e10vk
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C.
20549
Form 10-K
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þ
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ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
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For the Fiscal Year Ended December 31,
2009
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or
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TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
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Commission File Number 1-16463
Peabody Energy
Corporation
(Exact name of registrant as
specified in its charter)
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Delaware
(State or other jurisdiction
of incorporation or organization)
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13-4004153
(I.R.S. Employer
Identification No.)
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701 Market Street, St. Louis, Missouri
(Address of principal
executive offices)
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63101
(Zip
Code)
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(314) 342-3400
Registrants telephone
number, including area code
Securities
Registered Pursuant to Section 12(b) of the Act:
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Title of Each Class
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Name of Each Exchange on Which Registered
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Common Stock, par value $0.01 per share
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New York Stock Exchange
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Preferred Share Purchase Rights
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New York Stock Exchange
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Securities
Registered Pursuant to Section 12(g) of the Act:
None
Indicate by check mark if the registrant is a well-known
seasoned issuer, as defined in Rule 405 of the Securities
Act. Yes þ No o
Indicate by check mark if the registrant is not required to file
reports pursuant to Section 13 or Section 15(d) of the
Act. Yes o No þ
Indicate by check mark whether the registrant (1) has filed
all reports required to be filed by Section 13 or 15(d) of
the Securities Exchange Act of 1934 during the preceding
12 months (or for such shorter period that the registrant
was required to file such reports) and (2) has been subject
to such filing requirements for the past
90 days. Yes þ No o
Indicate by check mark whether the registrant has submitted
electronically and posted on its corporate Web site, if any,
every Interactive Data File required to be submitted and posted
pursuant to Rule 405 of
Regulation S-T
(§ 232.405 of this chapter) during the preceding
12 months (or for such shorter period that the registrant
was required to submit and post such
files). Yes þ No o
Indicate by check mark if disclosure of delinquent filers
pursuant to Item 405 of
Regulation S-K
(§ 229.405 of this chapter) 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):
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Large
accelerated
filer þ
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Accelerated
filer o
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Non-accelerated
filer o
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Smaller
reporting
company o
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(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 30, 2009: Common Stock, par value $0.01 per share,
$8.1 billion.
Number of shares outstanding of each of the Registrants
classes of Common Stock, as of February 12, 2010: Common
Stock, par value $0.01 per share, 268,757,971 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 2010 Annual Meeting of Stockholders (the
Companys 2010 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 in Managements Discussion and Analysis
of Financial Condition and Results of Operations. 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 operating results, 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:
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demand for coal in United States (U.S.), China and other
international power generation and steel production markets;
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price volatility and demand, particularly in higher-margin
products and in our trading and brokerage businesses;
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reductions
and/or
deferrals of purchases by major customers and ability to renew
sales contracts;
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credit and performance risks associated with customers,
suppliers, trading, banks and other financial counterparties;
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geologic, equipment, permitting and operational risks related to
mining;
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transportation availability, performance and costs;
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availability, timing of delivery and costs of key supplies,
capital equipment or commodities such as diesel fuel, steel,
explosives and tires;
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impact of weather on demand, production and transportation;
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successful implementation of business strategies, including our
Btu Conversion and generation development initiatives;
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negotiation of labor contracts, employee relations and workforce
availability;
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changes in postretirement benefit and pension obligations and
funding requirements;
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replacement and development of coal reserves;
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access to capital and credit markets and availability and costs
of credit, margin capacity, surety bonds, letters of credit, and
insurance;
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effects of changes in interest rates and currency exchange rates
(primarily the Australian dollar);
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effects of acquisitions or divestitures;
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economic strength and political stability of countries in which
we have operations or serve customers;
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legislation, regulations and court decisions or other government
actions, including new environmental requirements, changes in
federal or state income tax regulations or other regulatory
taxes;
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litigation, including claims not yet asserted;
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terrorist attacks or threats;
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impacts of pandemic illnesses; and
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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.
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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.
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Note:
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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.
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PART I
History
and Development of Business
Peabody Energy Corporation is the worlds largest
private-sector coal company. We were incorporated in Delaware in
2001 and our history in the coal mining business dates back to
1883. We own majority interests in 28 coal mining operations
located in the U.S. and Australia. In addition to our
mining operations, we market, broker and trade coal through our
Trading and Brokerage segment. In response to growing
international markets, we have expanded our international
trading group in the last few years, most recently with the
addition of a trading office in Singapore and a business
development office in Indonesia.
In the U.S., 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,
divestitures and strategic operational restructuring.
Internationally, we expanded our presence through the
acquisition of Excel Coal Limited (Excel) in Australia. We have
four core strategies to achieve growth:
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1)
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Executing the basics of
best-in-class
safety, operations and marketing;
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2)
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Capitalizing on organic growth opportunities;
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Expanding in high-growth global markets; and
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4)
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Participating in new generation and Btu Conversion technologies
designed to expand the uses of coal through
coal-to-liquids
and coal gasification technologies, and the advancement of clean
coal technologies, including carbon capture and storage.
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In 2007, we spun off portions of our formerly Eastern
U.S. Mining segment through a dividend of all outstanding
shares of Patriot Coal Corporation (Patriot), which is now an
independent public company traded on the New York Stock Exchange
(symbol PCX). 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. Our
results for all periods presented reflect Patriot as a
discontinued operation.
Segments
Our operations consist of four principal segments: our three
mining segments and our Trading and Brokerage segment. Our three
mining segments are Western U.S. Mining, Midwestern
U.S. Mining and Australian Mining. Our fifth segment,
Corporate and Other, includes mining and export/transportation
joint ventures, energy-related commercial activities as well as
the management of our vast coal reserve and real estate holdings
through initiatives such as 1) participation in developing
mine-mouth coal-fueled generating plants; 2) developing Btu
Conversion technologies, which are designed to convert coal to
natural gas and transportation fuels; and 3) advancing
carbon capture and storage initiatives. Our operating segments
are discussed in more detail below with financial information
contained in Note 22 to our consolidated financial
statements.
U.S. and
Australian Mining Operations
Mining Segments. Our Western U.S. Mining
operations consist of our Powder River Basin, Southwest and
Colorado operations, and our Midwestern U.S. Mining
operations consist of our Illinois and Indiana operations. The
principal business of our U.S. Mining segments is the
mining, preparation and sale of thermal (steam) coal, sold
primarily to electric utilities. Our Australian Mining
operations consist of metallurgical and thermal coal mines in
Queensland and New South Wales, Australia.
2
The maps below display our mine locations as of
December 31, 2009. Also noted are the primary ports
utilized in the U.S. and in Australia for our coal exports
and our corporate headquarters. The U.S. map does not
include our Bear Run Mine in western Indiana, which is expected
to begin operations in mid-2010.
3
The table below presents information regarding each of our 28
mines, including mine location, type of mine, mining method,
coal type, transportation method and tons sold in 2009. The
mines are sorted by tons sold within each mining segment.
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2009
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Mine
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Mining
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Coal
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Transport
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Tons Sold
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Mine
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Location
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Type
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Method
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Type
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Method
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(In millions)
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Western U.S. Mining
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North Antelope Rochelle
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Wright, WY
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S
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DL, T/S
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Thermal
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R
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98.3
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Caballo
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Gillette, WY
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S
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D, T/S
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Thermal
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R
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23.3
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Rawhide
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Gillette, WY
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S
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D, T/S
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Thermal
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R
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15.8
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Twentymile
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Oak Creek, CO
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U
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LW
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Thermal
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R, T
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7.7
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Kayenta
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Kayenta, AZ
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S
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DL, T/S
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Thermal
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R
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7.5
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El Segundo
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Grants, NM
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S
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T/S
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Thermal
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R
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5.4
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Lee Ranch
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Grants, NM
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S
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DL, T/S
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Thermal
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R
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2.1
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Midwestern U.S. Mining
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Farmersburg
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Pimento, IN
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S
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DL, D, T/S
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Thermal
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T, R
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3.6
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Willow Lake
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Equality, IL
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U
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CM
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Thermal
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T/B
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3.5
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Gateway
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Coulterville, IL
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U
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CM
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Thermal
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T, R, R/B
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3.4
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Somerville Central
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Oakland City, IN
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S
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DL, D, T/S
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Thermal
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R, T/R, T/B
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3.4
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Cottage Grove
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Equality, IL
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S
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D, T/S
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Thermal
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T/B
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2.1
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Francisco Underground
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Francisco, IN
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U
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CM
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Thermal
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R
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2.0
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Somerville North
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Oakland City, IN
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S
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D, T/S
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Thermal
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R, T/R, T/B
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2.0
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Miller Creek
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Bicknell, IN
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S
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D, T/S
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Thermal
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T, T/R
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2.0
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Somerville South
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Oakland City, IN
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S
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D, T/S
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Thermal
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R, T/R, T/B
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1.7
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Air Quality
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Vincennes, IN
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U
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CM
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Thermal
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T, T/R, T/B
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1.6
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Viking
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Cannelburg, IN
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S
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D, T/S
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Thermal
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T, T/R
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1.6
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Wildcat Hills Underground
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Eldorado, IL
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U
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CM
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Thermal
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T/B
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0.7
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Other(1)
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4.2
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Australian Mining
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Wilpinjong*
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Wilpinjong, New South Wales
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S
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T/S
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Thermal
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R, EV
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8.3
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Burton*(2)
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Glenden, Queensland
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S
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T/S
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Thermal/Met
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R, EV
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2.5
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Wilkie Creek
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Macalister, Queensland
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S
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T/S
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Thermal
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R, EV
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2.3
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North Wambo Underground
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Warkworth, New South Wales
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U
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LW
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Thermal/Met**
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R, EV
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2.3
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Wambo Open-Cut*
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Warkworth, New South Wales
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S
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T/S
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Thermal
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R, EV
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1.9
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North Goonyella
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Glenden, Queensland
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U
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LW
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Met
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R, EV
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1.8
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Metropolitan
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Helensburgh, New South Wales
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U
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LW
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Met
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R, EV
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1.5
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Eaglefield*
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Glenden, Queensland
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S
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T/S
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Met
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R, EV
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0.9
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Millennium
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Moranbah, Queensland
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S
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T/S
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Met
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R, EV
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0.8
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Legend:
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S
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Surface Mine
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R
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Rail
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U
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Underground Mine
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T
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Truck
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DL
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Dragline
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R/B
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Rail and Barge
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D
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Dozer/Casting
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T/B
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Truck and Barge
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T/S
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Truck and Shovel
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T/R
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Truck and Rail
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LW
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Longwall
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EV
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Export Vessel
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CM
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Continuous Miner
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Thermal
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Thermal/Steam
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Met
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Metallurgical
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* |
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Mine is operated by a contract miner |
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Metallurgical coal is pulverized coal injection, or PCI |
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(1) |
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Other in Midwestern U.S. Mining primarily
consists of purchased coal used to satisfy certain coal supply
agreements and shipments made from operations closed during 2009. |
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(2) |
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The Burton Mine is a 95% proportionally owned and consolidated
mine. |
4
See Item 2. Properties. for additional information
regarding coal reserves, coal characteristics and tons produced
for each mine.
Trading
and Brokerage Segment
Through our Trading and Brokerage segment, we broker coal sales
of other coal producers both as principal and agent, and trade
coal, freight and freight-related contracts. We also provide
transportation-related services in support of our coal trading
strategy, as well as hedging activities in support of our mining
operations.
In response to growing international markets, we expanded our
international trading group in 2006 and added trading operations
offices in London, England in 2007 and in Singapore in 2009. Our
trading and brokerage entities broker and trade coal in the
Australia and Pacific Rim markets. We also have sales, marketing
and business development offices in Beijing, China and Jakarta,
Indonesia (opened in 2009) to pursue potential long-term
growth opportunities in the Asian market.
Corporate
and Other Segment
Resource Management. We hold approximately
9.0 billion tons of proven and probable coal reserves and
more than 500,000 acres of surface property. Our resource
development group regularly reviews these reserves for
opportunities to generate earnings and cash flow 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, and
farm income from surface land under third-party contracts.
Export Facilities. We own a 37.5% interest in
Dominion Terminal Associates, a partnership that operates a coal
export terminal in Newport News, Virginia. The facility has a
rated throughput capacity of approximately 20 million tons
of coal per year and had 11.0 million tons of throughput in
2009. The facility also has ground storage capacity of
approximately 1.7 million tons. The facility exports both
metallurgical and thermal coal primarily to European and
Brazilian markets.
We control a 17.7% interest in the Newcastle Coal Infrastructure
Group, which is currently constructing a coal transloading
facility in Newcastle, Australia. The facility, which is
expected to be completed in 2010, is backed by take or pay
agreements and will have an initial capacity of 33 million
tons per year of which our share is 5.8 million tons, with
expansion capacity of up to 66 million tons per year.
Generation Development, Btu Conversion and Clean Coal
Technology. To maximize our coal assets and land
holdings for long-term growth, we are contributing to the
development of coal-fueled generation, pursuing Btu Conversion
projects that would convert coal to natural gas or
transportation fuels and advancing clean coal technologies.
Generation development projects involve using our surface lands
and coal reserves as the basis for mine-mouth plants. Our
ultimate role in these projects could take numerous forms,
including, but not limited to, equity partner, contract miner or
coal lessor. We are currently a 5.06% owner in the Prairie State
Energy Campus (Prairie State), a 1,600 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 its adjacent
underground mining operations. We sold 94.94% of the land and
coal reserves to our partners in Prairie State and we are
responsible for our 5.06% share of costs to construct the
facility. The plant is scheduled to begin generating electricity
in 2011.
We are exploring Btu Conversion projects designed to expand the
uses of coal through
coal-to-liquids
(CTL) and coal gasification technologies. Currently, we are
pursuing development of a
coal-to-gas
(CTG) facility known as Kentucky NewGas, a planned
mine-mouth gasification project using ConocoPhillips
proprietary
E-Gastm
technology to produce clean synthesis gas with carbon storage
potential. We also own an equity interest in GreatPoint Energy,
Inc., which is commercializing its
coal-to-pipeline
quality natural gas technology. We are also pursuing a project
with the government of Inner Mongolia and other Chinese partners
to explore development opportunities for a large surface mine
and downstream coal gasification facility that would produce
methanol, chemicals or fuel products.
5
We are participating in the advancement of clean coal
technologies, including carbon capture and storage, in the U.S.,
China and Australia. We are a founding member of the FutureGen
Alliance, a non-profit company working in partnership with the
U.S. Department of Energy (DOE), which under its new
configuration, would develop multiple carbon capture and storage
sites. We are the only non-Chinese equity partner in GreenGen, a
near-zero emissions coal-fueled power plant with carbon capture
and storage. In Australia, we made a
10-year
commitment to fund the Australian COAL21 Fund designed to
support clean coal technology demonstration projects and
research in Australia. We are also a founding member or member
of a number of related partnerships including the Global Carbon
Capture and Storage Institute (Australia), the
U.S.-China
Energy Cooperation Program, the Asia-Pacific Partnership for
Clean Development and Climate, the Consoritium for Clean Coal
Utilization, the National Carbon Capture Center, and the Western
Kentucky Carbon Storage Foundation.
Mongolia Joint Venture. In 2009, we acquired a
50% interest in a joint venture holding with Polo Resources
Limited (AIM: PRL), which holds coal and mineral interests in
Mongolia. In connection with this acquisition, we obtained
warrants to enable us to acquire an approximate 15% equity
interest in Polo Resources Limited. The joint venture is in the
development stage and plans to ship metallurgical and thermal
coal to Asian markets once developed.
Paso Diablo Mine. We own a 25.5% equity
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,
which is a surface operation in northwestern Venezuela that
produces thermal coal for export primarily to the U.S. 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. In December 2009, we entered
into an arrangement to assume Anglo Americans interest,
which is conditional on the approval of various parties
(including the Venezuelan governmental partner) and regulatory
approvals.
Coal
Supply Agreements
As of January 31, 2010 we had a sales backlog of over one
billion tons of coal, including backlog subject to price
reopener
and/or
extension provisions, representing nearly five years of current
production. Agreements in backlog have remaining terms ranging
from one to 17 years. For 2009, approximately 93% of our
worldwide sales (by volume) were under long-term coal supply
agreements. In 2009, we sold coal to 345 electricity generating
and industrial plants in 23 countries. For the year ended
December 31, 2009, we derived 28% of our total coal sales
revenues from our five largest customers (excluding trading
transactions). At December 31, 2009, we had 79 coal supply
agreements with these customers expiring at various times from
2010 to 2016.
U.S. We expect to continue selling a
significant portion of our coal under long-term supply
agreements. Customers continue to pursue long-term sales
agreements as the importance of reliability, service and
predictable prices are recognized. The terms of coal supply
agreements result from competitive bidding and extensive
negotiations with customers. Consequently, the terms of these
agreements 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. Our strategy
is to selectively renew, or enter into new, long-term supply
agreements when we can do so at prices we believe are favorable.
Australia. Our international coal mining
activities accounted for 10% of our mining operations sales
volume in 2009. Our production is sold primarily into the export
metallurgical and thermal markets. Price reopener provisions are
present in the majority of our multi-year international coal
agreements. Historically, these provisions allow either party to
commence a renegotiation of the agreement price annually. A
majority of the reopener provisions relate to metallurgical coal
repriced annually in the second quarter of each year. We also
have a long-term coal supply agreement with a customer in
Australia, which runs through 2025 and is expected to supply
approximately 130 million tons from our Wilpinjong Mine.
6
Transportation
Coal consumed in the U.S. is usually sold at the mine with
transportation costs borne by the purchaser. Australian and
U.S. 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). 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. See the table on page 4
for transportation methods by mine.
Suppliers
The main types of goods we purchase are mining equipment and
replacement parts, ammonium-nitrate and emulsion based
explosives, diesel fuel,
off-the-road
(OTR) tires, steel-related (including roof control materials)
products and lubricants. We also purchase services at our mine
sites that include maintenance services for mining equipment,
temporary labor and other various contracted services, including
contract miners. 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 to the coal industry has been relatively
consistent in recent years, although there continues to be some
consolidation. Supplier consolidation in explosives and
underground equipment has limited the number of sources for
these materials, resulting in our purchases of these items being
concentrated with one principal supplier; however, some supplier
competition continues to be present. In recent years, demand and
lead times for certain surface and underground mining equipment
and OTR tires has increased. However, we do not expect lead
times to have a near-term material impact on our financial
condition, results of operations or cash flows.
Technical
Innovation
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. In
2009, we began a program to upgrade the mining equipment at our
North Antelope Rochelle Mine, both to increase overburden
removal capacity and improve mining cost with larger more
efficient trucks and shovels. Our engineers have also been
working with several major equipment vendors to develop
conceptual designs of in-pit crushing and conveying systems in
place of trucks in an effort to move large quantities of
overburden resulting in cost savings and a more environmentally
friendly operation. We are currently working with a vendor to
implement the Landmark longwall shearer navigation
system at our North Wambo Underground Mine. This system includes
hardware and software that monitors and controls the pitch, roll
and depth of cut of the shearer to maintain the face alignment,
allowing the shearer to mine more efficiently. We have also
begun pilot testing of a paste slurry pumping system that, if
successful, will allow coal refuse from the Metropolitan Mine to
be disposed of in abandoned areas of the underground workings
rather than transported to the surface.
Our enterprise resource planning system provides detailed
equipment and mining performance data for all our
U.S. operations. Proprietary software for hand-held
Personal Digital Assistant devices was developed in-house, and
has been deployed at all U.S. underground mines to record
safety observations, safety audits, underground front-line
supervisor reports and delay information. Wireless data
acquisition systems are installed at our two largest mines,
North Antelope Rochelle and Caballo, to dispatch mobile
equipment more efficiently and monitor performance and condition
of all major mining equipment on a real-time basis.
We use maintenance standards based on reliability-centered
maintenance practices at all operations to increase equipment
utilization and reduce maintenance and capital spending by
extending the equipment life, while minimizing the risk of
premature failures. Specialized maintenance reliability software
is used at many operations to better support improved equipment
strategies, predict equipment condition and aid analysis
necessary for better decision-making for such issues as
component replacement timing.
7
We also use in-house developed software to schedule and monitor
trains, mine and pit blending, quality and customer shipments to
enhance our reliability and product consistency.
Competition
The markets in which we sell our coal are highly competitive.
