December 31, 2007, $70.1 million of which was a
current liability. We have estimated these unfunded obligations
based on assumptions described in the notes to our consolidated
financial statements. If our assumptions do not materialize as
expected, cash expenditures and costs that we incur could be
materially higher. Moreover, regulatory changes or changes to
Medicare benefit levels could increase our obligations to
provide these or additional benefits.
We are party to an agreement with the PBGC and TXU Europe
Limited, an affiliate of our former parent corporation, under
which we are required to make specified contributions to two of
our defined benefit pension plans and to maintain a
$37.0 million letter of credit in favor of the PBGC. If we
or the PBGC give notice of an intent to terminate one or more of
the covered pension plans in which liabilities are not fully
funded, or if we fail to maintain the letter of credit, the PBGC
may draw down on the letter of credit and use the proceeds to
satisfy liabilities under the Employment Retirement Income
Security Act of 1974, as amended. The PBGC, however, is required
to first apply amounts received from a $110.0 million
guaranty in place from TXU Europe Limited in favor of the PBGC
before it draws on our letter of credit. On November 19,
2002, TXU Europe Limited was placed under the administration
process in the United Kingdom (a process similar to bankruptcy
proceedings in the United States) and continues under this
process as of December 31, 2007.
The United Mine Workers of America Combined Fund was created by
federal law in 1992. This multi-employer fund provides health
care benefits to a closed group of retirees including retired
employees of our former subsidiaries (now owned by Patriot Coal
Corporation) who last worked prior to 1976, as well as orphaned
beneficiaries of bankrupt companies who were receiving benefits
as orphans prior to the 1992 law.
30
No new retirees will be added to this group. The liability is
subject to increases or decreases in per capita health care
costs, offset by the mortality curve in this aging population of
beneficiaries. Another fund, the 1992 Benefit Plan created by
the same federal law in 1992, provides benefits to qualifying
retired former employees of bankrupt companies who have
defaulted in providing their former employees with retiree
medical benefits. Beneficiaries continue to be added to this
fund as employers default in providing their former employees
with retiree medical benefits, but the overall exposure for new
beneficiaries into this fund is limited to retirees covered
under their employers plan who retired prior to
October 1, 1994. A third fund, the 1993 Benefit Plan, was
established through collective bargaining and provides benefits
to qualifying retired former employees who retired after
September 30, 1994 of certain signatory companies who have
gone out of business and have defaulted in providing their
former employees with retiree medical benefits. Beneficiaries
continue to be added to this fund as employers go out of
business.
The Surface Mining Control and Reclamation Act Amendments of
2006 (the 2006 Act) authorizes a specified amount of federal
funds to pay for these programs on a phased-in basis and other
programs. To the extent that (i) the annual retiree health
care funding requirement exceeds the specified amount of federal
funds, (ii) Congress does not allocate additional funds to
cover the shortfall, and (iii) Patriots subsidiaries
do not pay for their share of the shortfall, some of our
subsidiaries would be responsible for the additional costs.
A
decrease in the availability or increase in costs of key
supplies, capital equipment or commodities such as diesel fuel,
steel, explosives and tires could decrease our anticipated
profitability.
Our mining operations require a reliable supply of replacement
parts, explosives, fuel, tires, steel-related products
(including roof control) and lubricants. If the cost of any of
these inputs increased significantly, or if a source for these
supplies or mining equipment were unavailable to meet our
replacement demands, our profitability could be reduced from our
current expectations. Recent consolidation of suppliers of
explosives has limited the number of sources for these
materials, and our current supply of explosives is concentrated
with one supplier. Further, our purchases of some items of
underground mining equipment are concentrated with one principal
supplier. Over the past few years, industry-wide demand growth
has exceeded supply growth for certain surface and underground
mining equipment and other capital equipment as well as
off-the-road
tires. As a result, lead times for some items have increased
significantly.
Our
future success depends upon our ability to continue acquiring
and developing coal reserves that are economically
recoverable.
Our recoverable reserves decline as we produce coal. We have not
yet applied for the permits required or developed the mines
necessary to use all of our reserves. Furthermore, we may not be
able to mine all of our reserves as profitably as we do at our
current operations. Our future success depends upon our
conducting successful exploration and development activities or
acquiring properties containing economically recoverable
reserves. Our current strategy includes increasing our reserves
through acquisitions of government and other leases and
producing properties and continuing to use our existing
properties. The federal government also leases natural gas and
coalbed methane reserves in the West, including in the Powder
River Basin. Some of these natural gas and coalbed methane
reserves are located on, or adjacent to, some of our Powder
River Basin reserves, potentially creating conflicting interests
between us and lessees of those interests. Other lessees
rights relating to these mineral interests could prevent, delay
or increase the cost of developing our coal reserves. These
lessees may also seek damages from us based on claims that our
coal mining operations impair their interests. Additionally, the
federal government limits the amount of federal land that may be
leased by any company to 150,000 acres nationwide. As of
December 31, 2007, we leased a total of 63,463 acres
from the federal government. The limit could restrict our
ability to lease additional federal lands. For additional
discussion of our federal leases see Item 2. Properties.
Our planned mine development projects and acquisition activities
may not result in significant additional reserves, and we may
not have continuing success developing additional mines. Most of
our mining operations are conducted on properties owned or
leased by us. Because title to most of our leased properties and
mineral rights are not thoroughly verified until a permit to
mine the property is obtained, our right to mine some of our
reserves may be materially adversely affected if defects in
title or boundaries exist. In addition, in order to
31
develop our reserves, we must receive various governmental
permits. We cannot predict whether we will continue to receive
the permits necessary for us to operate profitably in the
future. We may not be able to negotiate new leases from the
government or from private parties, obtain mining contracts for
properties containing additional reserves or maintain our
leasehold interest in properties on which mining operations are
not commenced during the term of the lease. From time to time,
we have experienced litigation with lessors of our coal
properties and with royalty holders.
A
decrease in our production of metallurgical coal could decrease
our anticipated profitability.
We have annual capacity to produce approximately 8 to
10 million tons of metallurgical coal. Prices for
metallurgical coal at the end of 2007 were near historically
high levels. As a result, our margins from these sales have
increased significantly, and represented a larger percentage of
our overall revenues and profits and are expected to continue to
favorably contribute in the future. To the extent we experience
either production or transportation difficulties that impair our
ability to ship metallurgical coal to our customers at
anticipated levels, our profitability could be reduced in 2008.
The majority of our 2008 metallurgical coal production will be
priced during the first quarter of 2008. As a result, a decrease
in logistics or port capacity could decrease our profitability.
Our
financial performance could be adversely affected by our
debt.
Our financial performance could be affected by our indebtedness.
As of December 31, 2007, our total indebtedness was
$3.27 billion, and we had $1.29 billion of available
borrowing capacity under our Revolving Credit Facility. The
indentures governing our convertible debentures and 7.375% and
7.875% Senior Notes do not limit the amount of indebtedness
that we may issue, and the indentures governing our 6.875% and
5.875% Senior Notes permit the incurrence of additional
indebtedness.
The degree to which we are leveraged could have important
consequences, including, but not limited to:
|
|
|
|
|
making it more difficult for us to pay interest and satisfy our
debt obligations;
|
|
|
|
increasing our vulnerability to general adverse economic and
industry conditions;
|
|
|
|
requiring the dedication of a substantial portion of our cash
flow from operations to the payment of principal, and interest
on, our indebtedness, thereby reducing the availability of our
cash flow to fund working capital, capital expenditures,
acquisitions, research and development or other general
corporate uses;
|
|
|
|
limiting our ability to obtain additional financing to fund
future working capital, capital expenditures, acquisitions,
research and development or other general corporate requirements;
|
|
|
|
limiting our flexibility in planning for, or reacting to,
changes in our business and in the coal industry; and
|
|
|
|
placing us at a competitive disadvantage compared to less
leveraged competitors.
|
In addition, our indebtedness subjects us to financial and other
restrictive covenants. Failure by us to comply with these
covenants could result in an event of default that, if not cured
or waived, could have a material adverse effect on us.
If our cash flows and capital resources are insufficient to fund
our debt service obligations, we may be forced to sell assets,
seek additional capital or seek to restructure or refinance our
indebtedness. These alternative measures may not be successful
and may not permit us to meet our scheduled debt service
obligations. In the absence of such operating results and
resources, we could face substantial liquidity problems and
might be required to sell material assets or operations to
attempt to meet our debt service and other obligations. The
Senior Unsecured Credit Facility and indentures governing
certain of our notes restrict our ability to sell assets and use
the proceeds from the sales. We may not be able to consummate
those sales or to obtain the proceeds which we could realize
from them and these proceeds may not be adequate to meet any
debt service obligations then due.
32
The
covenants in our senior unsecured credit facility and the
indentures governing our senior notes and convertible debentures
impose restrictions that may limit our operating and financial
flexibility.
Our Senior Unsecured Credit Facility, the indentures governing
our senior notes and convertible debentures and the instruments
governing our other indebtedness contain certain restrictions
and covenants which restrict our ability to incur liens and debt
or provide guarantees in respect of obligations of any other
person. Under our Senior Unsecured Credit Facility, we must
comply with certain financial covenants on a quarterly basis
including a minimum interest coverage ratio and a maximum
leverage ratio, as defined. The financial covenants also place
limitations on our investments in joint ventures, unrestricted
subsidiaries, indebtedness of non-loan parties and the
imposition of liens on our assets. These covenants and
restrictions are reasonable and customary and have not impacted
our business in the past.
Operating results below current levels or other adverse factors,
including a significant increase in interest rates, could result
in our inability to comply with the financial covenants
contained in our Senior Unsecured Credit Facility. 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 our lenders. If our indebtedness is
accelerated, we may not be able to repay our debt or borrow
sufficient funds to refinance it. Even if we are able to obtain
new financing, it may not be on commercially reasonable terms,
on terms that are acceptable to us or at all. If our debt is in
default for any reason, our business, financial condition and
results of operations could be materially and adversely
affected. In addition, complying with these covenants may also
cause us to take actions that are not favorable to holders of
our other debt or equity securities and may make it more
difficult for us to successfully execute our business strategy
and compete against companies who are not subject to such
restrictions.
Our
operations could be adversely affected if we fail to
appropriately secure our obligations.
U.S. federal and state laws and Australian laws require us to
secure certain of our obligations to reclaim lands used for
mining, to pay federal and state workers compensation, to
secure coal lease obligations and to satisfy other miscellaneous
obligations. The primary method for us to meet those obligations
is to post a corporate guarantee (i.e. self bond), provide a
third-party surety bond or provide a letter of credit. As of
December 31, 2007, we had $640.6 million of self bonds
in place primarily for our reclamation obligations. As of
December 31, 2007, we also had outstanding surety bonds
with third parties and letters of credit of $952.9 million,
of which $419.9 million was for post-mining reclamation,
$133.9 million related to workers compensation
obligations, $41.4 million was for retiree healthcare
obligations, $73.0 million was for coal lease obligations,
and $284.7 million was for other obligations, including
collateral for surety companies and bank guarantees, road
maintenance, and performance guarantees. As of December 31,
2007, the amount of letters of credit securing Patriot
obligations was $136.8 million, of which $95.4 million
related to Patriots workers compensation
obligations. Surety bonds are typically renewable on a yearly
basis. Surety bond issuers and holders may not continue to renew
the bonds or may demand additional collateral upon those
renewals. Letters of credit are subject to our successful
renewal of our bank revolving credit facilities, which are
currently set to expire in 2011. Our failure to maintain, or
inability to acquire, surety bonds or letters of credit or to
provide a suitable alternative would have a material adverse
effect on us. That failure could result from a variety of
factors including the following:
|
|
|
|
|
lack of availability, higher expense or unfavorable market terms
of new surety bonds;
|
|
|
|
restrictions on the availability of collateral for current and
future third-party surety bond issuers under the terms of our
indentures or Senior Unsecured Credit Facility;
|
|
|
|
the exercise by third-party surety bond issuers of their right
to refuse to renew the surety; and
|
|
|
|
inability to renew our credit facility.
|
Our ability to self bond reduces our costs of providing
financial assurances. To the extent we are unable to maintain
our current level of self bonding, due to legislative or
regulatory changes or changes in our financial condition, our
costs would increase.
33
The
conversion of our convertible debentures may result in the
dilution of the ownership interests of our existing
stockholders.
If the conditions permitting the conversion of our convertible
debentures are met and holders of the convertible debentures
exercise their conversion rights, any conversion value in excess
of the principal amount will be delivered in shares of our
common stock. If any common stock is issued in connection with a
conversion of our convertible debentures, our existing
stockholders will experience dilution in the voting power of
their common stock and earnings per share could be negatively
impacted.
Provisions
of our convertible debentures could discourage an acquisition of
us by a third-party.
Certain provisions of our convertible debentures could make it
more difficult or more expensive for a third-party to acquire
us. Upon the occurrence of certain transactions constituting a
change of control as defined in the indenture
relating to our convertible debentures, holders of our
convertible debentures will have the right, at their option, to
convert their convertible debentures and thereby require us to
pay the principal amount of such converted debentures in cash.
An
inability of brokerage sources to fulfill the delivery terms of
their contracts with us could reduce our
profitability.
In conducting our trading, brokerage and mining operations, we
utilize third-party sources of coal production, including
contract miners and brokerage sources, to fulfill deliveries
under our coal supply agreements. In Australia, the majority of
our mines utilize contract miners. Employee relations at mines
that use contract miners is the responsibility of the contractor.
Our profitability or exposure to loss on transactions or
relationships is dependent upon the reliability (including
financial viability) and price of the third-party suppliers, our
obligation to supply coal to customers in the event that adverse
geologic mining conditions restrict deliveries from our
suppliers, our willingness to participate in temporary cost
increases experienced by our third-party coal suppliers, our
ability to pass on temporary cost increases to our customers,
the ability to substitute, when economical, third-party coal
sources with internal production or coal purchased in the
market, and other factors. The recent market volatility and
price increases for coal on the international markets could
result in non-performance by third-party suppliers under
existing contracts with us, in order to take advantage of the
higher prices in the current market. Such non-performance could
have an adverse impact on our ability to fulfill deliveries
under our coal supply agreements.
If the
coal industry experiences overcapacity in the future, our
profitability could be impaired.
During the mid-1970s and early 1980s, a growing coal market and
increased demand for coal attracted new investors to the coal
industry, spurred the development of new mines and resulted in
production capacity in excess of market demand throughout the
industry. Similarly, increases in future coal prices could
encourage the development of expanded capacity by new or
existing coal producers. Coal prices in most regions of the
U.S. and globally were approaching record highs in early
2008, and the sustainability of these prices or its effects on
future production is uncertain.
We
could be negatively affected if we fail to maintain satisfactory
labor relations.
As of December 31, 2007, we had approximately
7,000 employees. As of such date, approximately 27% of our
hourly employees were represented by unions and they generated
approximately 10% of our 2007 coal production. Relations with
our employees and, where applicable, organized labor are
important to our success.
Due to the higher labor costs and the increased risk of strikes
and other work-related stoppages that may be associated with
union operations in the coal industry, our competitors who
operate without union labor may have a competitive advantage in
areas where they compete with our unionized operations. If some
or all of our current non-union operations were to become
unionized, we could incur an increased risk of work stoppages,
reduced productivity and higher labor costs.
34
United
States Labor Relations
Approximately 85% of our U.S. miners are non-union and are
employed in the states of Wyoming, Colorado, Indiana, New
Mexico, and Illinois. The UMWA under the Western Surface
Agreement represented approximately 6% of our
U.S. subsidiaries hourly employees, who generated 4%
of our U.S. production during the year ended
December 31, 2007. An additional 7% of our
U.S. subsidiaries hourly employees are represented by
labor unions other than the UMWA. These employees generated 2%
of our U.S. production during the year ended
December 31, 2007. Hourly workers at our mine in Arizona
are represented by the UMWA under the Western Surface Agreement,
which is effective through September 2, 2013. In April
2007, a new labor agreement was ratified for our hourly
workforce at the Willow Lake Mine, which is represented by the
International Brotherhood of Boilermakers. The new four-year
labor agreement expires on April 15, 2011.
Australia
Labor Relations
The Australian coal mining industry is unionized and all of our
hourly workers and those employed through our contract mining
relationships are members of trade unions. The Construction
Forestry Mining and Energy Union represents our Australian
subsidiarys hourly production employees. As of
December 31, 2007, our Australian hourly employees were
approximately 26% of our Australian hourly workforce and
generated 29% of our Australian total production in the year
then ended. The labor agreements at our Metropolitan Mine were
renewed in July and October 2007 and those agreements expire in
2010. The Wambo mine coal handling plant labor agreement is
under negotiation and the North Goonyella Mine operates under an
agreement due to expire in March 2008.
Our
ability to operate our company effectively could be impaired if
we lose key personnel or fail to attract qualified
personnel.
We manage our business with a number of key personnel, the loss
of a number of whom could have a material adverse effect on us.
In addition, as our business develops and expands, we believe
that our future success will depend greatly on our continued
ability to attract and retain highly skilled and qualified
personnel. We cannot assure you 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 a material adverse effect on us.
Due to the current demographics of our mining workforce, a high
portion of our current hourly employees are eligible to retire
over the next decade. Additionally, many of our mine sites are
in more secluded areas of the United States, such as the Native
American reservations of Arizona and the Southern Powder River
Basin of Wyoming. These geographic locations provide limited
pools of qualified personnel, and it is challenging to locate
qualified persons interested in working in some of these
regions. Failure to attract new employees to the mining
workforce could have a material adverse effect on us.
Our
ability to collect payments from our customers could be impaired
if their creditworthiness deteriorates.
Our ability to receive payment for coal sold and delivered
depends on the continued creditworthiness of our customers. Our
customer base has changed with deregulation as utilities have
sold their power plants to their non-regulated affiliates or
third parties. These new power plant owners or other customers
may have credit ratings that are below investment grade. If
deterioration of the creditworthiness of our customers occurs,
our $275.0 million accounts receivable securitization
program and our business could be adversely affected.
Our
certificate of incorporation and by-laws include provisions that
may discourage a takeover attempt.
Provisions contained in our certificate of incorporation and
by-laws and Delaware law could make it more difficult for a
third-party to acquire us, even if doing so might be beneficial
to our stockholders. Provisions of our by-laws and certificate
of incorporation impose various procedural and other
requirements that could make it more difficult for stockholders
to effect certain corporate actions. For example, a change in
control of our Company may be delayed or deterred as a result of
the stockholders rights plan adopted by our Board of
35
Directors. These provisions could limit the price that certain
investors might be willing to pay in the future for shares of
our common stock and may have the effect of delaying or
preventing a change in control.
Growth
in our global operations increases our risks unique to
international mining and trading operations.
We currently have international mining operations in Australia
and Venezuela. We have a business development, sales and
marketing office in Beijing, China and an international trading
group in our Trading and Brokerage operations. In addition, we
are actively pursuing long-term operating, trading and
joint-venture opportunities in China, Mongolia and Mozambique.
The international expansion of our operations increases our
exposure to country and currency risks. Some of our
international activities include expansion into developing
countries where business practices and counterparty reputations
may not be as well developed as in our U.S. or Australian
operations. We are also challenged by political risks, including
expropriation and the inability to repatriate earnings on our
investment. In particular, the Venezuelan government has
suggested its desire to increase government ownership in
Venezuelan energy assets and natural resources. Actions to
nationalize Venezuelan coal properties could be detrimental to
our investments in the Paso Diablo Mine and Cosila development
project. During 2007, the Paso Diablo Mine contributed
$21.2 million to segment Adjusted EBITDA in Corporate
and Other Adjusted EBITDA (see Item 7) and paid
a dividend of $12.9 million. At December 31, 2007, our
investment in Paso Diablo was $68.4 million, recorded in
Investments and other assets on the consolidated
balance sheet.
As we
continue to pursue development of Generation Development and Btu
Conversion activities, we face challenges and risks that differ
from those in our mining business.
We continue to pursue the development of coal-fueled generating
projects in the U.S., including mine-mouth generating plants
using our surface lands and coal reserves. Our ultimate role in
these projects could take numerous forms, including, but not
limited to, equity partner, contract miner or coal sales. We are
a 5.06% owner in the 1,600 plus-megawatt Prairie State Energy
Campus in Washington County, Illinois and are pursuing
development of the 1,500-megawatt Thoroughbred Energy Campus in
Muhlenberg County, Kentucky. We also continue to pursue
opportunities to participate in technologies to economically
convert our coal resources to natural gas and liquids such as
diesel fuel, gasoline and jet fuel (Btu Conversion).
As we move forward with all of these projects, we are exposed to
risks related to the performance of our partners, securing
required financing, obtaining necessary permits, meeting
stringent regulatory laws, maintaining strong supplier
relationships and managing (along with our partners) large
projects, including managing through long lead times for
ordering and obtaining capital equipment. Our work in new or
recently commercialized technologies could expose us to
unanticipated risks, evolving legislation and uncertainty
regarding the extent of future government support and funding.
The
implementation of our new enterprise resource planning system
carries certain risks, including the potential for business
interruption, and the associated adverse impact.
To support the continued growth and globalization of our
businesses, we are converting our existing information systems
across major business processes to an integrated information
technology system provided by SAP AG. The
U.S. implementation occurred in August 2007. We made
extensive plans to support effective implementation of this
information technology system. Such a major undertaking carries
the additional risk of unforeseen issues, interruptions and
costs. The extent to which we successfully convert our
information technology systems and address unforeseen issues
will have a direct bearing on our ability to perform certain
day-to-day
functions.
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
36
issues. For example, some companies capitalize drilling and
related costs incurred to delineate and classify mineral
resources as proven and probable reserves, and other companies
expense such costs. In addition, some industry participants
expense pre-production stripping costs associated with
developing new pits at existing surface mining operations, while
other companies capitalize pre-production stripping costs for
new pit development at existing operations. The materiality of
such expenditures can vary greatly relative to a given
companys respective financial position and results of
operations. 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 with respect to drilling costs and advance stripping
costs, please see Item 7. Managements Discussion and
Analysis of Financial Condition and Results of
Operations Critical Accounting Policies and
Estimates).
|
|
Item 1B.
|
Unresolved
Staff Comments.
|
None.
Coal
Reserves
We had an estimated 9.3 billion tons of proven and probable
coal reserves as of December 31, 2007. An estimated
8.2 billion tons of our proven and probable coal reserves
are in the United States and 1.1 billion tons are in
Australia. Forty-six percent of our reserves, or
4.2 billion tons, are compliance coal and 54% are
non-compliance coal. We own approximately 37% of these reserves
and lease property containing the remaining 63%. Compliance coal
is defined by Phase II of the Clean Air Act as coal having
sulfur dioxide content of 1.2 pounds or less per million Btu.
Electricity generators are able to use coal that exceeds these
specifications by using emissions reduction technology, using
emission allowance credits or blending higher sulfur coal with
lower sulfur coal.
Below is a table summarizing the locations and reserves of our
major operating regions.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proven and Probable Reserves as of
|
|
|
|
|
|
December 31,
2007(1)
|
|
|
|
|
|
Owned
|
|
|
Leased
|
|
|
Total
|
|
Operating Regions
|
|
Locations
|
|
Tons
|
|
|
Tons
|
|
|
Tons
|
|
|
|
|
|
(Tons in millions)
|
|
|
Midwest
|
|
Illinois, Indiana and Kentucky
|
|
|
2,686
|
|
|
|
1,005
|
|
|
|
3,691
|
|
Powder River Basin
|
|
Wyoming and Montana
|
|
|
67
|
|
|
|
3,274
|
|
|
|
3,341
|
|
Southwest
|
|
Arizona and New Mexico
|
|
|
639
|
|
|
|
351
|
|
|
|
990
|
|
Colorado
|
|
Colorado
|
|
|
35
|
|
|
|
171
|
|
|
|
206
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total United States
|
|
|
|
|
3,427
|
|
|
|
4,801
|
|
|
|
8,228
|
|
Australia
|
|
New South Wales
|
|
|
|
|
|
|
484
|
|
|
|
484
|
|
Australia
|
|
Queensland
|
|
|
|
|
|
|
589
|
|
|
|
589
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Australia
|
|
|
|
|
|
|
|
|
1,073
|
|
|
|
1,073
|
|
Total Proven and Probable Coal Reserves
|
|
|
|
|
3,427
|
|
|
|
5,874
|
|
|
|
9,301
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Reserves have been adjusted to take into account estimated
losses involved in producing a saleable product. |
Reserves are defined by SEC Industry Guide 7 as that part of a
mineral deposit which could be economically and legally
extracted or produced at the time of the reserve determination.
Proven and probable coal reserves are defined by SEC Industry
Guide 7 as follows:
Proven (Measured) Reserves 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 close and
37
the geographic character is so well defined that size, shape,
depth and mineral content of reserves are well-established.
Probable (Indicated) Reserves 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.
Our estimates of proven and probable coal reserves are
established within these guidelines. Proven reserves require the
coal to lie within one-quarter mile of a valid point of measure
or point of observation, such as exploratory drill holes or
previously mined areas. Estimates of probable reserves may lie
more than one-quarter mile, but less than three-quarters of a
mile, from a point of thickness measurement. Estimates within
the proven category have the highest degree of assurance, while
estimates within the probable category have only a moderate
degree of geologic assurance. Further exploration is necessary
to place probable reserves into the proven reserve category. Our
active properties generally have a much higher degree of
reliability because of increased drilling density. Active
surface reserves generally have points of observation as close
as 330 feet to 660 feet.
Our reserve estimates are prepared by our staff of geologists,
whose experience ranges from 10 to over 30 years. We also
have a chief geologist of reserve reporting whose primary
responsibility is to track changes in reserve estimates,
supervise our other geologists and coordinate periodic
third-party reviews of our reserve estimates by qualified mining
consultants.
Our reserve estimates are predicated on information obtained
from our ongoing drilling program, which totals nearly 500,000
individual drill holes. We compile data from individual drill
holes in a computerized drill-hole database from which the
depth, thickness and, where core drilling is used, the quality
of the coal are determined. The density of the drill pattern
determines whether the reserves will be classified as proven or
probable. The reserve estimates are then input into our
computerized land management system, which overlays the
geological data with data on ownership or control of the mineral
and surface interests to determine the extent of our reserves in
a given area. The land management system contains reserve
information, including the quantity and quality (where
available) of reserves as well as production rates, surface
ownership, lease payments and other information relating to our
coal reserves and land holdings. We periodically update our
reserve estimates to reflect production of coal from the
reserves and new drilling or other data received. Accordingly,
reserve estimates will change from time to time to reflect
mining activities, analysis of new engineering and geological
data, changes in reserve holdings, modification of mining
methods and other factors.
Our estimate of the economic recoverability of our reserves is
based upon a comparison of unassigned reserves to assigned
reserves currently in production in the same geologic setting to
determine an estimated mining cost. These estimated mining costs
are compared to existing market prices for the quality of coal
expected to be mined and taking into consideration typical
contractual sales agreements for the region and product. Where
possible, we also review production by competitors in similar
mining areas. Only reserves expected to be mined economically
are included in our reserve estimates. Finally, our reserve
estimates include reductions for recoverability factors to
estimate a saleable product.
We periodically engage independent mining and geological
consultants and consider their input regarding the procedures
used by us to prepare our internal estimates of coal reserves,
selected property reserve estimates and tabulation of reserve
groups according to standard classifications of reliability.
With respect to the accuracy of our reserve estimates, our
experience is that recovered reserves are within plus or minus
10% of our proven and probable estimates, on average, and our
probable estimates are generally within the same statistical
degree of accuracy when the necessary drilling is completed to
move reserves from the probable to the proven classification.
We have numerous federal coal leases that are administered by
the U.S. Department of the Interior under the Federal Coal
Leasing Amendments Act of 1976. These leases cover our principal
reserves in Wyoming
38
and other reserves in Montana and Colorado. Each of these leases
continues indefinitely, provided there is diligent development
of the property and continued operation of the related mine or
mines. The Bureau of Land Management has asserted the right to
adjust the terms and conditions of these leases, including rent
and royalties, after the first 20 years of their term and
at 10-year
intervals thereafter. Annual rents on surface land under our
federal coal leases are now set at $3.00 per acre. Production
royalties on federal leases are set by statute at 12.5% of the
gross proceeds of coal mined and sold for surface-mined coal and
8% for underground-mined coal. The federal government limits by
statute the amount of federal land that may be leased by any
company and its affiliates at any time to 75,000 acres in
any one state and 150,000 acres nationwide. As of
December 31, 2007, we leased 11,103 acres of federal
land in Colorado, 11,254 acres in Montana and
41,106 acres in Wyoming, for a total of 63,463 nationwide.
Similar provisions govern three coal leases with the Navajo and
Hopi Indian tribes. These leases cover coal contained in
65,000 acres of land in northern Arizona lying within the
boundaries of the Navajo Nation and Hopi Indian reservations. We
also lease coal-mining properties from various state governments.
Private U.S. coal leases normally have terms of between 10
and 20 years and usually give us the right to renew the
lease for a stated period or to maintain the lease in force
until the exhaustion of mineable and merchantable coal contained
on the relevant site. These private U.S. leases provide for
royalties to be paid to the lessor either as a fixed amount per
ton or as a percentage of the sales price. Many U.S. leases
also require payment of a lease bonus or minimum royalty,
payable either at the time of execution of the lease or in
periodic installments.
The terms of our private U.S. leases are normally extended
by active production at or near the end of the lease term.
U.S. leases containing undeveloped reserves may expire or
these leases may be renewed periodically. With a portfolio of
approximately 9.3 billion tons, we believe that we have
sufficient reserves to replace capacity from depleting mines for
the foreseeable future and that our significant reserve holdings
is one of our strengths. We believe that the current level of
production at our major mines is sustainable for the foreseeable
future.
Mining and exploration in Australia is generally carried on
under leases or licenses granted by state governments. Mining
leases are typically for an initial term of up to 21 years
(but which may be renewed) and contain conditions relating to
such matters as minimum annual expenditures, restoration and
rehabilitation. Royalties are paid to the State Government as a
percentage of sale prices. Generally landowners do not own the
mineral rights or have the ability to grant rights to mine those
minerals. These rights are retained by State Governments.
Compensation is payable to landowners for loss of access to the
land, and the amount of compensation can be determined by
agreement or arbitration. Surface rights are typically acquired
directly from landowners and, in the absence of agreement, there
is an arbitration provision in the mining law.
Consistent with industry practice, we conduct only limited
investigation of title to our coal properties prior to leasing.
Title to lands and reserves of the lessors or grantors and the
boundaries of our leased properties are not completely verified
until we prepare to mine those reserves.
39
The following chart provides a summary, by mining complex, of
production for the years ended December 31, 2007 and 2006
and 2005, tonnage of coal reserves that is assigned to our
operating mines, our property interest in those reserves and
other characteristics of the facilities.
PRODUCTION
AND ASSIGNED
RESERVES(1)
(Tons in millions)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production
|
|
|
|
|
Sulfur
Content(2)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year
|
|
|
Year
|
|
|
Year
|
|
|
|
|
<1.2 lbs.
|
|
|
>1.2 to 2.5 lbs.
|
|
|
>2.5 lbs.
|
|
|
As
|
|
|
As of December 31, 2007
|
|
|
|
Ended
|
|
|
Ended
|
|
|
Ended
|
|
|
|
|
sulfur dioxide
|
|
|
sulfur dioxide
|
|
|
sulfur dioxide
|
|
|
Received
|
|
|
Assigned
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dec. 31,
|
|
|
Dec. 31,
|
|
|
Dec. 31,
|
|
|
Type of
|
|
per
|
|
|
per
|
|
|
per
|
|
|
Btu
|
|
|
Proven and
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Geographic Region/Mining Complex
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
Coal
|
|
Million Btu
|
|
|
Million Btu
|
|
|
Million Btu
|
|
|
per
pound(3)
|
|
|
Probable Reserves
|
|
|
Owned
|
|
|
Leased
|
|
|
Surface
|
|
|
Underground
|
|
|
Midwest:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Air Quality
|
|
|
2.1
|
|
|
|
2.2
|
|
|
|
2.1
|
|
|
Steam
|
|
|
24
|
|
|
|
1
|
|
|
|
31
|
|
|
|
11,300
|
|
|
|
56
|
|
|
|
3
|
|
|
|
53
|
|
|
|
|
|
|
|
56
|
|
Riola/Vermilion Grove
|
|
|
1.4
|
|
|
|
1.7
|
|
|
|
2.3
|
|
|
Steam
|
|
|
|
|
|
|
6
|
|
|
|
13
|
|
|
|
11,300
|
|
|
|
19
|
|
|
|
|
|
|
|
19
|
|
|
|
|
|
|
|
19
|
|
Miller Creek
|
|
|
1.6
|
|
|
|
1.6
|
|
|
|
1.0
|
|
|
Steam
|
|
|
|
|
|
|
2
|
|
|
|
25
|
|
|
|
10,000
|
|
|
|
27
|
|
|
|
26
|
|
|
|
1
|
|
|
|
27
|
|
|
|
|
|
Francisco Surface
|
|
|
2.2
|
|
|
|
2.0
|
|
|
|
1.8
|
|
|
Steam
|
|
|
|
|
|
|
|
|
|
|
3
|
|
|
|
10,500
|
|
|
|
3
|
|
|
|
|
|
|
|
3
|
|
|
|
3
|
|
|
|
|
|
Francisco Underground
|
|
|
0.9
|
|
|
|
1.1
|
|
|
|
1.2
|
|
|
Steam
|
|
|
|
|
|
|
|
|
|
|
33
|
|
|
|
11,200
|
|
|
|
33
|
|
|
|
4
|
|
|
|
29
|
|
|
|
|
|
|
|
33
|
|
Farmersburg
|
|
|
3.5
|
|
|
|
3.8
|
|
|
|
3.8
|
|
|
Steam
|
|
|
1
|
|
|
|
11
|
|
|
|
16
|
|
|
|
10,600
|
|
|
|
28
|
|
|
|
19
|
|
|
|
9
|
|
|
|
27
|
|
|
|
1
|
|
Somerville Central
|
|
|
3.4
|
|
|
|
3.5
|
|
|
|
3.4
|
|
|
Steam
|
|
|
|
|
|
|
|
|
|
|
2
|
|
|
|
10,400
|
|
|
|
2
|
|
|
|
1
|
|
|
|
1
|
|
|
|
2
|
|
|
|
|
|
Somerville North
|
|
|
2.5
|
|
|
|
2.4
|
|
|
|
2.4
|
|
|
Steam
|
|
|
|
|
|
|
|
|
|
|
5
|
|
|
|
10,500
|
|
|
|
5
|
|
|
|
5
|
|
|
|
|
|
|
|
5
|
|
|
|
|
|
Somerville South
|
|
|
2.5
|
|
|
|
2.5
|
|
|
|
2.4
|
|
|
Steam
|
|
|
|
|
|
|
|
|
|
|
15
|
|
|
|
9,900
|
|
|
|
15
|
|
|
|
9
|
|
|
|
6
|
|
|
|
15
|
|
|
|
|
|
Viking
|
|
|
1.7
|
|
|
|
1.5
|
|
|
|
1.5
|
|
|
Steam
|
|
|
|
|
|
|
1
|
|
|
|
8
|
|
|
|
10,600
|
|
|
|
9
|
|
|
|
|
|
|
|
9
|
|
|
|
9
|
|
|
|
|
|
Wildcat Hills
|
|
|
2.9
|
|
|
|
2.4
|
|
|
|
2.6
|
|
|
Steam
|
|
|
|
|
|
|
|
|
|
|
34
|
|
|
|
11,200
|
|
|
|
34
|
|
|
|
21
|
|
|
|
13
|
|
|
|
11
|
|
|
|
23
|
|
Gateway
|
|
|
2.7
|
|
|
|
2.6
|
|
|
|
0.5
|
|
|
Steam
|
|
|
|
|
|
|
|
|
|
|
18
|
|
|
|
11,000
|
|
|
|
18
|
|
|
|
18
|
|
|
|
|
|
|
|
|
|
|
|
18
|
|
Willow Lake
|
|
|
3.6
|
|
|
|
3.6
|
|
|
|
3.7
|
|
|
Steam
|
|
|
|
|
|
|
|
|
|
|
44
|
|
|
|
11,300
|
|
|
|
44
|
|
|
|
32
|
|
|
|
12
|
|
|
|
|
|
|
|
44
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
31.0
|
|
|
|
30.9
|
|
|
|
28.7
|
|
|
|
|
|
25
|
|
|
|
21
|
|
|
|
247
|
|
|
|
|
|
|
|
293
|
|
|
|
138
|
|
|
|
155
|
|
|
|
99
|
|
|
|
194
|
|
Powder River Basin:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
North Antelope/Rochelle
|
|
|
91.5
|
|
|
|
88.6
|
|
|
|
82.7
|
|
|
Steam
|
|
|
1,097
|
|
|
|
|
|
|
|
|
|
|
|
8,800
|
|
|
|
1,097
|
|
|
|
|
|
|
|
1,097
|
|
|
|
1,097
|
|
|
|
|
|
Caballo
|
|
|
31.2
|
|
|
|
32.8
|
|
|
|
30.5
|
|
|
Steam
|
|
|
756
|
|
|
|
122
|
|
|
|
23
|
|
|
|
8,600
|
|
|
|
901
|
|
|
|
|
|
|
|
901
|
|
|
|
901
|
|
|
|
|
|
Rawhide
|
|
|
17.2
|
|
|
|
17.0
|
|
|
|
12.4
|
|
|
Steam
|
|
|
274
|
|
|
|
59
|
|
|
|
53
|
|
|
|
8,600
|
|
|
|
386
|
|
|
|
|
|
|
|
386
|
|
|
|
386
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
139.9
|
|
|
|
138.4
|
|
|
|
125.6
|
|
|
|
|
|
2,127
|
|
|
|
181
|
|
|
|
76
|
|
|
|
|
|
|
|
2,384
|
|
|
|
|
|
|
|
2,384
|
|
|
|
2,384
|
|
|
|
|
|
Southwest/Colorado:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Black Mesa
|
|
|
|
|
|
|
|
|
|
|
3.9
|
|
|
Steam
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NA
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Kayenta
|
|
|
8.0
|
|
|
|
8.2
|
|
|
|
8.2
|
|
|
Steam
|
|
|
164
|
|
|
|
84
|
|
|
|
6
|
|
|
|
11,000
|
|
|
|
254
|
|
|
|
|
|
|
|
254
|
|
|
|
254
|
|
|
|
|
|
Lee Ranch
|
|
|
5.3
|
|
|
|
5.5
|
|
|
|
5.3
|
|
|
Steam
|
|
|
21
|
|
|
|
121
|
|
|
|
12
|
|
|
|
10,000
|
|
|
|
154
|
|
|
|
92
|
|
|
|
62
|
|
|
|
154
|
|
|
|
|
|
Twentymile
|
|
|
8.3
|
|
|
|
8.6
|
|
|
|
9.4
|
|
|
Steam
|
|
|
61
|
|
|
|
|
|
|
|
|
|
|
|
10,800
|
|
|
|
61
|
|
|
|
14
|
|
|
|
47
|
|
|
|
|
|
|
|
61
|
|
Seneca
|
|
|
|
|
|
|
|
|
|
|
1.1
|
|
|
Steam
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NA
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
21.6
|
|
|
|
22.3
|
|
|
|
27.9
|
|
|
|
|
|
246
|
|
|
|
205
|
|
|
|
18
|
|
|
|
|
|
|
|
469
|
|
|
|
106
|
|
|
|
363
|
|
|
|
408
|
|
|
|
61
|
|
Australia:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
North Goonyella / Eaglefield
|
|
|
2.8
|
|
|
|
2.2
|
|
|
|
2.1
|
|
|
Met.
|
|
|
45
|
|
|
|
|
|
|
|
|
|
|
|
12,800
|
|
|
|
45
|
|
|
|
|
|
|
|
45
|
|
|
|
1
|
|
|
|
44
|
|
Metropolitan
|
|
|
1.5
|
|
|
|
0.4
|
|
|
|
|
|
|
Met.
|
|
|
39
|
|
|
|
|
|
|
|
|
|
|
|
12,700
|
|
|
|
39
|
|
|
|
|
|
|
|
39
|
|
|
|
|
|
|
|
39
|
|
Wilkie Creek
|
|
|
2.4
|
|
|
|
2.0
|
|
|
|
1.9
|
|
|
Steam
|
|
|
344
|
|
|
|
|
|
|
|
|
|
|
|
10,800
|
|
|
|
344
|
|
|
|
|
|
|
|
344
|
|
|
|
344
|
|
|
|
|
|
Chain Valley
(80.0%)(5)
|
|
|
0.6
|
|
|
|
0.2
|
|
|
|
|
|
|
Steam
|
|
|
15
|
|
|
|
|
|
|
|
|
|
|
|
11,900
|
|
|
|
15
|
|
|
|
|
|
|
|
15
|
|
|
|
|
|
|
|
15
|
|
Wambo
Open-Cut(4)
|
|
|
4.4
|
|
|
|
1.2
|
|
|
|
|
|
|
Steam
|
|
|
121
|
|
|
|
|
|
|
|
|
|
|
|
12,400
|
|
|
|
121
|
|
|
|
|
|
|
|
121
|
|
|
|
121
|
|
|
|
|
|
Burton
(95.0%)(5)
|
|
|
3.1
|
|
|
|
4.3
|
|
|
|
4.4
|
|
|
Steam/Met.
|
|
|
33
|
|
|
|
|
|
|
|
|
|
|
|
12,400
|
|
|
|
33
|
|
|
|
|
|
|
|
33
|
|
|
|
33
|
|
|
|
|
|
Baralaba(4)
|
|
|
0.4
|
|
|
|
0.2
|
|
|
|
|
|
|
Steam/Met.
|
|
|
|
|
|
|
2
|
|
|
|
|
|
|
|
12,200
|
|
|
|
2
|
|
|
|
|
|
|
|
2
|
|
|
|
2
|
|
|
|
|
|
Wilpinjong
|
|
|
5.1
|
|
|
|
0.3
|
|
|
|
|
|
|
Steam
|
|
|
|
|
|
|
190
|
|
|
|
|
|
|
|
9,900
|
|
|
|
190
|
|
|
|
|
|
|
|
190
|
|
|
|
190
|
|
|
|
|
|
Millennium(4)
|
|
|
1.3
|
|
|
|
0.1
|
|
|
|
|
|
|
Met.
|
|
|
23
|
|
|
|
|
|
|
|
|
|
|
|
12,800
|
|
|
|
23
|
|
|
|
|
|
|
|
23
|
|
|
|
23
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
21.6
|
|
|
|
10.9
|
|
|
|
8.4
|
|
|
|
|
|
620
|
|
|
|
192
|
|
|
|
|
|
|
|
|
|
|
|
812
|
|
|
|
|
|
|
|
812
|
|
|
|
714
|
|
|
|
98
|
|
Discontinued Operations
|
|
|
17.0
|
|
|
|
23.3
|
|
|
|
22.4
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Assigned
|
|
|
231.1
|
|
|
|
225.8
|
|
|
|
213.0
|
|
|
|
|
|
3,018
|
|
|
|
599
|
|
|
|
341
|
|
|
|
|
|
|
|
3,958
|
|
|
|
244
|
|
|
|
3,714
|
|
|
|
3,605
|
|
|
|
353
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
40
The following chart provides a summary of the amount of our
proven and probable coal reserves in each U.S. state and
Australia state, the predominant type of coal mined in the
applicable location, our property interest in the reserves and
other characteristics of the facilities.
ASSIGNED
AND UNASSIGNED PROVEN AND PROBABLE COAL RESERVES
As of December 31, 2007
(Tons in millions)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sulfur
Content(2)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
<1.2 lbs.
|
|
|
>1.2 to 2.5 lbs.
|
|
|
>2.5 lbs.
|
|
|
As
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proven and
|
|
|
|
|
|
|
|
|
|
|
sulfur dioxide
|
|
|
sulfur dioxide
|
|
|
sulfur dioxide
|
|
|
Received
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Tons
|
|
|
Probable
|
|
|
|
|
|
|
|
|
Type of
|
|
per
|
|
|
per
|
|
|
per
|
|
|
Btu
|
|
|
Reserve Control
|
|
|
Mining Method
|
|
|
|
|
Coal Seam Location
|
|
Assigned
|
|
|
Unassigned
|
|
|
Reserves(6)
|
|
|
Proven
|
|
|
Probable
|
|
|
Coal
|
|
Million Btu
|
|
|
Million Btu
|
|
|
Million Btu
|
|
|
per
pound(3)
|
|
|
Owned
|
|
|
Leased
|
|
|
Surface
|
|
|
Underground
|
|
|
|
|
|
Midwest:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Illinois
|
|
|
116
|
|
|
|
2,210
|
|
|
|
2,326
|
|
|
|
1,154
|
|
|
|
1,172
|
|
|
Steam
|
|
|
|
|
|
|
24
|
|
|
|
2,302
|
|
|
|
10,500
|
|
|
|
1,821
|
|
|
|
505
|
|
|
|
77
|
|
|
|
2,249
|
|
|
|
|
|
Indiana
|
|
|
177
|
|
|
|
490
|
|
|
|
667
|
|
|
|
433
|
|
|
|
234
|
|
|
Steam
|
|
|
25
|
|
|
|
15
|
|
|
|
627
|
|
|
|
10,400
|
|
|
|
395
|
|
|
|
272
|
|
|
|
247
|
|
|
|
420
|
|
|
|
|
|
Kentucky
|
|
|
|
|
|
|
698
|
|
|
|
698
|
|
|
|
373
|
|
|
|
325
|
|
|
Steam
|
|
|
|
|
|
|
1
|
|
|
|
697
|
|
|
|
11,000
|
|
|
|
470
|
|
|
|
228
|
|
|
|
29
|
|
|
|
669
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Midwest
|
|
|
293
|
|
|
|
3,398
|
|
|
|
3,691
|
|
|
|
1,960
|
|
|
|
1,731
|
|
|
|
|
|
25
|
|
|
|
40
|
|
|
|
3,626
|
|
|
|
|
|
|
|
2,686
|
|
|
|
1,005
|
|
|
|
353
|
|
|
|
3,338
|
|
|
|
|
|
Powder River Basin:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Montana
|
|
|
|
|
|
|
162
|
|
|
|
162
|
|
|
|
158
|
|
|
|
4
|
|
|
Steam
|
|
|
15
|
|
|
|
117
|
|
|
|
30
|
|
|
|
8,600
|
|
|
|
67
|
|
|
|
95
|
|
|
|
162
|
|
|
|
|
|
|
|
|
|
Wyoming
|
|
|
2,384
|
|
|
|
795
|
|
|
|
3,179
|
|
|
|
3,111
|
|
|
|
68
|
|
|
Steam
|
|
|
2,900
|
|
|
|
181
|
|
|
|
98
|
|
|
|
8,700
|
|
|
|
|
|
|
|
3,179
|
|
|
|
3,179
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Powder River Basin
|
|
|
2,384
|
|
|
|
957
|
|
|
|
3,341
|
|
|
|
3,269
|
|
|
|
72
|
|
|
|
|
|
2,915
|
|
|
|
298
|
|
|
|
128
|
|
|
|
|
|
|
|
67
|
|
|
|
3,274
|
|
|
|
3,341
|
|
|
|
|
|
|
|
|
|
Southwest/Colorado:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Arizona
|
|
|
254
|
|
|
|
18
|
|
|
|
272
|
|
|
|
272
|
|
|
|
|
|
|
Steam
|
|
|
181
|
|
|
|
86
|
|
|
|
5
|
|
|
|
10,900
|
|
|
|
|
|
|
|
272
|
|
|
|
272
|
|
|
|
|
|
|
|
|
|
Colorado
|
|
|
60
|
|
|
|
146
|
|
|
|
206
|
|
|
|
140
|
|
|
|
66
|
|
|
Steam
|
|
|
151
|
|
|
|
|
|
|
|
55
|
|
|
|
10,700
|
|
|
|
35
|
|
|
|
171
|
|
|
|
|
|
|
|
206
|
|
|
|
|
|
New Mexico
|
|
|
155
|
|
|
|
563
|
|
|
|
718
|
|
|
|
650
|
|
|
|
68
|
|
|
Steam
|
|
|
90
|
|
|
|
361
|
|
|
|
267
|
|
|
|
9,200
|
|
|
|
639
|
|
|
|
79
|
|
|
|
718
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Southwest
|
|
|
469
|
|
|
|
727
|
|
|
|
1,196
|
|
|
|
1,062
|
|
|
|
134
|
|
|
|
|
|
422
|
|
|
|
447
|
|
|
|
327
|
|
|
|
|
|
|
|
674
|
|
|
|
522
|
|
|
|
990
|
|
|
|
206
|
|
|
|
|
|
Australia:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
New South Wales
|
|
|
365
|
|
|
|
119
|
|
|
|
484
|
|
|
|
309
|
|
|
|
175
|
|
|
Steam/Met.
|
|
|
294
|
|
|
|
190
|
|
|
|
|
|
|
|
12,400
|
|
|
|
|
|
|
|
484
|
|
|
|
311
|
|
|
|
173
|
|
|
|
|
|
Queensland
|
|
|
447
|
|
|
|
142
|
|
|
|
589
|
|
|
|
110
|
|
|
|
479
|
|
|
Steam/Met.
|
|
|
587
|
|
|
|
2
|
|
|
|
|
|
|
|
11,200
|
|
|
|
|
|
|
|
589
|
|
|
|
544
|
|
|
|
45
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Australia
|
|
|
812
|
|
|
|
261
|
|
|
|
1,073
|
|
|
|
419
|
|
|
|
654
|
|
|
|
|
|
881
|
|
|
|
192
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,073
|
|
|
|
855
|
|
|
|
218
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Proven and Probable
|
|
|
3,958
|
|
|
|
5,343
|
|
|
|
9,301
|
|
|
|
6,710
|
|
|
|
2,591
|
|
|
|
|
|
4,243
|
|
|
|
977
|
|
|
|
4,081
|
|
|
|
|
|
|
|
3,427
|
|
|
|
5,874
|
|
|
|
5,539
|
|
|
|
3,762
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
41
|
|
|
(1) |
|
Assigned reserves represent recoverable coal reserves that we
have committed to mine at locations operating as of
December 31, 2007. Unassigned reserves represent coal at
suspended locations and coal that has not been committed. These
reserves would require new mine development, mining equipment or
plant facilities before operations could begin on the property. |
|
(2) |
|
Compliance coal is defined by Phase II of the Clean Air Act
as coal having sulfur dioxide content of 1.2 pounds or less per
million Btu. Non-compliance coal is defined as coal having
sulfur dioxide content in excess of this standard. Electricity
generators are able to use coal that exceeds these
specifications by using emissions reduction technology, using
emissions allowance credits or blending higher sulfur coal with
lower sulfur coal. |
|
(3) |
|
As-received Btu per pound includes the weight of moisture in the
coal on an as sold basis. The following table reflects the
average moisture content used in the determination of the
as-received Btu by region. The range of variability of the
moisture content in coal across a given region may affect the
actual shipped Btu content of current production from assigned
reserves. |
|
|
|
|
|
Midwest:
|
|
|
|
|
Illinois
|
|
|
14.0
|
%
|
Indiana
|
|
|
15.0
|
%
|
Kentucky
|
|
|
12.5
|
%
|
Powder River Basin:
|
|
|
|
|
Montana
|
|
|
26.5
|
%
|
Wyoming
|
|
|
27.5
|
%
|
Southwest:
|
|
|
|
|
Arizona
|
|
|
13.0
|
%
|
Colorado
|
|
|
14.0
|
%
|
New Mexico
|
|
|
15.5
|
%
|
Australia
|
|
|
10.0
|
%
|
|
|
|
(4) |
|
These joint ventures are consolidated in our results and their
proven and probable coal reserves are reflected at 100%. Our
effective percentage interest in each operation is as follows:
Wambo Open-Cut 75.0%; Baralaba 62.5% and
Millennium 84.6%. |
|
(5) |
|
Proven and probable coal reserves for these joint ventures
reflect our proportional ownership as indicated parenthetically. |
|
(6) |
|
Proven and probable reserves exclude approximately
46 million tons located in Zulia State, Venezuela, related
to the Las Carmelitas Project, which is held through our 51%
interest in Excelven Pty Ltd. |
|
|
Item 3.
|
Legal
Proceedings
|
From time to time, we or our subsidiaries are involved in legal
proceedings arising in the ordinary course of business or
related to indemnities or historical operations. We believe we
have recorded adequate reserves for these liabilities and that
there is no individual case pending that is likely to have a
material adverse effect on our financial condition, results of
operations or cash flows. We discuss our significant legal
proceedings below.
Litigation
Relating to Continuing Operations
Navajo
Nation Litigation
On June 18, 1999, the Navajo Nation served three of our
subsidiaries, including Peabody Western Coal Company (Peabody
Western), with a complaint that had been filed in the
U.S. District Court for the District of Columbia. The
Navajo Nation has alleged 16 claims, including Civil Racketeer
Influenced and Corrupt Organizations Act (RICO) violations and
fraud. The complaint alleges that the defendants jointly
participated in unlawful activity to obtain favorable coal lease
amendments. The plaintiff is seeking various remedies including
actual damages of at least $600 million, which could be
trebled under the RICO counts, punitive
42
damages of at least $1 billion, a determination that
Peabody Westerns two coal leases have terminated due to
Peabody Westerns breach of these leases and a reformation
of these leases to adjust the royalty rate to 20%. Subsequently,
the court allowed the Hopi Tribe to intervene in this lawsuit
and the Hopi Tribe is also seeking unspecified actual damages,
punitive damages and reformation of its coal lease. One of our
subsidiaries named as a defendant is now a subsidiary of
Patriot. However, we are responsible for this litigation under
the Separation Agreement entered into with Patriot in connection
with the spin-off. On February 9, 2005, the
U.S. District Court for the District of Columbia granted a
consent motion to stay the litigation until further order of the
court. Peabody Western, the Navajo Nation, the Hopi Tribe and
the owners of the power plants served by the suspended Black
Mesa mine and the Kayenta mine have terminated the mediation
with respect to this litigation and other business issues, filed
a status report with the Court and asked the Court to lift the
stay. The Court has not lifted the stay.
The outcome of this litigation is subject to numerous
uncertainties. Based on our evaluation of the issues and their
potential impact, the amount of any future loss cannot be
reasonably estimated. However, based on current information, we
believe this matter is likely to be resolved without a material
adverse effect on our financial condition, results of operations
or cash flows.
Salt
River Project Agricultural Improvement and Power
District Mine Closing and Retiree Health
Care
Salt River Project and the other owners of the Navajo Generating
Station filed a lawsuit on September 27, 1996, in the
Superior Court of Maricopa County in Arizona seeking a
declaratory judgment that certain costs relating to final
reclamation, environmental monitoring work and mine
decommissioning and costs primarily relating to retiree health
care benefits are not recoverable by our subsidiary, Peabody
Western, under the terms of a coal supply agreement dated
February 18, 1977. The contract expires in 2011. The trial
court subsequently ruled that the mine decommissioning costs
were subject to arbitration but that the retiree health care
costs were not subject to arbitration. We have recorded a
receivable for mine decommissioning costs of $87.7 million
and $76.8 million included in Investments and other
assets in the consolidated balance sheets as of
December 31, 2007 and 2006, respectively. The parties have
negotiated a final comprehensive settlement and are in the
process of obtaining all required approvals of the settlement
documents.
Gulf
Power Company Litigation
On June 22, 2006, Gulf Power Company filed a breach of
contract lawsuit against one of our subsidiaries in the
U.S. District Court, Northern District of Florida,
contesting the force majeure declaration by our subsidiary under
a coal supply agreement with Gulf Power Company and seeking
damages for alleged past and future tonnage shortfalls of nearly
5 million tons under the agreement, which expired on
December 31, 2007. We have filed a motion to dismiss the
Florida lawsuit or to transfer it to Illinois. The Court held an
evidentiary hearing on our motion to dismiss or transfer and has
continued to stay discovery until the Court rules on the motion.
The outcome of this litigation is subject to numerous
uncertainties. Based on our evaluation of the issues and their
potential impact, the amount of any future loss cannot
reasonably be estimated. However, based on current information,
we believe this matter is likely to be resolved without a
material adverse effect on our financial condition, results of
operations or cash flows.
Claims
and Litigation Relating to Indemnities or Historical
Operations
Oklahoma
Lead Litigation
Gold Fields Mining, LLC (Gold Fields) is a dormant, non-coal
producing entity that was previously managed and owned by Hanson
PLC, our predecessor owner. In a February 1997 spin-off, Hanson
PLC transferred ownership of Gold Fields to us, despite the fact
that Gold Fields had no ongoing operations and we had no prior
involvement in its past operations. Gold Fields is currently one
of our subsidiaries. We indemnified TXU Group with respect to
certain claims relating to a former affiliate of Gold Fields. A
predecessor of Gold Fields formerly operated two lead mills near
Picher, Oklahoma prior to the 1950s and
43
mined, in accordance with lease agreements and permits,
approximately 0.15% of the total amount of the crude ore mined
in the county.
