PEABODY ENERGY CORP
10-Ks and 10-Qs
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Table of Contents
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C.
20549
Form 10-K
|
þ
|
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 | |
| For the Fiscal Year Ended December 31, 2009 | ||
|
or
|
||
|
o
|
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 | |
Commission File Number 1-16463
Peabody Energy
Corporation
(Exact name of registrant as
specified in its charter)
|
Delaware
(State or other jurisdiction of incorporation or organization) |
13-4004153
(I.R.S. Employer Identification No.) |
|
|
701 Market Street, St. Louis, Missouri
(Address of principal executive offices) |
63101
(Zip Code) |
(314) 342-3400
Registrant’s telephone
number, including area code
Securities
Registered Pursuant to Section 12(b) of the Act:
|
Title of Each Class
|
Name of Each Exchange on Which Registered
|
|
| Common Stock, par value $0.01 per share | New York Stock Exchange | |
| Preferred Share Purchase Rights | New York Stock Exchange |
Securities
Registered Pursuant to Section 12(g) of the Act:
None
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 registrant’s
knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this
Form 10-K
or any amendment to this
Form 10-K.
þ
Indicate by check mark whether the registrant is a large
accelerated filer, an accelerated filer, a non-accelerated
filer, or a smaller reporting company. See the definitions of
“large accelerated filer,” “accelerated
filer” and “smaller reporting company” in
Rule 12b-2 of the Exchange Act. (Check one):
| Large accelerated filer þ | Accelerated filer o | Non-accelerated filer o | Smaller reporting company o |
(Do not check if a smaller reporting company)
Indicate by check mark whether the registrant is a shell company
(as defined in
Rule 12b-2
of the Exchange
Act). Yes
o
No
þ
Aggregate market value of the voting stock held by
non-affiliates (shareholders who are not directors or executive
officers) of the Registrant, calculated using the closing price
on June 30, 2009: Common Stock, par value $0.01 per share,
$8.1 billion.
Number of shares outstanding of each of the Registrant’s
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 Company’s Proxy Statement to be filed with
the Securities and Exchange Commission in connection with the
Company’s 2010 Annual Meeting of Stockholders (the
Company’s 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.
Table of Contents
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 Management’s 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:
| • | demand for coal in United States (U.S.), China and other international power generation and steel production markets; | |
| • | price volatility and demand, particularly in higher-margin products and in our trading and brokerage businesses; | |
| • | reductions and/or deferrals of purchases by major customers and ability to renew sales contracts; | |
| • | credit and performance risks associated with customers, suppliers, trading, banks and other financial counterparties; | |
| • | geologic, equipment, permitting and operational risks related to mining; | |
| • | transportation availability, performance and costs; | |
| • | availability, timing of delivery and costs of key supplies, capital equipment or commodities such as diesel fuel, steel, explosives and tires; | |
| • | impact of weather on demand, production and transportation; | |
| • | successful implementation of business strategies, including our Btu Conversion and generation development initiatives; | |
| • | negotiation of labor contracts, employee relations and workforce availability; | |
| • | changes in postretirement benefit and pension obligations and funding requirements; | |
| • | replacement and development of coal reserves; | |
| • | access to capital and credit markets and availability and costs of credit, margin capacity, surety bonds, letters of credit, and insurance; | |
| • | effects of changes in interest rates and currency exchange rates (primarily the Australian dollar); | |
| • | effects of acquisitions or divestitures; | |
| • | economic strength and political stability of countries in which we have operations or serve customers; | |
| • | 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; |
i
Table of Contents
| • | litigation, including claims not yet asserted; | |
| • | terrorist attacks or threats; | |
| • | impacts of pandemic illnesses; and | |
| • | other factors, including those discussed in Legal Proceedings, set forth in Item 3 of this report and Risk Factors, set forth in Item 1A of this report. |
When considering these forward-looking statements, you should
keep in mind the cautionary statements in this document and in
our other Securities and Exchange Commission (SEC) filings.
These forward-looking statements speak only as of the date on
which such statements were made, and we undertake no obligation
to update these statements except as required by federal
securities laws.
ii
TABLE OF
CONTENTS
1
Table of Contents
| Note: | The words “we,” “our,” “Peabody” or “the Company” as used in this report, refer to Peabody Energy Corporation or its applicable subsidiary or subsidiaries. Unless otherwise noted herein, disclosures in this Annual Report on Form 10-K relate only to our continuing operations. |
| Item 1. | Business. |
History
and Development of Business
Peabody Energy Corporation is the world’s 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:
| 1) | Executing the basics of best-in-class safety, operations and marketing; | |
| 2) | Capitalizing on organic growth opportunities; | |
| 3) | Expanding in high-growth global markets; and | |
| 4) | 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. |
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
Table of Contents
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
Table of Contents
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 | Method | Type | Method | (In millions) | ||||||||
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Western U.S. Mining
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||||||||||||||
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North Antelope Rochelle
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Wright, WY | S | DL, T/S | Thermal | R | 98.3 | ||||||||
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Caballo
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Gillette, WY | S | D, T/S | Thermal | R | 23.3 | ||||||||
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Rawhide
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Gillette, WY | S | D, T/S | Thermal | R | 15.8 | ||||||||
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Twentymile
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Oak Creek, CO | U | LW | Thermal | R, T | 7.7 | ||||||||
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Kayenta
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Kayenta, AZ | S | DL, T/S | Thermal | R | 7.5 | ||||||||
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El Segundo
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Grants, NM | S | T/S | Thermal | R | 5.4 | ||||||||
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Lee Ranch
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Grants, NM | S | DL, T/S | Thermal | R | 2.1 | ||||||||
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Midwestern U.S. Mining
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||||||||||||||
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Farmersburg
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Pimento, IN | S | DL, D, T/S | Thermal | T, R | 3.6 | ||||||||
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Willow Lake
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Equality, IL | U | CM | Thermal | T/B | 3.5 | ||||||||
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Gateway
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Coulterville, IL | U | CM | Thermal | T, R, R/B | 3.4 | ||||||||
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Somerville Central
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Oakland City, IN | S | DL, D, T/S | Thermal | R, T/R, T/B | 3.4 | ||||||||
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Cottage Grove
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Equality, IL | S | D, T/S | Thermal | T/B | 2.1 | ||||||||
|
Francisco Underground
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Francisco, IN | U | CM | Thermal | R | 2.0 | ||||||||
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Somerville North
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Oakland City, IN | S | D, T/S | Thermal | R, T/R, T/B | 2.0 | ||||||||
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Miller Creek
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Bicknell, IN | S | D, T/S | Thermal | T, T/R | 2.0 | ||||||||
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Somerville South
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Oakland City, IN | S | D, T/S | Thermal | R, T/R, T/B | 1.7 | ||||||||
|
Air Quality
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Vincennes, IN | U | CM | Thermal | T, T/R, T/B | 1.6 | ||||||||
|
Viking
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Cannelburg, IN | S | D, T/S | Thermal | T, T/R | 1.6 | ||||||||
|
Wildcat Hills Underground
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Eldorado, IL | U | CM | Thermal | T/B | 0.7 | ||||||||
|
Other(1)
|
— | — | — | — | — | 4.2 | ||||||||
|
Australian Mining
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||||||||||||||
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Wilpinjong*
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Wilpinjong, New South Wales | S | T/S | Thermal | R, EV | 8.3 | ||||||||
|
Burton*(2)
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Glenden, Queensland | S | T/S | Thermal/Met | R, EV | 2.5 | ||||||||
|
Wilkie Creek
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Macalister, Queensland | S | T/S | Thermal | R, EV | 2.3 | ||||||||
|
North Wambo Underground
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Warkworth, New South Wales | U | LW | Thermal/Met** | R, EV | 2.3 | ||||||||
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Wambo Open-Cut*
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Warkworth, New South Wales | S | T/S | Thermal | R, EV | 1.9 | ||||||||
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North Goonyella
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Glenden, Queensland | U | LW | Met | R, EV | 1.8 | ||||||||
|
Metropolitan
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Helensburgh, New South Wales | U | LW | Met | R, EV | 1.5 | ||||||||
|
Eaglefield*
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Glenden, Queensland | S | T/S | Met | R, EV | 0.9 | ||||||||
|
Millennium
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Moranbah, Queensland | S | T/S | Met | R, EV | 0.8 | ||||||||
|
Legend:
|
||||||
|
S
|
Surface Mine | R | Rail | |||
|
U
|
Underground Mine | T | Truck | |||
|
DL
|
Dragline | R/B | Rail and Barge | |||
|
D
|
Dozer/Casting | T/B | Truck and Barge | |||
|
T/S
|
Truck and Shovel | T/R | Truck and Rail | |||
|
LW
|
Longwall | EV | Export Vessel | |||
|
CM
|
Continuous Miner | Thermal | Thermal/Steam | |||
| Met | Metallurgical | |||||
| * | Mine is operated by a contract miner | |
| ** | Metallurgical coal is pulverized coal injection, or PCI |
| (1) | “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. | |
| (2) | The Burton Mine is a 95% proportionally owned and consolidated mine. |
4
Table of Contents
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-Gas
tm
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
Table of Contents
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 American’s 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
Table of Contents
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.
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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 Association’s “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 country’s 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 subsidiary’s hourly production
and engineering employees, including those employed through
contract mining relationships. All the Australian
subsidiary’s 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.
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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
year’s 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.
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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 OSM’s 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
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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.
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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 EPA’s
Toxic Release Inventory process, companies are required annually
to report the use, manufacture or processing of listed toxic
materials that exceed defined thresholds, including chemicals
used in equipment maintenance, reclamation, water treatment and
ash received for mine placement from power generation customers.
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.
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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.
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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:
| • | employment conditions; | |
| • | unfair dismissal; | |
| • | enterprise bargaining; | |
| • | industrial action; and | |
| • | resolution of workplace disputes. |
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
CO
2
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 EPA’s
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 Australia’s
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 Australia’s 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 DOE’s 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 SEC’s 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 SEC’s 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.
| Item 1A. | Risk Factors. |
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:
| • | the demand for electricity and the strength of the global economy; | |
| • | the demand for steel, which may lead to price fluctuations in the annual repricing of our metallurgical coal contracts; | |
| • | the supply of U.S. domestic and international thermal and metallurgical coal; | |
| • | competition within our industry and the availability and price of alternative fuels and energy sources; | |
| • | the proximity, capacity and cost of transportation; |
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| • | coal industry capacity; | |
| • | domestic and foreign governmental regulations and taxes, including those establishing air emission standards for coal-fueled power plants; | |
| • | regulatory, administrative and judicial decisions, including those affecting future mining permits; and | |
| • | technological developments, including those intended to convert coal to liquids or gas and those aimed at capturing and storing carbon dioxide. |
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 customer’s 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 customer’s 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:
| • | lack of availability, higher expense or unfavorable market terms of new surety bonds; | |
| • | restrictions on the availability of collateral for current and future third-party surety bond issuers under the terms of our indentures or Senior Unsecured Credit Facility; | |
| • | the exercise by third-party surety bond issuers of their right to refuse to renew the surety; and | |
| • | inability to renew our credit facility. |
Our ability to self bond reduces our costs of providing
financial assurances. To the extent we are unable to maintain
our current level of self bonding, due to legislative or
regulatory changes or changes in our financial condition, our
costs would increase.
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
purchaser’s 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
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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
Table of Contents
amount of indebtedness that we may issue, and the indentures
governing our 6.875% and 5.875% Senior Notes permit the
incurrence of additional indebtedness. The degree to which we
are leveraged could have important consequences, including, but
not limited to:
| • | making it more difficult for us to pay interest and satisfy our debt obligations; | |
| • | increasing our vulnerability to general adverse economic and industry conditions; | |
| • | requiring the dedication of a substantial portion of our cash flow from operations to the payment of principal, and interest on, our indebtedness, thereby reducing the availability of our cash flow to fund working capital, capital expenditures, acquisitions, Btu Conversion and clean coal technology projects or other general corporate uses; | |
| • | 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; | |
| • | limiting our flexibility in planning for, or reacting to, changes in our business and in the coal industry; and | |
| • | placing us at a competitive disadvantage compared to less leveraged competitors. |
In addition, our 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
Table of Contents
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
Table of Contents
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
Table of Contents
development at existing operations. The materiality of such
expenditures can vary greatly relative to a given company’s
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.
| Item 1B. | Unresolved Staff Comments. |
None.
| Item 2. | Properties. |
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.
|
Proven and Probable
|
||||||||||||||
|
Reserves as of
|
||||||||||||||
| December 31, 2009 (1) | ||||||||||||||
|
Owned
|
Leased
|
Total
|
||||||||||||
|
Operating Regions
|
Locations
|
Tons
|
Tons
|
Tons | ||||||||||
| (Tons in millions) | ||||||||||||||
|
Midwest
|
Illinois, Indiana and Kentucky | 2,627 | 939 | 3,566 | ||||||||||
|
Powder River Basin
|
Wyoming and Montana | 67 | 2,948 | 3,015 | ||||||||||
|
Southwest
|
Arizona and New Mexico | 811 | 309 | 1,120 | ||||||||||
|
Colorado
|
Colorado | 44 | 196 | 240 | ||||||||||
|
Total United States
|
3,549 | 4,392 | 7,941 | |||||||||||
|
Australia
|
New South Wales | — | 451 | 451 | ||||||||||
|
Australia
|
Queensland | — | 623 | 623 | ||||||||||
|
Total Australia
|
— | 1,074 | 1,074 | |||||||||||
|
Total Proven and Probable Coal Reserves
|
3,549 | 5,466 | 9,015 | |||||||||||
| (1) | Reserves have been adjusted to take into account estimated losses involved in producing a saleable product. |
Reserves are defined by SEC Industry Guide 7 as that part of a
mineral deposit which could be economically and legally
extracted or produced at the time of the reserve determination.
Proven and probable coal reserves are defined by SEC Industry
Guide 7 as follows:
Proven (Measured) Reserves
— Reserves for which
(a) quantity is computed from dimensions revealed in
outcrops, trenches, workings or drill holes; grade
and/or
quality are computed from the results of detailed sampling and
(b) the sites for inspection, sampling and measurement are
spaced so close and 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
Table of Contents
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
Table of Contents
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
Table of Contents
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)
(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
Table of Contents
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
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
Table of Contents
| (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
Table of Contents
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 Children’s 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 Arizona’s 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 Chancellor’s 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 American’s 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
Table of Contents
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.
| Item 5. | Market for Registrant’s 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. Management’s
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
Table of Contents
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. Management’s 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 Excel’s 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.
Management’s Discussion and Analysis of Financial Condition
and Results of Operations.
35
Table of Contents
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
Table of Contents
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. | Management’s Discussion and Analysis of Financial Condition and Results of Operations. |
Overview
We are the world’s 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 segment’s 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
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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 Australia’s lower annual export contract
pricing that commenced on April 1, 2009 as compared to
2008’s 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
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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
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| 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
segment’s 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 | )% | |||||||
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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.
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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 | % | |||||||||||
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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. | |
| • | Australia’s 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. |
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Table of Contents
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.
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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.
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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
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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 Agency’s (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
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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 world’s 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.
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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.
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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: Moody’s has issued a Ba1 rating,
Standard & Poor’s a BB+ rating, and Fitch
has issued a BB+ rating. The ratings on the Debentures are as
follows: Moody’s has issued a Ba3 rating,
Standard & Poor’s 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
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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.
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Off-Balance
Sheet Arrangements
In the normal course of business, we are a party to certain
off-balance sheet arrangements. These arrangements include
guarantees, 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
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(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
Table of Contents
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
Table of Contents
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 counterparty’s 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
Table of Contents
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
customer’s 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
Table of Contents
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.
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Table of Contents
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
Table of Contents
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.
Management’s
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 Company’s 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
Chairman and Chief Executive Officer |
/s/
Michael
C. Crews
Executive Vice President and Chief Financial Officer |
|||
February 24, 2010
59
Table of Contents
REPORT OF
INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Directors and Stockholders
Peabody Energy Corporation
We have audited Peabody Energy Corporation’s (the
Company’s) internal control over financial reporting as of
December 31, 2009, based on criteria established in
Internal Control — Integrated Framework
, issued
by the Committee of Sponsoring Organizations of the Treadway
Commission (the COSO criteria). Peabody Energy
Corporation’s management is responsible for maintaining
effective internal control over financial reporting and for its
assessment of the effectiveness of internal control over
financial reporting included in the accompanying
Management’s Report on Internal Control Over Financial
Reporting. Our responsibility is to express an opinion on the
Company’s internal control over financial reporting based
on our audit.
We conducted our audit in accordance with the standards of the
Public Company Accounting Oversight Board (United States). Those
standards require that we plan and perform the audit to obtain
reasonable assurance about whether effective internal control
over financial reporting was maintained in all material
respects. Our audit included obtaining an understanding of
internal control over financial reporting, assessing the risk
that a material weakness exists, testing and evaluating the
design and operating effectiveness of internal control based on
the assessed risk, and performing such other procedures as we
considered necessary in the circumstances. We believe that our
audit provides a reasonable basis for our opinion.
A company’s internal control over financial reporting is a
process designed to provide reasonable assurance regarding the
reliability of financial reporting and the preparation of
financial statements for external purposes in accordance with
generally accepted accounting principles. A company’s
internal control over financial reporting includes those
policies and procedures that (1) pertain to the maintenance
of records that, in reasonable detail, accurately and fairly
reflect the transactions and dispositions of the assets of the
company; (2) provide reasonable assurance that transactions
are recorded as necessary to permit preparation of financial
statements in accordance with generally accepted accounting
principles and that receipts and expenditures of the company are
being made only in accordance with authorizations of management
and directors of the company; and (3) provide reasonable
assurance regarding prevention or timely detection of
unauthorized acquisition, use, or disposition of the
company’s assets that could have a material effect on the
financial statements.
Because of its inherent limitations, internal control over
financial reporting may not prevent or detect misstatements.
Also, projections of any evaluation of effectiveness to future
periods are subject to the risk that controls may become
inadequate because of changes in conditions or that the degree
of compliance with the policies or procedures may deteriorate.
In our opinion, 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.
/s/
Ernst &
Young LLP
St. Louis, Missouri
February 24, 2010
60
Table of Contents
| Item 9B. | Other Information. |
None.
| 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
Table of Contents
| 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.
| 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:
| Page | ||||
| F-70 | ||||
| F-71 | ||||
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
Table of Contents
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
/s/
GREGORY
H. BOYCE
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
|
Chairman and Chief Executive Officer,
Director (principal executive officer) |
February 24, 2010 | ||||
|
/s/
MICHAEL
C. CREWS
|
Executive Vice President and Chief
Financial Officer (principal financial and accounting officer) |
February 24, 2010 | ||||
|
/s/
WILLIAM
A. COLEY
|
Director | February 24, 2010 | ||||
|
/s/
WILLIAM
E. JAMES
|
Director | February 24, 2010 | ||||
|
/s/
ROBERT
B. KARN III
|
Director | February 24, 2010 | ||||
|
/s/
M.
FRANCES KEETH
|
Director | February 24, 2010 | ||||
|
/s/
HENRY
E. LENTZ
|
Director | February 24, 2010 | ||||
|
/s/
ROBERT
A. MALONE
|
Director | February 24, 2010 | ||||
|
/s/
WILLIAM
C. RUSNACK
|
Director | February 24, 2010 | ||||
63
Table of Contents
|
Signature
|
Title
|
Date
|
||||
|
/s/
JOHN
F. TURNER
|
Director | February 24, 2010 | ||||
|
/s/
SANDRA
VAN TREASE
|
Director | February 24, 2010 | ||||
|
/s/
ALAN
H. WASHKOWITZ
|
Director | February 24, 2010 | ||||
64
Table of Contents
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 Company’s 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 Corporation’s internal control over
financial reporting as of December 31, 2009, based on
criteria established in
Internal Control —
Integrated Framework
, issued by the Committee of Sponsoring
Organizations of the Treadway Commission, and our report dated
February 24, 2010, expressed an unqualified opinion thereon.