According to the National Mining Associations 2008
Coal Producer Survey, the top 10 coal companies in the
U.S. produced approximately 70% of total U.S. coal in
2008. Our principal U.S. competitors (listed
alphabetically) are other large coal producers, including Alpha
Natural Resources, Inc., Arch Coal, Inc., Cloud Peak Energy
Inc., CONSOL Energy Inc. and Massey Energy Company, which
collectively accounted for approximately 41% of total
U.S. coal production in 2008 (most recent publicly
available data). Major international competitors (listed
alphabetically) include
Anglo-American
PLC, BHP Billiton, China Coal, Rio Tinto, Shenhua Group, and
Xstrata PLC. In Australia, the top 10 coal companies produced
approximately 84% of the countrys coal in 2009. We compete
on the basis of coal quality, delivered price, customer service
and support and reliability.
Employees
As of December 31, 2009, we had approximately
7,300 employees, which included approximately
5,400 hourly employees. As of such date, approximately 29%
of our hourly employees were represented by organized labor
unions and generated 10% of 2009 coal production. Relations with
our employees and, where applicable, organized labor are
important to our success.
U.S. Labor Relations. Hourly workers at
our Kayenta Mine in Arizona are represented by the United Mine
Workers of America, under the Western Surface Agreement, which
is effective through September 2, 2013. This agreement
covers approximately 7% of our U.S. subsidiaries
hourly employees, who generated approximately 4% of our
U.S. production during the year ended December 31,
2009. Hourly workers at our Willow Lake Mine in Illinois are
represented by the International Brotherhood of Boilermakers,
under a labor agreement that expires April 15, 2011. This
agreement covers approximately 9% of our
U.S. subsidiaries hourly employees, who generated
approximately 2% of our U.S. production during the year
ended December 31, 2009.
Australian 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
and engineering employees, including those employed through
contract mining relationships. All the Australian
subsidiarys mine sites have enterprise bargaining
agreements. The current labor agreement at our Metropolitan Mine
expires in June 2010; renegotiations for a new agreement will
commence in the first quarter of 2010. The labor agreement for
the Wambo Mine coal handling plant was renewed in 2008 and
expires in 2011. The labor agreement for the Wambo Underground
Mine was renewed in early 2009 and will expire in 2012. For the
Wilkie Creek Mine (expired October 2009) and the North
Goonyella Mine (expired May 2009), we have reached agreements in
principle, with the vote of the unions and employees expected to
take place in late February 2010.
Regulatory
Matters U.S.
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.
8
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 our violations to date or
the monetary penalties assessed has been material.
Mine Safety and Health. Our goal 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.
During 2009, our worldwide safety performance set a new standard
in our
126-year
history. The U.S. injury incidence rate of 2.06 (computed
per 200,000 worker hours) was slightly higher compared to last
years record performance, but the Australian operations
improved by nearly 40% versus the previous year. This drove the
worldwide Peabody incidence rate to a new low of 2.82 for 2009,
which was 21% better than the previous record year and
approximately 31% better than the U.S. average for our
industry. We received multiple state and federal safety awards
during the year. Our training centers educate our employees in
safety best practices and reinforce our company-wide belief that
productivity and profitability follow when safety is the
cornerstone at all of our operations.
Following passage of The Mine Improvement and New Emergency
Response Act of 2006 (The Miner Act), the U.S. Mine Safety and
Health Administration (MSHA), significantly increased the
enforcement of safety and health standards and imposed safety
and health standards on all aspects of mining operations. There
has also been a dramatic increase in the dollar penalties
assessed for citations issued over the past two years.
The Miner Act requires the installation of wireless, two-way
communication systems for miners, and mine operators must have
the ability to track the location of each miner at work in an
underground mine. Since these developing technologies are nearly
ready for MSHA approval, we anticipate expenditures in 2010 to
fully equip all of our underground mines with this improved
capability.
Most of the states in which we operate have inspection programs
for mine safety and health. Collectively, federal and state
safety and health regulations in the coal mining industry are
perhaps the most comprehensive and pervasive systems 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 U.S., the Surface Mining Control and Reclamation Act of 1977
(SMCRA), which is administered by the Office of Surface Mining
Reclamation and Enforcement (OSM), established 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
SMCRA, 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.
9
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 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 was $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 is $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 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
comparable 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. It
is possible that the more stringent ambient air quality
standards (NAAQS) will directly impact our mining operations by,
for example, requiring additional controls of emissions from our
mining equipment and vehicles. Moreover, if the areas in which
our mines and coal preparation plants are located suffer from
extreme weather events such as droughts, or are designated as
non-attainment areas, we could be required to incur significant
costs to install additional emissions control equipment, or
otherwise change our operations and future development. In
addition, in September 2009 the
10
EPA adopted new rules tightening and adding additional
particulate matter emissions limits for coal preparation and
processing plants constructed, reconstructed or modified after
April 28, 2008.
The Clean Air Act indirectly, but more significantly, affects
the coal industry by extensively regulating the air emissions of
sulfur dioxide, nitrogen oxides, mercury and other substances
emitted by coal-based electricity generating plants. In addition
to the issues discussed under Global Climate Change
on page 14, the air emissions programs that may affect our
operations, directly or indirectly, include, but are not limited
to, the Acid Rain Program, NOx SIP Call, the Clean Air
Interstate Rule (CAIR), Maximum Achievable Control Technology
(MACT) emissions limits for Hazardous Air Pollutants, the
Regional Haze program and New Source Review. In addition, the
EPA has adopted NAAQS for particulate matter, nitrogen oxide and
sulfur dioxide. The EPA has proposed more stringent NAAQS for
sulfur dioxide and ozone. Almost all of these programs and
regulations have resulted in litigation which has not been
completely resolved.
Programs such as the Acid Rain Program and CAIR use a cap and
trade system. Affected power plants have sought to reduce sulfur
dioxide emissions by switching to lower sulfur fuels, installing
pollution control devices, reducing electricity generating
levels or purchasing or trading sulfur dioxide emissions
allowances. As a result of the CAIR program, the MACT
requirements and more stringent nitrogen oxides, particulate and
ozone NAAQS, many power plants have been or will be required to
install additional emission control measures, such as scrubbers
and selective catalytic reduction devices.
Our customers are among the electricity generators subject to
New Source Review 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. The Regional
Haze program may also require retrofitting of existing
facilities with additional control equipment.
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
existing law. 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.
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. 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.
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.
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.
11
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 wastes generated
at a mine site are those from products used in vehicles and for
machinery maintenance. Coal mine wastes, such as overburden and
coal cleaning wastes, are not considered hazardous wastes 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
wastes under RCRA. The EPA has retained 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. The EPA has announced that
it is developing a proposal for requirements for coal combustion
residue management.
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 CERCLA, 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.
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 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.
Endangered Species Act. The
U.S. Endangered Species Act and counterpart state
legislation is intended to protect species whose populations
allow for categorization as either endangered or threatened.
With respect to obtaining mining permits, protection of
endangered or threatened species may have the effect of
prohibiting, limiting the extent or causing delays that may
include permit conditions on the timing of, soil removal, timber
harvesting, road building and other mining or agricultural
activities in areas containing the associated species. Based on
the species that have been identified on our properties and the
current application of these laws and regulations, we do not
believe that they will have a material adverse effect on our
ability to mine the planned volumes of coal from our properties
in accordance with current mining plans. However, there are
ongoing lawsuits and petitions under these laws and regulations
that, if successful, could have a material adverse effect on our
ability to mine some of our properties in accordance with our
current mining plans.
12
Use of Explosives. Our surface mining
operations are subject to numerous regulations relating to
blasting activities. Pursuant to these regulations, we incur
costs to design and implement blast schedules and to conduct
pre-blast surveys and blast monitoring. In addition, the storage
of explosives is subject to strict regulatory requirements
established by four different federal regulatory agencies. For
example, pursuant to a rule issued by the U.S. Department
of Homeland Security in 2007, facilities in possession of
chemicals of interest, including ammonium nitrate at certain
threshold levels, must complete a screening review in order to
help determine whether there is a high level of security risk
such that a security vulnerability assessment and site security
plan will be required.
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 is
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, the NTA
provides for arbitration.
There is also federal and state legislation to prevent damage to
Aboriginal cultural heritage and archeological sites.
Mining Tenements and Environmental. In
Queensland and New South Wales the development of a mine
requires both the grant of a right to and also an approval which
authorizes the environmental impacts of the mine. These
approvals are obtained under separate legislation from separate
government authorities. However, the application processes run
concurrently and are also concurrent with any native title or
cultural heritage process that is required.
The environmental impacts of mining projects are regulated by
local, state and federal governments. Federal regulation will
only apply if the particular project will significantly impact a
matter of national environmental significance (e.g., endangered
species or particular protected places). If so, it will also be
regulated by the federal government.
Generally, the process involves an assessment of the
environmental impacts of the project and how these can be
managed which is submitted to the state government for
consideration (also to the federal government if federal
approval is required). Based on the environmental assessment,
conditions will be imposed on the environmental approval (if
granted). The conditions commonly relate to limits on emissions
to the atmosphere, emissions in water, noise impacts, dust
impacts, the generation, handling, storage and transportation of
waste and requirements for the rehabilitation and restoration of
land. Environmental assessments and applications for approval
are generally publicly notified and third parties may lodge
submissions.
13
Queensland and New South Wales each have their own mining
tenement legislation which regulates the process for applying
for and renewing mining tenements. Before obtaining a mining
lease which allows production, it is necessary to hold an
exploration license. This exploration license allows exploratory
drilling to take place but does not permit production.
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.
Currently all states and territories are responsible for making
and enforcing their own laws. Although these draw on a similar
approach for regulating workplaces, there are some differences
in the application and detail of the laws. However, in December
2009, the Workplace Relations Ministers Council endorsed a
model Work Health and Safety Act. Each of the states and
territories has agreed to implement their own legislation
adopting the model legislation by December 2011 to achieve
consistent requirements across the country.
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 by 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.
Industrial Relations. A national industrial
relations system administered by the federal government applies
to all private sector employers and employees. The system
largely became operational in July 2009 and fully operational in
January 2010. The matters regulated under the national system
regulates include:
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employment conditions;
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unfair dismissal;
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enterprise bargaining;
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industrial action; and
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resolution of workplace disputes.
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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. 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.
Peabody Energy Australia Pty Ltd, one of our subsidiaries, is
now registered as a controlling corporation and must report each
financial year about the greenhouse gas emissions and energy
production and consumption of our Australian entities.
Regulatory
Matters Mongolia
The Mongolian mining industry is regulated by Mongolian federal,
provincial and local governments with respect to exploration,
development, production, occupational health, mine safety, water
use, environmental protection and remediation, foreign
investment and other related matters. The Mineral Resources
Authority of
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Mongolia is the government agency with the authority to issue,
extend and revoke mineral licenses, which generally give the
license holder the right to engage in the mining of minerals
within the license area for 30 years (with the right to
extend for two additional periods of 20 years). Mongolian
law provides for state participation in the exploitation of any
mineral deposit of strategic importance, as
determined by the Mongolian Parliament.
Global
Climate Change
Global climate change continues to attract public and scientific
attention. Numerous reports, such as the Fourth Assessment
Report of the Intergovernmental Panel on Climate Change (IPCC),
have also engendered concern about the impacts of human
activity, especially fossil fuel combustion, on global climate
change. In turn, increasing government attention is being paid
to global climate change and to emissions of what are commonly
referred to as greenhouse gases, including emissions of carbon
dioxide from coal combustion by power plants.
Presently there are no U.S. federal mandatory greenhouse
gas reduction requirements. In June 2009, the U.S. House of
Representatives passed legislation which calls for a
cap-and-trade
system and other measures. Under a
cap-and-trade
program, or emissions trading scheme, allowances would be
granted or auctioned, with the quantity based on the acceptable
limits of aggregate emissions. Over time, those allowable
emissions would likely be decreased. The price would depend on a
number of factors including the market for such allowances and
the cost of emissions control technologies or alternatives. The
U.S. Senate has not acted on legislation in this area.
While it is possible that the U.S. will adopt legislation
in the future, the timing and specific requirements of any such
legislation are highly uncertain.
Even in the absence of new U.S. federal legislation,
greenhouse gas emissions may be regulated in the future by the
U.S. EPA pursuant to the Clean Air Act. In response to the
2007 U.S. Supreme Court ruling Massachusetts v. EPA
that the EPA has authority to regulate carbon dioxide emissions
under the Clean Air Act, the EPA has taken several actions
towards emissions regulation.
In December 2009, the EPA published its finding that atmospheric
concentrations of greenhouse gases endanger public health and
welfare within the meaning of the Clean Air Act, and that
emissions of greenhouse gases from new motor vehicles and new
motor vehicle engines are contributing to air pollution that are
endangering public health and welfare within the meaning of the
Clean Air Act. The finding does not by itself impose any
regulatory requirements and does not contain any specific
targets for reducing greenhouse gases. While the EPAs
finding is technically limited to greenhouse gas emissions from
new motor vehicles and new motor vehicle engines, the finding
may lead to endangerment findings under other Clean Air Act
programs, including those that relate directly to emissions from
stationary sources. In February 2010, we filed a petition with
the EPA requesting reconsideration of the finding as well as a
petition to review the finding with the U.S. Court of
Appeals for the District of Columbia Circuit. Our petitions are
based primarily on the release of email and other information
from the University of East Anglia Climatic Research Unit (CRU)
in November 2009. We believe that the CRU information undermines
a number of the central pillars on which the finding rests,
particularly the work of the IPCC.
In October 2009, the EPA published a proposed rule to regulate
the emission of greenhouse gases from certain stationary sources
with an initial focus on facilities that release more than
25,000 tons of greenhouse gases a year, and that would require
best available control technology for such emissions whenever
such facilities are built or significantly modified (the
so-called tailoring rule). It is unclear as to
whether the EPA has the statutory authority under the Clean Air
Act to adopt the tailoring rule. In addition, in September 2009
the EPA adopted a rule requiring certain emitters of greenhouse
gases, including coal-fired power plants, to monitor and report
their emissions to the EPA.
A number of states in the U.S. 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.
Six midwestern states (Illinois, Iowa, Kansas, Michigan,
Minnesota and Wisconsin) and one Canadian province have entered
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into the Midwestern Regional Greenhouse Gas Reduction Accord to
establish regional greenhouse gas reduction targets and develop
a multi-sector
cap-and-trade
system to help meet the targets. Seven western states (Arizona,
California, Montana, New Mexico, Oregon, Utah and Washington)
and two Canadian provinces have entered into the Western Climate
Initiative (WCI) to establish a regional greenhouse gas
reduction goal and develop market-based strategies to achieve
emissions reductions. However, the Governor of Arizona announced
in February 2010 that Arizona will not implement the greenhouse
gas
cap-and-trade
proposal advanced by the WCI, which begins on January 1,
2012. In 2006, the California legislature approved legislation
allowing the imposition of statewide caps on, and cuts in,
carbon dioxide emissions. Similar legislation was adopted in
2007 in Hawaii, Minnesota 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 U.S. has signed
the Kyoto Protocol, but it has not been ratified by the
U.S. Senate. As noted previously, Australia ratified the
Kyoto Protocol in December 2007 and became a full member in
March 2008. International discussions are underway to develop a
treaty to replace the Kyoto Protocol after its expiration in
2012, including the Copenhagen meetings in late 2009.
In May 2009, legislation was introduced in Australias
Parliament to establish a national emissions trading market,
called the Carbon Pollution Reduction Scheme (CPRS). If enacted,
the CPRS would set a cap on greenhouse gas emissions in
Australia and issue permit allowances up to the cap limit. The
CPRS was passed by Australias House of Representatives in
June 2009, but was voted down by the Australian Senate in August
2009. The Australian government reintroduced the CPRS for
consideration by Parliament in October 2009, but it was voted
down by the Australian Senate in December 2009.
We continue to support clean coal technology development and
other initiatives addressing global climate change through our
participation as a founding member of the FutureGen Alliance in
the U.S. and the COAL21 Fund in Australia and through our
participation in the Power Systems Development Facility, the
PowerTree Carbon Company LLC, the Midwest Geopolitical
Sequestration Consortium, the Asia-Pacific Partnership for Clean
Development and Climate, the
U.S.-China
Energy Cooperation Program, the Consortium for Clean Coal
Utilization, the National Carbon Capture Center and the Western
Kentucky Carbon Storage Foundation. 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 which is under development in China. We are also a
founding member of the Global Carbon Capture and Storage
Institute, an international initiative to accelerate
commercialization of carbon capture and storage (CCS)
technologies through development of 20 integrated,
industrial-scale demonstration projects.
In the U.S., clean coal technology development is being
accelerated by the American Recovery and Reinvestment Act of
2009 (the ARRA), which was signed into law by President Obama in
February 2009. The ARRA targets $3.4 billion for
U.S. Department of Energy (DOE) fossil fuel programs,
including $1 billion for CCS research; $800 million
for the Clean Coal Power Initiative, a
10-year
program supporting commercial CCS; and $50 million for
geology research.
In addition, in February 2010, President Obama announced the
formation of an Interagency Task Force on Carbon Capture and
Storage (the Task Force) to develop a comprehensive and
coordinated federal strategy to speed the commercial development
and deployment of clean coal technologies. The Task Force has
been asked to develop a proposed plan to overcome the barriers
to the widespread, cost-effective deployment of CCS within
10 years, with a goal of bringing five to 10 commercial
demonstration projects online by 2016.
We participate in the DOEs Voluntary Reporting of
Greenhouse Gases Program, and regularly disclose the quantity of
emissions per ton of coal produced by us in the U.S. The
vast majority of our emissions are generated by the operation of
heavy machinery to extract and transport coal at our mines. We
continue to evaluate and implement improvements in technology
and infrastructure such as the overland conveyor and
near pit truck dump and crusher facility at our North Antelope
Rochelle Mine in Wyoming that are expected to reduce
the level of emissions from our operations.
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Enactment of laws or passage of regulations regarding emissions
from the mining of coal by the U.S. or some of its states
or by other countries, or other actions to limit such emissions,
are not expected to have a material adverse effect on our
results of operations, financial condition or cash flows.
Enactment of laws or passage of regulations regarding emissions
from the combustion of coal by the U.S. or some of its
states or by other countries, or other actions to limit such
emissions, could result in electricity generators switching from
coal to other fuel sources. The potential financial impact on us
of future laws or regulations will depend upon the degree to
which any such laws or regulations forces electricity generators
to diminish their reliance on coal as a fuel source. That, in
turn, will depend on a number of factors, including the specific
requirements imposed by any such laws or regulations, the time
periods over which those laws or regulations would be phased in
and the state of commercial development and deployment of CCS
technologies. In view of the significant uncertainty surrounding
each of these factors, it is not possible for us to reasonably
predict the impact that any such laws or regulations may have on
our results of operations, financial condition or cash flows.
Additional
Information
We file annual, quarterly and current reports, and our
amendments to those reports, proxy statements and other
information with the 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.
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 following risk factors relate specifically to the risks
associated with our continuing operations.
Risks
Associated with Our Operations
The
global economic recession and disruptions in the financial
markets, and their impact on us, are uncertain.
The magnitude and pace of recovery from the global economic
recession and the worldwide financial and credit market
disruptions is uncertain. We are focused on strong cost control
and productivity improvements, increased contributions from our
high-margin operations, and exercising tight capital discipline.
However, there can be no assurance that these actions, or any
others that we may take in response to further deterioration in
economic and financial conditions, will be sufficient. A return
to the global recession or further disruptions in the financial
markets could have an adverse effect on our business, financial
condition or results of operations.
A
decline in coal prices could negatively affect our
profitability.
Our profitability depends upon the prices we receive for our
coal. Coal prices are dependent upon factors beyond our control,
including:
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the demand for electricity and the strength of the global
economy;
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the demand for steel, which may lead to price fluctuations in
the annual repricing of our metallurgical coal contracts;
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the supply of U.S. domestic and international thermal and
metallurgical coal;
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competition within our industry and the availability and price
of alternative fuels and energy sources;
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the proximity, capacity and cost of transportation;
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coal industry capacity;
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domestic and foreign governmental regulations and taxes,
including those establishing air emission standards for
coal-fueled power plants;
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regulatory, administrative and judicial decisions, including
those affecting future mining permits; and
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technological developments, including those intended to convert
coal to liquids or gas and those aimed at capturing and storing
carbon dioxide.
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As of January 26, 2010, we are fully contracted for 2010 at
planned production levels in the U.S. and have 4.5 to
5.5 million tons of Australian metallurgical coal and 6.5
to 7.0 million tons of Australian thermal coal available to
price. If we experience a weak coal pricing environment
resulting in a deterioration of coal prices, we could experience
an adverse effect on our revenues and profitability.
If a
substantial number 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, particularly in the U.S. In 2009, 93% of our
worldwide sales volume was sold under long-term coal supply
agreements. At January 31, 2010, our sales backlog,
including backlog subject to price reopener
and/or
extension provisions, was over one billion tons, representing
nearly five 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 restricts the use or type of coal
permissible at the customers plant or 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.