Gold Fields and two other companies are defendants in two class
action lawsuits allegedly involving past operations near Picher,
Oklahoma. The plaintiffs have asserted claims predicated on
allegations of intentional lead exposure by the defendants and
are seeking compensatory damages, punitive damages and the
implementation of medical monitoring and relocation programs for
the affected individuals. Gold Fields was also a defendant,
along with other companies, in personal injury lawsuits that at
one time involved over 50 individuals, arising out of the same
lead mill operations. Gold Fields, along with the former
affiliate, has settled most of the claims in the personal injury
lawsuits and the remaining lawsuits have been dismissed with
prejudice. In December 2003, the Quapaw Indian tribe and certain
Quapaw land owners filed a lawsuit against Gold Fields, five
other companies and the United States. The plaintiffs are
seeking compensatory and punitive damages based on a variety of
theories. In December 2007, the court dismissed the tribes
medical monitoring claim. Gold Fields has filed a third-party
complaint against the United States and other parties. In
February 2005, the state of Oklahoma on behalf of itself and
several other parties sent a notice to Gold Fields and other
companies regarding a possible natural resources damage claim.
All of the lawsuits are pending in the U.S. District Court
for the Northern District of Oklahoma.
The outcome of litigation and these claims are subject to
numerous uncertainties. Based on our evaluation of the issues
and their potential impact, the amount of any future loss cannot
be reasonably estimated. However, based on current information,
we believe this matter is likely to be resolved without a
material adverse effect on our financial condition, results of
operations or cash flows.
Environmental
Claims and Litigation
Environmental claims have been asserted against Gold Fields
related to activities of Gold Fields or a former affiliate. Gold
Fields or the former affiliate has been named a potentially
responsible party (PRP) at five national priority list sites
based on the Superfund Amendments and Reauthorization Act of
1986. Claims were asserted at 12 additional sites, the total of
which have since been reduced to 12 by completion of work,
transfer or regulatory inactivity. The number of PRP sites in
and of itself is not a relevant measure of liability, because
the nature and extent of environmental concerns varies by site,
as does the estimated share of responsibility for Gold Fields or
the former affiliate. Undiscounted liabilities for environmental
cleanup-related costs for all of the sites noted above were
$42.4 million as of December 31, 2007 and
$43.0 million as of December 31, 2006,
$7.1 million and $14.4 million of which was reflected
as a current liability, respectively. These amounts represent
those costs that we believe are probable and reasonably
estimable. In September 2005, Gold Fields and other PRPs
received a letter from the U.S. Department of Justice
alleging that the PRPs mining operations caused the
Environmental Protection Agency (EPA) to incur approximately
$125 million in residential yard remediation costs at
Picher, Oklahoma and will cause the EPA to incur additional
remediation costs relating to historical mining sites. Gold
Fields has participated in the settlement discussions. Gold
Fields believes it has meritorious defenses to these claims.
Gold Fields is involved in other litigation in the Picher area,
and we indemnified TXU Group with respect to a defendant as is
more fully discussed under the Oklahoma Lead
Litigation caption above. Significant uncertainty exists
as to whether claims will be pursued against Gold Fields in all
cases, and where they are pursued, the amount of the eventual
costs and liabilities, which could be greater or less than this
provision. Based on our evaluation of the issues and their
potential impact, the amount of any future loss cannot be
reasonably estimated. However, based on current information, we
believe these claims and litigation are likely to be resolved
without a material adverse effect on our financial condition,
results of operations or cash flows.
Other
In addition, at times we become a party to other claims,
lawsuits, arbitration proceedings and administrative procedures
in the ordinary course of business in the U.S., Australia and
other countries where we do business. Based on current
information, we believe that the ultimate resolution of such
other pending or threatened proceedings is not reasonably likely
to have a material adverse effect on our financial position,
results of operations or liquidity.
44
New
York Office of the Attorney General Subpoena
The New York Office of the Attorney General sent a letter to us
dated September 14, 2007. The letter referred to our
plans to build new coal-fired electric generating
units, and said that the increase in
CO2
emissions from the operation of these units, in combination with
Peabody Energys other coal-fired power plants, will
subject Peabody Energy to increased financial, regulatory, and
litigation risks. We currently have no electrical
generating capacity in place. The letter included a subpoena
issued under New York state law, which seeks information and
documents relating to our analysis of the risks associated with
climate change and possible climate change legislation or
regulations, and our disclosure of such risks to investors. We
believe that we made full and proper disclosure of these
potential risks.
|
|
Item 4.
|
Submission
of Matters to a Vote of Security Holders.
|
No matters were submitted to a vote of security holders during
the quarter ended December 31, 2007.
Executive
Officers of the Company
Set forth below are the names, ages as of February 15, 2008
and current positions of our executive officers. Executive
officers are appointed by, and hold office at the discretion of,
our Board of Directors.
|
|
|
|
|
|
|
Name
|
|
Age
|
|
Position
|
|
Gregory H. Boyce
|
|
|
53
|
|
|
Chairman and Chief Executive Officer, Director
|
Richard A. Navarre
|
|
|
47
|
|
|
President, Chief Commercial Officer and Chief Financial Officer
|
Sharon D. Fiehler
|
|
|
51
|
|
|
Executive Vice President and Chief Administrative Officer
|
Eric Ford
|
|
|
53
|
|
|
Executive Vice President and Chief Operating Officer
|
Alexander C. Schoch
|
|
|
53
|
|
|
Executive Vice President and Chief Legal Officer
|
Roger B. Walcott, Jr.
|
|
|
51
|
|
|
Executive Vice President
|
Ian S. Craig
|
|
|
54
|
|
|
Managing Director Australia Operations
|
Kemal Williamson
|
|
|
48
|
|
|
Group Vice President U.S. Western Operations
|
Rick Bowen
|
|
|
52
|
|
|
Senior Vice President, Btu Conversion and Strategic Planning
|
Gregory H. Boyce was elected Chairman of the Board on
October 10, 2007 and has been a director of the Company
since March 2005. He was named Chief Executive Officer Elect of
the Company in March 2005, and assumed the position of Chief
Executive Officer in January 2006. He also serves as President
of the Company, a position he has held since October 2003. He
was Chief Operating Officer of the Company from October 2003 to
December 2005. He previously served as Chief
Executive Energy of Rio Tinto plc (an international
natural resource company) from 2000 to 2003. Other prior
positions include President and Chief Executive Officer of
Kennecott Energy Company from 1994 to 1999 and President of
Kennecott Minerals Company from 1993 to 1994. He has extensive
engineering and operating experience with Kennecott and also
served as Executive Assistant to the Vice Chairman of Standard
Oil of Ohio from 1983 to 1984. Mr. Boyce is Vice Chairman
of the World Coal Institute, Co-Chairman of the Coal Based
Generation Stakeholders Group, and a member of the Coal Industry
Advisory Board of the International Energy Agency, the Advisory
Council of the University of Arizonas Department of Mining
and Geological Engineering and the National Council of the
School of Engineering and Applied Science at Washington
University in St. Louis. He is a board member of the
Business Roundtable, the Center for Energy and Economic
Development, the National Mining Association and the National
Coal Council. He is a member of the Board of Trustees of the
St. Louis Childrens Hospital; the School of
Engineering and Applied Science National Council of Washington
University in St. Louis; and the Advisory Council of the
University of Arizonas Department of Mining and Geological
Engineering.
45
Richard A. Navarre was named our President and Chief Commercial
Officer in January 2008. He served as our Executive Vice
President of Corporate Development from July 2006 to January
2008 and as Chief Financial Officer since October 1999.
Mr. Navarre will continue to serve as our Chief Financial
Officer until his successor is elected. He is a member of the
Hall of Fame of the College of Business at Southern Illinois
University Carbondale, a member of the Board of Advisors of the
College of Business and Administration of Southern Illinois
University Carbondale, a member of the International Business
Advisory Board of the University of Missouri-St. Louis, a
Director of the United Way of Greater St. Louis, a Director
of the Missouri Historical Society, a member of Financial
Executives International and the Civic Entrepreneurs
Organization, and a former chairman of the Bituminous Coal
Operators Association.
Sharon D. Fiehler has been our Executive Vice President and
Chief Administrative Officer since January 2008, with executive
responsibility for employee development, benefits, compensation,
employee relations, affirmative action programs, information
services, flight services, facilities management and
procurement. From April 2002 to January 2008, she served as our
Executive Vice President of Human Resources and Administration.
Ms. Fiehler joined us in 1981 as Manager Salary
Administration and has held a series of employee relations,
compensation and salaried benefits positions. She holds degrees
in social work and psychology and a MBA, and prior to joining us
was a personnel representative for Ford Motor Company.
Ms. Fiehler is a member of the Executive Committee and
Board of Directors of Junior Achievement of St. Louis, a
Board member of the Chancellors Council of the University
of Missouri-St. Louis and a member of the Board of Trustees
of the St. Louis Zoo.
Eric Ford was named our Executive Vice President and Chief
Operating Officer in March 2007, with responsibility for all of
our global mining operations, as well as the areas of safety,
operations improvement, engineering, and technical services.
Mr. Ford has 35 years of extensive international
management, operating and engineering experience, and most
recently served as Chief Executive Officer of Anglo Coal
Australia Pty Ltd. He joined Anglo Coal in 1971 and, after a
series of increasingly complex operating assignments, was
appointed President and Chief Executive Officer of Anglo
Americans joint venture coal mining operation in Colombia
in 1998. In 2000, he returned to Anglo American Corporation as
Executive Director of Operations for Anglo Platinum Corporation
Limited. He was subsequently appointed Chief Executive Officer
of Anglo Coal Australia Pty Ltd in 2001. Mr. Ford holds a
Master of Science degree in Management Science from Imperial
College in London and a Bachelor of Science degree in Mining
Engineering (cum laude) from the University of the Witwatersrand
in Johannesburg, South Africa. He is currently Deputy Chairman
and a member of the Executive Committee of the Coal Industry
Advisory Board of the International Energy Agency, and is Vice
Chairman and Director of the Minerals Council of Australia.
Alexander C. Schoch was named our Executive Vice President and
Chief Legal Officer in October 2006, with responsibility for all
of our legal and corporate secretary functions. Prior to joining
us, Mr. Schoch served as Vice President and General Counsel
for Emerson Process Management, an operating segment of Emerson
Electric Company and leading supplier of process-automation
products. Mr. Schoch also served in several legal positions
with Goodrich Corporation, a global supplier to the aerospace
and defense industries, from 1987 to 2004, including Vice
President, Associate General Counsel and Secretary. Prior to
that, he worked for Marathon Oil Company as an attorney in its
international exploration and production division.
Mr. Schoch holds a Juris Doctorate from Case Western
Reserve University in Ohio, as well as a Bachelor of Arts in
Economics from Kenyon College in Ohio. He is admitted to
practice law in several states, and is a member of the American
and International Bar Associations.
Roger B. Walcott, Jr. became Executive Vice President in
January 2008. He served as Executive Vice President
Strategy and Business Services from May 2006 to January 2008.
Prior to that, Mr. Walcott served as our Executive Vice
President Resource Management and Strategic Planning
from July 2005 to May 2006 and as our Executive Vice
President Corporate Development from February 2001
to July 2005. He joined us in June 1998 as Executive Vice
President. From 1987 to 1998, he was a Senior Vice President and
a director with The Boston Consulting Group, where he served a
variety of clients in strategy and operational assignments. He
joined Boston Consulting Group in 1981, and was Chairman of The
Boston Consulting Groups Human Resource Capabilities
Committee. Mr. Walcott holds a MBA with high distinction
from the Harvard Business School. Mr. Walcott intends to
retire from the Company on June 1, 2008.
46
Ian S. Craig was named our Managing Director
Australia Operations in September 2004. From May 2004 to August
2004, Mr. Craig served as Group Executive
Technical Services. He was Group Executive Powder
River Basin Operations from July 2001 to April 2004. Prior to
that, he was Managing Director of a former Peabody subsidiary in
Australia. Mr. Craig also held a number of management
positions within the subsidiary company and other Australian
mining organizations. He holds a Bachelor of Applied Science
Degree in Mineral Engineering from the South Australian
Institute of Technology. Mr. Craig is a Fellow of The
Australasian Institute of Mining and Metallurgy. Mr. Craig
will retire from the Company on February 29, 2008.
Kemal Williamson became our Group Vice President
U.S. Western Operations in July 2005. After joining us in
September 2000, Mr. Williamson served as Group
Executive Midwest Operations until April 2004, and
then was Group Executive Powder River Basin
Operations until July 2005. He has extensive mining engineering
and operations experience in the United States and Australia.
Mr. Williamson holds a Bachelor of Science Degree in Mining
Engineering from Pennsylvania State University and a MBA from
Kellogg Graduate School of Management, Northwestern University.
Rick Bowen became Senior Vice President of Btu Conversion and
Strategic Planning in January 2008, with responsibility for
project and business development for planned electric generating
initiatives and projects for technologies to transform the
energy in coal into other high-demand energy forms, as well as
our strategic planning function. He served as President of
Generation and Btu Conversion from July 2006 to January 2008.
Mr. Bowen joined us in September 2004 as Corporate Senior
Vice President and President of Generation. Prior to joining us,
Mr. Bowen served for 18 years with Dynegy Inc. and its
predecessor companies. Mr. Bowen is a member of the
Industry Advisory Board and the Consortium for Electric
Reliability Technology Solutions. He is also a member of the
Board of Directors of Econo-Power International Corporation and
holds the Advisory Board seat on GreatPoint Energy.
Mr. Bowen holds a Bachelor of Science in Business
Administration and a MBA from the University of Houston.
PART II
|
|
Item 5.
|
Market
for Registrants Common Equity, Related Stockholder Matters
and Issuer Purchases of Equity Securities.
|
Our common stock is listed on the New York Stock Exchange, under
the symbol BTU. As of February 15, 2008, there
were 1,074 holders of record of our common stock.
The table below sets forth the range of quarterly high and low
sales prices for our common stock (after giving retroactive
effect to the two-for-one stock split effective
February 22, 2006) on the New York Stock Exchange
during the calendar quarters indicated.
|
|
|
|
|
|
|
|
|
|
|
High
|
|
|
Low
|
|
|
2006
|
|
|
|
|
|
|
|
|
First Quarter
|
|
$
|
52.54
|
|
|
$
|
41.24
|
|
Second Quarter
|
|
|
76.29
|
|
|
|
46.81
|
|
Third Quarter
|
|
|
59.90
|
|
|
|
32.94
|
|
Fourth Quarter
|
|
|
48.59
|
|
|
|
34.05
|
|
2007
|
|
|
|
|
|
|
|
|
First Quarter
|
|
$
|
44.60
|
|
|
$
|
36.20
|
|
Second Quarter
|
|
|
55.76
|
|
|
|
39.96
|
|
Third Quarter
|
|
|
50.99
|
|
|
|
38.42
|
|
Fourth Quarter
|
|
|
62.55
|
|
|
|
47.52
|
|
47
Dividend
Policy
We paid quarterly dividends totaling $0.24 per share during the
years ended December 31, 2007 and 2006. Most recently, our
Board of Directors declared a dividend of $0.06 per share of
Common Stock on January 29, 2008, payable on March 4,
2008, to stockholders of record on February 12, 2008. The
declaration and payment of dividends and the amount of dividends
will depend on our results of operations, financial condition,
cash requirements, future prospects, any limitations imposed by
our debt instruments and other factors deemed relevant by our
Board of Directors; however, we presently expect that dividends
will continue to be paid. Limitations on our ability to pay
dividends imposed by our debt instruments are discussed in
Item 7. Managements Discussion and Analysis of
Financial Condition and Results of Operations.
Share
Repurchases
Share
Repurchase Program
In July 2005, our Board of Directors authorized a share
repurchase program of up to 5% of the then outstanding shares of
our common stock, approximately 13.1 million shares. The
repurchases may be made from time to time based on an evaluation
of our outlook and general business conditions, as well as
alternative investment and debt repayment options. As of
December 31, 2007, there were approximately
10.9 million shares available for repurchase. There were no
share repurchases under this program in the year ended
December 31, 2007.
Share
Relinquishment
During the year ended December 31, 2007, we received
137,625 shares of common stock as consideration for
employees exercise of stock options and to pay estimated
taxes at the vesting date of restricted stock. The value of the
common stock tendered by employees to exercise stock options and
to settle taxes on restricted stock was based upon the closing
price on the dates of the respective transactions.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Number of
|
|
|
Maximum Number
|
|
|
|
Total
|
|
|
|
|
|
Shares Purchased
|
|
|
of Shares that May
|
|
|
|
Number of
|
|
|
Average
|
|
|
as Part of Publicly
|
|
|
Yet Be Purchased
|
|
|
|
Shares
|
|
|
Price per
|
|
|
Announced
|
|
|
Under the Publicly
|
|
Period
|
|
Purchased(1)
|
|
|
Share
|
|
|
Program
|
|
|
Announced Program
|
|
|
October 1 through October 31, 2007
|
|
|
78,516
|
|
|
$
|
55.30
|
|
|
|
|
|
|
|
10,920,605
|
|
November 1 through November 30, 2007
|
|
|
57,541
|
|
|
|
49.36
|
|
|
|
|
|
|
|
10,920,605
|
|
December 1 through December 31, 2007
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10,920,605
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
136,057
|
|
|
$
|
52.79
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Represents shares withheld to cover the estimated withholding
taxes at the vesting date of restricted stock. |
|
|
Item 6.
|
Selected
Financial Data.
|
The following table presents selected financial and other data
about us for the most recent five fiscal years. The following
table and the discussion of our results of operations in 2007
and 2006 in Item 7. Managements Discussion and
Analysis of Financial Condition and Results of Operations
includes references to, and analysis of, our Adjusted EBITDA
results. Adjusted EBITDA is defined as income from continuing
operations before deducting early debt extinguishment costs, net
interest expense, income taxes, minority interests, asset
retirement obligation expense and depreciation, depletion and
amortization. Adjusted EBITDA is used by management to measure
operating performance, and management also believes it is a
useful indicator of our ability to meet debt service and capital
expenditure requirements. Because Adjusted EBITDA is not
calculated identically by all companies, our calculation may not
be comparable to similarly titled measures of other companies.
The selected financial data for all periods presented reflect
the assets, liabilities and results of operations from
subsidiaries spun-off as Patriot Coal Corporation as
discontinued operations.
48
In October 2006, we acquired Excel Coal Limited and our results
of operations for the year ended December 31, 2006 included
the results of operations of the three operating mines and three
development-stage mines (all of which are operating as of
December 31, 2007) in New South Wales, Australia and
Queensland, Australia from the date of acquisition.
On April 15, 2004, we acquired three coal operations from
RAG Coal International AG. Our results of operations for the
year ended December 31, 2004 include the results of
operations of the two mines in Queensland, Australia and the
results of operations of the Twentymile Mine in Colorado from
the April 15, 2004 purchase date.
Results of operations for the year ended December 31, 2003
included early debt extinguishment costs of $53.5 million
pursuant to our debt refinancing in the first half of 2003. In
addition, results included expense relating to the cumulative
effect of accounting changes, net of income taxes, of
$10.1 million. This amount represents the aggregate amount
of the recognition of accounting changes pursuant to the
adoption of SFAS No. 143, Accounting for Asset
Retirement Obligations, the change in method of
amortization of actuarial gains and losses related to net
periodic postretirement benefit costs and the effect of the
rescission of Emerging Issues Task Force
No. 98-10,
Accounting for Contracts Involved in Energy Trading and
Risk Management Activities.
We have derived the selected historical financial data as of and
for the years ended December 31, 2007, 2006, 2005, 2004 and
2003 from our audited financial statements. You should read the
following table in conjunction with the financial statements,
the related notes to those financial statements and Item 7.
Managements Discussion and Analysis of Financial Condition
and Results of Operations.
49
The results of operations for the historical periods included in
the following table are not necessarily indicative of the
results to be expected for future periods. In addition, the Risk
Factors section of Item 1A of this report includes a
discussion of risk factors that could impact our future results
of operations.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
2003
|
|
|
|
(Dollars in thousands, except share and per share data and
tons sold)
|
|
|
Results of Operations Data
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales
|
|
$
|
4,364,708
|
|
|
$
|
4,002,403
|
|
|
$
|
3,584,422
|
|
|
$
|
2,732,972
|
|
|
$
|
2,142,767
|
|
Other revenues
|
|
|
210,004
|
|
|
|
105,993
|
|
|
|
81,754
|
|
|
|
82,186
|
|
|
|
82,783
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
|
4,574,712
|
|
|
|
4,108,396
|
|
|
|
3,666,176
|
|
|
|
2,815,158
|
|
|
|
2,225,550
|
|
Costs and Expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating costs and expenses
|
|
|
3,574,818
|
|
|
|
3,155,732
|
|
|
|
2,885,320
|
|
|
|
2,252,949
|
|
|
|
1,745,616
|
|
Depreciation, depletion and amortization
|
|
|
361,559
|
|
|
|
294,270
|
|
|
|
253,788
|
|
|
|
211,630
|
|
|
|
180,262
|
|
Asset retirement obligation expense
|
|
|
25,610
|
|
|
|
15,830
|
|
|
|
20,329
|
|
|
|
15,125
|
|
|
|
13,226
|
|
Selling and administrative expenses
|
|
|
147,146
|
|
|
|
128,031
|
|
|
|
132,679
|
|
|
|
84,534
|
|
|
|
66,688
|
|
Other operating income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net gain on disposal or exchange of assets
|
|
|
(88,684
|
)
|
|
|
(53,532
|
)
|
|
|
(44,445
|
)
|
|
|
(18,065
|
)
|
|
|
(9,382
|
)
|
(Income) loss from equity affiliates
|
|
|
(14,461
|
)
|
|
|
(22,791
|
)
|
|
|
(15,227
|
)
|
|
|
(64
|
)
|
|
|
538
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Profit
|
|
|
568,724
|
|
|
|
590,856
|
|
|
|
433,732
|
|
|
|
269,049
|
|
|
|
228,602
|
|
Interest expense
|
|
|
235,236
|
|
|
|
137,668
|
|
|
|
98,066
|
|
|
|
89,052
|
|
|
|
90,754
|
|
Early debt extinguishment costs
|
|
|
(253
|
)
|
|
|
1,396
|
|
|
|
|
|
|
|
1,751
|
|
|
|
53,513
|
|
Interest income
|
|
|
(7,094
|
)
|
|
|
(11,309
|
)
|
|
|
(9,088
|
)
|
|
|
(3,999
|
)
|
|
|
(2,126
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income From Continuing Operations Before Income Taxes and
Minority Interests
|
|
|
340,835
|
|
|
|
463,101
|
|
|
|
344,754
|
|
|
|
182,245
|
|
|
|
86,461
|
|
Income tax provision (benefit)
|
|
|
(78,112
|
)
|
|
|
(90,084
|
)
|
|
|
63,779
|
|
|
|
281
|
|
|
|
(8,017
|
)
|
Minority interests
|
|
|
(2,316
|
)
|
|
|
611
|
|
|
|
2,472
|
|
|
|
1,007
|
|
|
|
3,035
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income From Continuing Operations
|
|
|
421,263
|
|
|
|
552,574
|
|
|
|
278,503
|
|
|
|
180,957
|
|
|
|
91,443
|
|
Income (loss) from discontinued operations
|
|
|
(156,978
|
)
|
|
|
48,123
|
|
|
|
144,150
|
|
|
|
(5,570
|
)
|
|
|
(49,951
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before accounting changes
|
|
|
264,285
|
|
|
|
600,697
|
|
|
|
422,653
|
|
|
|
175,387
|
|
|
|
41,492
|
|
Cumulative effect of accounting changes
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(10,144
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income
|
|
$
|
264,285
|
|
|
$
|
600,697
|
|
|
$
|
422,653
|
|
|
$
|
175,387
|
|
|
$
|
31,348
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic Earnings Per Share From Continuing Operations
|
|
$
|
1.60
|
|
|
$
|
2.10
|
|
|
$
|
1.06
|
|
|
$
|
0.73
|
|
|
$
|
0.43
|
|
Diluted Earnings Per Share From Continuing Operations
|
|
$
|
1.56
|
|
|
$
|
2.05
|
|
|
$
|
1.04
|
|
|
$
|
0.71
|
|
|
$
|
0.42
|
|
Weighted average shares used in calculating basic earnings per
share
|
|
|
264,068,180
|
|
|
|
263,419,344
|
|
|
|
261,519,424
|
|
|
|
248,732,744
|
|
|
|
213,638,084
|
|
Weighted average shares used in calculating diluted earnings per
share
|
|
|
269,166,290
|
|
|
|
269,166,005
|
|
|
|
268,013,476
|
|
|
|
254,812,632
|
|
|
|
219,342,512
|
|
Dividends Declared Per Share
|
|
$
|
0.24
|
|
|
$
|
0.24
|
|
|
$
|
0.17
|
|
|
$
|
0.13
|
|
|
$
|
0.11
|
|
Other Data
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Tons sold (in millions)
|
|
|
237.8
|
|
|
|
223.3
|
|
|
|
216.1
|
|
|
|
202.6
|
|
|
|
182.2
|
|
Net cash provided by (used in) continuing operations:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating activities
|
|
$
|
447,181
|
|
|
$
|
591,412
|
|
|
$
|
683,804
|
|
|
$
|
454,958
|
|
|
$
|
314,819
|
|
Investing activities
|
|
|
(541,730
|
)
|
|
|
(2,061,159
|
)
|
|
|
(516,453
|
)
|
|
|
(760,880
|
)
|
|
|
(308,792
|
)
|
Financing activities
|
|
|
44,768
|
|
|
|
1,407,581
|
|
|
|
(38,876
|
)
|
|
|
577,426
|
|
|
|
39,184
|
|
Adjusted
EBITDA(1)
|
|
|
955,893
|
|
|
|
900,956
|
|
|
|
707,849
|
|
|
|
495,804
|
|
|
|
422,090
|
|
Additions to property, plant, equipment and mine development
|
|
|
470,434
|
|
|
|
397,497
|
|
|
|
450,348
|
|
|
|
115,164
|
|
|
|
81,893
|
|
Federal coal lease expenditures
|
|
|
178,193
|
|
|
|
178,193
|
|
|
|
118,364
|
|
|
|
114,653
|
|
|
|
|
|
Acquisitions, net
|
|
|
|
|
|
|
1,507,775
|
|
|
|
|
|
|
|
426,571
|
|
|
|
90,000
|
|
Balance Sheet Data (at period end)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
9,668,307
|
|
|
$
|
9,514,056
|
|
|
$
|
6,852,006
|
|
|
$
|
6,178,592
|
|
|
$
|
5,280,265
|
|
Total debt
|
|
|
3,273,100
|
|
|
|
3,277,032
|
|
|
|
1,332,047
|
|
|
|
1,362,738
|
|
|
|
1,134,161
|
|
Total stockholders equity
|
|
|
2,519,671
|
|
|
|
2,338,526
|
|
|
|
2,178,467
|
|
|
|
1,724,592
|
|
|
|
1,132,057
|
|
|
|
|
(1) |
|
Adjusted EBITDA is defined as income from continuing operations
before deducting early debt extinguishment costs, net interest
expense, income taxes, minority interests, asset retirement
obligation expense and depreciation, depletion and amortization.
Adjusted EBITDA is used by management to measure operating
performance, and management also believes it is a useful
indicator of our ability to meet debt service and capital
expenditure requirements. Because Adjusted EBITDA is not
calculated identically by all companies, our calculation may not
be comparable to similarly titled measures of other companies. |
50
Adjusted EBITDA is calculated as follows (unaudited):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
2003
|
|
|
|
(Dollars in thousands)
|
|
|
Income from continuing operations
|
|
$
|
421,263
|
|
|
$
|
552,574
|
|
|
$
|
278,503
|
|
|
$
|
180,957
|
|
|
$
|
91,443
|
|
Income tax provision (benefit)
|
|
|
(78,112
|
)
|
|
|
(90,084
|
)
|
|
|
63,779
|
|
|
|
281
|
|
|
|
(8,017
|
)
|
Depreciation, depletion and amortization
|
|
|
361,559
|
|
|
|
294,270
|
|
|
|
253,788
|
|
|
|
211,630
|
|
|
|
180,262
|
|
Asset retirement obligation expense
|
|
|
25,610
|
|
|
|
15,830
|
|
|
|
20,329
|
|
|
|
15,125
|
|
|
|
13,226
|
|
Interest expense
|
|
|
235,236
|
|
|
|
137,668
|
|
|
|
98,066
|
|
|
|
89,052
|
|
|
|
90,754
|
|
Early debt extinguishment costs
|
|
|
(253
|
)
|
|
|
1,396
|
|
|
|
|
|
|
|
1,751
|
|
|
|
53,513
|
|
Interest income
|
|
|
(7,094
|
)
|
|
|
(11,309
|
)
|
|
|
(9,088
|
)
|
|
|
(3,999
|
)
|
|
|
(2,126
|
)
|
Minority interests
|
|
|
(2,316
|
)
|
|
|
611
|
|
|
|
2,472
|
|
|
|
1,007
|
|
|
|
3,035
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted EBITDA
|
|
$
|
955,893
|
|
|
$
|
900,956
|
|
|
$
|
707,849
|
|
|
$
|
495,804
|
|
|
$
|
422,090
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Item 7.
|
Managements
Discussion and Analysis of Financial Condition and Results of
Operations.
|
Overview
We are the largest private sector coal company in the world,
with majority interests in 31 coal operations located throughout
all major U.S. coal producing regions, except Appalachia,
and international interests in Australia and Venezuela. In 2007,
we sold 237.8 million tons of coal. Our U.S. sales
represented 19% of all U.S. coal sales and were
approximately 80% greater than the sales of our closest
U.S. competitor.
United States coal demand was approximately 1.1 billion
tons in 2007, based on Energy Information Administration (EIA)
estimates. Coals predominate use is for baseload
electricity requirements. For the 12 months ended November 2007,
coals share of electricity generation was approximately
50%, a share that the EIA projects will grow to 55% by 2030. EIA
projects an additional 130 gigawatts of new
U.S. coal-fueled generation by 2030, including 9 gigawatts
at coal-to-liquids plants and 45 gigawatts at integrated
gasification combined-cycle plants, which represents more than
500 million tons of additional coal demand. Domestic coal
consumption is expected to grow at an average annual rate of
1.8% from 2007 through 2030 when U.S. coal demand is
forecasted to reach 1.7 billion tons. Coal production
located west of the Mississippi River is projected to provide
most of the incremental growth as Western production increases
to an estimated 65% share of total production in 2030 versus 58%
in 2007.
Globally, we believe that coal demand is driven by electricity
generation (65%) and industrial use (31%), including steel
making. The International Energy Agency (IEA) estimates
coals share of total world energy consumption is projected
to increase from 25% in 2005 to 28% through 2030, and in the
electric power sector, its share is estimated to rise from 43%
in 2004 to 45% in 2030. More than 80% of the growth in global
coal demand is expected to come from China and India. These two
countries comprise approximately 45% of global coal use, which
is projected by IEA to grow to 80% by 2030. China alone added an
estimated 96 gigawatts of new coal-fueled generation in 2007,
representing more than 300 million tons of annual coal use.
Coal demand in India is forecasted to nearly triple by 2030. In
total, global coal consumption is expected to grow 73%, or more
than 4 billion tons by 2030.
Our primary U.S. customers are utilities, which accounted
for 85% of our sales in 2007. Our international production is
sold primarily into export markets. Our international activities
accounted for 13% of our sales by volume in 2007. We typically
sell coal to utility customers under long-term contracts (those
with terms longer than one year). During 2007, approximately 94%
of our sales were under long-term contracts. As of
December 31, 2007, production totaled 214.1 million
tons and sales totaled 237.8 million tons. As discussed
more fully in Item 1A. Risk Factors, our results of
operations in the near-term could be negatively impacted by poor
weather conditions, unforeseen geologic conditions or equipment
problems at mining locations, and by the availability of
transportation for coal shipments. On a long-term basis, our
results of operations could
51
be impacted by our ability to secure or acquire high-quality
coal reserves, find replacement buyers for coal under contracts
with comparable terms to existing contracts, or the passage of
new or expanded regulations that could limit our ability to
mine, increase our mining costs, or limit our customers
ability to utilize coal as fuel for electricity generation. In
the past, we have achieved production levels that are relatively
consistent with our projections. However, we expect to adjust
our production levels in response to changes in market demand.
We conduct business through four principal operating segments:
Western U.S. Mining, Eastern U.S. Mining, Australian
Mining, and Trading and Brokerage. Our Western U.S. Mining
operations consist of our Powder River Basin, Southwest and
Colorado operations, and our Eastern U.S. Mining operations
consist of our Illinois and Indiana operations. The principal
business of the Western and Eastern U.S. Mining segments is
the mining, preparation and sale of steam coal, sold primarily
to electric utilities.
Geologically, Western operations mine bituminous and
subbituminous coal deposits and Eastern operations mine
bituminous coal deposits. Our Western U.S. Mining
operations are characterized by predominantly surface extraction
processes, lower sulfur content and Btu of coal, and higher
customer transportation costs (due to longer shipping
distances). Our Eastern U.S. Mining operations are
characterized by a mix of surface and underground extraction
processes, higher sulfur content and Btu of coal, and lower
customer transportation costs (due to shorter shipping
distances).
Australian Mining operations are characterized by both surface
and underground extraction processes, mining various qualities
of low-sulfur, high Btu coal (metallurgical coal) as well as
steam coal primarily sold to an international customer base with
a small portion sold to Australian steel producers and power
generators. In the second half of 2006, through two separate
transactions, we acquired Excel Coal Limited (Excel), an
independent coal company in Australia for a total acquisition
price of US$1.51 billion, net of cash received, plus
approximately $293.0 million in assumed debt. See Liquidity
and Capital Resources for information on the financing of the
Excel transaction. Assets acquired include three operating mines
and three development-stage mines, along with up to
500 million tons of proven and probable coal reserves.
We own a 25.5% interest in Carbones del Guasare, which owns and
operates the Paso Diablo Mine in Venezuela. The Paso Diablo Mine
produces approximately 6 to 8 million tons of steam coal
annually for export to the United States and Europe. During
2007, the Paso Diablo Mine contributed $21.2 million to
segment Adjusted EBITDA in Corporate and Other Adjusted
EBITDA and paid a dividend of $12.9 million. At
December 31, 2007, our investment in Paso Diablo was
$68.4 million.
Metallurgical coal is produced primarily from four of our
Australian mines. Metallurgical coal is approximately 4% of our
total sales volume, but represents a larger share of our
revenue, approximately 15% in 2007.
In addition to our mining operations, which comprised 92% of
revenues in 2007, we generate revenues and additional cash flows
from our Trading and Brokerage operations (7% of revenues), and
other activities, including transactions utilizing our vast
natural resource position (selling non-core land holdings and
mineral interests).
We continue to pursue the development of coal-fueled generating
projects in areas of the U.S. where electricity demand is
strong and where there is access to land, water, transmission
lines and low-cost coal. The projects involve mine-mouth
generating plants using our surface lands and coal reserves. Our
ultimate role in these projects could take numerous forms,
including, but not limited to, equity partner, contract miner or
coal sales. We own 5.06% of the 1,600-megawatt Prairie State
Energy Campus that is under construction in Washington County,
Illinois. We are pursuing development of the 1,500-megawatt
Thoroughbred Energy Campus in Muhlenberg County, Kentucky. The
plants, assuming all necessary permits and financing are
obtained and following selection of partners and sale of a
majority of the output of each plant, could be operational
following a four-year construction phase.
The EIA projects that the high price of oil will lead to an
increase in demand for unconventional sources of transportation
fuel, including Btu Conversion technologies, and that coal will
increase its share as a fuel for electricity generation. We are
exploring several Btu Conversion projects, which are designed to
expand the
52
uses of coal through various technologies, and we are continuing
to explore options particularly as they relate to Btu Conversion
technologies such as coal-to-liquids and coal gasification.
In July 2005, our Board of Directors authorized a share
repurchase program of up to 5% of the outstanding shares of our
common stock. The repurchases may be made from time to time
based on an evaluation of our outlook and general business
conditions, as well as alternative investment and debt repayment
options. In 2006, we repurchased 2.2 million of our common
shares for $99.8 million under this repurchase program.
On October 31, 2007, we spun-off portions of our Eastern
U.S. Mining operations business segment to
form Patriot. We distributed Patriot stock to our
stockholders at a ratio of one share of Patriot stock for every
10 shares of Peabody stock held on the record date of
October 22, 2007. Our results for all periods presented
reflect Patriot as a discontinued operation. The spin-off
included eight company-operated mines, two majority-owned joint
venture mines, and numerous contractor operated mines serviced
by eight coal preparation facilities along with 1.2 billion
tons of proven and probable coal reserves. Prior to the
spin-off, we received necessary regulatory approvals including a
private letter ruling on the tax-free nature of the transaction
from the Internal Revenue Service.
Results
of Operations
The portions of the Eastern U.S. Mining operations business
segment that were included in the spin-off of Patriot have been
classified as discontinued operations and are excluded from the
operating results for all periods presented. See the description
of the spin-off in Part I, Item 1 Discontinued
Operations.
Adjusted
EBITDA
The discussion of our results of operations below includes
references to and analysis of our segments Adjusted EBITDA
results. Adjusted EBITDA is defined as income from continuing
operations before deducting early debt extinguishment costs, net
interest expense, income taxes, minority interests, asset
retirement obligation expense and depreciation, depletion and
amortization. Adjusted EBITDA is used by management to measure
our segments operating performance, and management also
believes it is a useful indicator of our ability to meet debt
service and capital expenditure requirements. Because Adjusted
EBITDA is not calculated identically by all companies, our
calculation may not be comparable to similarly titled measures
of other companies. Adjusted EBITDA is reconciled to its most
comparable measure, under generally accepted accounting
principles, in Note 24 to our consolidated financial
statements.
Year
Ended December 31, 2007 Compared to Year Ended
December 31, 2006
Summary
Higher average sales prices across all U.S. regions and
increased volumes, primarily from Australian Mining operations,
contributed to an 11.4% increase in revenues to
$4.57 billion compared to 2006. Segment Adjusted EBITDA
increased 3.4% to $1.06 billion primarily on higher prices
in the Western U.S. and increased results from Trading and
Brokerage operations. Increases in sales volumes and prices in
our U.S. mining operations were partially offset by
challenges experienced during the period such as ongoing
shipping constraints from port congestion in Australia; geologic
and equipment issues, higher commodity costs, as well as a
weaker U.S. dollar against the Australian Dollar. Also,
negatively impacting Australian Mining results was lower
metallurgical coal prices associated with annual contracts that
began in April 2007. Income from continuing operations was
$421.3 million in 2007, or $1.56 per diluted share, a
decrease of 23.8% from 2006 income from continuing operations of
$552.6 million, or $2.05 per diluted share.
53
Tons
Sold
The following table presents tons sold by operating segment for
the years ended December 31, 2007 and 2006:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
Increase
|
|
|
|
2007
|
|
|
2006
|
|
|
Tons
|
|
|
%
|
|
|
|
(Tons in millions)
|
|
|
Western U.S. Mining Operations
|
|
|
161.4
|
|
|
|
160.5
|
|
|
|
0.9
|
|
|
|
0.6
|
%
|
Eastern U.S. Mining Operations
|
|
|
30.9
|
|
|
|
30.4
|
|
|
|
0.5
|
|
|
|
1.6
|
%
|
Australian Mining Operations
|
|
|
21.4
|
|
|
|
11.0
|
|
|
|
10.4
|
|
|
|
94.5
|
%
|
Trading and Brokerage Operations
|
|
|
24.1
|
|
|
|
21.4
|
|
|
|
2.7
|
|
|
|
12.6
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total tons sold
|
|
|
237.8
|
|
|
|
223.3
|
|
|
|
14.5
|
|
|
|
6.5
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues
The following table presents revenues for the years ended
December 31, 2007 and 2006:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Increase (Decrease)
|
|
|
|
Year Ended December 31,
|
|
|
to Revenues
|
|
|
|
2007
|
|
|
2006
|
|
|
$
|
|
|
%
|
|
|
|
(Dollars in thousands)
|
|
|
Western U.S. Mining Operations
|
|
$
|
2,061,265
|
|
|
$
|
1,703,445
|
|
|
$
|
357,820
|
|
|
|
21.0
|
%
|
Eastern U.S. Mining Operations
|
|
|
984,841
|
|
|
|
905,743
|
|
|
|
79,098
|
|
|
|
8.7
|
%
|
Australian Mining Operations
|
|
|
1,161,093
|
|
|
|
843,194
|
|
|
|
317,899
|
|
|
|
37.7
|
%
|
Trading and Brokerage Operations
|
|
|
320,692
|
|
|
|
652,029
|
|
|
|
(331,337
|
)
|
|
|
(50.8
|
)%
|
Other
|
|
|
46,821
|
|
|
|
3,985
|
|
|
|
42,836
|
|
|
|
1074.9
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
$
|
4,574,712
|
|
|
$
|
4,108,396
|
|
|
$
|
466,316
|
|
|
|
11.4
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
In 2007, our total revenues were $4.57 billion, an increase
of $466.3 million, or 11.4%, compared to the prior year,
which resulted from sales price increases in all
U.S. regions, most notably in our Powder River Basin
operations and increased volumes from Australia. Volumes related
to operations acquired in the October 2006 Excel acquisition
accounted for 10.9 million tons of the increase to tons
sold. Partially offsetting sales price and volume increases was
the continued shift towards trading contracts versus brokerage
contracts in our Trading and Brokerage operations. Trading and
Brokerage operations sales decreased during the year as
the amount of brokerage business was reduced and replacement
business was in the form of traded contracts. Contracts for
trading activity are recorded at net margin in other revenues,
whereas contracts for brokerage activity are recorded at gross
sales price to revenues and operating costs. While the shift to
trading contracts reduced total sales, there was no impact to
Adjusted EBITDA.
Overall, prices in our Western U.S. Mining operations
increased due to a sales realization increase of approximately
29% for our premium Powder River Basin product and an average
increase across all U.S. regions of 16%. In addition,
Eastern U.S. Mining revenues increased due to higher
revenues from coal sold to synthetic fuel plants as those plants
were idled for part of 2006. Offsetting this increase was lower
average sales prices in our Australian Mining operations related
to lower metallurgical contract pricing and a significant change
in sales mix resulting in higher thermal export and domestic
product sales. Volumes were unfavorably impacted at some of our
Australian Mining operations as a result of damaged rails and
further amplified port and rail congestion throughout the year,
in addition to adverse weather events in the second quarter that
affected production.
54
Segment
Adjusted EBITDA
Our total segment Adjusted EBITDA was $1.06 billion for the
year ended 2007, compared with $1.03 billion in the prior
year. Details were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Increase (Decrease) to
|
|
|
|
Year Ended December 31,
|
|
|
Segment Adjusted EBITDA
|
|
|
|
2007
|
|
|
2006
|
|
|
$
|
|
|
%
|
|
|
|
|
|
|
(Dollars in thousands)
|
|
|
|
|
|
Western U.S. Mining Operations
|
|
$
|
597,333
|
|
|
$
|
473,074
|
|
|
$
|
124,259
|
|
|
|
26.3
|
%
|
Eastern U.S. Mining Operations
|
|
|
196,595
|
|
|
|
184,549
|
|
|
|
12,046
|
|
|
|
6.5
|
%
|
Australian Mining Operations
|
|
|
159,473
|
|
|
|
278,411
|
|
|
|
(118,938
|
)
|
|
|
(42.7
|
)%
|
Trading and Brokerage Operations
|
|
|
110,169
|
|
|
|
92,604
|
|
|
|
17,565
|
|
|
|
19.0
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Segment Adjusted EBITDA
|
|
$
|
1,063,570
|
|
|
$
|
1,028,638
|
|
|
$
|
34,932
|
|
|
|
3.4
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted EBITDA from our Western U.S. Mining operations
increased $124.3 million, or 26.3%, during the year
primarily related to the overall increase in average sales
prices from our Powder River Basin operations. Partially
offsetting higher average sales prices were higher costs
associated with equipment repairs and maintenance and higher
add-on taxes and royalties driven by higher sales prices
compared to the prior year, mine shutdown for maintenance in our
Colorado region in December, higher fuel costs and adverse
weather conditions in the Powder River Basin and capital project
delays in the first half of the year.
Eastern U.S. Mining operations Adjusted EBITDA
increased $12.0 million, or 6.5%, compared to prior year as
both volumes and prices per ton saw moderate increases. Results
improved compared to prior year as benefits of higher volumes
and sales prices were offset by higher costs for commodities,
including fuel. The 2007 results were also positively impacted
by higher revenues from coal sold to synthetic fuel facilities
of $12.5 million as customers idled their synthetic fuel
plants for a portion of 2006.
Our Australian Mining operations Adjusted EBITDA decreased
$118.9 million, or 42.7%, compared to prior year primarily
due to approximately $31 million of higher costs resulting
from the weakening U.S. dollar (higher costs of
approximately $112 million were offset by hedging gains of
$81 million); higher congestion-related demurrage costs
(approximately $50 million); lower pricing on annually
repriced metallurgical coal contracts; and, rail and port
congestion at Dalrymple Bay Coal Terminal and the Port of
Newcastle. Dalrymple Bay Coal Terminal has been experiencing
queues of over 41 vessels (approximately a
24-day load
time) down from 50 vessels in the second quarter
(approximately a
34-day
delay). Partially offsetting these decreases were the full year
contributions from our mines acquired in the Excel acquisition
and a $6.3 million insurance recovery on a business
interruption claim in the first half of 2007. Our Australian
mines acquired in 2006 experienced shipping difficulties and
damaged rail lines resulting from a storm late in the second
quarter. The Port of Newcastle was closed for several days in
June due to a storm, with up to 79 vessels in the queue (a
35-40 day
wait). Queues at Newcastle have recently been reduced to
31 vessels
(11-day
wait).
Trading and Brokerage operations Adjusted EBITDA increased
$17.6 million from the prior year, as 2007 results
reflected higher international trading gains, resulting from
higher volumes and pricing due to expanded global trading
activities, strong supply/demand fundamentals and tightened
seaborne market conditions.
55
Income
From Continuing Operations Before Income Taxes and Minority
Interests
The following table presents income before income taxes and
minority interests for the years ended December 31, 2007
and 2006:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Increase (Decrease)
|
|
|
|
Year Ended December 31,
|
|
|
to Income
|
|
|
|
2007
|
|
|
2006
|
|
|
$
|
|
|
%
|
|
|
|
|
|
|
(Dollars in thousands)
|
|
|
|
|
|
Total Segment Adjusted EBITDA
|
|
$
|
1,063,570
|
|
|
$
|
1,028,638
|
|
|
$
|
34,932
|
|
|
|
3.4
|
%
|
Corporate and Other Adjusted EBITDA
|
|
|
(107,677
|
)
|
|
|
(127,682
|
)
|
|
|
20,005
|
|
|
|
15.7
|
%
|
Depreciation, depletion and amortization
|
|
|
(361,559
|
)
|
|
|
(294,270
|
)
|
|
|
(67,289
|
)
|
|
|
(22.9
|
)%
|
Asset retirement obligation expense
|
|
|
(25,610
|
)
|
|
|
(15,830
|
)
|
|
|
(9,780
|
)
|
|
|
(61.8
|
)%
|
Interest expense and early debt extinguishment costs
|
|
|
(234,983
|
)
|
|
|
(139,064
|
)
|
|
|
(95,919
|
)
|
|
|
(69.0
|
)%
|
Interest income
|
|
|
7,094
|
|
|
|
11,309
|
|
|
|
(4,215
|
)
|
|
|
(37.3
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from continuing operations before income taxes and
minority interests
|
|
$
|
340,835
|
|
|
$
|
463,101
|
|
|
$
|
(122,266
|
)
|
|
|
(26.4
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from continuing operations before income taxes and
minority interests of $340.8 million for 2007 is
$122.3 million, or 26.4%, lower than 2006 primarily due to
higher interest expense and higher depreciation, depletion and
amortization related to the acquisition of Excel in late 2006.
Corporate and Other Adjusted EBITDA results include selling and
administrative expenses, equity income from our joint venture,
net gains on asset disposals or exchanges, costs associated with
past mining obligations and revenues and expenses related to our
other commercial activities such as coalbed methane, generation
development, Btu Conversion and resource management. The
$20.0 million improvement in Corporate and Other Adjusted
EBITDA (net expense) in 2007 compared to 2006 includes the
following:
|
|
|
|
|
Higher gains on asset disposals and exchanges of
$35.2 million. The 2007 activity included a gain of
$26.4 million on the sale of approximately 172 million
tons of coal reserves to the Prairie State equity partners. Our
2007 activity also included a gain of $50.5 million on the
exchange of our coalbed methane and oil and gas rights in the
Illinois Basin, West Virginia, New Mexico and the Powder River
Basin for
high-Btu
coal reserves located in West Virginia and Kentucky and cash
proceeds. In comparison, the 2006 activity included a
$39.2 million gain on an exchange with the Bureau of Land
Management of approximately 63 million tons of leased coal
reserves at our Caballo mining operation for approximately
46 million tons of coal reserves contiguous with our North
Antelope Rochelle mining operation and other gains on asset
disposals totaling $14.3 million;
|
|
|
|
Higher past mining obligation expenses of $15.5 million
resulting from increased retiree healthcare costs due to higher
than anticipated healthcare utilization by retirees,
particularly related to prescription drugs;
|
|
|
|
Higher selling and administrative expenses of $19.1 million
during the year primarily resulting from the implementation of a
new enterprise resource planning system and other corporate
development initiatives; and
|
|
|
|
Lower equity income of $6.8 million from our 25.5% interest
in Carbones del Guasare (owner and operator of the Paso Diablo
Mine in Venezuela), which primarily resulted from trucking
issues experienced earlier in the year, a temporary shortage of
explosives, and delays in receiving equipment, which impacted
operations.
|
Depreciation, depletion and amortization increased
$67.3 million primarily related to the addition of the
Australian operations acquired in late 2006.
Interest expense and early debt extinguishment costs increased
$95.9 million primarily due to approximately
$1.8 billion in new debt issued or assumed as part of the
Excel acquisition in the second half of 2006.
56
Net
Income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Increase (Decrease)
|
|
|
|
Year Ended December 31,
|
|
|
to Income
|
|
|
|
2007
|
|
|
2006
|
|
|
$
|
|
|
%
|
|
|
|
|
|
|
(Dollars in thousands)
|
|
|
|
|
|
Income from continuing operations before income taxes and
minority interests
|
|
$
|
340,835
|
|
|
$
|
463,101
|
|
|
$
|
(122,266
|
)
|
|
|
(26.4
|
)%
|
Income tax benefit
|
|
|
78,112
|
|
|
|
90,084
|
|
|
|
(11,972
|
)
|
|
|
(13.3
|
)%
|
Minority interests
|
|
|
2,316
|
|
|
|
(611
|
)
|
|
|
2,927
|
|
|
|
479.1
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from continuing operations
|
|
|
421,263
|
|
|
|
552,574
|
|
|
|
(131,311
|
)
|
|
|
(23.8
|
)%
|
Income (loss) from discontinued operations
|
|
|
(156,978
|
)
|
|
|
48,123
|
|
|
|
(205,101
|
)
|
|
|
(426.2
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
264,285
|
|
|
$
|
600,697
|
|
|
$
|
(336,412
|
)
|
|
|
(56.0
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from continuing operations decreased $131.3 million
in 2007 compared to prior year due to the decrease in income
from continuing operations before income taxes and minority
interests discussed above and a lower income tax benefit
compared to 2006. The decrease in the income tax benefit for the
year ended 2007 related primarily to a $56.0 million
foreign currency impact on deferred taxes as a result of
increases in Australian dollar/U.S. dollar exchange rates
and $33.2 million lower tax reserves than in the prior
year, partially offset by lower pre-tax income, a
$10.3 million increase in released valuation allowances,
and $24.3 million of additional tax credits. Minority
interests increased primarily from the absorption of losses in
excess of the minority interest capital contribution at one of
our mines, partially offset by lower earnings allocable to
partners.
Year
Ended December 31, 2006 Compared to Year Ended
December 31, 2005
Summary
Higher average sales prices and increased volumes in the Eastern
U.S., Powder River Basin and Australian Mining operations,
including the October 2006 acquisition of three mines in
Australia, contributed to a 12.1% increase in revenues to
$4.11 billion compared to 2005. Segment Adjusted EBITDA
increased 17.8% to $1.03 billion primarily on growth in
international volumes and higher sales prices from our
Australian Mining operations and increased contributions from
Trading and Brokerage operations. Increases in sales volumes and
prices in our U.S. mining operations were partially offset
by operational challenges experienced during the period such as
ongoing shipping constraints from rail performance in the Powder
River Basin and port congestion in Australia; geologic and
equipment issues as well as mine closures in our Western
U.S. Mining operations in late 2005. Net income was
$600.7 million in 2006, or $2.23 per diluted share, an
increase of 42.1% over 2005 net income of
$422.7 million, or $1.58 per diluted share.
Tons
Sold
The following table presents tons sold by operating segment for
the years ended December 31, 2006 and 2005:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
Increase (Decrease)
|
|
|
|
2006
|
|
|
2005
|
|
|
Tons
|
|
|
%
|
|
|
|
(Tons in millions)
|
|
|
Western U.S. Mining Operations
|
|
|
160.5
|
|
|
|
154.3
|
|
|
|
6.2
|
|
|
|
4.0
|
%
|
Eastern U.S. Mining Operations
|
|
|
30.4
|
|
|
|
28.7
|
|
|
|
1.7
|
|
|
|
5.9
|
%
|
Australian Mining Operations
|
|
|
11.0
|
|
|
|
8.3
|
|
|
|
2.7
|
|
|
|
32.5
|
%
|
Trading and Brokerage Operations
|
|
|
21.4
|
|
|
|
24.8
|
|
|
|
(3.4
|
)
|
|
|
(13.7
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total tons sold
|
|
|
223.3
|
|
|
|
216.1
|
|
|
|
7.2
|
|
|
|
3.3
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
57
Revenues
The table below presents revenues for the years ended
December 31, 2006 and 2005:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
Increase (Decrease)
|
|
|
|
2006
|
|
|
2005
|
|
|
$
|
|
|
%
|
|
|
|
|
|
|
(Dollars in thousands)
|
|
|
|
|
|
Western U.S. Mining Operations
|
|
$
|
1,703,445
|
|
|
$
|
1,611,587
|
|
|
$
|
91,858
|
|
|
|
5.7
|
%
|
Eastern U.S. Mining Operations
|
|
|
905,743
|
|
|
|
760,404
|
|
|
|
145,339
|
|
|
|
19.1
|
%
|
Australian Mining Operations
|
|
|
843,194
|
|
|
|
598,085
|
|
|
|
245,109
|
|
|
|
41.0
|
%
|
Trading and Brokerage Operations
|
|
|
652,029
|
|
|
|
679,176
|
|
|
|
(27,147
|
)
|
|
|
(4.0
|
)%
|
Other
|
|
|
3,985
|
|
|
|
16,924
|
|
|
|
(12,939
|
)
|
|
|
(76.5
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
$
|
4,108,396
|
|
|
$
|
3,666,176
|
|
|
$
|
442,220
|
|
|
|
12.1
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
In 2006, our total revenues were $4.11 billion, an increase
of $442.2 million, or 12.1%, compared to prior year, which
resulted from sales price increases in all regions, particularly
in our Eastern and Australian operations and demand-driven sales
volume increases in the Powder River Basin, Midwest and
Australian operations. Volumes related to the October 2006 Excel
acquisition accounted for 2.1 million tons of the increase
to tons sold and approximately 43% of the increase to sales in
Australia. Partially offsetting sales price increases were lower
western regional sales due to the late 2005 mine closures in the
Western U.S. Mining operations and lower brokerage volumes.
Overall, prices and volumes in our Western U.S. Mining
operations increased, mainly reflecting increases to sales
prices of over $0.70 per ton and volumes of 12.7 million
tons in the Powder River Basin. These increases at our Powder
River Basin operations resulted from strong demand for the
mines low-sulfur products and improved rail conditions
compared to 2005, when the region was dealing with major
railroad maintenance. Despite rail performance improvements
relative to 2005, constrained rail capacity continued to limit
growth in the region in 2006.
Also, affecting Western U.S. Mining revenues was lower
production due to the cessation of mining operations at our
Seneca and Black Mesa mines in late 2005 and unfavorable
geologic conditions and equipment issues at our Twentymile Mine.
Per ton sales prices in our Eastern U.S. Mining operations
increased and sales volumes increased due primarily to our
Gateway mine, which began operation in late 2005. Partially
offset by the overall increase in 2006 total revenues was the
customer idling of synfuel plants during 2006.
Revenues from our Australian Mining operations were
$245.1 million, or 41.0%, higher than in 2005, primarily
due to higher international metallurgical coal prices, higher
production at our underground mine following installation of a
new longwall in the second quarter of 2006 and additional
volumes from our newly acquired mines ($105.1 million). A
higher per ton sales price reflected higher contract prices in
2006 for metallurgical coal as well as the slower realization of
metallurgical coal price increases in 2005 when we operated
under some lower priced carry-over contracts from 2004 through
most of the first nine months of 2005.