/s/
Ernst &
Young LLP
St. Louis, Missouri
February 24, 2010
F-1
Table of Contents
PEABODY
ENERGY CORPORATION
| 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
Table of Contents
PEABODY
ENERGY CORPORATION
| 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
|
— | — | ||||||
|
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 | ) | ||||
|
Peabody Energy Corporation’s stockholders’ equity
|
3,749.7 | 3,118.1 | ||||||
|
Noncontrolling interests
|
6.2 | 1.4 | ||||||
|
Total stockholders’ equity
|
3,755.9 | 3,119.5 | ||||||
|
Total liabilities and stockholders’ equity
|
$ | 9,955.3 | $ | 9,695.6 | ||||
See accompanying notes to consolidated financial statements
F-3
Table of Contents
PEABODY
ENERGY CORPORATION
| Year Ended December 31, | ||||||||||||
| 2009 | 2008 | 2007 | ||||||||||
| (Dollars in millions) | ||||||||||||
|
Cash Flows From Operating Activities
|
||||||||||||
|
Net income
|
$ | 463.0 | $ | 959.1 | $ | 261.5 | ||||||
|
(Income) loss from discontinued operations, net of income taxes
|
(5.1 | ) | 28.8 | 180.1 | ||||||||
|
Income from continuing operations, net of income taxes
|
457.9 | 987.9 | 441.6 | |||||||||
|
Adjustments to reconcile income from continuing operations, net
of income taxes
|
||||||||||||
|
to net cash provided by operating activities:
|
||||||||||||
|
Depreciation, depletion and amortization
|
405.2 | 402.4 | 346.3 | |||||||||
|
Deferred income taxes
|
131.1 | (33.3 | ) | (196.5 | ) | |||||||
|
Share-based compensation
|
38.8 | 34.9 | 20.1 | |||||||||
|
Amortization of debt discount and debt issuance costs
|
7.8 | 7.7 | 8.0 | |||||||||
|
Net gain on disposal or exchange of assets
|
(23.2 | ) | (72.9 | ) | (88.6 | ) | ||||||
|
(Income) loss from equity affiliates
|
69.1 | — | (14.5 | ) | ||||||||
|
Revenue recovery on coal supply agreement
|
— | (56.9 | ) | — | ||||||||
|
Dividends received from equity affiliates
|
— | 19.9 | 12.9 | |||||||||
|
Changes in current assets and liabilities:
|
||||||||||||
|
Accounts receivable, including securitization
|
81.4 | (114.7 | ) | 65.6 | ||||||||
|
Inventories
|
(48.9 | ) | (13.2 | ) | (60.9 | ) | ||||||
|
Net assets from coal trading activities
|
70.9 | (43.0 | ) | (77.6 | ) | |||||||
|
Other current assets
|
(3.3 | ) | 1.9 | (57.1 | ) | |||||||
|
Accounts payable and accrued expenses
|
(123.8 | ) | 235.1 | 52.6 | ||||||||
|
Asset retirement obligations
|
27.7 | 32.9 | 13.6 | |||||||||
|
Workers’ compensation obligations
|
3.0 | 10.3 | 2.7 | |||||||||
|
Accrued postretirement benefit costs
|
7.2 | 13.6 | 13.1 | |||||||||
|
Contributions to pension plans
|
(38.7 | ) | (21.3 | ) | (5.4 | ) | ||||||
|
Other, net
|
(8.7 | ) | 18.5 | (15.2 | ) | |||||||
|
Net cash provided by continuing operations
|
1,053.5 | 1,409.8 | 460.7 | |||||||||
|
Net cash used in discontinued operations
|
(5.6 | ) | (123.0 | ) | (141.3 | ) | ||||||
|
Net cash provided by operating activities
|
1,047.9 | 1,286.8 | 319.4 | |||||||||
|
Cash Flows From Investing Activities
|
||||||||||||
|
Additions to property, plant, equipment and mine development
|
(260.6 | ) | (264.1 | ) | (438.8 | ) | ||||||
|
Investment in Prairie State Energy Campus
|
(56.8 | ) | (40.9 | ) | (28.8 | ) | ||||||
|
Federal coal lease expenditures
|
(123.6 | ) | (178.5 | ) | (178.2 | ) | ||||||
|
Proceeds from disposal of assets, net of notes receivable
|
53.9 | 72.8 | 119.6 | |||||||||
|
Additions to advance mining royalties
|
(6.1 | ) | (6.0 | ) | (8.1 | ) | ||||||
|
Investments in equity affiliates and joint ventures
|
(15.0 | ) | (2.6 | ) | (4.6 | ) | ||||||
|
Net cash used in continuing operations
|
(408.2 | ) | (419.3 | ) | (538.9 | ) | ||||||
|
Net cash provided by (used in) discontinued operations
|
1.7 | 23.9 | (36.4 | ) | ||||||||
|
Net cash used in investing activities
|
(406.5 | ) | (395.4 | ) | (575.3 | ) | ||||||
|
Cash Flows From Financing Activities
|
||||||||||||
|
Change in revolving line of credit
|
— | (97.7 | ) | 97.7 | ||||||||
|
Payments of long-term debt
|
(37.1 | ) | (32.7 | ) | (117.8 | ) | ||||||
|
Common stock repurchase
|
— | (199.8 | ) | — | ||||||||
|
Dividends paid
|
(66.8 | ) | (64.9 | ) | (63.7 | ) | ||||||
|
Payment of debt issuance costs
|
— | — | (0.8 | ) | ||||||||
|
Excess tax benefit related to stock options exercised
|
— | — | 96.7 | |||||||||
|
Proceeds from stock options exercised
|
3.6 | 14.1 | 26.2 | |||||||||
|
Net proceeds from borrowing
|
0.8 | — | — | |||||||||
|
Acquisition of noncontrolling interests (Millennium Mine)
|
— | (110.1 | ) | — | ||||||||
|
Other, net
|
(2.8 | ) | 4.1 | 3.4 | ||||||||
|
Net cash provided by (used in) continuing operations
|
(102.3 | ) | (487.0 | ) | 41.7 | |||||||
|
Net cash used in discontinued operations
|
— | — | (67.0 | ) | ||||||||
|
Net cash used in financing activities
|
(102.3 | ) | (487.0 | ) | (25.3 | ) | ||||||
|
Net change in cash and cash equivalents
|
539.1 | 404.4 | (281.2 | ) | ||||||||
|
Cash and cash equivalents at beginning of year
|
449.7 | 45.3 | 326.5 | |||||||||
|
Cash and cash equivalents at end of year
|
$ | 988.8 | $ | 449.7 | $ | 45.3 | ||||||
See accompanying notes to consolidated financial statements
F-4
Table of Contents
PEABODY
ENERGY CORPORATION
CONSOLIDATED
STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY
| Peabody Energy Corporation’s Stockholders’ Equity | ||||||||||||||||||||||||||||
|
Accumulated
|
||||||||||||||||||||||||||||
|
Additional
|
Other
|
Total
|
||||||||||||||||||||||||||
|
Common
|
Paid-in
|
Treasury
|
Retained
|
Comprehensive
|
Noncontrolling
|
Stockholders’
|
||||||||||||||||||||||
| Stock | Capital | Stock | Earnings | Loss | Interests | Equity | ||||||||||||||||||||||
| (Dollars in millions) | ||||||||||||||||||||||||||||
|
December 31, 2006
|
$ | 2.7 | $ | 1,788.0 | $ | (103.7 | ) | $ | 1,115.9 | $ | (249.2 | ) | $ | 33.3 | $ | 2,587.0 | ||||||||||||
|
Comprehensive income:
|
||||||||||||||||||||||||||||
|
Net income
|
— | — | — | 263.8 | — | (2.3 | ) | 261.5 | ||||||||||||||||||||
|
Increase in fair value of cash flow hedges (net of $14.5 tax
provision)
|
— | — | — | — | 21.9 | — | 21.9 | |||||||||||||||||||||
|
Postretirement plans and workers’ compensation obligations
(net of $50.2 tax provision)
|
— | — | — | — | 87.2 | — | 87.2 | |||||||||||||||||||||
|
Comprehensive income
|
263.8 | 109.1 | (2.3 | ) | 370.6 | |||||||||||||||||||||||
|
Dividends paid
|
— | — | — | (63.7 | ) | — | — | (63.7 | ) | |||||||||||||||||||
|
Patriot Coal Corporation spin-off
|
— | — | — | (375.1 | ) | 73.0 | (14.1 | ) | (316.2 | ) | ||||||||||||||||||
|
Share-based compensation
|
— | 48.8 | — | — | — | — | 48.8 | |||||||||||||||||||||
|
Stock options exercised
|
— | 26.2 | — | — | — | — | 26.2 | |||||||||||||||||||||
|
Employee stock purchases
|
— | 6.4 | — | — | — | — | 6.4 | |||||||||||||||||||||
|
Shares relinquished
|
— | — | (4.3 | ) | — | — | — | (4.3 | ) | |||||||||||||||||||
|
Income tax benefits from stock options exercised
|
— | 96.7 | — | — | — | — | 96.7 | |||||||||||||||||||||
|
Noncontrolling interests activity related to discontinued
operations
|
— | — | — | — | — | (6.2 | ) | (6.2 | ) | |||||||||||||||||||
|
Acquisition of noncontrolling interests associated with Excel
Coal Limited - purchase accounting adjustment
|
— | — | — | — | — | (7.0 | ) | (7.0 | ) | |||||||||||||||||||
|
Distributions to noncontrolling interests
|
— | — | — | — | — | (3.0 | ) | (3.0 | ) | |||||||||||||||||||
|
December 31, 2007
|
$ | 2.7 | $ | 1,966.1 | $ | (108.0 | ) | $ | 940.9 | $ | (67.1 | ) | $ | 0.7 | $ | 2,735.3 | ||||||||||||
|
Comprehensive income:
|
||||||||||||||||||||||||||||
|
Net income
|
— | — | — | 952.9 | — | 6.2 | 959.1 | |||||||||||||||||||||
|
Decrease in fair value of cash flow hedges (net of $178.2 tax
benefit)
|
— | — | — | — | (217.9 | ) | — | (217.9 | ) | |||||||||||||||||||
|
Postretirement plans and workers’ compensation obligations
(net of $59.3 tax benefit)
|
— | — | — | — | (103.5 | ) | — | (103.5 | ) | |||||||||||||||||||
|
Comprehensive income
|
952.9 | (321.4 | ) | 6.2 | 637.7 | |||||||||||||||||||||||
|
Dividends paid
|
— | — | — | (64.9 | ) | — | — | (64.9 | ) | |||||||||||||||||||
|
Patriot Coal Corporation spin-off adjustment
|
— | — | — | (26.5 | ) | — | — | (26.5 | ) | |||||||||||||||||||
|
Share-based compensation
|
— | 34.9 | — | — | — | — | 34.9 | |||||||||||||||||||||
|
Stock options exercised
|
0.1 | 14.0 | — | — | — | — | 14.1 | |||||||||||||||||||||
|
Employee stock purchases
|
— | 5.2 | — | — | — | — | 5.2 | |||||||||||||||||||||
|
Shares relinquished
|
— | — | (11.0 | ) | — | — | — | (11.0 | ) | |||||||||||||||||||
|
Common stock repurchased
|
— | — | (199.8 | ) | — | — | — | (199.8 | ) | |||||||||||||||||||
|
Distributions to noncontrolling interests
|
— | — | — | — | — | (1.1 | ) | (1.1 | ) | |||||||||||||||||||
|
Eliminations of noncontrolling interests due to acquisitions
|
— | — | — | — | — | (4.4 | ) | (4.4 | ) | |||||||||||||||||||
|
December 31, 2008
|
$ | 2.8 | $ | 2,020.2 | $ | (318.8 | ) | $ | 1,802.4 | $ | (388.5 | ) | $ | 1.4 | $ | 3,119.5 | ||||||||||||
|
Comprehensive income:
|
||||||||||||||||||||||||||||
|
Net income
|
— | — | — | 448.2 | — | 14.8 | 463.0 | |||||||||||||||||||||
|
Increase in fair value of cash flow hedges (net of $220.9 tax
provision)
|
— | — | — | — | 319.8 | — | 319.8 | |||||||||||||||||||||
|
Postretirement plans and workers’ compensation obligations
(net of $71.8 tax benefit)
|
— | — | — | — | (114.8 | ) | — | (114.8 | ) | |||||||||||||||||||
|
Comprehensive income
|
448.2 | 205.0 | 14.8 | 668.0 | ||||||||||||||||||||||||
|
Dividends paid
|
— | — | — | (66.8 | ) | — | — | (66.8 | ) | |||||||||||||||||||
|
Share-based compensation
|
— | 38.8 | — | — | — | — | 38.8 | |||||||||||||||||||||
|
Stock options exercised
|
— | 3.6 | — | — | — | — | 3.6 | |||||||||||||||||||||
|
Employee stock purchases
|
— | 5.1 | — | — | — | — | 5.1 | |||||||||||||||||||||
|
Shares relinquished
|
— | — | (2.3 | ) | — | — | — | (2.3 | ) | |||||||||||||||||||
|
Distributions to noncontrolling interests
|
— | — | — | — | — | (10.0 | ) | (10.0 | ) | |||||||||||||||||||
|
December 31, 2009
|
$ | 2.8 | $ | 2,067.7 | $ | (321.1 | ) | $ | 2,183.8 | $ | (183.5 | ) | $ | 6.2 | $ | 3,755.9 | ||||||||||||
See accompanying notes to consolidated financial statements
F-5
Table of Contents
PEABODY
ENERGY CORPORATION
| (1) | Summary of Significant Accounting Policies |
Basis
of Presentation
The consolidated financial statements include the accounts of
Peabody Energy Corporation (the Company) and its affiliates. All
intercompany transactions, profits and balances have been
eliminated in consolidation.
Description
of Business
The Company is engaged in the mining of thermal coal for sale
primarily to electric utilities and metallurgical coal for sale
to industrial customers. The Company’s mining operations
are located in the United States (U.S.) and Australia, and
include an equity interest in a mining operation in Venezuela.
In addition to the Company’s mining operations, the Company
markets, brokers and trades coal. The Company’s other
energy related commercial activities include participating in
the development of mine-mouth coal-fueled generating plants, the
management of its vast coal reserve and real estate holdings,
and the development of Btu Conversion and clean coal
technologies. The Company’s Btu Conversion projects are
designed to expand the uses of coal through various technologies
such as
coal-to-liquids
and coal gasification.
Newly
Adopted Accounting Standards
In August 2009, the Financial Accounting Standards Board (FASB)
issued accounting guidance that clarifies the fair value
measurement of liabilities in circumstances in which a quoted
price in an active market for the identical liability is not
available. In those circumstances, an entity is required to
measure fair value utilizing one or more of the following
techniques: (1) a valuation technique that uses the quoted
market price of an identical liability or similar liabilities
when traded as assets; or (2) another valuation technique
that is consistent with the principles of Accounting Standards
Codification (ASC) Topic 820, such as a present value technique
or market approach. The guidance also clarifies that when
estimating the fair value liability, a reporting entity is not
required to include a separate input or adjustment to other
inputs relating to the existence of a restriction that prevents
the transfer of a liability. Additionally, the guidance
clarifies that both a quoted price in an active market for the
identical liability at the measurement date and the quoted price
for the identical liability when traded as an asset in an active
market when no adjustments to the quoted price of the asset are
required are Level 1 fair value measurements. The guidance,
which became effective in the fourth quarter of 2009, did not
have a material impact on the Company’s results of
operations or financial condition.
In May 2009, the FASB issued an accounting standard that was
effective upon issuance that establishes accounting and
disclosure guidance for subsequent events, which are events that
occur after the balance sheet date but before financial
statements are issued or are available to be issued. The Company
evaluated subsequent events after the balance sheet date of
December 31, 2009 through the filing of this report with
the Securities and Exchange Commission on February 24, 2010.
In April 2009, the FASB issued an accounting standard which
requires disclosures of the fair value of all financial
instruments for which it is practicable to estimate that value,
whether recognized or not on a company’s balance sheet, in
interim reporting periods and in financial statements for annual
reporting periods. A related standard was also issued in April
2009 which requires entities to disclose the methods and
significant assumptions used to estimate the fair value of
financial instruments and describe changes in methods and
significant assumptions, in both interim and annual financial
statements. The Company adopted the standards on June 30,
2009. See Note 3 for further information.
In April 2009, the FASB issued an accounting standard which
provides additional guidance for estimating fair value when the
volume and level of activity for the asset or liability have
significantly decreased. The standard also includes guidance on
identifying circumstances that indicate a transaction is not
orderly and
F-6
Table of Contents
PEABODY
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
requires that a reporting entity: (1) disclose in interim
and annual periods the inputs and valuation technique(s) used to
measure fair value and a discussion of changes in valuation
techniques and related inputs, if any, during the period, and
(2) define the “major category” for any equity
securities and debt securities to be based on the “major
security types” (nature and risk of the security). The
Company adopted the standard on June 30, 2009. While
adoption of the standard had an impact on the Company’s
disclosures, it did not affect the Company’s results of
operations or financial condition.
In December 2008, the FASB issued an accounting standard to
provide for additional transparency on an employer’s
disclosures about plan assets of a defined benefit pension or
other postretirement plan, including the concentrations of risk
in those plans. The Company adopted the standard on
December 31, 2009. While the adoption of this guidance had
an impact on the Company’s disclosures, it did not affect
the Company’s results of operations, financial condition or
cash flows.
In June 2008, the FASB issued an accounting standard requiring
share-based payment awards that entitle their holders to receive
nonforfeitable dividends or dividend equivalents before vesting
should be considered participating securities and need to be
included in the earnings allocation in computing earnings per
share (EPS) under the “two-class method.” The
two-class method is an earnings allocation formula that
determines EPS for each class of common stock and participating
security according to dividends declared (or accumulated) and
participation rights in undistributed earnings. The
Company’s unvested restricted stock awards are considered
participating securities because they entitle holders to receive
nonforfeitable dividends during the vesting term. In applying
the two-class method, undistributed earnings are allocated
between common shares and unvested restricted stock awards. The
standard was effective for the Company for the fiscal year
beginning January 1, 2009 where the two-class method of
computing basic and diluted EPS was applied for all periods
presented. See Note 7 for additional information.
In May 2008, the FASB issued an accounting standard which
clarifies that convertible debt instruments that may be settled
in cash upon conversion, including partial cash settlement, are
not within the scope of the “Debt” topic of the FASB
ASC. Instead, issuers of such instruments should separately
account for the liability and equity components in a manner that
will reflect the issuer’s nonconvertible debt borrowing
rate when recognizing interest cost in subsequent periods. The
standard was effective for the Company’s Convertible Junior
Subordinated Debentures for the fiscal year beginning
January 1, 2009. Prior period balances in this report have
been adjusted to conform with these provisions. See Note 12
for additional information.