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The
loss of, or significant reduction in, purchases by our largest
customers could adversely affect our revenues.
In 2009, we derived 28% of our total coal sales revenues from
our five largest customers (excluding trading transactions). At
December 31, 2009, we had 79 coal supply agreements with
these customers expiring at various times from 2010 to 2016. 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. In addition,
our revenue could be adversely affected by a decline in customer
purchases due to lack of demand, cost of competing fuels and
environmental regulations.
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 or
for financially settled contracts depends on the continued
creditworthiness of our customers and counterparties. 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.
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 on our results of operations, financial
condition or cash flows.
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, 2009, certain coal supply agreements 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.
We 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, underperformance of the port and rail
infrastructure, congestion and balancing systems which are
imposed to manage vessel queuing and demurrage, 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.
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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 mining
equipment, replacement parts, explosives, fuel, tires,
steel-related products (including roof control) and lubricants.
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. 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.
An
inability of trading, brokerage, mining or freight 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 and
transportation, including contract miners and brokerage sources,
to fulfill deliveries under our coal supply agreements. In
Australia, the majority of our volume comes from mines that
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 the ability of our freight sources to fulfill their delivery
obligations. Market volatility and price increases for coal or
freight on the international and domestic 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.
Our
hedging activities may expose us to earnings volatility and
other risks.
We enter into hedging arrangements designed primarily to manage
our exposure to explosives, diesel fuel, foreign currency and
interest rate fluctuations. Generally, we attempt to designate
hedging arrangements as cash flow hedges with gains or losses
recorded as a separate component of stockholders equity
until the hedged transaction occurs (or until hedge
ineffectiveness is determined). While we utilize a variety of
risk monitoring and mitigation strategies, those strategies
require judgment and they cannot anticipate every potential
outcome or the timing of such outcomes. As such, there is
potential for these hedges to no longer qualify for hedge
accounting. If that were to happen, we will be required to
recognize the mark to market movements through current year
earnings, possibly resulting in increased volatility in our
income in future periods.
Additionally, some of our hedging arrangements require us to
post margin based on the value of those hedging arrangements and
other credit factors. If our credit is downgraded, the fair
value of our hedge positions move significantly, or laws or
regulations are passed requiring all hedge arrangements to be
exchange-traded or exchange-cleared, we could be required to
post additional margin, which could impact our liquidity.
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 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
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qualified personnel in the future. Failure to retain or attract
key personnel could have a material adverse effect on us.
We
could be negatively affected if we fail to maintain satisfactory
labor relations.
As of December 31, 2009, we had approximately
7,300 employees. Approximately 29% of our hourly employees
were represented by unions and they generated approximately 10%
of our 2009 coal production. Additionally, those employed
through contract mining relationships in Australia are also
members of unions. Relations with our employees and, where
applicable, organized labor are important to our success. 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.
Our
mining 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 methods for us to meet those
obligations are 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, 2009, we had $821.9 million of self
bonding in place for our reclamation obligations. As of
December 31, 2009, we also had outstanding surety bonds
with third parties and letters of credit of
$1,270.3 million, of which $807.2 million was for
post-mining reclamation, $51.7 million related to
workers compensation obligations, $116.3 million was
for coal lease obligations and $295.1 million was for other
obligations, including collateral for surety companies and bank
guarantees, road maintenance and performance guarantees. 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 Senior
Unsecured Credit Facility, which expires 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:
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lack of availability, higher expense or unfavorable market terms
of new surety bonds;
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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;
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the exercise by third-party surety bond issuers of their right
to refuse to renew the surety; and
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inability to renew our credit facility.
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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.
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 and local authorities data pertaining to the effect that
any proposed exploration for or production of coal may have upon
the environment. The public, including non-governmental
organizations, opposition groups and individuals, have statutory
rights to comment upon and submit objections to requested
permits and approvals. 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.
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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 or the reduction of greenhouse
gas emissions 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.
A number of laws, including in the U.S. the CERCLA, 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. Hanson PLC, which is a
predecessor owner of ours, 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. See Note 20 to our consolidated financial statements
for a description of pending legal proceedings involving Gold
Fields.
If the
assumptions underlying our asset retirement obligations for
reclamation and mine closures are materially inaccurate, our
costs could be significantly greater than
anticipated.
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 in the U.S. and Australia as
defined by each mining permit. These 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 and the timing of these cash flows, discounted
using a credit-adjusted, risk-free rate. Our management and
engineers periodically review these estimates. 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. The resulting estimated asset retirement
obligation could change significantly if actual amounts change
significantly from our assumptions, which could have a material
adverse effect on our results of operation, and financial
condition.
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. Moreover, the amount of
proven and probable coal reserves described in Item 2.
Properties. involved the use of certain estimates and those
estimates could be inaccurate. 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 U.S. federal government also leases natural
gas and coalbed methane reserves
22
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
U.S. federal government limits the amount of federal land
that may be leased by any company to 150,000 acres
nationwide. As of December 31, 2009, we leased a total of
64,260 acres from the federal government. The limit could
restrict our ability to lease additional U.S. federal lands.
Our planned mine development projects and acquisition activities
may not result in significant additional reserves, and we may
not have success developing additional mines. Most of our mining
operations are conducted on properties owned or leased by us.
Because we do not thoroughly verify title to most of our leased
properties and mineral rights until we obtain a permit to mine
the property, our right to mine some of our reserves may be
materially adversely affected if defects in title or boundaries
exist. In addition, in order to develop our reserves, we must
also own the rights to the related surface property and 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. In addition, from time
to time our permit applications have been challenged.
Growth
in our global operations increases our risks unique to
international mining and trading operations.
We currently have international mining operations in Australia.
We have business development, sales and marketing offices in
Beijing, China and Jakarta, Indonesia and an international
trading group in our Trading and Brokerage segment with offices
in London, England and Singapore. We also have joint venture
mining and exploration interests in Venezuela and Mongolia. In
addition, we are actively pursuing long-term operating, trading
and joint-venture opportunities in China, Mongolia, Mozambique,
Indonesia and India. 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 the potential for expropriation of assets and
limits on the repatriation of earnings. Despite our efforts to
mitigate these risks, our results of operation, financial
position or cash flow could be adversely affected by these
activities.
Risks
Associated with Our Indebtedness
We
could be adversely affected by the failure of financial
institutions to fulfill their commitments under our Senior
Unsecured Credit Facility.
As of December 31, 2009, we had $1.5 billion of
available borrowing capacity under our Senior Unsecured Credit
Facility, net of outstanding letters of credit. This committed
facility, which matures on September 15, 2011, is provided
by a syndicate of financial institutions, with each institution
agreeing severally (and not jointly) to make revolving credit
loans to us in accordance with the terms of the facility. If one
or more of the financial institutions providing the Senior
Unsecured Credit Facility were to default on its obligation to
fund its commitment, the portion of the facility provided by
such defaulting financial institution would not be available to
us.
Our
financial performance could be adversely affected by our
debt.
As of December 31, 2009, our total indebtedness was
$2.8 billion, and we had $1.5 billion of available
borrowing capacity under our Senior Unsecured Credit Facility.
The indentures governing our Convertible Junior Subordinated
Debentures (the Debentures) and 7.375% and 7.875% Senior
Notes do not limit the
23
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:
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making it more difficult for us to pay interest and satisfy our
debt obligations;
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increasing our vulnerability to general adverse economic and
industry conditions;
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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, Btu Conversion and clean coal technology projects
or other general corporate uses;
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limiting our ability to obtain additional financing to fund
future working capital, capital expenditures, acquisitions, Btu
Conversion and clean coal technology projects or other general
corporate requirements;
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limiting our flexibility in planning for, or reacting to,
changes in our business and in the coal industry; and
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placing us at a competitive disadvantage compared to less
leveraged competitors.
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In addition, our debt agreements subject 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.
The
covenants in our Senior Unsecured Credit Facility and the
indentures governing our Senior Notes and Debentures impose
restrictions that may limit our operating and financial
flexibility.
Our Senior Unsecured Credit Facility, the indentures governing
our 6.875% and 5.875% Senior Notes and 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 our Senior Unsecured Credit Facility and
our 6.875% and 5.875% Senior Notes and Debentures 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
24
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.
The
conversion of our Debentures may result in the dilution of the
ownership interests of our existing stockholders.
If the conditions permitting the conversion of our Debentures
are met and holders of the 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
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 Debentures could discourage an acquisition of us by a
third-party.
Certain provisions of our 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 Debentures, holders of our Debentures will have
the right, at their option, to convert their Debentures and
thereby require us to pay the principal amount of such
Debentures in cash.
Other
Business Risks
Under
certain circumstances, we could be responsible for certain
federal and state black lung occupational disease liabilities
assumed by Patriot in connection with its 2007 spin-off from
us.
Patriot is responsible for certain federal and state black lung
occupational disease liabilities, which are expected to be less
than $150 million, as well as related credit capacity in
support of these liabilities. Should Patriot not fund these
obligations as they become due, we could be responsible for such
costs when incurred.
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, which was a
liability of $982.2 million as of December 31, 2009,
$68.1 million of which was a current liability. Net pension
liabilities were $215.3 million as of December 31,
2009, $1.8 million of which was a current liability.
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 have made
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 or changes in medical
benefits provided by the government could increase our
obligation to satisfy these or additional obligations.
The decline in the stock market and real estate values which
occurred in 2008 and 2009 led to a decline in the value of our
pension plan assets which required an increase in contributions
in 2009 and will likely require increased contributions in
future years.
25
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 public and scientific
attention. Numerous reports, such as the Fourth Assessment
Report of the Intergovernmental Panel on Climate Change, have
also engendered concern about the impacts of human activity,
especially fossil fuel combustion, on global climate change. In
turn, increasing government attention is being paid to global
climate change and to emissions of what are commonly referred to
as greenhouse gases, including emissions of carbon dioxide from
coal combustion by power plants.
Enactment of laws or passage of regulations regarding emissions
from the combustion of coal by the U.S. or some of its
states or by other countries, or other actions to limit such
emissions, could result in electricity generators switching from
coal to other fuel sources. The potential financial impact on us
of future laws or regulations will depend upon the degree to
which any such laws or regulations forces electricity generators
to diminish their reliance on coal as a fuel source. That, in
turn, will depend on a number of factors, including the specific
requirements imposed by any such laws or regulations, the time
periods over which those laws or regulations would be phased in
and the state of commercial development and deployment of carbon
capture and storage technologies. In view of the significant
uncertainty surrounding each of these factors, it is not
possible for us to reasonably predict the impact that any such
laws or regulations may have on our results of operations,
financial condition or cash flows.
As we
continue to pursue Btu Conversion and clean coal technology
activities, we face challenges and risks that differ from others
in the mining business.
We continue to pursue opportunities to participate in
technologies to economically convert a portion of our coal
resources to natural gas and liquids such as diesel fuel,
gasoline and jet fuel (Btu Conversion). We are also promoting
the development of clean coal technologies that would reduce the
emissions from the use of coal,
and/or
capture and store the emissions from the use of coal. As we move
forward with 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.
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
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.
Diversity
in interpretation and application of accounting literature in
the mining industry may impact our reported financial
results.
The mining industry has limited industry-specific accounting
literature and, as a result, we understand diversity in practice
exists in the interpretation and application of accounting
literature to mining specific issues. 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
26
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.
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Item 1B.
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Unresolved
Staff Comments.
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None.
Coal
Reserves
We had an estimated 9.0 billion tons of proven and probable
coal reserves as of December 31, 2009. An estimated
7.9 billion tons of our proven and probable coal reserves
are in the U.S. and 1.1 billion tons are in Australia.
45% of our reserves, or 4.0 billion tons, are compliance
coal and 55% are non-compliance coal (assuming application of
the U.S. industry standard definition of compliance coal to
all of our reserves). We own approximately 39% of these reserves
and lease property containing the remaining 61%. 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.
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Proven and Probable
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Reserves as of
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December 31,
2009(1)
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Owned
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Leased
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Total
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Operating Regions
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Locations
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Tons
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Tons
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Tons
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(Tons in millions)
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Midwest
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Illinois, Indiana and Kentucky
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2,627
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939
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3,566
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Powder River Basin
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Wyoming and Montana
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67
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2,948
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3,015
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Southwest
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Arizona and New Mexico
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811
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309
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1,120
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Colorado
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Colorado
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44
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196
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240
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Total United States
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3,549
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4,392
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7,941
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Australia
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New South Wales
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451
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451
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Australia
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Queensland
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623
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623
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Total Australia
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1,074
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1,074
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Total Proven and Probable Coal Reserves
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3,549
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5,466
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9,015
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(1) |
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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 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
27
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 experienced
geologists. 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 is 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 expected 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 U.S. 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 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
28
and 8% for underground-mined coal. The U.S. 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, 2009, we leased
11,592 acres of federal land in Colorado, 11,256 acres
in Montana and 41,412 acres in Wyoming, for a total of
64,260 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
in the U.S.
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.
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.
With a portfolio of approximately 9.0 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.
29
The following chart provides a summary, by mining complex, of
production for the years ended December 31, 2009, 2008 and
2007, 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, 2009
|
|
|
|
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
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
Coal
|
|
Million Btu
|
|
|
Million Btu
|
|
|
Million Btu
|
|
|
per
pound(3)
|
|
|
Probable Reserves
|
|
|
Owned
|
|
|
Leased
|
|
|
Surface
|
|
|
Underground
|
|
|
Midwest:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Air Quality
|
|
|
1.6
|
|
|
|
1.9
|
|
|
|
2.1
|
|
|
Thermal
|
|
|
17
|
|
|
|
1
|
|
|
|
32
|
|
|
|
11,300
|
|
|
|
50
|
|
|
|
2
|
|
|
|
48
|
|
|
|
|
|
|
|
50
|
|
Bear Run
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Thermal
|
|
|
2
|
|
|
|
30
|
|
|
|
194
|
|
|
|
11,100
|
|
|
|
226
|
|
|
|
112
|
|
|
|
114
|
|
|
|
226
|
|
|
|
|
|
Miller Creek
|
|
|
2.0
|
|
|
|
1.9
|
|
|
|
1.6
|
|
|
Thermal
|
|
|
|
|
|
|
1
|
|
|
|
21
|
|
|
|
11,100
|
|
|
|
22
|
|
|
|
21
|
|
|
|
1
|
|
|
|
14
|
|
|
|
8
|
|
Francisco Surface (Mined out in 2009)
|
|
|
1.4
|
|
|
|
1.9
|
|
|
|
2.2
|
|
|
Thermal
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
11,100
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Francisco Underground
|
|
|
2.0
|
|
|
|
1.5
|
|
|
|
0.9
|
|
|
Thermal
|
|
|
|
|
|
|
|
|
|
|
46
|
|
|
|
11,300
|
|
|
|
46
|
|
|
|
8
|
|
|
|
38
|
|
|
|
|
|
|
|
46
|
|
Farmersburg
|
|
|
3.5
|
|
|
|
3.4
|
|
|
|
3.5
|
|
|
Thermal
|
|
|
|
|
|
|
1
|
|
|
|
20
|
|
|
|
10,900
|
|
|
|
21
|
|
|
|
18
|
|
|
|
3
|
|
|
|
21
|
|
|
|
|
|
Somerville Central
|
|
|
3.3
|
|
|
|
3.5
|
|
|
|
3.4
|
|
|
Thermal
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NA
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Somerville North
|
|
|
2.0
|
|
|
|
2.2
|
|
|
|
2.5
|
|
|
Thermal
|
|
|
|
|
|
|
|
|
|
|
2
|
|
|
|
11,200
|
|
|
|
2
|
|
|
|
2
|
|
|
|
|
|
|
|
2
|
|
|
|
|
|
Somerville South
|
|
|
1.8
|
|
|
|
2.2
|
|
|
|
2.5
|
|
|
Thermal
|
|
|
|
|
|
|
|
|
|
|
16
|
|
|
|
11,100
|
|
|
|
16
|
|
|
|
12
|
|
|
|
4
|
|
|
|
16
|
|
|
|
|
|
Viking
|
|
|
1.6
|
|
|
|
1.6
|
|
|
|
1.7
|
|
|
Thermal
|
|
|
|
|
|
|
1
|
|
|
|
6
|
|
|
|
11,500
|
|
|
|
7
|
|
|
|
|
|
|
|
7
|
|
|
|
7
|
|
|
|
|
|
Cottage Grove
|
|
|
0.7
|
|
|
|
0.7
|
|
|
|
0.9
|
|
|
Thermal
|
|
|
|
|
|
|
|
|
|
|
15
|
|
|
|
12,400
|
|
|
|
15
|
|
|
|
8
|
|
|
|
7
|
|
|
|
15
|
|
|
|
|
|
Wildcat Hills Underground
|
|
|
2.1
|
|
|
|
2.2
|
|
|
|
2.0
|
|
|
Thermal
|
|
|
|
|
|
|
|
|
|
|
23
|
|
|
|
12,200
|
|
|
|
23
|
|
|
|
15
|
|
|
|
8
|
|
|
|
|
|
|
|
23
|
|
Willow Lake
|
|
|
3.4
|
|
|
|
3.6
|
|
|
|
3.6
|
|
|
Thermal
|
|
|
|
|
|
|
|
|
|
|
25
|
|
|
|
12,100
|
|
|
|
25
|
|
|
|
18
|
|
|
|
7
|
|
|
|
|
|
|
|
25
|
|
Gateway
|
|
|
3.3
|
|
|
|
3.2
|
|
|
|
2.7
|
|
|
Thermal
|
|
|
|
|
|
|
|
|
|
|
18
|
|
|
|
11,000
|
|
|
|
18
|
|
|
|
17
|
|
|
|
1
|
|
|
|
|
|
|
|
18
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
28.7
|
|
|
|
29.8
|
|
|
|
29.6
|
|
|
|
|
|
19
|
|
|
|
34
|
|
|
|
418
|
|
|
|
|
|
|
|
471
|
|
|
|
233
|
|
|
|
238
|
|
|
|
301
|
|
|
|
170
|
|
Powder River Basin:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
North Antelope Rochelle
|
|
|
98.3
|
|
|
|
97.6
|
|
|
|
91.5
|
|
|
Thermal
|
|
|
850
|
|
|
|
|
|
|
|
9
|
|
|
|
8,700
|
|
|
|
859
|
|
|
|
|
|
|
|
859
|
|
|
|
859
|
|
|
|
|
|
Caballo
|
|
|
23.3
|
|
|
|
31.2
|
|
|
|
31.2
|
|
|
Thermal
|
|
|
681
|
|
|
|
131
|
|
|
|
33
|
|
|
|
8,200
|
|
|
|
845
|
|
|
|
|
|
|
|
845
|
|
|
|
845
|
|
|
|
|
|
Rawhide
|
|
|
15.8
|
|
|
|
18.4
|
|
|
|
17.2
|
|
|
Thermal
|
|
|
290
|
|
|
|
66
|
|
|
|
24
|
|
|
|
8,300
|
|
|
|
380
|
|
|
|
|
|
|
|
380
|
|
|
|
380
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
137.4
|
|
|
|
147.2
|
|
|
|
139.9
|
|
|
|
|
|
1,821
|
|
|
|
197
|
|
|
|
66
|
|
|
|
|
|
|
|
2,084
|
|
|
|
|
|
|
|
2,084
|
|
|
|
2,084
|
|
|
|
|
|
Southwest/Colorado:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Kayenta
|
|
|
7.5
|
|
|
|
8.0
|
|
|
|
8.0
|
|
|
Thermal
|
|
|
171
|
|
|
|
81
|
|
|
|
4
|
|
|
|
11,100
|
|
|
|
256
|
|
|
|
|
|
|
|
256
|
|
|
|
256
|
|
|
|
|
|
Lee Ranch
|
|
|
1.8
|
|
|
|
3.3
|
|
|
|
5.3
|
|
|
Thermal
|
|
|
19
|
|
|
|
144
|
|
|
|
21
|
|
|
|
9,400
|
|
|
|
184
|
|
|
|
144
|
|
|
|
40
|
|
|
|
184
|
|
|
|
|
|
Twentymile
|
|
|
7.8
|
|
|
|
8.0
|
|
|
|
8.3
|
|
|
Thermal
|
|
|
49
|
|
|
|
|
|
|
|
|
|
|
|
11,200
|
|
|
|
49
|
|
|
|
8
|
|
|
|
41
|
|
|
|
|
|
|
|
49
|
|
El Segundo
|
|
|
5.1
|
|
|
|
3.3
|
|
|
|
|
|
|
Thermal
|
|
|
25
|
|
|
|
88
|
|
|
|
69
|
|
|
|
9,300
|
|
|
|
182
|
|
|
|
168
|
|
|
|
14
|
|
|
|
182
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
22.2
|
|
|
|
22.6
|
|
|
|
21.6
|
|
|
|
|
|
264
|
|
|
|
313
|
|
|
|
94
|
|
|
|
|
|
|
|
671
|
|
|
|
320
|
|
|
|
351
|
|
|
|
622
|
|
|
|
49
|
|
Australia:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
North Goonyella / Eaglefield
|
|
|
2.5
|
|
|
|
2.8
|
|
|
|
2.8
|
|
|
Met.