Brokerage operations revenues decreased $27.1 million
in 2006 compared to 2005 due to lower sales volumes, partially
offset by higher sales prices and proceeds of $28.2 million
from settlement of commitments by a third-party coal producer
following a brokerage contract restructuring.
58
Segment
Adjusted EBITDA
Our total segment Adjusted EBITDA was $1.03 billion for the
year ended 2006 compared with $873.5 million in 2005.
Details were as follows:
Segment
Adjusted EBITDA
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Increase to Segment
|
|
|
|
Year Ended December 31,
|
|
|
Adjusted EBITDA
|
|
|
|
2006
|
|
|
2005
|
|
|
$
|
|
|
%
|
|
|
|
|
|
|
(Dollars in thousands)
|
|
|
|
|
|
Western U.S. Mining Operations
|
|
$
|
473,074
|
|
|
$
|
459,039
|
|
|
$
|
14,035
|
|
|
|
3.1
|
%
|
Eastern U.S. Mining Operations
|
|
|
184,549
|
|
|
|
168,793
|
|
|
|
15,756
|
|
|
|
9.3
|
%
|
Australian Mining Operations
|
|
|
278,411
|
|
|
|
202,582
|
|
|
|
75,829
|
|
|
|
37.4
|
%
|
Trading and Brokerage Operations
|
|
|
92,604
|
|
|
|
43,058
|
|
|
|
49,546
|
|
|
|
115.1
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Segment Adjusted EBITDA
|
|
$
|
1,028,638
|
|
|
$
|
873,472
|
|
|
$
|
155,166
|
|
|
|
17.8
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted EBITDA from our Western U.S. Mining operations
increased $14.0 million, or 3.1%, during 2006 primarily
reflecting an increase in sales volumes of 12.7 million
tons at our Powder River Basin operations, which resulted from
continued strong demand and improved rail performance relative
to 2005. Western U.S. Mining operations sales price per ton
increased moderately due to mix changes resulting from ceasing
operations at our Black Mesa and Seneca mines. Western
U.S. Mining operations cost increases were driven by higher
fuel costs, an increase in revenue-based royalties and
production taxes, and the timing of major repairs. In addition,
we experienced unfavorable geologic conditions and equipment
issues related to the new longwall system at our Twentymile
Mine; however, a recovery of certain costs associated with the
equipment difficulties lessened the impact of these issues on
our 2006 results. The Western U.S. Mining operations were
also negatively impacted in 2006 by the cessation of operations
at the Black Mesa mine in late 2005.
Eastern U.S. Mining operations Adjusted EBITDA
increased $15.8 million, or 9.3%, compared to 2005
primarily due to higher volumes and sales prices, partially
offset by higher costs per ton due to fuel costs, revenue-based
royalties and production taxes as well as higher costs
associated with equipment and geologic issues. The 2006 results
were also negatively impacted by lower revenues from synthetic
fuel facilities of $10.1 million as customers idled their
synthetic fuel plants.
Our Australian Mining operations Adjusted EBITDA increased
$75.8 million, or 37.4%, compared to 2005 primarily due to
increased sales volumes following increased production from the
second quarter installation of a new longwall system at our
underground mine, higher metallurgical coal sales prices, and a
$19.7 million contribution from our newly acquired mines.
Trading and Brokerage operations Adjusted EBITDA increased
$49.5 million from 2005, as 2006 results included proceeds
from restructuring the brokerage contract mentioned above,
improved brokerage margins and contributions from the newly
established international trading operation, partially offset by
lower U.S. trading results.
59
Income
From Continuing Operations Before Income Taxes and Minority
Interests
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Increase (Decrease)
|
|
|
|
Year Ended December 31,
|
|
|
to Income
|
|
|
|
2006
|
|
|
2005
|
|
|
$
|
|
|
%
|
|
|
|
|
|
|
(Dollars in thousands)
|
|
|
|
|
|
Total Segment Adjusted EBITDA
|
|
$
|
1,028,638
|
|
|
$
|
873,472
|
|
|
$
|
155,166
|
|
|
|
17.8
|
%
|
Corporate and Other Adjusted EBITDA
|
|
|
(127,682
|
)
|
|
|
(165,623
|
)
|
|
|
37,941
|
|
|
|
22.9
|
%
|
Depreciation, depletion and amortization
|
|
|
(294,270
|
)
|
|
|
(253,788
|
)
|
|
|
(40,482
|
)
|
|
|
(16.0
|
)%
|
Asset retirement obligation expense
|
|
|
(15,830
|
)
|
|
|
(20,329
|
)
|
|
|
4,499
|
|
|
|
22.1
|
%
|
Interest expense and early debt extinguishment costs
|
|
|
(139,064
|
)
|
|
|
(98,066
|
)
|
|
|
(40,998
|
)
|
|
|
(41.8
|
)%
|
Interest income
|
|
|
11,309
|
|
|
|
9,088
|
|
|
|
2,221
|
|
|
|
24.4
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from continuing operations before income taxes and
minority interests
|
|
$
|
463,101
|
|
|
$
|
344,754
|
|
|
$
|
118,347
|
|
|
|
34.3
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from continuing operations before income taxes and
minority interests of $463.1 million for 2006 is
$118.3 million, or 34.3%, higher than 2005 primarily due to
improved segment Adjusted EBITDA as discussed above.
Corporate and Other Adjusted EBITDA results include selling and
administrative expenses, equity income from our joint ventures,
net gains on asset disposals or exchanges, costs associated with
past mining obligations and revenues and expenses related to our
other commercial activities such as coalbed methane, generation
development, Btu Conversion and resource management. The
$37.9 million improvement in Corporate and Other Adjusted
EBITDA (net expense) in 2006 compared to 2005 includes the
following:
|
|
|
|
|
Higher gains on asset disposals and exchanges of
$9.1 million. The 2006 activity included a
$39.2 million gain on an exchange with the Bureau of Land
Management of approximately 63 million tons of leased coal
reserves at our Caballo mining operation for approximately
46 million tons of coal reserves contiguous with our North
Antelope Rochelle mining operation and other gains on asset
disposals totaling $14.3 million. In comparison, activity
in 2005 included a $31.1 million gain from the sale of our
remaining 0.838 million units of Penn Virginia Resource
Partners, L.P., a $12.5 million gain from the sale of
non-strategic coal reserves and properties, and other gains on
asset disposals of $0.8 million;
|
|
|
|
Higher equity income of $8.0 million from our 25.5%
interest in Carbones del Guasare, which owns and operates the
Paso Diablo Mine in Venezuela;
|
|
|
|
Lower selling and administrative expenses of $4.6 million
primarily associated with lower performance-based incentive
costs, partially offset by increases to share-based compensation
expense as a result of the new requirement to expense stock
options, costs to support corporate and international growth
initiatives and costs for the development and installation of a
new enterprise resource planning system. The lower costs
associated with the performance-based incentive plan related to
a long-term, executive incentive plan that is driven by
shareholder return and reflected lower stock price appreciation
in 2006 than in 2005; and
|
|
|
|
Lower net expenses of $4.7 million related to the
development of the Prairie State Energy Campus due to a higher
rate of cost reimbursement from the partners in 2006.
|
Depreciation, depletion and amortization increased
$40.5 million in 2006 due to higher production volume,
acquisitions and the impact of escalating capital costs and new
capital, including two new longwall installations and new mine
development. Also, 2005 depreciation, depletion and amortization
was net of amortization of acquired contract liabilities.
Interest expense and early debt extinguishment costs increased
$41.0 million primarily due to approximately
$1.8 billion of debt issued or assumed in the second half
of 2006 as part of the Excel acquisition. See Liquidity and
Capital Resources for more details of the debt issued.
60
Net
Income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Increase (Decrease)
|
|
|
|
Year Ended December 31,
|
|
|
to Income
|
|
|
|
2006
|
|
|
2005
|
|
|
$
|
|
|
%
|
|
|
|
|
|
|
(Dollars in thousands)
|
|
|
|
|
|
Income from continuing operations before income taxes and
minority interests
|
|
$
|
463,101
|
|
|
$
|
344,754
|
|
|
$
|
118,347
|
|
|
|
34.3
|
%
|
Income tax benefit (provision)
|
|
|
90,084
|
|
|
|
(63,779
|
)
|
|
|
153,863
|
|
|
|
241.2
|
%
|
Minority interests
|
|
|
(611
|
)
|
|
|
(2,472
|
)
|
|
|
1,861
|
|
|
|
75.3
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from continuing operations
|
|
|
552,574
|
|
|
|
278,503
|
|
|
|
274,071
|
|
|
|
98.4
|
%
|
Income from discontinued operations
|
|
|
48,123
|
|
|
|
144,150
|
|
|
|
(96,027
|
)
|
|
|
(66.6
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
600,697
|
|
|
$
|
422,653
|
|
|
$
|
178,044
|
|
|
|
42.1
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from continuing operations increased $274.1 million
in 2006 compared to 2005 due to the increase in income from
continuing operations before income taxes and minority interests
discussed above and an income tax benefit compared to an income
tax provision in 2005. The income tax benefit for the year ended
2006 related primarily to a reduction in tax reserves no longer
required due to the finalization of various federal and state
returns and expiration of applicable statute of limitations, and
a reduction in a portion of the valuation allowance related to
net operating loss (NOL) carry-forwards. The reduction to the
valuation allowance resulted from an increase to estimated
future taxable income primarily resulting from long-term
contracts signed in late 2006 which increased our ability to
realize these benefits in the future. Minority interests
increased primarily as a result of acquiring an additional
interest in a joint venture near the end of the first quarter of
2006.
Outlook
Events
Impacting Near-Term Operations
Global coal markets continued to grow, driven by increased
demand from growing and developing economies. The
U.S. economy grew 2.2% for 2007 as reported by the
U.S. Commerce Department, while Chinas economy grew
11.4% in 2007 as published by the National Bureau of Statistics
of China.
Growing constraints of global coal supplies ignited
U.S. coal export interests beginning in the third quarter
of 2007. By the start of 2008, global supply challenges became
even greater. Flooding in Queensland, Australia in early 2008 is
estimated to reduce seaborne coal supplies by more than
10 million metric tons; China issued a temporary moratorium
on 2008 coal exports to secure supply for domestic needs, and
South Africa temporarily shutdown coal production destined for
export markets to conserve energy while reestablishing
sufficient domestic coal supply. As a result, U.S. coal
products are realizing expanded market reach resulting in higher
published prices for all products. We expect to capitalize on
the strong global markets primarily through production and sales
of metallurgical and thermal coal from our Australian operations
as well as through our U.S. and international coal trading
activities.
In Australia, we anticipate selling 23 to 25 million tons
in 2008, as much as 17% higher than 2007s level. Of our
anticipated shipments, we have nine to 10 million tons of
coal production available to be priced in 2008, approximately
two-thirds of which is metallurgical coal. Our 2008 results will
be affected by the final Australian coal price settlements. Our
two primary shipping points, Dalrymple Bay Coal Terminal and
Port of Newcastle, continue to experience lengthy vessel queues,
extreme weather conditions impacting operations and the coal
logistics chain, and transportation challenges, which could
result in delayed shipments and demurrage charges.
In the U.S., we anticipate higher volumes in 2008 versus 2007
from all the coal basins where we operate. Approximately 97% of
our higher 2008 volumes are committed to existing customer
contracts. In addition, the higher 2008 volume includes the
mid-year startup of a new mine in the Southwestern U.S. Our
2008 results will be impacted to the extent we complete
ramp-up
activities on time and at expected capacity. Although we
61
currently expect to increase our shipment levels, our ability to
reach targeted volumes is dependent upon the performance of the
rail carriers.
We expect strong improvements in U.S. and Australia
operating results from higher prices and increased volumes,
partly offset by some of the factors discussed above and
escalation of key supply costs including approximately
$150 million in higher energy-related expenses and the
effects of exchange rates.
Long-term
Outlook
Our outlook for the coal markets remains positive. We believe
strong coal markets will continue worldwide, as long as growth
continues in the U.S., Asia and other industrialized economies
that are increasing coal demand for electricity generation and
steelmaking. More than 100 gigawatts of new coal-fueled
electricity generating capacity is scheduled to come on line
around the world between 2008 and 2010, and the EIA projects an
additional 130 gigawatts of new U.S. coal-fueled generation
by 2030, including 9 gigawatts at coal-to-liquids plants and 45
gigawatts at integrated gasification combined-cycle plants,
which represents more than 500 million tons of additional
coal demand.
Coal-to-gas (CTG) and coal-to-liquids (CTL) plants represent a
significant avenue for long-term industry growth. The EIA
continues to project an increase in demand for unconventional
sources of transportation fuel, including CTL, and in the
U.S. CTL technologies are receiving U.S. support from
both political parties. China and India are developing CTG and
CTL facilities.
Demand for Powder River Basin coal remains strong, particularly
for our ultra-low sulfur products. The Powder River Basin
represents more than half of our production. We control
approximately 3.3 billion tons of proven and probable
reserves in the Southern Powder River Basin, and we sold
139.8 million tons of coal from this region during 2007.
We are targeting 2008 production of 220 to 240 million tons
and total sales volume of 240 to 260 million tons, both of
which include 23 to 25 million tons from Australia. As of
December 31, 2007, our unpriced volumes for 2008 planned
production included nine to 10 million Australian tons,
two-thirds of which is metallurgical coal, and five to seven
million U.S. tons. Unpriced volumes for 2009 include 17 to
20 million Australian tons, approximately half of which is
metallurgical coal, and 80 to 90 million U.S. tons.
Management plans to aggressively control costs and operating
performance to mitigate external cost pressures, geologic
conditions and potentially adverse port and rail performance. We
are experiencing increases in operating costs related to fuel,
explosives, steel, tires, contract mining and healthcare, and
have taken measures to mitigate the increases in these costs,
including a company-wide initiative to instill best practices at
all operations. In addition, historically low long-term interest
rates also have a negative impact on expenses related to our
actuarially determined, employee-related liabilities. We may
also encounter poor geologic conditions, lower third-party
contract miner or brokerage source performance or unforeseen
equipment problems that limit our ability to produce at
forecasted levels. To the extent upward pressure on costs
exceeds our ability to realize sales increases, or if we
experience unanticipated operating or transportation
difficulties, our operating margins would be negatively
impacted. See Cautionary Notice Regarding Forward-Looking
Statements and Item 1A. Risk Factors for additional
considerations regarding our outlook.
Global climate change continues to attract considerable public
and scientific attention. Enactment of laws and passage of
regulations regarding greenhouse gas emissions by the United
States or some of its states or by other countries, or other
actions to limit carbon dioxide emissions, could result in
electric generators switching from coal to other fuel sources.
We continue to support clean coal technology development and
voluntary initiatives addressing global climate change through
our participation as a founding member of the FutureGen
Alliance, through our commitment to the Australian COAL21 Fund,
and through our participation in the Power Systems Development
Facility, the PowerTree Carbon Company LLC, and the Asia-Pacific
Partnership for Clean Development and Climate. In addition, we
are the only non-Chinese equity partner in GreenGen, the first
near-zero emissions coal-fueled power plant with carbon capture
and storage (CCS) which is under development in China.
62
Critical
Accounting Policies and Estimates
Our discussion and analysis of our financial condition, results
of operations, liquidity and capital resources is based upon our
financial statements, which have been prepared in accordance
with accounting principles generally accepted in the United
States. Generally accepted accounting principles require that we
make estimates and judgments that affect the reported amounts of
assets, liabilities, revenues and expenses, and related
disclosure of contingent assets and liabilities. On an on-going
basis, we evaluate our estimates. We base our estimates on
historical experience and on various other assumptions that we
believe are reasonable under the circumstances, the results of
which form the basis for making judgments about the carrying
values of assets and liabilities that are not readily apparent
from other sources. Actual results may differ from these
estimates.
Employee-Related
Liabilities
We have significant long-term liabilities for our
employees postretirement benefit costs and defined benefit
pension plans. Detailed information related to these liabilities
is included in Notes 15 and 16 to our consolidated
financial statements. The adoption of SFAS No. 158 on
December 31, 2006 resulted in each of these liabilities
recorded on the consolidated balance sheet as of
December 31, 2006 being equal to the actuarially-determined
funded status of the plans. Liabilities for postretirement
benefit costs and workers compensation obligations are not
funded. Our pension obligations are funded in accordance with
the provisions of federal law. Expense for the year ended
December 31, 2007 for the pension and postretirement
liabilities totaled $102.2 million, while payments were
$71.6 million.
Each of these liabilities are actuarially determined and we use
various actuarial assumptions, including the discount rate and
future cost trends, to estimate the costs and obligations for
these items. Our discount rate is determined by utilizing a
hypothetical bond portfolio model which approximates the future
cash flows necessary to service our liabilities.
We make assumptions related to future trends for medical care
costs in the estimates of retiree health care and work-related
injuries and illnesses obligations. Our medical trend assumption
is developed by annually examining the historical trend of our
cost per claim data. In addition, we make assumptions related to
future compensation increases and rates of return on plan assets
in the estimates of pension obligations.
If our assumptions do not materialize as expected, actual cash
expenditures and costs that we incur could differ materially
from our current estimates. Moreover, regulatory changes could
increase our obligation to satisfy these or additional
obligations. Our most significant employee liability is
postretirement health care, and assumed discount rates and
health care cost trend rates have a significant effect on the
expense and liability amounts reported for health care plans.
Below we have provided two separate sensitivity analyses to
demonstrate the significance of these assumptions in relation to
reported amounts.
Health care cost trend rate:
|
|
|
|
|
|
|
|
|
|
|
One-Percentage-
|
|
|
One-Percentage-
|
|
|
|
Point Increase
|
|
|
Point Decrease
|
|
|
|
(Dollars in thousands)
|
|
|
Effect on total service and interest cost
components(1)
|
|
$
|
11,202
|
|
|
$
|
(9,580
|
)
|
Effect on total postretirement benefit
obligation(1)
|
|
$
|
81,535
|
|
|
$
|
(70,842
|
)
|
63
Discount rate:
|
|
|
|
|
|
|
|
|
|
|
One-Half
|
|
|
One-Half
|
|
|
|
Percentage-
|
|
|
Percentage-
|
|
|
|
Point Increase
|
|
|
Point Decrease
|
|
|
|
(Dollars in thousands)
|
|
|
Effect on total service and interest cost
components(1)
|
|
$
|
1,076
|
|
|
$
|
(1,913
|
)
|
Effect on total postretirement benefit
obligation(1)
|
|
$
|
(35,166
|
)
|
|
$
|
41,399
|
|
Total
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
In addition to the effect on total service and interest cost
components of expense, changes in trend and discount rates would
also increase or decrease the actuarial gain or loss
amortization expense component. The gain or loss amortization
would approximate the increase or decrease in the obligation
divided by 8.92 years at December 31, 2007. |
Asset
Retirement Obligations
Our asset retirement obligations primarily consist of spending
estimates for surface land reclamation and support facilities at
both surface and underground mines in accordance with federal
and state reclamation laws as defined by each mining permit.
Asset retirement obligations are determined for each mine using
various estimates and assumptions including, among other items,
estimates of disturbed acreage as determined from engineering
data, estimates of future costs to reclaim the disturbed
acreage, the timing of these cash flows, and a credit-adjusted,
risk-free rate. As changes in estimates occur (such as mine plan
revisions, changes in estimated costs, or changes in timing of
the reclamation activities), the obligation and asset are
revised to reflect the new estimate after applying the
appropriate credit-adjusted, risk-free rate. If our assumptions
do not materialize as expected, actual cash expenditures and
costs that we incur could be materially different than currently
estimated. Moreover, regulatory changes could increase our
obligation to perform reclamation and mine closing activities.
Asset retirement obligation expense for the year ended
December 31, 2007, was $25.6 million, and payments
totaled $10.2 million. See detailed information regarding
our asset retirement obligations in Note 14 to our
consolidated financial statements.
Income
Taxes
We account for income taxes in accordance with
SFAS No. 109, Accounting for Income Taxes
(SFAS No. 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 No. 109
also requires that deferred tax assets be reduced by a valuation
allowance if it is more likely than not that some portion or all
of the deferred tax asset will not be realized. In our annual
evaluation of the need for a valuation allowance, we take into
account various factors, including the expected level of future
taxable income and available tax planning strategies. If actual
results differ from the assumptions made in our annual
evaluation of our valuation allowance, we may record a change in
valuation allowance through income tax expense in the period
such determination is made.
We establish reserves for tax contingencies when, despite the
belief that our tax return positions are fully supported,
certain positions are likely to be challenged and may not be
fully sustained. The tax contingency reserves are analyzed on a
quarterly basis and adjusted based upon changes in facts and
circumstances, such as the progress of federal and state audits,
case law and emerging legislation. Our effective tax rate
includes the impact of tax contingency reserves and changes to
the reserves, including related interest. We establish the
reserves based upon managements assessment of exposure
associated with permanent tax differences (i.e. tax depletion
expense, etc.) and certain tax sharing agreements. We are
subject to federal audits for several open years due to our
previous inclusion in multiple consolidated groups and the
various parties involved in finalizing those years. Additional
details regarding the effect of income taxes on our consolidated
financial statements is available in Note 12.
Interpretation No. 48 Accounting for Uncertainty in
Income Taxes an interpretation of FASB Statement
No. 109 (FIN No. 48) prescribes a
recognition threshold and measurement attribute for the
64
financial statement recognition and measurement of a tax
position taken or expected to be taken in a tax return.
FIN No. 48 also provides guidance on derecognition,
classification, interest and penalties, accounting in interim
periods, disclosure and transition. We adopted this
interpretation effective January 1, 2007.
Revenue
Recognition
In general, we recognize revenues when they are realizable and
earned. We generated 95% of our revenue in 2007 from the sale of
coal to our customers. Revenue from coal sales is realized and
earned when risk of loss passes to the customer. Coal sales are
made to our customers under the terms of coal supply agreements,
most of which are long-term (greater than one year). Under the
typical terms of these coal supply agreements, title and risk of
loss transfer to the customer at the mine or port, where coal is
loaded to the rail, barge, ocean-going vessel, truck or other
transportation source(s) that delivers coal to its destination.
With respect to other revenues, other operating income, or gains
on asset sales recognized in situations unrelated to the
shipment of coal, we carefully review the facts and
circumstances of each transaction and apply the relevant
accounting literature as appropriate, and do not recognize
revenue until the following criteria are met: persuasive
evidence of an arrangement exists; delivery has occurred or
services have been rendered; the sellers price to the
buyer is fixed or determinable; and collectibility is reasonably
assured.
Trading
Activities
We engage in the buying and selling of coal, freight and
emissions allowances, both in over-the-counter markets and on
exchanges. Our coal trading contracts are accounted for on a
fair value basis under SFAS No. 133, Accounting
for Derivative Instruments and Hedging Activities. To
establish fair values for our trading contracts, we use bid/ask
price quotations obtained from multiple, independent third-party
brokers to value coal, freight and emission allowance positions
from the over-the-counter market. Prices from these sources are
then averaged to obtain trading position values. We could
experience difficulty in valuing our market positions if the
number of third-party brokers should decrease or market
liquidity is reduced. Published settlement prices are used to
value our exchange-based positions.
As of December 31, 2007, 97% of the contracts in our
trading portfolio were valued utilizing prices from
over-the-counter market sources, adjusted for coal quality and
traded transportation differentials. As of December 31,
2007, 58% of the estimated future value of our trading portfolio
was scheduled to be realized by the end of 2008 and 99% within
24 months. See Note 6 to our consolidated financial
statements for additional details regarding assets and
liabilities from our coal trading activities.
Exploration
and Drilling Costs
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.
Advance
Stripping Costs
Pre-production: 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 and amortized over the life of the
developed pit consistent with coal industry practices.
Post-production: 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.
65
Business
Combinations
We account for our business acquisitions under the purchase
method of accounting consistent with the requirements of
SFAS No. 141, Business Combinations. The
total cost of acquisitions is allocated to the underlying
identifiable net assets, based on their respective estimated
fair values. Determining the fair value of assets acquired and
liabilities assumed requires managements judgment, and the
utilization of independent valuation experts, and often involves
the use of significant estimates and assumptions, including
assumptions with respect to future cash inflows and outflows,
discount rates, asset lives, and market multiples, among other
items.
Share-Based
Compensation
We account for share-based compensation in accordance with the
fair value recognition provisions of SFAS No. 123
(Revised 2004), Share-Based Payment
(SFAS 123(R)), which we adopted using the modified
prospective option on January 1, 2006. Under
SFAS No. 123(R), share-based compensation expense is
generally measured at the grant date and recognized as expense
over the vesting period of the award. We utilize restricted
stock, nonqualified stock options, performance units, and an
employee stock purchase plan as part of our share-based
compensation program. Determining fair value requires us to make
a number of assumptions, including items such as expected term,
risk-free rate and expected volatility. The assumptions used in
calculating the fair value of share-based awards represent our
best estimates, but these estimates involve inherent
uncertainties and the application of management judgment.
Although we believe the assumptions and estimates we have made
are reasonable and appropriate, changes in assumptions could
materially impact our reported financial results.
Liquidity
and Capital Resources
Our primary sources of cash include sales of our coal production
to customers, cash generated from our trading and brokerage
activities, sales of non-core assets and financing transactions,
including sales of our accounts receivable through our
securitization program. Our primary uses of cash include our
cash costs of coal production, capital expenditures, interest
costs and costs related to past mining obligations as well as
planned acquisitions. Our ability to pay dividends, service our
debt (interest and principal) and acquire new productive assets
or businesses is dependent upon our ability to continue to
generate cash from the primary sources noted above in excess of
the primary uses. Future dividends, among other things, are
subject to limitations imposed by our Senior Notes and Debenture
covenants. We expect to fund all of our capital expenditure
requirements with cash generated from operations.
Net cash provided by operating activities from continuing
operations was $447.2 million for the year ended
December 31, 2007, a decrease of $144.2 million
compared to $591.4 million provided by operating activities
from continuing operations in the prior year. The decrease was
primarily related to lower profitability from our operations.
Net cash used in operating activities of discontinued operations
of $130.8 million was primarily used to fund the
regions net operating loss and for cash costs of the
spin-off.
Net cash used in investing activities from continuing operations
was $541.7 million for the year ended December 31,
2007 compared to $2.06 billion used in the prior year. The
decrease was primarily related to the acquisition of Excel of
$1.51 billion, net of cash acquired, in 2006 and higher
proceeds of $90.2 million from disposals of assets in 2007.
Partially offsetting these items was higher capital spending of
$72.9 million. Capital expenditures in 2007 included mine
development at our recently acquired Australian mines, the
completion of an in pit conveyor system, and coal
blending and loadout facility at one of our Western
U.S. mines and the purchase of coal reserves and surface
lands in the Illinois Basin. Net cash used in investing
activities of discontinued operations was $33.6 million and
was used for pre-spin capital costs for Patriot.
Net cash provided by financing activities from continuing
operations was $44.8 million during the year ended
December 31, 2007, compared to $1.41 billion provided
in 2006. During 2007, we repaid $37.9 million of our Term
Loan and purchased in the open market $13.8 million face
value of our 5.875% Senior Notes due 2016. We also made the
final principal payment of $59.5 million on our
5% Subordinated Note. Our Revolving Credit Facility balance
increased to $97.7 million as it was utilized to fund cash
contributions to
66
Patriot at the spin-off. In 2006, we issued net borrowings of
$1.74 billion, which we utilized to fund the
$1.51 billion Excel acquisition, the repayment of
Excels bank facility and a portion of its outstanding
bonds, and other corporate purposes. The net issuance of debt
related to the Excel acquisition was partially offset in 2006 by
repurchases of $7.7 million of our 5.875% Senior Notes
in the open market, scheduled debt repayments of
$11.1 million on our 5% Subordinated Note and other
notes payable, and $99.8 million for the repurchase of
common stock. Net cash used in financing activities of
discontinued operations of $67.0 million was primarily cash
provided to Patriot at spin-off to fund their working capital
needs.
Our total indebtedness as of December 31, 2007 and 2006
consisted of the following:
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
|
(Dollars in thousands)
|
|
|
Term Loan under Senior Unsecured Credit Facility
|
|
$
|
509,084
|
|
|
$
|
547,000
|
|
Revolving Credit Facility
|
|
|
97,700
|
|
|
|
|
|
Convertible Junior Subordinated Debentures due 2066
|
|
|
732,500
|
|
|
|
732,500
|
|
7.375% Senior Notes due 2016
|
|
|
650,000
|
|
|
|
650,000
|
|
6.875% Senior Notes due 2013
|
|
|
650,000
|
|
|
|
650,000
|
|
7.875% Senior Notes due 2026
|
|
|
246,965
|
|
|
|
246,897
|
|
5.875% Senior Notes due 2016
|
|
|
218,090
|
|
|
|
231,845
|
|
5.0% Subordinated Note
|
|
|
|
|
|
|
59,504
|
|
6.84% Series C Bonds due 2016
|
|
|
43,000
|
|
|
|
43,000
|
|
6.34% Series B Bonds due 2014
|
|
|
21,000
|
|
|
|
21,000
|
|
6.84% Series A Bonds due 2014
|
|
|
10,000
|
|
|
|
10,000
|
|
Capital lease obligations
|
|
|
92,186
|
|
|
|
96,869
|
|
Fair value of interest rate swaps
|
|
|
1,604
|
|
|
|
(13,784
|
)
|
Other
|
|
|
971
|
|
|
|
2,201
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
3,273,100
|
|
|
$
|
3,277,032
|
|
|
|
|
|
|
|
|
|
|
Senior
Unsecured Credit Facility
In September 2006, we entered into a Third Amended and Restated
Credit Agreement, which established a $2.75 billion Senior
Unsecured Credit Facility and which amended and restated in full
our then existing $1.35 billion Senior Secured Credit
Facility. The Senior Unsecured Credit Facility provides a
$1.8 billion Revolving Credit Facility and a
$950.0 million Term Loan Facility. The Revolving Credit
Facility is intended to accommodate working capital needs,
letters of credit, the funding of capital expenditures and other
general corporate purposes. The Revolving Credit Facility also
includes a $50.0 million sub-facility available for
same-day
swingline loan borrowings.
The Term Loan Facility, which was fully drawn in October 2006 in
connection with the Excel acquisition was paid down in December
2006 ($403.0 million), from a portion of the net proceeds
from the Debentures. In conjunction with the establishment of
the Senior Unsecured Credit Facility, we incurred
$8.6 million in financing costs, of which $5.6 million
related to the Revolving Credit Facility and $3.0 million
related to the Term Loan Facility. These debt issuance costs
will be amortized to interest expense over five years, the term
of the Senior Unsecured Credit Facility.
Loans under the facility are available in U.S. dollars,
with a sub-facility under the Revolving Credit Facility
available in Australian dollars, pounds sterling and Euros.
Letters of credit under the Revolving Credit Facility are
available to us in U.S. dollars with a sub-facility
available in Australian dollars, pounds sterling and Euros. The
interest rate payable on the Revolving Credit Facility and the
Term Loan Facility under the Senior Unsecured Credit Facility is
based on a pricing grid tied to our leverage ratio, as defined
in the Third
67
Amended and Restated Credit Agreement. Currently, the interest
rate payable on the Revolving Credit Facility and the Term Loan
Facility is LIBOR plus 0.75%, which at December 31, 2007
was 5.4%.
Under the Senior Unsecured Credit Facility, we must comply with
certain financial covenants on a quarterly basis including a
minimum interest coverage ratio and a maximum leverage ratio, as
defined in the Third Amended and Restated Credit Agreement. The
financial covenants also place limitations on our investments in
joint ventures, unrestricted subsidiaries, indebtedness of
non-loan parties, and the imposition of liens on our assets. The
new facility is less restrictive with respect to limitations on
our dividend payments, capital expenditures, asset sales or
stock repurchases. The Senior Unsecured Credit Facility matures
on September 15, 2011.
As of December 31, 2007, we had $97.7 million
borrowings and $413.5 million letters of credit outstanding
under our Revolving Credit Facility. Our Revolving Credit
Facility is primarily used for standby letters of credit and
short-term working capital needs. The remaining available
borrowing capacity ($1.29 billion as of December 31,
2007) can be used to fund strategic acquisitions or meet
other financing needs, including additional standby letters of
credit. We were in compliance with all of the covenants of the
Senior Unsecured Credit Facility, the 6.875% Senior Notes,
the 5.875% Senior Notes, the 7.375% Senior Notes, the
7.875% Senior Notes and the Convertible Junior Subordinated
Debentures as of December 31, 2007.
Convertible
Junior Subordinated Debentures
On December 20, 2006, we issued $732.5 million
aggregate principal amount of 4.75% Convertible Junior
Subordinated Debentures due 2066 (the Debentures). Net proceeds
from the offering, after deducting underwriting discounts and
offering expenses, were $715.0 million and were used to
repay indebtedness under our Senior Unsecured Credit Facility.
The Debentures pay interest semiannually at a rate of 4.75% per
year. We may elect to, and if and to the extent that a mandatory
trigger event (as defined in the indenture governing the
Debentures) has occurred and is continuing will be required to,
defer interest payments on the Debentures. After five years of
deferral at our option, or upon the occurrence of a mandatory
trigger event, we generally must sell warrants or preferred
stock with specified characteristics and use the funds from that
sale to pay deferred interest, subject to certain limitations.
In no event may we defer payments of interest on the Debentures
for more than 10 years.
The Debentures are convertible at any time on or prior to
December 15, 2036 if any of the following conditions occur:
(i) our closing common stock price exceeds 140% of the then
applicable conversion price for the Debentures (currently $81.83
per share) for at least 20 of the final 30 trading days in any
quarter; (ii) a notice of redemption is issued with respect
to the Debentures; (iii) a change of control, as defined in
the indenture governing the Debentures; (iv) satisfaction
of certain trading price conditions; and (v) other
specified corporate transactions described in the indenture
governing the Debentures. In addition, the Debentures are
convertible at any time after December 15, 2036 to
December 15, 2041, the scheduled maturity date. In the case
of conversion following a notice of redemption or upon a
non-stock change of control, as defined in the indenture
governing the Debentures, holders may convert their Debentures
into cash in the amount of the principal amount of their
Debentures and shares of our common stock for any conversion
value in excess of the principal amount. In all other conversion
circumstances, holders will receive perpetual preferred stock
(see Note 17 to our consolidated financial statements) with
a liquidation preference equal to the principal amount of their
Debentures, and any conversion value in excess of the principal
amount will be settled with our common stock. As a result of the
Patriot spin-off, the conversion rate was adjusted to
17.1078 shares of common stock per $1,000 principal amount
of Debentures effective November 23, 2007. This adjusted
conversion rate represents a conversion price of approximately
$58.45.
The Debentures are unsecured obligations, ranking junior to all
existing and future senior and subordinated debt (excluding
trade accounts payable or accrued liabilities arising in the
ordinary course of business) except for any future debt that
ranks equal to or junior to the Debentures. The Debentures will
rank equal in right of payment with our obligations to trade
creditors. Substantially, all of our existing indebtedness is
senior to the Debentures. In addition, the Debentures will be
effectively subordinated to all indebtedness of
68
our subsidiaries. The indenture governing the Debentures places
no limitation on the amount of additional indebtedness that we
or any of our subsidiaries may incur (see Note 13 to our
consolidated financial statements for additional information on
the Debentures).
7.375% Senior
Notes Due November 2016 and 7.875% Senior Notes Due
November 2026
On October 12, 2006, we completed a $650.0 million
offering of 7.375%
10-year
Senior Notes due 2016 and $250 million of 7.875%
20-year
Senior Notes due 2026. The notes are general unsecured
obligations and rank senior in right of payment to any
subordinated indebtedness; equally in right of payment with any
senior indebtedness; effectively junior in right of payment to
our existing and future secured indebtedness, to the extent of
the value of the collateral securing that indebtedness; and
effectively junior to all the indebtedness and other liabilities
of our subsidiaries that do not guarantee the notes. Interest
payments are scheduled to occur on May 1 and November 1 of each
year, and commenced on May 1, 2007.
The notes are guaranteed by our Subsidiary Guarantors, as
defined in the note indenture. The note indenture contains
covenants that, among other things, limit our ability to create
liens and enter into sale and lease-back transactions. The notes
are redeemable at a redemption price equal to 100% of the
principal amount of the notes being redeemed plus a make-whole
premium, if applicable, and any accrued unpaid interest to the
redemption date. Net proceeds from the offering, after deducting
underwriting discounts and expenses, were $886.1 million.
6.875% Senior
Notes Due March 2013
On March 21, 2003, we issued $650.0 million of
6.875% Senior Notes due March 2013. The notes are senior
unsecured obligations and rank equally with all of our other
senior unsecured indebtedness. Interest payments are scheduled
to occur on March 15 and September 15 of each year. The notes
are guaranteed by our Subsidiary Guarantors as defined in the
note indenture. The note indenture contains covenants which,
among other things, limit our ability to incur additional
indebtedness and issue preferred stock, pay dividends or make
other distributions, make other restricted payments and
investments, create liens, sell assets and merge or consolidate
with other entities. The notes are redeemable prior to
March 15, 2008, at a redemption price equal to 100% of the
principal amount plus a make-whole premium (as defined in the
indenture) and on or after March 15, 2008, at fixed
redemption prices as set forth in the indenture.
5.875% Senior
Notes Due March 2016
On March 23, 2004, we completed an offering of
$250.0 million of 5.875% Senior Notes due March 2016.
The notes are senior unsecured obligations and rank equally with
all of our other senior unsecured indebtedness. Interest
payments are scheduled to occur on April 15 and October 15 of
each year, and commenced on April 15, 2004. The notes are
guaranteed by our Subsidiary Guarantors as defined in the note
indenture. The note indenture contains covenants which, among
other things, limit our ability to incur additional indebtedness
and issue preferred stock, pay dividends or make other
distributions, make other restricted payments and investments,
create liens, sell assets and merge or consolidate with other
entities. The notes are redeemable prior to April 15, 2009,
at a redemption price equal to 100% of the principal amount plus
a make-whole premium (as defined in the indenture) and on or
after April 15, 2009, at fixed redemption prices as set
forth in the indenture. Net proceeds from the offering, after
deducting underwriting discounts and expenses, were
$244.7 million.
Series Bonds
As of December 31, 2007, we had $74.0 million in
Series Bonds outstanding, which were assumed as part of the
Excel acquisition. The 6.84% Series A Bonds have a balloon
maturity in December 2014. The 6.34% Series B Bonds mature
in December 2014 and are payable in installments beginning
December 2008. The 6.84% Series C Bonds mature in December
2016 and are payable in installments beginning December 2012.
Interest payments are scheduled to occur in June and December of
each year.
69
Interest
Rate Swaps
As of December 31, 2007, we had entered into a series of
fixed-to-floating interest rate swaps with a notional principal
amount of $120.0 million. Under the terms of these swaps we
receive a fixed rate of 6.875% and pay a weighted average
floating rate of LIBOR plus 2.0%, which resets each
March 15, June 15, September 15 and December 15.
The swaps have been designated as a hedge of the changes in the
fair value of the 6.875% Senior Notes due 2013.
We have also entered into another series of fixed-to-floating
interest rate swaps with a notional principal amount of
$100.0 million. Under the terms of these swaps we receive a
fixed rate of 5.875% and pay a weighted average floating rate of
LIBOR plus 0.25%, which resets each April 15 and
October 15. This series of swaps has been designated as a
hedge of the changes in the fair value of the 5.875% Senior
Notes due 2016.
In conjunction with the Term Loan Facility, we have a
floating-to-fixed interest rate swap in place for a notional
principal amount of $120.0 million. Under the terms of this
swap we receive a floating rate of LIBOR plus 1.0% and pay a
fixed rate of 6.25%. This interest rate swap was designated as a
hedge of the variable interest payments on the Term Loan under
the Senior Unsecured Credit Facility.
Because the critical terms of the swaps and the respective debt
instruments they hedge coincide, there was no hedge
ineffectiveness recognized in the consolidated statements of
operations during the years ended December 31, 2007 and
2006. At December 31, 2007 and 2006 there was an unrealized
loss related to the cash flow hedge of $6.8 million and
$2.5 million, respectively. At December 31, 2007,
there was a net unrealized gain on the fair value hedges of
$1.6 million. At December 31, 2006, the net unrealized
loss on the fair value hedges was $13.8 million. The fair
value hedge is reflected as an adjustment to the carrying value
of the Senior Notes (see table above).
Third-party
Security Ratings
The ratings for our Senior Unsecured Credit Facility and our
Senior Unsecured Notes are as follows: Moodys has issued a
Ba1 rating, Standard & Poors a BB rating and
Fitch has issued a BB+ rating. The ratings on our Convertible
Junior Subordinated Debentures are as follows: Moodys has
issued a Ba3 rating, Standard & Poors a B rating
and Fitch has issued a BB- rating. These security ratings
reflected the views of the rating agency only. An explanation of
the significance of these ratings may be obtained from the
rating agency. Such ratings are not a recommendation to buy,
sell or hold securities, but rather an indication of
creditworthiness. Any rating can be revised upward or downward
or withdrawn at any time by a rating agency if it decides that
the circumstances warrant the change. Each rating should be
evaluated independently of any other rating.
Shelf
Registration Statement
On July 28, 2006, we filed an automatic shelf registration
statement on
Form S-3
as a well-known seasoned issuer with the SEC. The registration
was for an indeterminate number of securities and is effective
for three years, at which time we can file an automatic shelf
registration statement that would become immediately effective
for another three-year term. Under this universal shelf
registration statement, we have the capacity to offer and sell
from time to time securities, including common stock, preferred
stock, debt securities, warrants and units. The Debentures,
7.375% Senior Notes due 2016 and 7.875% Senior Notes
due 2026 were issued pursuant to the shelf registration
statement.
Excel
Transaction
In October 2006, we acquired Excel Coal Limited (Excel) for
US$1.54 billion in cash plus assumed debt of
US$293.0 million, less US$30.0 million of cash
acquired in the transaction. This acquisition was financed with
borrowings under our Senior Unsecured Credit Facility and Senior
Notes due 2016 and 2026 (see Note 13 of our consolidated
financial statements for additional information on the financing
of the Excel acquisition). The Excel acquisition included three
operating mines and three development-stage mines (all of which
are
70
operating as of December 31, 2007), with up to
500 million tons of proven and probable coal reserves. The
results of operations of Excel are included in our Australian
Mining Operations segment from October 2006. The acquisition was
accounted for as a purchase in accordance with
SFAS No. 141, Business Combinations (see
Note 5 of our consolidated financial statements for
additional information on the Excel acquisition).
Contractual
Obligations
The following is a summary of our contractual obligations as of
December 31, 2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Payments Due By Year
|
|
|
|
|
|
|
Less than
|
|
|
2-3
|
|
|
4-5
|
|
|
More than
|
|
|
|
Total
|
|
|
1 Year
|
|
|
Years
|
|
|
Years
|
|
|
5 Years
|
|
|
|
(Dollars in thousands)
|
|
|
Long-term debt obligations (principal and interest)
|
|
$
|
5,781,312
|
|
|
$
|
344,324
|
|
|
$
|
471,852
|
|
|
$
|
825,632
|
|
|
$
|
4,139,504
|
|
Capital lease obligations (principal and interest)
|
|
|
116,861
|
|
|
|
17,349
|
|
|
|
34,258
|
|
|
|
30,234
|
|
|
|
35,020
|
|
Operating lease obligations
|
|
|
359,045
|
|
|
|
85,356
|
|
|
|
120,218
|
|
|
|
71,759
|
|
|
|
81,712
|
|
Unconditional purchase
obligations(1)
|
|
|
168,923
|
|
|
|
168,923
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Coal reserve lease and royalty obligations
|
|
|
383,416
|
|
|
|
187,946
|
|
|
|
139,564
|
|
|
|
12,777
|
|
|
|
43,129
|
|
Other long-term
liabilities(2)
|
|
|
1,302,039
|
|
|
|
112,418
|
|
|
|
215,443
|
|
|
|
210,275
|
|
|
|
763,903
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total contractual cash obligations
|
|
$
|
8,111,596
|
|
|
$
|
916,316
|
|
|
$
|
981,335
|
|
|
$
|
1,150,677
|
|
|
$
|
5,063,268
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
We have purchase agreements with approved vendors for most types
of operating expenses. However, our specific open purchase
orders (which have not been recognized as a liability) under
these purchase agreements, combined with any other open purchase
orders, are not material. The commitments in the table above
relate to significant capital purchases. |
|
(2) |
|
Represents long-term liabilities relating to our postretirement
benefit plans, work-related injuries and illnesses, defined
benefit pension plans and mine reclamation and end of mine
closure costs. |
As of December 31, 2007, we had $67.8 million of
purchase obligations for capital expenditures and
$301.6 million of obligations related to federal coal
reserve lease payments due over the next three years. Total
capital expenditures for 2008 are expected to range from
$350 million to $400 million, excluding federal coal
reserve lease payments, and relate to replacement, improvement,
or expansion of existing mines, particularly in Australia, the
El Segundo mine development in New Mexico, and growth
initiatives such as increasing capacity in the Powder River
Basin. Capital expenditures were funded primarily through
operating cash flow.
Our subsidiary, Peabody Pacific, has committed to pay up to a
maximum of A$0.20/tonne (approximately US$0.15/tonne) of coal
sales for a period of five years to the Australian COAL21 Fund.
The COAL21 Fund is a voluntary coal industry fund to support
clean coal technology demonstration projects and research in
Australia. All major coal companies in Australia have committed
to this fund. The commitment to pay started on April 1,
2007 with a levy of A$0.10/tonne of coal sales. This levy rose
to A$0.20/tonne on July 1, 2007.
We do not expect any of the $152.6 million of gross
unrecognized tax benefits reported in our consolidated financial
statements to require cash settlement within the next year.
Beyond that, we are unable to make reasonably reliable estimates
of periodic cash settlements with respect to such unrecognized
tax benefits.
71
Off-Balance
Sheet Arrangements
In the normal course of business, we are a party to certain
off-balance sheet arrangements. These arrangements include
guarantees, indemnifications, financial instruments with
off-balance sheet risk, such as bank letters of credit and
performance or surety bonds and our accounts receivable
securitization. Liabilities related to these arrangements are
not reflected in our consolidated balance sheets, and we do not
expect any material adverse effects on our financial condition,
results of operations or cash flows to result from these
off-balance sheet arrangements.
We use a combination of surety bonds, corporate guarantees (i.e.
self bonds) and letters of credit to secure our financial
obligations for reclamation, workers compensation,
postretirement benefits and coal lease obligations as follows as
of December 31, 2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Workers
|
|
|
Retiree
|
|
|
|
|
|
|
|
|
|
Reclamation
|
|
|
Lease
|
|
|
Compensation
|
|
|
Healthcare
|
|
|
|
|
|
|
|
|
|
Obligations
|
|
|
Obligations
|
|
|
Obligations
|
|
|
Obligations
|
|
|
Other(1)
|
|
|
Total
|
|
|
|
(Dollars in millions)
|
|
|
Self Bonding
|
|
$
|
640.6
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
640.6
|
|
Surety Bonds
|
|
|
418.3
|
|
|
|
73.0
|
|
|
|
31.2
|
|
|
|
|
|
|
|
16.7
|
|
|
|
539.2
|
|
Letters of Credit
|
|
|
1.6
|
|
|
|
|
|
|
|
102.7
|
|
|
|
41.4
|
|
|
|
267.9
|
|
|
|
413.6
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
1,060.5
|
|
|
$
|
73.0
|
|
|
$
|
133.9
|
|
|
$
|
41.4
|
|
|
$
|
284.6
|
|
|
$
|
1,593.4
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Includes financial guarantees primarily related to joint venture
debt, the PBGC and collateral for surety companies. |
As part of arrangements through which we obtain exclusive sales
representation agreements with small coal mining companies (the
Counterparties), we issued financial guarantees on behalf of the
Counterparties. These guarantees facilitate the
Counterparties efforts to obtain bonding or financing. In
2007, we purchased approximately 345 million tons of coal
reserves and surface lands in the Illinois Basin. In conjunction
with this purchase, we agreed to provide up to
$64.8 million of reclamation and bonding commitments to a
third-party coal company. We have recognized the full amount of
these commitments as a liability as of December 31, 2007.
The non-cash portion of this transaction was excluded from the
investing section of the statement of cash flows.
In the event of default, the terms of our guarantees provide for
multiple recourse options, including the ability to assume the
loans and procure title and use of the equipment purchased
through the loans. If default occurs, we have the ability and
intent to exercise our recourse options, so the liability
associated with the guarantee has been valued at zero. The
aggregate amount guaranteed for all such Counterparties was
$8.8 million at December 31, 2007. See Note 20 to
our consolidated financial statements included in this report
for a discussion of our guarantees.
As part of the Patriot spin-off, we agreed to maintain in force
several letters of credit that secured Patriot obligations for
certain employee benefits and workers compensation
obligations. These letters of credit are to be released upon
Patriot satisfying the beneficiaries with alternate letters of
credit or insurance, which is expected to occur in 2008. If
Patriot is unable to satisfy the primary beneficiaries by
June 30, 2011, they are then required to provide directly
to us a letter of credit in the amount of the remaining
obligation. As of December 31, 2007, the amount of letters
of credit securing Patriot obligations was $136.8 million.
Under our accounts receivable securitization program, undivided
interests in a pool of eligible trade receivables contributed to
our wholly-owned, bankruptcy-remote subsidiary are sold, without
recourse, to a multi-seller, asset-backed commercial paper
conduit (Conduit). Purchases by the Conduit are financed with
the sale of highly rated commercial paper. We utilize proceeds
from the sale of our accounts receivable as an alternative to
other forms of debt, effectively reducing our overall borrowing
costs. The funding cost of the securitization program was
$11.2 million and $1.9 million for the years ended
December 31, 2007 and 2006, respectively. The
securitization program is scheduled to expire in September 2009.
The securitization transactions have been recorded as sales,
with those accounts receivable sold to the Conduit removed from
the
72
consolidated balance sheets. The amount of undivided interests
in accounts receivable sold to the Conduit was
$275.0 million and $219.2 million as of
December 31, 2007 and 2006, respectively (see Note 7
to our consolidated financial statements for additional
information on accounts receivable securitization).
The following is a summary of specified types of commercial
commitments available to us as of December 31, 2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expiration Per Year
|
|
|
|
Total Amounts
|
|
|
Within
|
|
|
|
|
|
|
|
|
Over
|
|
|
|
Committed
|
|
|
1 Year
|
|
|
2-3 Years
|
|
|
4-5 Years
|
|
|
5 Years
|
|
|
|
(Dollars in thousands)
|
|
|
Lines of credit and/or standby letters of credit
|
|
$
|
1,800,000
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
1,800,000
|
|
|
$
|
|
|
Newly
Adopted Accounting Pronouncements
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 No. 48). This
interpretation prescribes a recognition threshold and
measurement attribute for the financial statement recognition
and measurement of a tax position taken or expected to be taken
in a tax return. FIN No. 48 also provides guidance on
derecognition, classification, interest and penalties,
accounting in interim periods, disclosure and transition.
We adopted the provisions of FIN No. 48 on
January 1, 2007, and as a result, reported
$135.0 million of net unrecognized tax benefits
($144.0 million gross) in our consolidated financial
statements. Due to the valuation allowance recorded against our
deferred tax asset for NOL carryforwards as of January 1,
2007, none of the $135.0 million required an adjustment to
retained earnings upon adoption.
In September 2006, the FASB issued SFAS No. 158,
Employers Accounting for Defined Benefit Pension and
Other Postretirement Plans (SFAS No. 158). For
fiscal years ending after December 15, 2006,
SFAS No. 158 required recognition of the funded status
of pension and other postretirement benefit plans (an asset for
overfunded status or a liability for underfunded status) in a
companys balance sheet. In addition, the standard required
recognition of actuarial gains and losses, prior service cost,
and any remaining transition amounts from the initial
application of SFAS No. 87, Employers
Accounting for Pensions (SFAS No. 87) and
SFAS No. 106, Employers Accounting for
Postretirement Benefits Other Than Pensions
(SFAS No. 106) when determining a plans funded
status, with a corresponding charge to accumulated other
comprehensive income (loss).
We adopted SFAS No. 158 on December 31, 2006, and
as a result, recorded a noncurrent liability of
$376.1 million, which reflected the total underfunded
status of the pension, retiree healthcare and workers
compensation plans. The funded status of each plan was measured
as the difference between the fair value of the assets and the
projected benefit obligation (the funded status).
SFAS No. 158 did not impact net income.
Accounting
Pronouncements Not Yet Implemented
In September 2006, the FASB issued SFAS No. 157,
Fair Value Measurements, (SFAS No. 157).
SFAS No. 157 defines fair value, establishes a
framework for measuring fair value in generally accepted
accounting principles (GAAP), and expands disclosures about fair
value measurements. SFAS No. 157 applies under other
accounting pronouncements that require or permit fair value
measurements, and therefore does not require any new fair value
measurements. SFAS No. 157 is effective for fiscal
years beginning after November 15, 2007 (January 1,
2008 for the Company). In February 2008, the FASB amended SFAS
No. 157 to exclude leasing transactions and to delay the
effective date by one year for nonfinancial assets and
liabilities that are recognized or disclosed at fair value in
the financial statements on a nonrecurring basis. We are in the
process of determining the effect, if any, the adoption of
SFAS No. 157 will have on our financial statements.
In February 2007, the FASB issued SFAS No. 159,
The Fair Value Option for Financial Assets and Financial
Liabilities, including an amendment of FASB Statement
No. 115 (SFAS No. 159).
SFAS No. 159
73
provides all entities with an option to report selected
financial assets and liabilities at fair value.
SFAS No. 159 is effective for financial statements
issued for fiscal years beginning after November 15, 2007
(January 1, 2008 for the Company). We are in the process of
determining the effect, if any, the adoption of
SFAS No. 159 will have on our financial statements.
In December 2007, the FASB issued SFAS No. 160,
Noncontrolling Interests in Consolidated Financial
Statements an amendment of ARB No. 51
(SFAS No. 160). SFAS No. 160 establishes
accounting and reporting standards for (1) noncontrolling
interests in partially owned consolidated subsidiaries and
(2) the loss of control of subsidiaries.
SFAS No. 160 requires noncontrolling interests
(minority interests) to be reported as a separate component of
equity. The amount of net income attributable to the
noncontrolling interest will be included in consolidated net
income on the face of the income statement. In addition, this
statement requires that a parent recognize a gain or loss in net
income when a subsidiary is deconsolidated. Such gain or loss
will be measured using the fair value of the noncontrolling
equity investment on the deconsolidation date.
SFAS No. 160 also includes expanded disclosure
requirements regarding the interests of the parent and its
noncontrolling interest. SFAS No. 160 is effective for
fiscal years, and interim periods within those fiscal years,
beginning on or after December 15, 2008 (January 1,
2009 for the Company). Early adoption is not allowed. We are in
the process of determining the effect the adoption of
SFAS No. 160 will have on our financial statements.
In December 2007, the FASB issued SFAS No. 141(R),
Business Combinations, which replaces
SFAS No. 141. SFAS No. 141(R) significantly
changes the principles and requirements for how the acquirer of
a business recognizes and measures in its financial statements
the identifiable assets acquired, the liabilities assumed, and
any noncontrolling interest in the acquiree. This statement also
provides guidance for the recognition and measurement of
goodwill acquired in a business combination and for
determination of required disclosures that will enable users of
the financial statements to evaluate the nature and financial
effects of the business combination. This statement applies
prospectively to business combinations for which the acquisition
date is on or after the beginning of the first annual reporting
period beginning on or after December 15, 2008
(January 1, 2009 for the Company). We are in the process of
determining the effect, if any, the adoption of
SFAS No. 141(R) will have on our financial statements.
|
|
Item 7A.
|
Quantitative
and Qualitative Disclosures About Market Risk.
|
The potential for changes in the market value of our coal,
freight and emissions allowance trading, fuel, explosives,
interest rate and currency portfolios is referred to as
market risk. Market risk related to our coal,
freight and emissions allowance trading portfolio is evaluated
using a value at risk analysis (described below). Value at risk
analysis is not used to evaluate our non-trading fuel,
explosives, interest rate and currency portfolios. A description
of each market risk category is set forth below. We attempt to
manage market risks through diversification, controlling
position sizes and executing hedging strategies. Due to lack of
quoted market prices and the long-term, illiquid nature of the
positions, we have not quantified market risk related to our
non-trading, long-term coal supply agreement portfolio.
Coal
Trading Activities and Related Commodity Price Risk
We engage in over-the-counter, exchange-based and direct trading
of coal, freight and emission allowances (collectively coal
trading). These activities give rise to commodity price risk,
which represents the potential loss that can be caused by an
adverse change in the market value of a particular commitment.
We actively measure, monitor and adjust traded position levels
to remain within risk limits prescribed by management. For
example, we have policies in place that limit the amount of
total exposure, in value at risk terms, that we may assume at
any point in time.
We account for coal trading using the fair value method, which
requires us to reflect financial instruments with third parties,
such as forwards, options and swaps, at market value in our
consolidated financial statements. Our trading portfolio
included forwards and swaps as of December 31, 2007 and
2006.