In March 2008, the FASB issued an accounting standard which
expands the disclosure requirements for derivative instruments
and hedging activities. The standard specifically requires
entities to provide enhanced disclosures addressing the
following: (1) how and why an entity uses derivative
instruments, (2) how derivative instruments and related
hedged items are accounted for under the “Derivatives and
Hedging” topic of the FASB ASC, and (3) how derivative
instruments and related hedged items affect an entity’s
financial position, financial performance and cash flows. The
standard was effective for the Company for the fiscal year
beginning January 1, 2009. While the standard had an impact
on the Company’s disclosures, it did not affect the
Company’s results of operations or financial condition.
These additional disclosures are included in Note 3.
In December 2007, the FASB issued an accounting standard which
establishes accounting and reporting guidance for noncontrolling
interests in partially-owned consolidated subsidiaries and the
loss of control of subsidiaries. The standard requires
noncontrolling interests (minority interests) to be reported as
a separate component of equity. In addition, the standard
requires that a parent recognize a gain or loss in net income
when a subsidiary is deconsolidated. The standard was effective
for the Company for the fiscal year beginning January 1,
2009. Prior period balances in this report have been adjusted to
conform with these provisions.
In December 2007, the FASB issued an accounting standard which
changes the principles and requirements for the recognition and
measurement of identifiable assets acquired, liabilities assumed
and any
F-7
Table of Contents
PEABODY
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
noncontrolling interest of an acquiree in the financial
statements of an acquirer. This standard also provides for the
recognition and measurement of goodwill acquired in a business
combination and related disclosure. This standard applies
prospectively to business combinations for which the acquisition
date is on or after the beginning of the first annual reporting
period beginning January 1, 2009. In April 2009, the FASB
issued additional guidance on this topic, which amended and
clarified the initial recognition and measurement, subsequent
measurement and accounting and related disclosures arising from
contingencies in a business combination. Under this guidance,
assets acquired and liabilities assumed in a business
combination that arise from contingencies should be recognized
at fair value on the acquisition date if fair value can be
determined during the measurement period. If fair value cannot
be determined, companies should typically account for the
acquired contingencies using existing guidance. This standard is
effective for business combinations with an acquisition date
that is on or after the beginning of the first annual reporting
period beginning January 1, 2009.
In September 2006, the FASB issued an accounting standard which
establishes a framework for measuring fair value under U.S.
generally accepted accounting principles (GAAP) and expands
disclosures about fair value measurements. The standard applies
under accounting pronouncements that require or permit fair
value measurements, but the standard does not require any new
fair value measurements. In February 2008, the FASB amended the
standard to exclude leasing transactions and to delay the
effective date by one year for nonfinancial assets and
liabilities that are recognized or disclosed at fair value in
the financial statements on a nonrecurring basis. The Company
adopted the standard on a prospective basis on January 1,
2008. In October 2008, the FASB issued additional guidance,
which clarifies the application of the standard in an inactive
market and demonstrated how the fair value of a financial asset
is determined when the market for that financial asset is
inactive. This guidance was effective upon issuance, including
prior periods for which financial statements had not been
issued. The adoption of the standard did not have a material
impact on the Company’s determination of fair value for
financial assets. See Note 3 for additional details on fair
value.
Accounting
Standards Not Yet Implemented
In June 2009, the FASB issued accounting guidance which modifies
how a company determines when an entity that is insufficiently
capitalized or is not controlled through voting (or similar
rights) should be consolidated. The guidance clarifies that the
determination of whether a company is required to consolidate an
entity is based on, among other things, an entity’s purpose
and design and a company’s ability to direct the activities
of the entity that most significantly impact the entity’s
economic performance. The guidance also requires an ongoing
reassessment of whether a company is the primary beneficiary of
a variable interest entity, and additional disclosures about a
company’s involvement in variable interest entities and any
associated changes in risk exposure. The guidance is applicable
for annual periods beginning after November 15, 2009
(January 1, 2010 for the Company), at which time the
Company will begin the monitoring and assessment of its business
ventures in accordance with the guidance.
In June 2009, the FASB issued an accounting standard that seeks
to improve the relevance, representational faithfulness and
comparability of the information that a reporting entity
provides in its financial statements about a transfer of
financial assets; the effects of a transfer on its financial
position, financial performance and cash flows; and a
transferor’s continuing involvement, if any, in transferred
financial assets. The standard is effective for annual periods
beginning after November 15, 2009 (January 1, 2010 for
the Company). While the adoption of this guidance will have an
impact on the Company’s disclosures, it will not affect the
Company’s results of operations, financial condition or
cash flows.
Sales
The Company’s revenue from coal sales is realized and
earned when risk of loss passes to the customer. Under the
typical terms of the Company’s coal supply agreements,
title and risk of loss transfer to the
F-8
Table of Contents
PEABODY
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
customer at the mine or port, where coal is loaded to the
transportation source(s) that serves each of the Company’s
mines. The Company incurs certain “add-on” taxes and
fees on coal sales. Reported coal sales include taxes and fees
charged by various federal and state governmental bodies and the
freight charges on destination customer contracts.
Other
Revenues
Other revenues include royalties related to coal lease
agreements, sales agency commissions, farm income, property and
facility rentals, generation development activities, net
revenues from coal trading activities accounted for under the
Derivatives and Hedging guidance of the ASC and contract
termination or restructuring payments. Royalty income generally
results from the lease or sublease of mineral rights to third
parties, with payments based upon a percentage of the selling
price or an amount per ton of coal produced.
Discontinued
Operations and Assets Held for Sale
The Company classifies items within discontinued operations in
the consolidated statements of operations when the operations
and cash flows of a particular component (defined as operations
and cash flows that can be clearly distinguished, operationally
and for financial reporting purposes, from the rest of the
entity) of the Company have been (or will be) eliminated from
the ongoing operations of the Company as a result of a disposal
transaction, and the Company will no longer have any significant
continuing involvement in the operations of that component. See
Note 2 for additional details related to discontinued
operations and assets held for sale.
Cash
and Cash Equivalents
Cash and cash equivalents are stated at cost, which approximates
fair value. Cash equivalents consist of highly liquid
investments with original maturities of three months or less.
Inventories
Materials and supplies and coal inventory are valued at the
lower of average cost or market. Raw coal represents coal
stockpiles that may be sold in current condition or may be
further processed prior to shipment to a customer. Coal
inventory costs include labor, supplies, equipment, operating
overhead and other related costs.
Property,
Plant, Equipment and Mine Development
Property, plant, equipment and mine development are recorded at
cost. Interest costs applicable to major asset additions are
capitalized during the construction period. Capitalized interest
in 2009, 2008 and 2007 was immaterial.
Expenditures which extend the useful lives of existing plant and
equipment assets are capitalized. Maintenance and repairs are
charged to operating costs as incurred. Costs incurred to
develop coal mines or to expand the capacity of operating mines
are capitalized. Costs incurred to maintain current production
capacity at a mine and exploration expenditures are charged to
operating costs as incurred, including costs related to drilling
and study costs incurred to convert or upgrade mineral resources
to reserves. Costs to acquire computer hardware and the
development
and/or
purchase of software for internal use are capitalized and
depreciated over the estimated useful lives.
Coal reserves are recorded at cost, or at fair value in the case
of acquired businesses. The net book value of coal reserves
totaled $5.3 billion as of December 31, 2009 and
$5.4 billion as of December 31, 2008. These coal
reserves include mineral rights for leased coal interests and
advance royalties that had a net book value of $4.0 billion
as of December 31, 2009 and $4.1 billion as of
December 31, 2008. The remaining net book
F-9
Table of Contents
PEABODY
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
value of coal reserves of $1.3 billion at December 31,
2009 and 2008 relates to coal reserves held by fee ownership.
Amounts attributable to properties where the Company was not
currently engaged in mining operations or leasing to third
parties and, therefore, the coal reserves were not currently
being depleted was $1.9 billion as of December 31,
2009 and 2008.
Depletion of coal reserves and amortization of advance royalties
is computed using the
units-of-production
method utilizing only proven and probable reserves (as adjusted
for recoverability factors) in the depletion base. Mine
development costs are principally amortized over the estimated
lives of the mines using the straight-line method. Depreciation
of plant and equipment (excluding life of mine assets) is
computed using the straight-line method over the estimated
useful lives as follows:
| Years | ||||
|
Building and improvements
|
10 to 20 | |||
|
Machinery and equipment
|
3 to 37 | |||
|
Leasehold improvements
|
Life of Lease | |||
In addition, certain plant and equipment assets associated with
mining are depreciated using the straight-line method over the
estimated life of the mine, which varies from one to
37 years.
Investments
in Joint Ventures
The Company accounts for its investments in less than majority
owned corporate joint ventures under either the equity or cost
method. The Company applies the equity method to investments in
joint ventures when it has the ability to exercise significant
influence over the operating and financial policies of the joint
venture. Investments accounted for under the equity method are
initially recorded at cost, and any difference between the cost
of the Company’s investment and the underlying equity in
the net assets of the joint venture at the investment date is
amortized over the lives of the related assets that gave rise to
the difference. The Company’s pro rata share of earnings
from joint ventures and basis difference amortization is
reported in the consolidated statements of operations in
“(Income) loss from equity affiliates.” Included in
the Company’s equity method investments is its joint
venture interest in Carbones del Guasare, which owns and
operates the Paso Diablo Mine in Venezuela. In 2009, the Company
recognized an impairment loss of $34.7 million related to
its interest in Carbones del Guasare based on the joint
venture’s deteriorating operating results (resulting in
2009 equity losses of $19.9 million), ongoing cash flow
issues resulting in no dividend payments since January 2008, the
Company’s expectations concerning ongoing operating and
cash flow issues for the joint venture and uncertainty impacting
recoverability of this investment. The table below summarizes
the book value of the Company’s equity method investments,
which is reported in “Investments and other assets” in
the consolidated balance sheets, the income (loss) from its
equity affiliates and dividends received from its equity
investments:
|
Income (loss) from equity
|
||||||||||||||||||||
|
affiliates for the year ended
|
||||||||||||||||||||
| Book value at December 31, | December 31, | |||||||||||||||||||
| 2009 | 2008 | 2009 | 2008 | 2007 | ||||||||||||||||
| (Dollars in millions) | ||||||||||||||||||||
|
Interest in Carbones del Guasare
|
$ | — | $ | 54.2 | $ | (54.6 | ) | $ | 5.7 | $ | 21.2 | |||||||||
|
Other equity method investments
|
14.1 | 7.0 | (14.5 | ) | (5.7 | ) | (6.7 | ) | ||||||||||||
|
Total equity method investments
|
$ | 14.1 | $ | 61.2 | $ | (69.1 | ) | $ | — | $ | 14.5 | |||||||||
F-10
Table of Contents
PEABODY
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
Asset
Retirement Obligations
The Company’s asset retirement obligation (ARO) liabilities
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.
The Company estimates its ARO liabilities for final reclamation
and mine closure based upon detailed engineering calculations of
the amount and timing of the future cash spending for a
third-party to perform the required work. Spending estimates are
escalated for inflation and then discounted at the
credit-adjusted, risk-free rate. The Company records an ARO
asset associated with the discounted liability for final
reclamation and mine closure. The obligation and corresponding
asset are recognized in the period in which the liability is
incurred. The ARO asset is amortized on the
units-of-production
method over its expected life and the ARO liability is accreted
to the projected spending date. As changes in estimates occur
(such as mine plan revisions, changes in estimated costs or
changes in timing of the performance of reclamation activities),
the revisions to the obligation and asset are recognized at the
appropriate historical credit-adjusted, risk-free rate. The
Company also recognizes an obligation for contemporaneous
reclamation liabilities incurred as a result of surface mining.
Contemporaneous reclamation consists primarily of grading,
topsoil replacement and re-vegetation of backfilled pit areas.
Environmental
Liabilities
Included in “Other noncurrent liabilities” are
accruals for other environmental matters that are recorded in
operating expenses when it is probable that a liability has been
incurred and the amount of the liability can be reasonably
estimated. Accrued liabilities are exclusive of claims against
third parties and are not discounted. In general, costs related
to environmental remediation are charged to expense.
Income
Taxes
Income taxes are accounted for using a balance sheet approach.
The Company accounts for deferred income taxes by applying
statutory tax rates in effect at the reporting date of the
balance sheet to differences between the book and tax basis of
assets and liabilities. A valuation allowance is established if
it is “more likely than not” that the related tax
benefits will not be realized. In determining the appropriate
valuation allowance, the Company considers projected realization
of tax benefits based on expected levels of future taxable
income, available tax planning strategies, and the overall
deferred tax position.
The Company recognized the tax benefit from uncertain tax
positions only if it is “more likely than not” the tax
position will be sustained on examination by the taxing
authorities. The tax benefits recognized from such a position
are measured based on the largest benefit that has a greater
than fifty percent likelihood of being realized upon ultimate
settlement. To the extent the Company’s assessment of such
tax positions changes, the change in estimate will be recorded
in the period in which the determination is made. Tax-related
interest and penalties are classified as a component of income
tax expense.
Postretirement
Health Care and Life Insurance Benefits
The Company accounts for postretirement benefits other than
pensions by accruing the costs of benefits to be provided over
the employees’ period of active service. These costs are
determined on an actuarial basis. The Company’s
consolidated balance sheets reflect the funded status of
postretirement benefits.
Pension
Plans
The Company sponsors non-contributory defined benefit pension
plans accounted for by accruing the cost to provide the benefits
over the employees’ period of active service. These costs
are determined on an
F-11
Table of Contents
PEABODY
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
actuarial basis. The Company’s consolidated balance sheets
reflect the funded status of the defined benefit pension plans.
Derivatives
The Company recognizes at fair value all derivatives as assets
or liabilities on the consolidated balance sheets. Gains or
losses from derivative financial instruments designated as fair
value hedges are recognized immediately in the consolidated
statements of operations, along with the offsetting gain or loss
related to the underlying hedged item.
Non-derivative contracts and derivative contracts for which the
Company has elected to apply the normal purchase/normal sale
exception are accounted for on an accrual basis.
Gains or losses on derivative financial instruments designated
as cash flow hedges are recorded as a separate component of
stockholders’ equity until the hedged transaction occurs
(or until hedge ineffectiveness is determined), at which time
gains or losses are reclassified to the consolidated statements
of operations in conjunction with the recognition of the
underlying hedged item. To the extent that the periodic changes
in the fair value of the derivatives exceed the changes in the
hedged item, the ineffective portion of the periodic non-cash
changes are recorded in the consolidated statements of
operations in the period of the change. If the hedge ceases to
qualify for hedge accounting, the Company prospectively
recognizes the
mark-to-market
movements in the consolidated statements of operations in the
period of the change. The potential for hedge ineffectiveness is
present in the design of the Company’s cash flow hedge
relationships and is discussed in detail in Note 3.
Use of
Estimates in the Preparation of the Consolidated Financial
Statements
The preparation of financial statements in conformity with GAAP
requires management to make estimates and assumptions that
affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of
the financial statements and reported amounts of revenues and
expenses during the reporting period. Actual results could
differ from those estimates.
Impairment
of Long-Lived Assets
The Company records impairment losses on long-lived assets used
in operations when events and circumstances indicate that assets
might be impaired and the undiscounted cash flows estimated to
be generated by those assets under various assumptions are less
than the carrying amounts of the assets. Impairment losses are
measured by comparing the estimated fair value of the impaired
asset to its carrying amount. There were no impairment losses
recorded during the years ended December 31, 2009, 2008 or
2007.
Fair
Value
For assets and liabilities that are recognized or disclosed at
fair value in the consolidated financial statements, the Company
defines fair value as the price that would be received to sell
an asset or paid to transfer a liability in an orderly
transaction between market participants at the measurement date.
The Company’s asset and liability derivative positions are
offset on a
counterparty-by-counterparty
basis if the contractual agreement provides for the net
settlement of contracts with the counterparty in the event of
default or termination of any one contract.
Foreign
Currency
The Company’s foreign subsidiaries utilize the
U.S. dollar as their functional currency. As such, monetary
assets and liabilities are remeasured at year-end exchange rates
while non-monetary items are remeasured at
F-12
Table of Contents
PEABODY
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
historical rates. Income and expense accounts are remeasured at
the average rates in effect during the year, except for those
expenses related to balance sheet amounts that are remeasured at
historical exchange rates. Gains and losses from foreign
currency remeasurement related to tax balances are included as a
component of income tax expense while all other remeasurement
gains and losses are included in operating costs and expenses.
The foreign currency remeasurement loss for the year ended
December 31, 2009, was $55.4 million. The foreign
currency remeasurement gain for the year ended December 31,
2008 was $71.1 million and the foreign currency
remeasurement loss for the year ended December 31, 2007 was
$61.2 million.
Share-Based
Compensation
The Company accounts for share-based compensation at the grant
date fair value of awards and recognizes the related expense
over the vesting period of the award.
Exploration
and Drilling Costs
Exploration expenditures are charged to operating costs as
incurred, including costs related to drilling and study costs
incurred to convert or upgrade mineral resources to reserves.
Advance
Stripping Costs
Pre-production:
At existing surface
operations, additional pits may be added to increase production
capacity in order to meet customer requirements. These
expansions may require significant capital to purchase
additional equipment, expand the workforce, build or improve
existing haul roads and create the initial pre-production box
cut to remove overburden (i.e., advance stripping costs) for new
pits at existing operations. If these pits operate in a separate
and distinct area of the mine, the costs associated with
initially uncovering coal (i.e., advance stripping costs
incurred for the initial box cuts) for production are
capitalized and amortized over the life of the developed pit
consistent with coal industry practices.
Post-production:
Advance stripping costs
related to post-production are expensed as incurred. Where new
pits are routinely developed as part of a contiguous mining
sequence, the Company expenses such costs as incurred. The
development of a contiguous pit typically reflects the planned
progression of an existing pit, thus maintaining production
levels from the same mining area utilizing the same employee
group and equipment.
Reclassifications
Certain amounts in prior periods have been reclassified to
conform with the current year presentation, with no effect on
previously reported net income or stockholders’ equity.
| (2) | Discontinued Operations |
Patriot
Coal Corporation
On October 31, 2007, the Company spun-off portions of its
formerly Eastern U.S. Mining operations business 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.
Revenues from the spun-off operations are the result of supply
agreements the Company entered into with Patriot to meet
commitments under non-assignable pre-existing customer
agreements sourced from Patriot mining operations. The Company
makes no profit as part of these arrangements. The loss from
discontinued operations for the year ended December 31,
2008 was primarily related to the write-off of a
$19.4 million
F-13
Table of Contents
PEABODY
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
receivable related to excise taxes previously paid on export
shipments produced from discontinued operations. As part of the
Patriot spin-off, the Company retained a receivable for excise
tax refunds on export shipments that had previously been ruled
unconstitutional by the appellate court. The U.S. Supreme
Court reversed the appellate court’s ruling on
April 15, 2008, and the Company recorded the charge to
discontinued operations.
In October 2008, the Energy Improvement and Extension Act of
2008 was enacted, which contained provisions that allow for the
refund of coal excise tax collected on coal exported from the
U.S. between January 1, 1990 and the date of the
legislation. The Company’s claim for refund was approved by
the Internal Revenue Service (IRS) in 2009. During the year
ended December 31, 2009 the refund of approximately
$35 million (net of income taxes) was recorded in
“Income (loss) from discontinued operations, net of income
taxes” in the consolidated statement of operations.
Approximately $59 million was received during 2009 and is
shown in “Net cash used in discontinued operations” as
a component of cash flows from operating activities in the
consolidated statements of cash flows.
Baralaba
In December 2008, the Company sold its Baralaba Mine, a
non-strategic Australian mine, for $25.8 million of cash
proceeds and an Australian dollar note receivable valued at
approximately $8.7 million on December 31, 2008,
resulting in a gain of $26.2 million. In 2008, the non-cash
portion of this transaction was excluded from the investing
section of the consolidated statement of cash flows.