|
|
|
38
|
|
|
|
|
|
|
|
|
|
|
|
12,900
|
|
|
|
38
|
|
|
|
|
|
|
|
38
|
|
|
|
3
|
|
|
|
35
|
|
Metropolitan
|
|
|
1.5
|
|
|
|
1.5
|
|
|
|
1.5
|
|
|
Met.
|
|
|
44
|
|
|
|
|
|
|
|
|
|
|
|
12,600
|
|
|
|
44
|
|
|
|
|
|
|
|
44
|
|
|
|
|
|
|
|
44
|
|
Wilkie Creek
|
|
|
2.3
|
|
|
|
2.6
|
|
|
|
2.4
|
|
|
Thermal
|
|
|
370
|
|
|
|
|
|
|
|
|
|
|
|
10,800
|
|
|
|
370
|
|
|
|
|
|
|
|
370
|
|
|
|
370
|
|
|
|
|
|
Wambo(4)
|
|
|
4.1
|
|
|
|
5.4
|
|
|
|
4.4
|
|
|
Thermal/Met.
|
|
|
201
|
|
|
|
|
|
|
|
|
|
|
|
12,200
|
|
|
|
201
|
|
|
|
|
|
|
|
201
|
|
|
|
33
|
|
|
|
168
|
|
Burton
(95.0%)(5)
|
|
|
2.0
|
|
|
|
2.6
|
|
|
|
3.1
|
|
|
Thermal/Met.
|
|
|
33
|
|
|
|
|
|
|
|
|
|
|
|
12,700
|
|
|
|
33
|
|
|
|
|
|
|
|
33
|
|
|
|
33
|
|
|
|
|
|
Wilpinjong
|
|
|
8.4
|
|
|
|
7.5
|
|
|
|
5.1
|
|
|
Thermal
|
|
|
|
|
|
|
206
|
|
|
|
|
|
|
|
11,200
|
|
|
|
206
|
|
|
|
|
|
|
|
206
|
|
|
|
206
|
|
|
|
|
|
Millennium
|
|
|
0.9
|
|
|
|
1.2
|
|
|
|
1.3
|
|
|
Met.
|
|
|
41
|
|
|
|
|
|
|
|
|
|
|
|
12,600
|
|
|
|
41
|
|
|
|
|
|
|
|
41
|
|
|
|
41
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
21.7
|
|
|
|
23.6
|
|
|
|
20.6
|
|
|
|
|
|
727
|
|
|
|
206
|
|
|
|
|
|
|
|
|
|
|
|
933
|
|
|
|
|
|
|
|
933
|
|
|
|
686
|
|
|
|
247
|
|
Total Continuing Operations
|
|
|
210.0
|
|
|
|
223.2
|
|
|
|
211.7
|
|
|
|
|
|
2,831
|
|
|
|
750
|
|
|
|
578
|
|
|
|
|
|
|
|
4,159
|
|
|
|
553
|
|
|
|
3,606
|
|
|
|
3,693
|
|
|
|
466
|
|
Discontinued Operations
|
|
|
0.8
|
|
|
|
2.0
|
|
|
|
19.4
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Assigned
|
|
|
210.8
|
|
|
|
225.2
|
|
|
|
231.1
|
|
|
|
|
|
2,831
|
|
|
|
750
|
|
|
|
578
|
|
|
|
|
|
|
|
4,159
|
|
|
|
553
|
|
|
|
3,606
|
|
|
|
3,693
|
|
|
|
466
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
30
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, 2009
(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
|
|
|
Proven
|
|
|
Probable
|
|
|
Coal
|
|
Million Btu
|
|
|
Million Btu
|
|
|
Million Btu
|
|
|
per
pound(3)
|
|
|
Owned
|
|
|
Leased
|
|
|
Surface
|
|
|
Underground
|
|
|
Midwest:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Illinois
|
|
|
81
|
|
|
|
2,193
|
|
|
|
2,274
|
|
|
|
1,161
|
|
|
|
1,113
|
|
|
Thermal
|
|
|
|
|
|
|
|
|
|
|
2,274
|
|
|
|
10,900
|
|
|
|
1,902
|
|
|
|
372
|
|
|
|
69
|
|
|
|
2,205
|
|
Indiana
|
|
|
390
|
|
|
|
412
|
|
|
|
802
|
|
|
|
571
|
|
|
|
231
|
|
|
Thermal
|
|
|
19
|
|
|
|
39
|
|
|
|
744
|
|
|
|
11,200
|
|
|
|
451
|
|
|
|
351
|
|
|
|
415
|
|
|
|
387
|
|
Kentucky
|
|
|
|
|
|
|
490
|
|
|
|
490
|
|
|
|
230
|
|
|
|
260
|
|
|
Thermal
|
|
|
|
|
|
|
1
|
|
|
|
489
|
|
|
|
11,800
|
|
|
|
274
|
|
|
|
216
|
|
|
|
20
|
|
|
|
470
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Midwest
|
|
|
471
|
|
|
|
3,095
|
|
|
|
3,566
|
|
|
|
1,962
|
|
|
|
1,604
|
|
|
|
|
|
19
|
|
|
|
40
|
|
|
|
3,507
|
|
|
|
|
|
|
|
2,627
|
|
|
|
939
|
|
|
|
504
|
|
|
|
3,062
|
|
Powder River Basin:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Montana
|
|
|
|
|
|
|
162
|
|
|
|
162
|
|
|
|
158
|
|
|
|
4
|
|
|
Thermal
|
|
|
9
|
|
|
|
121
|
|
|
|
32
|
|
|
|
8,500
|
|
|
|
67
|
|
|
|
95
|
|
|
|
162
|
|
|
|
|
|
Wyoming
|
|
|
2,084
|
|
|
|
769
|
|
|
|
2,853
|
|
|
|
2,811
|
|
|
|
42
|
|
|
Thermal
|
|
|
2,625
|
|
|
|
196
|
|
|
|
32
|
|
|
|
8,500
|
|
|
|
|
|
|
|
2,853
|
|
|
|
2,853
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Powder River Basin
|
|
|
2,084
|
|
|
|
931
|
|
|
|
3,015
|
|
|
|
2,969
|
|
|
|
46
|
|
|
|
|
|
2,634
|
|
|
|
317
|
|
|
|
64
|
|
|
|
|
|
|
|
67
|
|
|
|
2,948
|
|
|
|
3,015
|
|
|
|
|
|
Southwest/Colorado:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Arizona
|
|
|
256
|
|
|
|
|
|
|
|
256
|
|
|
|
256
|
|
|
|
|
|
|
Thermal
|
|
|
173
|
|
|
|
81
|
|
|
|
2
|
|
|
|
11,100
|
|
|
|
|
|
|
|
256
|
|
|
|
256
|
|
|
|
|
|
Colorado
|
|
|
49
|
|
|
|
191
|
|
|
|
240
|
|
|
|
149
|
|
|
|
91
|
|
|
Thermal
|
|
|
193
|
|
|
|
|
|
|
|
47
|
|
|
|
10,700
|
|
|
|
44
|
|
|
|
196
|
|
|
|
|
|
|
|
240
|
|
New Mexico
|
|
|
366
|
|
|
|
498
|
|
|
|
864
|
|
|
|
777
|
|
|
|
87
|
|
|
Thermal
|
|
|
160
|
|
|
|
373
|
|
|
|
331
|
|
|
|
9,000
|
|
|
|
811
|
|
|
|
53
|
|
|
|
848
|
|
|
|
16
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Southwest
|
|
|
671
|
|
|
|
689
|
|
|
|
1,360
|
|
|
|
1,182
|
|
|
|
178
|
|
|
|
|
|
526
|
|
|
|
454
|
|
|
|
380
|
|
|
|
|
|
|
|
855
|
|
|
|
505
|
|
|
|
1,104
|
|
|
|
256
|
|
Australia:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
New South Wales
|
|
|
451
|
|
|
|
|
|
|
|
451
|
|
|
|
372
|
|
|
|
79
|
|
|
Thermal/Met.
|
|
|
247
|
|
|
|
204
|
|
|
|
|
|
|
|
11,800
|
|
|
|
|
|
|
|
451
|
|
|
|
249
|
|
|
|
202
|
|
Queensland
|
|
|
482
|
|
|
|
141
|
|
|
|
623
|
|
|
|
351
|
|
|
|
272
|
|
|
Thermal/Met.
|
|
|
623
|
|
|
|
|
|
|
|
|
|
|
|
11,300
|
|
|
|
|
|
|
|
623
|
|
|
|
588
|
|
|
|
35
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Australia
|
|
|
933
|
|
|
|
141
|
|
|
|
1,074
|
|
|
|
723
|
|
|
|
351
|
|
|
|
|
|
870
|
|
|
|
204
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,074
|
|
|
|
837
|
|
|
|
237
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Proven and Probable
|
|
|
4,159
|
|
|
|
4,856
|
|
|
|
9,015
|
|
|
|
6,836
|
|
|
|
2,179
|
|
|
|
|
|
4,049
|
|
|
|
1,015
|
|
|
|
3,951
|
|
|
|
|
|
|
|
3,549
|
|
|
|
5,466
|
|
|
|
5,460
|
|
|
|
3,555
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
31
|
|
|
(1) |
|
Assigned reserves represent recoverable coal reserves that are
controlled and accessible at active operations as of
December 31, 2009. Unassigned reserves represent coal at
currently non-producing locations that 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 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. |
|
(4) |
|
The North Wambo Underground Mine produces both thermal and
pulverized coal injection, or PCI metallurgical coal. |
|
(5) |
|
Proven and probable coal reserves for our Burton Mine reflects
our 95% proportional ownership and consolidation. |
|
|
Item 3.
|
Legal
Proceedings.
|
See Note 20 to our consolidated financial statements for a
description of our pending legal proceedings, which is
incorporated herein by reference.
|
|
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, 2009.
Executive
Officers of the Company
Set forth below are the names, ages as of February 24, 2010
and current positions of our executive officers. Executive
officers are appointed by, and hold office at the discretion of,
our Board of Directors, subject to the terms of any employment
agreements.
|
|
|
|
|
|
|
Name
|
|
Age
|
|
Position
|
|
Gregory H. Boyce
|
|
|
55
|
|
|
Chairman and Chief Executive Officer, Director
|
Richard A. Navarre
|
|
|
49
|
|
|
President and Chief Commercial Officer
|
Michael C. Crews
|
|
|
43
|
|
|
Executive Vice President and Chief Financial Officer
|
Sharon D. Fiehler
|
|
|
53
|
|
|
Executive Vice President and Chief Administrative Officer
|
Eric Ford
|
|
|
55
|
|
|
Executive Vice President and Chief Operating Officer
|
Alexander C. Schoch
|
|
|
55
|
|
|
Executive Vice President Law, Chief Legal Officer and Secretary
|
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 in
March 2005, and assumed the position of Chief Executive Officer
in January 2006. Mr. Boyce served as our President from
October 2003 to December 2007 and as our Chief Operating Officer
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 serves on the
board of
32
directors of Marathon Oil Corporation. He is Vice Chairman of
the World Coal Institute and the National Mining Association. He
is a member of the National Coal Council and the Coal Industry
Advisory Board of the International Energy Agency. He is a Board
member of the Business Roundtable, and the American Coalition
for Clean Coal Electricity. He is a member of the Board of
Trustees of St. Louis Childrens Hospital; the Board
of Trustees of Washington University in St. Louis; the
School of Engineering and Applied Science National Council at
Washington University in St. Louis; and the Advisory
Council of the University of Arizonas Department of Mining
and Geological Engineering.
Richard A. Navarre is our President and Chief Commercial
Officer. He previously served as our Executive Vice President of
Corporate Development and Chief Financial Officer from July 2006
to January 2008 and as Chief Financial Officer from October 1999
to June 2008. Mr. Navarre 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 and the School of Accountancy of
Southern Illinois University Carbondale; a member of the
International Business Advisory Board of the University of
Missouri St. Louis; a member of the Board of
Directors of the Regional Chamber and Growth Association of
St. Louis; a Director of the United Way of Greater
St. Louis; a Vice Chair of the Missouri Historical Society;
a member of Financial Executives International and the Civic
Entrepreneurs Organization; Fellow, Foreign Policy Association;
and a former chairman of the Bituminous Coal Operators
Association.
Michael C. Crews was named our Executive Vice President and
Chief Financial Officer in June 2008. He joined us in 1998 as
Senior Manager of Financial Reporting, and has served as
Assistant Corporate Controller, Director of Planning, Assistant
Treasurer, Vice President of Planning, Analysis, and Performance
Assessment, and Vice President of Operations Planning. Prior to
joining us, Mr. Crews served for three years in financial
positions with MEMC Electronic Materials, Inc. and six years at
KPMG Peat Marwick in St. Louis. He has a Bachelor of
Science degree in Accountancy from the University of Missouri at
Columbia and a Master of Business Administration (MBA) degree
from Washington University in St. Louis.
Sharon D. Fiehler has been our Executive Vice President and
Chief Administrative Officer since January 2008. 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
Director of the Federal Reserve Bank of St. Louis. She is a
member of the Executive Committee and Board of Directors of
Junior Achievement of St. Louis; a member of the Board of
Directors of the St. Louis Zoo Association; and President
of the Chancellors Council of the University of Missouri
St. Louis. She was a recipient of the 2006 St. Louis
Business Journal Most Influential Women Award and a recipient of
the 2008 YWCA Leader of Distinction Award.
Eric Ford was named our Executive Vice President and Chief
Operating Officer in March 2007. Mr. Ford has 38 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 was previously Deputy Chairman and a member of the Executive
Committee of the Coal Industry Advisory Board of the
International Energy Agency, and Vice Chairman and Director of
the Minerals Council of Australia.
Alexander C. Schoch was named our Executive Vice President Law
and Chief Legal Officer in October 2006 and our Secretary in May
2008. Prior to joining us, Mr. Schoch served as Vice
President and General Counsel for Emerson Process Management, an
operating segment of Emerson Electric Co. and a leading supplier
of process-automation products, from August 2004 to October
2006. Mr. Schoch also served in
33
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.
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 12, 2010, there
were 1,395 holders of record of our common stock.
The table below sets forth the range of quarterly high and low
sales prices (including intraday prices) for our common stock on
the New York Stock Exchange during the calendar quarters
indicated.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Share Price
|
|
Dividends
|
|
|
High
|
|
Low
|
|
Paid
|
|
2008
|
|
|
|
|
|
|
|
|
|
|
|
|
First Quarter
|
|
$
|
63.97
|
|
|
$
|
42.05
|
|
|
$
|
0.06
|
|
Second Quarter
|
|
|
88.69
|
|
|
|
49.38
|
|
|
|
0.06
|
|
Third Quarter
|
|
|
88.39
|
|
|
|
39.06
|
|
|
|
0.06
|
|
Fourth Quarter
|
|
|
43.99
|
|
|
|
16.00
|
|
|
|
0.06
|
|
2009
|
|
|
|
|
|
|
|
|
|
|
|
|
First Quarter
|
|
$
|
30.95
|
|
|
$
|
20.17
|
|
|
$
|
0.06
|
|
Second Quarter
|
|
|
37.44
|
|
|
|
23.56
|
|
|
|
0.06
|
|
Third Quarter
|
|
|
41.54
|
|
|
|
27.19
|
|
|
|
0.06
|
|
Fourth Quarter
|
|
|
48.21
|
|
|
|
34.54
|
|
|
|
0.07
|
|
Dividend
Policy
We paid quarterly dividends totaling $0.25 per share and $0.24
per share for the years ended December 31, 2009 and 2008,
respectively. Most recently, our Board of Directors declared a
dividend of $0.07 per share of Common Stock on January 27,
2010, payable on March 3, 2010, to stockholders of record
on February 10, 2010. 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.
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
Our Board of Directors has authorized a share repurchase program
of up to $1 billion of the then 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. Our Chairman and Chief Executive Officer also has the
authority to direct us to repurchase up to $100 million of
our common stock outside the share repurchase program. The
repurchase program does not have an expiration date and may be
discontinued at any time. Through December 31, 2009, we
have made repurchases of 7.7 million shares at a cost of
$299.6 million, leaving $700.4 million available for
share repurchase under the program.
34
The following table summarizes all share repurchases for the
three months ended December 31, 2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Maximum Dollar
|
|
|
|
|
|
|
|
|
|
|
|
|
Value that May Yet
|
|
|
|
|
|
|
|
|
|
Total Number of
|
|
|
Be Used to
|
|
|
|
Total
|
|
|
|
|
|
Shares Purchased
|
|
|
Repurchase
|
|
|
|
Number of
|
|
|
Average
|
|
|
as Part of Publicly
|
|
|
Shares Under the
|
|
|
|
Shares
|
|
|
Price per
|
|
|
Announced
|
|
|
Publicly Announced
|
|
Period
|
|
Purchased(1)
|
|
|
Share
|
|
|
Program
|
|
|
Program (in millions)
|
|
|
October 1 through October 31, 2009
|
|
|
558
|
|
|
$
|
43.37
|
|
|
|
|
|
|
$
|
700.4
|
|
November 1 through November 30, 2009
|
|
|
1,358
|
|
|
|
39.59
|
|
|
|
|
|
|
$
|
700.4
|
|
December 1 through December 31, 2009
|
|
|
570
|
|
|
|
45.21
|
|
|
|
|
|
|
$
|
700.4
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
2,486
|
|
|
$
|
41.73
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Represents 2,486 shares withheld to cover the withholding
taxes upon the vesting 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 2009,
2008 and 2007 in Item 7. Managements Discussion and
Analysis of Financial Condition and Results of Operations
includes references to, and analysis of, our Adjusted EBITDA
results. We define Adjusted EBITDA as income from continuing
operations before deducting net interest expense, income taxes,
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 U.S. generally accepted
accounting principles (GAAP), as reflected at the end of
Item 6. Selected Financial Data. and in Note 22 to our
consolidated financial statements.
The selected financial data for all periods presented reflect
the assets, liabilities and results of operations from
subsidiaries spun off as Patriot as discontinued operations. We
also have classified as discontinued operations those operations
recently divested, as well as certain non-strategic mining
assets held for sale where we have committed to the divestiture
of such assets.
In October 2006, we acquired Excel. Our results of operations
include Excels results of operations from the date of
acquisition.
We have derived the selected historical financial data as of and
for the years ended December 31, 2009, 2008, 2007, 2006 and
2005 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.