We perform a value at risk analysis on our coal trading
portfolio. The use of value at risk allows us to quantify in
dollars, on a daily basis, the price risk inherent in our
trading portfolio. Value at risk represents the
74
potential loss in value of our mark-to-market portfolio due to
adverse market movements over a defined time horizon
(liquidation period) within a specified confidence level. Our
value at risk model is based on the industry standard
variance/co-variance approach. This captures our exposure
related to both swaps and forward positions. Our value at risk
model assumes 5 and 15 day holding periods, as applicable,
and a 95% one-tailed confidence interval. This means that there
is a one in 20 statistical chance that the portfolio would lose
more than the value at risk estimates during the liquidation
period.
The use of value at risk allows management to aggregate pricing
risks across products in the portfolio, compare risk on a
consistent basis and identify the drivers of risk. Due to the
subjectivity in the choice of the liquidation period, reliance
on historical data to calibrate the models and the inherent
limitations in the value at risk methodology, we perform regular
stress and scenario analysis to estimate the impacts of market
changes on the value of the portfolio. Additionally,
back-testing is regularly performed to monitor the effectiveness
of our value at risk measure. The results of these analyses are
used to supplement the value at risk methodology and identify
additional market-related risks.
We use historical data to estimate our value at risk and to
better reflect current asset and liability volatilities. Given
our reliance on historical data, value at risk is effective in
estimating risk exposures in markets in which there are not
sudden fundamental changes or shifts in market conditions. An
inherent limitation of value at risk is that past changes in
market risk factors may not produce accurate predictions of
future market risk. Value at risk should be evaluated in light
of this limitation.
During the year ended December 31, 2007, the combined
actual low, high, and average values at risk for our coal
trading portfolio were $1.2 million, $13.7 million,
and $6.8 million, respectively. Our value at risk increased
over the prior year due to greater price volatility in the coal
markets, particularly in the international markets into which we
have recently expanded. As of December 31, 2007, the timing
of the estimated future realization of the value of our trading
portfolio was as follows:
|
|
|
|
|
|
|
Percentage
|
|
Year of Expiration
|
|
of Portfolio
|
|
|
2008
|
|
|
58
|
%
|
2009
|
|
|
41
|
%
|
2010
|
|
|
0
|
%
|
2011
|
|
|
1
|
%
|
|
|
|
|
|
|
|
|
100
|
%
|
|
|
|
|
|
We also monitor other types of risk associated with our coal
trading activities, including credit, market liquidity and
counterparty nonperformance.
Credit
Risk
Our concentration of credit risk is substantially with energy
producers and marketers and electric utilities. Our policy is to
independently evaluate each customers creditworthiness
prior to entering into transactions and to constantly monitor
the credit extended. If we engage in a transaction with a
counterparty that does not meet our credit standards, we will
protect our position by requiring the counterparty to provide
appropriate credit enhancement. In general, increases in coal
price volatility and our own trading activity resulted in
greater exposure to our coal-trading counterparties during the
year. When appropriate (as determined by our credit management
function), we have taken steps to reduce our credit exposure to
customers or counterparties whose credit has deteriorated and
who may pose a higher risk of failure to perform under their
contractual obligations. These steps include obtaining letters
of credit or cash collateral, requiring prepayments for
shipments or the creation of customer trust accounts held for
our benefit to serve as collateral in the event of a failure to
pay. To reduce our credit exposure related to trading and
brokerage activities, we seek to enter into netting agreements
with counterparties that permit us to offset receivables and
payables with such counterparties. Counterparty risk with
respect to interest rate swap and foreign currency forwards and
options transactions is not considered to be significant based
upon the creditworthiness of the participating financial
institutions.
75
Foreign
Currency Risk
We utilize currency forwards to hedge currency risk associated
with anticipated Australian dollar expenditures. Our currency
hedging program for 2008 targets hedging at least approximately
70% of our anticipated, non-capital Australian
dollar-denominated expenditures. As of December 31, 2007,
we had in place forward contracts designated as cash flow hedges
with notional amounts outstanding totaling A$2.03 billion
of which A$1.08 billion, A$556.7 million, and
A$388.8 million will expire in 2008, 2009, and 2010,
respectively. The accounting for these derivatives is discussed
in Note 3 to our consolidated financial statements.
Assuming we had no hedges in place, our exposure in
Operating costs and expenses due to a $0.01 change
in the Australian dollar/U.S. dollar exchange rate is
approximately $12 million for 2008. However, taking into
consideration hedges currently in place, our net exposure to the
same rate change is approximately $1.6 million in 2008.
Interest
Rate Risk
Our objectives in managing exposure to interest rate changes are
to limit the impact of interest rate changes on earnings and
cash flows and to lower overall borrowing costs. To achieve
these objectives, we manage fixed-rate debt as a percent of net
debt through the use of various hedging instruments, which are
discussed in detail in Note 13 to our consolidated
financial statements. As of December 31, 2007, after taking
into consideration the effects of interest rate swaps, we had
$2.57 billion of fixed-rate borrowings and
$707.2 million of variable-rate borrowings outstanding. A
one percentage point increase in interest rates would result in
an annualized increase to interest expense of $7.1 million
on our variable-rate borrowings. With respect to our fixed-rate
borrowings, a one percentage point increase in interest rates
would result in a $0.3 million decrease in the estimated
fair value of these borrowings.
Other
Non-trading Activities
We manage our commodity price risk for our non-trading,
long-term coal contract portfolio through the use of long-term
coal supply agreements, rather than through the use of
derivative instruments. We sold 94% and 90% of our sales volume
under long-term coal supply agreements during 2007 and 2006,
respectively. As of December 31, 2007, we had 5 to
10 million tons of expected U.S. production unpriced
for 2008. We had 9 to 10 million tons remaining to be
priced for 2008 in Australia at December 31, 2007. We have
approximately 80 to 90 million tons of expected
U.S. production unpriced for 2009, with an additional 17 to
20 million tons of expected Australia coal production
unpriced for 2009.
Some of the products used in our mining activities, such as
diesel fuel and explosives, are subject to commodity price risk.
To manage this risk, we use a combination of forward contracts
with our suppliers and financial derivative contracts, primarily
swap contracts with financial institutions. As of
December 31, 2007, we had derivative contracts outstanding
that are designated as cash flow hedges of anticipated purchases
of fuel and explosives.
Notional amounts outstanding under fuel-related, derivative swap
contracts were 114.8 million gallons of crude oil scheduled
to expire through 2010. We expect to consume 125 to
130 million gallons of fuel next year. A one dollar per
barrel change in the price of crude oil would increase or
decrease our annual fuel costs (ignoring the effects of hedging)
by approximately $2.4 million.
Notional amounts outstanding under explosives-related swap
contracts, scheduled to expire through 2010, were 5.7 mmbtu of
natural gas. We expect to consume 315,000 to 325,000 tons of
explosives per year. Through our natural gas hedge contracts, we
have fixed prices for approximately 49% of our anticipated
explosives requirements for 2008. Based on our expected usage, a
change in natural gas prices of ten cents per mmbtu (ignoring
the effects of hedging) would result in an increase or decrease
in our operating costs of approximately $0.6 million per
year.
|
|
Item 8.
|
Financial
Statements and Supplementary Data.
|
See Part IV, Item 15 of this report for information
required by this Item.
76
|
|
Item 9.
|
Changes
in and Disagreements with Accountants on Accounting and
Financial Disclosure.
|
None.
|
|
Item 9A.
|
Controls
and Procedures.
|
Evaluation
of Disclosure Controls and Procedures
As of the end of the period covered by this Annual Report on
Form 10-K,
we carried out an evaluation of the effectiveness of the design
and operation of our disclosure controls and procedures. Based
upon that evaluation, the Chief Executive Officer and the Chief
Financial Officer concluded that our disclosure controls and
procedures, as defined in
Rule 13a-15
under the Securities Act of 1934, were effective.
Changes
in Internal Control Over Financial Reporting
We periodically review our internal control over financial
reporting as part of our efforts to ensure compliance with the
requirements of Section 404 of the Sarbanes-Oxley Act of
2002. In addition, we routinely review our system of internal
control over financial reporting to identify potential changes
to our processes and systems that may improve controls and
increase efficiency, while ensuring that we maintain an
effective internal control environment. Changes may include such
activities as implementing new systems, consolidating the
activities of acquired business units, migrating certain
processes to our shared services organizations, formalizing and
refining policies and procedures, improving segregation of
duties, and adding additional monitoring controls. In addition,
when we acquire new businesses, we incorporate our controls and
procedures into the acquired business as part of our integration
activities. There have been no changes in our internal control
over financial reporting that occurred during the quarter ended
December 31, 2007 that have materially affected, or are
reasonably likely to materially affect, our internal control
over financial reporting.
Managements
Report on Internal Control Over Financial Reporting
Management is responsible for maintaining and establishing
adequate internal control over financial reporting. Our internal
control framework and processes were designed to provide
reasonable assurance regarding the reliability of financial
reporting and the preparation of our consolidated financial
statements for external purposes in accordance with
U.S. generally accepted accounting principles.
Because of inherent limitations, any system of 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.
Management conducted an assessment of the effectiveness of our
internal control over financial reporting using the criteria set
by the Committee of Sponsoring Organizations of the Treadway
Commission (COSO) in Internal Control Integrated
Framework. Based on this assessment, management concluded
that the Companys internal control over financial
reporting was effective as of December 31, 2007.
Our Independent Registered Public Accounting Firm,
Ernst & Young LLP, has audited our internal control
over financial reporting, as stated in their unqualified opinion
report included herein.
|
|
|
/s/ GREGORY
H. BOYCE
|
|
/s/ RICHARD
A. NAVARRE
|
|
|
|
Gregory H. Boyce
Chairman and Chief Executive Officer
|
|
Richard A. NavarrePresident, Chief Commercial Officer and
Chief Financial Officer
|
February 27, 2008
77
REPORT OF
INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Directors and Stockholders
Peabody Energy Corporation
We have audited Peabody Energy Corporations (the
Companys) 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). Peabody Energy
Corporations 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 accompanying
Managements Report on Internal Control Over Financial
Reporting. Our responsibility is to express an opinion on the
Companys 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 companys 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 companys
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
companys 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, Peabody Energy Corporation 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
consolidated balance sheets of Peabody Energy Corporation as of
December 31, 2007 and 2006, and the related consolidated
statements of operations, changes in stockholders equity,
and cash flows for each of the three years in the period ended
December 31, 2007, and our report dated February 27,
2008, expressed an unqualified opinion thereon.
St. Louis, Missouri
February 27, 2008
78
|
|
Item 9B.
|
Other
Information.
|
None.
PART III
|
|
Item 10.
|
Directors,
Executive Officers and Corporate Governance.
|
The information required by Item 401 of
Regulation S-K
is included under the caption Election of Directors
in our 2008 Proxy Statement and in Part I of this report
under the caption Executive Officers of the Company.
The information required by Items 405, 406 and 407(c)(3),
(d)(4) and (d)(5) of
Regulation S-K
is included under the captions Ownership of Company
Securities Section 16(a) Beneficial Ownership
Reporting Compliance, Corporate Governance
Matters and Information Regarding Board of Directors
and Committees in our 2008 Proxy Statement. Such
information is incorporated herein by reference.
|
|
Item 11.
|
Executive
Compensation.
|
The information required by Items 402 and 407 (e)(4) and
(e)(5) of
Regulation S-K
is included under the captions Executive
Compensation, Compensation Committee Interlocks and
Insider Participation and Report of the Compensation
Committee in our 2008 Proxy Statement and is incorporated
herein by reference.
|
|
Item 12.
|
Security
Ownership of Certain Beneficial Owners and Management and
Related Stockholder Matters.
|
The information required by Item 403 of
Regulation S-K
is included under the caption Ownership of Company
Securities in our 2008 Proxy Statement and is incorporated
herein by reference.
Equity
Compensation Plan Information
As required by Item 201(d) of
Regulation S-K,
the following table provides information regarding our equity
compensation plans as of December 31, 2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Number of Securities
|
|
|
|
(a)
|
|
|
|
|
|
Remaining Available for
|
|
|
|
Number of Securities
|
|
|
|
|
|
Future Issuance Under
|
|
|
|
to be Issued upon
|
|
|
Weighted-Average
|
|
|
Equity Compensation
|
|
|
|
Exercise of
|
|
|
Exercise Price of
|
|
|
Plans (Excluding
|
|
|
|
Outstanding Options,
|
|
|
Outstanding Options,
|
|
|
Securities Reflected in
|
|
Plan Category
|
|
Warrants and Rights
|
|
|
Warrants and Rights
|
|
|
Column (a))
|
|
|
Equity compensation plans approved by security holders
|
|
|
6,424,945
|
|
|
$
|
9.32
|
|
|
|
13,554,993
|
|
Equity compensation plans not approved by security holders
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
6,424,945
|
|
|
$
|
9.32
|
|
|
|
13,554,993
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Item 13.
|
Certain
Relationships and Related Transactions, and Director
Independence.
|
The information required by Items 404 and 407(a) of
Regulation S-K
is included under the captions Certain Transactions and
Relationships and Information Regarding Board of
Directors and Committees in our 2008 Proxy Statement and
is incorporated herein by reference.
|
|
Item 14.
|
Principal
Accounting Fees and Services.
|
The information required by Item 9(e) of Schedule 14A
is included under the caption Appointment of Independent
Registered Public Accounting Firm and Fees in our 2008
Proxy Statement and is incorporated herein by reference.
79
PART IV
Item 15. Exhibits
and Financial Statement Schedules.
(a) Documents Filed as Part of the Report
(1) Financial Statements.
The following consolidated financial statements of Peabody
Energy Corporation are included herein on the pages indicated:
|
|
|
|
|
|
|
Page
|
|
Report of Independent Registered Public Accounting Firm
|
|
|
F-1
|
|
Consolidated Statements of Operations - Years Ended
December 31, 2007, 2006
and 2005
|
|
|
F-2
|
|
Consolidated Balance Sheets December 31, 2007
and December 31, 2006
|
|
|
F-3
|
|
Consolidated Statements of Cash Flows Years Ended
December 31, 2007, 2006 and 2005
|
|
|
F-4
|
|
Consolidated Statements of Changes in Stockholders Equity
- Years Ended December 31, 2007, 2006 and 2005
|
|
|
F-5
|
|
Notes to Consolidated Financial Statements
|
|
|
F-6
|
|
(2) Financial Statement Schedule.
The following financial statement schedule of Peabody Energy
Corporation and the report thereon of the independent registered
public accounting firm are at the pages indicated:
|
|
|
|
|
|
|
Page
|
|
Report of Independent Registered Public Accounting Firm on
Financial Statement Schedule
|
|
|
F-67
|
|
Valuation and Qualifying Accounts
|
|
|
F-68
|
|
All other schedules for which provision is made in the
applicable accounting regulation of the Securities and Exchange
Commission are not required under the related instructions or
are inapplicable and, therefore, have been omitted.
(3) Exhibits.
See Exhibit Index hereto.
Pursuant to the Instructions to Exhibits, certain instruments
defining the rights of holders of long-term debt securities of
the company and its consolidated subsidiaries are not filed
because the total amount of securities authorized under any such
instrument does not exceed 10 percent of the total assets
of the company and its subsidiaries on a consolidated basis. A
copy of such instrument will be furnished to the Commission upon
request.
80
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the
Securities Exchange Act of 1934, the registrant has duly caused
this report to be signed on its behalf by the undersigned,
thereunto duly authorized.
PEABODY ENERGY CORPORATION
Gregory H. Boyce
Chairman and Chief Executive Officer
Date: February 27, 2008
Pursuant to the requirements of the Securities Exchange Act of
1934, this report has been signed below by the following
persons, on behalf of the registrant and in the capacities and
on the dates indicated.
|
|
|
|
|
|
|
Signature
|
|
Title
|
|
Date
|
|
|
|
|
|
|
/s/ GREGORY
H. BOYCE
Gregory
H. Boyce
|
|
Chairman and Chief Executive Officer, Director (principal
executive officer)
|
|
February 27, 2008
|
|
|
|
|
|
/s/ RICHARD
A. NAVARRE
Richard
A. Navarre
|
|
President, Chief Commercial Officer and Chief Financial Officer
(principal financial and accounting officer)
|
|
February 27, 2008
|
|
|
|
|
|
/s/ WILLIAM
A. COLEY
William
A. Coley
|
|
Director
|
|
February 27, 2008
|
|
|
|
|
|
/s/ HENRY
GIVENS, JR.,
PhD
Henry
Givens, Jr., PhD
|
|
Director
|
|
February 27, 2008
|
|
|
|
|
|
/s/ WILLIAM
E. JAMES
William
E. James
|
|
Director
|
|
February 27, 2008
|
|
|
|
|
|
/s/ ROBERT
B. KARN III
Robert
B. Karn III
|
|
Director
|
|
February 27, 2008
|
|
|
|
|
|
/s/ HENRY
E. LENTZ
Henry
E. Lentz
|
|
Director
|
|
February 27, 2008
|
|
|
|
|
|
/s/ WILLIAM
C. RUSNACK
William
C. Rusnack
|
|
Director
|
|
February 27, 2008
|
|
|
|
|
|
/s/ JAMES
R. SCHLESINGER,
PhD
James
R. Schlesinger, PhD
|
|
Director
|
|
February 27, 2008
|
81
|
|
|
|
|
|
|
Signature
|
|
Title
|
|
Date
|
|
|
|
|
|
|
/s/ BLANCHE
M. TOUHILL,
PhD
Blanche
M. Touhill, PhD
|
|
Director
|
|
February 27, 2008
|
|
|
|
|
|
/s/ JOHN
F. TURNER
John
F. Turner
|
|
Director
|
|
February 27, 2008
|
|
|
|
|
|
/s/ SANDRA
VAN TREASE
Sandra
Van Trease
|
|
Director
|
|
February 27, 2008
|
|
|
|
|
|
/s/ ALAN
H. WASHKOWITZ
Alan
H. Washkowitz
|
|
Director
|
|
February 27, 2008
|
82
REPORT OF
INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Directors and Stockholders
Peabody Energy Corporation
We have audited the accompanying consolidated balance sheets of
Peabody Energy Corporation (the Company) as of December 31,
2007 and 2006, and the related consolidated statements of
operations, changes in stockholders equity, and cash flows
for each of the three years in the period ended
December 31, 2007. These financial statements are the
responsibility of the Companys management. Our
responsibility is to express an opinion on these financial
statements based on our audits.
We conducted our audits in accordance with the standards of the
Public Company Accounting Oversight Board (United States). Those
standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are
free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in
the financial statements. An audit also includes assessing the
accounting principles used and significant estimates made by
management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, the financial statements referred to above
present fairly, in all material respects, the consolidated
financial position of Peabody Energy Corporation 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.
As discussed in Note 1 to the consolidated financial
statements, on January 1, 2007, the Company changed its
method of accounting for uncertain tax positions, on
January 1, 2006, the Company changed its method of
accounting for stripping costs and share-based payments, and on
December 31, 2006, the Company changed its method of
accounting for defined pension benefit and other postretirement
plans.
We also have audited, in accordance with the standards of the
Public Company Accounting Oversight Board (United States),
Peabody Energy Corporations 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 27, 2008, expressed an unqualified opinion thereon.
/s/ Ernst & Young LLP
St. Louis, Missouri
February 27, 2008
F-1
PEABODY
ENERGY CORPORATION
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
(Dollars in thousands, except share and per share data)
|
|
|
Revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales
|
|
$
|
4,364,708
|
|
|
$
|
4,002,403
|
|
|
$
|
3,584,422
|
|
Other revenues
|
|
|
210,004
|
|
|
|
105,993
|
|
|
|
81,754
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
|
4,574,712
|
|
|
|
4,108,396
|
|
|
|
3,666,176
|
|
Costs and Expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating costs and expenses
|
|
|
3,574,818
|
|
|
|
3,155,732
|
|
|
|
2,885,320
|
|
Depreciation, depletion and amortization
|
|
|
361,559
|
|
|
|
294,270
|
|
|
|
253,788
|
|
Asset retirement obligation expense
|
|
|
25,610
|
|
|
|
15,830
|
|
|
|
20,329
|
|
Selling and administrative expenses
|
|
|
147,146
|
|
|
|
128,031
|
|
|
|
132,679
|
|
Other operating income:
|
|
|
|
|
|
|
|
|
|
|
|
|
Net gain on disposal or exchange of assets
|
|
|
(88,684
|
)
|
|
|
(53,532
|
)
|
|
|
(44,445
|
)
|
Income from equity affiliates
|
|
|
(14,461
|
)
|
|
|
(22,791
|
)
|
|
|
(15,227
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Profit
|
|
|
568,724
|
|
|
|
590,856
|
|
|
|
433,732
|
|
Interest expense
|
|
|
235,236
|
|
|
|
137,668
|
|
|
|
98,066
|
|
Early debt extinguishment costs
|
|
|
(253
|
)
|
|
|
1,396
|
|
|
|
|
|
Interest income
|
|
|
(7,094
|
)
|
|
|
(11,309
|
)
|
|
|
(9,088
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income From Continuing Operations Before Income Taxes and
Minority Interests
|
|
|
340,835
|
|
|
|
463,101
|
|
|
|
344,754
|
|
Income tax provision (benefit)
|
|
|
(78,112
|
)
|
|
|
(90,084
|
)
|
|
|
63,779
|
|
Minority interests
|
|
|
(2,316
|
)
|
|
|
611
|
|
|
|
2,472
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income From Continuing Operations
|
|
|
421,263
|
|
|
|
552,574
|
|
|
|
278,503
|
|
Income (loss) from discontinued operations
|
|
|
(156,978
|
)
|
|
|
48,123
|
|
|
|
144,150
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income
|
|
$
|
264,285
|
|
|
$
|
600,697
|
|
|
$
|
422,653
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic Earnings Per Share
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from continuing operations
|
|
$
|
1.60
|
|
|
$
|
2.10
|
|
|
$
|
1.06
|
|
Income (loss) from discontinued operations
|
|
|
(0.60
|
)
|
|
|
0.18
|
|
|
|
0.55
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
1.00
|
|
|
$
|
2.28
|
|
|
$
|
1.61
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted Average Shares Outstanding Basic
|
|
|
264,068,180
|
|
|
|
263,419,344
|
|
|
|
261,519,424
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted Earnings Per Share
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from continuing operations
|
|
$
|
1.56
|
|
|
$
|
2.05
|
|
|
$
|
1.04
|
|
Income (loss) from discontinued operations
|
|
|
(0.58
|
)
|
|
|
0.18
|
|
|
|
0.54
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
0.98
|
|
|
$
|
2.23
|
|
|
$
|
1.58
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted Average Shares Outstanding Diluted
|
|
|
269,166,290
|
|
|
|
269,166,005
|
|
|
|
268,013,476
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dividends Declared Per Share
|
|
$
|
0.24
|
|
|
$
|
0.24
|
|
|
$
|
0.17
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to consolidated financial statements
F-2
PEABODY
ENERGY CORPORATION
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
|
(Dollars in thousands, except share and per share data)
|
|
|
ASSETS
|
Current assets
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
45,279
|
|
|
$
|
326,511
|
|
Accounts receivable, net of allowance for doubtful accounts of
$11,888 and $10,893 at December 31, 2007 and 2006,
respectively
|
|
|
257,950
|
|
|
|
320,822
|
|
Inventories
|
|
|
268,862
|
|
|
|
202,909
|
|
Assets from coal trading activities
|
|
|
966,548
|
|
|
|
150,373
|
|
Deferred income taxes
|
|
|
98,633
|
|
|
|
77,562
|
|
Other current assets
|
|
|
215,928
|
|
|
|
109,859
|
|
Current assets of discontinued operations
|
|
|
74,093
|
|
|
|
108,522
|
|
|
|
|
|
|
|
|
|
|
Total current assets
|
|
|
1,927,293
|
|
|
|
1,296,558
|
|
Property, plant, equipment and mine development
|
|
|
|
|
|
|
|
|
Land and coal interests
|
|
|
7,198,090
|
|
|
|
6,498,816
|
|
Buildings and improvements
|
|
|
700,509
|
|
|
|
622,059
|
|
Machinery and equipment
|
|
|
1,267,328
|
|
|
|
1,139,072
|
|
Less accumulated depreciation, depletion and amortization
|
|
|
(1,833,527
|
)
|
|
|
(1,551,117
|
)
|
|
|
|
|
|
|
|
|
|
Property, plant, equipment and mine development, net
|
|
|
7,332,400
|
|
|
|
6,708,830
|
|
Goodwill
|
|
|
|
|
|
|
240,667
|
|
Investments and other assets
|
|
|
408,614
|
|
|
|
304,518
|
|
Noncurrent assets of discontinued operations
|
|
|
|
|
|
|
963,483
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
9,668,307
|
|
|
$
|
9,514,056
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND STOCKHOLDERS EQUITY
|
Current liabilities
|
|
|
|
|
|
|
|
|
Current maturities of long-term debt
|
|
$
|
134,373
|
|
|
$
|
95,757
|
|
Liabilities from coal trading activities
|
|
|
918,596
|
|
|
|
126,731
|
|
Accounts payable and accrued expenses
|
|
|
953,661
|
|
|
|
944,151
|
|
Current liabilities of discontinued operations
|
|
|
180,356
|
|
|
|
160,730
|
|
|
|
|
|
|
|
|
|
|
Total current liabilities
|
|
|
2,186,986
|
|
|
|
1,327,369
|
|
Long-term debt, less current maturities
|
|
|
3,138,727
|
|
|
|
3,181,275
|
|
Deferred income taxes
|
|
|
315,604
|
|
|
|
412,886
|
|
Asset retirement obligations
|
|
|
369,547
|
|
|
|
283,328
|
|
Accrued postretirement benefit costs
|
|
|
785,708
|
|
|
|
809,013
|
|
Other noncurrent liabilities
|
|
|
318,127
|
|
|
|
351,166
|
|
Noncurrent liabilities of discontinued operations
|
|
|
33,236
|
|
|
|
777,156
|
|
|
|
|
|
|
|
|
|
|
Total liabilities
|
|
|
7,147,935
|
|
|
|
7,142,193
|
|
Minority interests, including $16,153 of discontinued operations
at December 31, 2006
|
|
|
701
|
|
|
|
33,337
|
|
Stockholders equity
|
|
|
|
|
|
|
|
|
Preferred Stock $0.01 per share par value;
10,000,000 shares authorized, no shares issued or
outstanding as of December 31, 2007 or 2006
|
|
|
|
|
|
|
|
|
Series A Junior Participating Preferred Stock
1,500,000 shares authorized, no shares issued or
outstanding as of December 31, 2007 or 2006
|
|
|
|
|
|
|
|
|
Perpetual Preferred Stock 750,000 shares
authorized, no shares issued or outstanding as of
December 31, 2007 or 2006
|
|
|
|
|
|
|
|
|
Series Common Stock $0.01 per share par value;
40,000,000 shares authorized, no shares issued or
outstanding as of December 31, 2007 or 2006
|
|
|
|
|
|
|
|
|
Common Stock $0.01 per share par value;
800,000,000 shares authorized, 272,911,564 shares
issued and 270,066,621 shares outstanding as of
December 31, 2007 and 800,000,000 shares authorized,
266,554,157 shares issued and 263,846,839 shares
outstanding as of December 31, 2006
|
|
|
2,729
|
|
|
|
2,666
|
|
Additional paid-in capital
|
|
|
1,750,627
|
|
|
|
1,572,614
|
|
Retained earnings
|
|
|
941,424
|
|
|
|
1,115,994
|
|
Accumulated other comprehensive loss
|
|
|
(67,066
|
)
|
|
|
(249,058
|
)
|
Treasury shares, at cost: 2,844,943 shares as of
December 31, 2007 and 2,707,318 shares as of
December 31, 2006
|
|
|
(108,043
|
)
|
|
|
(103,690
|
)
|
|
|
|
|
|
|
|
|
|
Total stockholders equity
|
|
|
2,519,671
|
|
|
|
2,338,526
|
|
|
|
|
|
|
|
|
|
|
Total liabilities and stockholders equity
|
|
$
|
9,668,307
|
|
|
$
|
9,514,056
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to consolidated financial statements
F-3
PEABODY
ENERGY CORPORATION
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
(Dollars in thousands)
|
|
|
Cash Flows From Operating Activities
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
264,285
|
|
|
$
|
600,697
|
|
|
$
|
422,653
|
|
(Income) loss from discontinued operations
|
|
|
156,978
|
|
|
|
(48,123
|
)
|
|
|
(144,150
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from continuing operations
|
|
|
421,263
|
|
|
|
552,574
|
|
|
|
278,503
|
|
Adjustments to reconcile income from continuing operations to
net cash provided by operating activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation, depletion and amortization
|
|
|
361,559
|
|
|
|
294,270
|
|
|
|
253,788
|
|
Deferred income taxes
|
|
|
(201,444
|
)
|
|
|
(195,546
|
)
|
|
|
10,436
|
|
Amortization of debt discount and debt issuance costs
|
|
|
7,185
|
|
|
|
7,410
|
|
|
|
6,938
|
|
Net gain on disposal or exchange of assets
|
|
|
(88,684
|
)
|
|
|
(53,532
|
)
|
|
|
(44,445
|
)
|
Income from equity affiliates
|
|
|
(14,461
|
)
|
|
|
(22,791
|
)
|
|
|
(15,227
|
)
|
Dividends received from equity affiliates
|
|
|
12,927
|
|
|
|
18,128
|
|
|
|
|
|
Changes in current assets and liabilities, net of acquisitions:
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts receivable, including securitization
|
|
|
64,871
|
|
|
|
(111,242
|
)
|
|
|
(32,601
|
)
|
Inventories
|
|
|
(63,440
|
)
|
|
|
(30,210
|
)
|
|
|
(62,628
|
)
|
Net assets from coal trading activities
|
|
|
(77,631
|
)
|
|
|
(9,419
|
)
|
|
|
11,377
|
|
Other current assets
|
|
|
(56,459
|
)
|
|
|
(20,339
|
)
|
|
|
(12,016
|
)
|
Accounts payable and accrued expenses
|
|
|
56,872
|
|
|
|
104,192
|
|
|
|
182,877
|
|
Asset retirement obligations
|
|
|
15,143
|
|
|
|
(3,058
|
)
|
|
|
12,484
|
|
Workers compensation obligations
|
|
|
2,742
|
|
|
|
(86
|
)
|
|
|
6,345
|
|
Accrued postretirement benefit costs
|
|
|
13,122
|
|
|
|
59,062
|
|
|
|
57,814
|
|
Distributions to minority interests
|
|
|
(2,975
|
)
|
|
|
(4,545
|
)
|
|
|
(2,498
|
)
|
Contributions to pension plans
|
|
|
(5,322
|
)
|
|
|
(6,146
|
)
|
|
|
(7,162
|
)
|
Other, net
|
|
|
1,913
|
|
|
|
12,690
|
|
|
|
39,819
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by continuing operations
|
|
|
447,181
|
|
|
|
591,412
|
|
|
|
683,804
|
|
Net cash provided by (used in) discontinued operations
|
|
|
(130,816
|
)
|
|
|
(8,150
|
)
|
|
|
41,457
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating activities
|
|
|
316,365
|
|
|
|
583,262
|
|
|
|
725,261
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash Flows From Investing Activities
|
|
|
|
|
|
|
|
|
|
|
|
|
Acquisition of Excel Coal, net of cash acquired
|
|
|
|
|
|
|
(1,507,775
|
)
|
|
|
|
|
Additions to property, plant, equipment and mine development
|
|
|
(470,434
|
)
|
|
|
(397,497
|
)
|
|
|
(450,348
|
)
|
Federal coal lease expenditures
|
|
|
(178,193
|
)
|
|
|
(178,193
|
)
|
|
|
(118,364
|
)
|
Proceeds from disposal of assets, net of notes receivable
|
|
|
119,586
|
|
|
|
29,411
|
|
|
|
62,731
|
|
Additions to advance mining royalties
|
|
|
(8,123
|
)
|
|
|
(4,956
|
)
|
|
|
(8,472
|
)
|
Investments in joint ventures
|
|
|
(4,566
|
)
|
|
|
(2,149
|
)
|
|
|
(2,000
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash used in continuing operations
|
|
|
(541,730
|
)
|
|
|
(2,061,159
|
)
|
|
|
(516,453
|
)
|
Net cash used in discontinued operations
|
|
|
(33,602
|
)
|
|
|
(82,659
|
)
|
|
|
(67,749
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash used in investing activities
|
|
|
(575,332
|
)
|
|
|
(2,143,818
|
)
|
|
|
(584,202
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash Flows From Financing Activities
|
|
|
|
|
|
|
|
|
|
|
|
|
Change in revolving line of credit
|
|
|
97,700
|
|
|
|
|
|
|
|
|
|
Proceeds from long-term debt
|
|
|
|
|
|
|
2,604,087
|
|
|
|
11,734
|
|
Payments of long-term debt
|
|
|
(117,817
|
)
|
|
|
(1,045,973
|
)
|
|
|
(20,198
|
)
|
Common stock repurchase
|
|
|
|
|
|
|
(99,774
|
)
|
|
|
|
|
Dividends paid
|
|
|
(63,658
|
)
|
|
|
(63,456
|
)
|
|
|
(44,535
|
)
|
Payment of debt issuance costs
|
|
|
(774
|
)
|
|
|
(40,611
|
)
|
|
|
|
|
Excess tax benefit related to stock options exercised
|
|
|
96,743
|
|
|
|
33,173
|
|
|
|
|
|
Proceeds from stock options exercised
|
|
|
26,197
|
|
|
|
15,617
|
|
|
|
22,573
|
|
Issuance of notes payable
|
|
|
|
|
|
|
|
|
|
|
(11,459
|
)
|
Proceeds from employee stock purchases
|
|
|
6,377
|
|
|
|
4,518
|
|
|
|
3,009
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by (used in) continuing operations
|
|
|
44,768
|
|
|
|
1,407,581
|
|
|
|
(38,876
|
)
|
Net cash provided by (used in) discontinued operations
|
|
|
(67,033
|
)
|
|
|
(23,792
|
)
|
|
|
11,459
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by (used in) financing activities
|
|
|
(22,265
|
)
|
|
|
1,383,789
|
|
|
|
(27,417
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net increase (decrease) in cash and cash equivalents
|
|
|
(281,232
|
)
|
|
|
(176,767
|
)
|
|
|
113,642
|
|
Cash and cash equivalents at beginning of year
|
|
|
326,511
|
|
|
|
503,278
|
|
|
|
389,636
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents at end of year
|
|
$
|
45,279
|
|
|
$
|
326,511
|
|
|
$
|
503,278
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to consolidated financial statements
F-4
PEABODY
ENERGY CORPORATION
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Additional
|
|
|
Other
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
Common
|
|
|
Paid-In
|
|
|
Comprehensive
|
|
|
Retained
|
|
|
Treasury
|
|
|
Stockholders
|
|
|
|
Stock
|
|
|
Capital
|
|
|
Loss
|
|
|
Earnings
|
|
|
Stock
|
|
|
Equity
|
|
|
|
|
|
|
|
|
|
(Dollars in thousands)
|
|
|
|
|
|
|
|
|
December 31, 2004
|
|
$
|
2,596
|
|
|
$
|
1,435,562
|
|
|
$
|
(60,618
|
)
|
|
$
|
350,968
|
|
|
$
|
(3,916
|
)
|
|
$
|
1,724,592
|
|
Comprehensive income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
422,653
|
|
|
|
|
|
|
|
422,653
|
|
Increase in fair value of cash flow hedges (net of $7,613 tax
provision)
|
|
|
|
|
|
|
|
|
|
|
11,421
|
|
|
|
|
|
|
|
|
|
|
|
11,421
|
|
Minimum pension liability adjustment (net of $1,601 tax
provision)
|
|
|
|
|
|
|
|
|
|
|
2,402
|
|
|
|
|
|
|
|
|
|
|
|
2,402
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Comprehensive income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
436,476
|
|
Dividends paid
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(44,535
|
)
|
|
|
|
|
|
|
(44,535
|
)
|
Stock options exercised
|
|
|
36
|
|
|
|
22,627
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
22,663
|
|
Income tax benefits from stock options exercised
|
|
|
|
|
|
|
30,437
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
30,437
|
|
Employee stock purchases
|
|
|
2
|
|
|
|
3,007
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,009
|
|
Employee stock grants
|
|
|
4
|
|
|
|
(4
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Share-based compensation
|
|
|
|
|
|
|
5,825
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
5,825
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2005
|
|
$
|
2,638
|
|
|
$
|
1,497,454
|
|
|
$
|
(46,795
|
)
|
|
$
|
729,086
|
|
|
$
|
(3,916
|
)
|
|
$
|
2,178,467
|
|
Comprehensive income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
600,697
|
|
|
|
|
|
|
|
600,697
|
|
Increase in fair value of cash flow hedges (net of $16,230 tax
provision)
|
|
|
|
|
|
|
|
|
|
|
24,347
|
|
|
|
|
|
|
|
|
|
|
|
24,347
|
|
Minimum pension liability adjustment (net of $16,842 tax
provision)
|
|
|
|
|
|
|
|
|
|
|
22,377
|
|
|
|
|
|
|
|
|
|
|
|
22,377
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Comprehensive income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
647,421
|
|
Postretirement plans and workers compensation obligations
(net of $149,499 tax benefit):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated actuarial loss, net of tax
|
|
|
|
|
|
|
|
|
|
|
(241,954
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
Prior service cost, net of tax
|
|
|
|
|
|
|
|
|
|
|
(7,033
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(248,987
|
)
|
|
|
|
|
|
|
|
|
|
|
(248,987
|
)
|
Dividends paid
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(63,456
|
)
|
|
|
|
|
|
|
(63,456
|
)
|
Stock options exercised
|
|
|
20
|
|
|
|
15,600
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
15,620
|
|
Share-based compensation
|
|
|
|
|
|
|
21,877
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
21,877
|
|
Income tax benefits from stock options exercised
|
|
|
|
|
|
|
33,173
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
33,173
|
|
Employee stock purchases
|
|
|
2
|
|
|
|
4,516
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4,518
|
|
Employee stock grants
|
|
|
6
|
|
|
|
(6
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Advance stripping adjustment (net of $95,189 tax benefit)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(150,333
|
)
|
|
|
|
|
|
|
(150,333
|
)
|
Shares repurchased
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(99,774
|
)
|
|
|
(99,774
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2006
|
|
$
|
2,666
|
|
|
$
|
1,572,614
|
|
|
$
|
(249,058
|
)
|
|
$
|
1,115,994
|
|
|
$
|
(103,690
|
)
|
|
$
|
2,338,526
|
|
Comprehensive income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
264,285
|
|
|
|
|
|
|
|
264,285
|
|
Increase in fair value of cash flow hedges (net of $14,530 tax
provision)
|
|
|
|
|
|
|
|
|
|
|
21,796
|
|
|
|
|
|
|
|
|
|
|
|
21,796
|
|
Postretirement plans and workers compensation obligations
(net of $50,232 tax provision):
|
|
|
|
|
|
|
|
|
|
|
87,211
|
|
|
|
|
|
|
|
|
|
|
|
87,211
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Comprehensive income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
373,292
|
|
Dividends paid
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(63,658
|
)
|
|
|
|
|
|
|
(63,658
|
)
|
Patriot Coal Corp. spin-off
|
|
|
|
|
|
|
|
|
|
|
72,985
|
|
|
|
(375,197
|
)
|
|
|
|
|
|
|
(302,212
|
)
|
Stock options exercised
|
|
|
54
|
|
|
|
26,143
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
26,197
|
|
Income tax benefits from stock options exercised
|
|
|
|
|
|
|
96,743
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
96,743
|
|
Employee stock purchases
|
|
|
2
|
|
|
|
6,375
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
6,377
|
|
Employee stock grants
|
|
|
7
|
|
|
|
(7
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Share-based compensation
|
|
|
|
|
|
|
48,759
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
48,759
|
|
Shares relinquished
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(4,353
|
)
|
|
|
(4,353
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2007
|
|
$
|
2,729
|
|
|
$
|
1,750,627
|
|
|
$
|
(67,066
|
)
|
|
$
|
941,424
|
|
|
$
|
(108,043
|
)
|
|
$
|
2,519,671
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to consolidated financial statements
F-5
PEABODY
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS
|
|
(1)
|
Summary
of Significant Accounting Policies
|
Basis
of Presentation
The consolidated financial statements include the accounts of
Peabody Energy Corporation (the Company) and its affiliates. All
intercompany transactions, profits and balances have been
eliminated in consolidation.
Description
of Business
The Company is engaged in the mining of steam coal for sale
primarily to electric utilities and metallurgical coal for sale
to industrial customers. The Companys mining operations
are located in the United States and Australia, and include an
equity interest in mining operations in Venezuela. In addition
to the Companys mining operations, the Company markets,
brokers and trades coal. The Companys other energy related
commercial activities include the development of mine-mouth
coal-fueled generating plants, the management of its vast coal
reserve and real estate holdings, coalbed methane production and
Btu conversion technologies. The Companys Btu conversion
projects are designed to expand the uses of coal through various
technologies such as coal-to-liquids and coal gasification.
New
Accounting Pronouncements
In December 2004, the Financial Accounting Standards Board
(FASB) issued Statement of Financial Accounting Standard (SFAS)
No. 123 (revised 2004), Share-Based Payment
(SFAS No. 123(R)), which is a revision of
SFAS No. 123, Accounting for Stock-Based
Compensation (SFAS No. 123).
SFAS No. 123(R) supersedes Accounting Principles Board
(APB) Opinion No. 25, Accounting for Stock Issued to
Employees (APB Opinion No. 25) and amends FASB
Statement No. 95, Statement of Cash Flows.
Generally, the approach in SFAS No. 123(R) is similar
to the approach described in SFAS No. 123. However,
SFAS No. 123(R) requires all share-based payments to
employees, including employee stock options, to be recognized in
the income statement based on their fair values at the grant
date.
The Company adopted SFAS No. 123(R) on January 1,
2006 and used the modified prospective method, in which
compensation cost is recognized beginning with the effective
date (a) based on the requirements of
SFAS No. 123(R) for all share-based payments granted
or modified after the effective date and (b) based on the
requirements of SFAS No. 123 for all awards granted to
employees prior to the effective date of
SFAS No. 123(R) that remain unvested on the effective
date. Prior to January 1, 2006, the Company had elected to
apply APB Opinion No. 25 and related interpretations in
accounting for its stock option plans, as permitted under
SFAS No. 123 and SFAS No. 148
Accounting for Stock-Based Compensation-Transition and
Disclosure. Beginning in 2006, SFAS No. 123(R)
also requires that excess income tax benefits from stock options
exercised be recorded as financing cash inflow on the statements
of cash flows. The excess income tax benefit from stock option
exercises during 2005 is included in operating cash flows,
netted in deferred tax activity.
In March 2005, the Emerging Issues Task Force (EITF) issued EITF
Issue
No. 04-6,
Accounting for Stripping Costs in the Mining
Industry (EITF Issue
No. 04-6).
EITF Issue
No. 04-6
and its interpretations require stripping costs incurred during
a period to be attributed only to the inventory costs of the
coal that is extracted during that same period. The Company
adopted EITF Issue
No. 04-6
on January 1, 2006 and utilized the cumulative effect
adjustment approach whereby the cumulative effect adjustment
reduced retained earnings by $150.3 million, net of tax.
This non-cash item is excluded from the consolidated statements
of cash flows. Advance stripping costs are primarily expensed as
incurred.
In September 2006, the FASB issued SFAS No. 158,
Employers Accounting for Defined Benefit Pension and
Other Postretirement Plans (SFAS No. 158). For
fiscal years ending after December 15, 2006,
SFAS No. 158 requires recognition of the funded status
of pension and other postretirement benefit plans (an
F-6
PEABODY
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
asset for overfunded status or a liability for underfunded
status) in a companys balance sheet. In addition, the
standard requires recognition of actuarial gains and losses,
prior service cost, and any remaining transition amounts from
the initial application of SFAS No. 87,
Employers Accounting for Pensions
(SFAS No. 87) and SFAS No. 106,
Employers Accounting for Postretirement Benefits
Other Than Pensions (SFAS No. 106) when
determining a plans funded status, with a corresponding
charge to accumulated other comprehensive income (loss).
The Company adopted SFAS No. 158 on December 31,
2006, and as a result, recorded a noncurrent liability of
$376.1 million, which reflected the net underfunded status
of the pension, retiree healthcare and workers
compensation plans. The funded status of each plan was measured
as the difference between the fair value of the assets and the
projected benefit obligation (the funded status).
SFAS No. 158 did not impact net income.
In June 2006, the FASB issued Interpretation No. 48,
Accounting for Uncertainty in Income Taxes an
interpretation of FASB Statement No. 109
(FIN No. 48). This interpretation prescribes a
recognition threshold and measurement attribute for the
financial statement recognition and measurement of a tax
position taken or expected to be taken in a tax return.
FIN No. 48 also provides guidance on derecognition,
classification, interest and penalties, accounting in interim
periods, disclosure and transition.
The Company adopted the provisions of FIN No. 48 on
January 1, 2007, and as a result, reported
$135.0 million of net unrecognized tax benefits
($144.0 million gross) in its consolidated financial
statements. Due to the valuation allowance recorded against the
Companys deferred tax asset for net operating loss (NOL)
carryforwards as of January 1, 2007, none of the
$135.0 million required an adjustment to retained earnings
upon adoption.
In September 2006, the FASB issued SFAS No. 157,
Fair Value Measurements, (SFAS No. 157).
SFAS No. 157 defines fair value, establishes a
framework for measuring fair value in generally accepted
accounting principles (GAAP), and expands disclosures about fair
value measurements. SFAS No. 157 applies under other
accounting pronouncements that require or permit fair value
measurements, and therefore does not require any new fair value
measurements. SFAS No. 157 is effective for fiscal
years beginning after November 15, 2007 (January 1,
2008 for the Company). In February 2008, the FASB amended
SFAS No. 157 to exclude leasing transactions and to
delay the effective date by one year for nonfinancial assets and
liabilities that are recognized or disclosed at fair value in
the financial statements on a nonrecurring basis. The Company is
in the process of determining the effect, if any, the adoption
of SFAS No. 157 will have on its financial statements.
In February 2007, the FASB issued SFAS No. 159,
The Fair Value Option for Financial Assets and Financial
Liabilities, including an amendment of FASB Statement
No. 115 (SFAS No. 159).
SFAS No. 159 provides all entities with an option to
report selected financial assets and liabilities at fair value.
SFAS No. 159 is effective for financial statements
issued for fiscal years beginning after November 15, 2007
(January 1, 2008 for the Company). The Company is in the
process of determining the effect, if any, the adoption of
SFAS No. 159 will have on its financial statements.
In December 2007, the FASB issued SFAS No. 160,
Noncontrolling Interests in Consolidated Financial
Statements an amendment of ARB No. 51
(SFAS No. 160). SFAS No. 160 establishes
accounting and reporting standards for (1) noncontrolling
interests in partially owned consolidated subsidiaries and
(2) the loss of control of subsidiaries.
SFAS No. 160 requires noncontrolling interests
(minority interests) to be reported as a separate component of
equity. The amount of net income attributable to the
noncontrolling interest will be included in consolidated net
income on the face of the income statement. In addition, this
statement requires that a parent recognize a gain or loss in net
income when a subsidiary is deconsolidated. Such gain or loss
will be measured using the fair value of the noncontrolling
equity investment on the deconsolidation date. SFAS 160
also includes expanded disclosure requirements regarding the
interests of the parent and its
F-7
PEABODY
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
noncontrolling interest. SFAS No. 160 is effective for
fiscal years, and interim periods within those fiscal years,
beginning on or after December 15, 2008 (January 1,
2009 for the Company). Early adoption is not allowed. The
Company is in the process of determining the effect the adoption
of SFAS No. 160 will have on its financial statements.
In December 2007, the FASB issued SFAS No. 141(R),
Business Combinations, which replaces
SFAS No. 141. SFAS No. 141(R) significantly
changes the principles and requirements for how the acquirer of
a business recognizes and measures in its financial statements
the identifiable assets acquired, the liabilities assumed, and
any noncontrolling interest in the acquiree. This statement also
provides guidance for recognizing and measuring the goodwill
acquired in the business combination and determines what
information to disclose to enable users of the financial
statements to evaluate the nature and financial effects of the
business combination. This statement applies prospectively to
business combinations for which the acquisition date is on or
after the beginning of the first annual reporting period
beginning on or after December 15, 2008 (January 1,
2009 for the Company). The Company is in the process of
determining the effect, if any, the adoption of
SFAS No. 141(R) will have on its financial statements.
Sales
The Companys revenue from coal sales is realized and
earned when risk of loss passes to the customer. Coal sales are
made to the Companys customers under the terms of coal
supply agreements, most of which are long-term (greater than one
year). Under the typical terms of these coal supply agreements,
title and risk of loss transfer to the customer at the mine or
port, where coal is loaded to the rail, barge, ocean-going
vessel, truck or other transportation source(s) that serves each
of the Companys mines. The Company incurs certain
add-on taxes and fees on coal sales. Coal sales are
reported including taxes and fees charged by various federal and
state governmental bodies. Coal sales includes the freight
charges on destination customer contracts.
Other
Revenues
Other revenues include royalties related to coal lease
agreements, sales agency commissions, farm income, coalbed
methane revenues, property and facility rentals, generation
development activities, net revenues from coal trading
activities accounted for under SFAS No. 133,
Accounting for Derivative Instruments and Hedging
Activities (SFAS No. 133), as amended, and
contract termination or restructuring payments. 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 annual 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 five to 15 years, or can be for an unspecified
period until all reserves are depleted.
Discontinued
Operations
The Company classifies items within discontinued operations in
the consolidated statements of operations when the operations
and cash flows of a particular component (defined as operations
and cash flows that can be clearly distinguished, operationally
and for financial reporting purposes, from the rest of the
entity) of the Company have been (or will be) eliminated from
the ongoing operations of the Company as a result of a disposal
transaction, and the Company will no longer have any significant
continuing involvement in the operations of that component.
Discontinued operations, net of taxes, for the years ended
December 31, 2007, 2006, and 2005, reflected a
$157.0 million loss, $48.1 million income, and
$144.2 million income, respectively, related to the
spin-off of Patriot Coal Corporation (Patriot). See Note 2
for additional details related to discontinued operations.
F-8
PEABODY
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Cash
and Cash Equivalents
Cash and cash equivalents are stated at cost, which approximates
fair value. Cash equivalents consist of highly liquid
investments with original maturities of three months or less.
Inventories
Materials and supplies and coal inventory are valued at the
lower of average cost or market. Raw coal represents coal
stockpiles that may be sold in current condition or may be
further processed prior to shipment to a customer. Coal
inventory costs include labor, supplies, equipment, operating
overhead and other related costs.
Assets
and Liabilities from Coal Trading Activities
The Companys coal trading activities are evaluated under
SFAS No. 133, as amended. Trading contracts that meet
the SFAS No. 133 definition of a derivative are
accounted for at fair value, while contracts that do not qualify
as derivatives are accounted for under the accrual method. All
trading contracts are recorded subject to the requirements of
EITF Issue
No. 02-3,
Issues Involved in Accounting for Derivative Contracts
Held for Trading Purposes and Contracts Involved in Energy
Trading and Risk Management Activities (EITF Issue
No. 02-3).
The Companys trading contracts are reflected at fair value
and are included in Assets and liabilities from coal
trading activities in the consolidated balance sheets as
of December 31, 2007 and 2006. Under EITF Issue
No. 02-3,
all mark-to-market gains and losses on energy trading contracts
(including derivatives and hedged contracts) are presented on a
net basis in the statement of operations, even if settled
physically. The Companys consolidated statements of
operations reflect revenues related to all mark-to-market
trading contracts on a net basis in Other revenues.
Property,
Plant, Equipment and Mine Development
Property, plant, equipment and mine development are recorded at
cost. Interest costs applicable to major asset additions are
capitalized during the construction period, including
$2.0 million, $3.0 million and $0.1 million for
the years ended December 31, 2007, 2006 and 2005,
respectively.
Expenditures which extend the useful lives of existing plant and
equipment assets are capitalized. Maintenance and repairs are
charged to operating costs as incurred. Costs incurred to
develop coal mines or to expand the capacity of operating mines
are capitalized. 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. Costs to acquire computer hardware and the
development
and/or
purchase of software for internal use are capitalized and
depreciated over the estimated useful lives.
Coal reserves are recorded at cost, or at fair value in the case
of acquired businesses. As of December 31, 2007 and 2006,
the net book value of coal reserves totaled $5.6 billion
and $4.6 billion, respectively. These amounts included
$2.1 billion and $1.7 billion at December 31,
2007 and 2006, respectively, attributable to properties where
the Company was not currently engaged in mining operations or
leasing to third parties and, therefore, the coal reserves were
not currently being depleted. Included in the book value of coal
reserves are mineral rights for leased coal interests including
advance royalties and the net book value of these mineral rights
was $2.2 billion and $3.2 billion at December 31,
2007 and 2006, respectively. The remaining net book value of the
Companys coal reserves of $3.4 billion and
$1.4 billion, at December 31, 2007 and 2006,
respectively, relates to coal reserves held by fee ownership.
F-9
PEABODY
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Depletion of coal reserves and amortization of advance royalties
is computed using the units-of-production method utilizing only
proven and probable reserves (as adjusted for recoverability
factors) in the depletion base. Mine development costs are
principally amortized over the estimated lives of the mines
using the straight-line method. Depreciation of plant and
equipment (excluding life of mine assets) is computed using the
straight-line method over the estimated useful lives as follows:
|
|
|
|
|
Years
|
|
Building and improvements
|
|
10 to 20
|
Machinery and equipment
|
|
3 to 29
|
Leasehold improvements
|
|
Life of Lease
|
In addition, certain plant and equipment assets associated with
mining are depreciated using the straight-line method over the
estimated life of the mine, which varies from one to
29 years.
Investments
in Joint Ventures
The Company accounts for its investments in less than majority
owned corporate joint ventures under either the equity or cost
method. The Company applies the equity method to investments in
joint ventures when it has the ability to exercise significant
influence over the operating and financial policies of the joint
venture. Investments accounted for under the equity method are
initially recorded at cost, and any difference between the cost
of the Companys investment and the underlying equity in
the net assets of the joint venture at the investment date is
amortized over the lives of the related assets that gave rise to
the difference. The Companys pro rata share of earnings
from joint ventures and basis difference amortization is
reported in the consolidated statements of operations in
Income from equity affiliates. The book value of the
Companys equity method investments as of December 31,
2007 and 2006 was $76.7 million and $65.1 million,
respectively, and is reported in Investments and other
assets in the consolidated balance sheets. Included in the
Companys equity method investments was its 25.5% interest
in Carbones del Guasare, which owns and operates the Paso Diablo
Mine in Venezuela. The Companys investment in Paso Diablo
was $68.4 million and $60.1 million as of
December 31, 2007 and 2006, respectively. The Company
recorded income from this equity affiliate of
$21.2 million, $28.0 million and $20.0 million
for the years ended December 31, 2007, 2006 and 2005,
respectively, which is reported in Income from equity
affiliates in the consolidated statements of operations.
The Company received dividends from this equity affiliate of
$12.9 million and $18.1 million for the years ended
December 31, 2007 and 2006, respectively, while no
dividends were received for the year ended December 31,
2005.
Generation
Development Costs
Development costs related to coal-based electricity generation,
including expenditures for permitting and licensing, are
capitalized at cost under the guidelines in
SFAS No. 142, Goodwill and Other Intangible
Assets.
Start-up
costs, as defined in Statement of Position (SOP)
No. 98-5,
Reporting on the Costs of
Start-up
Activities, are expensed as incurred. Development costs of
$36.9 million and $21.4 million were recorded as part
of Investments and other assets in the consolidated
balance sheets as of December 31, 2007 and 2006,
respectively.
Asset
Retirement Obligations
SFAS No. 143, Accounting for Asset Retirement
Obligations (SFAS No. 143) addresses
financial accounting and reporting for obligations associated
with the retirement of tangible long-lived assets and the
associated asset retirement costs. The Companys asset
retirement obligation (ARO) liabilities primarily consist of
spending estimates related to reclaiming surface land and
support facilities at both surface and underground mines in
accordance with applicable reclamation laws as defined by each
mining permit.
F-10
PEABODY
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The Company estimates its ARO liabilities for final reclamation
and mine closure based upon detailed engineering calculations of
the amount and timing of the future cash spending for a
third-party to perform the required work. Spending estimates are
escalated for inflation and then discounted at the
credit-adjusted, risk-free rate. The Company records an ARO
asset associated with the discounted liability for final
reclamation and mine closure. The obligation and corresponding
asset are recognized in the period in which the liability is
incurred. The ARO asset is amortized on the units-of-production
method over its expected life and the ARO liability is accreted
to the projected spending date. As changes in estimates occur
(such as mine plan revisions, changes in estimated costs or
changes in timing of the performance of reclamation activities),
the revisions to the obligation and asset are recognized at the
appropriate credit-adjusted, risk-free rate. The Company also
recognizes an obligation for contemporaneous reclamation
liabilities incurred as a result of surface mining.