Chain
Valley
In December 2009, the Company sold its Chain Valley Mine, a
non-strategic Australian mine, and recorded a loss of
$10.0 million in conjunction with the sale.
F-14
Table of Contents
PEABODY
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
Summary
Financial Information
Operating results related to discontinued operations and assets
held for sale were as follows:
| Year Ended December 31, | ||||||||||||
| 2009 | 2008 | 2007 | ||||||||||
| (Dollars in millions) | ||||||||||||
|
Revenues:
|
||||||||||||
|
Patriot
|
$ | 275.7 | $ | 431.2 | $ | 1,024.5 | ||||||
|
Baralaba
|
— | 18.8 | 22.1 | |||||||||
|
Chain Valley
|
20.6 | 32.4 | 21.3 | |||||||||
|
Assets held for sale
|
5.2 | 30.6 | 39.5 | |||||||||
|
Total
|
$ | 301.5 | $ | 513.0 | $ | 1,107.4 | ||||||
|
Income (loss) before income taxes:
|
||||||||||||
|
Patriot
|
$ | 35.4 | $ | (23.0 | ) | $ | (238.4 | ) | ||||
|
Baralaba
|
— | 10.5 | (10.6 | ) | ||||||||
|
Chain Valley
|
(16.8 | ) | (3.5 | ) | (6.9 | ) | ||||||
|
Assets held for sale
|
(4.2 | ) | (44.6 | ) | 13.5 | ) | ||||||
|
Total
|
$ | 14.4 | $ | (60.6 | ) | $ | (269.4 | ) | ||||
|
Income tax provision (benefit):
|
||||||||||||
|
Patriot
|
$ | 13.6 | $ | (8.9 | ) | $ | (81.5 | ) | ||||
|
Baralaba
(1)
|
— | — | — | |||||||||
|
Chain Valley
|
(2.8 | ) | (6.0 | ) | (2.5 | ) | ||||||
|
Assets held for sale
|
(1.5 | ) | (16.9 | ) | (5.3 | ) | ||||||
|
Total
|
$ | 9.3 | $ | (31.8 | ) | $ | (89.3 | ) | ||||
|
Income (loss), net of income taxes:
|
||||||||||||
|
Patriot
|
$ | 21.8 | $ | (14.1 | ) | $ | (156.9 | ) | ||||
|
Baralaba
|
— | 10.5 | (10.6 | ) | ||||||||
|
Chain Valley
|
(14.0 | ) | 2.5 | (4.4 | ) | |||||||
|
Assets held for sale
|
(2.7 | ) | (27.7 | ) | (8.2 | ) | ||||||
|
Total
|
$ | 5.1 | $ | (28.8 | ) | $ | (180.1 | ) | ||||
| (1) | Income tax benefits associated with Baralaba’s operating results were completely offset by valuation allowances recorded against the deferred tax assets created by the operating losses. |
F-15
Table of Contents
PEABODY
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
Assets and liabilities related to discontinued operations were
as follows:
| December 31, 2009 | December 31, 2008 | |||||||||||||||||||||||||||
|
Assets held
|
Assets held
|
|||||||||||||||||||||||||||
| Patriot (1) | for sale | Total | Patriot (1) | Chain Valley | for sale | Total | ||||||||||||||||||||||
| (Dollars in millions) | ||||||||||||||||||||||||||||
|
Assets
|
||||||||||||||||||||||||||||
|
Current assets
|
||||||||||||||||||||||||||||
|
Other current assets
|
$ | 29.2 | $ | — | $ | 29.2 | $ | 51.0 | $ | 3.1 | $ | — | $ | 54.1 | ||||||||||||||
|
Total current assets
|
29.2 | — | 29.2 | 51.0 | 3.1 | — | 54.1 | |||||||||||||||||||||
|
Noncurrent assets
|
||||||||||||||||||||||||||||
|
Investments and other assets
|
— | 11.4 | 11.4 | 4.9 | 17.8 | 12.6 | 35.3 | |||||||||||||||||||||
|
Total assets
|
$ | 29.2 | $ | 11.4 | $ | 40.6 | $ | 55.9 | $ | 20.9 | $ | 12.6 | $ | 89.4 | ||||||||||||||
|
Liabilities
|
||||||||||||||||||||||||||||
|
Current liabilities
|
||||||||||||||||||||||||||||
|
Accounts payable and accrued expenses
|
$ | 40.6 | $ | — | $ | 40.6 | $ | 69.1 | $ | 5.4 | $ | — | $ | 74.5 | ||||||||||||||
|
Total current liabilities
|
40.6 | — | 40.6 | 69.1 | 5.4 | — | 74.5 | |||||||||||||||||||||
|
Noncurrent liabilities
|
||||||||||||||||||||||||||||
|
Other noncurrent liabilities
|
— | 6.5 | 6.5 | 12.8 | 4.6 | 9.4 | 26.8 | |||||||||||||||||||||
|
Total liabilities
|
$ | 40.6 | $ | 6.5 | $ | 47.1 | $ | 81.9 | $ | 10.0 | $ | 9.4 | $ | 101.3 | ||||||||||||||
| (1) | “Other current assets” included receivables from customers in relation to the supply agreements with Patriot and “Accounts payable and accrued expenses” included the amounts due to Patriot on these pass-through transactions. |
| (3) | Labor Relations, Risk Management and Fair Value Measurements |
Employees
As of December 31, 2009, the Company had approximately
7,300 employees, which included approximately
5,400 hourly employees. As of December 31, 2009,
approximately 29% of the Company’s hourly employees were
represented by organized labor unions and generated 10% of its
2009 coal production. Relations with its employees and, where
applicable, organized labor are important to the Company’s
success.
U.S. Labor Relations.
Hourly workers at the
Company’s Kayenta Mine in Arizona are represented by the
United Mine Workers of America (UMWA) under the Western Surface
Agreement, which is effective through September 2, 2013.
This agreement covers approximately 7% of the Company’s
U.S. subsidiaries’ hourly employees, who generated 4%
of the Company’s U.S. production during the year ended
December 31, 2009.
Hourly workers at the Company’s 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 the
Company’s U.S. subsidiaries’ hourly employees,
who generated approximately 2% of the Company’s
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 the Company’s Australian Mining operations are
members of trade unions. The
F-16
Table of Contents
PEABODY
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
Construction Forestry Mining and Energy Union represents the
Company’s Australian subsidiary’s hourly production
and engineering employees, including those employed through
contract mining relationships. All the Australian
subsidiary’s mine sites have enterprise bargaining
agreements. The current labor agreement at the Company’s
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), the Company has
reached agreements in principle, with the vote of the unions and
employees expected to take place in late February 2010.
Risk
Management — Non Coal Trading
The Company is exposed to various types of risk in the normal
course of business, including fluctuations in commodity prices,
interest rates and foreign currency exchange rates. These risks
are actively monitored in an effort to ensure compliance with
the risk management policies of the Company. In most cases,
commodity price risk (excluding coal trading activities) related
to the sale of coal is mitigated through the use of long-term,
fixed-price contracts rather than financial instruments.
Interest Rate Swaps.
The Company is exposed to
interest rate risk on its fixed rate and variable rate long-term
debt. The interest rate risk associated with the fair value of
the Company’s fixed rate borrowings is managed using
fixed-to-floating
interest rate swaps to effectively convert a portion of the
underlying cash flows on the debt into variable rate cash flows.
The Company designates these swaps as fair value hedges, with
the objective of hedging against changes in the fair value of
the fixed rate debt that results from market interest rate
changes. The interest rate risk associated with the
Company’s variable rate borrowings is managed using
floating-to-fixed
interest rate swaps. The Company designates these swaps as cash
flow hedges, with the objective of reducing the variability of
cash flows associated with market interest rate changes.
Foreign Currency Risk.
The Company is exposed
to foreign currency exchange rate risk on Australian dollar
expenditures made in its Australian Mining segment. This risk is
managed by entering into forward contracts and options that the
Company designates as cash flow hedges, with the objective of
reducing the variability of cash flows associated with
forecasted Australian dollar expenditures.
Diesel Fuel and Explosives Hedges.
The Company
is exposed to commodity price risk associated with diesel fuel
in the U.S. and Australia and explosives in the
U.S. Explosives costs and a portion of the diesel fuel
costs in Australia are included in the fees paid to the
Company’s contract miners. This risk is managed through the
use of fixed price contracts, cost plus contracts and
derivatives, primarily swaps. The Company has generally
designated the swap contracts as cash flow hedges, with the
objective of reducing the variability of cash flows associated
with the forecasted purchase of diesel fuel and explosives.
F-17
Table of Contents
PEABODY
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
Notional Amounts and Fair Value.
The following summarizes
the Company’s 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
|
Fair
|
||||||||||||||||
|
flow
|
value
|
Economic
|
Fair Value
|
||||||||||||||
| hedge | hedge | hedge | Asset (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 | ) | |||||||||||
Hedge Ineffectiveness.
The Company assesses both at
inception and at least quarterly thereafter, whether the
derivatives used in hedging activities are highly effective at
offsetting the changes in the anticipated cash flows of the
hedged item. The effective portion of the change in the fair
value is recorded as a separate component of stockholders’
equity until the hedged transaction impacts reported earnings,
at which time gains and losses are reclassified to the
consolidated statements of operations at the time of the
recognition of the underlying hedged item. The ineffective
portion of the derivative’s change in fair value is
recorded in the consolidated statements of operations. In
addition, if the hedging relationship ceases to be highly
effective, or it becomes probable that a forecasted transaction
is no longer expected to occur, gains and losses on the
derivative are recorded to the consolidated statements of
operations.
A measure of ineffectiveness is inherent in hedging future
diesel fuel purchases with derivative positions based on crude
oil and refined petroleum products.
The Company’s hedging of future explosives purchases also
has an inherent measure of ineffectiveness as the derivative
positions are primarily based on natural gas, which closely
matches the contractual purchase
F-18
Table of Contents
PEABODY
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
price of explosives since price changes occur in a constant
ratio of MMBtu per ton in the manufacture of explosives and
generally carry a fixed surcharge.
With respect to the interest rate swaps, there was no hedge
ineffectiveness recognized in the consolidated statements of
operations for these instruments during the years ended
December 31, 2009, 2008, or 2007.
The table below shows the classification and amounts of pre-tax
gains and losses related to the Company’s non-trading
hedges during the year ended December 31, 2009:
|
Gain (loss)
|
||||||||||||||||||
|
Gain (loss)
|
Gain (loss)
|
reclassified
|
||||||||||||||||
|
recognized in
|
reclassified
|
from other
|
||||||||||||||||
|
Gain (loss)
|
other
|
from other
|
comprehensive
|
|||||||||||||||
|
recognized in
|
comprehensive
|
comprehensive
|
income into
|
|||||||||||||||
|
Income Statement
|
income on non
|
income on
|
income into
|
income
|
||||||||||||||
|
Classification
|
designated
|
derivative
|
income (effective
|
(ineffective
|
||||||||||||||
|
Financial Instrument
|
Gains (Losses) - Realized | derivatives (1) | (effective portion) | portion) | portion) | |||||||||||||
| (Dollars in millions) | ||||||||||||||||||
|
Interest rate swaps:
|
||||||||||||||||||
|
- Cash flow hedges
|
Interest expense | $ | — | $ | 0.2 | $ | (5.5 | ) | $ | — | ||||||||
|
Diesel fuel hedge contracts:
|
||||||||||||||||||
|
- Cash flow hedges
|
Operating costs and expenses | — | 67.9 | (84.4 | ) | 0.7 | ||||||||||||
|
- Economic hedges
|
Operating costs and expenses | (0.6 | ) | — | — | — | ||||||||||||
|
Explosives cash flow hedge contracts:
|
||||||||||||||||||
|
- Cash flow hedges
|
Operating costs and expenses | — | (2.4 | ) | (13.9 | ) | — | |||||||||||
|
- Economic hedges
|
Operating costs and expenses | (2.1 | ) | — | — | — | ||||||||||||
|
Foreign currency cash flow hedge contracts
|
Operating costs and expenses | — | 458.0 | (30.8 | ) | — | ||||||||||||
|
Total
|
$ | (2.7 | ) | $ | 523.7 | $ | (134.6 | ) | $ | 0.7 | ||||||||
| (1) | Amounts relate to diesel fuel and explosives hedge derivatives that were de-designated in 2009. |
As of December 31, 2009, the classification and amount of
derivatives presented on a gross basis are as follows:
| Fair Value | ||||||||||||||||
|
Other
|
Investments
|
Accounts Payable
|
Other
|
|||||||||||||
|
Current
|
and Other
|
and Accrued
|
Noncurrent
|
|||||||||||||
|
Financial Instrument
|
Assets | Assets | Expenses | Liabilities | ||||||||||||
| (Dollars in millions) | ||||||||||||||||
|
Interest rate swaps:
|
||||||||||||||||
|
- Fair value hedges
|
$ | — | $ | 1.5 | $ | — | $ | — | ||||||||
|
- Cash flow hedges
|
— | — | — | 9.8 | ||||||||||||
|
Diesel fuel cash flow hedge contracts
|
142.9 | 243.8 | 167.5 | 241.4 | ||||||||||||
|
Explosives cash flow hedge contracts
|
15.9 | — | 20.7 | — | ||||||||||||
|
Foreign currency cash flow hedge contracts
|
110.6 | 100.2 | 1.6 | 3.1 | ||||||||||||
|
Total
|
$ | 269.4 | $ | 345.5 | $ | 189.8 | $ | 254.3 | ||||||||
The Company elected the trading exemption under GAAP for its
coal trading transactions which allows for reduced disclosure
since it is the Company’s policy to include these
instruments as a part of its trading book. For further
information, see Risk Management - Coal Trading below.
F-19
Table of Contents
PEABODY
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
Risk
Management — Coal Trading
The Company engages in direct and brokered trading of coal,
ocean freight and fuel-related commodities in
over-the-counter
markets (coal trading), some of which is subsequently
exchange-cleared and some of which is bilaterally-cleared.
Except those for which the Company has elected to apply a normal
purchases and normal sales exception, all derivative coal
trading contracts are accounted for on a fair value basis. For
derivative trading contracts, the Company establishes fair
values using bid/ask price quotations or other market
assessments obtained from multiple, independent third-party
brokers to value its trading positions from the
over-the-counter
market. Prices from these sources are then averaged to obtain
trading position values. While the Company does not anticipate
any decrease in the number of third-party brokers or market
liquidity, such events could erode the quality of market
information and therefore in valuing its market positions should
the number of third-party brokers decrease or if market
liquidity is reduced. For its exchange-cleared positions, the
Company utilizes exchange-published settlement prices. See
Note 5 for information related to the maturity and
valuation of the Company’s trading portfolio.
|
Trading Revenue by Type of Instrument
|
Year Ended December 31, 2009 | |||
| (Dollars in millions) | ||||
|
Commodity swaps and options
|
$ | 176.5 | ||
|
Physical commodity purchase / sale contracts
|
85.0 | |||
|
Total trading revenue
|
$ | 261.5 | ||
Trading revenues are recorded in “Other revenues” in
the consolidated statements of operations and include realized
and unrealized gains and losses on derivative instruments,
including those under the normal purchases and normal sales
exception.
Hedge Ineffectiveness — Coal
Trading.
In some instances, the Company has
designated an existing coal trading derivative as a hedge and,
thus, the derivative has a non-zero fair value at hedge
inception. The “off-market” nature of these
derivatives, which is best described as an embedded financing
element within the derivative, is a source of ineffectiveness.
In other instances, the Company uses a coal trading derivative
that settles at a different time or has a different location
basis than the occurrence of the cash flow being hedged. These
collectively yield ineffectiveness to the extent that the
derivative hedge contract does not exactly offset changes in the
fair value or expected cash flows of the hedged item.
Nonperformance
and Credit Risk
The fair value of the Company’s assets and liabilities
reflect adjustments for nonperformance and credit risk. The
concentration of nonperformance and credit risk is substantially
with electric utilities, steel producers, energy producers and
energy marketers. The Company’s policy is to independently
evaluate each customer’s creditworthiness prior to entering
into transactions and to regularly monitor the credit extended.
If the Company engages in a transaction with a counterparty that
does not meet its credit standards, the Company seeks to protect
its position by requiring the counterparty to provide an
appropriate credit enhancement. Also, when appropriate (as
determined by its credit management function), the Company has
taken steps to reduce its 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 the Company’s
benefit to serve as collateral in the event of a failure to pay
or perform. To reduce its credit exposure related to trading and
brokerage activities, the Company seeks to enter into netting
agreements with counterparties that permit the Company to offset
receivables and payables with such counterparties and, to the
extent required, will post or receive margin amounts associated
with exchange-cleared positions.
F-20
Table of Contents
PEABODY
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
The Company conducts its 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 the Company
continues to closely monitor counterparty creditworthiness.
Certain of the Company’s derivative instruments require the
parties to provide additional performance assurances whenever a
material adverse event jeopardizes one party’s ability to
perform under the instrument. In the event the Company were to
sustain a material adverse event (using commercially reasonable
standards), the counterparties could request collateralization
on derivative instruments in net liability positions, which
based on an aggregate fair value on December 31, 2009,
could require the Company to post up to $83.8 million of
collateral to its counterparties.
Certain of the Company’s other derivative instruments
require the parties to provide additional performance assurances
whenever a credit downgrade occurs below a certain level as
specified in each underlying contract. The terms of such
instruments typically require additional collateralization on an
incremental basis, which is commensurate with the severity of
the credit downgrade. As of December 31, 2009, if a credit
downgrade were to occur below a certain level, the
Company’s additional collateral requirements are estimated
to be approximately $15.9 million (for which the Company
currently has posted approximately $0.8 million) to its
counterparties based on the aggregate fair value of all
derivative instruments with such features that are in a net
liability position.
The Company is required to post collateral on its
exchange-settled positions for its entire net liability
position, which was $18.1 million as of December 31,
2009. In addition, as of December 31, 2009, the Company has
posted $29.7 million of collateral to meet the requirements
of the respective exchanges (reflected in “Other current
assets”).
Fair
Value Measurements
The Company uses a three-level fair value hierarchy that
categorizes assets and liabilities measured at fair value based
on the observability of the inputs utilized in the valuation.
These levels include: Level 1, inputs are quoted prices in
active markets for the identical assets or liabilities;
Level 2, inputs other than quoted prices included in
Level 1 that are directly or indirectly observable through
market-corroborated inputs; and Level 3, inputs are
unobservable, or observable but cannot be market-corroborated,
requiring the Company to make assumptions about pricing by
market participants.