35
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,
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
(In millions, except per share data)
|
|
|
Results of Operations Data
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
$
|
6,012.4
|
|
|
$
|
6,561.0
|
|
|
$
|
4,523.8
|
|
|
$
|
4,045.6
|
|
|
$
|
3,597.9
|
|
Costs and expenses
|
|
|
5,167.6
|
|
|
|
5,164.7
|
|
|
|
3,924.1
|
|
|
|
3,432.8
|
|
|
|
3,166.3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating profit
|
|
|
844.8
|
|
|
|
1,396.3
|
|
|
|
599.7
|
|
|
|
612.8
|
|
|
|
431.6
|
|
Interest expense, net
|
|
|
193.1
|
|
|
|
217.0
|
|
|
|
228.8
|
|
|
|
127.8
|
|
|
|
88.9
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from continuing operations before income taxes
|
|
|
651.7
|
|
|
|
1,179.3
|
|
|
|
370.9
|
|
|
|
485.0
|
|
|
|
342.7
|
|
Income tax provision (benefit)
|
|
|
193.8
|
|
|
|
191.4
|
|
|
|
(70.7
|
)
|
|
|
(85.6
|
)
|
|
|
62.3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from continuing operations, net of income taxes
|
|
|
457.9
|
|
|
|
987.9
|
|
|
|
441.6
|
|
|
|
570.6
|
|
|
|
280.4
|
|
Income (loss) from discontinued operations, net of income taxes
|
|
|
5.1
|
|
|
|
(28.8
|
)
|
|
|
(180.1
|
)
|
|
|
30.7
|
|
|
|
144.8
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
|
463.0
|
|
|
|
959.1
|
|
|
|
261.5
|
|
|
|
601.3
|
|
|
|
425.2
|
|
Less: net income (loss) attributable to noncontrolling interests
|
|
|
14.8
|
|
|
|
6.2
|
|
|
|
(2.3
|
)
|
|
|
0.6
|
|
|
|
2.5
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income attributable to common stockholders
|
|
$
|
448.2
|
|
|
$
|
952.9
|
|
|
$
|
263.8
|
|
|
$
|
600.7
|
|
|
$
|
422.7
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic earnings per share from continuing
operations(1)
|
|
$
|
1.66
|
|
|
$
|
3.63
|
|
|
$
|
1.67
|
|
|
$
|
2.15
|
|
|
$
|
1.06
|
|
Diluted earnings per share from continuing
operations(1)
|
|
$
|
1.64
|
|
|
$
|
3.60
|
|
|
$
|
1.64
|
|
|
$
|
2.11
|
|
|
$
|
1.04
|
|
Weighted average shares used in calculating basic earnings per
share
|
|
|
265.5
|
|
|
|
268.9
|
|
|
|
264.1
|
|
|
|
263.4
|
|
|
|
261.5
|
|
Weighted average shares used in calculating diluted earnings per
share
|
|
|
267.5
|
|
|
|
270.7
|
|
|
|
268.6
|
|
|
|
268.8
|
|
|
|
267.3
|
|
Dividends declared per share
|
|
$
|
0.25
|
|
|
$
|
0.24
|
|
|
$
|
0.24
|
|
|
$
|
0.24
|
|
|
$
|
0.17
|
|
Other Data
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Tons sold
|
|
|
243.6
|
|
|
|
255.0
|
|
|
|
235.5
|
|
|
|
221.2
|
|
|
|
213.7
|
|
Net cash provided by (used in) continuing operations:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating activities
|
|
$
|
1,053.5
|
|
|
$
|
1,409.8
|
|
|
$
|
460.7
|
|
|
$
|
611.1
|
|
|
$
|
672.4
|
|
Investing activities
|
|
|
(408.2
|
)
|
|
|
(419.3
|
)
|
|
|
(538.9
|
)
|
|
|
(2,055.6
|
)
|
|
|
(506.3
|
)
|
Financing activities
|
|
|
(102.3
|
)
|
|
|
(487.0
|
)
|
|
|
41.7
|
|
|
|
1,403.0
|
|
|
|
(41.4
|
)
|
Adjusted EBITDA
|
|
|
1,290.1
|
|
|
|
1,846.9
|
|
|
|
969.7
|
|
|
|
909.7
|
|
|
|
696.4
|
|
Balance Sheet Data (at period end)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
9,955.3
|
|
|
$
|
9,695.6
|
|
|
$
|
9,082.3
|
|
|
$
|
9,504.7
|
|
|
$
|
6,852.0
|
|
Total long-term debt (including capital leases)
|
|
|
2,752.3
|
|
|
|
2,793.6
|
|
|
|
2,909.0
|
|
|
|
2,911.6
|
|
|
|
1,332.0
|
|
Total stockholders equity
|
|
|
3,755.9
|
|
|
|
3,119.5
|
|
|
|
2,735.3
|
|
|
|
2,587.0
|
|
|
|
2,178.5
|
|
|
|
|
(1) |
|
Effective January 1, 2009, we adopted the two-class method
to compute basic and diluted earnings per share. This method has
been retrospectively applied to all periods presented. |
36
Adjusted EBITDA is calculated as follows (unaudited):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
(Dollars in millions)
|
|
|
Income from continuing operations, net of income taxes
|
|
$
|
457.9
|
|
|
$
|
987.9
|
|
|
$
|
441.6
|
|
|
$
|
570.6
|
|
|
$
|
280.4
|
|
Income tax provision (benefit)
|
|
|
193.8
|
|
|
|
191.4
|
|
|
|
(70.7
|
)
|
|
|
(85.6
|
)
|
|
|
62.3
|
|
Depreciation, depletion and amortization
|
|
|
405.2
|
|
|
|
402.4
|
|
|
|
346.3
|
|
|
|
282.7
|
|
|
|
244.9
|
|
Asset retirement obligation expense
|
|
|
40.1
|
|
|
|
48.2
|
|
|
|
23.7
|
|
|
|
14.2
|
|
|
|
19.9
|
|
Interest expense, net
|
|
|
193.1
|
|
|
|
217.0
|
|
|
|
228.8
|
|
|
|
127.8
|
|
|
|
88.9
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted EBITDA
|
|
$
|
1,290.1
|
|
|
$
|
1,846.9
|
|
|
$
|
969.7
|
|
|
$
|
909.7
|
|
|
$
|
696.4
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Item 7.
|
Managements
Discussion and Analysis of Financial Condition and Results of
Operations.
|
Overview
We are the worlds largest private sector coal company,
with majority interests in 28 coal mining operations in the
U.S. and Australia. In 2009, we produced 210.0 million
tons of coal and sold 243.6 million tons of coal. For 2009,
our U.S. sales represented 19% of U.S. coal
consumption and were approximately 50% greater than the sales of
our closest U.S. competitor.
We conduct business through four principal segments: Western
U.S. Mining, Midwestern U.S. Mining, Australian
Mining, and Trading and Brokerage. The principal business of the
Western and Midwestern U.S. Mining segments is the mining,
preparation and sale of thermal coal, sold primarily to electric
utilities. Our Western U.S. Mining operations consist of
our Powder River Basin, Southwest and Colorado operations. Our
Midwestern U.S. Mining operations consist of our Illinois
and Indiana operations. The business of our Australian Mining
Segment is the mining of various qualities of low-sulfur, high
Btu coal (metallurgical coal) as well as thermal coal primarily
sold to an international customer base with a portion sold to
Australian steel producers and power generators. Metallurgical
coal is produced primarily from five of our Australian mines. In
2009, metallurgical coal was approximately 3% of our total sales
volume, but represented a larger share of our revenue,
approximately 23%.
We typically sell coal to utility customers under long-term
contracts (those with terms longer than one year). During 2009,
approximately 93% of our worldwide sales (by volume) were under
long-term contracts. For the year ended December 31, 2009,
81% of our total sales (by volume) were to U.S. electricity
generators, 17% were to customers outside the U.S. and 2%
were to the U.S. industrial sector.
Our Trading and Brokerage segments principal business is
the brokering of coal sales of other producers both as principal
and agent, and the trading of coal, freight and freight-related
contracts. We also provide transportation-related services in
support of our coal trading strategy, as well as hedging
activities in support of our mining operations.
Our fifth segment, Corporate and Other, includes mining and
export/transportation joint ventures, energy-related commercial
activities, as well as the management of our vast coal reserve
and real estate holdings.
We continue to pursue development of coal-fueled generating and
Btu Conversion 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. Coal-fueled
generating projects may 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.
Currently, we own 5.06% of the 1,600-megawatt Prairie State
Energy Campus that is under construction in Washington County,
Illinois.
We are determining how to best participate in Btu Conversion
technologies to economically convert our coal resources to
natural gas and transportation fuels through the Kentucky NewGas
and GreatPoint Energy projects in the U.S. We are also
advancing the development of clean coal technologies, including
carbon
37
capture and sequestration, through a number of initiatives that
include the FutureGen Alliance and university research programs
in the U.S., GreenGen in China and COAL21 Fund in Australia.
As discussed more fully in Item 1A. Risk Factors, our
results of operations in the near-term could be negatively
impacted by the rate of the economic recovery, adverse 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 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. We may adjust
our production levels further in response to changes in market
demand.
Year
Ended December 31, 2009 Compared to Year Ended
December 31, 2008
Summary
Our overall results for 2009 compared to 2008 reflect the
unfavorable impact of lower global demand for coal as a result
of the global economic recession. Despite the recession, our
2009 Adjusted EBITDA was the second highest in our
126-year
history and second only to our 2008 Adjusted EBITDA. We also
ended 2009 with total available liquidity of $2.5 billion.
We continue to focus on strong cost control and productivity
improvements, increased contributions from our high-margin
operations and exercising tight capital discipline.
Our 2009 tons sold were below prior year levels reflecting
planned production reductions in the Powder River Basin to match
lower demand, partially offset by increased volumes associated
with the full-year operation of our El Segundo Mine in the
Southwest. In the U.S., the decreased demand from lower
industrial output, lower natural gas prices that resulted in
higher fuel switching, and higher coal stockpiles in the
U.S. led to an 8.5 million ton decline in sales
volume. In Australia, lower demand from steel customers resulted
in a 1.3 million ton decline in metallurgical coal volume,
although volumes in the second half of 2009 began to increase on
an improved economic outlook led by demand from Asian-Pacific
markets.
Our 2009 revenues declined compared to 2008 and were primarily
impacted by Australias lower annual export contract
pricing that commenced on April 1, 2009 as compared to
2008s record pricing and the overall decline in volume.
Lower revenues were also driven by the decline in Trading and
Brokerage revenues that resulted from lower coal pricing
volatility. The lower Australian and Trading and Brokerage
revenues were partially offset by an increase in
U.S. revenues per ton that reflect multi-year contracts
signed at higher prices in recent years.
While our Segment Adjusted EBITDA reflects the lower revenue
discussed above, our 2009 margins also reflect the impact of
producing at reduced levels as well as higher sales related
costs. In addition, our costs in Australia were higher due to
two additional longwall moves compared to 2008 and the impact of
mining in difficult geologic conditions that also included
higher costs for overburden removal.
Net income declined in 2009 compared to 2008 reflecting the
above items, as well as lower results from equity affiliates and
decreased net gains on disposals of assets. Income from
continuing operations, net of income taxes was
$457.9 million in 2009, or $1.64 per diluted share, 53.6%
below 2008 income from continuing operations, net of income
taxes of $987.9 million, or $3.60 per diluted share.
38
Tons
Sold
The following table presents tons sold by operating segment for
the years ended December 31, 2009 and 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
Increase (Decrease)
|
|
|
|
2009
|
|
|
2008
|
|
|
Tons
|
|
|
%
|
|
|
|
(Tons in millions)
|
|
|
Western U.S. Mining
|
|
|
160.1
|
|
|
|
169.7
|
|
|
|
(9.6
|
)
|
|
|
(5.7
|
)%
|
Midwestern U.S. Mining
|
|
|
31.8
|
|
|
|
30.7
|
|
|
|
1.1
|
|
|
|
3.6
|
%
|
Australian Mining
|
|
|
22.3
|
|
|
|
23.4
|
|
|
|
(1.1
|
)
|
|
|
(4.7
|
)%
|
Trading and Brokerage
|
|
|
29.4
|
|
|
|
31.2
|
|
|
|
(1.8
|
)
|
|
|
(5.8
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total tons sold
|
|
|
243.6
|
|
|
|
255.0
|
|
|
|
(11.4
|
)
|
|
|
(4.5
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues
The following table presents revenues for the years ended
December 31, 2009 and 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Increase (Decrease)
|
|
|
|
Year Ended December 31,
|
|
|
to Revenues
|
|
|
|
2009
|
|
|
2008
|
|
|
$
|
|
|
%
|
|
|
|
(Dollars in millions)
|
|
|
Western U.S. Mining
|
|
$
|
2,612.6
|
|
|
$
|
2,533.1
|
|
|
$
|
79.5
|
|
|
|
3.1
|
%
|
Midwestern U.S. Mining
|
|
|
1,303.8
|
|
|
|
1,154.6
|
|
|
|
149.2
|
|
|
|
12.9
|
%
|
Australian Mining
|
|
|
1,678.0
|
|
|
|
2,242.8
|
|
|
|
(564.8
|
)
|
|
|
(25.2
|
)%
|
Trading and Brokerage
|
|
|
391.0
|
|
|
|
601.8
|
|
|
|
(210.8
|
)
|
|
|
(35.0
|
)%
|
Other
|
|
|
27.0
|
|
|
|
28.7
|
|
|
|
(1.7
|
)
|
|
|
(5.9
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
$
|
6,012.4
|
|
|
$
|
6,561.0
|
|
|
$
|
(548.6
|
)
|
|
|
(8.4
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009 revenues were below prior year driven by decreases in
our Australian Mining and Trading and Brokerage segments as
discussed below:
|
|
|
|
|
Australian Mining operations average sales price decreased
21.4% from the prior year reflecting the lower annual export
contract pricing that commenced April 1, 2009 compared to
the record pricing realized in 2008. The price decreases were
combined with volume decreases from the prior year (4.7%) due to
overall lower demand experienced in the first half of 2009. 2009
metallurgical coal shipments of 6.9 million tons were
1.3 million tons below prior year. In the second half of
2009, 5.0 million tons of metallurgical coal were shipped,
reflecting a partial recovery from the lower metallurgical coal
shipments that occurred in the first half of the year.
|
|
|
|
Trading and Brokerage revenues decreased from the prior year
primarily due to lower coal pricing volatility in 2009 resulting
in lower margins on trading transactions, partially offset by
profit from business contracted in 2008 that was realized in
2009 on an international brokerage arrangement.
|
These decreases to revenues were partially offset by revenue
increases in our Midwestern U.S. and Western
U.S. Mining segments as discussed below:
|
|
|
|
|
Midwestern U.S. Mining operations average sales price
increased over the prior year (9.3%) driven by the benefit of
higher Illinois Basin prices and increased shipments, including
purchased coal used to satisfy certain coal supply agreements.
|
|
|
|
Western U.S. Mining operations average sales price
increased over the prior year (9.2%) due to a combination of
higher contract pricing and a shift in sales mix. Revenues were
also higher due to increased shipments from our El Segundo Mine
(commissioned in June 2008) and customer contract
termination and restructuring agreements. These increases were
partially offset by the prior year
|
39
|
|
|
|
|
revenue recovery on a long-term coal supply agreement
($56.9 million) and an overall volume decrease (5.7%)
reflecting our planned Powder River Basin production decreases
to match demand.
|
Segment
Adjusted EBITDA
The following table presents segment Adjusted EBITDA for the
years ended December 31, 2009 and 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Increase (Decrease) to
|
|
|
|
Year Ended December 31,
|
|
|
Segment Adjusted EBITDA
|
|
|
|
2009
|
|
|
2008
|
|
|
$
|
|
|
%
|
|
|
|
(Dollars in millions)
|
|
|
Western U.S. Mining
|
|
$
|
721.5
|
|
|
$
|
681.3
|
|
|
$
|
40.2
|
|
|
|
5.9
|
%
|
Midwestern U.S. Mining
|
|
|
281.9
|
|
|
|
177.3
|
|
|
|
104.6
|
|
|
|
59.0
|
%
|
Australian Mining
|
|
|
437.8
|
|
|
|
1,016.6
|
|
|
|
(578.8
|
)
|
|
|
(56.9
|
)%
|
Trading and Brokerage
|
|
|
193.4
|
|
|
|
218.9
|
|
|
|
(25.5
|
)
|
|
|
(11.6
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Segment Adjusted EBITDA
|
|
$
|
1,634.6
|
|
|
$
|
2,094.1
|
|
|
$
|
(459.5
|
)
|
|
|
(21.9
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Australian Mining operations Adjusted EBITDA decreased
compared to the prior year due to lower annual export contract
pricing and lower sales volume due to reduced demand
($416.0 million) as discussed above. Also impacting the
segments Adjusted EBITDA was higher production costs
($170.7 million) driven by increased overburden stripping
ratios and decreased longwall mine performance, which included
higher costs associated with two additional longwall moves in
2009 compared to 2008.
Trading and Brokerage Adjusted EBITDA decreased compared to
prior year primarily due to lower net revenue discussed above.
Western U.S. Mining operations Adjusted EBITDA
increased over the prior year driven by higher pricing
($205.5 million), partially offset by lower demand
($63.2 million), a prior year revenue recovery on a
long-term coal supply agreement ($56.9 million), higher
sales related costs ($52.0 million) and lower productivity
due to increased stripping ratios ($20.8 million). The
impact of lower demand was partially mitigated by revenues from
customer contract termination and restructuring agreements
($27.8 million).
Midwestern U.S. Mining operations Adjusted EBITDA
increased over the prior year primarily due to higher pricing
($110.7 million) and decreased commodity costs
($16.0 million), partially offset by higher costs
associated with mining in more difficult geological conditions
compared to the prior year ($20.7 million).
Income
From Continuing Operations Before Income Taxes
The following table presents income from continuing operations
before income taxes for the years ended December 31, 2009
and 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Increase (Decrease)
|
|
|
|
Year Ended December 31,
|
|
|
to Income
|
|
|
|
2009
|
|
|
2008
|
|
|
$
|
|
|
%
|
|
|
|
(Dollars in millions)
|
|
|
Total Segment Adjusted EBITDA
|
|
$
|
1,634.6
|
|
|
$
|
2,094.1
|
|
|
$
|
(459.5
|
)
|
|
|
(21.9
|
)%
|
Corporate and Other Adjusted EBITDA
|
|
|
(344.5
|
)
|
|
|
(247.2
|
)
|
|
|
(97.3
|
)
|
|
|
(39.4
|
)%
|
Depreciation, depletion and amortization
|
|
|
(405.2
|
)
|
|
|
(402.4
|
)
|
|
|
(2.8
|
)
|
|
|
(0.7
|
)%
|
Asset retirement obligation expense
|
|
|
(40.1
|
)
|
|
|
(48.2
|
)
|
|
|
8.1
|
|
|
|
16.8
|
%
|
Interest expense
|
|
|
(201.2
|
)
|
|
|
(227.0
|
)
|
|
|
25.8
|
|
|
|
11.4
|
%
|
Interest income
|
|
|
8.1
|
|
|
|
10.0
|
|
|
|
(1.9
|
)
|
|
|
(19.0
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from continuing operations before income taxes
|
|
$
|
651.7
|
|
|
$
|
1,179.3
|
|
|
$
|
(527.6
|
)
|
|
|
(44.7
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
40
Income from continuing operations before income taxes decreased
from prior year primarily due to the lower Total Segment
Adjusted EBITDA discussed above and lower Corporate and Other
Adjusted EBITDA, partially offset by lower interest expense and
asset retirement obligation expense.
The decrease of $97.3 million in Corporate and Other
Adjusted EBITDA during 2009 compared to 2008 was due to the
following:
|
|
|
|
|
Lower results from equity affiliates ($69.1 million)
primarily from our joint venture interest in Carbones del
Guasare (owner and operator of the Paso Diablo Mine in
Venezuela). Carbones del Guasare incurred unfavorable results in
2009 compared to 2008 (our share of which was
$25.6 million) due to lower productivity, higher operating
costs and ongoing labor issues; in addition, we recognized a
$34.7 million impairment loss on this investment. See
Note 1 to our consolidated financial statements for
additional information concerning this joint venture interest.
|
|
|
|
Lower net gains on disposal or exchange of assets
($49.7 million) was due primarily to a $54.0 million
gain in the prior year from the sale of non-strategic coal
reserves and surface lands located in Kentucky.
|
|
|
|
The above decreases to Corporate and Other Adjusted EBITDA were
offset by lower costs associated with Btu Conversion activities
($16.9 million).
|
Interest expense was lower than prior year due to lower variable
interest rates on our Term Loan Facility and accounts receivable
securitization program and lower average borrowings on our
Revolving Credit Facility.
Asset retirement obligation expense decreased in 2009 as
compared to the prior year due primarily to a decrease in the
ongoing and closed mine reclamation rates reflecting lower fuel
and re-vegetation costs incurred in our Midwestern
U.S. Mining segment.
Net
Income Attributable to Common Stockholders
The following table presents net income attributable to common
stockholders for the years ended December 31, 2009 and 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Increase (Decrease)
|
|
|
|
(Dollars in millions)
|
|
|
to Income
|
|
|
|
2009
|
|
|
2008
|
|
|
$
|
|
|
%
|
|
|
|
|
|
|
(Dollars in millions)
|
|
|
|
|
|
Income from continuing operations before income taxes
|
|
$
|
651.7
|
|
|
$
|
1,179.3
|
|
|
$
|
(527.6
|
)
|
|
|
(44.7
|
)%
|
Income tax provision
|
|
|
(193.8
|
)
|
|
|
(191.4
|
)
|
|
|
(2.4
|
)
|
|
|
(1.3
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from continuing operations, net of income taxes
|
|
|
457.9
|
|
|
|
987.9
|
|
|
|
(530.0
|
)
|
|
|
(53.6
|
)%
|
Income (loss) from discontinued operations, net of income taxes
|
|
|
5.1
|
|
|
|
(28.8
|
)
|
|
|
33.9
|
|
|
|
117.7
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
|
463.0
|
|
|
|
959.1
|
|
|
|
(496.1
|
)
|
|
|
(51.7
|
)%
|
Net income attributable to noncontrolling interests
|
|
|
(14.8
|
)
|
|
|
(6.2
|
)
|
|
|
(8.6
|
)
|
|
|
(138.7
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income attributable to common stockholders
|
|
$
|
448.2
|
|
|
$
|
952.9
|
|
|
$
|
(504.7
|
)
|
|
|
(53.0
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income attributable to common stockholders decreased in 2009
compared to the prior year due to the decrease in income from
continuing operations before incomes taxes discussed above.