Contemporaneous reclamation consists primarily of grading,
topsoil replacement and revegetation of backfilled pit areas.
Environmental
Liabilities
Included in Other noncurrent liabilities are
accruals for other environmental matters that are recorded in
operating expenses when it is probable that a liability has been
incurred and the amount of the liability can be reasonably
estimated. Accrued liabilities are exclusive of claims against
third parties and are not discounted. In general, costs related
to environmental remediation are charged to expense.
Income
Taxes
Income taxes are accounted for using a balance sheet approach in
accordance with SFAS No. 109, Accounting for
Income Taxes. The Company accounts for deferred income
taxes by applying statutory tax rates in effect at the date of
the balance sheet to differences between the book and tax basis
of assets and liabilities. A valuation allowance is established
if it is more likely than not that the related tax
benefits will not be realized. In determining the appropriate
valuation allowance, the Company considers projected realization
of tax benefits based on expected levels of future taxable
income, available tax planning strategies, and the overall
deferred tax position.
FIN No. 48 Accounting for Uncertainty in Income
Taxes an interpretation of FASB Statement
No. 109 prescribes a recognition threshold and
measurement attribute for the financial statement recognition
and measurement of a tax position taken or expected to be taken
in a tax return. FIN No. 48 also provides guidance on
derecognition, classification, interest and penalties,
accounting in interim periods, disclosure and transition. The
Company adopted this interpretation effective January 1,
2007.
Postretirement
Health Care and Life Insurance Benefits
The Company accounts for postretirement benefits other than
pensions in accordance with SFAS No. 106, which
requires the costs of benefits to be provided to be accrued over
the employees period of active service. These costs are
determined on an actuarial basis. As a result of the adoption of
SFAS No. 158 on December 31, 2006, the
Companys consolidated balance sheet reflects the funded
status of postretirement benefits.
Pension
Plans
The Company sponsors non-contributory defined benefit pension
plans accounted for in accordance with SFAS No. 87,
which requires that the cost to provide the benefits be accrued
over the employees period of active service. These costs
are determined on an actuarial basis. SFAS No. 158
amended SFAS No. 87 and as a result of the adoption of
SFAS No. 158 on December 31, 2006, the
Companys consolidated balance sheet reflects the funded
status of the defined benefit pension plans.
F-11
PEABODY
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Postemployment
Benefits
The Company provides postemployment benefits to qualifying
employees, former employees and dependents and accounts for
these benefits on the accrual basis in accordance with
SFAS No. 112 Employers Accounting for
Postemployment Benefits. Postemployment benefits include
workers compensation occupational disease, which is
accounted for on the actuarial basis over the employees
period of active service; workers compensation traumatic
injury claims, which are accounted for based on estimated loss
rates applied to payroll and claim reserves determined by
independent actuaries and claims administrators; disability
income benefits, which are accrued when a claim occurs; and
continuation of medical benefits, which are recognized when the
obligation occurs. As a result of the adoption of
SFAS No. 158 on December 31, 2006, the
Companys consolidated balance sheet reflects the funded
status of postemployment benefits.
Derivatives
SFAS No. 133, as amended, requires the recognition at
fair value of all derivatives as assets or liabilities on the
consolidated balance sheets. Gains or losses from derivative
financial instruments designated as fair value hedges are
recognized immediately in the consolidated statements of
operations, along with the offsetting gain or loss related to
the underlying hedged item.
Gains or losses on derivative financial instruments designated
as cash flow hedges are recorded as a separate component of
stockholders equity until settlement (or until hedge
ineffectiveness is determined), whereby gains or losses are
reclassified to the consolidated statements of operations in
conjunction with the recognition of the underlying hedged item.
To the extent that the periodic changes in the fair value of the
derivatives are not effective, or if the hedge ceases to qualify
for hedge accounting, the ineffective portion of the periodic
non-cash changes are recorded in Operating costs and
expenses in the consolidated statement of operations in
the period of the change. The potential for hedge
ineffectiveness is only present in the design of the hedge
relationship in the Companys cash flow hedges of
anticipated fuel purchases (see Note 3 for additional
details).
Use of
Estimates in the Preparation of the Consolidated Financial
Statements
The preparation of financial statements in conformity with
generally accepted accounting principles requires management to
make estimates and assumptions that affect the reported amounts
of assets and liabilities and disclosure of contingent assets
and liabilities at the date of the financial statements and
reported amounts of revenues and expenses during the reporting
period. Actual results could differ from those estimates.
In particular, the Company has significant long-term liabilities
relating to retiree health care, work-related injuries and
illnesses and defined benefit pension plans. Each of these
liabilities is actuarially determined and the Company uses
various actuarial assumptions, including the discount rate and
future cost trends, to estimate the costs and obligations for
these items. In addition, the Company has significant asset
retirement obligations that involve estimations of costs to
remediate mining lands and the timing of cash outlays for such
costs. If these assumptions do not materialize as expected,
actual cash expenditures and costs incurred could differ
materially from current estimates. Moreover, regulatory changes
could increase the obligation to satisfy these or additional
obligations.
Finally, in evaluating the valuation allowance related to the
Companys deferred tax assets, the Company takes into
account various factors, including the expected level of future
taxable income and available tax planning strategies. If actual
results differ from the assumptions made in the evaluation of
the valuation allowance, the Company may record a change in
valuation allowance through income tax expense in the period
such determination is made.
F-12
PEABODY
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Impairment
of Long-Lived Assets
The Company records impairment losses on long-lived assets used
in operations when events and circumstances indicate that assets
might be impaired and the undiscounted cash flows estimated to
be generated by those assets under various assumptions are less
than the carrying amounts of the assets. Impairment losses are
measured by comparing the estimated fair value of the impaired
asset to its carrying amount. There were no impairment losses
recorded during the periods covered by the consolidated
financial statements.
Fair
Value of Financial Instruments
SFAS No. 107, Disclosures About Fair Value of
Financial Instruments, defines the fair value of a
financial instrument as the amount at which the instrument could
be exchanged in a current transaction between willing parties,
other than in a forced or liquidation sale. See Note 21 for
additional information.
Foreign
Currency Translation
The Companys foreign subsidiaries utilize the
U.S. dollar as their functional currency. As such, monetary
assets and liabilities are translated at year-end exchange rates
while non-monetary items are translated at historical rates.
Income and expense accounts are translated at the average rates
in effect during the year, except for those expenses related to
balance sheet amounts that are remeasured at historical exchange
rates. Gains and losses from foreign currency remeasurement are
included in the consolidated statements of operations with
amounts related to the remeasurement of deferred tax balances
included as a component of the income tax provision. The foreign
currency remeasurement loss for the years ended
December 31, 2007 and 2006 was $60.4 million and
$12.8 million, respectively. Gains and losses from foreign
currency remeasurement did not have a material impact on the
Companys consolidated results of operations for the year
ended December 31, 2005.
Business
Combinations
The Company accounts for its business acquisitions under the
purchase method of accounting consistent with the requirements
of SFAS No. 141, Business Combinations.
The total cost of acquisitions is allocated to the underlying
identifiable net assets, based on their respective estimated
fair values. Determining the fair value of assets acquired and
liabilities assumed requires managements judgment, and the
utilization of independent valuation experts, and often involves
the use of significant estimates and assumptions, including
assumptions with respect to future cash inflows and outflows,
discount rates, asset lives, and market multiples, among other
items.
Share-Based
Compensation
The Company accounts for share-based compensation in accordance
with the fair value recognition provisions of
SFAS No. 123 (Revised 2004), Share-Based
Payment (SFAS 123(R)), which the Company adopted
using the modified prospective option on January 1, 2006.
Under SFAS No. 123(R), share-based compensation
expense is generally measured at the grant date and recognized
as expense over the vesting period of the award.
Reclassifications
Certain amounts in prior periods have been reclassified to
conform with the presentation of 2007, with no effect on
previously reported net income or stockholders equity.
F-13
PEABODY
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
(2)
|
Discontinued
Operations
|
On October 10, 2007, the Companys Board of Directors
approved a spin-off of portions of its
Eastern U.S. Mining operations business segment. The
spin-off was accomplished on October 31, 2007 through a
dividend of all outstanding shares of Patriot, which is now an
independent public company traded on the New York Stock
Exchange (symbol PCX). Prior to the spin-off, the Company
received necessary regulatory approvals including a private
letter ruling on the tax-free nature of the transaction from the
Internal Revenue Service, and a declaration of effectiveness for
Patriots registration statement on Form 10 with the
Securities and Exchange Commission (SEC). Distribution of the
Patriot stock to the Companys stockholders occurred on
October 31, 2007, at a ratio of one share of Patriot stock
for every 10 shares of Peabody stock held on the record
date of October 22, 2007.
The spin-off included eight company-operated mines, two joint
venture mines, and numerous contractor operated mines serviced
by eight coal preparation facilities along with 1.2 billion
tons of proven and probable coal reserves. Revenues, pretax
income (loss) and the income tax provision (benefit) reported in
discontinued operations were as follows.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
(Dollars in thousands)
|
|
|
Revenues
|
|
$
|
1,024,462
|
|
|
$
|
1,147,919
|
|
|
$
|
978,277
|
|
Income (loss) before income taxes and minority interests
|
|
|
(235,215
|
)
|
|
|
67,861
|
|
|
|
81,331
|
|
Income tax provision (benefit)
|
|
|
(81,473
|
)
|
|
|
8,569
|
|
|
|
(62,819
|
)
|
The Company entered into agreements to pay for certain retiree
healthcare liabilities of Patriot arising under the Coal Act and
the 2007 National Bituminous Coal Wage Agreement (NBCWA), as
well as retiree healthcare liabilities relating to certain
Patriot salaried employees. These liabilities totaled
$617 million at October 31, 2007 and are included in
accrued postretirement benefit costs.
The 2007 loss before income taxes and minority interests
totaling $235.2 million includes certain charges taken in
connection with the spin-off including a $162.2 million
loss related to firm purchase commitments that extend through
2010 for purchases from Patriot to supply pre-existing below
market customer sales contracts that will be sourced from
Patriot operations, $23.8 million of accelerated vesting of
share-based compensation awarded to Patriot executives and
$21.5 million of transaction related costs.
The Company has also entered into a transition services
agreement to provide certain administrative and other services
to Patriot for a period of six months. Patriot will have the
option to extend this agreement for an additional term of three
months and, under certain circumstances, for another term of
three months. Under this agreement, the Company billed
$0.9 million for transitional services in the last two
months of 2007.
F-14
PEABODY
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The assets, liabilities and minority interests of the
discontinued operations as of December 31, 2007 and 2006
are shown below.
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
|
(Dollars in thousands)
|
|
|
Assets
|
|
|
|
|
|
|
|
|
Current assets
|
|
|
|
|
|
|
|
|
Accounts receivable, net
|
|
$
|
74,093
|
|
|
$
|
37,420
|
|
Inventories
|
|
|
|
|
|
|
34,693
|
|
Deferred income taxes
|
|
|
|
|
|
|
29,405
|
|
Other current assets
|
|
|
|
|
|
|
7,004
|
|
|
|
|
|
|
|
|
|
|
Total current assets
|
|
|
74,093
|
|
|
|
108,522
|
|
Property, plant, equipment and mine development, net
|
|
|
|
|
|
|
842,687
|
|
Investments and other assets
|
|
|
|
|
|
|
120,796
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
74,093
|
|
|
$
|
1,072,005
|
|
|
|
|
|
|
|
|
|
|
Liabilities
|
|
|
|
|
|
|
|
|
Current liabilities
|
|
|
|
|
|
|
|
|
Accounts payable and accrued expenses
|
|
$
|
180,356
|
|
|
$
|
160,730
|
|
|
|
|
|
|
|
|
|
|
Total current liabilities
|
|
|
180,356
|
|
|
|
160,730
|
|
Long-term debt, less current maturities
|
|
|
|
|
|
|
20,717
|
|
Deferred income taxes
|
|
|
|
|
|
|
(217,673
|
)
|
Asset retirement obligations
|
|
|
|
|
|
|
139,703
|
|
Workers compensation obligations
|
|
|
|
|
|
|
211,500
|
|
Accrued postretirement benefit costs
|
|
|
|
|
|
|
559,673
|
|
Other noncurrent liabilities
|
|
|
33,236
|
|
|
|
63,236
|
|
|
|
|
|
|
|
|
|
|
Total liabilities
|
|
$
|
213,592
|
|
|
$
|
937,886
|
|
|
|
|
|
|
|
|
|
|
Minority interests
|
|
$
|
|
|
|
$
|
16,153
|
|
|
|
|
|
|
|
|
|
|
|
|
(3)
|
Risk
Management and Derivative Financial Instruments
|
The Company is exposed to various types of risk in the normal
course of business, including fluctuations in commodity prices,
interest rates and foreign currency exchange rates. These risks
are actively monitored to ensure compliance with the risk
management policies of the Company. In most cases, commodity
price risk (excluding coal trading activities) related to the
sale of coal is mitigated through the use of long-term,
fixed-price contracts rather than financial instruments, while
commodity price risk related to materials used in production is
managed through the use of fixed price and cost plus contracts
and derivatives. Interest rate and foreign currency exchange
risk are managed through the use of forward contracts, swaps and
options. The Companys usage of interest rate swaps is
discussed in Note 13.
Commodity
Price Risk
In addition to the derivatives related to coal trading
activities, the Company manages its exposure to price volatility
of materials used in production, including diesel fuel and
explosives, through various contractual arrangements. As of
December 31, 2007, the Company had designated derivative
contracts as cash flow
F-15
PEABODY
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
hedges for 114.8 million gallons of anticipated fuel usage
with contract maturities extending through 2010. The
consolidated balance sheet at December 31, 2007 reflects
unrealized gains on these cash flow hedges of
$48.4 million, which is recorded net of a
$19.4 million tax provision in Accumulated other
comprehensive loss (see Note 19).
A measure of ineffectiveness is inherent in hedging future
diesel fuel purchases with derivative positions based on crude
oil or other mid-distillate commodities. The amount of
ineffectiveness in the Companys hedge of physical fuel
purchases with heating oil derivatives has historically been
insignificant and is expected to remain minimal because the
hedged diesel fuel contracts are priced based on the underlying
derivative, heating oil, adjusted for a fixed transportation
differential. Due to the market volatility of crude oil prices
and refining spreads, the measured ineffectiveness in the
Companys hedges of physical diesel fuel purchases with
crude oil derivatives has historically been greater than for
hedging contracts based on heating oil. Due to the implicit
market volatility of crude and heating oil prices and refining
crack spreads, the Company is unable to predict the amount of
ineffectiveness that may occur in future periods, including the
loss of hedge accounting (which could be determined on a
derivative by derivative basis or in the aggregate), which may
result in increased volatility in the Companys future
results.
Due to the inherent ineffectiveness that occurs when the price
of a derivative contract does not perfectly mirror the value of
the hedged instrument or transaction, SFAS No. 133
permits a degree of ineffectiveness within a narrowly defined
corridor, provided that critical terms of the hedge contract and
the hedged activity are sufficiently matched, including maturity
and notional amount, and provided that historical and expected
future prices are sufficiently correlated. During 2007 and 2006,
the Company did not recognize any impact due to ineffectiveness
of hedging contracts that exceeded the defined corridor
stipulated in SFAS No. 133.
The notional amounts outstanding of 114.8 million gallons
of derivative swap contracts for crude oil that were designated
as cash flow hedges of future anticipated diesel fuel purchases
as of December 31, 2007. The crude oil swaps are used to
hedge incremental fuel purchases in the Companys Eastern
mining operations with any excess over Eastern requirements
allocated to Western operations.
In addition to the derivatives related to trading activities and
diesel fuel, the Company enters contracts to manage its exposure
to the price volatility of explosives. As of December 31,
2007, the Company had derivative contracts designated as cash
flow hedges with notional amounts outstanding totaling
5.7 million MMBtu of natural gas, with maturities extending
through August 2010. The consolidated balance sheet as of
December 31, 2007, reflects unrealized losses on these cash
flow hedges of $2.0 million, which is recorded net of a
$0.8 million tax benefit in Accumulated other
comprehensive loss (see Note 19). The Companys
hedge of explosives with natural gas is perfectly effective by
design since the contractual purchase of explosives is fixed to
the previous months closing price for natural gas, which
occurs in a constant ratio of MMBtu per ton in the manufacture
of explosives, plus a fixed surcharge.
Credit
Risk
The Companys concentration of credit risk is substantially
with energy producers and marketers and electric utilities,
although it also has exposure to international steel producers,
brokerage sources and trading counterparties. The Companys
policy is to independently evaluate each customers
creditworthiness prior to entering into transactions and to
constantly monitor the credit extended. In the event that the
Company enters into a transaction with a counterparty that does
not meet its credit standards, the Company may protect its
position by requiring the counterparty to provide appropriate
credit enhancement.
When appropriate, the Company has taken steps to reduce the
Companys credit exposure to customers or counterparties
whose credit has deteriorated and who may pose a higher risk, as
determined by the Companys credit management function, of
failure to perform under their contractual obligations. These
steps include
F-16
PEABODY
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
obtaining letters of credit or cash collateral, requiring
prepayments for shipments or the creation of customer trust
accounts held for the Companys benefit to fund payment for
coal under existing coal supply agreements.
To reduce the Companys credit exposure related to its
trading and brokerage activities, the Company seeks to enter
into netting agreements with counterparties that permit the
Company to offset receivables and payables with such
counterparties. Counterparty risk with respect to interest rate
swap and foreign currency forwards transactions is not
considered to be significant based upon the creditworthiness of
the participating financial institutions.
Foreign
Currency Risk
The Company utilizes currency forwards to hedge currency risk
associated with anticipated Australian dollar expenditures. As
of December 31, 2007, the Company had forward contracts
designated as cash flow hedges with notional amounts outstanding
totaling approximately A$2.03 billion, with maturities
extending through 2010. The consolidated balance sheet as of
December 31, 2007, reflects unrealized gains on the cash
flow hedges of $124.8 million, which is recorded net of a
$49.9 million tax benefit in Accumulated other
comprehensive loss (see Note 19).
Employees
As of December 31, 2007, the Company had approximately
7,000 employees. As of December 31, 2007,
approximately 27% of the Companys hourly employees were
represented by organized labor unions and generated 10% of the
2007 coal production. Relations with its employees and, where
applicable, organized labor are important to the Companys
success.
United
States Labor Relations
The United Mine Workers of America (UMWA) represented
approximately 6% of the Companys
U.S. subsidiaries hourly employees, who generated 4%
of the Companys U.S. production during the year ended
December 31, 2007. An additional 7% of the U.S. hourly
employees are represented by labor unions other than the UMWA.
These employees generated 2% of the Companys
U.S. production during the year ended December 31,
2007. Hourly workers at the Companys mine in Arizona are
represented by the UMWA under the Western Surface Agreement,
which is effective through September 2, 2013. In April
2007, a new labor agreement was ratified for the Companys
hourly workforce at the Willow Lake underground mine, which is
represented by the International Brotherhood of Boilermakers.
The new four-year labor agreement expires on April 15, 2011.
Australia
Labor Relations
The Australian coal mining industry is unionized and all of the
Companys hourly workers and those employed through
contract mining relationships are members of trade unions. The
Construction Forestry Mining and Energy Union represents the
Companys Australian subsidiarys hourly production
employees. As of December 31, 2007, the Companys
Australian hourly employees were approximately 26% of its hourly
workforce and generated 29% of the Companys total
Australian production in the year then ended. The labor
agreements at the Companys Metropolitan Mine were renewed
in July and October 2007 and those agreements expire in 2010.
The Wambo mine coal handling plant labor agreement is under
negotiation and the North Goonyella Mine operates under an
agreement due to expire in March 2008.
F-17
PEABODY
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
(4)
|
Resource
Management and Other Commercial Events
|
During 2007, the Company purchased approximately
345 million tons of coal reserves and surface lands in the
Illinois Basin. In conjunction with the purchase, the Company
also agreed to provide up to $64.8 million of reclamation
and bonding commitments to a third-party coal company. The
Company has recognized the full amount of these commitments as a
liability as of December 31, 2007. The non-cash portion of
this transaction was excluded from the investing section of the
statement of cash flows.
During 2007, the Company sold approximately 172 million
tons of coal reserves and surface lands to the Prairie State
Energy Campus (Prairie State) equity partners. The Company
recognized a gain totaling $26.4 million and received
$114.3 million in cash proceeds associated with this
transaction. See Note 20 for additional information
regarding Prairie State.
In 2007, the Company exchanged oil and gas rights and assets in
more than 860,000 acres in the Illinois Basin, West
Virginia, New Mexico and the Powder River Basin for
approximately 40 million tons of
high-Btu
coal reserves in West Virginia and Kentucky and
$15.0 million in cash proceeds. The Companys
subsidiaries, including one subsidiary now owned by Patriot,
received approximately 40 million tons of coal reserves.
Based on the fair value of the coal reserves received, the
Company recognized a $50.5 million gain on the exchange.
The non-cash portion of this transaction was excluded from the
investing section of the statement of cash flows.
In 2006, the Company exchanged approximately 63 million
tons of coal reserves at its Caballo mining operation for
approximately 46 million tons of coal reserves contiguous
with the Companys North Antelope Rochelle mining
operation. Based on the fair value of the coal reserves
exchanged, the Company recognized a gain totaling
$39.2 million. This non-cash transaction was excluded from
the investing section of the statement of cash flows.
The Company recognized $35.8 million during the year ended
December 31, 2006 in gains related to the settlement of
commitments by a third-party coal producer following a brokerage
contract restructuring. The gains are included in Other
revenues in the consolidated statements of operations.
In the fourth quarter of 2005, the Company acquired rail,
loadout and surface facilities as well as other mining assets
from another major coal producer for $84.7 million and
exchanged 60 million ton blocks of leased coal reserves in
the Powder River Basin. The Company plans to utilize these
reserves and infrastructure to accelerate the development of a
new mine, which will include adjoining Company-leased reserves.
In the first quarter of 2005, the Company purchased mining
assets from Lexington Coal Company for $61.0 million, of
which $56.5 million was recorded in Property, plant,
equipment and mine development and the remainder recorded
primarily to Inventories in the consolidated balance
sheet. The Company used the acquired assets to open a new mine
that produced 2.4 million tons of coal during 2006 and to
provide other synergies to existing properties.
In the third quarter of 2005, the Company exchanged certain idle
steam coal reserves for steam and metallurgical coal reserves as
part of a contractual dispute settlement. Under the settlement,
the Company received $10.0 million in cash, a new coal
supply agreement that partially replaced the disputed coal
supply agreement, and exchanged the idle steam coal reserves. As
a result of the final settlement and based on the fair values of
the items exchanged in the overall settlement transaction, the
Company recorded net contract losses of $4.0 million and a
gain on assets exchanged of $37.4 million. The fair value
of assets exchanged exceeded the book value by
$33.4 million and this non-cash addition is not included in
Additions to property, plant, equipment and mine
development in the consolidated statements of cash flows.
The gain from this transaction is included in Net gain on
disposal or exchange of assets in the consolidated
statements of operations.
F-18
PEABODY
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
(5)
|
Business
Combinations
|
Excel
Coal Limited
In October 2006, the Company acquired Excel Coal Limited
(Excel), an independent coal company, by means of a scheme of
arrangement transaction under Australian law (the Transaction).
The total acquisition price was $1.54 billion in cash plus
assumed debt of $293.0 million, less $30.0 million of
cash acquired in the transaction, and was financed with
borrowings under the Companys Senior Unsecured Credit
Facility and Senior Notes due 2016 and 2026 as discussed in
Note 13. The Excel acquisition expands the Companys
presence in Australia and included three operating mines and
three development-stage mines (all of which are operating as of
December 31, 2007), with up to 500 million tons of
proven and probable coal reserves and approximately
100 million tons of coal resources. The results of
operations of Excel are included in the Companys
Australian Mining Operations segment from October 2006. The
acquisition was accounted for as a purchase in accordance with
SFAS No. 141, Business Combinations.
The purchase accounting allocations related to the acquisition
have been completed and recorded in the accompanying
consolidated financial statements as of, and for periods
subsequent to, October 2006. Pursuant to a final valuation, the
adjustments to the Companys preliminary allocation were
recorded in 2007 and resulted in an increase in the value
assigned to property, plant and equipment and related deferred
income taxes, thus eliminating the preliminary goodwill
allocation. The following table summarizes the fair values of
the assets acquired and the liabilities assumed at the date of
acquisition:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Preliminary
|
|
|
|
|
|
Final
|
|
|
|
Allocation
|
|
|
Adjustments
|
|
|
Allocation
|
|
|
|
(Dollars in thousands)
|
|
|
Accounts receivable, net
|
|
$
|
18,700
|
|
|
$
|
2,543
|
|
|
$
|
21,243
|
|
Inventories
|
|
|
32,044
|
|
|
|
(1,325
|
)
|
|
|
30,719
|
|
Other current assets
|
|
|
5,336
|
|
|
|
2,513
|
|
|
|
7,849
|
|
Property, plant, equipment and mine development, net
|
|
|
1,897,672
|
|
|
|
363,307
|
|
|
|
2,260,979
|
|
Goodwill
|
|
|
240,667
|
|
|
|
(240,667
|
)
|
|
|
|
|
Accounts payable and accrued expenses
|
|
|
(135,474
|
)
|
|
|
(14,929
|
)
|
|
|
(150,403
|
)
|
Debt
|
|
|
(293,024
|
)
|
|
|
9,508
|
|
|
|
(283,516
|
)
|
Deferred income taxes, net
|
|
|
(179,026
|
)
|
|
|
(114,083
|
)
|
|
|
(293,109
|
)
|
Other noncurrent assets and liabilities, net
|
|
|
(60,857
|
)
|
|
|
(13,852
|
)
|
|
|
(74,709
|
)
|
Minority interests
|
|
|
(18,263
|
)
|
|
|
6,985
|
|
|
|
(11,278
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total purchase price, net of cash received of $29,995
|
|
$
|
1,507,775
|
|
|
$
|
|
|
|
$
|
1,507,775
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
In connection with the acquisition, the Company acquired
contract based intangibles consisting solely of coal supply
agreement obligations (customer contracts) and recorded a net
intangible liability of $32.8 million. The net intangible
liability is being amortized based on market differential and
tonnage delivered over the terms of the applicable agreements,
which range from 1 to 20 years. As of December 31,
2007, the carrying value of the net intangible liability was
$28.9 million and the amortization (reduction to
Depreciation, depletion and amortization in the
consolidated statement of operations) recorded through
December 31, 2007 was $3.9 million.
F-19
PEABODY
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Estimated amortization (reduction to Depreciation,
depletion and amortization in the consolidated statement
of operations) as of December 31, 2007 is as follows:
|
|
|
|
|
|
|
Year Ended
|
|
|
|
December 31,
|
|
|
|
(Dollars in thousands)
|
|
|
2008
|
|
$
|
9,414
|
|
2009
|
|
|
5,015
|
|
2010
|
|
|
4,245
|
|
2011
|
|
|
7,648
|
|
2012
|
|
|
182
|
|
Thereafter
|
|
|
2,351
|
|
|
|
|
|
|
Total
|
|
$
|
28,855
|
|
|
|
|
|
|
The following unaudited pro forma financial information presents
the combined results of operations of the Company and Excel, on
a pro forma basis, as though the companies had been combined as
of the beginning of each period presented. The pro forma
financial information does not necessarily reflect the results
of operations that would have occurred had the Company and Excel
constituted a single entity during those periods.
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2006
|
|
|
2005
|
|
|
|
(Dollars in thousands,
|
|
|
|
except per share data)
|
|
|
Revenues:
|
|
|
|
|
|
|
|
|
As reported
|
|
$
|
4,108,396
|
|
|
$
|
3,666,176
|
|
Pro forma
|
|
|
4,403,428
|
|
|
|
3,994,514
|
|
Net income:
|
|
|
|
|
|
|
|
|
As reported
|
|
$
|
600,697
|
|
|
$
|
422,653
|
|
Pro forma
|
|
|
569,956
|
|
|
|
364,258
|
|
Basic earnings per share net income:
|
|
|
|
|
|
|
|
|
As reported
|
|
$
|
2.28
|
|
|
$
|
1.61
|
|
Pro forma
|
|
|
2.16
|
|
|
|
1.39
|
|
Diluted earnings per share net income:
|
|
|
|
|
|
|
|
|
As reported
|
|
$
|
2.23
|
|
|
$
|
1.58
|
|
Pro forma
|
|
|
2.12
|
|
|
|
1.36
|
|
|
|
(6)
|
Assets
and Liabilities from Coal Trading Activities
|
The fair value of assets and liabilities from coal trading
activities is set forth below:
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
|
(Dollars in thousands)
|
|
|
Assets from coal trading activities
|
|
$
|
966,548
|
|
|
$
|
150,373
|
|
Liabilities from coal trading activities
|
|
|
918,596
|
|
|
|
126,731
|
|
|
|
|
|
|
|
|
|
|
Net assets from coal trading activities
|
|
$
|
47,952
|
|
|
$
|
23,642
|
|
|
|
|
|
|
|
|
|
|
F-20
PEABODY
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The recent increase in coal price volatility and trading
volumes, particularly in the Companys international
markets, has significantly increased the relative value of the
Companys trading asset and liability portfolio. Trading
assets and liabilities are primarily forward contracts with
financial swaps representing most of the remaining balance. The
net value of trading assets and liabilities represents the
future realizable value of the trading portfolio.
Of the coal trading derivatives and related hedge contracts in
the Companys trading portfolio as of December 31,
2007, 97% were valued utilizing prices from over-the-counter
market sources, adjusted for coal quality and traded
transportation differentials and 3% of the Companys
contracts were valued based on similar market transactions.
As of December 31, 2007, the estimated future realization
of the value of the Companys trading portfolio was as
follows:
|
|
|
|
|
|
|
Percentage
|
|
Year of Expiration
|
|
of Portfolio
|
|
|
2008
|
|
|
58
|
%
|
2009
|
|
|
41
|
%
|
2010
|
|
|
0
|
%
|
2011
|
|
|
1
|
%
|
|
|
|
|
|
|
|
|
100
|
%
|
|
|
|
|
|
At December 31, 2007, 27% of the Companys credit
exposure related to coal trading activities with investment
grade counterparties and 73% with non-investment grade
counterparties. The Companys coal trading operations
traded 166.5 million tons, 79.1 million tons and
36.2 million tons for the years ended December 31,
2007, 2006 and 2005, respectively.
|
|
(7)
|
Accounts
Receivable Securitization
|
The Company has established an accounts receivable
securitization program through its wholly-owned,
bankruptcy-remote subsidiary (Seller). Under the program, the
Company contributes undivided interests in a pool of eligible
trade receivables to the Seller, which then sells, without
recourse, to a multi-seller, asset-backed commercial paper
conduit (Conduit). Purchases by the Conduit are financed with
the sale of highly rated commercial paper. The Company utilizes
proceeds from the sale of its accounts receivable as an
alternative to other forms of debt, effectively reducing its
overall borrowing costs. The funding cost of the securitization
program was $11.2 million, $1.9 million and
$2.5 million for the years ended December 31, 2007,
2006 and 2005, respectively. The securitization program is
scheduled to expire in September 2009.
The securitization transactions have been recorded as sales,
with those accounts receivable sold to the Conduit removed from
the consolidated balance sheets. The amount of undivided
interests in accounts receivable sold to the Conduit was
$275.0 million and $219.2 million as of
December 31, 2007 and 2006, respectively.
The Seller is a separate legal entity whose assets are available
first and foremost to satisfy the claims of its creditors.
Eligible receivables, as defined in the securitization
agreement, consist of trade receivables from most of the
Companys U.S. subsidiaries, and are reduced for
certain items such as past due balances and concentration
limits. Of the eligible pool of receivables contributed to the
Seller, undivided interests in only a portion of the pool are
sold to the Conduit. The Company (the Seller) continues to own
$186.5 million of receivables as of December 31, 2007,
that represents collateral supporting the securitization
program. The Sellers interest in these receivables is
subordinate to the Conduits interest in the event of
default under the securitization agreement. If the Company
defaulted under the securitization agreement or if its pool of
eligible
F-21
PEABODY
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
trade receivables decreased significantly, the Company could be
prohibited from selling any additional receivables in the future
under the agreement.
A reconciliation of weighted-average shares outstanding follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
Weighted-average shares outstanding basic
|
|
|
264,068,180
|
|
|
|
263,419,344
|
|
|
|
261,519,424
|
|
Dilutive impact of stock options, restricted stock units and
performance units
|
|
|
5,098,110
|
|
|
|
5,746,661
|
|
|
|
6,494,052
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted-average shares outstanding diluted
|
|
|
269,166,290
|
|
|
|
269,166,005
|
|
|
|
268,013,476
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Inventories consisted of the following:
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
|
(Dollars in thousands)
|
|
|
Materials and supplies
|
|
$
|
90,242
|
|
|
$
|
71,899
|
|
Raw coal
|
|
|
55,524
|
|
|
|
37,996
|
|
Saleable coal
|
|
|
123,096
|
|
|
|
93,014
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
268,862
|
|
|
$
|
202,909
|
|
|
|
|
|
|
|
|
|
|
The Company leases equipment and facilities under various
noncancelable lease agreements. Certain lease agreements require
the maintenance of specified ratios and contain restrictive
covenants which limit indebtedness, subsidiary dividends,
investments, asset sales and other Company actions. Rental
expense under operating leases was $104.7 million,
$78.5 million and $78.6 million for the years ended
December 31, 2007, 2006 and 2005, respectively. The gross
value of property, plant, equipment and mine development assets
under capital leases was $116.9 million and
$72.3 million as of December 31, 2007 and 2006,
respectively, related primarily to the leasing of mining
equipment. The gross accumulated amortization for these items
was $24.7 million and $15.6 million at
December 31, 2007 and 2006, respectively.
The Company also leases coal reserves under agreements that
require royalties to be paid as the coal is mined. Certain
agreements also require minimum annual royalties to be paid
regardless of the amount of coal mined during the year. Total
royalty expense was $343.1 million, $285.7 million and
$255.2 million for the years ended December 31, 2007,
2006 and 2005, respectively.
A substantial amount of the coal mined by the Company is
produced from mineral reserves leased from the owner. One of the
major lessors is the U.S. government, from which the
Company leases substantially all of the coal it mines in Wyoming
and Colorado under terms set by Congress and administered by the
U.S. Bureau of Land Management. These leases are generally
for an initial term of ten years but may be extended by diligent
development and mining of the reserve until all economically
recoverable reserves are depleted. The Company has met the
diligent development requirements for substantially all of these
federal leases either directly through production or by
including the lease as a part of a logical mining unit with
other leases upon which development has occurred. Annual
production on these federal leases must total at least 1.0% of
the original amount of coal in the entire logical mining unit.
In addition, royalties are payable
F-22
PEABODY
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
monthly at a rate of 12.5% of the gross realization from the
sale of the coal mined using surface mining methods and at a
rate of 8.0% of the gross realization for coal produced using
underground mining methods. The Company also leases coal
reserves in Arizona from The Navajo Nation and the Hopi Tribe
under leases that are administered by the U.S. Department
of the Interior. These leases expire upon exhaustion of the
leased reserves or upon the permanent ceasing of all mining
activities on the related reserves as a whole. The royalty rates
are also generally based upon a percentage of the gross
realization from the sale of coal. These rates are subject to
redetermination every ten years under the terms of the leases.
The remainder of the leased coal is generally leased from state
governments, land holding companies and various individuals. The
duration of these leases varies greatly. Typically, the lease
terms are automatically extended as long as active mining
continues. Royalty payments are generally based upon a specified
rate per ton or a percentage of the gross realization from the
sale of the coal.
Future minimum lease and royalty payments as of
December 31, 2007, are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital
|
|
|
Operating
|
|
|
Coal
|
|
Year Ended December 31,
|
|
Leases
|
|
|
Leases
|
|
|
Reserves
|
|
|
|
(Dollars in thousands)
|
|
|
2008
|
|
$
|
17,349
|
|
|
$
|
85,356
|
|
|
$
|
187,946
|
|
2009
|
|
|
19,141
|
|
|
|
66,037
|
|
|
|
132,060
|
|
2010
|
|
|
15,117
|
|
|
|
54,181
|
|
|
|
7,504
|
|
2011
|
|
|
15,117
|
|
|
|
44,661
|
|
|
|
6,638
|
|
2012
|
|
|
15,117
|
|
|
|
27,098
|
|
|
|
6,139
|
|
2013 and thereafter
|
|
|
35,020
|
|
|
|
81,712
|
|
|
|
43,129
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total minimum lease payments
|
|
$
|
116,861
|
|
|
$
|
359,045
|
|
|
$
|
383,416
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Less interest
|
|
|
24,675
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Present value of minimum capital lease payments
|
|
$
|
92,186
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31, 2007, certain of the Companys
lease obligations were secured by outstanding surety bonds and
letters of credit totaling $89.9 million.
F-23
PEABODY
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
(11)
|
Accounts
Payable and Accrued Expenses
|
Accounts payable and accrued expenses consisted of the following:
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
|
(Dollars in thousands)
|
|
|
Trade accounts payable
|
|
$
|
398,186
|
|
|
$
|
369,891
|
|
Accrued taxes other than income
|
|
|
152,195
|
|
|
|
113,416
|
|
Accrued payroll and related benefits
|
|
|
76,066
|
|
|
|
109,006
|
|
Accrued health care
|
|
|
83,501
|
|
|
|
70,705
|
|
Workers compensation obligations
|
|
|
6,220
|
|
|
|
6,510
|
|
Other accrued benefits
|
|
|
3,103
|
|
|
|
3,148
|
|
Accrued royalties
|
|
|
35,367
|
|
|
|
48,879
|
|
Accrued environmental
|
|
|
7,093
|
|
|
|
14,390
|
|
Income taxes payable Australia
|
|
|
27,623
|
|
|
|
94,692
|
|
Accrued interest
|
|
|
30,869
|
|
|
|
38,189
|
|
Other accrued expenses
|
|
|
133,438
|
|
|
|
75,325
|
|
|
|
|
|
|
|
|
|
|
Total accounts payable and accrued expenses
|
|
$
|
953,661
|
|
|
$
|
944,151
|
|
|
|
|
|
|
|
|
|
|
Income from continuing operations before income tax provision
(benefit) and minority interests consisted of the following:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
(Dollars in thousands)
|
|
|
U.S
|
|
$
|
283,501
|
|
|
$
|
224,218
|
|
|
$
|
171,998
|
|
Non U.S.
|
|
|
57,334
|
|
|
|
238,883
|
|
|
|
172,756
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
340,835
|
|
|
$
|
463,101
|
|
|
$
|
344,754
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
F-24
PEABODY
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Total income tax provision (benefit) consisted of the following:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
(Dollars in thousands)
|
|
|
Current:
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. federal
|
|
$
|
|
|
|
$
|
4,319
|
|
|
$
|
|
|
Non U.S.
|
|
|
26,410
|
|
|
|
67,565
|
|
|
|
25,622
|
|
State
|
|
|
179
|
|
|
|
405
|
|
|
|
300
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current
|
|
|
26,589
|
|
|
|
72,289
|
|
|
|
25,922
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred:
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. federal
|
|
|
(141,086
|
)
|
|
|
(164,768
|
)
|
|
|
36,491
|
|
Non U.S.
|
|
|
44,142
|
|
|
|
4,094
|
|
|
|
22,997
|
|
State
|
|
|
(7,757
|
)
|
|
|
(1,699
|
)
|
|
|
(21,631
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total deferred
|
|
|
(104,701
|
)
|
|
|
(162,373
|
)
|
|
|
37,857
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total provision (benefit)
|
|
$
|
(78,112
|
)
|
|
$
|
(90,084
|
)
|
|
$
|
63,779
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The income tax rate differed from the U.S. federal
statutory rate as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
(Dollars in thousands)
|
|
|
Federal statutory rate
|
|
$
|
119,292
|
|
|
$
|
162,086
|
|
|
$
|
120,664
|
|
Depletion
|
|
|
(55,279
|
)
|
|
|
(52,317
|
)
|
|
|
(44,228
|
)
|
Foreign earnings rate differential
|
|
|
(13,613
|
)
|
|
|
(16,649
|
)
|
|
|
(12,279
|
)
|
Remeasurement of foreign deferred taxes
|
|
|
56,029
|
|
|
|
|
|
|
|
|
|
State income taxes, net of U.S. federal tax benefit
|
|
|
329
|
|
|
|
5,089
|
|
|
|
(21,436
|
)
|
Deemed liquidation of subsidiary
|
|
|
|
|
|
|
|
|
|
|
(245,674
|
)
|
Tax credits
|
|
|
(24,296
|
)
|
|
|
|
|
|
|
|
|
Changes in valuation allowance
|
|
|
(175,735
|
)
|
|
|
(165,481
|
)
|
|
|
216,908
|
|
Changes in tax reserves
|
|
|
3,256
|
|
|
|
(28,658
|
)
|
|
|
44,968
|
|
Other, net
|
|
|
11,905
|
|
|
|
5,846
|
|
|
|
4,856
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total provision (benefit)
|
|
$
|
(78,112
|
)
|
|
$
|
(90,084
|
)
|
|
$
|
63,779
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
F-25
PEABODY
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The tax effects of temporary differences that give rise to
significant portions of the deferred tax assets and liabilities
consisted of the following:
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
|
(Dollars in thousands)
|
|
|
Deferred tax assets:
|
|
|
|
|
|
|
|
|
Tax credits and loss carryforwards
|
|
$
|
660,325
|
|
|
$
|
607,717
|
|
Postretirement benefit obligations
|
|
|
324,660
|
|
|
|
323,058
|
|
Intangible tax asset and purchased contract rights
|
|
|
73,715
|
|
|
|
90,462
|
|
Accrual at spin-off for loss on firm purchase commitment
|
|
|
52,934
|
|
|
|
|
|
Accrued reclamation and mine closing liabilities
|
|
|
15,981
|
|
|
|
5,243
|
|
Accrued long-term workers compensation liabilities
|
|
|
15,581
|
|
|
|
13,818
|
|
Others
|
|
|
85,462
|
|
|
|
83,604
|
|
|
|
|
|
|
|
|
|
|
Total gross deferred tax assets
|
|
|
1,228,658
|
|
|
|
1,123,902
|
|
|
|
|
|
|
|
|
|
|
Deferred tax liabilities:
|
|
|
|
|
|
|
|
|
Property, plant, equipment and mine development, leased coal
interests and advance royalties, principally due to differences
in depreciation, depletion and asset writedowns
|
|
|
1,355,162
|
|
|
|
1,217,217
|
|
Others
|
|
|
19,054
|
|
|
|
20,256
|
|
|
|
|
|
|
|
|
|
|
Total gross deferred tax liabilities
|
|
|
1,374,216
|
|
|
|
1,237,473
|
|
|
|
|
|
|
|
|
|
|
Valuation allowance
|
|
|
(71,413
|
)
|
|
|
(221,753
|
)
|
|
|
|
|
|
|
|
|
|
Net deferred tax liability
|
|
$
|
(216,971
|
)
|
|
$
|
(335,324
|
)
|
|
|
|
|
|
|
|
|
|
Deferred taxes consisted of the following:
|
|
|
|
|
|
|
|
|
Current deferred income taxes
|
|
$
|
98,633
|
|
|
$
|
77,562
|
|
Noncurrent deferred income taxes
|
|
|
(315,604
|
)
|
|
|
(412,886
|
)
|
|
|
|
|
|
|
|
|
|
Net deferred tax liability
|
|
$
|
(216,971
|
)
|
|
$
|
(335,324
|
)
|
|
|
|
|
|
|
|
|
|
The Companys tax credits and loss carryforwards included
alternative minimum tax (AMT) and general business credits of
$50.0 million and $32.2 million, U.S. net
operating loss (NOL) carryforwards of $574.9 million and
$535.9 million and foreign loss carryforwards of
$35.4 million and $39.6 million as of
December 31, 2007 and 2006, respectively. The AMT credits
and foreign NOL and capital loss carryforwards have no
expiration date and the U.S. NOL carryforwards begin to
expire in the year 2020. The Company evaluated and assessed the
expected near-term utilization of NOLs, future book and taxable
income, available tax strategies and the overall deferred tax
position to determine the appropriate amount and timing of
valuation allowance adjustments. This assessment resulted in a
significant reduction of valuation allowance during 2007 and
2006. During 2005, the Company completed a comprehensive and
strategic internal corporate restructuring project resulting in
a deduction for a deemed liquidation of a subsidiary for tax
purposes which significantly increased the Companys
NOLs. The valuation allowance was increased during 2005 to
correspond with the increase in available NOLs. The
remaining valuation allowance at December 31, 2007 of
$71.4 million represents a reserve for AMT credits, certain
foreign deferred tax assets and state and foreign loss
carryforwards, due to uncertainty of their ultimate realization.
The Company adopted the provisions of FIN No. 48 on
January 1, 2007. As a result of the implementation of
FIN No. 48, the Company decreased its balance of
unrecognized tax benefits by $24.6 million, none
F-26
PEABODY
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
of which was accounted for as a reduction to the Companys
retained earnings balance due to a valuation allowance recorded
against the Companys deferred tax asset for NOL
carryforwards.
The total amount of the net unrecognized tax benefits at
January 1, 2007 and December 31, 2007 was
$135.0 million ($144.0 million gross) and
$143.0 million ($152.6 million gross), respectively.
The amount of the Companys gross unrecognized tax benefits
has increased by $8.6 million since January 1, 2007. A
reconciliation of the beginning and ending amount of gross
unrecognized tax benefits is as follows (dollars in thousands):
|
|
|
|
|
Balance at January 1, 2007
|
|
$
|
144,000
|
|
Additions based on tax positions related to current year
|
|
|
4,000
|
|
Additions for tax positions of prior years
|
|
|
4,600
|
|
|
|
|
|
|
Balance at December 31, 2007
|
|
$
|
152,600
|
|
|
|
|
|
|
The amount of the net unrecognized tax benefits that, if
recognized, would directly affect the effective tax rate is
$143.0 million. However, $27.0 million would generate
a deferred tax asset for state NOL carryforwards that would more
likely than not be offset by a valuation allowance. The Company
does not expect any significant increases or decreases to its
unrecognized tax benefits within twelve months of this reporting
date.
The Company recognizes interest and penalties accrued related to
unrecognized tax benefits in its income tax provision. The
Company has recognized $2.3 million of interest for the
year ended December 31, 2007. Due to NOL carryforwards, the
Company had not accrued interest for any of its unrecognized tax
benefits in prior years. The Company has considered the
application of penalties on its unrecognized tax benefits and
determined, based upon several factors, including the existence
of NOL carryforwards, that no accrual of penalties is required.
The Companys Federal income tax returns for the tax years
1999 through 2001 and 2003 through 2007 remain subject to
examination by the Internal Revenue Service. The Companys
state income tax returns for the tax years 1991 and beyond
remain subject to examination by various state taxing
authorities. The Companys foreign income tax returns for
the tax years 2003 and beyond remain subject to examination by
various foreign taxing authorities.
The total amount of undistributed earnings of foreign
subsidiaries for income tax purposes was approximately
$303.6 million and $318.9 million at December 31,
2007 and 2006, respectively. The Company has not provided
deferred taxes on $264.5 million and $314.0 million of
foreign earnings for 2007 and 2006, respectively, because such
earnings were intended to be indefinitely reinvested outside the
United States. Should the Company repatriate all of these
earnings, a one-time income tax charge to the Companys
consolidated results of operations of up to $92.6 million
could occur.
The Company made U.S. Federal tax payments totaling
$3.0 million and $3.9 million for the years ended
December 31, 2007 and 2006, respectively. The Company made
no U.S. Federal tax payments for the year ended
December 31, 2005. The Company paid state and local income
taxes totaling $1.2 million, $0.5 million and
$0.3 million for the years ended December 31, 2007,
2006 and 2005, respectively. The Company made
non-U.S. tax
payments totaling $80.0 million, $23.1 million and
$2.8 million for the years ended December 31, 2007,
2006 and 2005, respectively.
F-27
PEABODY
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The Companys total indebtedness as of December 31,
2007 and 2006, consisted of the following:
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
|
(Dollars in thousands)
|
|
|
Term Loan under Senior Unsecured Credit Facility
|
|
$
|
509,084
|
|
|
$
|
547,000
|
|
Revolving Credit Facility
|
|
|
97,700
|
|
|
|
|
|
Convertible Junior Subordinated Debentures due 2066
|
|
|
732,500
|
|
|
|
732,500
|
|
7.375% Senior Notes due 2016
|
|
|
650,000
|
|
|
|
650,000
|
|
6.875% Senior Notes due 2013
|
|
|
650,000
|
|
|
|
650,000
|
|
7.875% Senior Notes due 2026
|
|
|
246,965
|
|
|
|
246,897
|
|
5.875% Senior Notes due 2016
|
|
|
218,090
|
|
|
|
231,845
|
|
5.0% Subordinated Note
|
|
|
|
|
|
|
59,504
|
|
6.84% Series C Bonds due 2016
|
|
|
43,000
|
|
|
|
43,000
|
|
6.34% Series B Bonds due 2014
|
|
|
21,000
|
|
|
|
21,000
|
|
6.84% Series A Bonds due 2014
|
|
|
10,000
|
|
|
|
10,000
|
|
Capital lease obligations
|
|
|
92,186
|
|
|
|
96,869
|
|
Fair value of interest rate swaps
|
|
|
1,604
|
|
|
|
(13,784
|
)
|
Other
|
|
|
971
|
|
|
|
2,201
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
3,273,100
|
|
|
$
|
3,277,032
|
|
|
|
|
|
|
|
|
|
|
Senior
Unsecured Credit Facility
On September 15, 2006, the Company entered into a Third
Amended and Restated Credit Agreement (the Agreement), which
established a $2.75 billion Senior Unsecured Credit
Facility (the Senior Unsecured Credit Facility) and which
amended and restated in full the Companys then existing
$1.35 billion Senior Secured Credit Facility (the Senior
Secured Credit Facility). The Senior Unsecured Credit Facility
provides a $1.8 billion Revolving Credit Facility (the
Revolver) and a $950.0 million Term Loan Facility (the Term
Loan Facility).
The Revolver is intended to accommodate working capital needs,
letters of credit, the funding of capital expenditures and other
general corporate purposes. The Revolver also includes a
$50.0 million sub-facility available for
same-day
swingline loan borrowings. As of December 31, 2007, the
Company had $97.7 million borrowings and
$413.5 million letters of credit outstanding under the
Revolver, with a remaining available borrowing capacity of
$1.29 billion.
The Term Loan Facility, which was fully drawn in October 2006 in
connection with the Excel acquisition was paid down
($403.0 million) from a portion of the net proceeds from
the Debentures. In conjunction with the establishment of the
Senior Unsecured Credit Facility, the Company incurred
$8.6 million in financing costs, of which $5.6 million
related to the Revolver and $3.0 million related to the
Term Loan. These debt issuance costs are being amortized to
interest expense over five years, the term of the Senior
Unsecured Credit Facility.
Loans under the facility are available to the Company in
U.S. dollars, with a sub-facility under the Revolver
available in Australian dollars, pounds sterling and Euros.
Letters of credit under the Revolver are available to the
Company in U.S. dollars with a sub-facility available in
Australian dollars, pounds sterling and Euros. The interest rate
payable on the Revolver and the Term Loan is based on a pricing
grid tied to the
F-28
PEABODY
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Companys leverage ratio, as defined in the Agreement. The
interest rate payable on the Revolver and the Term Loan is
currently LIBOR plus 0.75%, which was 5.4% at December 31,
2007.
Under the Senior Unsecured Credit Facility, the Company must
comply with certain financial covenants on a quarterly basis
including a minimum interest coverage ratio and a maximum
leverage ratio, as defined in the Agreement. The financial
covenants also place limitations on the Companys
investments in joint ventures, unrestricted subsidiaries,
indebtedness of non-loan parties and the imposition of liens on
Company assets. The new facility is less restrictive with
respect to limitations on the Companys dividend payments,
capital expenditures, asset sales and stock repurchases. The
Senior Unsecured Credit Facility matures on September 15,
2011.
Convertible
Junior Subordinated Debentures
On December 20, 2006, the Company issued
$732.5 million aggregate principal amount of
4.75% Convertible Junior Subordinated Debentures due 2066
(the Debentures), including $57.5 million issued pursuant
to the underwriters exercise of their over-allotment
option. Net proceeds from the offering, after deducting
underwriting discounts and offering expenses, were
$715.0 million and were used to repay indebtedness under
the Companys Senior Unsecured Credit Facility.
The Debentures will pay interest semiannually at a rate of 4.75%
per year. The Company may elect to, and if and to the extent
that a mandatory trigger event (as defined in the indenture
governing the Debentures) has occurred and is continuing will be
required to, defer interest payments on the Debentures. After
five years of deferral at the Companys option, or upon the
occurrence of a mandatory trigger event, the Company generally
must sell warrants or preferred stock with specified
characteristics and use the funds from that sale to pay deferred
interest, subject to certain limitations. In no event may the
Company defer payments of interest on the Debentures for more
than 10 years.
The Debentures are convertible at any time on or prior to
December 15, 2036 if any of the following conditions occur:
(i) the Companys closing common stock price exceeds
140% of the then applicable conversion price for the Debentures
(currently $81.83 per share) for at least 20 of the final 30
trading days in any quarter; (ii) a notice of redemption is
issued with respect to the Debentures; (iii) a change of
control, as defined in the indenture governing the Debentures;
(iv) satisfaction of certain trading price conditions; and
(v) other specified corporate transactions described in the
indenture governing the Debentures. In addition, the Debentures
are convertible at any time after December 15, 2036 to
December 15, 2041, the scheduled maturity date. In the case
of conversion following a notice of redemption or upon a
non-stock change of control, as defined in the indenture
governing the Debentures, holders may convert their Debentures
into cash in the amount of the principal amount of their
Debentures and shares of the Companys common stock for any
conversion value in excess of the principal amount. In all other
conversion circumstances, holders will receive perpetual
preferred stock (see Note 17) with a liquidation
preference equal to the principal amount of their Debentures,
and any conversion value in excess of the principal amount will
be settled with the Companys common stock. As a result of
the Patriot Coal Corporation spin-off, the conversion rate was
adjusted to 17.1078 shares of common stock per $1,000
principal amount of Debentures effective November 23, 2007.
This adjusted conversion rate represents a conversion price of
approximately $58.45.
The Debentures are not subject to redemption prior to
December 20, 2011. Between December 20, 2011 and
December 19, 2036 the Company may redeem the Debentures, in
whole or in part, if for at least 20 out of the 30 consecutive
trading days immediately prior to the date on which notice of
redemption is given, the Companys closing common stock
price has exceeded 130% of the then applicable conversion price
for the Debentures. On or after December 20, 2036, whether
or not the redemption condition is satisfied, the Company may
redeem the Debentures, in whole or in part. The Company may not
redeem any Debentures unless (i) all accrued and unpaid
interest on the Debentures has been paid in full on or prior to
the redemption date and (ii) if any perpetual preferred
stock is outstanding, the Company has first given notice to
redeem the
F-29
PEABODY
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
perpetual preferred stock in the same proportion as the
redemption of the Debentures. Any redemption of the Debentures
will be at a cash redemption price of 100% of the principal
amount of the Debentures to be redeemed, plus accrued and unpaid
interest to the date of redemption.
On December 15, 2041, the scheduled maturity date, the
Company will use commercially reasonable efforts, subject to the
occurrence of a market disruption event, as defined in the
indenture governing the Debentures, to issue securities of
equivalent equity content in an amount sufficient to pay the
principal amount of the Debentures, together with accrued and
unpaid interest. The final maturity date of the Debentures is
December 15, 2066, on which date the entire principal
amount of the Debentures will mature and become due and payable,
together with accrued and unpaid interest.
In connection with the issuance of the Debentures, the Company
entered into a Capital Replacement Covenant (the CRC). Pursuant
to the CRC, the Company covenanted for the benefit of holders of
covered debt, as defined in the CRC (currently the
Companys 7.875% Senior Notes due 2026, issued in the
aggregate principal amount of $250.0 million), that neither
the Company nor any of its subsidiaries shall repay, redeem or
repurchase all or any part of the Debentures on or after
December 15, 2041 and prior to December 15, 2046,
except to the extent that the total repayment, redemption or
repurchase price does not exceed the sum of: (i) 400% of
the Companys net cash proceeds from the sale of its common
stock and rights to acquire its common stock (including common
stock issued pursuant to the Companys dividend
reinvestment plan or employee benefit plans); (ii) the
Companys net cash proceeds from the sale of its
mandatorily convertible preferred stock, as defined in the CRC,
or debt exchangeable for equity, as defined in the CRC; and
(iii) the Companys net cash proceeds from the sale of
other replacement capital securities, as defined in the CRC, in
each case, during the six months prior to the notice date for
the relevant payment, redemption or repurchase.