The following tables set forth the hierarchy of the
Company’s net financial asset (liability) positions for
which fair value is measured on a recurring basis:
| December 31, 2009 | ||||||||||||||||
| Level 1 | Level 2 | Level 3 | Total | |||||||||||||
| (Dollars in millions) | ||||||||||||||||
|
Commodity swaps and options — coal trading activities
|
$ | (1.7 | ) | $ | 80.7 | $ | — | $ | 79.0 | |||||||
|
Commodity swaps and options — other than coal
|
— | (27.0 | ) | — | (27.0 | ) | ||||||||||
|
Physical commodity purchase/sale contracts — coal
trading activities
|
— | 70.2 | 17.0 | 87.2 | ||||||||||||
|
Interest rate swaps
|
— | (8.3 | ) | — | (8.3 | ) | ||||||||||
|
Foreign currency hedge contracts
|
— | 206.1 | — | 206.1 | ||||||||||||
|
Total net financial assets (liabilities)
|
$ | (1.7 | ) | $ | 321.7 | $ | 17.0 | $ | 337.0 | |||||||
F-21
Table of Contents
PEABODY
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
| December 31, 2008 | ||||||||||||||||
| Level 1 | Level 2 | Level 3 | Total | |||||||||||||
| (Dollars in millions) | ||||||||||||||||
|
Commodity swaps and options — coal trading activities
|
$ | (17.0 | ) | $ | 233.7 | $ | (1.1 | ) | $ | 215.6 | ||||||
|
Commodity swaps and options — other than coal
|
— | (194.7 | ) | — | (194.7 | ) | ||||||||||
|
Physical commodity purchase/sale contracts — coal
trading activities
|
— | 104.1 | 38.9 | 143.0 | ||||||||||||
|
Interest rate swaps
|
— | (9.3 | ) | — | (9.3 | ) | ||||||||||
|
Foreign currency hedge contracts
|
— | (283.8 | ) | — | (283.8 | ) | ||||||||||
|
Total net financial assets (liabilities)
|
$ | (17.0 | ) | $ | (150.0 | ) | $ | 37.8 | $ | (129.2 | ) | |||||
For Level 1 and 2 financial assets and liabilities, the
Company utilizes both direct and indirect observable price
quotes, including LIBOR yield curves, New York Mercantile
Exchange and Intercontinental Exchange indices (ICE), broker
quotes, published indices, and other market quotes. Below is a
summary of the Company’s valuation techniques for
Level 1 and 2 financial assets and liabilities:
| • | Commodity swaps and options — coal trading activities: generally valued based on unadjusted quoted prices in active markets (Level 1) or a valuation that is corroborated by the use of market-based pricing (Level 2). | |
| • | Commodity swaps and options — other than coal: generally valued based on a valuation that is corroborated by the use of market-based pricing (Level 2). | |
| • | Physical commodity purchase/sale contracts — coal trading activities: purchases and sales at locations with significant market activity corroborated by market-based information (Level 2). | |
| • | Interest rate swaps: valued based on modeling observable market data and corroborated with statements from counterparties (Level 2). | |
| • | Foreign currency hedge contracts: valued utilizing inputs obtained in quoted public markets (Level 2). |
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. These instruments or contracts are
valued based on quoted inputs from brokers or counterparties, or
reflect methodologies that consider historical relationships
among similar commodities to derive the Company’s best
estimate of fair value. The Company has consistently applied
these valuation techniques in all periods presented, and
believes it has obtained the most accurate information available
for the types of derivative contracts held.
The following table summarizes the changes in the Company’s
recurring Level 3 net financial assets:
| Year Ended December 31, | ||||||||
| 2009 | 2008 | |||||||
| (Dollars in millions) | ||||||||
|
Beginning of period
|
$ | 37.8 | $ | 128.7 | ||||
|
Total gains or losses (realized/unrealized):
|
||||||||
|
Included in earnings
|
(2.9 | ) | (9.8 | ) | ||||
|
Included in other comprehensive income
|
(1.6 | ) | 3.4 | |||||
|
Purchases, issuances and settlements
|
(20.5 | ) | (58.8 | ) | ||||
|
Net transfers in (out)
|
4.2 | (25.7 | ) | |||||
|
End of period
|
$ | 17.0 | $ | 37.8 | ||||
F-22
Table of Contents
PEABODY
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
The following table summarizes the changes in unrealized gains
(losses) relating to Level 3 net financial assets held
both as of the beginning and the end of the period:
| Year Ended December 31, | ||||||||
| 2009 | 2008 | |||||||
| (Dollars in millions) | ||||||||
|
Changes in unrealized gains
(losses)
(1)
|
$ | 15.6 | $ | (34.8 | ) | |||
| (1) | Within the consolidated statements of operations for the periods presented, unrealized gains and losses from Level 3 items are combined with unrealized gains and losses on positions classified in Level 1 or 2, as well as other positions that have been realized during the applicable periods. |
Fair
Value — Other Financial Instruments
The following methods and assumptions were used by the Company
in estimating fair values for other financial instruments as of
December 31, 2009 and 2008:
| • | Cash and cash equivalents, accounts receivable and accounts payable and accrued expenses have carrying values which approximate fair value due to the short maturity or the financial nature of these instruments. | |
| • | Long-term debt fair value estimates are based on observed prices for securities with an active trading market when available, and otherwise on estimated borrowing rates to discount the cash flows to their present value. The carrying amounts of the 7.875% Senior Notes due 2026 and the Convertible Junior Subordinated Debentures due 2066 are net of the respective unamortized note discounts. |
The carrying amounts and estimated fair values of the
Company’s debt are summarized as follows:
| December 31, 2009 | December 31, 2008 | |||||||||||||||
|
Carrying
|
Estimated
|
Carrying
|
Estimated
|
|||||||||||||
| Amount | Fair Value | Amount | Fair Value | |||||||||||||
| (Dollars in millions) | ||||||||||||||||
|
Long-term debt
|
$ | 2,752.3 | $ | 2,828.8 | $ | 2,793.6 | $ | 2,472.1 | ||||||||
| (4) | Resource Management and Other Commercial Events |
In 2008, the Company sold approximately 58 million tons of
non-strategic coal reserves and surface lands located in
Kentucky for $21.5 million cash proceeds and a note
receivable of $54.9 million, and recognized a gain of
$54.0 million. The note receivable was paid in two
installments, $30.0 million of which was received in
December 2008 with the balance received in June 2009. The
non-cash portion of this transaction was excluded from the
investing section of the consolidated statement of cash flows
until the cash was received.
In 2007, the Company sold approximately 172 million tons of
coal reserves and surface lands to the Prairie State Energy
Campus (Prairie State) equity partners. The Company recognized a
gain totaling $26.4 million and received
$114.3 million in cash proceeds associated with this
transaction. See Note 19 for additional information
regarding Prairie State.
In 2007, the Company exchanged oil and gas rights and assets in
more than 860,000 acres in the Illinois Basin, West
Virginia, New Mexico and the Powder River Basin for coal
reserves in West Virginia and Kentucky and $15.0 million in
cash proceeds. The Company’s subsidiaries, including one
subsidiary now owned by Patriot, received approximately
40 million tons of coal reserves. Based on the fair value
of the coal reserves received, the Company recognized a
$50.5 million gain on the exchange. The non-cash portion of
this transaction was excluded from the investing section of the
consolidated statement of cash flows.
F-23
Table of Contents
PEABODY
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
| (5) | Assets and Liabilities from Coal Trading Activities |
The fair value of assets and liabilities from coal trading
activities is set forth below:
| December 31, | ||||||||||||||||
| 2009 | 2008 | |||||||||||||||
| Gross Basis | Net Basis | Gross Basis | Net Basis | |||||||||||||
| (Dollars in millions) | ||||||||||||||||
|
Assets from coal trading activities
|
$ | 949.8 | $ | 276.8 | $ | 1,969.7 | $ | 662.8 | ||||||||
|
Liabilities from coal trading activities
|
(779.3 | ) | (110.6 | ) | (1,548.5 | ) | (304.2 | ) | ||||||||
|
Subtotal
|
170.5 | 166.2 | 421.2 | 358.6 | ||||||||||||
|
Net margin held
|
(4.3 | ) | — | (62.6 | ) | — | ||||||||||
|
Net value of coal trading positions
|
$ | 166.2 | $ | 166.2 | $ | 358.6 | $ | 358.6 | ||||||||
As of December 31, 2009, forward contracts made up 53% and
65% of the Company’s trading assets and liabilities,
respectively; financial swaps represent most of the remaining
balances. The net fair value of coal trading positions
designated as cash flow hedges of anticipated future sales was
an asset of $93.0 million as of December 31, 2009 and
an asset of $220.4 million as of December 31, 2008.
The net value of trading positions, including those designated
as hedges of future cash flows, represents the fair value of the
trading portfolio.
As of December 31, 2009, the estimated future realization
of the value of the Company’s trading portfolio was as
follows:
|
Year of
|
Percentage of
|
|||
|
Expiration
|
Portfolio Total | |||
|
2010
|
46 | % | ||
|
2011
|
51 | % | ||
|
2012
|
3 | % | ||
| 100 | % | |||
At December 31, 2009, 73% of the Company’s credit
exposure related to coal trading activities with investment
grade counterparties and 27% with non-investment grade
counterparties.
| (6) | Accounts Receivable Securitization |
The Company has an accounts receivable securitization program
(securitization program) through its wholly-owned,
bankruptcy-remote subsidiary (Seller). Under the program, the
Company contributes a pool of eligible trade receivables to the
Seller, which then sells, without recourse, to a multi-seller,
asset-backed commercial paper conduit (Conduit). Purchases by
the Conduit are financed with the sale of highly rated
commercial paper. The Company utilizes proceeds from the sale of
its accounts receivable as an alternative to other forms of
debt, effectively reducing its overall borrowing costs. The
funding cost of the securitization program was
$4.0 million, $10.8 million and $11.2 million for
the years ended December 31, 2009, 2008 and 2007,
respectively and is included in interest expense in the
consolidated statements of operations. The Company continues to
service the sold trade receivables but does not receive a
servicing fee. The securitization program was renewed in May
2009, and amended in December 2009 and January 2010, 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 those accounts receivable sold to the Conduit removed from
the 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. The $20.4 million decrease in the
securitization program for the year ended December 31, 2009
is reflected in
F-24
Table of Contents
PEABODY
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
cash flows from operating activities in the consolidated
statements of cash flows. There was no change in the facility
usage during the year ended December 31, 2008.
The Seller is a separate legal entity whose assets are available
first and foremost to satisfy the claims of its creditors.
Eligible receivables, as defined in the securitization
agreement, consist of trade receivables from most of the
Company’s U.S. subsidiaries, and are reduced for
certain items such as past due balances and concentration
limits. Of the eligible pool of receivables contributed to the
Seller, only a portion of the pool is sold to the Conduit. The
Company continues to own $9.4 million of receivables as of
December 31, 2009, which represents collateral supporting
the securitization program. The Seller’s interest in these
receivables is subordinate to the Conduit’s interest in the
event of default under the securitization agreement. If the
Company defaulted under the securitization agreement or if its
pool of eligible trade receivables decreased significantly, the
Company could be prohibited from selling any additional
receivables in the future under the securitization agreement.
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.
| (7) | Earnings per Share |
As discussed in Note 1, the Company uses the two-class
method to compute basic and diluted EPS for all periods
presented. The following illustrates the earnings allocation
method utilized in the calculation of basic and diluted EPS.
| Year Ended December 31, 2009 | ||||||||||||
| 2009 | 2008 | 2007 | ||||||||||
| (In millions, except per share amounts) | ||||||||||||
|
Basic earnings per share:
|
||||||||||||
|
Income from continuing operations, net of income taxes
|
$ | 457.9 | $ | 987.9 | $ | 441.6 | ||||||
|
Less: Net income (loss) attributable to noncontrolling interests
|
14.8 | 6.2 | (2.3 | ) | ||||||||
|
Income from continuing operations attributable to common
stockholders before allocation of earnings to participating
securities
|
443.1 | 981.7 | 443.9 | |||||||||
|
Less: Earnings allocated to participating securities
|
(2.9 | ) | (5.5 | ) | (1.2 | ) | ||||||
|
Income from continuing operations attributable to common
stockholders
|
440.2 | 976.2 | 442.7 | |||||||||
|
Income (loss) from discontinued operations, net of income taxes
|
5.1 | (28.8 | ) | (180.1 | ) | |||||||
|
Net income attributable to common stockholders
|
$ | 445.3 | $ | 947.4 | $ | 262.6 | ||||||
|
Diluted earnings per share:
|
||||||||||||
|
Income from continuing operations attributable to common
stockholders before allocation of earnings to participating
securities
|
$ | 443.1 | $ | 981.7 | $ | 443.9 | ||||||
|
Less: Earnings allocated to participating securities
|
(2.9 | ) | (5.5 | ) | (1.2 | ) | ||||||
|
Income from continuing operations attributable to common
stockholders before the reallocation of the earnings of
participating securities
|
440.2 | 976.2 | 442.7 | |||||||||
|
Reallocation of the earnings of participating securities
|
— | — | — | |||||||||
|
Income from continuing operations attributable to common
stockholders
|
440.2 | 976.2 | 442.7 | |||||||||
|
Income (loss) from discontinued operations, net of income taxes
|
5.1 | (28.8 | ) | (180.1 | ) | |||||||
|
Net income attributable to common stockholders
|
$ | 445.3 | $ | 947.4 | $ | 262.6 | ||||||
|
Weighted average shares outstanding — basic
|
265.5 | 268.9 | 264.1 | |||||||||
|
Dilutive impact of share-based
compensation
(1)
|
2.0 | 1.8 | 4.5 | |||||||||
|
Weighted average shares outstanding —
diluted
(2)
|
267.5 | 270.7 | 268.6 | |||||||||
F-25
Table of Contents
PEABODY
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
| Year Ended December 31, 2009 | ||||||||||||
| 2009 | 2008 | 2007 | ||||||||||
| (In millions, except per share amounts) | ||||||||||||
|
Basic earnings per share attributable to common stockholders:
|
||||||||||||
|
Income from continuing operations
|
$ | 1.66 | $ | 3.63 | $ | 1.67 | ||||||
|
Income (loss) from discontinued operations
|
0.02 | (0.11 | ) | (0.68 | ) | |||||||
|
Net income
|
$ | 1.68 | $ | 3.52 | $ | 0.99 | ||||||
|
Diluted earnings per share attributable to common stockholders:
|
||||||||||||
|
Income from continuing operations
|
$ | 1.64 | $ | 3.60 | $ | 1.64 | ||||||
|
Income (loss) from discontinued operations
|
0.02 | (0.10 | ) | (0.67 | ) | |||||||
|
Net income
|
$ | 1.66 | $ | 3.50 | $ | 0.97 | ||||||
| (1) | Includes the dilutive impact of stock options, restricted stock awards, deferred stock units, employee stock purchase plan and performance units. | |
| (2) | Weighted average shares outstanding excludes anti-dilutive shares totaling 0.2 million, 0.1 million and 0.2 million for the years ended December 31, 2009, 2008 and 2007, respectively. |
| (8) | Inventories |
Inventories consisted of the following:
| December 31, | ||||||||
| 2009 | 2008 | |||||||
| (Dollars in millions) | ||||||||
|
Materials and supplies
|
$ | 106.5 | $ | 109.6 | ||||
|
Raw coal
|
80.5 | 22.7 | ||||||
|
Saleable coal
|
138.1 | 143.9 | ||||||
|
Total
|
$ | 325.1 | $ | 276.2 | ||||
| (9) | Leases |
The Company leases equipment and facilities under various
noncancelable lease agreements. Certain lease agreements require
the maintenance of specified ratios and contain restrictive
covenants which limit indebtedness, subsidiary dividends,
investments, asset sales and other Company actions. Rental
expense under operating leases was $127.8 million,
$121.3 million and $104.6 million for the years ended
December 31, 2009, 2008 and 2007, respectively. The gross
value of property, plant, equipment and mine development assets
under capital leases was $98.4 million and
$108.6 million as of December 31, 2009 and 2008,
respectively, related primarily to the leasing of mining
equipment. The accumulated depreciation for these items was
$31.0 million and $27.6 million at December 31,
2009 and 2008, respectively.
The Company also leases coal reserves under agreements that
require royalties to be paid as the coal is mined. Certain
agreements also require minimum annual royalties to be paid
regardless of the amount of coal mined during the year. Total
royalty expense was $439.4 million, $506.4 million and
$338.6 million for the years ended December 31, 2009,
2008 and 2007, respectively.
A substantial amount of the coal mined by the Company is
produced from mineral reserves leased from the owner. One of the
major lessors is the U.S. government, from which the
Company leases substantially all of the coal it mines in Wyoming
and Colorado under terms set by Congress and administered by the
U.S. Bureau of Land Management. These leases are generally
for an initial term of ten years but may be extended by diligent
F-26
Table of Contents
PEABODY
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
development and mining of the reserves until all economically
recoverable reserves are depleted. The Company has met the
diligent development requirements for substantially all of these
federal leases either directly through production or by
including the lease as a part of a logical mining unit with
other leases upon which development has occurred. Annual
production on these federal leases must total at least 1.0% of
the original amount of coal in the entire logical mining unit.
In addition, royalties are payable monthly at a rate of 12.5% of
the gross realization from the sale of the coal mined using
surface mining methods and at a rate of 8.0% of the gross
realization for coal produced using underground mining methods.
The Company also leases coal reserves in Arizona from The Navajo
Nation and the Hopi Tribe under leases that are administered by
the U.S. Department of the Interior. These leases expire
upon exhaustion of the leased reserves or upon the permanent
ceasing of all mining activities on the related reserves as a
whole. The royalty rates are also generally based upon a
percentage of the gross realization from the sale of coal. These
rates are subject to redetermination every ten years under the
terms of the leases. The remainder of the leased coal is
generally leased from state governments, land holding companies
and various individuals. The duration of these leases varies
greatly. Typically, the lease terms are automatically extended
as long as active mining continues. Royalty payments are
generally based upon a specified rate per ton or a percentage of
the gross realization from the sale of the coal.
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.
Future minimum lease and royalty payments as of
December 31, 2009 are as follows:
|
Coal Lease
|
||||||||||||
|
and
|
||||||||||||
|
Capital
|
Operating
|
Royalty
|
||||||||||
|
Year Ended December 31,
|
Leases | Leases | Obligations | |||||||||
| (Dollars in millions) | ||||||||||||
|
2010
|
$ | 15.1 | $ | 96.4 | $ | 11.3 | ||||||
|
2011
|
15.1 | 87.4 | 9.0 | |||||||||
|
2012
|
15.1 | 66.2 | 7.8 | |||||||||
|
2013
|
23.0 | 56.6 | 8.3 | |||||||||
|
2014
|
12.0 | 43.7 | 6.7 | |||||||||
|
2015 and thereafter
|
— | 117.8 | 36.8 | |||||||||
|
Total minimum lease payments
|
$ | 80.3 | $ | 468.1 | $ | 79.9 | ||||||
|
Less interest
|
12.8 | |||||||||||
|
Present value of minimum capital lease payments
|
$ | 67.5 | ||||||||||
As of December 31, 2009, certain of the Company’s
lease obligations were secured by outstanding surety bonds
totaling $116.3 million.