41
Income tax provision was impacted by the following:
|
|
|
|
|
Increased expense associated with the remeasurement of
non-U.S. tax
accounts as a result of the strengthening Australian dollar
against the U.S dollar ($139.6 million; exchange rate rose
29% in 2009 compared to a 21% decrease in 2008, as illustrated
below); and
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
Rate Change
|
|
|
2009
|
|
2008
|
|
2007
|
|
2009
|
|
2008
|
|
Australian dollar to U.S. dollar exchange rate
|
|
$
|
0.8969
|
|
|
$
|
0.6928
|
|
|
$
|
0.8816
|
|
|
$
|
0.2041
|
|
|
$
|
(0.1888
|
)
|
|
|
|
|
|
The prior year release of a foreign valuation allowance related
to our Australian net operating loss carry forwards
($45.3 million) as a result of significantly higher
earnings resulting from the higher contract pricing that was
secured during 2008.
|
|
|
|
The above increases to income tax expense were partially offset
by lower pre-tax earnings in 2009, which drove a decrease to the
income tax provision ($184.6 million).
|
Income from discontinued operations increased compared to the
prior year as the prior year included operating losses, net of a
$26.2 million gain on the sale of our Baralaba Mine, and an
$11.7 million write-off of a coal excise tax receivable in
the first quarter of 2008. In late 2008, legislation was passed
which contained provisions that allowed for the refund of coal
excise tax collected on certain coal shipments. In 2009, we
received a coal excise tax refund resulting in approximately
$35 million, net of income taxes, recorded in Income
(loss) from discontinued operations, net of income taxes
(see Note 2 to the consolidated financial statements for
more information related to the excise tax refund). Partially
offsetting the 2009 excise tax refund were operating losses
associated with discontinued operations and assets held for sale
($20.6 million) and a $10.0 million loss on the sale
of our Chain Valley Mine in Australia.
Year
Ended December 31, 2008 Compared to Year Ended
December 31, 2007
Summary
Higher average sales prices and volumes across all operating
regions, particularly in Australia, contributed to an increase
in revenues in 2008 compared to 2007. Segment Adjusted EBITDA
rose primarily on the higher pricing mentioned above and
favorable results from Trading and Brokerage. Increases in sales
prices and volumes were partially offset by higher commodity,
material, supply, sales-related and labor costs in all operating
regions. Income from continuing operations, net of income taxes
was $987.9 million in 2008, or $3.60 per diluted share,
123.7% above 2007 income from continuing operations, net of
income taxes of $441.6 million, or $1.64 per diluted share.
Tons
Sold
The following table presents tons sold by operating segment for
the years ended December 31, 2008 and 2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
Increase
|
|
|
|
2008
|
|
|
2007
|
|
|
Tons
|
|
|
%
|
|
|
|
(Tons in millions)
|
|
|
Western U.S. Mining
|
|
|
169.7
|
|
|
|
161.4
|
|
|
|
8.3
|
|
|
|
5.1
|
%
|
Midwestern U.S. Mining
|
|
|
30.7
|
|
|
|
29.6
|
|
|
|
1.1
|
|
|
|
3.7
|
%
|
Australian Mining
|
|
|
23.4
|
|
|
|
20.4
|
|
|
|
3.0
|
|
|
|
14.7
|
%
|
Trading and Brokerage
|
|
|
31.2
|
|
|
|
24.1
|
|
|
|
7.1
|
|
|
|
29.5
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total tons sold
|
|
|
255.0
|
|
|
|
235.5
|
|
|
|
19.5
|
|
|
|
8.3
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
42
Revenues
The following table presents revenues for the years ended
December 31, 2008 and 2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Increase (Decrease)
|
|
|
|
Year Ended December 31,
|
|
|
to Revenues
|
|
|
|
2008
|
|
|
2007
|
|
|
$
|
|
|
%
|
|
|
|
(Dollars in millions)
|
|
|
Western U.S. Mining
|
|
$
|
2,533.1
|
|
|
$
|
2,063.2
|
|
|
$
|
469.9
|
|
|
|
22.8
|
%
|
Midwestern U.S. Mining
|
|
|
1,154.6
|
|
|
|
987.1
|
|
|
|
167.5
|
|
|
|
17.0
|
%
|
Australian Mining
|
|
|
2,242.8
|
|
|
|
1,117.6
|
|
|
|
1,125.2
|
|
|
|
100.7
|
%
|
Trading and Brokerage
|
|
|
601.8
|
|
|
|
320.7
|
|
|
|
281.1
|
|
|
|
87.7
|
%
|
Other
|
|
|
28.7
|
|
|
|
35.2
|
|
|
|
(6.5
|
)
|
|
|
(18.5
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
$
|
6,561.0
|
|
|
$
|
4,523.8
|
|
|
$
|
2,037.2
|
|
|
|
45.0
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues increased in 2008 compared to the prior year
across all operating segments. The primary drivers of the
increases included the following:
|
|
|
|
|
An increase in average sales price at our Australian Mining
operations (75.0%), primarily driven by the strength of
metallurgical coal prices on our Australian contracts that
reprice annually in the second quarter of each year.
|
|
|
|
U.S. Mining operations average sales price increased
over the prior year (15.2%) driven by the benefit of higher
priced coal supply agreements signed in recent years.
|
|
|
|
Australias volumes increased over the prior year (14.7%)
from strong demand during the first three quarters of 2008 and
additional production from recently completed mines.
Year-over-year
increases were partially offset by heavy rainfall and flooding
in Queensland during the first quarter of 2008 and customer
shipment deferrals in the fourth quarter of 2008 due to the
global economic slowdown.
|
|
|
|
Increased demand also led to higher volumes across our
U.S. operating segments, which overcame slightly lower
volumes at some of our Midwestern U.S. Mining surface
operations due to poor weather in that operating region that
impacted production during the first and second quarters. The
volume increase of 5.1% at our Western U.S. Mining
operations resulted from greater throughput from capital
improvements and contributions from our new El Segundo Mine,
partially offset by the flooding in the midwestern
U.S. that impacted railroad shipping performance related to
western U.S. production during the second quarter of 2008.
|
|
|
|
Trading and Brokerage revenues increased over the prior year due
to increased trading positions allowing us to capture market
movements derived from the volatility of both domestic and
international coal markets.
|
|
|
|
Also impacting
year-over-year
revenues in our Western U.S. Mining operations was an
agreement to recover previously recognized postretirement
healthcare and reclamation costs of $56.9 million in the
second quarter of 2008.
|
43
Segment
Adjusted EBITDA
The following table presents segment Adjusted EBITDA for the
years ended December 31, 2008 and 2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Increase (Decrease) to
|
|
|
|
Year Ended December 31,
|
|
|
Segment Adjusted EBITDA
|
|
|
|
2008
|
|
|
2007
|
|
|
$
|
|
|
%
|
|
|
|
|
|
|
(Dollars in millions)
|
|
|
|
|
|
Western U.S. Mining
|
|
$
|
681.3
|
|
|
$
|
595.4
|
|
|
$
|
85.9
|
|
|
|
14.4
|
%
|
Midwestern U.S. Mining
|
|
|
177.3
|
|
|
|
200.0
|
|
|
|
(22.7
|
)
|
|
|
(11.4
|
)%
|
Australian Mining
|
|
|
1,016.6
|
|
|
|
167.2
|
|
|
|
849.4
|
|
|
|
508.0
|
%
|
Trading and Brokerage
|
|
|
218.9
|
|
|
|
116.6
|
|
|
|
102.3
|
|
|
|
87.7
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Segment Adjusted EBITDA
|
|
$
|
2,094.1
|
|
|
$
|
1,079.2
|
|
|
$
|
1,014.9
|
|
|
|
94.0
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted EBITDA from our Western U.S. Mining operations
increased in 2008 over the prior year primarily driven by an
overall increase in average sales prices per ton across the
region ($2.10) and higher volumes in the region due to increased
demand and greater throughput as a result of capital
improvements. Also contributing to the increase was the recovery
of postretirement healthcare and reclamation costs discussed
above. Partially offsetting the pricing and volume contributions
were higher per ton costs ($1.78). The cost increases were
primarily due to higher sales related costs, higher material,
supply and labor costs, higher repair and maintenance costs in
the Powder River Basin and increased commodity costs, net of
hedging activities, driven by higher average fuel and explosives
pricing.
Midwestern U.S. Mining operations Adjusted EBITDA
decreased in 2008 as increases in average sales price per ton
($4.22) were offset by cost increases resulting from higher
costs for commodities, net of hedging activities, driven by
higher average fuel and explosives prices, as well as higher
material, supply and labor costs. Heavy rains and flooding in
the midwestern U.S. affected sales volume at some of our
mines, particularly in the first half of the year. Also
affecting the Midwestern U.S. Mining segment was the
decrease in revenues from coal sold to synthetic fuel plants in
the prior year ($28.9 million) due to the producers exiting
the synthetic fuel market after expiration of federal tax
credits at the end of 2007.
Our Australian Mining operations Adjusted EBITDA increased
in 2008 primarily due to higher pricing negotiated in the second
quarter of 2008 ($41.06 per ton), higher overall volumes as a
result of strong export demand and contributions from our
recently completed mines and lower demurrage costs. These
favorable impacts were partially offset by higher fuel costs, an
increase in labor and overburden removal expenses and higher
contractor costs (five of ten Australian mines are managed
utilizing contract miners).
Trading and Brokerage Adjusted EBITDA increased in 2008 over the
prior year due to increased trading volumes and higher coal
price volatility.
44
Income
From Continuing Operations Before Income Taxes
The following table presents income from continuing operations
before income taxes for the years ended December 31, 2008
and 2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Increase (Decrease)
|
|
|
|
Year Ended December 31,
|
|
|
to Income
|
|
|
|
2008
|
|
|
2007
|
|
|
$
|
|
|
%
|
|
|
|
(Dollars in millions)
|
|
|
Total Segment Adjusted EBITDA
|
|
$
|
2,094.1
|
|
|
$
|
1,079.2
|
|
|
$
|
1,014.9
|
|
|
|
94.0
|
%
|
Corporate and Other Adjusted EBITDA
|
|
|
(247.2
|
)
|
|
|
(109.5
|
)
|
|
|
(137.7
|
)
|
|
|
(125.8
|
)%
|
Depreciation, depletion and amortization
|
|
|
(402.4
|
)
|
|
|
(346.3
|
)
|
|
|
(56.1
|
)
|
|
|
(16.2
|
)%
|
Asset retirement obligation expense
|
|
|
(48.2
|
)
|
|
|
(23.7
|
)
|
|
|
(24.5
|
)
|
|
|
(103.4
|
)%
|
Interest expense
|
|
|
(227.0
|
)
|
|
|
(235.8
|
)
|
|
|
8.8
|
|
|
|
3.7
|
%
|
Interest income
|
|
|
10.0
|
|
|
|
7.0
|
|
|
|
3.0
|
|
|
|
42.9
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from continuing operations before income taxes
|
|
$
|
1,179.3
|
|
|
$
|
370.9
|
|
|
$
|
808.4
|
|
|
|
218.0
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from continuing operations before income taxes increased
over the prior year primarily due to the higher Total Segment
Adjusted EBITDA discussed above, partially offset by lower
Corporate and Other Adjusted EBITDA, higher depreciation,
depletion and amortization, and higher asset retirement
obligation expense.
The decrease in Corporate and Other Adjusted EBITDA during 2008
compared to 2007 was due to the following:
|
|
|
|
|
Higher selling and administrative expenses ($54.7 million)
primarily driven by an increase in performance-based incentive
costs and legal expenses;
|
|
|
|
Cost reimbursement and partner fees received in the prior year
for the Prairie State project, primarily related to the entrance
of new project partners ($29.5 million);
|
|
|
|
Lower net gains on disposals or exchanges of assets
($15.7 million). 2008 activity included a gain of
$54.0 million on the sale of approximately 58 million
tons of non-strategic coal reserves and surface lands located in
Kentucky. 2007 activity included a gain of $50.5 million on
the exchange of 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 coal reserves in West
Virginia and Kentucky and cash proceeds. The prior year also
included a gain of $26.4 million on the sale of
approximately 172 million tons of coal reserves and surface
lands to the Prairie State equity partners; and
|
|
|
|
Lower equity income ($15.5 million) from our joint venture
interest in Carbones del Guasare (owner and operator of the Paso
Diablo Mine in Venezuela) and higher costs associated with Btu
Conversion activities of $14.3 million in 2008.
|
Depreciation, depletion and amortization was higher in 2008
compared to the prior year because of increased depletion across
our operating platform resulting from the volume increases and
the impact of mining higher value coal reserves. In addition,
depreciation and depletion increases resulted from our recently
completed Australian mines and depletion at our El Segundo Mine.
Asset retirement obligation expense increased in 2008 as
compared to the prior year due to an increase in the ongoing and
closed mine reclamation rates that reflect higher fuel, labor
and re-vegetation costs, as well as an overall increase in the
number of acres disturbed. The addition of the El Segundo Mine,
which was completed in June 2008, also contributed to higher
asset retirement obligation expense.
45
Net
Income Attributable to Common Stockholders
The following table presents net income attributable to common
stockholders for the years ended December 31, 2008 and 2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Increase (Decrease)
|
|
|
|
(Dollars in millions)
|
|
|
to Income
|
|
|
|
2008
|
|
|
2007
|
|
|
$
|
|
|
%
|
|
|
|
(Dollars in millions)
|
|
|
Income from continuing operations before income taxes
|
|
$
|
1,179.3
|
|
|
$
|
370.9
|
|
|
$
|
808.4
|
|
|
|
218.0
|
%
|
Income tax (provision) benefit
|
|
|
(191.4
|
)
|
|
|
70.7
|
|
|
|
(262.1
|
)
|
|
|
(370.7
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from continuing operations, net of income taxes
|
|
|
987.9
|
|
|
|
441.6
|
|
|
|
546.3
|
|
|
|
123.7
|
%
|
Loss from discontinued operations, net of income taxes
|
|
|
(28.8
|
)
|
|
|
(180.1
|
)
|
|
|
151.3
|
|
|
|
84.0
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
|
959.1
|
|
|
|
261.5
|
|
|
|
697.6
|
|
|
|
266.8
|
%
|
Net (income) loss attributable to noncontrolling interests
|
|
|
(6.2
|
)
|
|
|
2.3
|
|
|
|
(8.5
|
)
|
|
|
(369.6
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income attributable to common stockholders
|
|
$
|
952.9
|
|
|
$
|
263.8
|
|
|
$
|
689.1
|
|
|
|
261.2
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income attributable to common stockholders increased in 2008
compared to the prior year due to the increase in income from
continuing operations before incomes taxes discussed above.
Income tax provision was impacted by the following:
|
|
|
|
|
Increased expense in 2008 due to higher pre-tax earnings
($282.9 million); and
|
|
|
|
Valuation allowance release against federal net operating loss
credits recognized into income in 2007 ($197.8 million);
partially offset by
|
|
|
|
Income tax benefit associated with the remeasurement of
non-U.S. tax
accounts as a result of the weakening Australian dollar against
the U.S dollar in 2008 ($121.2 million; exchange rate fell
21% in 2008 compared to an 11% increase in 2007, as illustrated
below); and
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
Rate Change
|
|
|
2008
|
|
2007
|
|
2006
|
|
2008
|
|
2007
|
|
Australian dollar to U.S. dollar exchange rate
|
|
$
|
0.6928
|
|
|
$
|
0.8816
|
|
|
$
|
0.7913
|
|
|
$
|
(0.1888
|
)
|
|
$
|
0.0903
|
|
|
|
|
|
|
The favorable rate difference resulting from higher foreign
generated income in 2008 ($106.2 million); and
|
|
|
|
The release of a foreign valuation allowance against a portion
of our Australian net operating loss carryforwards in 2008
($45.3 million) as a result of significantly higher
earnings resulting from the higher contract pricing that was
secured during 2008.
|
Net income for 2008 was also impacted by a lower loss from
discontinued operations as compared to the prior year due
primarily to losses incurred for Patriot operations in 2007. The
loss from discontinued operations for 2008 related to operating
losses, net of a $26.2 million gain on the sale of our
Baralaba Mine, and an $11.7 million write-off of an excise
tax refund receivable (net of tax) as a result of an April 2008
U.S. Supreme Court ruling (see Note 2 to the
consolidated financial statements).
Outlook
Near-Term
Outlook
Global economies are showing signs of improvement, with 2010
economic forecasts estimating a 2.6 to 4.0%
expansion although slower than expected economic
improvement could temper these estimates. The
46
Asia-Pacific markets are expected to continue to outpace the
U.S. and European markets in economic growth and therefore
electricity generation and steel production. For 2009, China and
India were the only steel producing majors to
outpace prior-year levels, with all other nations 23% lower on
average. For 2010, the World Steel Association estimates global
steel production will increase 9 percent over 2009.
Globally, 72 gigawatts of new coal-fueled generation are
under construction and expected to come on line during 2010,
more than 70% of which are new units in China and India. New
global coal-fueled generation for 2010 is estimated to require
approximately 300 million tons of new annual coal demand.
In the U.S., higher coal use caused by colder winter weather
lowered utility stockpiles an estimated 25 to 30 million
tons between December 2009 and mid-January 2010. As of
February 15, 2010, utility stockpiles were approximately
150 to 155 million tons, 24% above the
10-year
average and 6% above the year-ago level. We believe
U.S. coal demand could rise 60 to 80 million tons
based on economic growth, increasing industrial production and
an expected reduction of
coal-to-gas
switching due to rising natural gas prices. Conversely, the
Energy Information Administration (EIA) estimates coal
production will be 43 million tons lower in 2010, in part
due to production declines initiated in 2009. With rising demand
and lower production, utility coal inventories are likely to be
reduced.
As of January 26, 2010, we are targeting full-year 2010
production of approximately 185 to 195 million tons in the
U.S. and 26 to 28 million tons in Australia. Total
2010 sales are expected to be in a range of 240 to
260 million tons. We may continue to adjust our production
levels in response to changes in market demand.
We are fully contracted for 2010 at planned production levels in
the U.S. As of January 26, 2010 we had 4.5 to
5.5 million tons of Australian metallurgical coal unpriced
for 2010, along with 6.5 to 7.0 million tons of unpriced
export thermal coal. Unpriced 2010 volumes are primarily planned
for deliveries over the last three quarters of 2010.
We continue to manage costs and operating performance to
mitigate external cost pressures, geologic conditions and
potential shipping delays resulting from adverse port and rail
performance. To mitigate the external cost pressures, we have an
ongoing company-wide initiative to instill best practices at all
operations. We may have higher per ton costs as a result of
below-optimal production levels due to market-driven changes in
demand. We may also encounter poor geologic conditions, lower
third-party contract miner or brokerage 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. of this report for additional
considerations regarding our outlook.
We rely on ongoing access to the worldwide financial markets for
capital, insurance, hedging and investments through a wide
variety of financial instruments and contracts. To the extent
these markets are not available or increase significantly in
cost, this could have a negative impact on our ability to meet
our business goals. Similarly, many of our customers and
suppliers rely on the availability of the financial markets to
secure the necessary financing and financial surety (letters of
credit, performance bonds, etc.) to complete transactions with
us. To the extent customers and suppliers are not able to secure
this financial support, it could have a negative impact on our
results of operations
and/or
counterparty credit exposure.
Long-Term
Outlook
Our long-term global outlook remains positive. Coal has been the
fastest-growing fuel in the world for each of the past six
years, with consumption growing nearly twice as fast as total
energy use.
The International Energy Agencys (IEA) World Energy
Outlook estimates world primary energy demand will grow 40%
between 2007 and 2030, with demand for coal rising 53%. China
and India alone account for more than half of the expected
incremental energy demand.
Coal is expected to retain its strong presence as a fuel for the
power sector worldwide, with its share of the power generation
mix projected to rise to 44% in 2030. Currently, 217 gigawatts
of coal-fueled electricity
47
generating plants are under construction around the world,
representing more than 800 million tons of annual coal
demand expected to come online in the next several years. In the
U.S., 16 gigawatts of new coal-based generating capacity have
been completed in 2009 or are under construction, representing
approximately 65 million tons of annual coal demand when
they come online over the next three to five years as expected.