The Debentures are unsecured obligations of the Company, ranking
junior to all existing and future senior and subordinated debt
(excluding trade accounts payable or accrued liabilities arising
in the ordinary course of business) except for any future debt
that ranks equal to or junior to the Debentures. The Debentures
will rank equal in right of payment with the Companys
obligations to trade creditors. Substantially, all of the
Companys existing indebtedness is senior to the
Debentures. In addition, the Debentures will be effectively
subordinated to all indebtedness of the Companys
subsidiaries. The indenture governing the Debentures places no
limitation on the amount of additional indebtedness that the
Company or any of the Companys subsidiaries may incur.
7.375% Senior
Notes Due November 2016 and 7.875% Senior Notes Due
November 2026
On October 12, 2006, the Company completed a
$650.0 million offering of 7.375%
10-year
Senior Notes due 2016 and $250.0 million of 7.875%
20-year
Senior Notes due 2026. The notes are general unsecured
obligations of the Company and rank senior in right of payment
to any subordinated indebtedness of the Company; equally in
right of payment with any senior indebtedness of the Company;
effectively junior in right of payment to the Companys
existing and future secured indebtedness, to the extent of the
value of the collateral securing that indebtedness; and
effectively junior to all the indebtedness and other liabilities
of the Companys subsidiaries that do not guarantee the
notes. Interest payments are scheduled to occur on May 1 and
November 1 of each year. The first interest payment occurred on
May 1, 2007.
The notes are guaranteed by the Companys Subsidiary
Guarantors, as defined in the note indenture. The note indenture
contains covenants that, among other things, limit the
Companys ability to create liens and enter into sale and
lease-back transactions. The notes are redeemable at a
redemption price equal to 100% of the principal amount of the
notes being redeemed plus a make-whole premium, if applicable,
and any accrued unpaid interest to the redemption date. Net
proceeds from the offering, after deducting underwriting
discounts and expenses, were $886.1 million.
F-30
PEABODY
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
6.875% Senior
Notes Due March 2013
On March 21, 2003, the Company issued $650.0 million
of 6.875% Senior Notes due March 2013. The notes are senior
unsecured obligations of the Company and rank equally with all
of the Companys other senior unsecured indebtedness.
Interest payments are scheduled to occur on March 15 and
September 15 of each year. The notes are guaranteed by the
Companys Subsidiary Guarantors as defined in the note
indenture. The note indenture contains covenants which, among
other things, limit the Companys ability to incur
additional indebtedness and issue preferred stock, pay dividends
or make other distributions, make other restricted payments and
investments, create liens, sell assets and merge or consolidate
with other entities. The notes are redeemable prior to
March 15, 2008, at a redemption price equal to 100% of the
principal amount plus a make-whole premium (as defined in the
indenture) and on or after March 15, 2008, at fixed
redemption prices as set forth in the indenture.
5.875% Senior
Notes Due March 2016
On March 23, 2004, the Company completed an offering of
$250.0 million of 5.875% Senior Notes due March 2016.
The notes are senior unsecured obligations of the Company and
rank equally with all of the Companys other senior
unsecured indebtedness. Interest payments are scheduled to occur
on April 15 and October 15 of each year, and commenced on
April 15, 2004. The notes are guaranteed by the
Companys Subsidiary Guarantors as defined in the note
indenture. The note indenture contains covenants which, among
other things, limit the Companys ability to incur
additional indebtedness and issue preferred stock, pay dividends
or make other distributions, make other restricted payments and
investments, create liens, sell assets and merge or consolidate
with other entities. The notes are redeemable prior to
April 15, 2009, at a redemption price equal to 100% of the
principal amount plus a make-whole premium (as defined in the
indenture) and on or after April 15, 2009, at fixed
redemption prices as set forth in the indenture. Net proceeds
from the offering, after deducting underwriting discounts and
expenses, were $244.7 million.
5.0% Subordinated
Note
The 5.0% Subordinated Note was retired during the three
months ended March 31, 2007.
Series Bonds
As of December 31, 2007, the Company had $74.0 million
in Series Bonds outstanding, which were assumed as part of
the Excel acquisition. The 6.84% Series A Bonds have a
balloon maturity in December 2014. The 6.34% Series B Bonds
mature in December 2014 and are payable in installments
beginning December 2008. The 6.84% Series C Bonds mature in
December 2016 and are payable in installments beginning December
2012. Interest payments are scheduled to occur in June and
December of each year.
Interest
Rate Swaps
As of December 31, 2007, the Company had a series of
fixed-to-floating interest rate swaps with a notional principal
amount of $120.0 million. Under the terms of these swaps
the Company receives a fixed rate of 6.875% and pays a weighted
average floating rate of LIBOR plus 2.0%, which resets each
March 15, June 15, September 15 and December 15.
The swaps have been designated as a hedge of the changes in the
fair value of the 6.875% Senior Notes due 2013.
The Company also has another series of fixed-to-floating
interest rate swaps with a notional principal amount of
$100.0 million. Under the terms of these swaps the Company
receives a fixed rate of 5.875% and pays a weighted average
floating rate of LIBOR plus 0.25%, which resets each April 15
and October 15. This series of swaps has been designated as
a hedge of the changes in the fair value of the
5.875% Senior Notes due 2016.
F-31
PEABODY
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
In conjunction with the Term Loan Facility, the Company has a
floating-to-fixed interest rate swap in place for a notional
principal amount of $120.0 million. Under the terms of this
swap the Company receives a floating rate of LIBOR plus 1.0% and
pays a fixed rate of 6.25%. This interest rate swap was
designated as a hedge of the variable interest payments on the
Term Loan under the Senior Unsecured Credit Facility.
Because the critical terms of the swaps and the respective debt
instruments they hedge coincide, there was no hedge
ineffectiveness recognized in the consolidated statements of
operations during the years ended December 31, 2007 and
2006. At December 31, 2007 and 2006 there was an unrealized
loss related to the cash flow hedge of $6.8 million and
$2.5 million, respectively. At December 31, 2007 there
was a net unrealized gain on the fair value hedges of
$1.6 million. At December 31, 2006 there was a net
unrealized loss on the fair value hedges of $13.8 million.
The fair value hedge is reflected as an adjustment to the
carrying value of the Senior Notes (see table above).
Capital
Lease Obligations and Other
Capital lease obligations include obligations assumed from the
Excel acquisition, primarily for mining equipment (see
Note 10 for additional information on the Companys
capital lease obligations).
Other long-term debt, which consists principally of notes
payable, is due in installments through 2016. The
weighted-average effective interest rate of this debt was 6.32%
as of December 31, 2007.
As of December 31, 2006, Capital lease
obligations reflected an additional $40.2 million
that was previously classified as Accounts payable and
accrued expenses on the Companys consolidated
balance sheet in its Annual Report on
Form 10-K
for the year ended December 31, 2006. The reclassification
relates to a capital lease transaction structure that was
finalized during the three months ended March 31, 2007. The
lease term is seven years with annual payments of
approximately $7.2 million over the term of the lease, and
a balloon payment at maturity of approximately
$11.2 million.
The aggregate amounts of long-term debt maturities subsequent to
December 31, 2007, including capital lease obligations,
were as follows:
|
|
|
|
|
Year of Maturity
|
|
(Dollars in thousands)
|
|
|
2008
|
|
$
|
36,673
|
|
2009
|
|
|
37,395
|
|
2010
|
|
|
33,217
|
|
2011
|
|
|
546,875
|
|
2012
|
|
|
20,862
|
|
2013 and thereafter
|
|
|
2,598,078
|
|
|
|
|
|
|
Total
|
|
$
|
3,273,100
|
|
|
|
|
|
|
Interest paid on long-term debt was $191.9 million,
$114.6 million and $94.2 million for the years ended
December 31, 2007, 2006 and 2005, respectively. The Company
paid interest expense of $1.5 million and $3.3 million
on the Revolver in 2007 and 2006, respectively, and no interest
was paid on the Revolver in 2005.
Early
Debt Extinguishment Costs
For the year ended December 31, 2007, the Company recorded
net early debt extinguishment costs of $0.3 million,
primarily related to the repayment of borrowings under the Term
Loan Facility. For the year ended December 31, 2006, the
Company recorded net early debt extinguishment costs of
$1.4 million, primarily related to the repayment of
borrowings on the 5.875% Senior Notes.
F-32
PEABODY
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Shelf
Registration Statement
On July 28, 2006, the Company filed an automatic shelf
registration statement on
Form S-3
as a well-known seasoned issuer with the SEC. The registration
was for an indeterminate number of securities and is effective
for three years, at which time the Company can file an automatic
shelf registration statement that would become immediately
effective for another three-year term. Under this universal
shelf registration statement, the Company has the capacity to
offer and sell from time to time securities, including common
stock, preferred stock, debt securities, warrants and units. The
Debentures, 7.375% Senior Notes due 2016 and
7.875% Senior Notes due 2026 were issued pursuant to the
shelf registration statement.
|
|
(14)
|
Asset
Retirement Obligations
|
Reconciliations of the Companys liability for asset
retirement obligations were as follows:
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
|
(Dollars in thousands)
|
|
|
Balance at beginning of year, including discontinued operations
|
|
$
|
423,031
|
|
|
$
|
399,203
|
|
Liabilities incurred or acquired
|
|
|
27,041
|
|
|
|
18,573
|
|
Liabilities settled or disposed
|
|
|
(16,563
|
)
|
|
|
(40,621
|
)
|
Accretion expense
|
|
|
27,813
|
|
|
|
29,480
|
|
Revisions to estimate
|
|
|
32,142
|
|
|
|
16,396
|
|
|
|
|
|
|
|
|
|
|
Consolidated asset retirement obligations
|
|
|
493,464
|
|
|
|
423,031
|
|
Liabilities related to the Patriot spin-off
|
|
|
(123,917
|
)
|
|
|
(139,703
|
)
|
|
|
|
|
|
|
|
|
|
Balance at end of year
|
|
$
|
369,547
|
|
|
$
|
283,328
|
|
|
|
|
|
|
|
|
|
|
As of December 31, 2007, asset retirement obligations of
$369.5 million consisted of $337.0 million related to
locations with active mining operations and $32.5 million
related to locations that are closed or inactive. As of
December 31, 2006, asset retirement obligations of
$423.0 million consisted of $354.0 million related to
locations with active mining operations and $69.0 million
related to locations that are closed or inactive. The amount of
asset retirement obligations related to discontinued operations
was $139.7 million at December 31, 2006. This total
consists of $96.3 million related to locations with active
mining operations and $43.4 million related to locations
that are closed or inactive. The credit-adjusted, risk-free
interest rates were 7.85% at December 31, 2007 and 6.60%
and 6.16% at January 1, 2007 and 2006, respectively.
As of December 31, 2007 and 2006, the Company had
$418.3 million and $356.0 million, respectively, in
surety bonds outstanding to secure reclamation obligations or
activities. The amount of reclamation self-bonding in certain
states in which the Company qualifies was $640.6 million
and $636.5 million as of December 31, 2007 and 2006,
respectively. Additionally, the Company had $1.6 million
and $2.7 million of letters of credit in support of
reclamation obligations or activities as of December 31,
2007 and 2006, respectively. These figures have all been
adjusted to exclude financial guarantees related to Patriot Coal
Corporation.
|
|
(15)
|
Pension
and Savings Plans
|
One of the Companys subsidiaries, Peabody Investments
Corp., sponsors a defined benefit pension plan covering certain
U.S. salaried employees and eligible hourly employees at
certain Peabody Investments Corp. subsidiaries (the Peabody
Plan). A Peabody Investments Corp. subsidiary also has a defined
benefit pension plan covering eligible employees who are
represented by the UMWA under the Western Surface Agreement (the
Western Plan). Peabody Investments Corp. also sponsors an
unfunded supplemental retirement plan to provide senior
management with benefits in excess of limits under the federal
tax law.
F-33
PEABODY
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Annual contributions to the plans are made as determined by
consulting actuaries based upon the Employee Retirement Income
Security Act of 1974 minimum funding standard. In May 1998, the
Company entered into an agreement with the Pension Benefit
Guaranty Corporation (PBGC) which requires the Company to
maintain certain minimum funding requirements. Beginning on
January 1, 2008, new minimum funding standards will be
required by the Pension Protection Act of 2006. Assets of the
plans are primarily invested in various marketable securities,
including U.S. government bonds, corporate obligations and
listed stocks.
Net periodic pension costs included the following components:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
(Dollars in thousands)
|
|
|
Service cost for benefits earned
|
|
$
|
12,719
|
|
|
$
|
12,234
|
|
|
$
|
11,853
|
|
Interest cost on projected benefit obligation
|
|
|
48,959
|
|
|
|
46,034
|
|
|
|
45,499
|
|
Expected return on plan assets
|
|
|
(57,370
|
)
|
|
|
(54,587
|
)
|
|
|
(52,812
|
)
|
Amortization of prior service cost
|
|
|
349
|
|
|
|
(32
|
)
|
|
|
|
|
Amortization of actuarial losses
|
|
|
15,329
|
|
|
|
22,685
|
|
|
|
24,588
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net periodic pension costs
|
|
|
19,986
|
|
|
|
26,334
|
|
|
|
29,128
|
|
Curtailment (gain) loss
|
|
|
(403
|
)
|
|
|
|
|
|
|
9,527
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total net periodic pension costs
|
|
$
|
19,583
|
|
|
$
|
26,334
|
|
|
$
|
38,655
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
During 2007, benefits were frozen for certain participants of
the Companys Western U.S. Mining operations and those
participants impacted by the Patriot spin-off under the Peabody
Plan resulting in a curtailment gain of $0.4 million. The
2005 curtailment loss resulted from the termination of
operations at two of the three operating mines that participate
in the Western Plan during 2005. The loss is actuarially
determined and consists of an increase in the actuarial
liability, the accelerated recognition of previously unamortized
prior service cost and contractual termination benefits under
the Western Plan resulting from the termination of operations.
The following includes amounts recognized in accumulated other
comprehensive income:
|
|
|
|
|
|
|
Year Ended
|
|
|
|
December 31, 2007
|
|
|
|
(Dollars in thousands)
|
|
|
Net actuarial gain arising during year
|
|
$
|
(89,628
|
)
|
Prior service cost arising during year
|
|
|
7,893
|
|
Amortizations:
|
|
|
|
|
Actuarial loss
|
|
|
(15,329
|
)
|
Prior service credit
|
|
|
54
|
|
|
|
|
|
|
Total recognized in other comprehensive income
|
|
|
(97,010
|
)
|
Net periodic postretirement benefit costs
|
|
|
19,986
|
|
|
|
|
|
|
Total recognized in net periodic postretirement benefit costs
and other comprehensive income
|
|
$
|
(77,024
|
)
|
|
|
|
|
|
The Company amortizes actuarial gains and losses using a 5%
corridor with a five-year amortization period. The estimated net
actuarial gain and prior service cost that will be amortized
from accumulated other comprehensive income (loss) into net
periodic pension costs during the year ended December 31,
2008 are $0.5 million and $1.2 million, respectively.
F-34
PEABODY
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The following summarizes the change in benefit obligation,
change in plan assets and funded status of the Companys
plans:
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
|
(Dollars in thousands)
|
|
|
Change in benefit obligation:
|
|
|
|
|
|
|
|
|
Projected benefit obligation at beginning of period
|
|
$
|
832,800
|
|
|
$
|
801,818
|
|
Service cost
|
|
|
12,719
|
|
|
|
12,234
|
|
Interest cost
|
|
|
48,959
|
|
|
|
46,034
|
|
Plan amendments
|
|
|
7,893
|
|
|
|
|
|
Curtailments
|
|
|
(20,516
|
)
|
|
|
|
|
Benefits paid
|
|
|
(42,642
|
)
|
|
|
(40,323
|
)
|
Actuarial (gain) loss
|
|
|
(61,063
|
)
|
|
|
13,037
|
|
|
|
|
|
|
|
|
|
|
Projected benefit obligation at end of period
|
|
|
778,150
|
|
|
|
832,800
|
|
|
|
|
|
|
|
|
|
|
Change in plan assets:
|
|
|
|
|
|
|
|
|
Fair value of plan assets at beginning of period
|
|
|
704,172
|
|
|
|
654,023
|
|
Actual return on plan assets
|
|
|
65,417
|
|
|
|
84,326
|
|
Employer contributions
|
|
|
5,357
|
|
|
|
6,146
|
|
Benefits paid
|
|
|
(42,642
|
)
|
|
|
(40,323
|
)
|
|
|
|
|
|
|
|
|
|
Fair value of plan assets at end of period
|
|
|
732,304
|
|
|
|
704,172
|
|
|
|
|
|
|
|
|
|
|
Funded status at end of year
|
|
$
|
(45,846
|
)
|
|
$
|
(128,628
|
)
|
|
|
|
|
|
|
|
|
|
Amounts recognized in the consolidated balance sheets:
|
|
|
|
|
|
|
|
|
Intangible asset (included in Investments and other assets)
|
|
$
|
208
|
|
|
$
|
|
|
Current obligation (included in Accounts payable and accrued
expenses)
|
|
|
(1,315
|
)
|
|
|
(1,312
|
)
|
Noncurrent obligation (included in Other noncurrent liabilities)
|
|
|
(44,739
|
)
|
|
|
(127,316
|
)
|
|
|
|
|
|
|
|
|
|
Net amount recognized
|
|
$
|
(45,846
|
)
|
|
$
|
(128,628
|
)
|
|
|
|
|
|
|
|
|
|
The weighted-average assumptions used to determine the benefit
obligations as of the end of each year were as follows:
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
Discount rate
|
|
|
6.75%
|
|
|
|
6.00%
|
|
Rate of compensation increase
|
|
|
N/A
|
|
|
|
3.50%
|
|
Measurement date
|
|
|
December 31, 2007
|
|
|
|
December 31, 2006
|
|
F-35
PEABODY
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The weighted-average assumptions used to determine net periodic
benefit cost were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
Discount rate
|
|
|
6.00%
|
|
|
|
5.90%
|
|
|
|
6.10%
|
|
Expected long-term return on plan assets
|
|
|
8.75%
|
|
|
|
8.75%
|
|
|
|
8.75%
|
|
Rate of compensation increase
|
|
|
3.50%
|
|
|
|
3.50%
|
|
|
|
3.50%
|
|
Measurement date
|
|
|
December 31, 2006
|
|
|
|
December 31, 2005
|
|
|
|
December 31, 2004
|
|
The expected rate of return on plan assets is determined by
taking into consideration expected long-term returns associated
with each major asset class (net of inflation) based on
long-term historical ranges, inflation assumptions and the
expected net value from active management of the assets based on
actual results.
The projected benefit obligation and the accumulated benefit
obligation exceeded plan assets for all plans as of
December 31, 2007 and 2006. The accumulated benefit
obligation for all pension plans was $681.1 million and
$808.4 million as of December 31, 2007, and 2006,
respectively.
Plan
Assets
Assets of the Peabody Plan and the Western Plan are commingled
in the Peabody Investment Corporation Master Trust (the Master
Trust) and are invested in accordance with investment guidelines
that have been established by the Companys Retirement
Committee (the Retirement Committee) after consultation with
outside investment advisors and actuaries.
As of the year ended December 31, 2007, Master Trust assets
totaled $732.3 million and were invested in the following
major asset categories:
|
|
|
|
|
|
|
|
|
|
|
Percentage
|
|
|
|
|
|
|
Allocation of
|
|
|
Target
|
|
|
|
Total Assets
|
|
|
Allocation
|
|
|
Equity securities
|
|
|
38.5
|
%
|
|
|
40.0
|
%
|
Fixed income
|
|
|
36.6
|
%
|
|
|
35.0
|
%
|
International equity
|
|
|
15.5
|
%
|
|
|
15.0
|
%
|
Real estate
|
|
|
9.4
|
%
|
|
|
10.0
|
%
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
100.0
|
%
|
|
|
100.0
|
%
|
|
|
|
|
|
|
|
|
|
As of the year ended December 31, 2006, Master Trust assets
totaled $704.2 million and were invested in the following
major asset categories:
|
|
|
|
|
|
|
|
|
|
|
Percentage
|
|
|
|
|
|
|
Allocation of
|
|
|
Target
|
|
|
|
Total Assets
|
|
|
Allocation
|
|
|
Equity securities
|
|
|
58.5
|
%
|
|
|
55.0
|
%
|
Fixed income
|
|
|
32.9
|
%
|
|
|
35.0
|
%
|
Real estate
|
|
|
7.6
|
%
|
|
|
10.0
|
%
|
Cash fund
|
|
|
1.0
|
%
|
|
|
0.0
|
%
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
100.0
|
%
|
|
|
100.0
|
%
|
|
|
|
|
|
|
|
|
|
The asset allocation targets have been set with the expectation
that the plans assets will fund the plans expected
liabilities with an appropriate level of risk. To determine the
appropriate target asset allocations, the Retirement Committee
considers the demographics of the plan participants, the funding
status of the plan, the
F-36
PEABODY
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
business and financial profile of the Company and other
associated risk preferences. These allocation targets are
reviewed by the Retirement Committee on a regular basis and
revised as necessary. Periodically, assets are rebalanced among
major asset categories to maintain the allocations within a
range of plus or minus 5% of the target allocation.
Plan assets are either under active management by third-party
investment advisors or in index funds, all selected and
monitored by the Retirement Committee. The Retirement Committee
has established specific investment guidelines for each major
asset class including performance benchmarks, allowable and
prohibited investment types and concentration limits. In
general, the plan investment guidelines do not permit leveraging
the Master Trusts assets. Equity investment guidelines do
not permit entering into put or call options (except as deemed
appropriate to manage currency risk), and futures contracts are
permitted only to the extent necessary to equitize cash holdings.
Contributions
The Company expects to contribute $19.7 million to its
funded pension plans and make $1.3 million in expected
benefit payments attributable to its unfunded pension plans
during 2008.
Estimated
Future Benefit Payments
The following benefit payments (net of retiree contributions),
which reflect expected future service, as appropriate, are
expected to be paid by the Master Trust:
|
|
|
|
|
|
|
Pension
|
|
|
|
Benefits
|
|
|
|
(Dollars in
|
|
|
|
thousands)
|
|
|
2008
|
|
$
|
45,287
|
|
2009
|
|
|
46,575
|
|
2010
|
|
|
48,084
|
|
2011
|
|
|
50,211
|
|
2012
|
|
|
52,010
|
|
Years
2013-2017
|
|
|
321,112
|
|
Defined
Contribution Plans
The Company sponsors employee retirement accounts under three
401(k) plans for eligible salaried U.S. employees. The
Company matches voluntary contributions to each plan up to
specified levels. Excluding the discontinued operations of
Patriot, the expense for these plans was $21.7 million,
$12.7 million and $9.5 million for the years ended
December 31, 2007, 2006 and 2005, respectively. A
performance contribution feature allows for additional
contributions from the Company based upon meeting specified
Company performance targets, and the performance contributions
made by the Company were $4.9 million, $7.3 million
and $8.7 million for the years ended December 31,
2007, 2006 and 2005, respectively, excluding the discontinued
operations of Patriot.
Multi-Employer
Pension Plan Discontinued Operations
Certain subsidiaries that were part of the Patriot spin-off
participate in multi-employer pension plans (the 1950 Plan and
the 1974 Plan), which provide defined benefits to substantially
all hourly coal production workers represented by the UMWA under
the 2007 NBCWA. During 2007, contributions of $5.9 million
made to the 1974 Plan were expensed as paid, and are reflected
in Discontinued operations. There were no
contributions to the multi-employer pension plans during the
years ended December 31, 2006 or 2005.
F-37
PEABODY
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
(16)
|
Postretirement
Health Care and Life Insurance Benefits
|
The Company currently provides health care and life insurance
benefits to qualifying salaried and hourly retirees and their
dependents from defined benefit plans established by the
Company. Plan coverage for health and life insurance benefits is
provided to future hourly retirees in accordance with the
applicable labor agreement.
Net periodic postretirement benefit costs included the following
components:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
(Dollars in thousands)
|
|
|
Service cost for benefits earned
|
|
$
|
9,427
|
|
|
$
|
7,575
|
|
|
$
|
4,812
|
|
Interest cost on accumulated postretirement benefit obligation
|
|
|
50,542
|
|
|
|
43,497
|
|
|
|
45,108
|
|
Amortization of prior service cost
|
|
|
(158
|
)
|
|
|
(2,232
|
)
|
|
|
(2,667
|
)
|
Amortization of actuarial losses
|
|
|
22,788
|
|
|
|
18,123
|
|
|
|
16,318
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net periodic postretirement benefit costs
|
|
$
|
82,599
|
|
|
$
|
66,963
|
|
|
$
|
63,571
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net periodic postretirement benefit costs related to the
spin-off of Patriot for the years ended December 31, 2007,
2006, and 2005, were $46.6 million, $41.4 million, and
$35.4 million, respectively, and were included in
Discontinued operations. The Company amortizes
actuarial gains and losses using a 0% corridor with an
amortization period that covers the average remaining service
period of active employees (8.92 years and 8.47 years
at January 1, 2007 and 2006, respectively).
The following includes amounts recognized in accumulated other
comprehensive income:
|
|
|
|
|
|
|
Year Ended
|
|
|
|
December 31, 2007
|
|
|
|
(Dollars in thousands)
|
|
|
Net actuarial gain arising during year
|
|
$
|
(24,474
|
)
|
Prior service cost arising during year
|
|
|
13,835
|
|
Amortizations:
|
|
|
|
|
Actuarial loss
|
|
|
(22,788
|
)
|
Prior service credit
|
|
|
158
|
|
|
|
|
|
|
Total recognized in other comprehensive income
|
|
|
(33,269
|
)
|
Net periodic postretirement benefit costs
|
|
|
82,599
|
|
|
|
|
|
|
Total recognized in net periodic postretirement benefit costs
and other comprehensive income
|
|
$
|
49,330
|
|
|
|
|
|
|
The estimated net actuarial loss and prior service cost that
will be amortized from accumulated other comprehensive income
(loss) into net periodic postretirement benefit costs during the
year ended December 31, 2008 are $18.0 million and
$0.4 million, respectively.
F-38
PEABODY
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The following table sets forth the plans combined funded
status reconciled with the amounts shown in the consolidated
balance sheets:
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
|
(Dollars in thousands)
|
|
|
Change in benefit obligation:
|
|
|
|
|
|
|
|
|
Accumulated postretirement benefit obligation at beginning of
period
|
|
$
|
872,732
|
|
|
$
|
765,928
|
|
Service cost
|
|
|
9,427
|
|
|
|
7,575
|
|
Interest cost
|
|
|
50,542
|
|
|
|
43,497
|
|
Participant contributions
|
|
|
883
|
|
|
|
1,082
|
|
Plan amendments
|
|
|
13,835
|
|
|
|
15,878
|
|
Benefits paid
|
|
|
(67,168
|
)
|
|
|
(68,475
|
)
|
Actuarial (gain) loss
|
|
|
(24,474
|
)
|
|
|
107,247
|
|
|
|
|
|
|
|
|
|
|
Accumulated postretirement benefit obligation at end of period
|
|
|
855,777
|
|
|
|
872,732
|
|
|
|
|
|
|
|
|
|
|
Change in plan assets:
|
|
|
|
|
|
|
|
|
Fair value of plan assets at beginning of period
|
|
|
|
|
|
|
|
|
Employer contributions
|
|
|
66,285
|
|
|
|
67,393
|
|
Participant contributions
|
|
|
883
|
|
|
|
1,082
|
|
Benefits paid and administrative fees (net of Medicare
Part D reimbursements)
|
|
|
(67,168
|
)
|
|
|
(68,475
|
)
|
|
|
|
|
|
|
|
|
|
Fair value of plan assets at end of period
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Funded status at end of year
|
|
|
(855,777
|
)
|
|
|
(872,732
|
)
|
Less current portion (included in Accounts payable and accrued
expenses)
|
|
|
70,069
|
|
|
|
63,719
|
|
|
|
|
|
|
|
|
|
|
Noncurrent obligation (included in Accrued postretirement
benefit costs)
|
|
$
|
(785,708
|
)
|
|
$
|
(809,013
|
)
|
|
|
|
|
|
|
|
|
|
The weighted-average assumptions used to determine the benefit
obligations as of the end of each year were as follows:
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
Discount rate
|
|
|
6.60%
|
|
|
|
6.00%
|
|
Rate of compensation increase
|
|
|
3.50%
|
|
|
|
3.50%
|
|
Measurement date
|
|
|
December 31, 2007
|
|
|
|
December 31, 2006
|
|
The weighted-average assumptions used to determine net periodic
benefit cost were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
Discount rate
|
|
|
6.00%
|
|
|
|
5.90%
|
|
|
|
6.10%
|
|
Rate of compensation increase
|
|
|
3.50%
|
|
|
|
3.50%
|
|
|
|
3.50%
|
|
Measurement date
|
|
|
December 31, 2006
|
|
|
|
December 31, 2005
|
|
|
|
December 31, 2004
|
|
F-39
PEABODY
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The following presents information about the assumed health care
cost trend rate:
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
Health care cost trend rate assumed for next year
|
|
|
7.50
|
%
|
|
|
7.50
|
%
|
Rate to which the cost trend is assumed to decline (the ultimate
trend rate)
|
|
|
4.75
|
%
|
|
|
4.75
|
%
|
Year that the rate reaches the ultimate trend rate
|
|
|
2013
|
|
|
|
2012
|
|
Assumed health care cost trend rates have a significant effect
on the amounts reported for health care plans. A
one-percentage-point change in the assumed health care cost
trend would have the following effects:
|
|
|
|
|
|
|
|
|
|
|
One Percentage-
|
|
|
One Percentage-
|
|
|
|
Point Increase
|
|
|
Point Decrease
|
|
|
|
(Dollars in thousands)
|
|
|
Effect on total service and interest cost components
|
|
$
|
11,202
|
|
|
$
|
(9,580
|
)
|
Effect on total postretirement benefit obligation
|
|
$
|
81,535
|
|
|
$
|
(70,842
|
)
|
Plan
Assets
The Companys postretirement benefit plans are unfunded.
Estimated
Future Benefit Payments
The following benefit payments (net of retiree contributions),
which reflect expected future service, as appropriate, are
expected to be paid by the Company:
|
|
|
|
|
|
|
Postretirement
|
|
|
|
Benefits
|
|
|
|
(Dollars in thousands)
|
|
|
2008
|
|
$
|
70,069
|
|
2009
|
|
|
71,115
|
|
2010
|
|
|
72,391
|
|
2011
|
|
|
73,755
|
|
2012
|
|
|
76,752
|
|
Years
2013-2017
|
|
|
378,227
|
|
Medicare
and Other Plan Changes
Effective November 15, 2006, the medical premium
reimbursement plan was changed for salaried employees who
retired after December 31, 2004. The plan change did not
apply to Powder River or Lee Ranch employees. The amendment
resulted in a $20.6 million increase to the retiree health
care liability. The Company began recognizing the effect of the
plan amendment over 10.25 years beginning November 15,
2006. The effect was $2.0 million and $0.3 million for
the years ended December 31, 2007 and 2006, respectively.
On December 8, 2003, the Medicare Prescription Drug,
Improvement and Modernization Act of 2003 (the Act) was signed
into law. The Company elected not to defer the effects of the
Act as discussed in FASB Staff Position
106-1,
Accounting and Disclosure Requirements Related to the
Medicare Prescription Drug, Improvement and Modernization Act of
2003. Additionally, the Company did not elect the federal
subsidy provisions of the Act; rather the Company coordinated
benefits with available Medicare coverage considered the primary
payer, whether or not the beneficiary enrolled and paid the
required premiums.
F-40
PEABODY
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The Company recognized a reduction in the benefit obligation on
two distinct components. For plans that required amendment to
incorporate the Act, the Company recognized a liability
reduction of $19.1 million. This reduction was treated as a
negative plan amendment and is being amortized to income over
six years beginning December 15, 2003. For plans that did
not require amendment, the Company recognized a liability
reduction of $162.4 million. The reduction was treated as a
change in the estimated cost to provide benefits to Medicare
eligible beneficiaries constituting a component of the
cumulative actuarial gain or loss subject to amortization in
accordance with the Companys amortization method.
In January 1999, the Company adopted reductions to the salaried
employee medical coverage levels for employees retiring before
January 1, 2003, which was changed to January 1, 2005,
in 2002. For employees retiring on or after January 1,
2005, the previous medical plan was replaced with a medical
premium reimbursement plan. This plan change did not apply to
Powder River or Lee Ranch salaried employees. The change in the
retiree health care plan resulted in a $22.4 million
reduction to the salaried retiree health care liability. The
Company began recognizing the effect of the plan amendment over
nine years beginning January 1, 1999. The effect was
$1.0 million for the years ended December 31, 2007,
2006 and 2005, respectively.
Multi-Employer
Benefit Plans Discontinued Operations
Multi-employer benefit obligations related to the Combined Fund,
the 1992 Benefit Plan and 1993 Benefit Plan became the
responsibility of Patriot in conjunction with the spin-off. The
Surface Mining Control and Reclamation Act Amendments of 2006
amended the federal laws establishing the Combined Fund and the
1992 Benefit Plan and include the 1993 Benefit Plan. To the
extent that (i) the annual federal funding exceeds a
specified amount, (ii) Congress does not allocate
additional funds to cover the shortfall and
(iii) Patriots subsidiaries do not pay for their
share of the shortfall, some of the Companys subsidiaries
would be responsible for the additional costs.
As of December 31, 2006, the $25.6 million noncurrent
obligation for the Combined Fund was in Noncurrent
liabilities of discontinued operations and the current
portion of $5.2 million was in Current liabilities of
discontinued operations in the consolidated balance
sheets. The total expense for the Combined Fund, the 1992
Benefit Plan and 1993 Benefit Plan was $14.5 million,
$8.2 million and $4.9 million for the years ended
December 31, 2007, 2006 and 2005, respectively, and was
included in Discontinued operations.
Pursuant to the provisions of the Coal Act and the 1992 Benefit
Plan, the Company was required to provide a specified amount of
security. In accordance with the 1992 Benefit Plan, the Company
had outstanding letters of credit of $41.4 million as of
October 31, 2007 and $119.4 million as of
December 31, 2006, to secure the Companys obligation.
|
|
(17)
|
Stockholders
Equity
|
Common
Stock
The Company has 800.0 million authorized shares of
$0.01 par value common stock. Holders of common stock are
entitled to one vote per share on all matters to be voted upon
by the stockholders. The holders of common stock do not have
cumulative voting rights in the election of directors. Holders
of common stock are entitled to receive ratably dividends if, as
and when dividends are declared from time to time by the Board
of Directors out of funds legally available for that purpose,
after payment of dividends required to be paid on outstanding
preferred stock or series common stock. Upon liquidation,
dissolution or winding up, any business combination or a sale or
disposition of all or substantially all of the assets, the
holders of common stock are entitled to receive ratably the
assets available for distribution to the stockholders after
payment of liabilities and accrued but unpaid dividends and
liquidation preferences on any outstanding preferred stock or
series common stock. The common stock has no preemptive or
conversion rights and is not subject to further calls
F-41
PEABODY
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
or assessment by the Company. There are no redemption or sinking
fund provisions applicable to the common stock.
Effective February 22, 2006, the Company implemented a
two-for-one stock split on all shares of its common stock. The
Company had a similar two-for-one stock split on March 30,
2005. All share and per share amounts in these consolidated
financial statements and related notes reflect the stock splits.
The following table summarizes common stock activity from
December 31, 2004 to December 31, 2007:
|
|
|
|
|
|
|
Shares
|
|
|
|
Outstanding
|
|
|
December 31, 2004
|
|
|
259,135,908
|
|
Stock options exercised
|
|
|
3,633,750
|
|
Stock grants to employees
|
|
|
375,400
|
|
Employee stock purchases
|
|
|
210,750
|
|
Stock grants to non-employee directors
|
|
|
1,594
|
|
|
|
|
|
|
December 31, 2005
|
|
|
263,357,402
|
|
Stock options exercised
|
|
|
1,940,539
|
|
Stock grants to employees
|
|
|
566,631
|
|
Employee stock purchases
|
|
|
156,785
|
|
Stock grants to non-employee directors
|
|
|
10,440
|
|
Shares repurchased
|
|
|
(2,184,958
|
)
|
|
|
|
|
|
December 31, 2006
|
|
|
263,846,839
|
|
Stock options exercised
|
|
|
5,222,074
|
|
Stock grants to employees
|
|
|
937,795
|
|
Employee stock purchases
|
|
|
185,646
|
|
Stock grants to non-employee directors
|
|
|
11,892
|
|
Shares relinquished
|
|
|
(137,625
|
)
|
|
|
|
|
|
December 31, 2007
|
|
|
270,066,621
|
|
|
|
|
|
|
Preferred
Stock and Series Common Stock
In addition to the common stock, the Board of Directors is
authorized to issue up to 10.0 million shares of preferred
stock and up to 40.0 million shares of series common stock.
The Board of Directors is authorized to determine the terms and
rights of each series, including the number of authorized
shares, whether dividends (if any) will be cumulative or
non-cumulative and the dividend rate of the series, redemption
or sinking fund provisions, conversion terms, prices and rates,
and amounts payable on shares of the series in the event of any
voluntary or involuntary liquidation, dissolution or winding up
of the affairs of the Company. The Board of Directors may also
determine restrictions on the issuance of shares of the same
series or of any other class or series, and the voting rights
(if any) of the holders of the series. There were no outstanding
shares of preferred stock or series common stock as of
December 31, 2007.
Perpetual
Preferred Stock
As discussed in Note 13, the Company issued
$732.5 million aggregate principal amount of Debentures on
December 20, 2006. Perpetual preferred stock issued upon a
conversion of Debentures will be fully paid and non-assessable,
and holders will have no preemptive or preferential right to
purchase any of the Companys other securities. The
perpetual preferred stock has a liquidation preference of $1,000
per share, is
F-42
PEABODY
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
not convertible and is redeemable at the Companys option
at any time at a cash redemption price per share equal to the
liquidation preference plus any accumulated dividends. Holders
are entitled to receive cumulative dividends at an annual rate
of 3.0875% if and when declared by the Companys Board of
Directors. After the Company has failed to pay dividends on the
perpetual preferred stock for five years, or upon the occurrence
of a mandatory trigger event, as defined in the certificate of
designations governing the perpetual preferred stock, the
Company generally must sell warrants or preferred stock with
specified characteristics and use the funds from that sale to
pay accumulated dividends after the payment in full of any
deferred interest on the Debentures, subject to certain
limitations. In the event of a mandatory trigger event, the
Company may not declare dividends on the perpetual preferred
stock other than those funded through the sale of warrants or
preferred stock as described above. Any deferred interest on the
Debentures at the time of notice of conversion will be reflected
as accumulated dividends on the perpetual preferred stock at
issuance. Additionally, holders of the perpetual preferred stock
are entitled to elect two additional members to serve on the
Companys Board of Directors if (i) prior to any
remarketing of the perpetual preferred stock, the Company fails
to declare and pay dividends with respect to the perpetual stock
for 10 consecutive years or (ii) after any successful
remarketing or any final failed remarketing of the perpetual
preferred stock, the Company fails to declare and pay six
dividends thereon, whether or not consecutive. The perpetual
preferred stock may be remarketed at the holders election
after December 15, 2046 or earlier, upon the first
occurrence of a change of control if the Company does not redeem
the perpetual preferred stock. There were no outstanding shares
of perpetual preferred stock as of December 31, 2007.
Preferred
Share Purchase Rights Plan and Series A Junior
Participating Preferred Stock
Each outstanding share of common stock, par value $0.01 per
share, of the Company carries one preferred share purchase right
(a Right). The Rights are governed by a plan that expires in
August 2012.
The Rights have certain anti-takeover effects. The Rights will
cause substantial dilution to a person or group that attempts to
acquire the Company on terms not approved by the Companys
Board of Directors, except pursuant to any offer conditioned on
a substantial number of Rights being acquired. The Rights should
not interfere with any merger or other business combination
approved by the Board of Directors since the Rights may be
redeemed by the Company at a redemption price of $0.001 per
Right prior to the time that a person or group has acquired
beneficial ownership of 15% or more of the common stock of the
Company. In addition, the Board of Directors is authorized to
reduce the 15% threshold to not less than 10%.
Each Right entitles the holder to purchase one quarter of
one-hundredth of a share of series A junior participating
preferred stock from the Company at an exercise price of $27.50,
which in turn provides rights to receive the number of common
stock shares having a market value of two times the exercise
price of the Right. The Right is exercisable only if a person or
group acquires 15% or more of the Companys common stock.
The Board of Directors is authorized to issue up to
1.5 million shares of series A junior participating
preferred stock. There were no outstanding shares of
series A junior participating preferred stock as of
December 31, 2007.
Treasury
Stock
In July 2005, the Companys Board of Directors authorized a
share repurchase program of up to 5% of the then outstanding
shares of its common stock, or approximately 13.1 million
shares. The repurchases may be made from time to time based on
an evaluation of the Companys outlook and general business
conditions, as well as alternative investment and debt repayment
options. During the year ended December 31, 2006, the
Company repurchased 2,184,958 of its common shares at a cost of
$99.8 million. There were no share repurchases under this
program for the year ended December 31, 2007.
During the year ended December 31, 2007, the Company
received 137,625 shares of common stock as consideration
for employees exercise of stock options and to pay
estimated taxes at the vesting date of
F-43
PEABODY
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
restricted stock. The value of the common stock tendered by
employees to exercise stock options and to settle taxes on
restricted stock was based upon the closing price on the dates
of the respective transactions. The common stock tenders were in
accordance with the provisions of the 1998 Stock Purchase and
Option Plan, which was previously approved by the Companys
Board of Directors.
|
|
(18)
|
Share-Based
Compensation
|
The Company recognizes share-based compensation expense in
accordance with SFAS No. 123(R), which it adopted on
January 1, 2006, and utilizes restricted stock,
nonqualified stock options, performance units, and an employee
stock purchase plan as part of its share-based compensation
program. The Company has four equity incentive plans for
employees and non-employee directors that in the aggregate allow
for the issuance of share-based compensation in the form of
stock appreciation rights, restricted stock, performance awards,
incentive stock options, nonqualified stock options and stock
units. Members of the Companys Board of Directors are
eligible for stock option and restricted stock grants at the
date of their election and annually in January. These plans made
47.4 million shares of the Companys common stock
available for grant, with 13.6 million shares available for
grant as of December 31, 2007. Additionally, in 2001, the
Company established an employee stock purchase plan that
provided for the purchase of up to 6.0 million shares of
the Companys common stock.
For share-based payment instruments excluding restricted stock,
the Company recognized $6.6 million (or $0.02 per diluted
share), $17.7 million (or $0.07 per diluted share) and
$24.8 million (or $0.09 per diluted share) of expense, net
of taxes, for the years ended December 31, 2007, 2006 and
2005, respectively. Share-based compensation expense is recorded
in Selling and administrative expenses in the
consolidated statements of operations. As of December 31,
2007, the total unrecognized compensation cost related to
nonvested awards was $26.9 million, net of taxes, which is
expected to be recognized over 5.2 years with a
weighted-average period of 1.1 years.
The Company used the Black-Scholes option pricing model to
determine the fair value of stock options and employee stock
purchase plan share-based payments made before and after the
adoption of SFAS No. 123(R). The Company utilized
U.S. Treasury yields as of the grant date for its risk-free
interest rate assumption, matching the treasury yield terms to
the expected life of the option or vesting period of the
performance unit awards. The Company utilized historical company
data to develop its dividend yield, expected volatility and
expected option life assumptions.
Restricted
Stock Awards
The Company began utilizing restricted stock as part of its
equity-based compensation strategy in January 2005. Accounting
for restricted stock awards was not changed by the adoption of
SFAS No. 123(R). The Company recognized
$10.6 million, $4.2 million and $0.9 million of
expense, net of taxes, for the years ended December 31,
2007, 2006 and 2005, respectively, related to restricted stock.
F-44
PEABODY
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
A summary of restricted stock award activity is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted
|
|
|
|
Year Ended
|
|
|
Average
|
|
|
|
December 31,
|
|
|
Grant-Date
|
|
|
|
2007
|
|
|
Fair Value
|
|
|
Nonvested at January 1, 2007
|
|
|
1,011,577
|
|
|
$
|
33.32
|
|
Granted
|
|
|
1,020,809
|
|
|
|
42.16
|
|
Vested
|
|
|
(38,607
|
)
|
|
|
27.12
|
|
Acceleration at spin-off
|
|
|
(389,798
|
)
|
|
|
47.55
|
|
Forfeited
|
|
|
(71,122
|
)
|
|
|
32.79
|
|
|
|
|
|
|
|
|
|
|
Nonvested at December 31, 2007
|
|
|
1,532,859
|
|
|
$
|
36.01
|
|
|
|
|
|
|
|
|
|
|
Stock
Options
Employee and director stock options granted since the
Companys initial public offering (IPO) of common stock in
May 2001 generally vest ratably over three years and expire
after 10 years from the date of the grant, subject to
earlier termination upon discontinuation of an employees
service. Options granted prior to the IPO generally cliff vest
in 2010 and represented 1.2 million options of the
4.8 million options outstanding at December 31, 2007.
Option grants are typically made in January of each year or
following the inception of employment for employees hired during
the year who are eligible to participate in the plan. The fair
value of each option grant is estimated on the date of grant
using the Black-Scholes option-pricing model. The Company
recognized expense, net of taxes, of $3.7 million,
$4.7 million and $0.1 million for the years ended
December 31, 2007, 2006 and 2005, respectively, related to
stock option grants to employees and non-employee directors.
A summary of outstanding option activity under the plans is as
follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
|
|
|
|
Weighted
|
|
|
Average
|
|
|
Aggregate
|
|
|
|
Year Ended
|
|
|
Average
|
|
|
Remaining
|
|
|
Intrinsic
|
|
|
|
December 31,
|
|
|
Exercise
|
|
|
Contractual
|
|
|
Value
|
|
|
|
2007
|
|
|
Price
|
|
|
Life
|
|
|
(in millions)
|
|
|
Beginning balance
|
|
|
9,320,718
|
|
|
$
|
8.16
|
|
|
|
|
|
|
|
|
|
Granted
|
|
|
427,298
|
|
|
|
35.05
|
|
|
|
|
|
|
|
|
|
Spin-off adjustment
|
|
|
349,108
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exercised
|
|
|
(5,222,074
|
)
|
|
|
4.86
|
|
|
|
|
|
|
|
|
|
Forfeited
|
|
|
(70,116
|
)
|
|
|
3.86
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding
|
|
|
4,804,934
|
|
|
$
|
12.46
|
|
|
|
4.8
|
|
|
$
|
236.3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Vested and Exercisable
|
|
|
2,626,802
|
|
|
$
|
8.95
|
|
|
|
4.5
|
|
|
$
|
138.4
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
F-45
PEABODY
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
During the years ended December 31, 2007, 2006 and 2005,
the total intrinsic value of options exercised, defined as the
excess fair value of the underlying stock over the exercise
price of the options, was $248.7 million,
$84.2 million and $77.6 million, respectively. The
weighted-average fair values of the Companys stock options
and the assumptions used in applying the Black-Scholes option
pricing model (for grants during the years ended
December 31, 2007, 2006 and 2005) were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
Weighted-average fair value
|
|
$
|
37.93
|
|
|
$
|
16.52
|
|
|
$
|
8.03
|
|
Risk-free interest rate
|
|
|
4.6%
|
|
|
|
4.3%
|
|
|
|
3.6%
|
|
Expected option life
|
|
|
5.0 years
|
|
|
|
6.0 years
|
|
|
|
5.7 years
|
|
Expected volatility
|
|
|
43%
|
|
|
|
36%
|
|
|
|
40%
|
|
Dividend yield
|
|
|
0.6%
|
|
|
|
0.8%
|
|
|
|
1.0%
|
|
Prior to adopting SFAS No. 123(R), the Company applied
APB Opinion No. 25 and related interpretations to account
for its equity incentive plans. The following table reflects
2005 pro forma net income and basic and diluted earnings per
share had compensation cost been determined for the
Companys non-qualified and incentive stock options based
on the fair value at the grant dates consistent with the
methodology set forth under SFAS No. 123:
|
|
|
|
|
|
|
Year Ended
|
|
|
|
December 31, 2005
|
|
|
|
(Dollars in thousands
|
|
|
|
except per share data)
|
|
|
Net income:
|
|
|
|
|
As reported
|
|
$
|
422,653
|
|
Pro forma
|
|
|
418,704
|
|
Basic earnings per share:
|
|
|
|
|
As reported
|
|
$
|
1.62
|
|
Pro forma
|
|
|
1.60
|
|
Diluted earnings per share:
|
|
|
|
|
As reported
|
|
$
|
1.58
|
|
Pro forma
|
|
|
1.56
|
|
Performance
Units
Performance units, which are typically granted annually in
January, and vest over a three-year measurement period, subject
to the achievement of performance goals and relative stock price
performance at the conclusion of the vesting term. Three
performance unit grants were outstanding during 2007 (the 2005,
2006 and 2007 grants), 2006 (the 2004, 2005 and 2006 grants) and
2005 (the 2003, 2004 and 2005 grants). The payouts related to
all active grants will be settled in the Companys common
stock. The payouts for the 2004 and 2003 grants were settled in
cash. Payouts for the 2004 through 2007 grants are based 50% on
stock price performance compared to both an industry peer group
and a S&P index (a market condition under
SFAS No. 123(R)) and 50% on a return on capital target
(a performance condition under
SFAS No. 123(R)). The payout related to the 2003 grant
was based on the Companys stock price performance relative
to both an industry peer group and an S&P index. The
Company granted 0.2 million performance units in each of
the years ended December 31, 2007, 2006, and 2005.
F-46
PEABODY
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
A summary of performance unit activity is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted
|
|
|
Weighted
|
|
|
|
|
|
|
Average
|
|
|
Average
|
|
|
|
Year Ended
|
|
|
Grant-
|
|
|
Remaining
|
|
|
|
December 31,
|
|
|
Date
|
|
|
Contractual
|
|
|
|
2007
|
|
|
Fair Value
|
|
|
Life
|
|
|
Nonvested at January 1, 2007
|
|
|
421,421
|
|
|
$
|
35.24
|
|
|
|
|
|
Granted
|
|
|
180,462
|
|
|
|
42.33
|
|
|
|
|
|
Spin-off adjustment
|
|
|
49,689
|
|
|
|
|
|
|
|
|
|
Vested
|
|
|
(305,864
|
)
|
|
|
38.32
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nonvested at December 31, 2007
|
|
|
345,708
|
|
|
$
|
41.53
|
|
|
|
1.5
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31, 2007, there were 305,864 performance
units vested that had an aggregate intrinsic value of
$25.8 million and a conversion price per share of $59.31.
Under APB Opinion No. 25, all performance unit awards were
accounted for as variable awards. Under
SFAS No. 123(R), the awards settled in cash were
accounted for as liability awards and adjusted to fair value at
each period-end, and the awards settled in common stock are
accounted for based on their grant date fair value. The
performance condition awards were valued utilizing the grant
date fair values of the Companys stock adjusted for
dividends foregone during the vesting period. The market
condition awards were valued utilizing a Monte Carlo simulation
which incorporates the total shareholder return hurdles set for
each grant. The Company recognized expense, net of taxes, of
$1.6 million, $11.7 million, and $24.7 million
for the years ended December 31, 2007, 2006, and 2005,
respectively, related to performance units. The assumptions used
in the valuations for grants during the years ended
December 31, 2007 and 2006 were as follows:
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
Risk-free interest rate
|
|
|
4.7
|
%
|
|
|
4.3
|
%
|
Expected volatility
|
|
|
43
|
%
|
|
|
36
|
%
|
Dividend yield
|
|
|
0.6
|
%
|
|
|
0.8
|
%
|
Employee
Stock Purchase Plan
Based on the Companys employee stock purchase plan,
eligible full-time and part-time employees are able to
contribute up to 15% of their base compensation into this plan,
subject to a limit of $25,000 per person per year. Employees are
able to purchase Company common stock at a 15% discount to the
lower of the fair market value of the Companys common
stock on the initial or final trading dates of each six-month
offering period. Offering periods begin on January 1 and July 1
of each year. The fair value of the six-month
look-back option in the Companys employee
stock purchase plan is estimated by adding the fair value of
0.15 of one share of stock to the fair value of 0.85 of an
option on one share of stock. The Company recognized expense,
net of taxes, of $1.2 million for the year ended
December 31, 2007 related to its employee stock purchase
plan. Shares purchased under the plan were 0.2 million for
each of the years ended December 31, 2007, 2006 and 2005,
respectively.
F-47
PEABODY
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
(19)
|
Accumulated
Other Comprehensive Income (Loss)
|
The following table sets forth the after-tax components of
comprehensive income (loss):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Actuarial Loss
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Associated with
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Postretirement
|
|
|
Prior Service
|
|
|
|
|
|
Total
|
|
|
|
Foreign
|
|
|
Minimum
|
|
|
Plans and
|
|
|
Cost Associated
|
|
|
|
|
|
Accumulated
|
|
|
|
Currency
|
|
|
Pension
|
|
|
Workers
|
|
|
with
|
|
|
|
|
|
Other
|
|
|
|
Translation
|
|
|
Liability
|
|
|
Compensation
|
|
|
Postretirement
|
|
|
Cash Flow
|
|
|
Comprehensive
|
|
|
|
Adjustment
|
|
|
Adjustment
|
|
|
Obligations
|
|
|
Plans
|
|
|
Hedges
|
|
|
Loss
|
|
|
|
(Dollars in thousands)
|
|
|
December 31, 2004
|
|
$
|
3,153
|
|
|
$
|
(71,645
|
)
|
|
$
|
|
|
|
$
|
|
|
|
$
|
7,874
|
|
|
$
|
(60,618
|
)
|
Net increase in value of cash flow hedges
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
36,154
|
|
|
|
36,154
|
|
Reclassification from other comprehensive income to earnings
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(24,733
|
)
|
|
|
(24,733
|
)
|
Current period change
|
|
|
|
|
|
|
2,402
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,402
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2005
|
|
$
|
3,153
|
|
|
$
|
(69,243
|
)
|
|
$
|
|
|
|
$
|
|
|
|
$
|
19,295
|
|
|
$
|
(46,795
|
)
|
Net increase in value of cash flow hedges
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
45,799
|
|
|
|
45,799
|
|
Reclassification from other comprehensive income to earnings
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(21,452
|
)
|
|
|
(21,452
|
)
|
Current period change
|
|
|
|
|
|
|
22,377
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
22,377
|
|
Adjustment to initially apply SFAS No. 158
|
|
|
|
|
|
|
46,866
|
|
|
|
(288,820
|
)
|
|
|
(7,033
|
)
|
|
|
|
|
|
|
(248,987
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2006
|
|
$
|
3,153
|
|
|
$
|
|
|
|
$
|
(288,820
|
)
|
|
$
|
(7,033
|
)
|
|
$
|
43,642
|
|
|
$
|
(249,058
|
)
|
Net increase in value of cash flow hedges
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
83,606
|
|
|
|
83,606
|
|
Reclassification from other comprehensive income to earnings:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Continuing operations
|
|
|
|
|
|
|
|
|
|
|
24,329
|
|
|
|
(127
|
)
|
|
|
(61,810
|
)
|
|
|
(37,608
|
)
|
Discontinued operations
|
|
|
|
|
|
|
|
|
|
|
17,937
|
|
|
|
(6,074
|
)
|
|
|
|
|
|
|
11,863
|
|
Current period change
|
|
|
|
|
|
|
|
|
|
|
64,183
|
|
|
|
(13,037
|
)
|
|
|
|
|
|
|
51,146
|
|
Patriot spin-off
|
|
|
|
|
|
|
|
|
|
|
65,644
|
|
|
|
7,341
|
|
|
|
|
|
|
|
72,985
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2007
|
|
$
|
3,153
|
|
|
$
|
|
|
|
$
|
(116,727
|
)
|
|
$
|
(18,930
|
)
|
|
$
|
65,438
|
|
|
$
|
(67,066
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Comprehensive income differs from net income by the amount of
unrealized gain or loss resulting from valuation changes of the
Companys cash flow hedges (which include fuel and natural
gas hedges, currency forwards and interest rate swaps) during
the periods, and for the year ended December 31, 2007, the
adjustment required by SFAS No. 158 to record the
funded status of the Companys pension and other
post-retirement benefit plans. The values of the Companys
cash flow hedging instruments are affected by changes in
interest rates, crude oil, heating oil and natural gas prices
and the U.S. dollar/Australian dollar exchange rate.
F-48
PEABODY
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
(20)
|
Guarantees
and Financial Instruments With Off-Balance-Sheet Risk
|
In the normal course of business, the Company is a party to
guarantees and financial instruments with off-balance-sheet
risk, such as bank letters of credit, performance or surety
bonds and other guarantees and indemnities, which are not
reflected in the accompanying consolidated balance sheets. Such
financial instruments are valued based on the amount of exposure
under the instrument and the likelihood of required performance.
In the Companys past experience, virtually no claims have
been made against these financial instruments. Management does
not expect any material losses to result from these guarantees
or off-balance-sheet instruments.