F-27
Table of Contents
PEABODY
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
| (10) | Accounts Payable and Accrued Expenses |
Accounts payable and accrued expenses consisted of the following:
| December 31, | ||||||||
| 2009 | 2008 | |||||||
| (Dollars in millions) | ||||||||
|
Trade accounts payable
|
$ | 387.6 | $ | 427.2 | ||||
|
Accrued taxes other than income
|
172.3 | 170.7 | ||||||
|
Other accrued expenses
|
160.0 | 127.0 | ||||||
|
Accrued payroll and related benefits
|
135.0 | 120.1 | ||||||
|
Income taxes payable
|
80.7 | 142.7 | ||||||
|
Accrued health care
|
78.7 | 82.5 | ||||||
|
Accrued royalties
|
51.1 | 77.7 | ||||||
|
Accrued interest
|
31.7 | 31.1 | ||||||
|
Commodity and foreign currency hedge contracts
|
29.4 | 261.1 | ||||||
|
Workers’ compensation obligations
|
8.7 | 8.7 | ||||||
|
Accrued environmental
|
7.9 | 7.6 | ||||||
|
Other accrued benefits
|
4.0 | 4.1 | ||||||
|
Liabilities associated with discontinued operations
|
40.6 | 69.1 | ||||||
|
Current liabilities associated with assets held for sale
|
— | 5.4 | ||||||
|
Total accounts payable and accrued expenses
|
$ | 1,187.7 | $ | 1,535.0 | ||||
| (11) | Income Taxes |
Income from continuing operations before income taxes consisted
of the following:
| Year Ended December 31, | ||||||||||||
| 2009 | 2008 | 2007 | ||||||||||
| (Dollars in millions) | ||||||||||||
|
U.S.
|
$ | 281.4 | $ | 185.2 | $ | 296.1 | ||||||
|
Non U.S.
|
370.3 | 994.1 | 74.8 | |||||||||
|
Total
|
$ | 651.7 | $ | 1,179.3 | $ | 370.9 | ||||||
F-28
Table of Contents
PEABODY
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
Total income tax provision (benefit) consisted of the following:
| Year Ended December 31, | ||||||||||||
| 2009 | 2008 | 2007 | ||||||||||
| (Dollars in millions) | ||||||||||||
|
Current:
|
||||||||||||
|
U.S. federal
|
$ | (0.7 | ) | $ | — | $ | — | |||||
|
Non U.S.
|
61.7 | 224.7 | 28.9 | |||||||||
|
State
|
1.7 | — | 0.2 | |||||||||
|
Total current
|
62.7 | 224.7 | 29.1 | |||||||||
|
Deferred:
|
||||||||||||
|
U.S. federal
|
56.0 | 47.1 | (139.3 | ) | ||||||||
|
Non U.S.
|
74.4 | (81.7 | ) | 46.7 | ||||||||
|
State
|
0.7 | 1.3 | (7.2 | ) | ||||||||
|
Total deferred
|
131.1 | (33.3 | ) | (99.8 | ) | |||||||
|
Total provision (benefit)
|
$ | 193.8 | $ | 191.4 | $ | (70.7 | ) | |||||
The income tax rate differed from the U.S. federal
statutory rate as follows:
| Year Ended December 31, | ||||||||||||
| 2009 | 2008 | 2007 | ||||||||||
| (Dollars in millions) | ||||||||||||
|
Federal statutory rate
|
$ | 228.1 | $ | 412.7 | $ | 129.8 | ||||||
|
Excess depletion
|
(44.0 | ) | (40.1 | ) | (55.3 | ) | ||||||
|
Foreign earnings rate differential
|
(83.6 | ) | (119.7 | ) | (13.5 | ) | ||||||
|
Remeasurement of foreign deferred taxes
|
74.4 | (65.2 | ) | 56.0 | ||||||||
|
State income taxes, net of U.S. federal tax benefit
|
3.4 | (1.6 | ) | 0.3 | ||||||||
|
Tax credits
|
(12.2 | ) | (12.6 | ) | (24.3 | ) | ||||||
|
Changes in valuation allowance
|
17.3 | (44.2 | ) | (175.7 | ) | |||||||
|
Changes in tax reserves
|
5.9 | 34.4 | 4.1 | |||||||||
|
Other, net
|
4.5 | 27.7 | 7.9 | |||||||||
|
Total provision (benefit)
|
$ | 193.8 | $ | 191.4 | $ | (70.7 | ) | |||||
F-29
Table of Contents
PEABODY
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
The tax effects of temporary differences that give rise to
significant portions of the deferred tax assets and liabilities
consisted of the following:
| December 31, | ||||||||
| 2009 | 2008 | |||||||
| (Dollars in millions) | ||||||||
|
Deferred tax assets:
|
||||||||
|
Tax credits and loss carryforwards
|
$ | 557.1 | $ | 785.9 | ||||
|
Postretirement benefit obligations
|
474.7 | 403.9 | ||||||
|
Intangible tax asset and purchased contract rights
|
30.9 | 58.1 | ||||||
|
Accrued reclamation and mine closing liabilities
|
57.0 | 46.1 | ||||||
|
Accrued long-term workers’ compensation liabilities
|
23.1 | 12.6 | ||||||
|
Employee benefits
|
80.3 | 56.2 | ||||||
|
Financial guarantee
|
20.1 | 23.9 | ||||||
|
Others
|
39.5 | 56.5 | ||||||
|
Total gross deferred tax assets
|
1,282.7 | 1,443.2 | ||||||
|
Deferred tax liabilities:
|
||||||||
|
Property, plant, equipment and mine development, leased coal
interests and advance royalties, principally due to differences
in depreciation, depletion and asset writedowns
|
1,221.0 | 1,154.2 | ||||||
|
Unamortized discount on Convertible Junior Subordinated
Debentures
|
139.6 | 139.9 | ||||||
|
Hedge activities
|
29.2 | 35.3 | ||||||
|
Investments and other assets
|
64.8 | 75.9 | ||||||
|
Total gross deferred tax liabilities
|
1,454.6 | 1,405.3 | ||||||
|
Valuation allowance
|
(87.2 | ) | (57.0 | ) | ||||
|
Net deferred tax liability
|
$ | (259.1 | ) | $ | (19.1 | ) | ||
|
Deferred taxes are classified as follows:
|
||||||||
|
Current deferred income taxes
|
$ | 40.0 | $ | 1.7 | ||||
|
Noncurrent deferred income taxes
|
(299.1 | ) | (20.8 | ) | ||||
|
Net deferred tax liability
|
$ | (259.1 | ) | $ | (19.1 | ) | ||
The Company’s tax credits and loss carryforwards included
alternative minimum tax (AMT) and general business credits of
$73.3 million and $62.4 million, U.S. net
operating loss (NOL) carryforwards of $392.1 million and
$653.5 million and foreign loss carryforwards of
$91.7 million and $70.0 million as of
December 31, 2009 and 2008, respectively. The AMT credits
and foreign NOL and capital loss carryforwards have no
expiration date and the U.S. NOL carryforwards begin to
expire in the year 2025. The Company evaluated and assessed the
expected near-term utilization of NOLs, future book and taxable
income, available tax strategies and the overall deferred tax
position to determine the appropriate amount and timing of
valuation allowance adjustments. Of the $17.3 million
change in the valuation allowance, the largest component of the
2009 assessment was a $15.7 million increase of a valuation
allowance on AMT credits. Significant reductions of valuation
allowance were made to foreign NOLs during the 2008 assessment
and on U.S. NOL carryforwards during the 2007 assessments.
The remaining valuation allowance at December 31, 2009 of
$87.2 million represents a reserve for AMT credits and
certain foreign deferred tax assets.
F-30
Table of Contents
PEABODY
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
The total amount of the net unrecognized tax benefits was
$109.2 million ($113.2 million gross) at
December 31, 2009 and was $176.9 million
($186.3 million gross) at December 31, 2008. The
amount of the Company’s gross unrecognized tax benefits has
decreased by $73.1 million since January 1, 2009
primarily as a result of the Company’s IRS audit for the
2005 and 2006 tax years. The corresponding adjustment was a
reduction of the deferred tax asset associated with net
operating losses. A reconciliation of the beginning and ending
amount of gross unrecognized tax benefits is as follows (dollars
in millions):
| Year Ended December 31, | ||||||||||||
| 2009 | 2008 | 2007 | ||||||||||
|
Balance at beginning of period
|
$ | 186.3 | $ | 152.6 | $ | 144.0 | ||||||
|
Additions for current year tax positions
|
2.7 | 30.3 | 4.0 | |||||||||
|
Additions for prior year positions
|
15.7 | 3.4 | 4.6 | |||||||||
|
Reductions for settlements with tax authorities
|
(88.5 | ) | — | — | ||||||||
|
Reductions for expirations of statute of limitations
|
(3.0 | ) | — | — | ||||||||
|
Balance at end of period
|
$ | 113.2 | $ | 186.3 | $ | 152.6 | ||||||
The amount of the net unrecognized tax benefits that, if
recognized, would directly affect the effective tax rate is
$109.2 million. However, $10.4 million would generate
a deferred tax asset for state NOL carryforwards that would more
likely than not be offset by a valuation allowance. The Company
does not expect any significant changes to its net unrecognized
tax benefits within 12 months of this reporting date.
The Company’s federal income tax returns are under
examination by the IRS for the 2005 and 2006 income tax years.
The IRS has issued the Company notices of proposed adjustments
to decrease the Company’s net operating losses associated
with the liquidation of an insolvent subsidiary and interest
income accrued by a foreign subsidiary. The Company believes its
position regarding these matters is supported by applicable
valuation methodology, tax laws and existing Treasury
regulations. The Company and the IRS have agreed to proceed to
an alternative dispute resolution program (Fast Track
Settlement) which could facilitate a settlement within
120 days (expected to be May 2010); and, provided a
settlement is reached in this process, additional changes could
occur to the amount of unrecognized tax benefits. However, the
Company does not expect any changes to have a material impact on
its financial position or results of operations.
If a settlement is not reached under the Fast Track Settlement
process, the Company will begin the formal IRS appeals process
to resolve any outstanding issues which could take two or more
years to complete. Should the IRS positions ultimately be
sustained at the conclusion of the appeals process, additional
income tax charges would be required to the extent the
Company’s net operating loss carryforwards are reduced.
The Company recognizes interest and penalties accrued related to
unrecognized tax benefits in its income tax provision. The
Company has recognized $2.8 million of interest for the
year ended December 31, 2009. The Company had
$6.4 million and $3.6 million of accrued interest
related to uncertain tax positions at December 31, 2009 and
2008, respectively. The Company has considered the application
of penalties on its unrecognized tax benefits and determined,
based upon several factors, including the existence of NOL
carryforwards, that no accrual of penalties is required.
The Company’s federal income tax returns for 1999 through
2001, 2003 through 2004 and 2007 through 2008 remain subject to
examination by the IRS. The Company’s state income tax
returns for the tax years 1991 and beyond remain subject to
examination by various state taxing authorities. The
Company’s foreign income tax returns for the tax years 2003
and beyond remain subject to examination by various foreign
taxing authorities.
The total amount of undistributed earnings of foreign
subsidiaries for income tax purposes was approximately
$1.4 billion at December 31, 2009 and
$1.2 billion at December 31, 2008. The Company has
F-31
Table of Contents
PEABODY
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
not provided deferred taxes on foreign earnings of
$1.3 billion for 2009 and $1.1 billion for 2008
because such earnings were intended to be indefinitely
reinvested outside the U.S. Should the Company repatriate
all of these earnings, a one-time income tax charge to the
Company’s consolidated results of operations of up to
$466.0 million could occur.
The following table summarizes the Company’s tax payments:
| Year Ended December 31, | ||||||||||||
| 2009 | 2008 | 2007 | ||||||||||
| (Dollars in millions) | ||||||||||||
|
U.S. — federal
|
$ | — | $ | — | $ | 3.0 | ||||||
|
U.S. — state and local
|
0.9 | — | 1.2 | |||||||||
|
Non U.S.
|
169.7 | 65.8 | 80.0 | |||||||||
|
Total tax payments
|
$ | 170.6 | $ | 65.8 | $ | 84.2 | ||||||
| (12) |
|
The Company’s 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 | ||||
Senior
Unsecured Credit Facility
The Senior Unsecured Credit Facility provides a
$1.8 billion Revolving Credit Facility (the Revolver) and a
$950.0 million Term Loan Facility (the Term Loan) and
matures on September 15, 2011. The Revolver is intended to
accommodate working capital needs, letters of credit, and other
general corporate purposes, and includes a $50.0 million
sub-facility
available for
same-day
swingline loan borrowings. As of December 31, 2009, the
Company had $315.7 million of letters of credit outstanding
under the Revolver, with a remaining available borrowing
capacity of approximately $1.5 billion.
Loans under the facility are available to the Company in
U.S. dollars, with a
sub-facility
under the Revolver available in Australian dollars, pounds
sterling and euros. Letters of credit under the Revolver are
available to the Company in U.S. dollars with a
sub-facility
available in Australian dollars, pounds sterling
F-32
Table of Contents
PEABODY
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
and euros. The interest rate payable on the Revolver and the
Term Loan is based on a pricing grid tied to the Company’s
leverage ratio, as defined in the Third Amended and Restated
Credit Agreement. The interest rate payable on the Revolver and
the Term Loan is currently LIBOR plus 0.75%, which was 1.0% at
December 31, 2009.
Under the Senior Unsecured Credit Facility, the Company must
comply with certain financial covenants on a quarterly basis
including a minimum interest coverage ratio and a maximum
leverage ratio. The financial covenants also place limitations
on the Company’s investments in joint ventures,
unrestricted subsidiaries, indebtedness of non-loan parties and
the imposition of liens on Company assets.
Convertible
Junior Subordinated Debentures
As of December 31, 2009, the Company had
$732.5 million aggregate principal outstanding of
Convertible Junior Subordinated Debentures (the Debentures) that
generally require interest to be paid semiannually at a rate of
4.75% per year. The Company may elect to, and to the extent that
a mandatory trigger event (as defined in the indenture governing
the Debentures) has occurred and is continuing will be required
to, defer interest payments on the Debentures. After five years
of deferral at the Company’s option, or upon the occurrence
of a mandatory trigger event, the Company generally must sell
warrants or preferred stock with specified characteristics and
use the funds from that sale to pay deferred interest, subject
to certain limitations. In no event may the Company defer
payments of interest on the Debentures for more than
10 years.
The Debentures are convertible at any time on or prior to
December 15, 2036 if any of the following conditions occur:
(i) the Company’s closing common stock price exceeds
140% of the then applicable conversion price for the Debentures
(currently $81.75 per share) for at least 20 of the final 30
trading days in any quarter; (ii) a notice of redemption is
issued with respect to the Debentures; (iii) a change of
control, as defined in the indenture governing the Debentures;
(iv) satisfaction of certain trading price conditions; and
(v) other specified corporate transactions described in the
indenture governing the Debentures. In addition, the Debentures
are convertible at any time after December 15, 2036 to
December 15, 2041, the scheduled maturity date. In the case
of conversion following a notice of redemption or upon a
non-stock change of control, as defined in the indenture
governing the Debentures, holders may convert their Debentures
into cash in the amount of the principal amount of their
Debentures and shares of the Company’s common stock for any
conversion value in excess of the principal amount. In all other
conversion circumstances, holders will receive perpetual
preferred stock (see Note 16) with a liquidation
preference equal to the principal amount of their Debentures,
and any conversion value in excess of the principal amount will
be settled with the Company’s common stock. As a result of
the Patriot spin-off and a change in the Company’s dividend
distribution rate, the conversion rate was adjusted. The current
conversion rate is 17.1244 shares of common stock per
$1,000 principal amount of Debentures effective February 8,
2010. This adjusted conversion rate represents a conversion
price of approximately $58.40.
The Debentures are not subject to redemption prior to
December 20, 2011. Between December 20, 2011 and
December 19, 2036 the Company may redeem the Debentures, in
whole or in part, if for at least 20 out of the 30 consecutive
trading days immediately prior to the date on which notice of
redemption is given, the Company’s closing common stock
price has exceeded 130% of the then applicable conversion price
for the Debentures. On or after December 20, 2036, whether
or not the redemption condition is satisfied, the Company may
redeem the Debentures, in whole or in part. The Company may not
redeem any Debentures unless (i) all accrued and unpaid
interest on the Debentures has been paid in full on or prior to
the redemption date and (ii) if any perpetual preferred
stock is outstanding, the Company has first given notice to
redeem the perpetual preferred stock in the same proportion as
the redemption of the Debentures. Any redemption of the
Debentures will be at a cash redemption price of 100% of the
principal amount of the Debentures to be redeemed, plus accrued
and unpaid interest to the date of redemption.
F-33
Table of Contents
PEABODY
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
On December 15, 2041, the scheduled maturity date, the
Company will use commercially reasonable efforts, subject to the
occurrence of a market disruption event, as defined in the
indenture governing the Debentures, to issue securities of
equivalent equity content in an amount sufficient to pay the
principal amount of the Debentures, together with accrued and
unpaid interest. At the final maturity date of the Debentures on
December 15, 2066, the entire principal amount will become
due and payable, together with accrued and unpaid interest.
In connection with the issuance of the Debentures, the Company
entered into a Capital Replacement Covenant (the CRC). Pursuant
to the CRC, the Company covenanted for the benefit of holders of
covered debt, as defined in the CRC (currently the
Company’s 7.875% Senior Notes, issued in the aggregate
principal amount of $250.0 million), that neither the
Company nor any of its subsidiaries shall repay, redeem or
repurchase all or any part of the Debentures on or after
December 15, 2041 and prior to December 15, 2046,
except to the extent that the total repayment, redemption or
repurchase price does not exceed the sum of: (i) 400% of
the Company’s net cash proceeds from the sale of its common
stock and rights to acquire its common stock (including common
stock issued pursuant to the Company’s dividend
reinvestment plan or employee benefit plans); (ii) the
Company’s net cash proceeds from the sale of its
mandatorily convertible preferred stock, as defined in the CRC,
or debt exchangeable for equity, as defined in the CRC; and
(iii) the Company’s net cash proceeds from the sale of
other replacement capital securities, as defined in the CRC, in
each case, during the six months prior to the notice date for
the relevant payment, redemption or repurchase.
The Debentures are unsecured obligations of the Company, ranking
junior to all existing and future senior and subordinated debt
(excluding trade accounts payable or accrued liabilities arising
in the ordinary course of business) except for any future debt
that ranks equal to or junior to the Debentures. The Debentures
will rank equal in right of payment with the Company’s
obligations to trade creditors. Substantially all of the
Company’s existing indebtedness is senior to the
Debentures. In addition, the Debentures will be effectively
subordinated to all indebtedness of the Company’s
subsidiaries. The indenture governing the Debentures places no
limitation on the amount of additional indebtedness that the
Company or any of the Company’s subsidiaries may incur.
As discussed in Note 1, the Company adopted an accounting
standard such that the Company separately accounts for the
liability and equity components of the Debentures in a manner
that reflects the nonconvertible debt borrowing rate when
recognizing interest cost in subsequent periods. The following
table illustrates the carrying amount of the equity and debt
components of the Debentures:
| December 31, | ||||||||
| 2009 | 2008 | |||||||
| (Dollars in millions) | ||||||||
|
Carrying amount of the equity component
|
$ | 215.4 | $ | 215.4 | ||||
|
Principal amount of the liability component
|
732.5 | 732.5 | ||||||
|
Unamortized discount
|
(361.0 | ) | (362.6 | ) | ||||
|
Net carrying amount
|
$ | 371.5 | $ | 369.9 | ||||
The following table illustrates the effective interest rate and
the interest expense related to the Debentures:
| Year Ended December 31, | ||||||||||||
| 2009 | 2008 | 2007 | ||||||||||
| (Dollars in millions) | ||||||||||||
|
Effective interest rate
|
4.9 | % | 4.9 | % | 4.9 | % | ||||||
|
Interest expense — contractual interest coupon
|
$ | 34.8 | $ | 34.5 | $ | 34.9 | ||||||
|
Interest expense — amortization of debt discount
|
1.6 | 1.5 | 1.3 | |||||||||
F-34
Table of Contents
PEABODY
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
The remaining period over which the discount will be amortized
is 32 years as of December 31, 2009.
7.375% Senior
Notes and 7.875% Senior Notes
The notes are general unsecured obligations of the Company and
rank senior in right of payment to any subordinated indebtedness
of the Company; equally in right of payment with any senior
indebtedness of the Company; effectively junior in right of
payment to the Company’s existing and future secured
indebtedness, to the extent of the value of the collateral
securing that indebtedness; and effectively junior to all the
indebtedness and other liabilities of the Company’s
subsidiaries that do not guarantee the notes. Interest payments
are scheduled to occur on May 1 and November 1 of each year.