We believe that Btu Conversion applications such as CTG and CTL
plants represent an avenue for potential long-term industry
growth. The EIA continues to project an increase in demand for
unconventional sources of transportation fuel such as CTL, which
is estimated to add nearly 70 million tons of annual
U.S. coal demand by 2035. In addition, China and India are
developing CTG and CTL facilities.
The IEA projects natural gas demand will grow 1.5% per year to
just under 4,310 billion cubic meters in 2030. The biggest
increase in absolute terms occurs in the Middle East, which
holds the majority of the worlds proven reserves, and
non-OECD Asia. North America and Eastern Europe/Eurasia are
expected to remain the leading gas consumers in 2030, even
though their demand is expected to rise less in percentage terms
than almost anywhere else globally. Globally, the share of
renewables is projected to rise four percentage points to 22%
between 2007 and 2030, with most of the growth coming from
non-hydro sources. Nuclear power is expected to grow in all
major regions with the exception of Europe, but its share in
total generation is expected to fall between 2007 and 2030.
We continue to support clean coal technology development and
other initiatives addressing global climate change through our
participation in a number of projects in the U.S., China and
Australia. In addition, clean coal technology development in the
U.S. is being accelerated by funding under the American
Recovery and Reinvestment Act of 2009 and by the formation of an
Interagency Task Force on Carbon Capture and Storage to develop
a comprehensive and coordinated federal strategy to speed the
commercial development of clean coal technologies.
Enactment of laws or passage of regulations regarding emissions
from the combustion of coal by the U.S. or some of its
states or by other countries, or other actions to limit such
emissions, could result in electricity generators switching from
coal to other fuel sources. The potential financial impact on us
of future laws or regulations will depend upon the degree to
which any such laws or regulations forces electricity generators
to diminish their reliance on coal as a fuel source. That, in
turn, will depend on a number of factors, including the specific
requirements imposed by any such laws or regulations, the time
periods over which those laws or regulations would be phased in
and the state of commercial development and deployment of carbon
capture and storage technologies. In view of the significant
uncertainty surrounding each of these factors, it is not
possible for us to reasonably predict the impact that any such
laws or regulations may have on our results of operations,
financial condition or cash flows.
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 the sale of our accounts receivable (through our
securitization program). Our primary uses of cash include our
cash costs of coal production, capital expenditures, federal
coal lease payments, interest costs and costs related to past
mining obligations as well as 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 and
share repurchases, among other restricted items, are subject to
limitations imposed in the covenants of our 5.875% and
6.875% Senior Notes and the Debentures. We generally fund
all of our capital expenditure requirements with cash generated
from operations.
We believe our available borrowing capacity and operating cash
flows will be sufficient in the near term. As of
December 31, 2009, we had cash and cash equivalents of
$988.8 million and $1.5 billion of available borrowing
capacity under our Senior Unsecured Credit Facility, net of
outstanding letters of credit. The Senior Unsecured Credit
Facility matures on September 15, 2011.
48
The Pension Protection Act of 2006 (the Pension Protection Act),
which was effective January 1, 2008, increased the
long-term funding targets for single employer pension plans from
90% to 100%. At risk plans, as defined by the
Pension Protection Act, are restricted from making full lump sum
payments and from increasing benefits unless they are funded
immediately, and also requires that the plan give participants
notice regarding the at-risk status of the plan. If a plan falls
below 60%, lump sum payments are prohibited and participant
benefit accruals cease. As of December 31, 2009, our
pension plans were approximately 77% funded, before considering
planned 2010 contributions. Our minimum funding requirement for
2010 is approximately $3 million, and the qualified plans
would not be considered at-risk. Using current assumptions, our
2011 minimum funding requirement would be approximately
$98 million.
We also have a share repurchase program that has an available
capacity of $700.4 million at December 31, 2009. While
no repurchases were made in 2009 under the program, 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. The repurchase program
does not have an expiration date and may be discontinued at any
time.
Net cash provided by operating activities from continuing
operations for 2009 decreased $356.3 million compared to
the prior year primarily due to the decline in operating cash
flows generated from our Australian mining operations on lower
volumes and lower average pricing and the timing of cash flows
from our working capital, primarily driven by foreign income tax
payments related to prior year earnings.
The decrease in cash used in discontinued operations of
$117.4 million was primarily due to approximately
$59 million of cash received related to coal excise tax
refunds in 2009 (see Note 2 to the consolidated financial
statements for more information related to the excise tax
refund) and lower current year payments related to Patriot
discontinued operations.
Net cash used in investing activities from continuing operations
decreased $11.1 million in 2009 compared to the prior year.
The decrease primarily reflects lower federal coal lease
expenditures of $54.9 million in 2009, partially offset by
higher spending for our share of the Prairie State construction
costs and additional investments in equity affiliates and joint
venture projects in the prior year. Capital expenditures in 2009
were consistent with prior year as current year spending related
to the development of our Bear Run Mine was offset by prior year
spending related to the completion of our El Segundo Mine and
expenditures for our blending and loadout facility at our North
Antelope Rochelle Mine in the Western U.S.
Net cash used in financing activities decreased
$384.7 million, primarily due to 2008 payments related to
the repurchase of common stock ($199.8 million), the
acquisition of noncontrolling interests relating to our
Millennium Mine ($110.1 million) and payments on our
revolving line of credit ($97.7 million). During 2009, we
purchased $10.0 million face value of our 6.84%
Series A bonds and $10.0 million face value of our
6.84% Series C bonds for a combined total of
$19.0 million.
49
Our total indebtedness as of December 31, 2009 and 2008
consisted of the following:
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
|
(Dollars in millions)
|
|
|
Term Loan under Senior Unsecured Credit Facility
|
|
$
|
490.3
|
|
|
$
|
490.3
|
|
Convertible Junior Subordinated Debentures due December 2066
|
|
|
371.5
|
|
|
|
369.9
|
|
7.375% Senior Notes due November 2016
|
|
|
650.0
|
|
|
|
650.0
|
|
6.875% Senior Notes due March 2013
|
|
|
650.0
|
|
|
|
650.0
|
|
7.875% Senior Notes due November 2026
|
|
|
247.1
|
|
|
|
247.0
|
|
5.875% Senior Notes due March 2016
|
|
|
218.1
|
|
|
|
218.1
|
|
6.84% Series C Bonds due December 2016
|
|
|
33.0
|
|
|
|
43.0
|
|
6.34% Series B Bonds due December 2014
|
|
|
15.0
|
|
|
|
18.0
|
|
6.84% Series A Bonds due December 2014
|
|
|
|
|
|
|
10.0
|
|
Capital lease obligations
|
|
|
67.5
|
|
|
|
81.2
|
|
Fair value hedge adjustment
|
|
|
8.4
|
|
|
|
15.1
|
|
Other
|
|
|
1.4
|
|
|
|
1.0
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
2,752.3
|
|
|
$
|
2,793.6
|
|
|
|
|
|
|
|
|
|
|
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 Debentures as of
December 31, 2009.
Senior Unsecured Credit Facility. Our 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.
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 is based on a pricing grid tied to our
leverage ratio, as defined in the Third Amended and Restated
Credit Agreement. At December 31, 2009, the interest rate
payable on the Revolving Credit Facility and the Term Loan
Facility was LIBOR plus 0.75%, or a total of 1.0%.
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 Senior Unsecured Credit Facility matures on
September 15, 2011.
As of December 31, 2009, we had no borrowings and
$315.7 million letters of credit outstanding under our
Revolving Credit Facility.
Other Long-Term Debt. A description of our
other debt instruments is described in Note 12 to the
consolidated financial statements.
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 the 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
50
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
August 7, 2009, 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 expect to be able to 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.
Capital Expenditures. Capital expenditures for
2010 are anticipated to be between $600 million to
$650 million. The planned expenditures include sustaining
capital at our existing mines, completion of our Bear Run Mine
in western Indiana, expansion of our metallurgical and thermal
coal export platform in Australia to serve the growth markets in
Asia and funding of our Prairie State investment.
Contractual
Obligations
The following is a summary of our contractual obligations as of
December 31, 2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Payments Due By Year
|
|
|
|
|
|
|
Less than
|
|
|
1 - 3
|
|
|
3 - 5
|
|
|
More than
|
|
|
|
Total
|
|
|
1 Year
|
|
|
Years
|
|
|
Years
|
|
|
5 Years
|
|
|
|
|
|
|
|
|
|
(Dollars in millions)
|
|
|
|
|
|
Long-term debt obligations (principal and interest)
|
|
$
|
5,219.5
|
|
|
$
|
203.4
|
|
|
$
|
884.8
|
|
|
$
|
964.8
|
|
|
$
|
3,166.5
|
|
Capital lease obligations (principal and interest)
|
|
|
80.3
|
|
|
|
15.1
|
|
|
|
30.2
|
|
|
|
35.0
|
|
|
|
|
|
Operating lease obligations
|
|
|
468.1
|
|
|
|
96.4
|
|
|
|
153.6
|
|
|
|
100.3
|
|
|
|
117.8
|
|
Unconditional purchase
obligations(1)
|
|
|
70.4
|
|
|
|
70.4
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Coal reserve lease and royalty obligations
|
|
|
79.9
|
|
|
|
11.3
|
|
|
|
16.8
|
|
|
|
15.0
|
|
|
|
36.8
|
|
Take or pay
obligations(2)
|
|
|
1,864.4
|
|
|
|
110.7
|
|
|
|
297.4
|
|
|
|
310.4
|
|
|
|
1,145.9
|
|
Other long-term
liabilities(3)
|
|
|
1,485.5
|
|
|
|
151.0
|
|
|
|
300.3
|
|
|
|
292.6
|
|
|
|
741.6
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total contractual cash obligations
|
|
$
|
9,268.1
|
|
|
$
|
658.3
|
|
|
$
|
1,683.1
|
|
|
$
|
1,718.1
|
|
|
$
|
5,208.6
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(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 capital purchases. |
|
(2) |
|
Represents various long- and short-term take or pay arrangements
associated with rail and port commitments for the delivery of
coal, some of which extend to 2040, including amounts relating
to export facilities currently under construction which are
expected to be completed in 2010. |
|
(3) |
|
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, 2009, we had $70.4 million of
purchase obligations for capital expenditures and
$0.9 million of obligations related to federal coal reserve
lease payments due over the next five years. The purchase
obligations for capital expenditures primarily relate to the
replacement and improvement of equipment and facilities at
existing mines.
We do not expect any of the $113.2 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.
51
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. Assets and 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 (such
as self bonds) and letters of credit to secure our financial
obligations for reclamation, workers compensation, and
coal lease obligations as follows as of December 31, 2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Workers
|
|
|
|
|
|
|
|
|
|
Reclamation
|
|
|
Lease
|
|
|
Compensation
|
|
|
|
|
|
|
|
|
|
Obligations
|
|
|
Obligations
|
|
|
Obligations
|
|
|
Other(1)
|
|
|
Total
|
|
|
|
(Dollars in millions)
|
|
|
Self bonding
|
|
$
|
821.9
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
821.9
|
|
Surety bonds
|
|
|
772.3
|
|
|
|
116.3
|
|
|
|
8.7
|
|
|
|
57.3
|
|
|
|
954.6
|
|
Letters of credit
|
|
|
34.9
|
|
|
|
|
|
|
|
43.0
|
|
|
|
237.8
|
|
|
|
315.7
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
1,629.1
|
|
|
$
|
116.3
|
|
|
$
|
51.7
|
|
|
$
|
295.1
|
|
|
$
|
2,092.2
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Other includes the six letter of credit obligations described
below and an additional $61.1 million in letters of credit
and surety bonds related to collateral for surety companies,
road maintenance, performance guarantees and other operations. |
We own a 37.5% interest in Dominion Terminal Associates, a
partnership that operates a coal export terminal in Newport
News, 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, 2009, our maximum reimbursement obligation to
the commercial bank was in turn supported by four letters of
credit totaling $42.7 million.
We are party to an agreement with the Pension Benefit Guarantee
Corporation (PBGC) and TXU Europe Limited, an affiliate of our
former parent corporation, under which we are required to make
special 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 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 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 U.S.) and continues under this
process as of December 31, 2009. 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.
At December 31, 2009, we have a $154.3 million letter
of credit for collateral for bank guarantees issued with respect
to certain reclamation and performance obligations related to
some of our Australian mines.
Other Guarantees. See the Other
Guarantees section of Note 19 to our consolidated
financial statements for a description of our other guarantees.
Accounts Receivable Securitization
Program. Under our accounts receivable
securitization program in place at December 31, 2009, a
pool of eligible trade receivables contributed to our
wholly-owned, bankruptcy-remote subsidiary were sold, without
recourse, to a multi-seller, asset-backed commercial paper
conduit
52
(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 $4.0 million
for the year ended December 31, 2009 and $10.8 million
for the year ended December 31, 2008. The securitization
program was renewed in May 2009 and amended in December 2009,
and extends to May 2012, while the letter of credit commitment
that supports the commercial paper facility underlying the
securitization program must be renewed annually. The
securitization transactions have been recorded as sales, with
receivables sold to the Conduit removed from our consolidated
balance sheets. The amount of interest in accounts receivable
sold to the Conduit was $254.6 million as of
December 31, 2009 and $275.0 million as of
December 31, 2008 (see Note 6 to our consolidated
financial statements for additional information on our accounts
receivable securitization program). On January 25, 2010,
the receivables purchase agreement for the accounts receivable
securitization program was amended and restated to add a second
multi-seller asset-backed commercial paper conduit as a
purchaser.
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 GAAP. GAAP requires that we make estimates and judgments
that affect the reported amounts of assets, liabilities,
revenues and expenses, and related disclosure of contingent
assets and liabilities. On an ongoing basis, we evaluate our
estimates. We base our estimates on historical experience and on
various other 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
long-term liabilities for our employees postretirement
benefit costs and defined benefit pension plans. Detailed
information related to these liabilities is included in
Notes 14 and 15 to our consolidated financial statements.
Liabilities for postretirement benefit costs and workers
compensation obligations are not funded. Our pension obligations
are funded in accordance with the provisions of applicable law.
Expense for the year ended December 31, 2009 for the
pension and postretirement liabilities totaled
$76.8 million, while funding payments were
$110.3 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. For our postretirement health care liability,
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 millions)
|
|
Effect on total service and interest cost
components(1)
|
|
$
|
6.7
|
|
|
$
|
(5.7
|
)
|
Effect on total postretirement benefit
obligation(1)
|
|
$
|
98.3
|
|
|
$
|
(84.6
|
)
|
53
Discount rate:
|
|
|
|
|
|
|
|
|
|
|
One-Half
|
|
One-Half
|
|
|
Percentage-
|
|
Percentage-
|
|
|
Point Increase
|
|
Point Decrease
|
|
|
(Dollars in millions)
|
|
Effect on total service and interest cost
components(1)
|
|
$
|
0.6
|
|
|
$
|
(0.6
|
)
|
Effect on total postretirement benefit
obligation(1)
|
|
$
|
(46.1
|
)
|
|
$
|
52.2
|
|
|
|
|
(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 10.92 years at December 31, 2009. |
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 applicable
reclamation laws in the U.S. and Australia 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 and the timing of these cash flows, discounted
using 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, 2009 was $40.1 million, and
payments totaled $12.4 million. See Note 13 to our
consolidated financial statements for additional details
regarding our asset retirement obligations.
Income Taxes. We account for income taxes in
accordance with accounting guidance which requires 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. The guidance 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.
Our liability for unrecognized tax benefits contains
uncertainties because management is required to make assumptions
and to apply judgment to estimate the exposures associated with
our various filing positions. We recognize the tax benefit from
an uncertain tax position only if it is more likely than
not that the tax position will be sustained on examination
by the taxing authorities, based on the technical merits of the
position. The tax benefits recognized in the financial
statements from such a position must be measured based on the
largest benefit that has a greater than 50% likelihood of being
realized upon ultimate settlement. We believe that the judgments
and estimates are reasonable; however, actual results could
differ.
Level 3 Fair Value Measurements. In
accordance with the Fair Value Measurements and
Disclosures topic of the Financial Accounting Standards
Board Accounting Standards Codification, we evaluate the quality
and reliability of the assumptions and data used to measure fair
value in the three hierarchy Levels 1, 2 and 3 (see
Note 3 to our consolidated financial statements for
additional information). Commodity swaps and options and
physical commodity purchase/sale contracts transacted in less
liquid markets or contracts, such as long-term arrangements,
with limited price availability were classified in Level 3.
Indicators of less liquid markets are those with periods of low
trade activity or when broker quotes reflect wide pricing
spreads. Generally, these instruments or contracts are valued
using internally generated models that include forward pricing
curve quotes from one to three reputable brokers. Our valuation
techniques also include basis
54
adjustments for heat rate, sulfur and ash content, port and
freight costs, and credit and nonperformance risk. We validate
our valuation inputs with third-party information and settlement
prices from other sources where available. We also consider
credit and nonperformance risk in the fair value measurement by
analyzing the counterpartys exposure balance, credit
rating and average default rate, net of any counterparty credit
enhancements (e.g., collateral), as well as our own credit
rating for financial derivative liabilities.
We have consistently applied these valuation techniques in all
periods presented, and believe we have obtained the most
accurate information reasonably available for the types of
derivative contracts held. Valuation changes from period to
period for each level will increase or decrease depending on:
(i) the relative change in fair value for positions held,
(ii) new positions added, (iii) realized amounts for
completed trades, and (iv) transfers between levels. Our
coal trading strategies utilize various swaps and derivative
physical contracts. Periodic changes in fair value for purchase
and sale positions, which are executed to lock in coal trading
spreads, occur in each level and therefore the overall change in
value of our coal-trading platform requires consideration of
valuation changes across all levels.
At December 31, 2009, 5% of our net financial assets were
categorized as Level 3. At December 31, 2008, the
percentage of Level 3 net financial assets compared to
the total net financial liabilities is not meaningful due to the
overall liability position at December 31, 2008. See
Note 3 to our consolidated financial statements for
additional information regarding fair value measurements.
Newly
Adopted Accounting Standards and Accounting Standards Not Yet
Implemented
See Note 1 to our consolidated financial statements for a
discussion of newly adopted accounting pronouncements and
accounting pronouncements not yet implemented.
|
|
Item 7A.
|
Quantitative
and Qualitative Disclosures About Market Risk
|
The potential for changes in the market value of our coal and
freight trading, emission allowances, crude oil, diesel fuel,
natural gas, explosives, interest rate and currency portfolios
is referred to as market risk. Market risk related
to our coal trading and freight portfolio is evaluated using a
value at risk (VaR) analysis. VaR analysis is not used to
evaluate our non-trading interest rate, diesel fuel, explosives
or currency hedging 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,
direct and brokered trading of coal, ocean freight and
fuel-related commodities to support our coal trading related
activities (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, as measured by VaR, 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
at market value in our consolidated financial statements. Our
trading portfolio included forwards, swaps and options as of
December 31, 2009 and 2008.
We perform a VaR analysis on our coal trading portfolio, which
includes bilaterally-settled and exchange-settled
over-the-counter
and brokerage coal trading. The use of VaR allows us to quantify
in dollars, on a daily basis, a measure of price risk inherent
in our trading portfolio. VaR represents the 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 VaR model is based on a variance/co-variance
approach. This captures our exposure related to forwards, swaps
and options positions. Our VaR model assumes a 5 to
15-day
holding period and a 95% one-tailed confidence interval. This
means that there is a one in 20 statistical
55
chance that the portfolio would lose more than the VaR estimates
during the liquidation period. Our volatility calculation
incorporates an exponentially weighted moving average algorithm
based on the previous 60 market days, which makes our volatility
more representative of recent market conditions, while still
reflecting an awareness of historical price movements. VaR does
not capture the loss expected in the 5% of the time the
portfolio value exceeds measured VaR.
The use of VaR allows us to aggregate pricing risks across
products in the portfolio, compare risk on a consistent basis
and identify the drivers of risk. We use historical data to
estimate price volatility as an input to VaR. Given our reliance
on historical data, we believe VaR is reasonably effective in
characterizing risk exposures in markets in which there are not
sudden fundamental changes or shifts in market conditions. 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 VaR methodology, we perform regular
stress and scenario analyses 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 VaR measure. The results of these analyses are used to
supplement the VaR methodology and identify additional
market-related risks. An inherent limitation of VaR is that past
changes in market risk factors may not produce accurate
predictions of future market risk.