Letters
of Credit and Bonding
The Company has letters of credit, surety bonds and corporate
guarantees (such as self bonds) in support of the Companys
reclamation, lease, workers compensation, retiree
healthcare and other obligations as follows as of
December 31, 2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Workers
|
|
|
Retiree
|
|
|
|
|
|
|
|
|
|
Reclamation
|
|
|
Lease
|
|
|
Compensation
|
|
|
Healthcare
|
|
|
|
|
|
|
|
|
|
Obligations
|
|
|
Obligations
|
|
|
Obligations
|
|
|
Obligations
|
|
|
Other(1)
|
|
|
Total
|
|
|
|
(Dollars in thousands)
|
|
|
Self Bonding
|
|
$
|
640,630
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
640,630
|
|
Surety Bonds
|
|
|
418,303
|
|
|
|
72,985
|
|
|
|
31,210
|
|
|
|
|
|
|
|
16,747
|
|
|
|
539,245
|
|
Letters of Credit
|
|
|
1,625
|
|
|
|
|
|
|
|
102,687
|
|
|
|
41,361
|
|
|
|
267,947
|
|
|
|
413,620
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
1,060,558
|
|
|
$
|
72,985
|
|
|
$
|
133,897
|
|
|
$
|
41,361
|
|
|
$
|
284,694
|
|
|
$
|
1,593,495
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Other includes the three letter of credit obligations described
below and an additional $78.3 million in self-bonding,
letters of credit and surety bonds related to collateral for
surety companies, road maintenance, performance guarantees and
other operations. |
The Company owns a 30.0% interest in a partnership that leases a
coal export terminal from the Peninsula Ports Authority of
Virginia under a
30-year
lease that permits the partnership to purchase the terminal at
the end of the lease term for a nominal amount. The partners
have severally (but not jointly) agreed to make payments under
various agreements which in the aggregate provide the
partnership with sufficient funds to pay rents and to cover the
principal and interest payments on the floating-rate industrial
revenue bonds issued by the Peninsula Ports Authority, and which
are supported by letters of credit from a commercial bank. As of
December 31, 2007, the Companys maximum reimbursement
obligation to the commercial bank was in turn supported by a
letter of credit totaling $42.8 million.
The Company is party to an agreement with the PBGC and TXU
Europe Limited, an affiliate of the Companys former parent
corporation, under which the Company is required to make special
contributions to two of the Companys defined benefit
pension plans and to maintain a $37.0 million letter of
credit in favor of the PBGC. If the Company or the PBGC gives
notice of an intent to terminate one or more of the covered
pension plans in which liabilities are not fully funded, or if
the Company fails to maintain the letter of credit, the PBGC may
draw down on the letter of credit and use the proceeds to
satisfy liabilities under the Employee Retirement Income
Security Act of 1974, as amended. The PBGC, however, is required
to first apply amounts received from a $110.0 million
guarantee in place from TXU Europe Limited in favor of the PBGC
before it draws on the Companys letter of credit. On
November 19, 2002 TXU Europe Limited was placed under the
administration process in the United Kingdom (a process similar
to bankruptcy proceedings in the United States) and continues
under this process as of December 31, 2007. As a result of
these proceedings, TXU Europe Limited may be liquidated or
otherwise reorganized in such a way as to relieve it of its
obligations under its guarantee.
F-49
PEABODY
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
At December 31, 2007, the Company has a $126.6 million
letter of credit for collateral for bank guarantees issued with
respect to certain reclamation and performance obligations
related to the mines acquired in the Excel acquisition.
Other
Guarantees
As part of arrangements through which the Company obtains
exclusive sales representation agreements with small coal mining
companies (the Counterparties), the Company issued financial
guarantees on behalf of the Counterparties. These guarantees
facilitate the Counterparties efforts to obtain bonding or
financing. In 2007, the Company purchased approximately
345 million tons of coal reserves and surface lands in the
Illinois Basin. In conjunction with this purchase, the Company
agreed to provide up to $64.8 million of reclamation and
bonding commitments to a third-party coal company. The Company
has recognized the full amount of these commitments as a
liability as of December 31, 2007. The non-cash portion of
this transaction was excluded from the investing section of the
statement of cash flows.
In the event of default, the Company has multiple recourse
options, including the ability to assume the loans and procure
title and use of the equipment purchased through the loans. If
default occurs, the Company has the ability and intent to
exercise its recourse options, so the liability associated with
the guarantee has been valued at zero. The Company also
guaranteed bonding for a partnership in which it formerly held
an interest. The aggregate amount guaranteed by the Company for
all such Counterparties was $8.8 million at
December 31, 2007. The Companys obligations under the
guarantees extend to September 2015.
The Company is the lessee under numerous equipment and property
leases. It is common in such commercial lease transactions for
the Company, as the lessee, to agree to indemnify the lessor for
the value of the property or equipment leased, should the
property be damaged or lost during the course of the
Companys operations. The Company expects that losses with
respect to leased property would be covered by insurance
(subject to deductibles). The Company and certain of its
subsidiaries have guaranteed other subsidiaries
performance under their various lease obligations. Aside from
indemnification of the lessor for the value of the property
leased, the Companys maximum potential obligations under
its leases are equal to the respective future minimum lease
payments as presented in Note 10, and the Company assumes
that no amounts could be recovered from third parties.
The Companys former wholly-owned subsidiary, Prairie State
Generating Company, LLC (PSGC), had previously entered into a
cost reimbursable Target Price Engineering, Procurement and
Construction Agreement (the EPC Agreement) with Bechtel Power
Corporation (Bechtel) related to the Prairie State mine mouth
pulverized coal-fired generating facility. The Company provided
an absolute and unconditional payment guarantee of all amounts
due until financial closing by PSGC to Bechtel under the EPC
Agreement (Initial Owner Guarantee). On September 28, 2007,
PSGC gave Bechtel notice to proceed to full scale construction
of the facility. On that date, the Companys ownership
interest in PSGC was transferred to an Indiana non-profit
corporation that is owned and controlled by a group of owners
(Owners), including two of the Companys affiliates.
Contemporaneously with the transfer of PSGCs membership
interests, each Owner (including the Companys affiliates)
issued a guarantee to Bechtel for its proportionate share of
PSGCs obligations under the EPC Agreement and the Company
issued a guarantee to Bechtel for the Companys two
affiliates. The Initial Owner Guarantee was returned to the
Company following the issuance of new guarantees by each Owner.
After the sale of one of the Companys owner affiliates in
December 2007, the Companys remaining affiliate owns 5.06%
of PSGC.
The Company has provided financial guarantees under certain
long-term debt agreements entered into by its subsidiaries, and
substantially all of the Companys subsidiaries provide
financial guarantees under long-term debt agreements entered
into by the Company. The maximum amounts payable under the
Companys debt agreements are equal to the respective
principal and interest payments. See Note 13 for the
descriptions
F-50
PEABODY
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
of the Companys (and its subsidiaries) debt.
Supplemental guarantor/non-guarantor financial information is
provided in Note 25.
As part of the Patriot spin-off, the Company agreed to maintain
in force several letters of credit that secured Patriot
obligations for certain employee benefits and workers
compensation obligations. These letters of credit are to be
released upon Patriot satisfying the beneficiaries with
alternate letters of credit or insurance, which is expected to
occur in 2008. If Patriot is unable to satisfy the primary
beneficiaries by June 30, 2011, they are then required to
provide directly to the Company a letter of credit in the amount
of the remaining obligation. As of December 31, 2007, the
amount of letters of credit securing Patriot obligations is
$136.8 million.
A discussion of the Companys accounts receivable
securitization is included in Note 7 to the consolidated
financial statements.
|
|
(21)
|
Fair
Value of Financial Instruments
|
The following methods and assumptions were used by the Company
in estimating its fair value disclosures for financial
instruments as of December 31, 2007 and 2006:
|
|
|
|
|
Cash and cash equivalents, accounts receivable and accounts
payable and accrued expenses have carrying values which
approximate fair value due to the short maturity or the
financial nature of these instruments.
|
|
|
|
The fair value of the Companys coal trading assets and
liabilities was determined as described in Note 6.
|
|
|
|
Long-term debt fair value estimates are based on observed prices
for securities with an active trading market when available, and
otherwise on estimated borrowing rates to discount the cash
flows to their present value. The 7.875% Senior Notes due
2026 and the 5.0% Subordinated Note carrying amount are net
of unamortized note discount.
|
|
|
|
The fair values of interest rate swap contracts, currency
forward contracts, explosives hedge contracts and fuel hedge
contracts were provided by the respective contract
counterparties, and were based on benchmark transactions entered
into on terms substantially similar to those entered into by the
Company and the contract counterparties. Based on these
estimates as of December 31, 2007, the Company would have
paid $1.1 million and $2.0 million, respectively, upon
liquidation of its interest rate swaps and explosives hedges and
would have received $124.8 million and $48.4 million,
respectively, upon liquidation of its currency forwards and
diesel fuel hedges.
|
The carrying amounts and estimated fair values of the
Companys debt are summarized as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2007
|
|
|
December 31, 2006
|
|
|
|
Carrying
|
|
|
Estimated
|
|
|
Carrying
|
|
|
Estimated
|
|
|
|
Amount
|
|
|
Fair Value
|
|
|
Amount
|
|
|
Fair Value
|
|
|
|
|
|
|
(Dollars in thousands)
|
|
|
|
|
|
Long-term debt
|
|
$
|
3,273,100
|
|
|
$
|
3,471,561
|
|
|
$
|
3,277,032
|
|
|
$
|
3,310,590
|
|
See Note 3 for a discussion of the Companys
derivative financial instruments.
F-51
PEABODY
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
(22)
|
Commitments
and Contingencies
|
Commitments
As of December 31, 2007, purchase commitments for capital
expenditures were $67.8 million. Commitments for
expenditures to be made under coal leases are reflected in
Note 10.
From time to time, the Company or its subsidiaries are involved
in legal proceedings arising in the ordinary course of business
or related to indemnities or historical operations. The Company
believes it has recorded adequate reserves for these liabilities
and that there is no individual case pending that is likely to
have a material adverse effect on the Companys financial
condition, results of operations or cash flows. The Company
discusses its significant legal proceedings below.
Litigation
Relating to Continuing Operations
Navajo
Nation Litigation
On June 18, 1999, the Navajo Nation served three of the
Companys subsidiaries, including Peabody Western Coal
Company (Peabody Western), with a complaint that had been filed
in the U.S. District Court for the District of Columbia.
The Navajo Nation has alleged 16 claims, including Civil
Racketeer Influenced and Corrupt Organizations Act (RICO)
violations and fraud. The complaint alleges that the defendants
jointly participated in unlawful activity to obtain favorable
coal lease amendments. The plaintiff is seeking various remedies
including actual damages of at least $600 million, which
could be trebled under the RICO counts, punitive damages of at
least $1 billion, a determination that Peabody
Westerns two coal leases have terminated due to Peabody
Westerns breach of these leases and a reformation of these
leases to adjust the royalty rate to 20%. Subsequently, the
court allowed the Hopi Tribe to intervene in this lawsuit and
the Hopi Tribe is also seeking unspecified actual damages,
punitive damages and reformation of its coal lease. One of the
Companys subsidiaries named as a defendant is now a
subsidiary of Patriot. However, the Company is responsible for
this litigation under the Separation Agreement entered into with
Patriot in connection with the spin-off. On February 9,
2005, the U.S. District Court for the District of Columbia
granted a consent motion to stay the litigation until further
order of the court. Peabody Western, the Navajo Nation, the Hopi
Tribe and the owners of the power plants served by the suspended
Black Mesa mine and the Kayenta mine have terminated the
mediation with respect to this litigation and other business
issues, filed a status report with the Court and asked the Court
to lift the stay. The Court has not lifted the stay.
The outcome of this litigation is subject to numerous
uncertainties. Based on the Companys evaluation of the
issues and their potential impact, the amount of any future loss
cannot be reasonably estimated. However, based on current
information, the Company believes this matter is likely to be
resolved without a material adverse effect on its financial
condition, results of operations or cash flows.
Salt
River Project Agricultural Improvement and Power
District Mine Closing and Retiree Health
Care
Salt River Project and the other owners of the Navajo Generating
Station filed a lawsuit on September 27, 1996, in the
Superior Court of Maricopa County in Arizona seeking a
declaratory judgment that certain costs relating to final
reclamation, environmental monitoring work and mine
decommissioning and costs primarily relating to retiree health
care benefits are not recoverable by the Companys
subsidiary, Peabody Western, under the terms of a coal supply
agreement dated February 18, 1977. The contract expires in
2011. The trial court subsequently ruled that the mine
decommissioning costs were subject to arbitration but that the
retiree health care costs were not subject to arbitration. The
Company has recorded a receivable for mine decommissioning costs
of $87.7 million and $76.8 million included in
Investments and other assets in the consolidated
balance sheets as of December 31, 2007 and 2006,
respectively. The parties negotiated a final comprehensive
settlement and are in the process of obtaining all required
approvals of the settlement documents.
F-52
PEABODY
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Gulf
Power Company Litigation
On June 22, 2006, Gulf Power Company filed a breach of
contract lawsuit against a Company subsidiary in the
U.S. District Court, Northern District of Florida,
contesting the force majeure declaration by the Company
subsidiary under a coal supply agreement with Gulf Power Company
and seeking damages for alleged past and future tonnage
shortfalls of nearly 5 million tons under the agreement,
which expired on December 31, 2007. The Company has filed a
motion to dismiss the Florida lawsuit or to transfer it to
Illinois. The Court held an evidentiary hearing on the
Companys motion to dismiss or transfer and has continued
to stay discovery until the Court rules on the motion.
The outcome of this litigation is subject to numerous
uncertainties. Based on the Companys evaluation of the
issues and their potential impact, the amount of any future loss
cannot reasonably be estimated. However, based on current
information, the Company believes this matter is likely to be
resolved without a material adverse effect on its financial
condition, results of operations or cash flows.
Claims
and Litigation Relating to Indemnities or Historical
Operations
Oklahoma
Lead Litigation
Gold Fields Mining, LLC (Gold Fields) is a dormant, non-coal
producing entity that was previously managed and owned by Hanson
PLC, the Companys predecessor owner. In a February 1997
spin-off, Hanson PLC transferred ownership of Gold Fields to the
Company, despite the fact that Gold Fields had no ongoing
operations and the Company had no prior involvement in its past
operations. Gold Fields is currently one of the Companys
subsidiaries. The Company indemnified TXU Group with respect to
certain claims relating to a former affiliate of Gold Fields. A
predecessor of Gold Fields formerly operated two lead mills near
Picher, Oklahoma prior to the 1950s and mined, in accordance
with lease agreements and permits, approximately 0.15% of the
total amount of the crude ore mined in the county.
Gold Fields and two other companies are defendants in two class
action lawsuits allegedly involving past operations near Picher,
Oklahoma. The plaintiffs have asserted claims predicated on
allegations of intentional lead exposure by the defendants and
are seeking compensatory damages, punitive damages and the
implementation of medical monitoring and relocation programs for
the affected individuals. Gold Fields was also a defendant,
along with other companies, in personal injury lawsuits that at
one time involved over 50 individuals, arising out of the same
lead mill operations. Gold Fields, along with the former
affiliate, has settled most of the claims in the personal injury
lawsuits and the remaining lawsuits have been dismissed with
prejudice. In December 2003, the Quapaw Indian tribe and certain
Quapaw land owners filed a lawsuit against Gold Fields, five
other companies and the United States. The plaintiffs are
seeking compensatory and punitive damages based on a variety of
theories. In December 2007, the court dismissed the tribes
medical monitoring claim. Gold Fields has filed a third-party
complaint against the United States and other parties. In
February 2005, the state of Oklahoma on behalf of itself and
several other parties sent a notice to Gold Fields and other
companies regarding a possible natural resources damage claim.
All of the lawsuits are pending in the U.S. District Court
for the Northern District of Oklahoma.
The outcome of litigation and these claims are subject to
numerous uncertainties. Based on the Companys evaluation
of the issues and their potential impact, the amount of any
future loss cannot be reasonably estimated. However, based on
current information, the Company believes this matter is likely
to be resolved without a material adverse effect on its
financial condition, results of operations or cash flows.
Environmental
Claims and Litigation
Environmental claims have been asserted against Gold Fields
related to activities of Gold Fields or a former affiliate. Gold
Fields or the former affiliate has been named a potentially
responsible party (PRP) at five national priority list sites
based on the Superfund Amendments and Reauthorization Act of
1986. Claims
F-53
PEABODY
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
were asserted at 12 additional sites, the total of which have
since been reduced to 12 by completion of work, transfer or
regulatory inactivity. The number of PRP sites in and of itself
is not a relevant measure of liability, because the nature and
extent of environmental concerns varies by site, as does the
estimated share of responsibility for Gold Fields or the former
affiliate. Undiscounted liabilities for environmental
cleanup-related costs for all of the sites noted above were
$42.4 million as of December 31, 2007 and
$43.0 million as of December 31, 2006,
$7.1 million and $14.4 million of which was reflected
as a current liability, respectively. These amounts represent
those costs that the Company believes are probable and
reasonably estimable. In September 2005, Gold Fields and other
PRPs received a letter from the U.S. Department of Justice
alleging that the PRPs mining operations caused the
Environmental Protection Agency (EPA) to incur approximately
$125 million in residential yard remediation costs at
Picher, Oklahoma and will cause the EPA to incur additional
remediation costs relating to historical mining sites. Gold
Fields has participated in the settlement discussions. Gold
Fields believes it has meritorious defenses to these claims.
Gold Fields is involved in other litigation in the Picher area,
and the Company indemnified TXU Group with respect to a
defendant as is more fully discussed under the Oklahoma
Lead Litigation caption above. Significant uncertainty
exists as to whether claims will be pursued against Gold Fields
in all cases, and where they are pursued, the amount of the
eventual costs and liabilities, which could be greater or less
than this provision. Based on the Companys evaluation of
the issues and their potential impact, the amount of any future
loss cannot be reasonably estimated. However, based on current
information, the Company believes these claims and litigation
are likely to be resolved without a material adverse effect on
its financial condition, results of operations or cash flows.
Other
Certain subsidiaries of the Company are required to pay black
lung excise taxes to the Federal Black Lung Trust Fund (the
Trust Fund). The Trust Fund pays occupational disease
benefits to entitled former miners who worked prior to
July 1, 1973. Excise taxes are based on the selling price
of coal, up to a maximum of $1.10 per ton for underground mines
and $0.55 per ton for surface mines. The Company had a
receivable for excise tax refunds paid on export shipments of
$19.4 million as of December 31, 2007 and 2006. In a
January 2007 decision, a federal appellate court ruled that coal
companies are entitled to a refund of the Black Lung tax paid on
export shipments for certain years and that they are also
entitled to collect interest on the refund. This matter is now
pending before the U.S. Supreme Court.
In addition, at times the Company becomes a party to other
claims, lawsuits, arbitration proceedings and administrative
procedures in the ordinary course of business in the U.S.,
Australia and other countries where the Company does business.
Based on current information, the Company believes that the
ultimate resolution of such other pending or threatened
proceedings is not reasonably likely to have a material adverse
effect on its financial position, results of operations or
liquidity.
New York
Office of the Attorney General Subpoena
The New York Office of the Attorney General sent a letter to the
Company dated September 14, 2007. The letter referred to
the Companys plans to build new coal-fired electric
generating units, and said that the increase in
CO2
emissions from the operation of these units, in combination with
Peabody Energys other coal-fired power plants, will
subject Peabody Energy to increased financial, regulatory, and
litigation risks. The Company currently has no electrical
generating capacity in place. The letter included a subpoena
issued under New York state law, which seeks information and
documents relating to the Companys analysis of the risks
associated with climate change and possible climate change
legislation or regulations, and its disclosure of such risks to
investors. The Company believes that it has made full and proper
disclosure of these potential risks.
F-54
PEABODY
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
(23)
|
Summary
Quarterly Financial Information (Unaudited)
|
A summary of the unaudited quarterly results of operations for
the years ended December 31, 2007 and 2006, is presented
below. The portions of the Eastern U.S. Mining operations
business segment that were included in the spin-off of Patriot
have been classified as discontinued operations and are excluded
from the operating results for all periods presented. Peabody
Energy common stock is listed on the New York Stock Exchange
under the symbol BTU.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2007
|
|
|
|
First Quarter
|
|
|
Second Quarter
|
|
|
Third Quarter
|
|
|
Fourth Quarter
|
|
|
|
(Dollars in thousands except per share and stock price
data)
|
|
|
Revenues
|
|
$
|
1,096,055
|
|
|
$
|
1,065,835
|
|
|
$
|
1,200,494
|
|
|
$
|
1,212,328
|
|
Operating profit
|
|
|
147,384
|
|
|
|
174,891
|
|
|
|
112,896
|
|
|
|
133,553
|
|
Income from continuing operations
|
|
|
81,918
|
|
|
|
96,013
|
|
|
|
52,189
|
|
|
|
191,143
|
|
Net income
|
|
|
88,506
|
|
|
|
107,692
|
|
|
|
32,272
|
|
|
|
35,815
|
|
Basic earnings per share
|
|
$
|
0.31
|
|
|
$
|
0.37
|
|
|
$
|
0.20
|
|
|
$
|
0.72
|
|
Diluted earnings per share
|
|
$
|
0.30
|
|
|
$
|
0.36
|
|
|
$
|
0.19
|
|
|
$
|
0.71
|
|
Weighted average shares used in calculating basic earnings per
share
|
|
|
263,031,869
|
|
|
|
263,479,042
|
|
|
|
263,871,330
|
|
|
|
265,861,546
|
|
Weighted average shares used in calculating diluted earnings per
share
|
|
|
268,123,462
|
|
|
|
268,712,309
|
|
|
|
268,940,930
|
|
|
|
270,535,150
|
|
Stock price high and low prices
|
|
$
|
44.60-$36.20
|
|
|
$
|
55.76-$39.96
|
|
|
$
|
50.99-$38.42
|
|
|
$
|
62.55-$47.52
|
|
Dividends per share
|
|
$
|
0.06
|
|
|
$
|
0.06
|
|
|
$
|
0.06
|
|
|
$
|
0.06
|
|
F-55
PEABODY
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Second quarter operating profit included a $50.5 million
gain resulting from an exchange of oil and gas rights for coal
reserves (see Note 4 for information). Operating profit in
the third and fourth quarters of 2007 included
$17.8 million and $8.6 million, respectively, of gains
from the sale of coal reserves and surface lands (see
Note 4 for information). Operating profit for the third
quarter of 2007 was negatively impacted by disruption in the
coal-chain in Australia. Net income for the fourth quarter of
2007 included a tax benefit related to a reduction of
$205.0 million in net operating loss valuation allowances,
partially offset by ongoing tax expense and a $56.0 million
impact on deferred taxes as a result of foreign exchange rates
(see Note 12 for information).
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2006
|
|
|
|
First Quarter
|
|
|
Second Quarter
|
|
|
Third Quarter
|
|
|
Fourth Quarter
|
|
|
|
(Dollars in thousands except per share and stock price
data)
|
|
|
Revenues
|
|
$
|
1,022,900
|
|
|
$
|
1,004,091
|
|
|
$
|
980,396
|
|
|
$
|
1,101,009
|
|
Operating profit
|
|
|
133,078
|
|
|
|
159,628
|
|
|
|
152,450
|
|
|
|
145,700
|
|
Income from continuing operations
|
|
|
109,257
|
|
|
|
142,005
|
|
|
|
140,516
|
|
|
|
160,796
|
|
Net income
|
|
|
130,222
|
|
|
|
153,434
|
|
|
|
142,008
|
|
|
|
175,033
|
|
Basic earnings per share
|
|
$
|
0.42
|
|
|
$
|
0.54
|
|
|
$
|
0.53
|
|
|
$
|
0.61
|
|
Diluted earnings per share
|
|
$
|
0.41
|
|
|
$
|
0.52
|
|
|
$
|
0.52
|
|
|
$
|
0.60
|
|
Weighted average shares used in calculating basic earnings per
share
|
|
|
263,491,072
|
|
|
|
263,958,590
|
|
|
|
263,444,254
|
|
|
|
262,790,879
|
|
Weighted average shares used in calculating diluted earnings per
share
|
|
|
269,358,728
|
|
|
|
269,756,666
|
|
|
|
268,822,681
|
|
|
|
268,137,610
|
|
Stock price high and low prices
|
|
$
|
52.54-$41.24
|
|
|
$
|
76.29-$46.81
|
|
|
$
|
59.90-$32.94
|
|
|
$
|
48.59-$34.05
|
|
Dividends per share
|
|
$
|
0.06
|
|
|
$
|
0.06
|
|
|
$
|
0.06
|
|
|
$
|
0.06
|
|
Second quarter operating profit included $39.2 million of
gains resulting from exchanges of coal reserves (see Note 4
for information). Net income for the second quarter included the
tax benefit related to a reduction in tax reserves due to the
favorable finalization of former parent companies federal tax
audits, partially offset by higher pretax earnings in 2006.
Operating profit for the third quarter of 2006 benefited from
lower performance-based compensation expense of
$20.6 million. Net income for the fourth quarter of 2006
included a tax benefit related to the partial reduction in net
operating loss valuation allowances (see Note 12 for
information).
The Company reports its operations primarily through the
following reportable operating segments: Western
U.S. Mining, Eastern U.S. Mining,
Australian Mining and Trading and
Brokerage. Western U.S. Mining operations reflect the
aggregation of the Powder River Basin, Southwest and Colorado
operating segments, and Eastern U.S. Mining operations
reflects the Companys Midwest operating segments. The
principal business of the Western U.S. Mining, Eastern
U.S. Mining and Australian Mining segments is the mining,
preparation and sale of steam coal, sold primarily to electric
utilities, and metallurgical coal, sold to steel and coke
producers. For the year ended December 31, 2007, 85% of the
Companys sales were to U.S. electricity generators,
2% were to the U.S. industrial sector, and 13% were to
customers outside the United States. Western U.S. Mining
operations are characterized by predominantly surface mining
extraction processes, lower sulfur content and Btu of coal and
longer shipping distances from the mine to the customer.
Conversely, Eastern U.S. Mining operations are
characterized by a mix of surface and underground mining
extraction processes, higher sulfur content and Btu of coal and
shorter shipping distances from the mine to the
F-56
PEABODY
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
customer. Geologically, Western operations mine bituminous and
subbituminous coal deposits, and Eastern operations mine
bituminous coal deposits. Australian Mining operations are
characterized by both surface and underground extraction
processes, mining low-sulfur, high Btu coal (metallurgical coal)
as well as steam coal primarily sold to an international
customer base with a small portion sold to Australian steel
producers and power generators. The Trading and Brokerage
segments principal business is the marketing, brokerage
and trading of coal. Corporate and Other includes
selling and administrative expenses, net gains on property
disposals, costs associated with past mining obligations, joint
venture earnings related to the Companys 25.5% investment
in a Venezuelan mine and revenues and expenses related to the
Companys other commercial activities such as coalbed
methane, generation development and resource management.
The Companys chief operating decision maker uses Adjusted
EBITDA as the primary measure of segment profit and loss.
Adjusted EBITDA is defined as income from continuing operations
before deducting early debt extinguishment costs, net interest
expense, income taxes, minority interests, asset retirement
obligation expense and depreciation, depletion and amortization.
Operating segment results for the year ended December 31,
2007 were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Western
|
|
|
Eastern
|
|
|
Australian
|
|
|
Trading and
|
|
|
Corporate
|
|
|
|
|
|
|
U.S. Mining
|
|
|
U.S. Mining
|
|
|
Mining
|
|
|
Brokerage
|
|
|
and Other
|
|
|
Consolidated
|
|
|
|
|
|
|
|
|
|
(Dollars in thousands)
|
|
|
|
|
|
|
|
|
Revenues
|
|
$
|
2,061,265
|
|
|
$
|
984,841
|
|
|
$
|
1,161,093
|
|
|
$
|
320,692
|
|
|
$
|
46,821
|
|
|
$
|
4,574,712
|
|
Adjusted EBITDA
|
|
|
597,333
|
|
|
|
196,595
|
|
|
|
159,473
|
|
|
|
110,169
|
|
|
|
(107,677
|
)
|
|
|
955,893
|
|
Total assets
|
|
|
2,893,828
|
|
|
|
529,576
|
|
|
|
3,033,280
|
|
|
|
963,636
|
|
|
|
2,247,987
|
|
|
|
9,668,307
|
|
Additions to property,
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
plant, equipment and
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
mine development
|
|
|
175,423
|
|
|
|
35,763
|
|
|
|
168,258
|
|
|
|
|
|
|
|
90,990
|
|
|
|
470,434
|
|
Federal coal lease expenditures
|
|
|
178,193
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
178,193
|
|
Income (loss) from equity affiliates
|
|
|
10
|
|
|
|
(6,130
|
)
|
|
|
|
|
|
|
|
|
|
|
20,581
|
|
|
|
14,461
|
|
Operating segment results for the year ended December 31,
2006 were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Western
|
|
|
Eastern
|
|
|
Australian
|
|
|
Trading and
|
|
|
Corporate
|
|
|
|
|
|
|
U.S. Mining
|
|
|
U.S. Mining
|
|
|
Mining
|
|
|
Brokerage
|
|
|
and Other
|
|
|
Consolidated
|
|
|
|
(Dollars in thousands)
|
|
|
Revenues
|
|
$
|
1,703,445
|
|
|
$
|
905,743
|
|
|
$
|
843,194
|
|
|
$
|
652,029
|
|
|
$
|
3,985
|
|
|
$
|
4,108,396
|
|
Adjusted EBITDA
|
|
|
473,074
|
|
|
|
184,549
|
|
|
|
278,411
|
|
|
|
92,604
|
|
|
|
(127,682
|
)
|
|
|
900,956
|
|
Total assets
|
|
|
2,628,070
|
|
|
|
348,790
|
|
|
|
2,784,922
|
|
|
|
240,329
|
|
|
|
3,511,945
|
|
|
|
9,514,056
|
|
Additions to property,
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
plant, equipment and
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
mine development
|
|
|
151,572
|
|
|
|
62,515
|
|
|
|
123,242
|
|
|
|
1,045
|
|
|
|
59,123
|
|
|
|
397,497
|
|
Federal coal lease expenditures
|
|
|
178,193
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
178,193
|
|
Income (loss) from equity affiliates
|
|
|
15
|
|
|
|
(4,968
|
)
|
|
|
|
|
|
|
|
|
|
|
27,744
|
|
|
|
22,791
|
|
F-57
Operating segment results for the year ended December 31,
2005 were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Western
|
|
|
Eastern
|
|
|
Australian
|
|
|
Trading and
|
|
|
Corporate
|
|
|
|
|
|
|
U.S. Mining
|
|
|
U.S. Mining
|
|
|
Mining
|
|
|
Brokerage
|
|
|
and Other
|
|
|
Consolidated
|
|
|
|
|
|
|
|
|
|
(Dollars in thousands)
|
|
|
|
|
|
|
|
|
Revenues
|
|
$
|
1,611,587
|
|
|
$
|
760,404
|
|
|
$
|
598,085
|
|
|
$
|
679,176
|
|
|
$
|
16,924
|
|
|
$
|
3,666,176
|
|
Adjusted EBITDA
|
|
|
459,039
|
|
|
|
168,793
|
|
|
|
202,582
|
|
|
|
43,058
|
|
|
|
(165,623
|
)
|
|
|
707,849
|
|
Total assets
|
|
|
2,566,034
|
|
|
|
247,722
|
|
|
|
426,810
|
|
|
|
212,550
|
|
|
|
2,509,874
|
|
|
|
5,962,990
|
|
Additions to property,
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
plant, equipment and
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
mine development
|
|
|
197,742
|
|
|
|
48,157
|
|
|
|
85,335
|
|
|
|
|
|
|
|
119,114
|
|
|
|
450,348
|
|
Federal coal lease expenditures
|
|
|
118,364
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
118,364
|
|
Income (loss) from equity affiliates
|
|
|
14
|
|
|
|
(5,151
|
)
|
|
|
|
|
|
|
|
|
|
|
20,364
|
|
|
|
15,227
|
|
A reconciliation of adjusted EBITDA to consolidated income from
continuing operations follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
(Dollars in thousands)
|
|
|
Total adjusted EBITDA
|
|
$
|
955,893
|
|
|
$
|
900,956
|
|
|
$
|
707,849
|
|
Depreciation, depletion and amortization
|
|
|
(361,559
|
)
|
|
|
(294,270
|
)
|
|
|
(253,788
|
)
|
Asset retirement obligation expense
|
|
|
(25,610
|
)
|
|
|
(15,830
|
)
|
|
|
(20,329
|
)
|
Interest expense
|
|
|
(235,236
|
)
|
|
|
(137,668
|
)
|
|
|
(98,066
|
)
|
Early debt extinguishment costs
|
|
|
253
|
|
|
|
(1,396
|
)
|
|
|
|
|
Interest income
|
|
|
7,094
|
|
|
|
11,309
|
|
|
|
9,088
|
|
Income tax (provision) benefit
|
|
|
78,112
|
|
|
|
90,084
|
|
|
|
(63,779
|
)
|
Minority interests
|
|
|
2,316
|
|
|
|
(611
|
)
|
|
|
(2,472
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from continuing operations
|
|
$
|
421,263
|
|
|
$
|
552,574
|
|
|
$
|
278,503
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(25)
|
Supplemental
Guarantor/Non-Guarantor Financial Information
|
In accordance with the indentures governing the
6.875% Senior Notes due March 2013, the 5.875% Senior
Notes due March 2016, the 7.375% Senior Notes due November
2016 and the 7.875% Senior Notes due November 2026, certain
wholly-owned U.S. subsidiaries of the Company have fully
and unconditionally guaranteed these Senior Notes, on a joint
and several basis. Separate financial statements and other
disclosures concerning the Guarantor Subsidiaries are not
presented because management believes that such information is
not material to the Senior Note holders. The following
historical financial statement information is provided for the
Guarantor/Non-Guarantor Subsidiaries.
F-58
PEABODY
ENERGY CORPORATION
SUPPLEMENTAL
CONSOLIDATED STATEMENTS OF OPERATIONS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2007
|
|
|
|
Parent
|
|
|
Guarantor
|
|
|
Non-Guarantor
|
|
|
|
|
|
|
|
|
|
Company
|
|
|
Subsidiaries
|
|
|
Subsidiaries
|
|
|
Eliminations
|
|
|
Consolidated
|
|
|
|
(Dollars in thousands)
|
|
|
Total revenues
|
|
$
|
|
|
|
$
|
3,429,228
|
|
|
$
|
1,307,412
|
|
|
$
|
(161,928
|
)
|
|
$
|
4,574,712
|
|
Costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating costs and expenses
|
|
|
(70,022
|
)
|
|
|
2,621,908
|
|
|
|
1,184,860
|
|
|
|
(161,928
|
)
|
|
|
3,574,818
|
|
Depreciation, depletion and amortization
|
|
|
|
|
|
|
242,380
|
|
|
|
119,179
|
|
|
|
|
|
|
|
361,559
|
|
Asset retirement obligation expense
|
|
|
|
|
|
|
18,823
|
|
|
|
6,787
|
|
|
|
|
|
|
|
25,610
|
|
Selling and administrative expenses
|
|
|
21,459
|
|
|
|
120,828
|
|
|
|
4,859
|
|
|
|
|
|
|
|
147,146
|
|
Other operating income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net (gain) loss on disposal or exchange of assets
|
|
|
|
|
|
|
(88,831
|
)
|
|
|
147
|
|
|
|
|
|
|
|
(88,684
|
)
|
(Income) loss from equity affiliates
|
|
|
(549,741
|
)
|
|
|
6,767
|
|
|
|
(21,228
|
)
|
|
|
549,741
|
|
|
|
(14,461
|
)
|
Interest expense
|
|
|
278,879
|
|
|
|
26,170
|
|
|
|
32,580
|
|
|
|
(102,393
|
)
|
|
|
235,236
|
|
Early debt extinguishment costs
|
|
|
(253
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(253
|
)
|
Interest income
|
|
|
(17,405
|
)
|
|
|
(59,898
|
)
|
|
|
(32,184
|
)
|
|
|
102,393
|
|
|
|
(7,094
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
and minority interests
|
|
|
337,083
|
|
|
|
541,081
|
|
|
|
12,412
|
|
|
|
(549,741
|
)
|
|
|
340,835
|
|
Income tax provision (benefit)
|
|
|
(84,180
|
)
|
|
|
(65,660
|
)
|
|
|
71,728
|
|
|
|
|
|
|
|
(78,112
|
)
|
Minority interests
|
|
|
|
|
|
|
868
|
|
|
|
(3,184
|
)
|
|
|
|
|
|
|
(2,316
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) from continuing operations
|
|
|
421,263
|
|
|
|
605,873
|
|
|
|
(56,132
|
)
|
|
|
(549,741
|
)
|
|
|
421,263
|
|
Loss from discontinued operations, net of tax
|
|
|
(156,978
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(156,978
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
264,285
|
|
|
$
|
605,873
|
|
|
$
|
(56,132
|
)
|
|
$
|
(549,741
|
)
|
|
$
|
264,285
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
F-59
PEABODY
ENERGY CORPORATION
SUPPLEMENTAL
CONSOLIDATED STATEMENTS OF OPERATIONS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2006
|
|
|
|
Parent
|
|
|
Guarantor
|
|
|
Non-Guarantor
|
|
|
|
|
|
|
|
|
|
Company
|
|
|
Subsidiaries
|
|
|
Subsidiaries
|
|
|
Eliminations
|
|
|
Consolidated
|
|
|
|
(Dollars in thousands)
|
|
|
Total revenues
|
|
$
|
|
|
|
$
|
2,968,631
|
|
|
$
|
1,245,856
|
|
|
$
|
(106,091
|
)
|
|
$
|
4,108,396
|
|
Costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating costs and expenses
|
|
|
(15,307
|
)
|
|
|
2,334,793
|
|
|
|
942,337
|
|
|
|
(106,091
|
)
|
|
|
3,155,732
|
|
Depreciation, depletion and amortization
|
|
|
|
|
|
|
229,247
|
|
|
|
65,023
|
|
|
|
|
|
|
|
294,270
|
|
Asset retirement obligation expense
|
|
|
|
|
|
|
15,293
|
|
|
|
537
|
|
|
|
|
|
|
|
15,830
|
|
Selling and administrative expenses
|
|
|
17,188
|
|
|
|
107,311
|
|
|
|
3,532
|
|
|
|
|
|
|
|
128,031
|
|
Other operating income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net (gain) loss on disposal or exchange of assets
|
|
|
|
|
|
|
(53,585
|
)
|
|
|
53
|
|
|
|
|
|
|
|
(53,532
|
)
|
(Income) loss from equity affiliates
|
|
|
(661,245
|
)
|
|
|
5,228
|
|
|
|
(28,019
|
)
|
|
|
661,245
|
|
|
|
(22,791
|
)
|
Interest expense
|
|
|
197,130
|
|
|
|
51,637
|
|
|
|
14,851
|
|
|
|
(125,950
|
)
|
|
|
137,668
|
|
Early debt extinguishment costs
|
|
|
1,396
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,396
|
|
Interest income
|
|
|
(21,427
|
)
|
|
|
(85,080
|
)
|
|
|
(30,752
|
)
|
|
|
125,950
|
|
|
|
(11,309
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
and minority interests
|
|
|
482,265
|
|
|
|
363,787
|
|
|
|
278,294
|
|
|
|
(661,245
|
)
|
|
|
463,101
|
|
Income tax provision (benefit)
|
|
|
(70,309
|
)
|
|
|
(99,611
|
)
|
|
|
79,836
|
|
|
|
|
|
|
|
(90,084
|
)
|
Minority interests
|
|
|
|
|
|
|
(152
|
)
|
|
|
763
|
|
|
|
|
|
|
|
611
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from continuing operations
|
|
|
552,574
|
|
|
|
463,550
|
|
|
|
197,695
|
|
|
|
(661,245
|
)
|
|
|
552,574
|
|
Income from discontinued operations, net of tax
|
|
|
48,123
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
48,123
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
600,697
|
|
|
$
|
463,550
|
|
|
$
|
197,695
|
|
|
$
|
(661,245
|
)
|
|
$
|
600,697
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
F-60
PEABODY
ENERGY CORPORATION
SUPPLEMENTAL CONSOLIDATED STATEMENTS OF OPERATIONS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2005
|
|
|
|
Parent
|
|
|
Guarantor
|
|
|
Non-Guarantor
|
|
|
|
|
|
|
|
|
|
Company
|
|
|
Subsidiaries
|
|
|
Subsidiaries
|
|
|
Eliminations
|
|
|
Consolidated
|
|
|
|
(Dollars in thousands)
|
|
|
Total revenues
|
|
$
|
|
|
|
$
|
2,721,451
|
|
|
$
|
1,036,649
|
|
|
$
|
(91,924
|
)
|
|
$
|
3,666,176
|
|
Costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating costs and expenses
|
|
|
(30,188
|
)
|
|
|
2,191,860
|
|
|
|
815,572
|
|
|
|
(91,924
|
)
|
|
|
2,885,320
|
|
Depreciation, depletion and amortization
|
|
|
|
|
|
|
220,279
|
|
|
|
33,509
|
|
|
|
|
|
|
|
253,788
|
|
Asset retirement obligation expense
|
|
|
|
|
|
|
19,658
|
|
|
|
671
|
|
|
|
|
|
|
|
20,329
|
|
Selling and administrative expenses
|
|
|
3,683
|
|
|
|
119,608
|
|
|
|
9,388
|
|
|
|
|
|
|
|
132,679
|
|
Other operating income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net gain on disposal or exchange of assets
|
|
|
|
|
|
|
(44,185
|
)
|
|
|
(260
|
)
|
|
|
|
|
|
|
(44,445
|
)
|
Income from equity affiliates
|
|
|
(342,697
|
)
|
|
|
4,772
|
|
|
|
(19,999
|
)
|
|
|
342,697
|
|
|
|
(15,227
|
)
|
Interest expense
|
|
|
154,307
|
|
|
|
54,686
|
|
|
|
18,676
|
|
|
|
(129,603
|
)
|
|
|
98,066
|
|
Interest income
|
|
|
(22,759
|
)
|
|
|
(89,442
|
)
|
|
|
(26,490
|
)
|
|
|
129,603
|
|
|
|
(9,088
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
and minority interests
|
|
|
237,654
|
|
|
|
244,215
|
|
|
|
205,582
|
|
|
|
(342,697
|
)
|
|
|
344,754
|
|
Income tax provision (benefit)
|
|
|
(40,849
|
)
|
|
|
48,503
|
|
|
|
56,125
|
|
|
|
|
|
|
|
63,779
|
|
Minority interests
|
|
|
|
|
|
|
429
|
|
|
|
2,043
|
|
|
|
|
|
|
|
2,472
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from continuing operations
|
|
|
278,503
|
|
|
|
195,283
|
|
|
|
147,414
|
|
|
|
(342,697
|
)
|
|
|
278,503
|
|
Income from discontinued operations, net of tax
|
|
|
144,150
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
144,150
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
422,653
|
|
|
$
|
195,283
|
|
|
$
|
147,414
|
|
|
$
|
(342,697
|
)
|
|
$
|
422,653
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
F-61
PEABODY
ENERGY CORPORATION
SUPPLEMENTAL CONSOLIDATED BALANCE SHEETS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2007
|
|
|
|
Parent
|
|
|
Guarantor
|
|
|
Non-Guarantor
|
|
|
|
|
|
|
|
|
|
Company
|
|
|
Subsidiaries
|
|
|
Subsidiaries
|
|
|
Eliminations
|
|
|
Consolidated
|
|
|
|
|
|
|
(Dollars in thousands)
|
|
|
|
|
|
ASSETS
|
Current assets
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
6,909
|
|
|
$
|
6,086
|
|
|
$
|
32,284
|
|
|
$
|
|
|
|
$
|
45,279
|
|
Accounts receivable, net
|
|
|
9,241
|
|
|
|
(399,178
|
)
|
|
|
647,887
|
|
|
|
|
|
|
|
257,950
|
|
Inventories
|
|
|
|
|
|
|
138,285
|
|
|
|
130,577
|
|
|
|
|
|
|
|
268,862
|
|
Assets from coal trading activities
|
|
|
|
|
|
|
966,548
|
|
|
|
|
|
|
|
|
|
|
|
966,548
|
|
Deferred income taxes
|
|
|
|
|
|
|
98,633
|
|
|
|
|
|
|
|
|
|
|
|
98,633
|
|
Other current assets
|
|
|
102,146
|
|
|
|
55,223
|
|
|
|
58,559
|
|
|
|
|
|
|
|
215,928
|
|
Current assets of discontinued operations
|
|
|
74,093
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
74,093
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current assets
|
|
|
192,389
|
|
|
|
865,597
|
|
|
|
869,307
|
|
|
|
|
|
|
|
1,927,293
|
|
Property, plant, equipment and mine development
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Land and coal interests
|
|
|
|
|
|
|
4,563,046
|
|
|
|
2,635,044
|
|
|
|
|
|
|
|
7,198,090
|
|
Buildings and improvements
|
|
|
|
|
|
|
577,044
|
|
|
|
123,465
|
|
|
|
|
|
|
|
700,509
|
|
Machinery and equipment
|
|
|
|
|
|
|
1,065,015
|
|
|
|
202,313
|
|
|
|
|
|
|
|
1,267,328
|
|
Less accumulated depreciation, depletion and amortization
|
|
|
|
|
|
|
(1,582,947
|
)
|
|
|
(250,580
|
)
|
|
|
|
|
|
|
(1,833,527
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Property, plant, equipment and mine development, net
|
|
|
|
|
|
|
4,622,158
|
|
|
|
2,710,242
|
|
|
|
|
|
|
|
7,332,400
|
|
Investments and other assets
|
|
|
7,734,604
|
|
|
|
(287,306
|
)
|
|
|
4,096
|
|
|
|
(7,042,780
|
)
|
|
|
408,614
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
7,926,993
|
|
|
$
|
5,200,449
|
|
|
$
|
3,583,645
|
|
|
$
|
(7,042,780
|
)
|
|
$
|
9,668,307
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND STOCKHOLDERS EQUITY
|
Current liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current maturities of long-term debt
|
|
$
|
122,681
|
|
|
$
|
(44
|
)
|
|
$
|
11,736
|
|
|
$
|
|
|
|
$
|
134,373
|
|
Payables and notes payable to affiliates, net
|
|
|
1,903,040
|
|
|
|
(2,527,482
|
)
|
|
|
624,442
|
|
|
|
|
|
|
|
|
|
Liabilities from coal trading activities
|
|
|
|
|
|
|
918,596
|
|
|
|
|
|
|
|
|
|
|
|
918,596
|
|
Accounts payable and accrued expenses
|
|
|
23,998
|
|
|
|
670,604
|
|
|
|
259,059
|
|
|
|
|
|
|
|
953,661
|
|
Current liabilities of discontinued operations
|
|
|
180,356
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
180,356
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current liabilities
|
|
|
2,230,075
|
|
|
|
(938,326
|
)
|
|
|
895,237
|
|
|
|
|
|
|
|
2,186,986
|
|
Long-term debt, less current maturities
|
|
|
2,983,262
|
|
|
|
199
|
|
|
|
155,266
|
|
|
|
|
|
|
|
3,138,727
|
|
Deferred income taxes
|
|
|
65,734
|
|
|
|
(100,833
|
)
|
|
|
350,703
|
|
|
|
|
|
|
|
315,604
|
|
Other noncurrent liabilities
|
|
|
95,015
|
|
|
|
1,278,314
|
|
|
|
100,053
|
|
|
|
|
|
|
|
1,473,382
|
|
Noncurrent liabilities of discontinued operations
|
|
|
33,236
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
33,236
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilities
|
|
|
5,407,322
|
|
|
|
239,354
|
|
|
|
1,501,259
|
|
|
|
|
|
|
|
7,147,935
|
|
Minority interests
|
|
|
|
|
|
|
(4,145
|
)
|
|
|
4,846
|
|
|
|
|
|
|
|
701
|
|
Stockholders equity
|
|
|
2,519,671
|
|
|
|
4,965,240
|
|
|
|
2,077,540
|
|
|
|
(7,042,780
|
)
|
|
|
2,519,671
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilities and stockholders equity
|
|
$
|
7,926,993
|
|
|
$
|
5,200,449
|
|
|
$
|
3,583,645
|
|
|
$
|
(7,042,780
|
)
|
|
$
|
9,668,307
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
F-62
PEABODY
ENERGY CORPORATION
SUPPLEMENTAL CONSOLIDATED BALANCE SHEETS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2006
|
|
|
|
Parent
|
|
|
Guarantor
|
|
|
Non-Guarantor
|
|
|
|
|
|
|
|
|
|
Company
|
|
|
Subsidiaries
|
|
|
Subsidiaries
|
|
|
Eliminations
|
|
|
Consolidated
|
|
|
|
(Dollars in thousands)
|
|
|
ASSETS
|
Current assets
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
272,226
|
|
|
$
|
3,652
|
|
|
$
|
50,633
|
|
|
$
|
|
|
|
$
|
326,511
|
|
Accounts receivable, net
|
|
|
|
|
|
|
29,808
|
|
|
|
291,014
|
|
|
|
|
|
|
|
320,822
|
|
Inventories
|
|
|
|
|
|
|
114,176
|
|
|
|
88,733
|
|
|
|
|
|
|
|
202,909
|
|
Assets from coal trading activities
|
|
|
|
|
|
|
150,373
|
|
|
|
|
|
|
|
|
|
|
|
150,373
|
|
Deferred income taxes
|
|
|
|
|
|
|
77,562
|
|
|
|
|
|
|
|
|
|
|
|
77,562
|
|
Other current assets
|
|
|
54,007
|
|
|
|
35,107
|
|
|
|
20,745
|
|
|
|
|
|
|
|
109,859
|
|
Current assets of discontinued operations
|
|
|
108,522
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
108,522
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current assets
|
|
|
434,755
|
|
|
|
410,678
|
|
|
|
451,125
|
|
|
|
|
|
|
|
1,296,558
|
|
Property, plant, equipment and mine development
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Land and coal interests
|
|
|
|
|
|
|
4,377,294
|
|
|
|
2,121,522
|
|
|
|
|
|
|
|
6,498,816
|
|
Buildings and improvements
|
|
|
|
|
|
|
498,780
|
|
|
|
123,279
|
|
|
|
|
|
|
|
622,059
|
|
Machinery and equipment
|
|
|
|
|
|
|
947,277
|
|
|
|
191,795
|
|
|
|
|
|
|
|
1,139,072
|
|
Less accumulated depreciation, depletion and amortization
|
|
|
|
|
|
|
(1,411,162
|
)
|
|
|
(139,955
|
)
|
|
|
|
|
|
|
(1,551,117
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Property, plant, equipment and mine development, net
|
|
|
|
|
|
|
4,412,189
|
|
|
|
2,296,641
|
|
|
|
|
|
|
|
6,708,830
|
|
Goodwill
|
|
|
|
|
|
|
|
|
|
|
240,667
|
|
|
|
|
|
|
|
240,667
|
|
Investments and other assets
|
|
|
7,060,642
|
|
|
|
(75,614
|
)
|
|
|
66,910
|
|
|
|
(6,747,420
|
)
|
|
|
304,518
|
|
Noncurrent assets of discontinued operations
|
|
|
963,483
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
963,483
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
8,458,880
|
|
|
$
|
4,747,253
|
|
|
$
|
3,055,343
|
|
|
$
|
(6,747,420
|
)
|
|
$
|
9,514,056
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND STOCKHOLDERS EQUITY
|
Current liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current maturities of long-term debt
|
|
$
|
27,350
|
|
|
$
|
60,522
|
|
|
$
|
7,885
|
|
|
$
|
|
|
|
$
|
95,757
|
|
Payables and notes payable to affiliates, net
|
|
|
2,025,605
|
|
|
|
(2,135,941
|
)
|
|
|
110,336
|
|
|
|
|
|
|
|
|
|
Liabilities from coal trading activities
|
|
|
|
|
|
|
126,731
|
|
|
|
|
|
|
|
|
|
|
|
126,731
|
|
Accounts payable and accrued expenses
|
|
|
46,748
|
|
|
|
615,166
|
|
|
|
282,237
|
|
|
|
|
|
|
|
944,151
|
|
Current liabilities of discontinued operations
|
|
|
160,730
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
160,730
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current liabilities
|
|
|
2,260,433
|
|
|
|
(1,333,522
|
)
|
|
|
400,458
|
|
|
|
|
|
|
|
1,327,369
|
|
Long-term debt, less current maturities
|
|
|
3,017,107
|
|
|
|
13
|
|
|
|
164,155
|
|
|
|
|
|
|
|
3,181,275
|
|
Deferred income taxes
|
|
|
29,094
|
|
|
|
192,596
|
|
|
|
191,196
|
|
|
|
|
|
|
|
412,886
|
|
Other noncurrent liabilities
|
|
|
20,411
|
|
|
|
1,322,000
|
|
|
|
101,096
|
|
|
|
|
|
|
|
1,443,507
|
|
Noncurrent liabilities of discontinued operations
|
|
|
777,156
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
777,156
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilities
|
|
|
6,104,201
|
|
|
|
181,087
|
|
|
|
856,905
|
|
|
|
|
|
|
|
7,142,193
|
|
Minority interests, including $16,153 of discontinued operations
at December 31, 2006
|
|
|
16,153
|
|
|
|
|
|
|
|
17,184
|
|
|
|
|
|
|
|
33,337
|
|
Stockholders equity
|
|
|
2,338,526
|
|
|
|
4,566,166
|
|
|
|
2,181,254
|
|
|
|
(6,747,420
|
)
|
|
|
2,338,526
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilities and stockholders equity
|
|
$
|
8,458,880
|
|
|
$
|
4,947,253
|
|
|
$
|
3,055,343
|
|
|
$
|
(6,747,420
|
)
|
|
$
|
9,514,056
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
F-63
PEABODY
ENERGY CORPORATION
SUPPLEMENTAL
CONSOLIDATED STATEMENTS OF CASH FLOWS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2007
|
|
|
|
Parent
|
|
|
Guarantor
|
|
|
Non-Guarantor
|
|
|
|
|
|
|
Company
|
|
|
Subsidiaries
|
|
|
Subsidiaries
|
|
|
Consolidated
|
|
|
|
(Dollars in thousands)
|
|
|
Cash Flows From Operating Activities
Net cash provided by (used in) continuing operations
|
|
$
|
1,410
|
|
|
$
|
719,976
|
|
|
$
|
(274,205
|
)
|
|
$
|
447,181
|
|
Net cash used in discontinued operations
|
|
|
(130,816
|
)
|
|
|
|
|
|
|
|
|
|
|
(130,816
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by (used in) operating activities
|
|
|
(129,406
|
)
|
|
|
719,976
|
|
|
|
(274,205
|
)
|
|
|
316,365
|
|
Cash Flows From Investing Activities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Additions to property, plant, equipment and mine development
|
|
|
(25,017
|
)
|
|
|
(274,899
|
)
|
|
|
(170,518
|
)
|
|
|
(470,434
|
)
|
Federal coal lease expenditures
|
|
|
|
|
|
|
(178,193
|
)
|
|
|
|
|
|
|
(178,193
|
)
|
Proceeds from disposal of assets, net of notes receivable
|
|
|
|
|
|
|
118,281
|
|
|
|
1,305
|
|
|
|
119,586
|
|
Additions to advance mining royalties
|
|
|
|
|
|
|
(8,093
|
)
|
|
|
(30
|
)
|
|
|
(8,123
|
)
|
Investment in joint venture
|
|
|
|
|
|
|
(4,566
|
)
|
|
|
|
|
|
|
(4,566
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash used in continuing operations
|
|
|
(25,017
|
)
|
|
|
(347,470
|
)
|
|
|
(169,243
|
)
|
|
|
(541,730
|
)
|
Net cash used in discontinued operations
|
|
|
(33,602
|
)
|
|
|
|
|
|
|
|
|
|
|
(33,602
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash used in investing activities
|
|
|
(58,619
|
)
|
|
|
(347,470
|
)
|
|
|
(169,243
|
)
|
|
|
(575,332
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash Flows From Financing Activities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Change in revolving line of credit
|
|
|
97,700
|
|
|
|
|
|
|
|
|
|
|
|
97,700
|
|
Payments of long-term debt
|
|
|
(51,053
|
)
|
|
|
(60,940
|
)
|
|
|
(5,824
|
)
|
|
|
(117,817
|
)
|
Dividends paid
|
|
|
(63,658
|
)
|
|
|
|
|
|
|
|
|
|
|
(63,658
|
)
|
Payment of debt issuance costs
|
|
|
|
|
|
|
(774
|
)
|
|
|
|
|
|
|
(774
|
)
|
Excess tax benefit related to stock options exercised
|
|
|
96,743
|
|
|
|
|
|
|
|
|
|
|
|
96,743
|
|
Proceeds from stock options exercised
|
|
|
26,197
|
|
|
|
|
|
|
|
|
|
|
|
26,197
|
|
Proceeds from employee stock purchases
|
|
|
6,377
|
|
|
|
|
|
|
|
|
|
|
|
6,377
|
|
Transactions with affiliates, net
|
|
|
(122,565
|
)
|
|
|
(308,358
|
)
|
|
|
430,923
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by (used in) continuing operations
|
|
|
(10,259
|
)
|
|
|
(370,072
|
)
|
|
|
425,099
|
|
|
|
44,768
|
|
Net cash used in discontinued operations
|
|
|
(67,033
|
)
|
|
|
|
|
|
|
|
|
|
|
(67,033
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by (used in) financing activities
|
|
|
(77,292
|
)
|
|
|
(370,072
|
)
|
|
|
425,099
|
|
|
|
(22,265
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net increase (decrease) in cash and cash equivalents
|
|
|
(265,317
|
)
|
|
|
2,434
|
|
|
|
(18,349
|
)
|
|
|
(281,232
|
)
|
Cash and cash equivalents at beginning of year
|
|
|
272,226
|
|
|
|
3,652
|
|
|
|
50,633
|
|
|
|
326,511
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents at end of year
|
|
$
|
6,909
|
|
|
$
|
6,086
|
|
|
$
|
32,284
|
|
|
$
|
45,279
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
F-64
PEABODY
ENERGY CORPORATION
SUPPLEMENTAL CONSOLIDATED STATEMENTS OF CASH FLOWS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2006
|
|
|
|
Parent
|
|
|
Guarantor
|
|
|
Non-Guarantor
|
|
|
|
|
|
|
Company
|
|
|
Subsidiaries
|
|
|
Subsidiaries
|
|
|
Consolidated
|
|
|
|
(Dollars in thousands)
|
|
|
Cash Flows From Operating Activities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by (used in) continuing operations
|
|
$
|
(166,841
|
)
|
|
$
|
501,741
|
|
|
$
|
256,512
|
|
|
|
591,412
|
|
Net cash used in discontinued operations
|
|
|
(8,150
|
)
|
|
|
|
|
|
|
|
|
|
|
(8,150
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by (used in) operating activities
|
|
|
(174,991
|
)
|
|
|
501,741
|
|
|
|
256,512
|
|
|
|
583,262
|
|
Cash Flows From Investing Activities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Acquisition of Excel Coal, net of cash acquired
|
|
|
|
|
|
|
|
|
|
|
(1,507,775
|
)
|
|
|
(1,507,775
|
)
|
Additions to property, plant, equipment and
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
mine development
|
|
|
|
|
|
|
(271,548
|
)
|
|
|
(125,949
|
)
|
|
|
(397,497
|
)
|
Federal coal lease expenditures
|
|
|
|
|
|
|
(178,193
|
)
|
|
|
|
|
|
|
(178,193
|
)
|
Proceeds from disposal of assets, net of notes receivable
|
|
|
|
|
|
|
28,836
|
|
|
|
575
|
|
|
|
29,411
|
|
Additions to advance mining royalties
|
|
|
|
|
|
|
(4,956
|
)
|
|
|
|
|
|
|
(4,956
|
)
|
Investment in joint venture
|
|
|
|
|
|
|
(2,149
|
)
|
|
|
|
|
|
|
(2,149
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash used in continuing operations
|
|
|
|
|
|
|
(428,010
|
)
|
|
|
(1,633,149
|
)
|
|
|
(2,061,159
|
)
|
Net cash used in discontinued operations
|
|
|
(82,659
|
)
|
|
|
|
|
|
|
|
|
|
|
(82,659
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash used in investing activities
|
|
|
(82,659
|
)
|
|
|
(428,010
|
)
|
|
|
(1,633,149
|
)
|
|
|
(2,143,818
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash Flows From Financing Activities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proceeds from long-term debt
|
|
|
2,603,175
|
|
|
|
|
|
|
|
912
|
|
|
|
2,604,087
|
|
Payments of long-term debt
|
|
|
(876,972
|
)
|
|
|
(10,957
|
)
|
|
|
(158,044
|
)
|
|
|
(1,045,973
|
)
|
Common stock repurchase
|
|
|
(99,774
|
)
|
|
|
|
|
|
|
|
|
|
|
(99,774
|
)
|
Dividends paid
|
|
|
(63,456
|
)
|
|
|
|
|
|
|
|
|
|
|
(63,456
|
)
|
Payment of debt issuance costs
|
|
|
(40,611
|
)
|
|
|
|
|
|
|
|
|
|
|
(40,611
|
)
|
Excess tax benefit related to stock options exercised
|
|
|
33,173
|
|
|
|
|
|
|
|
|
|
|
|
33,173
|
|
Proceeds from stock options exercised
|
|
|
15,617
|
|
|
|
|
|
|
|
|
|
|
|
15,617
|
|
Proceeds from employee stock purchases
|
|
|
4,518
|
|
|
|
|
|
|
|
|
|
|
|
4,518
|
|
Transactions with affiliates, net
|
|
|
(1,516,234
|
)
|
|
|
(61,622
|
)
|
|
|
1,577,856
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by (used in) continuing operations
|
|
|
59,436
|
|
|
|
(72,579
|
)
|
|
|
1,420,724
|
|
|
|
1,407,581
|
|
Net cash used in discontinued operations
|
|
|
(23,792
|
)
|
|
|
|
|
|
|
|
|
|
|
(23,792
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by (used in) financing activities
|
|
|
35,644
|
|
|
|
(72,579
|
)
|
|
|
1,420,724
|
|
|
|
1,383,789
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net increase (decrease) in cash and cash equivalents
|
|
|
(222,006
|
)
|
|
|
1,152
|
|
|
|
44,087
|
|
|
|
(176,767
|
)
|
Cash and cash equivalents at beginning of year
|
|
|
494,232
|
|
|
|
2,500
|
|
|
|
6,546
|
|
|
|
503,278
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents at end of year
|
|
$
|
272,226
|
|
|
$
|
3,652
|
|
|
$
|
50,633
|
|
|
$
|
326,511
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
F-65
PEABODY
ENERGY CORPORATION
SUPPLEMENTAL CONSOLIDATED STATEMENTS OF CASH FLOWS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2005
|
|
|
|
Parent
|
|
|
Guarantor
|
|
|
Non-Guarantor
|
|
|
|
|
|
|
Company
|
|
|
Subsidiaries
|
|
|
Subsidiaries
|
|
|
Consolidated
|
|
|
|
(Dollars in thousands)
|
|
|
Cash Flows From Operating Activities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by (used in) continuing operations
|
|
$
|
(126,861
|
)
|
|
$
|
602,798
|
|
|
$
|
207,867
|
|
|
|
683,804
|
|
Net cash provided by discontinued operations
|
|
|
41,457
|
|
|
|
|
|
|
|
|
|
|
|
41,457
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by (used in) operating activities
|
|
|
(85,404
|
)
|
|
|
602,798
|
|
|
|
207,867
|
|
|
|
725,261
|
|
Cash Flows From Investing Activities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Additions to property, plant, equipment and
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
mine development
|
|
|
|
|
|
|
(363,084
|
)
|
|
|
(87,264
|
)
|
|
|
(450,348
|
)
|
Federal coal lease expenditures
|
|
|
|
|
|
|
(118,364
|
)
|
|
|
|
|
|
|
(118,364
|
)
|
Proceeds from disposal of assets, net of notes receivable
|
|
|
|
|
|
|
60,607
|
|
|
|
2,124
|
|
|
|
62,731
|
|
Additions to advance mining royalties
|
|
|
|
|
|
|
(8,472
|
)
|
|
|
|
|
|
|
(8,472
|
)
|
Investment in joint venture
|
|
|
|
|
|
|
(2,000
|
)
|
|
|
|
|
|
|
(2,000
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash used in continuing operations
|
|
|
|
|
|
|
(431,313
|
)
|
|
|
(85,140
|
)
|
|
|
(516,453
|
)
|
Net cash used in discontinued operations
|
|
|
(67,749
|
)
|
|
|
|
|
|
|
|
|
|
|
(67,749
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash used in investing activities
|
|
|
(67,749
|
)
|
|
|
(431,313
|
)
|
|
|
(85,140
|
)
|
|
|
(584,202
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash Flows From Financing Activities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proceeds from long-term debt
|
|
|
|
|
|
|
11,734
|
|
|
|
|
|
|
|
11,734
|
|
Payments of long-term debt
|
|
|
(6,250
|
)
|
|
|
(12,959
|
)
|
|
|
(989
|
)
|
|
|
(20,198
|
)
|
Dividends paid
|
|
|
(44,535
|
)
|
|
|
|
|
|
|
|
|
|
|
(44,535
|
)
|
Proceeds from stock options exercised
|
|
|
22,573
|
|
|
|
|
|
|
|
|
|
|
|
22,573
|
|
Issuance of notes payable
|
|
|
|
|
|
|
(11,459
|
)
|
|
|
|
|
|
|
(11,459
|
)
|
Proceeds from employee stock purchases
|
|
|
3,009
|
|
|
|
|
|
|
|
|
|
|
|
3,009
|
|
Transactions with affiliates, net
|
|
|
288,063
|
|
|
|
(159,797
|
)
|
|
|
(128,266
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by (used in) continuing operations
|
|
|
262,860
|
|
|
|
(172,481
|
)
|
|
|
(129,255
|
)
|
|
|
(38,876
|
)
|
Net cash provided by discontinued operations
|
|
|
11,459
|
|
|
|
|
|
|
|
|
|
|
|
11,459
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by (used in) financing activities
|
|
|
274,319
|
|
|
|
(172,481
|
)
|
|
|
(129,255
|
)
|
|
|
(27,417
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net increase (decrease) in cash and cash equivalents
|
|
|
121,166
|
|
|
|
(996
|
)
|
|
|
(6,528
|
)
|
|
|
113,642
|
|
Cash and cash equivalents at beginning of year
|
|
|
373,066
|
|
|
|
3,496
|
|
|
|
13,074
|
|
|
|
389,636
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents at end of year
|
|
$
|
494,232
|
|
|
$
|
2,500
|
|
|
$
|
6,546
|
|
|
$
|
503,278
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
F-66
REPORT OF
INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Directors and Stockholders
Peabody Energy Corporation
We have audited the consolidated financial statements of Peabody
Energy Corporation as of December 31, 2007 and 2006, and
for each of the three years in the period ended
December 31, 2007, and have issued our report thereon dated
February 27, 2008. Our audits also included the financial
statement schedule listed in Item 15(a). This schedule is
the responsibility of the Companys management. Our
responsibility is to express an opinion based on our audits. In
our opinion, the financial statement schedule referred to above,
when considered in relation to the basic financial statements
taken as a whole, presents fairly in all material respects the
information set forth therein.