The notes are guaranteed by the Company’s Subsidiary
Guarantors, as defined in the note indenture. The note indenture
contains covenants that, among other things, limit the
Company’s ability to create liens and enter into sale and
lease-back transactions. The notes are redeemable at a
redemption price equal to 100% of the principal amount of the
notes being redeemed plus a make-whole premium, if applicable,
and any accrued unpaid interest to the redemption date.
6.875% Senior
Notes
The notes are senior unsecured obligations of the Company and
rank equally with all of the Company’s other senior
unsecured indebtedness. Interest payments are scheduled to occur
on March 15 and September 15 of each year. The notes are
guaranteed by the Company’s Subsidiary Guarantors as
defined in the note indenture. The note indenture contains
covenants which, among other things, limit the Company’s
ability to incur additional indebtedness and issue preferred
stock, pay dividends or make other distributions, make other
restricted payments and investments, create liens, sell assets
and merge or consolidate with other entities. The notes are
redeemable at fixed redemption prices as set forth in the
indenture.
5.875% Senior
Notes
The notes are senior unsecured obligations of the Company and
rank equally with all of the Company’s other senior
unsecured indebtedness. Interest payments are scheduled to occur
on April 15 and October 15 of each year. The notes are
guaranteed by the Company’s Subsidiary Guarantors as
defined in the note indenture. The note indenture contains
covenants which, among other things, limit the Company’s
ability to incur additional indebtedness and issue preferred
stock, pay dividends or make other distributions, make other
restricted payments and investments, create liens, sell assets
and merge or consolidate with other entities. The notes are
redeemable at fixed redemption prices as set forth in the
indenture.
Series Bonds
The Series Bonds were assumed as part of the Excel
acquisition. In December 2009, the Company purchased
$20.0 million of the bonds in an open market transaction
for $19.0 million resulting in a $1.0 million gain
that was recorded as a component of interest expense. The
purchase included $10.0 million of the 6.84% Series A
Bonds and $10.0 million of the 6.84% Series C Bonds.
Based on this purchase, the 6.84% Series A Bonds were paid
in full. The 6.34% Series B Bonds are payable in
installments. The first scheduled payment occurred in December
2008. The 6.84% Series C Bonds are payable in installments
beginning December 2012. Interest payments are scheduled to
occur in June and December of each year. The notes are
redeemable at a redemption price equal to 100% of the principal
amount of the notes being redeemed plus a make-whole premium, if
applicable, and any accrued unpaid interest to the redemption
date.
F-35
Table of Contents
PEABODY
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
Interest
Rate Swaps
As of December 31, 2009, the Company had the following
fixed-to-floating
and
floating-to-fixed
interest rate swaps:
|
Notional
|
Benefit
|
Amount
|
Termination
|
Fair
|
||||||||||
| Amount | Received | Paid | Date | Value | ||||||||||
| (Dollars in millions) | ||||||||||||||
|
Fixed to Floating
|
||||||||||||||
|
6
7
/
8
$650 Senior Notes
|
$ | 25.0 | 6.875% semi-annually | 6-M LIBOR + 299.75 bps semi-annually | 3/15/2013 | $ | 0.8 | |||||||
|
6
7
/
8
$650 Senior Notes
|
$ | 25.0 | 6.875% semi-annually | 6-M LIBOR + 307 bps semi-annually | 3/15/2013 | $ | 0.7 | |||||||
|
Floating to Fixed
|
||||||||||||||
|
Senior Unsecured Term Loan
|
$ | 120.0 | 3-M LIBOR + 100 bps quarterly | 6.25% semi-annually | 9/15/2011 | $ | (9.8 | ) | ||||||
Legend: M = month; bps = basis points
Because the critical terms of the swaps and the respective debt
instruments they hedge coincide, there was no hedge
ineffectiveness recognized in the consolidated statements of
operations during the years ended December 31, 2009, 2008,
or 2007. At December 31, 2009 and 2008, there was an
unrealized loss related to the cash flow hedge of
$9.8 million and $21.8 million, respectively. At
December 31, 2009 and 2008, there was a net unrealized gain
on the fair value hedges of $8.4 million and
$15.1 million, respectively. The fair value hedge
adjustment, which includes the unamortized portion of terminated
fair value hedges ($6.9 million and $2.6 million at
December 31, 2009 and 2008, respectively), is reflected as
an adjustment to the carrying value of the 6.875% Senior
Notes.
Capital
Lease Obligations
Capital lease obligations are primarily for mining equipment
(see Note 9 for additional information on the
Company’s capital lease obligations).
Debt
Maturities, Interest Paid, and Financing Costs
The aggregate amounts of long-term debt maturities (excluding
unamortized debt discounts) subsequent to December 31,
2009, including capital lease obligations, were as follows
(Dollars in millions):
|
Year of Maturity
|
||||
|
2010
|
$ | 14.1 | ||
|
2011
|
505.2 | |||
|
2012
|
22.1 | |||
|
2013
|
689.5 | |||
|
2014
|
21.5 | |||
|
2015 and thereafter
|
1,863.8 | |||
|
Total
|
$ | 3,116.2 | ||
Interest paid on long-term debt was $201.6 million,
$226.0 million and $191.9 million for the years ended
December 31, 2009, 2008 and 2007, respectively.
Financing costs incurred with the issuance of the Company’s
debt are being amortized to interest expense over the remaining
term of the associated debt. The remaining balance at
December 31, 2009 was $30.6 million, of which
$17.9 million will be amortized to interest expense over
the next five years.
F-36
Table of Contents
PEABODY
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
| (13) | Asset Retirement Obligations |
Reconciliations of the Company’s ARO liability are as
follows:
| December 31, | ||||||||
| 2009 | 2008 | |||||||
| (Dollars in millions) | ||||||||
|
Balance at beginning of year
|
$ | 418.7 | $ | 360.7 | ||||
|
Liabilities incurred or acquired
|
0.4 | — | ||||||
|
Liabilities settled or disposed
|
(8.1 | ) | (6.1 | ) | ||||
|
Accretion expense
|
24.0 | 20.5 | ||||||
|
Revisions to estimates
|
17.1 | 43.6 | ||||||
|
Balance at end of year
|
$ | 452.1 | $ | 418.7 | ||||
|
Balance at end of year — active locations
|
$ | 422.0 | $ | 383.3 | ||||
|
Balance at end of year — closed or inactive locations
|
$ | 30.1 | $ | 35.4 | ||||
The credit-adjusted, risk-free interest rates were 7.92% at
December 31, 2009 and 7.91% at December 31, 2008 and
7.85% at January 1, 2008.
As of December 31, 2009 and 2008, the Company had
$772.3 million and $740.6 million, respectively, in
surety bonds outstanding to secure reclamation obligations or
activities. The amount of reclamation self-bonding in certain
states in which the Company qualifies was $821.9 million
and $773.4 million as of December 31, 2009 and 2008,
respectively. Additionally, the Company had $34.9 million
and $0.1 million of letters of credit in support of
reclamation obligations or activities as of December 31,
2009 and 2008, respectively.
| (14) | Pension and Savings Plans |
One of the Company’s subsidiaries, Peabody Investments
Corp. (PIC), sponsors a defined benefit pension plan covering
certain U.S. salaried employees and eligible hourly
employees at certain PIC subsidiaries (the Peabody Plan). A PIC
subsidiary also has a defined benefit pension plan covering
eligible employees who are represented by the UMWA under the
Western Surface Agreement (the Western Plan). PIC also sponsors
an unfunded supplemental retirement plan to provide senior
management with benefits in excess of limits under the federal
tax law. These plans are collectively referred to as The Plans.
Effective June 1, 2008 the Peabody Plan was frozen in its
entirety for both participation and benefit accrual purposes.
The Company adopted an enhanced savings plan contribution
structure in lieu of benefits formerly accrued under the Peabody
Plan.
F-37
Table of Contents
PEABODY
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
Net periodic pension cost included the following components:
| Year Ended December 31, | ||||||||||||
| 2009 | 2008 | 2007 | ||||||||||
| (Dollars in millions) | ||||||||||||
|
Service cost for benefits earned
|
$ | 1.4 | $ | 2.0 | $ | 12.7 | ||||||
|
Interest cost on projected benefit obligation
|
51.3 | 51.0 | 49.0 | |||||||||
|
Expected return on plan assets
|
(60.9 | ) | (60.6 | ) | (57.4 | ) | ||||||
|
Amortization of prior service cost
|
1.4 | 1.3 | 0.4 | |||||||||
|
Amortization of actuarial (gains) losses
|
1.9 | (0.5 | ) | 15.3 | ||||||||
|
Net periodic pension cost
|
(4.9 | ) | (6.8 | ) | 20.0 | |||||||
|
Curtailment gain
|
— | (0.6 | ) | (0.4 | ) | |||||||
|
Total net periodic pension (benefit) cost
|
$ | (4.9 | ) | $ | (7.4 | ) | $ | 19.6 | ||||
The following includes amounts recognized in accumulated other
comprehensive loss:
| Year Ended December 31, | ||||||||||||
| 2009 | 2008 | 2007 | ||||||||||
| (Dollars in millions) | ||||||||||||
|
Net actuarial (gain) loss arising during year
|
$ | 46.1 | $ | 199.2 | $ | (89.6 | ) | |||||
|
Prior service cost arising during year
|
— | — | 7.9 | |||||||||
|
Amortizations:
|
||||||||||||
|
Actuarial gain (loss)
|
(1.9 | ) | 0.5 | (15.3 | ) | |||||||
|
Prior service cost
|
(1.4 | ) | (0.7 | ) | — | |||||||
|
Total recognized in other comprehensive loss
|
42.8 | 199.0 | (97.0 | ) | ||||||||
|
Net periodic pension (benefit) costs
|
(4.9 | ) | (6.8 | ) | 20.0 | |||||||
|
Total recognized in net periodic pension cost and other
comprehensive loss
|
$ | 37.9 | $ | 192.2 | $ | (77.0 | ) | |||||
The Company amortizes actuarial gains and losses using a 5%
corridor with a five-year amortization period. The estimated net
actuarial loss and prior service cost that will be amortized
from accumulated other comprehensive loss into net periodic
pension costs during the year ended December 31, 2010 are
$21.9 million and $1.4 million, respectively.
F-38
Table of Contents
PEABODY
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
The following summarizes the change in benefit obligation,
change in plan assets and funded status of the Company’s
plans:
| December 31, | ||||||||
| 2009 | 2008 | |||||||
| (Dollars in millions) | ||||||||
|
Change in benefit obligation:
|
||||||||
|
Projected benefit obligation at beginning of period
|
$ | 768.6 | $ | 778.2 | ||||
|
Service cost
|
1.4 | 2.0 | ||||||
|
Interest cost
|
51.3 | 51.0 | ||||||
|
Benefits paid
|
(48.3 | ) | (46.7 | ) | ||||
|
Actuarial (gain) loss
|
71.9 | (15.9 | ) | |||||
|
Projected benefit obligation at end of period
|
844.9 | 768.6 | ||||||
|
Change in plan assets:
|
||||||||
|
Fair value of plan assets at beginning of period
|
552.6 | 732.4 | ||||||
|
Actual return on plan assets
|
86.6 | (154.4 | ) | |||||
|
Employer contributions
|
38.7 | 21.3 | ||||||
|
Benefits paid
|
(48.3 | ) | (46.7 | ) | ||||
|
Fair value of plan assets at end of period
|
629.6 | 552.6 | ||||||
|
Funded status at end of year
|
$ | (215.3 | ) | $ | (216.0 | ) | ||
|
Amounts recognized in the consolidated balance sheets:
|
||||||||
|
Current obligation (included in Accounts payable and accrued
expenses)
|
$ | (1.8 | ) | $ | (1.6 | ) | ||
|
Noncurrent obligation (included in Other noncurrent liabilities)
|
(213.5 | ) | (214.4 | ) | ||||
|
Net amount recognized
|
$ | (215.3 | ) | $ | (216.0 | ) | ||
The weighted-average assumptions used to determine the benefit
obligations as of the end of each year were as follows:
| Year Ended December 31, | ||||||||
| 2009 | 2008 | |||||||
|
Discount rate
|
6.19 | % | 6.90 | % | ||||
|
Rate of compensation increase
|
N/A | N/A | ||||||
|
Measurement date
|
December 31, 2009 | December 31, 2008 | ||||||
The weighted-average assumptions used to determine net periodic
benefit cost were as follows:
| Year Ended December 31, | ||||||||||||
| 2009 | 2008 | 2007 | ||||||||||
|
Discount rate
|
6.90 | % | 6.75 | % | 6.00 | % | ||||||
|
Expected long-term return on plan assets
|
8.75 | % | 8.75 | % | 8.75 | % | ||||||
|
Rate of compensation increase
|
N/A | N/A | 3.50 | % | ||||||||
|
Measurement date
|
December 31, 2008 | December 31, 2007 | December 31, 2006 | |||||||||
The expected rate of return on plan assets is determined by
taking into consideration expected long-term returns associated
with each major asset class (net of inflation) based on
long-term historical ranges, inflation assumptions and the
expected net value from active management of the assets based on
actual results.
F-39
Table of Contents
PEABODY
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
Effective January 1, 2010, the Company lowered its expected
rate of return on plan assets from 8.75% to 8.25% given the
decline in asset performance due to the global recession and
disruption in the financial markets, as well as
management’s reevaluation of the ongoing impact of active
management of assets by outside investment advisors.
The projected benefit obligation and the accumulated benefit
obligation exceeded plan assets for all plans as of
December 31, 2009 and 2008. The accumulated benefit
obligation for all pension plans was $844.9 million and
$768.6 million as of December 31, 2009, and 2008,
respectively.
Assets
of the Plans
Assets of the Peabody Plan and the Western Plan are commingled
in the PIC Master Trust (the Master Trust) and are invested in
accordance with investment guidelines that have been established
by the Company’s Retirement Committee (the Retirement
Committee) after consultation with outside investment advisors
and actuaries.
The asset allocation targets have been set with the expectation
that the Plans’ assets will be managed with an appropriate
level of risk so that they can fund each Plan’s expected
liabilities. To determine the appropriate target asset
allocations, the Retirement Committee considers the demographics
of each Plan’s participants, the funding status of each
Plan, the business and financial profile of the Company and
other associated risk preferences. These allocation targets are
reviewed by the Retirement Committee on a regular basis and
revised as necessary. The current target allocations for plan
assets are 55% equity securities, 35% fixed income investments
and 10% real estate investments. The Company plans to transition
to 60% equity securities and 40% fixed income investments over
time.
Assets of the Plans are either under active management by
third-party investment advisors or in index funds, all selected
and monitored by the Retirement Committee. The Retirement
Committee has established specific investment guidelines for
each major asset class including performance benchmarks,
allowable and prohibited investment types and concentration
limits. In general, the Plans’ investment guidelines do not
permit leveraging the assets held in the Master Trust. Equity
investment guidelines do not permit entering into put or call
options (except as deemed appropriate to manage currency risk),
and futures contracts are permitted only to the extent necessary
to equitize cash holdings.
The following table presents the fair value of assets in the
Master Trust by category and by fair value valuation hierarchy:
| December 31, 2009 | ||||||||||||||||
| Level 1 | Level 2 | Level 3 | Total | |||||||||||||
| (Dollars in millions) | ||||||||||||||||
|
U.S. equity securities
|
$ | 68.1 | $ | 200.2 | $ | — | $ | 268.3 | ||||||||
|
International equity securities
|
— | 102.2 | — | 102.2 | ||||||||||||
|
Mortgage-backed debt securities
|
— | 77.5 | — | 77.5 | ||||||||||||
|
U.S. debt securities
|
10.5 | 35.3 | — | 45.8 | ||||||||||||
|
International debt securities
|
— | 19.2 | — | 19.2 | ||||||||||||
|
Corporate debt securities
|
— | 37.2 | — | 37.2 | ||||||||||||
|
Short-term investments
|
— | 32.0 | — | 32.0 | ||||||||||||
|
Interests in real estate
|
— | — | 47.4 | 47.4 | ||||||||||||
|
Total assets at fair value
|
$ | 78.6 | $ | 503.6 | $ | 47.4 | $ | 629.6 | ||||||||
A financial instrument’s level within the valuation
hierarchy is based upon the lowest level of input that is
significant to the fair value measurement. Following is a
description of the valuation methodologies used
F-40
Table of Contents
PEABODY
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
for investments measured at fair value, including the general
classification of such investments pursuant to the valuation
hierarchy.
U.S. equity securities.
Investment
vehicles include various small-cap publicly traded common
stocks, an exchange-traded fund and a common collective trust.
Publicly traded common stocks and the exchange-traded fund are
traded on a national securities exchange and are valued at
quoted market prices in active markets and are classified within
Level 1 of the valuation hierarchy. While the common
collective trust invests in various large-cap publicly traded
common stocks that are traded on a national securities exchange,
it is classified within Level 2 of the valuation hierarchy
since the net asset value (NAV) is based on a derived price in
an active market and it is not publicly traded on a national
securities exchange.
International equity securities.
Investment
vehicles include a common collective trust and an investment
entity that primarily invest in various large-cap international
equity securities that are valued on the basis of quotations
from the primary market in which they are traded and translated
at each valuation date from the local currency into
U.S. dollars using the mean between the bid and asked
market rates for such currencies. The NAV of the fund and the
calculation of the NAV of each underlying investment is
determined in U.S. dollars by the custodial trustee or at
the direction of the investment manager as of the end of each
month. These investments are classified within the Level 2
valuation hierarchy since the NAV is based on a derived price in
an active market and neither the common collective trust nor the
investment entity are publicly traded on a national securities
exchange.
Debt securities.
Investment vehicles for U.S
debt securities, mortgage-backed debt securities, international
debt securities and corporate debt securities (collectively,
debt securities) primarily consist of mutual funds, which are
invested in various diversified portfolios of fixed-income
instruments. NAV for each debt security is calculated daily in
actively traded markets by an independent custodian for the
investment manager. For purposes of calculating NAV, portfolio
securities and other assets for which market quotes are readily
available are valued at market value. Market value is generally
determined on the basis of last reported sales prices, or if no
sales are reported, based on quotes obtained from a quotation
reporting system, established market makers, or pricing
services. Investments initially valued in currencies other than
the U.S. dollar are converted to the U.S. dollar using
exchange rates obtained from pricing services. Since the fair
value inputs are derived prices in active markets and the mutual
funds are not publicly traded on a national securities exchange,
the debt securities are classified within the Level 2
valuation hierarchy.
Short-term investments.
Investments primarily
consist of a common collective trust that invests in commercial
paper, repurchase agreements, time deposits and agency discount
notes. Units in the common collective trust are valued at NAV at
year-end. These investments are classified within Level 2
of the valuation hierarchy as the NAV for these investments is a
derived price in an active market and the common collective
trust is not publicly traded on a national securities exchange.
Interests in real estate.
Investments in real
estate represent interests in real estate pooled funds and
limited partnerships, which consist of net partnership interests
in properties. They are valued using various methodologies
including independent third party appraisals. For some
investments little market activity may exist and determination
of fair value is then based on the best information available in
the circumstances. This involves a significant degree of
judgment by taking into consideration a combination of internal
and external factors. Based on the above factors, the real
estate funds are classified within the Level 3 valuation
hierarchy.
The methods described above may produce a fair value calculation
that may not be indicative of net realizable value or reflective
of future fair values. Furthermore, while the Company believes
the valuation methods are appropriate and consistent with other
market participants, the use of different methodologies or
assumptions to determine the fair value of certain financial
instruments could result in a different fair value measurement
at the reporting date. The inputs or methodology used for
valuing investments are not necessarily an indication of the
risk associated with investing in those investments.