During the year ended December 31, 2009, the actual low,
high, and average VaR for our coal trading portfolio were
$2.7 million, $15.9 million, and $8.7 million,
respectively. Our VaR decreased over the prior year due to less
price volatility and lower overall prices in the U.S. and
international coal markets.
As of December 31, 2009, the timing of the estimated future
realization of the value of our trading portfolio was as follows:
|
|
|
|
|
Year of
|
|
Percentage of
|
|
Expiration
|
|
Portfolio Total
|
|
|
2010
|
|
|
46
|
%
|
2011
|
|
|
51
|
%
|
2012
|
|
|
3
|
%
|
|
|
|
|
|
|
|
|
100
|
%
|
|
|
|
|
|
We also monitor other types of risk associated with our coal
trading activities, including credit, market liquidity and
counterparty nonperformance.
Nonperformance
and Credit Risk
The fair value of our assets and liabilities reflect adjustments
for nonperformance and credit risk. Our concentration of
nonperformance and credit risk is substantially with electric
utilities, steel producers, energy producers and energy
marketers. Our policy is to independently evaluate each
customers creditworthiness prior to entering into
transactions and to regularly monitor the credit extended. If we
engage in a transaction with a counterparty that does not meet
our credit standards, we seek to protect our position by
requiring the counterparty to provide an appropriate credit
enhancement. Also, when appropriate (as determined by our credit
management function), we have taken steps to reduce our 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 or perform. 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 and, to the
extent required, will post or receive margin amounts associated
with exchange-cleared positions.
We conduct our various hedging activities related to foreign
currency, interest rate, and fuel and explosives exposures with
a variety of highly-rated commercial banks. In light of the
recent turmoil in the financial markets, we continue to closely
monitor counterparty creditworthiness.
56
Foreign
Currency Risk
We utilize currency forwards and options to hedge currency risk
associated with anticipated Australian dollar expenditures. 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
$0.05 change in the Australian dollar/U.S. dollar exchange
rate is approximately $82 million for 2010. However, taking
into consideration hedges currently in place, our net exposure
to the same rate change is approximately $17 million for
2010. The chart at the end of Item 7A shows the notional
amount of our hedge contracts as of December 31, 2009.
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 3 to our consolidated financial
statements. As of December 31, 2009, after taking into
consideration the effects of interest rate swaps, we had
$2.4 billion of fixed-rate borrowings and $0.4 billion
of variable-rate borrowings outstanding. A one percentage point
increase in interest rates would result in an annualized
increase to interest expense of approximately $4.2 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 decrease of approximately $130 million in
the estimated fair value of these borrowings.
Other
Non-trading Activities Commodity Price
Risk
Long-term Coal Contracts. We manage our
commodity price risk for our non-trading, long-term coal
contract portfolio through the use of long-term coal supply
agreements (those with terms longer than one year), rather than
through the use of derivative instruments. We sold 93% and 90%
of our worldwide sales volume under long-term coal supply
agreements during 2009 and 2008, respectively. We are fully
contracted for 2010 at planned production levels in the
U.S. We had 11 to 12.5 million tons remaining to be
priced for 2010 in Australia at January 26, 2010.
Diesel Fuel and Explosives Hedges. We manage
commodity price risk of the diesel fuel and explosives used in
our mining activities through the use of fixed price contracts,
cost-plus contracts and a combination of forward contracts with
our suppliers and financial derivative contracts, which are
primarily swap contracts with financial institutions.
Notional amounts outstanding under fuel-related, derivative swap
contracts are noted in the chart at the end of Item 7A. We
expect to consume 130 to 135 million gallons of diesel fuel
in 2010. Assuming we had no hedges in place, a $10 per barrel
change in the price of crude oil (the primary component of a
refined diesel fuel product) would increase or decrease our
annual diesel fuel costs by approximately $31 million based
on our expected usage. However, taking into consideration hedges
currently in place, our net exposure to changes in the price of
crude oil is approximately $14 million.
Notional amounts outstanding under explosives-related swap
contracts are noted in the chart at the end of Item 7A. We
expect to consume 345,000 to 355,000 tons of explosives during
2010 in the U.S. Explosives costs in Australia are
generally included in the fees paid to our contract miners.
Assuming we had no hedges in place, a price change in natural
gas (often a key component in the production of explosives) of
one dollar per million MMBtu would result in an increase or
decrease in our annual explosives costs of approximately
$6 million based on our expected usage. However, taking
into consideration hedges currently in place, our net exposure
to changes in the price of natural gas is approximately
$3 million.
57
Notional Amounts and Fair Value. The following
summarizes our interest rate, foreign currency and commodity
positions at December 31, 2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Notional Amount by Year of Maturity
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2015 and
|
|
|
Total
|
|
2010
|
|
2011
|
|
2012
|
|
2013
|
|
2014
|
|
thereafter
|
|
Interest Rate Swaps
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fixed-to-floating
(dollars in millions)
|
|
$
|
50.0
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
50.0
|
|
|
$
|
|
|
|
$
|
|
|
Floating-to-fixed
(dollars in millions)
|
|
$
|
120.0
|
|
|
$
|
|
|
|
$
|
120.0
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
Foreign Currency
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
A$:US$ hedge contracts (A$ millions)
|
|
$
|
3,291.7
|
|
|
$
|
1,299.3
|
|
|
$
|
994.8
|
|
|
$
|
742.6
|
|
|
$
|
120.0
|
|
|
$
|
135.0
|
|
|
$
|
|
|
Commodity Contracts
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diesel fuel hedge contracts (million gallons)
|
|
|
177.8
|
|
|
|
71.1
|
|
|
|
65.3
|
|
|
|
41.4
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. explosives hedge contracts (million MMBtu)
|
|
|
3.0
|
|
|
|
3.0
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Account Classification by
|
|
|
|
|
|
Cash flow
|
|
Fair value
|
|
Economic
|
|
|
Fair Value Asset
|
|
|
hedge
|
|
hedge
|
|
hedge
|
|
|
(Liability)
|
|
|
|
|
|
|
|
|
|
(Dollars in millions)
|
Interest Rate Swaps
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fixed-to-floating
(dollars in millions)
|
|
$
|
|
|
|
$
|
50.0
|
|
|
$
|
|
|
|
|
$
|
1.5
|
|
Floating-to-fixed
(dollars in millions)
|
|
$
|
120.0
|
|
|
$
|
|
|
|
$
|
|
|
|
|
$
|
(9.8
|
)
|
Foreign Currency
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
A$:US$ hedge contracts (A$ millions)
|
|
$
|
3,291.7
|
|
|
$
|
|
|
|
$
|
|
|
|
|
$
|
206.1
|
|
Commodity Contracts
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diesel fuel hedge contracts (million gallons)
|
|
|
177.8
|
|
|
|
|
|
|
|
|
|
|
|
$
|
(22.2
|
)
|
U.S. explosives hedge contracts (million MMBtu)
|
|
|
3.0
|
|
|
|
|
|
|
|
|
|
|
|
$
|
(4.8
|
)
|
|
|
Item 8.
|
Financial
Statements and Supplementary Data.
|
See Part IV, Item 15 of this report for information
required by this Item, which information is incorporated by
reference herein.
|
|
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
Our disclosure controls and procedures are designed to, among
other things, provide reasonable assurance that material
information, both financial and non-financial, and other
information required under the securities laws to be disclosed
is accumulated and communicated to senior management, including
the principal executive officer and principal financial officer,
on a timely basis. As of December 31, 2009, 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, our Chief Executive Officer and Chief
Financial Officer have evaluated our disclosure controls and
procedures (as defined in
Rules 13a-15(e)
and
15d-15(e)
under the Securities Exchange Act of 1934) as of
December 31,
58
2009, and concluded that such controls and procedures are
effective to provide reasonable assurance that the desired
control objectives were achieved.
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 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, 2009 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 were effective to provide reasonable assurance that
the desired control objectives were achieved as of
December 31, 2009.
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
Gregory
H. Boyce
Chairman and Chief Executive Officer
|
|
/s/ Michael
C. Crews
Michael
C. Crews
Executive Vice President and
Chief Financial Officer
|
February 24, 2010
59
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, 2009, 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, 2009, 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, 2009 and 2008, 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, 2009, and our report dated February 24,
2010, expressed an unqualified opinion thereon.
St. Louis, Missouri
February 24, 2010
60
|
|
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-Director
Qualifications in our 2010 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-Committees of the Board of Directors-Audit
Committee in our 2010 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 2010 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 Items 403 of
Regulation S-K
is included under the caption Ownership of Company
Securities in our 2010 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, 2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Number of Securities
|
|
|
|
|
|
|
|
|
|
Remaining Available
|
|
|
|
|
|
|
|
|
|
for Future Issuance
|
|
|
|
(a)
|
|
|
|
|
|
Under Equity
|
|
|
|
Number of Securities
|
|
|
|
|
|
Compensation Plans
|
|
|
|
to be Issued
|
|
|
Weighted-Average
|
|
|
(Excluding
|
|
|
|
upon Exercise of
|
|
|
Exercise Price of
|
|
|
Securities
|
|
|
|
Outstanding Options,
|
|
|
Outstanding Options,
|
|
|
Reflected in Column
|
|
Plan Category
|
|
Warrants and Rights
|
|
|
Warrants and Rights
|
|
|
(a))
|
|
|
Equity compensation plans approved
|
|
|
|
|
|
|
|
|
|
|
|
|
by security holders
|
|
|
1,715,557
|
|
|
$
|
20.78
|
|
|
|
14,588,584
|
|
Equity compensation plans not approved
|
|
|
|
|
|
|
|
|
|
|
|
|
by security holders
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
1,715,557
|
|
|
$
|
20.78
|
|
|
|
14,588,584
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 Policy for Approval of
Related Person Transactions and Information
Regarding Board of Directors and
Committees-Director
Independence in our 2010 Proxy Statement and is
incorporated herein by reference.
61
|
|
Item 14.
|
Principal
Accounting Fees and Services.
|
The information required by Item 9(e) of Schedule 14A
is included under the caption Fees Paid to Independent
Registered Public Accounting Firm in our 2010 Proxy
Statement and is incorporated herein by reference.
PART IV
|
|
Item 15.
|
Exhibit,
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
|
|
|
|
|
F-1
|
|
|
|
|
F-2
|
|
|
|
|
F-3
|
|
|
|
|
F-4
|
|
|
|
|
F-5
|
|
|
|
|
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:
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 Securities and
Exchange Commission upon request.
62
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 24, 2010
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 24, 2010
|
|
|
|
|
|
/s/ MICHAEL
C. CREWS
Michael
C. Crews
|
|
Executive Vice President and Chief
Financial Officer (principal financial and accounting officer)
|
|
February 24, 2010
|
|
|
|
|
|
/s/ WILLIAM
A. COLEY
William
A. Coley
|
|
Director
|
|
February 24, 2010
|
|
|
|
|
|
/s/ WILLIAM
E. JAMES
William
E. James
|
|
Director
|
|
February 24, 2010
|
|
|
|
|
|
/s/ ROBERT
B. KARN III
Robert
B. Karn III
|
|
Director
|
|
February 24, 2010
|
|
|
|
|
|
/s/ M.
FRANCES KEETH
M.
Frances Keeth
|
|
Director
|
|
February 24, 2010
|
|
|
|
|
|
/s/ HENRY
E. LENTZ
Henry
E. Lentz
|
|
Director
|
|
February 24, 2010
|
|
|
|
|
|
/s/ ROBERT
A. MALONE
Robert
A. Malone
|
|
Director
|
|
February 24, 2010
|
|
|
|
|
|
/s/ WILLIAM
C. RUSNACK
William
C. Rusnack
|
|
Director
|
|
February 24, 2010
|
63
|
|
|
|
|
|
|
Signature
|
|
Title
|
|
Date
|
|
|
|
|
|
|
/s/ JOHN
F. TURNER
John
F. Turner
|
|
Director
|
|
February 24, 2010
|
|
|
|
|
|
/s/ SANDRA
VAN TREASE
Sandra
Van Trease
|
|
Director
|
|
February 24, 2010
|
|
|
|
|
|
/s/ ALAN
H. WASHKOWITZ
Alan
H. Washkowitz
|
|
Director
|
|
February 24, 2010
|
64
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,
2009 and 2008, 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, 2009. 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, 2009 and 2008, and the consolidated results of
its operations and its cash flows for each of the three years in
the period ended December 31, 2009, in conformity with
U.S. generally accepted accounting principles.
As discussed in Note 1 to the consolidated financial
statements, on January 1, 2009, the Company changed its
method for accounting for noncontrolling interests, its method
for accounting for convertible debt that may be settled in cash
upon conversion, and its method for accounting for earnings per
share under the two-class method, and on January 1, 2008,
the Company changed its method of accounting for the recognition
of derivative positions with the same counterparty.
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, 2009, 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 24, 2010, expressed an unqualified opinion thereon.
St. Louis, Missouri
February 24, 2010
F-1
PEABODY
ENERGY CORPORATION
CONSOLIDATED
STATEMENTS OF OPERATIONS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
|
(Dollars in millions, except per share data)
|
|
|
Revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales
|
|
$
|
5,468.1
|
|
|
$
|
6,004.0
|
|
|
$
|
4,313.9
|
|
Other revenues
|
|
|
544.3
|
|
|
|
557.0
|
|
|
|
209.9
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
|
6,012.4
|
|
|
|
6,561.0
|
|
|
|
4,523.8
|
|
Costs and expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating costs and expenses
|
|
|
4,467.7
|
|
|
|
4,585.2
|
|
|
|
3,510.1
|
|
Depreciation, depletion and amortization
|
|
|
405.2
|
|
|
|
402.4
|
|
|
|
346.3
|
|
Asset retirement obligation expense
|
|
|
40.1
|
|
|
|
48.2
|
|
|
|
23.7
|
|
Selling and administrative expenses
|
|
|
208.7
|
|
|
|
201.8
|
|
|
|
147.1
|
|
Other operating (income) loss:
|
|
|
|
|
|
|
|
|
|
|
|
|
Net gain on disposal or exchange of assets
|
|
|
(23.2
|
)
|
|
|
(72.9
|
)
|
|
|
(88.6
|
)
|
(Income) loss from equity affiliates
|
|
|
69.1
|
|
|
|
|
|
|
|
(14.5
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating profit
|
|
|
844.8
|
|
|
|
1,396.3
|
|
|
|
599.7
|
|
Interest expense
|
|
|
201.2
|
|
|
|
227.0
|
|
|
|
235.8
|
|
Interest income
|
|
|
(8.1
|
)
|
|
|
(10.0
|
)
|
|
|
(7.0
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from continuing operations before income taxes
|
|
|
651.7
|
|
|
|
1,179.3
|
|
|
|
370.9
|
|
Income tax provision (benefit)
|
|
|
193.8
|
|
|
|
191.4
|
|
|
|
(70.7
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from continuing operations, net of income taxes
|
|
|
457.9
|
|
|
|
987.9
|
|
|
|
441.6
|
|
Income (loss) from discontinued operations, net of income taxes
|
|
|
5.1
|
|
|
|
(28.8
|
)
|
|
|
(180.1
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
|
463.0
|
|
|
|
959.1
|
|
|
|
261.5
|
|
Less: Net income (loss) attributable to noncontrolling interests
|
|
|
14.8
|
|
|
|
6.2
|
|
|
|
(2.3
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income attributable to common stockholders
|
|
$
|
448.2
|
|
|
$
|
952.9
|
|
|
$
|
263.8
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income From Continuing Operations
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic earnings per share
|
|
$
|
1.66
|
|
|
$
|
3.63
|
|
|
$
|
1.67
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted earnings per share
|
|
$
|
1.64
|
|
|
$
|
3.60
|
|
|
$
|
1.64
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income Attributable to Common Stockholders
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic earnings per share
|
|
$
|
1.68
|
|
|
$
|
3.52
|
|
|
$
|
0.99
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted earnings per share
|
|
$
|
1.66
|
|
|
$
|
3.50
|
|
|
$
|
0.97
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dividends declared per share
|
|
$
|
0.25
|
|
|
$
|
0.24
|
|
|
$
|
0.24
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to consolidated financial statements
F-2
PEABODY
ENERGY CORPORATION
CONSOLIDATED
BALANCE SHEETS
|
|
|
|
|
|
|
|
|
|
|
December 31, 2009
|
|
|
December 31, 2008
|
|
|
|
(Amounts in millions, except share and per share data)
|
|
|
ASSETS
|
Current assets
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
988.8
|
|
|
$
|
449.7
|
|
Accounts receivable, net of allowance for doubtful accounts of
$18.3 at December 31, 2009 and $24.8 at December 31,
2008
|
|
|
303.0
|
|
|
|
382.2
|
|
Inventories
|
|
|
325.1
|
|
|
|
276.2
|
|
Assets from coal trading activities, net
|
|
|
276.8
|
|
|
|
662.8
|
|
Deferred income taxes
|
|
|
40.0
|
|
|
|
1.7
|
|
Other current assets
|
|
|
255.3
|
|
|
|
198.7
|
|
|
|
|
|
|
|
|
|
|
Total current assets
|
|
|
2,189.0
|
|
|
|
1,971.3
|
|
Property, plant, equipment and mine development
Land and coal interests
|
|
|
7,557.3
|
|
|
|
7,349.4
|
|
Buildings and improvements
|
|
|
908.0
|
|
|
|
858.1
|
|
Machinery and equipment
|
|
|
1,391.2
|
|
|
|
1,245.1
|
|
Less: accumulated depreciation, depletion and amortization
|
|
|
(2,595.0
|
)
|
|
|
(2,155.3
|
)
|
|
|
|
|
|
|
|
|
|
Property, plant, equipment and mine development, net
|
|
|
7,261.5
|
|
|
|
7,297.3
|
|
Investments and other assets
|
|
|
504.8
|
|
|
|
427.0
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
9,955.3
|
|
|
$
|
9,695.6
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND STOCKHOLDERS EQUITY
|
Current liabilities
|
|
|
|
|
|
|
|
|
Current maturities of long-term debt
|
|
$
|
14.1
|
|
|
$
|
17.0
|
|
Liabilities from coal trading activities, net
|
|
|
110.6
|
|
|
|
304.2
|
|
Accounts payable and accrued expenses
|
|
|
1,187.7
|
|
|
|
1,535.0
|
|
|
|
|
|
|
|
|
|
|
Total current liabilities
|
|
|
1,312.4
|
|
|
|
1,856.2
|
|
Long-term debt, less current maturities
|
|
|
2,738.2
|
|
|
|
2,776.6
|
|
Deferred income taxes
|
|
|
299.1
|
|
|
|
20.8
|
|
Asset retirement obligations
|
|
|
452.1
|
|
|
|
418.7
|
|
Accrued postretirement benefit costs
|
|
|
914.1
|
|
|
|
766.1
|
|
Other noncurrent liabilities
|
|
|
483.5
|
|
|
|
737.7
|
|
|
|
|
|
|
|
|
|
|
Total liabilities
|
|
|
6,199.4
|
|
|
|
6,576.1
|
|
Stockholders equity
|
|
|
|
|
|
|
|
|
Preferred Stock $0.01 per share par value;
10,000,000 shares authorized, no shares issued or
outstanding as of December 31, 2009 or December 31,
2008
|
|
|
|
|
|
|
|
|
Series A Junior Participating Preferred Stock
1,500,000 shares authorized, no shares issued or
outstanding as of December 31, 2009 or December 31,
2008
|
|
|
|
|
|
|
|
|
Perpetual Preferred Stock 750,000 shares
authorized, no shares issued or outstanding as of
December 31, 2009 or December 31, 2008
|
|
|
|
|
|
|
|
|
Series Common Stock $0.01 per share par value;
40,000,000 shares authorized, no shares issued or
outstanding as of December 31, 2009 or December 31,
2008
|
|
|
|
|
|
|
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|
Common Stock $0.01 per share par value;
800,000,000 shares authorized, 276,848,279 shares
issued and 268,203,815 shares outstanding as of
December 31, 2009 and 275,211,240 shares issued and
266,644,979 shares outstanding as of December 31, 2008
|
|
|
2.8
|
|
|
|
2.8
|
|
Additional paid-in capital
|
|
|
2,067.7
|
|
|
|
2,020.2
|
|
Retained earnings
|
|
|
2,183.8
|
|
|
|
1,802.4
|
|
Accumulated other comprehensive loss
|
|
|
(183.5
|
)
|
|
|
(388.5
|
)
|
Treasury shares, at cost: 8,644,464 shares as of
December 31, 2009 and 8,566,261 shares as of
December 31, 2008
|
|
|
(321.1
|
)
|
|
|
(318.8
|
)
|
|