St. Louis, Missouri
February 27, 2008
F-67
PEABODY
ENERGY CORPORATION
SCHEDULE II VALUATION AND QUALIFYING
ACCOUNTS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at
|
|
|
Charged to
|
|
|
|
|
|
|
|
|
Balance
|
|
|
|
Beginning
|
|
|
Costs and
|
|
|
|
|
|
|
|
|
at End
|
|
Description
|
|
of Period
|
|
|
Expenses
|
|
|
Deductions(1)
|
|
|
Other
|
|
|
of Period
|
|
|
|
(Dollars in thousands)
|
|
Year ended December 31, 2007
Reserves deducted from asset accounts:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Advance royalty recoupment reserve
|
|
$
|
11,958
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
1,643
|
(2)
|
|
$
|
13,601
|
|
Reserve for materials and supplies
|
|
|
3,241
|
|
|
|
458
|
|
|
|
(652
|
)
|
|
|
1,252
|
(2)
|
|
|
4,299
|
|
Allowance for doubtful accounts
|
|
|
10,893
|
|
|
|
1,124
|
|
|
|
(129
|
)
|
|
|
|
|
|
|
11,888
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year ended December 31, 2006
Reserves deducted from asset accounts:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Advance royalty recoupment reserve
|
|
$
|
12,414
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
(456
|
)(2)
|
|
$
|
11,958
|
|
Reserve for materials and supplies
|
|
|
3,426
|
|
|
|
229
|
|
|
|
|
|
|
|
(414
|
)(2)
|
|
|
3,241
|
|
Allowance for doubtful accounts
|
|
|
10,761
|
|
|
|
446
|
|
|
|
|
|
|
|
(314
|
)(2)/(4)
|
|
|
10,893
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year ended December 31, 2005
Reserves deducted from asset accounts:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Advance royalty recoupment reserve
|
|
$
|
11,250
|
|
|
$
|
867
|
|
|
$
|
|
|
|
$
|
297
|
(2)
|
|
$
|
12,414
|
|
Reserve for materials and supplies
|
|
|
2,602
|
|
|
|
836
|
|
|
|
(1,531
|
)
|
|
|
1,519
|
(2)
|
|
|
3,426
|
|
Allowance for doubtful accounts
|
|
|
1,361
|
|
|
|
20,305
|
(3)
|
|
|
(5,860
|
)
|
|
|
(5,045
|
)(4)
|
|
|
10,761
|
|
|
|
|
(1) |
|
Reserves utilized, unless otherwise indicated. |
|
(2) |
|
Balances transferred (to) from other accounts or reserves
recorded as part of a property transaction or acquisition. |
|
(3) |
|
Includes $19.5 million for the establishment of a reserve
for the collectibility of certain receivables billed prior to
2005. |
|
(4) |
|
Reflects subsequent recovery of amounts previously reserved. |
F-68
EXHIBIT INDEX
The exhibits below are numbered in accordance with the
Exhibit Table of Item 601 of
Regulation S-K.
|
|
|
|
|
Exhibit
|
|
|
No.
|
|
Description of Exhibit
|
|
|
2
|
.1
|
|
Merger Implementation Agreement, dated as of July 6, 2006,
between the Registrant and Excel Coal Limited (Incorporated by
reference to Exhibit 2.1 of the Registrants Current
Report on
Form 8-K,
filed on July 7, 2006).
|
|
2
|
.2
|
|
Deed of Variation Merger Implementation Agreement,
dated as of September 18, 2006, between the Registrant and
Excel Coal Limited (Incorporated by reference to
Exhibit 2.2 of the Registrants Quarterly Report on
Form 10-Q
for the quarter ended September 30, 2006, filed on
November 7, 2006).
|
|
3
|
.1
|
|
Third Amended and Restated Certificate of Incorporation of the
Registrant, as amended (Incorporated by reference to
Exhibit 3.1 of the Registrants Quarterly Report on
Form 10-Q
for the quarter ended June 30, 2006, filed on
August 7, 2006).
|
|
3
|
.2
|
|
Amended and Restated By-Laws of the Registrant (Incorporated by
reference to Exhibit 3.2 of the Registrants Current
Report on
Form 8-K
filed on August 2, 2007).
|
|
4
|
.1
|
|
Rights Agreement, dated as of July 24, 2002, between the
Registrant and EquiServe Trust Company, N.A., as Rights
Agent (which includes the form of Certificate of Designations of
Series A Junior Preferred Stock of the Registrant as
Exhibit A, the form of Right Certificate as Exhibit B
and the Summary of Rights to Purchase Preferred Shares as
Exhibit C) (Incorporated herein by reference to
Exhibit 4.1 to the Registrants Registration Statement
on
Form 8-A,
filed on July 24, 2002).
|
|
4
|
.2
|
|
Certificate of Designations of Series A Junior
Participating Preferred Stock of the Registrant, filed with the
Secretary of State of the State of Delaware on July 24,
2002 (Incorporated herein by reference to Exhibit 3.1 to
the Registrants Registration Statement on
Form 8-A,
filed on July 24, 2002).
|
|
4
|
.3
|
|
Certificate of Adjustment delivered by the Registrant to
Equiserve Trust Company, NA., as Rights Agent, on
March 29, 2005 (Incorporated by reference to
Exhibit 4.2 to Amendment No. 1 to the
Registrants Registration Statement on
Form 8-A,
filed on March 29, 2005).
|
|
4
|
.4
|
|
Certificate of Adjustment delivered by the Registrant to
American Stock Transfer & Trust Company, as
Rights Agent, on February 22, 2006 (Incorporated by
reference to Exhibit 4.2 to Amendment No. 1 to the
Registrants Registration Statement on
Form 8-A,
filed on February 22, 2006).
|
|
4
|
.5
|
|
Specimen of stock certificate representing the Registrants
common stock, $.01 par value (Incorporated by reference to
Exhibit 4.13 of the Registrants
Form S-1
Registration Statement
No. 333-55412).
|
|
4
|
.6
|
|
67/8% Senior
Notes Due 2013 Indenture, dated as of March 21, 2003,
between the Registrant and US Bank National Association, as
trustee (Incorporated by reference to Exhibit 4.27 of the
Registrants Quarterly Report on
Form 10-Q
for the quarter ended March 31, 2003, filed on May 13,
2003).
|
|
4
|
.7
|
|
67/8% Senior
Notes Due 2013 First Supplemental Indenture, dated as of
May 7, 2003, among the Registrant, the Guaranteeing
Subsidiaries (as defined therein), and US Bank National
Association, as trustee (Incorporated by reference to
Exhibit 4.3 of the Registrants
Form S-4
Registration Statement
No. 333-106208).
|
|
4
|
.8
|
|
67/8% Senior
Notes Due 2013 Second Supplemental Indenture, dated as of
September 30, 2003, among the Registrant, the Guaranteeing
Subsidiaries (as defined therein), and US Bank National
Association, as trustee (Incorporated by reference to
Exhibit 4.198 of the Registrants
Form S-3
Registration Statement
No. 333-109906,
filed on October 22, 2003).
|
|
4
|
.9
|
|
67/8% Senior
Notes Due 2013 Third Supplemental Indenture, dated as of
February 24, 2004, among the Registrant, the Guaranteeing
Subsidiaries (as defined therein), and US Bank National
Association, as trustee (Incorporated by reference to
Exhibit 4.211 of the Registrants
Form S-3/A
Registration Statement
No. 333-109906,
filed on March 4, 2004).
|
|
|
|
|
|
Exhibit
|
|
|
No.
|
|
Description of Exhibit
|
|
|
4
|
.10
|
|
67/8% Senior
Notes Due 2013 Fourth Supplemental Indenture, dated as of
April 22, 2004, among the Registrant, the Guaranteeing
Subsidiaries (as defined therein), and US Bank National
Association, as trustee (Incorporated by reference to
Exhibit 10.57 of the Registrants Quarterly Report on
Form 10-Q
for the quarter ended June 30, 2004, filed on
August 6, 2004).
|
|
4
|
.11
|
|
67/8% Senior
Notes Due 2013 Fifth Supplemental Indenture, dated as of
October 18, 2004, among the Registrant, the Guaranteeing
Subsidiaries (as defined therein), and US Bank National
Association, as trustee (Incorporated by reference to
Exhibit 4.9 of the Registrants Annual Report on
Form 10-K
for the year ended December 31, 2004, filed on
March 16, 2005).
|
|
4
|
.12
|
|
67/8% Senior
Notes Due 2013 Sixth Supplemental Indenture, dated as of
January 20, 2005, among the Registrant, the Guaranteeing
Subsidiaries (as defined therein), and US Bank National
Association, as trustee (Incorporated by reference to
Exhibit 4.1 of the Registrants Quarterly Report on
Form 10-Q
for the quarter ended March 31, 2005, filed on May 6,
2005).
|
|
4
|
.13
|
|
67/8% Senior
Notes Due 2013 Seventh Supplemental Indenture, dated as of
September 30, 2005, among the Registrant, the Guaranteeing
Subsidiaries (as defined therein), and US Bank National
Association, as trustee (as defined therein), and US Bank
National Association, as trustee (Incorporated by reference to
Exhibit 4.1 of the Registrants Quarterly Report on
Form 10-Q
for the quarter ended September 30, 2005, filed on
November 8, 2005).
|
|
4
|
.14
|
|
67/8% Senior
Notes Due 2013 Eighth Supplemental Indenture, dated as of
January 20, 2006, among the Registrant, the Guaranteeing
Subsidiaries (as defined therein), and US Bank National
Association, as trustee (Incorporated by reference to
Exhibit 4.14 of the Registrants Annual Report on
Form 10-K
for the year ended December 31, 2005, filed on
March 6, 2006).
|
|
4
|
.15
|
|
67/8% Senior
Notes Due 2013 Ninth Supplemental Indenture, dated as of
June 13, 2006, among the Registrant, the Guaranteeing
Subsidiaries (as defined therein), and US Bank National
Association, as trustee (Incorporated by reference to
Exhibit 4.1 of the Registrants Quarterly Report on
Form 10-Q
for the quarter ended June 30, 2006, filed on
August 7, 2006).
|
|
4
|
.16
|
|
67/8% Senior
Notes Due 2013 Tenth Supplemental Indenture, dated as of
June 30, 2006, among the Registrant, the Guaranteeing
Subsidiaries (as defined therein), and US Bank National
Association, as trustee (Incorporated by reference to
Exhibit 4.2 of the Registrants Quarterly Report on
Form 10-Q
for the quarter ended June 30, 2006, filed on
August 7, 2006).
|
|
4
|
.17
|
|
67/8% Senior
Notes Due 2013 Eleventh Supplemental Indenture, dated as of
September 29, 2006, among the Registrant, the Guaranteeing
Subsidiaries (as defined therein), and US Bank National
Association, as trustee (Incorporated by reference to
Exhibit 4.2 of the Registrants Quarterly Report on
Form 10-Q
for the quarter ended September 30, 2006, filed on
November 7, 2006).
|
|
4
|
.18
|
|
67/8% Senior
Notes Due 2013 Twelfth Supplemental Indenture, dated as of
November 10, 2006, among the Registrant, the Guaranteeing
Subsidiaries (as defined therein), and US Bank National
Association, as trustee. (Incorporated by reference to
Exhibit 4.18 of the Registrants Annual Report on
Form 10-K
for the year ended December 31, 2006, filed on
February 28, 2007).
|
|
4
|
.19
|
|
67/8% Senior
Notes Due 2013 Thirteenth Supplemental Indenture, dated as of
January 31, 2007, among the Registrant, the Guaranteeing
Subsidiaries (as defined therein), and US Bank National
Association, as trustee (Incorporated by reference to
Exhibit 4.19 of the Registrants Annual Report on
Form 10-K
for the year ended December 31, 2006, filed on
February 28, 2007)
|
|
4
|
.20
|
|
67/8% Senior
Notes Due 2013 Fourteenth Supplemental Indenture, dated as of
June 14, 2007, among the Registrant, the Guaranteeing
Subsidiaries (as defined therein), and US Bank National
Association, as trustee (Incorporated by reference to
Exhibit 4.1 of the Registrants Quarterly Report on
Form 10-Q
for the quarter ended June 30, 2007).
|
|
4
|
.21
|
|
67/8% Senior
Notes Due 2013 Fifteenth Supplemental Indenture, dated as of
November 14, 2007, among the Registrant, the Guaranteeing
Subsidiaries (as defined therein), and US Bank National
Association, as trustee.
|
|
4
|
.22
|
|
57/8% Senior
Notes Due 2016 Indenture, dated as of March 19, 2004,
between the Registrant and US Bank National Association, as
trustee (Incorporated by reference to Exhibit 4.12 of the
Registrants Quarterly Report on
Form 10-Q
for the quarter ended March 31, 2004, filed on May 10,
2004).
|
|
|
|
|
|
Exhibit
|
|
|
No.
|
|
Description of Exhibit
|
|
|
4
|
.23
|
|
57/8% Senior
Notes Due 2016 First Supplemental Indenture, dated as of
March 23, 2004, between the Registrant and US Bank National
Association, as trustee (Incorporated by reference to
Exhibit 4.1 of the Registrants Current Report on
Form 8-K
dated March 23, 2004).
|
|
4
|
.24
|
|
57/8% Senior
Notes Due 2016 Second Supplemental Indenture, dated as of
April 22, 2004, among the Registrant, the Guaranteeing
Subsidiaries (as defined therein), and US Bank National
Association, as trustee (Incorporated by reference to
Exhibit 10.58 of the Registrants Quarterly Report on
Form 10-Q
for the quarter ended June 30, 2004, filed on
August 6, 2004).
|
|
4
|
.25
|
|
57/8% Senior
Notes Due 2016 Third Supplemental Indenture, dated as of
October 18, 2004, among the Registrant, the Guaranteeing
Subsidiaries (as defined therein), and US Bank National
Association, as trustee (Incorporated by reference to
Exhibit 4.13 of the Registrants Annual Report on
Form 10-K
for the year ended December 31, 2004, filed on
March 16, 2005).
|
|
4
|
.26
|
|
57/8% Senior
Notes Due 2016 Fourth Supplemental Indenture, dated as of
January 20, 2005, among the Registrant, the Guaranteeing
Subsidiaries (as defined therein), and US Bank National
Association, as trustee (Incorporated by reference to
Exhibit 4.2 of the Registrants Quarterly Report on
Form 10-Q
for the quarter ended March 31, 2005, filed on May 6,
2005).
|
|
4
|
.27
|
|
57/8% Senior
Notes Due 2016 Fifth Supplemental Indenture, dated as of
September 30, 2005, among the Registrant, the Guaranteeing
Subsidiaries (as defined therein), and US Bank National
Association, as trustee (Incorporated by reference to
Exhibit 4.2 of the Registrants Quarterly Report on
Form 10-Q
for the quarter ended September 30, 2005, filed on
November 8, 2005).
|
|
4
|
.28
|
|
57/8% Senior
Notes Due 2016 Sixth Supplemental Indenture, dated as of
January 20, 2006, among the Registrant, the Guaranteeing
Subsidiaries (as defined therein), and US Bank National
Association, as trustee (Incorporated by reference to
Exhibit 4.21 of the Registrants Annual Report on
Form 10-K
for the year ended December 31, 2005, filed on
March 6, 2006).
|
|
4
|
.29
|
|
57/8% Senior
Notes Due 2016 Seventh Supplemental Indenture, dated as of
June 13, 2006, among the Registrant, the Guaranteeing
Subsidiaries (as defined therein), and US Bank National
Association, as trustee (Incorporated by reference to
Exhibit 4.3 of the Registrants Quarterly Report on
Form 10-Q
for the quarter ended June 30, 2006, filed on
August 7, 2006).
|
|
4
|
.30
|
|
57/8% Senior
Notes Due 2016 Eighth Supplemental Indenture, dated as of
June 30, 2006, among the Registrant, the Guaranteeing
Subsidiaries (as defined therein), and US Bank National
Association, as trustee (Incorporated by reference to
Exhibit 4.4 of the Registrants Quarterly Report on
Form 10-Q
for the quarter ended June 30, 2006, filed on
August 7, 2006).
|
|
4
|
.31
|
|
57/8% Senior
Notes Due 2016 Ninth Supplemental Indenture, dated as of
September 29, 2006, among the Registrant, the Guaranteeing
Subsidiaries (as defined therein), and US Bank National
Association, as trustee (Incorporated by reference to
Exhibit 4.1 of the Registrants Quarterly Report on
Form 10-Q
for the quarter ended September 30, 2006, filed on
November 7, 2006).
|
|
4
|
.32
|
|
57/8% Senior
Notes Due 2016 Twelfth Supplemental Indenture, dated as of
November 10, 2006, among the Registrant, the Guaranteeing
Subsidiaries (as defined therein), and US Bank National
Association, as trustee. (Incorporated by reference to
Exhibit 4.30 of the Registrants Annual Report on
Form 10-K
for the year ended December 31, 2006, filed on
February 28, 2007).
|
|
4
|
.33
|
|
57/8% Senior
Notes Due 2016 Fifteenth Supplemental Indenture, dated as of
January 31, 2007, among the Registrant, the Guaranteeing
Subsidiaries (as defined therein), and US Bank National
Association, as trustee. (Incorporated by reference to
Exhibit 4.31 of the Registrants Annual Report on
Form 10-K
for the year ended December 31, 2006, filed on
February 28, 2007).
|
|
4
|
.34
|
|
57/8% Senior
Notes Due 2016 Eighteenth Supplemental Indenture, dated as of
June 14, 2007, among the Registrant, the Guaranteeing
Subsidiaries (as defined therein), and US Bank National
Association, as trustee (Incorporated by reference to
Exhibit 4.2 of the Registrants Quarterly Report on
Form 10-Q
for the quarter ended June 30, 2007).
|
|
4
|
.35
|
|
57/8% Senior
Notes Due 2016 Twenty-First Supplemental Indenture, dated as of
November 14, 2007, among the Registrant, the Guaranteeing
Subsidiaries (as defined therein), and US Bank National
Association, as trustee.
|
|
4
|
.36
|
|
73/8% Senior
Notes due 2016 Tenth Supplemental Indenture, dated as of
October 12, 2006 among the Registrant, the Guaranteeing
Subsidiaries (as defined therein), and U.S. Bank National
Association, as trustee (Incorporated by reference to
Exhibit 4.1 of the Registrants Current Report on
Form 8-K
dated October 13, 2006).
|
|
|
|
|
|
Exhibit
|
|
|
No.
|
|
Description of Exhibit
|
|
|
4
|
.37
|
|
73/8% Senior
Notes due 2016 Thirteenth Supplemental Indenture, dated as of
November 10, 2006 among the Registrant, the Guaranteeing
Subsidiaries (as defined therein), and U.S. Bank National
Association, as trustee (Incorporated by reference to
Exhibit 4.33 of the Registrants Annual Report on
Form 10-K
for the year ended December 31, 2006, filed on
February 28, 2007).
|
|
4
|
.38
|
|
73/8% Senior
Notes due 2016 Sixteenth Supplemental Indenture, dated as of
January 31, 2007 among the Registrant, the Guaranteeing
Subsidiaries (as defined therein), and U.S. Bank National
Association, as trustee (Incorporated by reference to
Exhibit 4.34 of the Registrants Annual Report on
Form 10-K
for the year ended December 31, 2006, filed on
February 28, 2007).
|
|
4
|
.39
|
|
73/8% Senior
Notes due 2016 Nineteenth Supplemental Indenture, dated as of
June 14, 2007 among the Registrant, the Guaranteeing
Subsidiaries (as defined therein), and U.S. Bank National
Association, as trustee (Incorporated by reference to
Exhibit 4.3 of the Registrants Quarterly Report on
Form 10-Q
for the quarter ended June 30, 2007).
|
|
4
|
.40
|
|
73/8% Senior
Notes due 2016 Twenty-Second Supplemental Indenture, dated as of
November 14, 2007 among the Registrant, the Guaranteeing
Subsidiaries (as defined therein), and U.S. Bank National
Association, as trustee.
|
|
4
|
.41
|
|
77/8% Senior
Notes due 2026 Eleventh Supplemental Indenture, dated as of
October 12, 2006, among the Registrant, the Guaranteeing
Subsidiaries (as defined therein), and U.S. Bank National
Association, as trustee (Incorporated by reference to
Exhibit 4.2 of the Registrants Current Report on
Form 8-K
dated October 13, 2006).
|
|
4
|
.42
|
|
77/8% Senior
Notes due 2026 Fourteenth Supplemental Indenture, dated as of
November 10, 2006, among the Registrant, the Guaranteeing
Subsidiaries (as defined therein), and U.S. Bank National
Association, as trustee (Incorporated by reference to
Exhibit 4.36 of the Registrants Annual Report on
Form 10-K
for the year ended December 31, 2006, filed on
February 28, 2007).
|
|
4
|
.43
|
|
77/8% Senior
Notes due 2026 Seventeenth Supplemental Indenture, dated as of
January 31, 2007, among the Registrant, the Guaranteeing
Subsidiaries (as defined therein), and U.S. Bank National
Association, as trustee (Incorporated by reference to
Exhibit 4.37 of the Registrants Annual Report on
Form 10-K
for the year ended December 31, 2006, filed on
February 28, 2007).
|
|
4
|
.44
|
|
77/8% Senior
Notes due 2026 Twentieth Supplemental Indenture, dated as of
June 14, 2007, among the Registrant, the Guaranteeing
Subsidiaries (as defined therein), and U.S. Bank National
Association, as trustee (Incorporated by reference to
Exhibit 4.4 of the Registrants Quarterly Report on
Form 10-Q
for the quarter ended June 30, 2007).
|
|
4
|
.45
|
|
77/8% Senior
Notes due 2026 Twenty-Third Supplemental Indenture, dated as of
November 14, 2007, among the Registrant, the Guaranteeing
Subsidiaries (as defined therein), and U.S. Bank National
Association, as trustee.
|
|
4
|
.46
|
|
Subordinated Indenture, dated as of December 20, 2006,
between the Registrant and U.S. Bank National Association,
as trustee (Incorporated by reference to Exhibit 4.1 of the
Registrants Current Report on
Form 8-K,
filed December 20, 2006).
|
|
4
|
.47
|
|
4.75% Convertible Junior Subordinated Debentures Due 2066
First Supplemental Indenture, dated as December 20, 2006,
among the Registrant and U.S. Bank National Association, as
trustee (Incorporated by reference to Exhibit 4.2 of the
Registrants Current Report on
Form 8-K,
filed December 20, 2006).
|
|
4
|
.48
|
|
Capital Replacement Covenant dated December 19, 2006
(Incorporated by reference to Exhibit 99.1 of the
Registrants Current Report on
Form 8-K,
filed December 20, 2006).
|
|
4
|
.49
|
|
Notice of Adjustment of Conversion Rate of
4.75% Convertible Junior Subordinated Debentures Due 2066,
dated November 26, 2007.
|
|
10
|
.1
|
|
Third Amended and Restated Credit Agreement, dated as of
September 15, 2006, among the Registrant, Bank of America,
N.A., as administrative agent, Citibank, N.A., as syndication
agent, and the lenders named therein (Incorporated by reference
to Exhibit 10.1 of the Registrants Current Report on
Form 8-K,
filed September 18, 2006).
|
|
10
|
.2
|
|
Amendment No. 1 to Third Amended and Restated Credit
Agreement, dated as of September 27, 2006, among the
Registrant, the Lenders named therein, and Bank of America,
N.A., as Administrative Agent (Incorporated by reference to
Exhibit 10.3 of the Registrants Quarterly Report on
Form 10-Q
for the quarter ended September 30, 2006, filed on
November 7, 2006).
|
|
|
|
|
|
Exhibit
|
|
|
No.
|
|
Description of Exhibit
|
|
|
10
|
.3
|
|
Amended and Restated Guarantee, dated as of September 15,
2006, among the Registrant and the Guarantors (as defined
therein) in favor of Bank of America, N.A., as administrative
agent under the Third Amended and Restated Credit Agreement
dated as of September 15, 2006 (Incorporated by reference
to Exhibit 10.2 of the Registrants Current Report on
Form 8-K,
filed September 18, 2006).
|
|
10
|
.4
|
|
Federal Coal Lease WYW0321779: North Antelope/Rochelle Mine
(Incorporated by reference to Exhibit 10.3 of the
Registrants
Form S-4
Registration Statement
No. 333-59073).
|
|
10
|
.5
|
|
Federal Coal Lease WYW119554: North Antelope/Rochelle Mine
(Incorporated by reference to Exhibit 10.4 of the
Registrants
Form S-4
Registration Statement
No. 333-59073).
|
|
10
|
.6
|
|
Federal Coal Lease WYW5036: Rawhide Mine (Incorporated by
reference to Exhibit 10.5 of the Registrants
Form S-4
Registration Statement
No. 333-59073).
|
|
10
|
.7
|
|
Federal Coal Lease WYW3397: Caballo Mine (Incorporated by
reference to Exhibit 10.6 of the Registrants
Form S-4
Registration Statement
No. 333-59073).
|
|
10
|
.8
|
|
Federal Coal Lease WYW83394: Caballo Mine (Incorporated by
reference to Exhibit 10.7 of the Registrants
Form S-4
Registration Statement
No. 333-59073).
|
|
10
|
.9
|
|
Federal Coal Lease WYW136142 (Incorporated by reference to
Exhibit 10.8 of Amendment No. 1 of the
Registrants
Form S-4
Registration Statement
No. 333-59073).
|
|
10
|
.10
|
|
Royalty Prepayment Agreement by and among Peabody Natural
Resources Company, Gallo Finance Company and Chaco Energy
Company, dated September 30, 1998 (Incorporated by
reference to Exhibit 10.9 of the Registrants
Quarterly Report on
Form 10-Q
for the second quarter ended September 30, 1998, filed on
November 13, 1998).
|
|
10
|
.11
|
|
Federal Coal Lease WYW154001: North Antelope Rochelle South
(Incorporated by reference to Exhibit 10.68 of the
Registrants Quarterly Report on
Form 10-Q
for the third quarter ended September 30, 2004, filed on
December 10, 2004).
|
|
10
|
.12
|
|
Federal Coal Lease WYW150210: North Antelope Rochelle Mine
(Incorporated by reference to Exhibit 10.8 of the
Registrants Quarterly Report on
Form 10-Q
for the quarter ended March 31, 2005, filed on May 6,
2005).
|
|
10
|
.13
|
|
Federal Coal Lease WYW151134 effective May 1, 2005: West
Roundup (Incorporated by reference to Exhibit 10.1 of the
Registrants Quarterly Report on
Form 10-Q
for the quarter ended June 30, 2005, filed on
August 8, 2005).
|
|
10
|
.14
|
|
Separation Agreement, Plan of Reorganization and Distribution,
dated October 22, 2007, between the Registrant and Patriot
Coal Corporation (Incorporated by reference to Exhibit 10.1
of the Registrants Current Report on
Form 8-K
filed October 25, 2007).
|
|
10
|
.15
|
|
Tax Separation Agreement, dated October 22, 2007, between
the Registrant and Patriot Coal Corporation (Incorporated by
reference to Exhibit 10.2 of the Registrants Current
Report on
Form 8-K
filed October 25, 2007).
|
|
10
|
.16
|
|
Coal Act Liabilities Assumption Agreement, dated
October 22, 2007, among Patriot Coal Corporation, Peabody
Holding Company, LLC and the Registrant (Incorporated by
reference to Exhibit 10.3 of the Registrants Current
Report on
Form 8-K
filed October 25, 2007).
|
|
10
|
.17
|
|
NBCWA Liabilities Assumption Agreement, dated October 22,
2007, among Patriot Coal Corporation, Peabody Holding Company,
LLC, Peabody Coal Company, LLC and the Registrant (Incorporated
by reference to Exhibit 10.4 of the Registrants
Current Report on
Form 8-K
filed October 25, 2007).
|
|
10
|
.18
|
|
Salaried Employee Liabilities Assumption Agreement, dated
October 22, 2007, among Patriot Coal Corporation, Peabody
Holding Company, LLC, Peabody Coal Company, LLC and the
Registrant (Incorporated by reference to Exhibit 10.5 of
the Registrants Current Report on
Form 8-K
filed October 25, 2007).
|
|
10
|
.19
|
|
Coal Supply Agreement, dated October 22, 2007, between
Patriot Coal Sales LLC and COALSALES II, LLC (Incorporated by
reference to Exhibit 10.6 of the Registrants Current
Report on
Form 8-K
filed October 25, 2007).
|
|
10
|
.20*
|
|
1998 Stock Purchase and Option Plan for Key Employees of the
Registrant (Incorporated by reference to Exhibit 4.9 of the
Registrants
Form S-8
Registration Statement
No. 333-105456,
filed on May 21, 2003).
|
|
|
|
|
|
Exhibit
|
|
|
No.
|
|
Description of Exhibit
|
|
|
10
|
.21*
|
|
Amendment to the 1998 Stock Purchase and Option Plan for Key
Employees of the Registrant (Incorporated by reference to
Exhibit 10.4 of the Registrants Current Report on
Form 8-K
filed October 17, 2007).
|
|
10
|
.22*
|
|
Amendment No. 2 to the 1998 Stock Purchase and Option Plan
for Key Employees of the Registrant (Incorporated by reference
to Exhibit 10.2 of the Registrants Current Report on
Form 8-K
filed December 11, 2007).
|
|
10
|
.23*
|
|
Form of Non-Qualified Stock Option Agreement under the
Registrants 1998 Stock Purchase and Option Plan for Key
Employees (Incorporated by reference to Exhibit 10.15 of
the Registrants Annual Report on
Form 10-K
for the year ended December 31, 2003, filed on
March 4, 2004).
|
|
10
|
.24*
|
|
Form of Amendment to Non-Qualified Stock Option Agreement under
the Registrants 1998 Stock Purchase and Option Plan for
Key Employees (Incorporated by reference to Exhibit 10.16
of the Registrants Annual Report on
Form 10-K
for the year ended December 31, 2003, filed on
March 4, 2004).
|
|
10
|
.25*
|
|
Form of Amendment, dated as of June 15, 2004, to
Non-Qualified Stock Option Agreement under the Registrants
1998 Stock Purchase and Option Plan for Key Employees
(Incorporated by reference to Exhibit 10.65 of the
Registrants Quarterly Report on
Form 10-Q
for the quarter ended June 30, 2004, filed on
August 6, 2004).
|
|
10
|
.26*
|
|
Form of Incentive Stock Option Agreement under the
Registrants 1998 Stock Purchase and Option Plan for Key
Employees (Incorporated by reference to Exhibit 10.17 of
the Registrants Annual Report on
Form 10-K
for the year ended December 31, 2003, filed on
March 4, 2004).
|
|
10
|
.27*
|
|
Long-Term Equity Incentive Plan of the Registrant (Incorporated
by reference to Exhibit 99.2 of the Registrants
Form S-8
Registration Statement
No. 333-61406,
filed on May 22, 2001).
|
|
10
|
.28*
|
|
Amendment to the Registrants 2001 Long-Term Equity
Incentive Plan (Incorporated by reference to Exhibit 10.3
of the Registrants Current Report on
Form 8-K
filed October 17, 2007).
|
|
10
|
.29*
|
|
The Registrants 2004 Long-Term Equity Incentive Plan
(Incorporated by reference to Annex A to the
Registrants Proxy Statement for the 2004 Annual Meeting of
Stockholders, filed on April 2, 2004).
|
|
10
|
.30*
|
|
Amendment No. 1 to the Registrants 2004 Long Term
Equity Incentive Plan (Incorporated by reference to
Exhibit 10.67 of the Registrants Quarterly Report on
Form 10-Q
for the third quarter ended September 30, 2004, filed on
December 10, 2004).
|
|
10
|
.31*
|
|
Amendment No. 2 to the Registrants 2004 Long-Term
Equity Incentive Plan (Incorporated by reference to
Exhibit 10.1 of the Registrants Current Report on
Form 8-K
filed October 17, 2007).
|
|
10
|
.32*
|
|
Amendment No. 3 to the Registrants 2004 Long-Term
Equity Incentive Plan (Incorporated by reference to
Exhibit 10.2 of the Registrants Current Report on
Form 8-K
filed October 17, 2007).
|
|
10
|
.33*
|
|
Amendment No. 4 to the Registrants 2004 Long-Term
Equity Incentive Plan (Incorporated by reference to
Exhibit 10.1 of the Registrants Current Report on
Form 8-K
filed December 11, 2007).
|
|
10
|
.34*
|
|
Form of Non-Qualified Stock Option Agreement under the
Registrants 2004 Long-Term Equity Incentive Plan
(Incorporated by reference to Exhibit 10.1 to the
Registrants Current Report on
Form 8-K,
filed on January 7, 2005).
|
|
10
|
.35*
|
|
Form of Performance Units Agreement under the Registrants
2004 Long-Term Equity Incentive Plan (Incorporated by reference
to Exhibit 10.2 of the Registrants Current Report on
Form 8-K,
dated January 3, 2005).
|
|
10
|
.36*
|
|
Form of Performance Units Agreement under the Registrants
2004 Long-Term Equity Incentive Plan.
|
|
10
|
.37*
|
|
Equity Incentive Plan for Non-Employee Directors of the
Registrant (Incorporated by reference to Exhibit 99.3 of
the Registrants
Form S-8
Registration Statement
No. 333-61406,
filed on May 22, 2001).
|
|
|
|
|
|
Exhibit
|
|
|
No.
|
|
Description of Exhibit
|
|
|
10
|
.38*
|
|
Form of Non-Qualified Stock Option Agreement for Outside
Directors under the Registrants Long-Term Equity Incentive
Plan (Incorporated by reference to Exhibit 10.1 to the
Registrants Current Report on
Form 8-K,
filed on December 14, 2005).
|
|
10
|
.39*
|
|
Form of Non-Qualified Stock Option Agreement under the
Registrants Long-Term Equity Incentive Plan (Incorporated
by reference to Exhibit 10.18 of the Registrants
Annual Report on
Form 10-K
for the year ended December 31, 2003, filed on
March 4, 2004).
|
|
10
|
.40*
|
|
Form of Performance Unit Award Agreement under the
Registrants Long-Term Equity Incentive Plan (Incorporated
by reference to Exhibit 10.19 of the Registrants
Annual Report on
Form 10-K
for the year ended December 31, 2003, filed on
March 4, 2004).
|
|
10
|
.41*
|
|
Form of Non-Qualified Stock Option Agreement under the
Registrants Equity Incentive Plan for Non-Employee
Directors (Incorporated by reference to Exhibit 10.20 of
the Registrants Annual Report on
Form 10-K
for the year ended December 31, 2003, filed on
March 4, 2004).
|
|
10
|
.42*
|
|
Form of Restricted Stock Agreement under the Registrants
Equity Incentive Plan for Non-Employee Directors (Incorporated
by reference to Exhibit 10.21 of the Registrants
Annual Report on
Form 10-K
for the year ended December 31, 2003, filed on
March 4, 2004).
|
|
10
|
.43*
|
|
Form of Restricted Stock Award Agreement for Outside Directors
under the Registrants Long-Term Equity Incentive Plan
(Incorporated by reference to Exhibit 10.2 to the
Registrants Current Report on
Form 8-K,
filed on December 14, 2005).
|
|
10
|
.44*
|
|
Employee Stock Purchase Plan of the Registrant (Incorporated by
reference to Exhibit 99.1 of the Registrants
Form S-8
Registration Statement
No. 333-61406,
filed on May 22, 2001).
|
|
10
|
.45*
|
|
First Amendment to Registrants Employee Stock Purchase
Plan, dated as of February 7, 2002 (Incorporated by
reference to Exhibit 10.23 of the Registrants Annual
Report on
Form 10-K
for the year ended December 31, 2003, filed on
March 4, 2004).
|
|
10
|
.46*
|
|
Second Amendment to Registrants Employee Stock Purchase
Plan (Incorporated by reference to Exhibit 10.5 of the
Registrants Current Report on
Form 8-K
filed October 17, 2007).
|
|
10
|
.47*
|
|
Third Amendment to Registrants Employee Stock Purchase
Plan.
|
|
10
|
.48*
|
|
Letter Agreement, dated as of March 1, 2005, by and between
the Registrant and Gregory H. Boyce (Incorporated by reference
to Exhibit 10.1 of the Registrants Current Report on
Form 8-K,
filed March 4, 2005).
|
|
10
|
.49*
|
|
Amended and Restated Employment Agreement, dated as of
January 1, 2006, by and between the Registrant and Gregory
H. Boyce (Incorporated by reference to Exhibit 10.3 of the
Registrants Current Report on
Form 8-K,
filed March 4, 2005).
|
|
10
|
.50*
|
|
Employment Agreement between Richard A. Navarre and the
Registrant dated May 19, 1998 (Incorporated by reference to
Exhibit 10.13 of the Registrants
Form S-1
Registration Statement
No. 333-55412).
|
|
10
|
.51*
|
|
First Amendment to the Employment Agreement between Richard A.
Navarre and the Registrant dated as of May 10, 2001
(Incorporated by reference to Exhibit 10.23 of the
Registrants
Form S-1
Registration Statement
No. 333-55412).
|
|
10
|
.52*
|
|
Second Amendment to the Employment Agreement between Richard A.
Navarre and the Registrant dated as of June 15, 2004
(Incorporated by reference to Exhibit 10.61 of the
Registrants Quarterly Report on
Form 10-Q
for the quarter ended June 30, 2004, filed on
August 6, 2004).
|
|
10
|
.53*
|
|
Employment Agreement between Roger B. Walcott, Jr. and the
Registrant dated May 19, 1998 (Incorporated by reference to
Exhibit 10.14 of the Registrants
Form S-1
Registration Statement
No. 333-55412).
|
|
10
|
.54*
|
|
First Amendment to the Employment Agreement between Roger B.
Walcott, Jr. and the Registrant dated as of May 10, 2001
(Incorporated by reference to Exhibit 10.24 of the
Registrants
Form S-1
Registration Statement
No. 333-55412).
|
|
10
|
.55*
|
|
Second Amendment to the Employment Agreement between Roger B.
Walcott and the Registrant dated as of June 15, 2004
(Incorporated by reference to Exhibit 10.62 of the
Registrants Quarterly Report on
Form 10-Q
for the quarter ended June 30, 2004, filed on
August 6, 2004).
|
|
|
|
|
|
Exhibit
|
|
|
No.
|
|
Description of Exhibit
|
|
|
10
|
.56*
|
|
Letter Agreement, dated as of December 22, 2006, by and
between the Registrant and Eric Ford (Incorporated by reference
to Exhibit 10.1 of the Registrants Current Report on
Form 8-K,
filed December 29, 2006).
|
|
10
|
.57*
|
|
Employment Agreement, dated as of December 22, 2006, by and
between the Company and Eric Ford (Incorporated by reference to
Exhibit 10.2 of the Registrants Current Report on
Form 8-K,
filed December 29, 2006).
|
|
10
|
.57A*
|
|
Form of Restricted Stock Agreement Exhibit A
(Incorporated by reference to Exhibit 10.3 of the
Registrants Current Report on
Form 8-K,
filed December 29, 2006).
|
|
10
|
.57B*
|
|
Form of Restricted Stock Agreement Exhibit B
(Incorporated by reference to Exhibit 10.4 of the
Registrants Current Report on
Form 8-K,
filed December 29, 2006).
|
|
10
|
.58*
|
|
Employment Agreement between Sharon D. Fiehler and the
Registrant dated May 19, 1998.
|
|
10
|
.59*
|
|
First Amendment to the Employment Agreement between Sharon D.
Fiehler and the Registrant dated as of May 10, 2001.
|
|
10
|
.60*
|
|
Second Amendment to the Employment Agreement between Sharon D.
Fiehler and the Registrant dated as of June 15, 2004.
|
|
10
|
.61*
|
|
Management Annual Incentive Compensation Plan.
|
|
10
|
.62*
|
|
The Registrants Deferred Compensation Plan (Incorporated
by reference to Exhibit 10.30 of the Registrants
Quarterly Report on
Form 10-Q
for the quarter ended September 30, 2001, filed on
October 30, 2001).
|
|
10
|
.63*
|
|
First Amendment to the Registrants Deferred Compensation
Plan (Incorporated by reference to Exhibit 10.49 of the
Registrants Annual Report on
Form 10-K
for the year ended December 31, 2004, filed on
March 16, 2005).
|
|
10
|
.64*
|
|
Indemnification Agreement, dated as of December 5, 2002, by
and between Registrant and William E. James (Incorporated by
reference to Exhibit 10.34 of the Registrants Annual
Report on
Form 10-K
for the year ended December 31, 2002, filed on
March 7, 2003).
|
|
10
|
.65*
|
|
Indemnification Agreement, dated as of December 5, 2002, by
and between Registrant and Henry E. Lentz (Incorporated by
reference to Exhibit 10.35 of the Registrants Annual
Report on
Form 10-K
for the year ended December 31, 2002, filed on
March 7, 2003).
|
|
10
|
.66*
|
|
Indemnification Agreement, dated as of December 5, 2002, by
and between Registrant and William C. Rusnack (Incorporated by
reference to Exhibit 10.36 of the Registrants Annual
Report on
Form 10-K
for the year ended December 31, 2002, filed on
March 7, 2003).
|
|
10
|
.67*
|
|
Indemnification Agreement, dated as of December 5, 2002, by
and between Registrant and Dr. James R. Schlesinger
(Incorporated by reference to Exhibit 10.37 of the
Registrants Annual Report on
Form 10-K
for the year ended December 31, 2002, filed on
March 7, 2003).
|
|
10
|
.68*
|
|
Indemnification Agreement, dated as of December 5, 2002, by
and between Registrant and Dr. Blanche M. Touhill
(Incorporated by reference to Exhibit 10.38 of the
Registrants Annual Report on
Form 10-K
for the year ended December 31, 2002, filed on
March 7, 2003).
|
|
10
|
.69*
|
|
Indemnification Agreement, dated as of December 5, 2002, by
and between Registrant and Alan H. Washkowitz (Incorporated by
reference to Exhibit 10.39 of the Registrants Annual
Report on
Form 10-K
for the year ended December 31, 2002, filed on
March 7, 2003).
|
|
10
|
.70*
|
|
Indemnification Agreement, dated as of December 5, 2002, by
and between Registrant and Richard A. Navarre (Incorporated by
reference to Exhibit 10.40 of the Registrants Annual
Report on
Form 10-K
for the year ended December 31, 2002, filed on
March 7, 2003).
|
|
10
|
.71*
|
|
Indemnification Agreement, dated as of January 16, 2003, by
and between Registrant and Robert B. Karn III (Incorporated
by reference to Exhibit 10.41 of the Registrants
Annual Report on
Form 10-K
for the year ended December 31, 2002, filed on
March 7, 2003).
|
|
10
|
.72*
|
|
Indemnification Agreement, dated as of January 16, 2003, by
and between Registrant and Sandra A. Van Trease (Incorporated by
reference to Exhibit 10.42 of the Registrants Annual
Report on
Form 10-K
for the year ended December 31, 2002, filed on
March 7, 2003).
|
|
10
|
.73*
|
|
Indemnification Agreement, dated as of March 22, 2004, by
and between Registrant and Henry Givens, Jr. (Incorporated by
reference to Exhibit 10.52 of the Registrants
Quarterly Report on
Form 10-Q
for the quarter Ended March 31, 2004, filed on May 10,
2004).
|
|
|
|
|
|
Exhibit
|
|
|
No.
|
|
Description of Exhibit
|
|
|
10
|
.74*
|
|
Indemnification Agreement, dated as of March 22, 2004, by
and between Registrant and William A. Coley (Incorporated by
reference to Exhibit 10.53 of the Registrants
Quarterly Report on
Form 10-Q
for the quarter Ended March 31, 2004, filed on May 10,
2004).
|
|
10
|
.75*
|
|
Indemnification Agreement, dated as of April 8, 2005, by
and between the Registrant and Gregory H. Boyce (Incorporated by
reference to Exhibit 10.1 of the Registrants Current
Report on
Form 8-K,
filed April 14, 2005).
|
|
10
|
.76*
|
|
Indemnification Agreement, dated July 21, 2005, by and
between the Registrant and John F. Turner (Incorporated by
reference to Exhibit 10.1 of the Registrants Current
Report on
Form 8-K,
filed on August 5, 2005).
|
|
10
|
.77*
|
|
Peabody Investments Corp. Supplemental Employee Retirement
Account (Incorporated by reference to Exhibit 10.1 of the
Registrants Quarterly Report on
Form 10-Q
for the quarter ended June 30, 2007).
|
|
10
|
.78
|
|
Amended and Restated Receivables Purchase Agreement, dated as of
September 30, 2005, by and among Seller, the Registrant,
the
Sub-Servicers
named therein, Market Street Funding Corporation, as Issuer, and
PNC Bank, National Association, as Administrator (Incorporated
by reference to Exhibit 10.2 of the Registrants
Quarterly Report on
Form 10-Q
for the quarter ended June 30, 2005, filed on
August 8, 2005).
|
|
10
|
.79
|
|
Second Amendment to Amended and Restated Receivables Purchase
Agreement, dated as of May 15, 2007, by and among the
Seller, the Registrant, the
Sub-Servicers
named therein, Market Street Funding LLC, as Issuer, and PNC
Bank, National Association, as Administrator (Incorporated by
reference to Exhibit 10.2 of the Registrants
Quarterly Report on
Form 10-Q
for the quarter ended June 30, 2007).
|
|
21
|
|
|
List of Subsidiaries.
|
|
23
|
|
|
Consent of Ernst & Young LLP, Independent Registered
Public Accounting Firm.
|
|
31
|
.1
|
|
Certification of periodic financial report by the
Registrants Chief Executive Officer pursuant to
Rule 13a-14(a)
under the Securities Exchange Act of 1934, as amended pursuant
to Section 302 of the Sarbanes-Oxley Act of 2002.
|
|
31
|
.2
|
|
Certification of periodic financial report by the
Registrants Chief Financial Officer pursuant to
Rule 13a-14(a)
under the Securities Exchange Act of 1934, as amended pursuant
to Section 302 of the Sarbanes-Oxley Act of 2002.
|
|
32
|
.1
|
|
Certification of periodic financial report pursuant to
18 U.S.C. Section 1350, adopted pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002, by the
Registrants Chief Executive Officer.
|
|
32
|
.2
|
|
Certification of periodic financial report pursuant to
18 U.S.C. Section 1350, adopted pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002, by the
Registrants Chief Financial Officer.
|
|
|
|
* |
|
These exhibits constitute all management contracts, compensatory
plans and arrangements required to be filed as an exhibit to
this form pursuant to Item 15(a)(3) and 15(b) of this
report. |
|
|
|
Filed herewith. |