F-41
Table of Contents
PEABODY
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
The table below sets forth a summary of changes in the fair
value of the Master Trust’s Level 3 investments.
|
Year Ended
|
||||
| Interests in Real Estate | December 31, 2009 | |||
| (Dollars in millions) | ||||
|
Beginning of year
|
$ | 62.2 | ||
|
Assets held at the reporting date:
|
||||
|
Realized gains
|
1.5 | |||
|
Unrealized losses
|
(21.5 | ) | ||
|
Purchases, sales and settlements, net
|
6.2 | |||
|
Transfers out of Level 3
|
(1.0 | ) | ||
|
End of year
|
$ | 47.4 | ||
Contributions
Annual contributions to the Plans are made as determined by
consulting actuaries based upon the Employee Retirement Income
Security Act of 1974 minimum funding standard. In May 1998, the
Company entered into an agreement with the Pension Benefit
Guaranty Corporation (PBGC) which requires the Company to
maintain certain minimum funding requirements. Effective
January 1, 2008, new minimum funding standards were
required by the Pension Protection Act of 2006 (the Pension
Protection Act) that 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 benefit accruals cease.
As of December 31, 2009, the Company’s qualified
pension plans were approximately 77% funded (on a GAAP
accounting basis), before considering planned 2010 contributions
of $3.4 million, which represents the 2010 minimum funding
requirement for the qualified Plans.
Estimated
Future Benefit Payments
The following benefit payments (net of retiree contributions),
which reflect expected future service, as appropriate, are
expected to be paid by the Master Trust:
| Pension Benefits | ||||
| (Dollars in millions) | ||||
|
2010
|
$ | 53.9 | ||
|
2011
|
55.4 | |||
|
2012
|
56.9 | |||
|
2013
|
58.8 | |||
|
2014
|
61.0 | |||
|
Years
2015-2019
|
327.1 | |||
Defined
Contribution Plans
The Company sponsors employee retirement accounts under three
401(k) plans for eligible U.S. employees. The Company
matches voluntary contributions to each plan up to specified
levels. The expense for these plans was $47.9 million,
$50.5 million and $21.7 million for the years ended
December 31, 2009, 2008 and 2007, respectively. A
performance contribution feature allows for additional
contributions from the Company
F-42
Table of Contents
PEABODY
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
based upon meeting specified Company performance targets.
Performance contributions related to the years ended
December 31, 2009, 2008, and 2007 were $20.3 million,
$18.7 million and $4.9 million, respectively.
Multi-Employer
Pension Plan — Discontinued Operations
Certain subsidiaries that were part of the Patriot spin-off
participate in multi-employer pension plans (the 1950 Plan and
the 1974 Plan), which provide defined benefits to substantially
all hourly coal production workers represented by the UMWA under
the 2007 NBCWA. During 2007, contributions of $5.9 million
made to the 1974 Plan were expensed as paid, and are reflected
in “Discontinued operations.” There were no
contributions to the multi-employer pension plans during the
years ended December 31, 2009 and 2008.
| (15) | Postretirement Health Care and Life Insurance Benefits |
The Company currently provides health care and life insurance
benefits to qualifying salaried and hourly retirees and their
dependents from defined benefit plans established by the
Company. Plan coverage for health and life insurance benefits is
provided to future hourly retirees in accordance with the
applicable labor agreement.
Net periodic postretirement benefit cost included the following
components:
| Year Ended December 31, | ||||||||||||
| 2009 | 2008 | 2007 | ||||||||||
| (Dollars in millions) | ||||||||||||
|
Service cost for benefits earned
|
$ | 10.5 | $ | 10.1 | $ | 9.4 | ||||||
|
Interest cost on accumulated postretirement benefit obligation
|
55.2 | 54.0 | 50.6 | |||||||||
|
Amortization of prior service cost (credit)
|
1.5 | 0.4 | (0.2 | ) | ||||||||
|
Amortization of actuarial losses
|
14.5 | 17.3 | 22.8 | |||||||||
|
Net periodic postretirement benefit cost
|
$ | 81.7 | $ | 81.8 | $ | 82.6 | ||||||
Net periodic postretirement benefit cost related to the spin-off
of Patriot was $46.6 million for the year ended
December 31, 2007 and was included in “Discontinued
operations.”
The following includes amounts recognized in accumulated other
comprehensive loss:
| Year Ended December 31, | ||||||||||||
| 2009 | 2008 | 2007 | ||||||||||
| (Dollars in millions) | ||||||||||||
|
Net actuarial (gain) loss arising during year
|
$ | 165.2 | $ | (18.3 | ) | $ | (24.5 | ) | ||||
|
Prior service cost arising during year
|
(10.5 | ) | — | 13.8 | ||||||||
|
Amortizations:
|
||||||||||||
|
Actuarial loss
|
(14.5 | ) | (17.3 | ) | (22.8 | ) | ||||||
|
Prior service (cost) credit
|
(1.5 | ) | (0.4 | ) | 0.2 | |||||||
|
Total recognized in other comprehensive loss
|
138.7 | (36.0 | ) | (33.3 | ) | |||||||
|
Net periodic postretirement benefit cost
|
81.7 | 81.8 | 82.6 | |||||||||
|
Total recognized in net periodic postretirement benefit costs
and other comprehensive loss
|
$ | 220.4 | $ | 45.8 | $ | 49.3 | ||||||
The Company amortizes actuarial gains and losses using a 0%
corridor with an amortization period that covers the average
remaining service period of active employees (10.92 years
and 10.68 years at January 1, 2009 and 2008,
respectively). The estimated net actuarial loss and prior
service cost that will be amortized
F-43
Table of Contents
PEABODY
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
from accumulated other comprehensive loss into net periodic
postretirement benefit cost during the year ended
December 31, 2010 are $25.4 million and
$2.0 million, respectively.
The following table sets forth the plan’s funded status
reconciled with the amounts shown in the consolidated balance
sheets:
| December 31, | ||||||||
| 2009 | 2008 | |||||||
| (Dollars in millions) | ||||||||
|
Change in benefit obligation:
|
||||||||
|
Accumulated postretirement benefit obligation at beginning of
period
|
$ | 833.4 | $ | 855.8 | ||||
|
Service cost
|
10.5 | 10.1 | ||||||
|
Interest cost
|
55.2 | 54.0 | ||||||
|
Participant contributions
|
1.2 | 1.5 | ||||||
|
Plan
amendments
(1)
|
(10.5 | ) | — | |||||
|
Benefits paid
|
(72.8 | ) | (69.7 | ) | ||||
|
Actuarial (gain) loss
|
165.2 | (18.3 | ) | |||||
|
Accumulated postretirement benefit obligation at end of period
|
982.2 | 833.4 | ||||||
|
Change in plan assets:
|
||||||||
|
Fair value of plan assets at beginning of period
|
— | — | ||||||
|
Employer contributions
|
71.6 | 68.2 | ||||||
|
Participant contributions
|
1.2 | 1.5 | ||||||
|
Benefits paid and administrative fees (net of Medicare
Part D reimbursements)
|
(72.8 | ) | (69.7 | ) | ||||
|
Fair value of plan assets at end of period
|
— | — | ||||||
|
Funded status at end of year
|
(982.2 | ) | (833.4 | ) | ||||
|
Less current portion (included in Accounts payable and accrued
expenses)
|
68.1 | 67.3 | ||||||
|
Noncurrent obligation (included in Accrued postretirement
benefit costs)
|
$ | (914.1 | ) | $ | (766.1 | ) | ||
| (1) | Effective January 1, 2010, the benefits provided to certain salaried retirees are capped at a fixed level, which resulted in a decrease to the retiree health care liability of $7.3 million. The Company will begin realizing the effect of this plan amendment over 13.54 years beginning January 1, 2010. |
The weighted-average assumptions used to determine the benefit
obligations as of the end of each year were as follows:
| Year Ended December 31, | ||||||||
| 2009 | 2008 | |||||||
|
Discount rate
|
6.14 | % | 6.85 | % | ||||
|
Rate of compensation increase
|
3.50 | % | 3.50 | % | ||||
|
Measurement date
|
December 31, 2009 | December 31, 2008 | ||||||
F-44
Table of Contents
PEABODY
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
The weighted-average assumptions used to determine net periodic
benefit cost were as follows:
| Year Ended December 31, | ||||||||||||
| 2009 | 2008 | 2007 | ||||||||||
|
Discount rate
|
6.85 | % | 6.60 | % | 6.00 | % | ||||||
|
Rate of compensation increase
|
3.50 | % | 3.50 | % | 3.50 | % | ||||||
|
Measurement date
|
December 31, 2008 | December 31, 2007 | December 31, 2006 | |||||||||
The following presents information about the assumed health care
cost trend rate:
| Year Ended December 31, | ||||||||
| 2009 | 2008 | |||||||
|
Health care cost trend rate assumed for next year
|
7.50% | 7.50% | ||||||
|
Rate to which the cost trend is assumed to decline (the ultimate
trend rate)
|
5.00% | 4.75% | ||||||
|
Year that the rate reaches the ultimate trend rate
|
2016 | 2014 | ||||||
Assumed health care cost trend rates have a significant effect
on the amounts reported for health care plans. A
one-percentage-point change in the assumed health care cost
trend would have the following effects:
|
One Percentage-
|
One Percentage-
|
|||||||
| Point Increase | Point Decrease | |||||||
| (Dollars in millions) | ||||||||
|
Effect on total service and interest cost components
|
$ | 6.7 | $ | (5.7 | ) | |||
|
Effect on total postretirement benefit obligation
|
$ | 98.3 | $ | (84.6 | ) | |||
Plan
Assets
The Company’s postretirement benefit plans are unfunded.
Estimated
Future Benefit Payments
The following benefit payments (net of retiree contributions),
which reflect expected future service as appropriate, are
expected to be paid by the Company:
|
Postretirement
|
||||
| Benefits | ||||
| (Dollars in millions) | ||||
|
2010
|
$ | 68.1 | ||
|
2011
|
70.7 | |||
|
2012
|
74.5 | |||
|
2013
|
75.9 | |||
|
2014
|
77.1 | |||
|
Years
2015-2019
|
398.3 | |||
Multi-Employer
Benefit Plans — Discontinued Operations
Multi-employer benefit obligations related to the Combined Fund,
the 1992 Benefit Plan and 1993 Benefit Plan became the
responsibility of Patriot in conjunction with the spin-off. The
Surface Mining Control and Reclamation Act Amendments of 2006
amended the federal laws establishing the Combined Fund and the
1992 Benefit Plan and include the 1993 Benefit Plan. To the
extent that (i) the annual federal funding is less than
benefits paid, (ii) Congress does not allocate additional
funds to cover the shortfall and (iii) Patriot’s
subsidiaries do not pay for their share of the shortfall, some
of the Company’s subsidiaries would be
F-45
Table of Contents
PEABODY
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
responsible for the additional costs. The total expense for the
Combined Fund, the 1992 Benefit Plan and 1993 Benefit Plan was
$14.5 million for the year ended December 31, 2007 and
was included in “Discontinued operations.”
| (16) | Stockholders’ Equity |
Common
Stock
The Company has 800.0 million authorized shares of
$0.01 par value common stock. Holders of common stock are
entitled to one vote per share on all matters to be voted upon
by the stockholders and vote together, as one class, with the
holders of the Company’s Series A Junior Participating
Preferred Stock, if any such shares were issued and outstanding.
The holders of common stock do not have cumulative voting rights
in the election of directors. Holders of common stock are
entitled to receive ratably dividends if, as and when dividends
are declared from time to time by the Company’s Board of
Directors out of funds legally available for that purpose, after
payment of dividends required to be paid on outstanding
preferred stock or series common stock, as described below. Upon
liquidation, dissolution or winding up, any business combination
or a sale or disposition of all or substantially all of the
assets, the holders of common stock are entitled to receive
ratably the assets available for distribution to the
stockholders after payment of liabilities and accrued but unpaid
dividends and liquidation preferences on any outstanding
preferred stock or series common stock. The common stock has no
preemptive or conversion rights and is not subject to further
calls or assessment by the Company. There are no redemption or
sinking fund provisions applicable to the common stock.
The following table summarizes common stock activity from
December 31, 2006 to December 31, 2009:
|
Shares
|
||||
| Outstanding | ||||
|
December 31, 2006
|
263,846,839 | |||
|
Stock options exercised
|
5,222,074 | |||
|
Stock grants to employees
|
937,795 | |||
|
Employee stock purchases
|
185,646 | |||
|
Stock grants to non-employee directors
|
11,892 | |||
|
Shares relinquished
|
(137,625 | ) | ||
|
December 31, 2007
|
270,066,621 | |||
|
Stock options exercised
|
1,388,174 | |||
|
Stock grants to employees
|
788,895 | |||
|
Employee stock purchases
|
119,737 | |||
|
Stock grants to non-employee directors
|
2,870 | |||
|
Shares repurchased
|
(5,524,574 | ) | ||
|
Shares relinquished
|
(196,744 | ) | ||
|
December 31, 2008
|
266,644,979 | |||
|
Stock options exercised
|
463,490 | |||
|
Stock grants to employees
|
794,213 | |||
|
Employee stock purchases
|
374,548 | |||
|
Stock grants to non-employee directors
|
4,788 | |||
|
Shares relinquished
|
(78,203 | ) | ||
|
December 31, 2009
|
268,203,815 | |||
F-46
Table of Contents
PEABODY
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
Preferred
Stock and Series Common Stock
The Board of Directors is authorized to issue up to
10.0 million shares of preferred stock and up to
40.0 million shares of series common stock. The Board of
Directors can determine the terms and rights of each series,
whether dividends (if any) will be cumulative or non-cumulative
and the dividend rate of the series, redemption or sinking fund
provisions, conversion terms, prices and rates, and amounts
payable on shares of the series in the event of any voluntary or
involuntary liquidation, dissolution or winding up of the
affairs of the Company. The Board of Directors may also
determine restrictions on the issuance of shares of the same
series or of any other class or series, and the voting rights
(if any) of the holders of the series. There were no outstanding
shares of preferred stock or series common stock as of
December 31, 2009.
Perpetual
Preferred Stock
As discussed in Note 12, the Company had
$732.5 million aggregate principal amount of Debentures
outstanding as of December 31, 2009. Perpetual preferred
stock issued upon a conversion of the Debentures will be fully
paid and non-assessable, and holders will have no preemptive or
preferential right to purchase any of the Company’s other
securities. The perpetual preferred stock has a liquidation
preference of $1,000 per share, is not convertible and is
redeemable at the Company’s option at any time at a cash
redemption price per share equal to the liquidation preference
plus any accumulated dividends. Holders are entitled to receive
cumulative dividends at an annual rate of 3.0875% if and when
declared by the Company’s Board of Directors. If the
Company fails to pay dividends on the perpetual preferred stock
for five years, or upon the occurrence of a mandatory trigger
event, as defined in the certificate of designations governing
the perpetual preferred stock, the Company generally must sell
warrants or preferred stock with specified characteristics and
use the funds from that sale to pay accumulated dividends after
the payment in full of any deferred interest on the Debentures,
subject to certain limitations. In the event of a mandatory
trigger event, the Company may not declare dividends on the
perpetual preferred stock other than those funded through the
sale of warrants or preferred stock as described above. Any
deferred interest on the Debentures at the time of notice of
conversion will be reflected as accumulated dividends on the
perpetual preferred stock at issuance. Additionally, holders of
the perpetual preferred stock are entitled to elect two
additional members to serve on the Company’s Board of
Directors if (i) prior to any remarketing of the perpetual
preferred stock, the Company fails to declare and pay dividends
with respect to the perpetual stock for 10 consecutive years or
(ii) after any successful remarketing or any final failed
remarketing of the perpetual preferred stock, the Company fails
to declare and pay six dividends thereon, whether or not
consecutive. The perpetual preferred stock may be remarketed at
the holder’s election after December 15, 2046 or
earlier, upon the first occurrence of a change of control if the
Company does not redeem the perpetual preferred stock. There
were no outstanding shares of perpetual preferred stock as of
December 31, 2009.
Preferred
Share Purchase Rights Plan and Series A Junior
Participating Preferred Stock
Each outstanding share of common stock, par value $0.01 per
share, of the Company carries one preferred share purchase right
(a Right). The Rights are governed by a plan that expires in
August 2012.
The Rights have certain anti-takeover effects. The Rights will
cause substantial dilution to a person or group that attempts to
acquire the Company on terms not approved by the Company’s
Board of Directors, except pursuant to any offer conditioned on
a substantial number of Rights being acquired. The Rights should
not interfere with any merger or other business combination
approved by the Board of Directors since the Rights may be
redeemed by the Company at a redemption price of $0.001 per
Right prior to the time that a person or group has acquired
beneficial ownership of 15% or more of the common stock of the
Company. In addition, the Board of Directors is authorized to
reduce the 15% threshold to not less than 10%.
Each Right entitles the holder to purchase one quarter of
one-hundredth of a share of Series A Junior Participating
Preferred Stock from the Company at an exercise price of $27.50,
which in turn provides rights
F-47
Table of Contents
PEABODY
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
to receive the number of common stock shares having a market
value of two times the exercise price of the Right. The Right is
exercisable only if a person or group acquires 15% or more of
the Company’s common stock. The Board of Directors is
authorized to issue up to 1.5 million shares of
Series A Junior Participating Preferred Stock. There were
no outstanding shares of Series A Junior Participating
Preferred Stock as of December 31, 2009.
Treasury
Stock
The Company has a share repurchase program for its common stock
with an authorized amount of $1 billion in which
repurchases may be made from time to time based on an evaluation
of the Company’s outlook and general business conditions,
as well as alternative investment and debt repayment options.
The Company’s Chairman and Chief Executive Officer also has
authority to direct the Company to repurchase up to
$100 million of 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, the Company has 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.
During the year ended December 31, 2009, the Company
received 78,203 shares of common stock to pay estimated
taxes as consideration for the exercise of stock options, the
payout of performance units and the vesting of restricted stock.
The value of the common stock tendered by employees was based
upon the closing price on the dates of the respective
transactions.
| (17) | Share-Based Compensation |
The Company recognizes share-based compensation expense in
accordance with the fair value recognition provisions of
“Compensation” topic of the ASC, which it adopted on
January 1, 2006. The Company has four equity incentive
plans for employees and non-employee directors that in the
aggregate allow for the issuance of share-based compensation in
the form of stock appreciation rights, restricted stock,
performance awards, incentive stock options, nonqualified stock
options and deferred stock units. These plans made
47.4 million shares of the Company’s common stock
available for grant, with 14.6 million shares available for
grant as of December 31, 2009. The Company has two employee
stock purchase plans that provide for the purchase of up to
6.0 million shares of the Company’s common stock, with
5.0 million shares authorized for purchase by
U.S. employees and 1.0 million shares authorized for
purchase by the Australian employees.
Share-based compensation expense, which is recorded in
“Selling and administrative expenses” in the
consolidated statements of operations, was as follows (Dollars
in millions):
|
Year Ended
|
Expense, Net of
|
|||||||||||
|
December 31,
|
Total Expense | Tax Benefit | Tax Benefit | |||||||||
|
2009
|
$ | 38.8 | $ | 15.0 | $ | 23.8 | ||||||
|
2008
|
34.9 | 13.5 | 21.4 | |||||||||
|
2007
|
20.1 | 2.9 | 17.2 | |||||||||
As of December 31, 2009, the total unrecognized
compensation cost related to nonvested awards was
$28.0 million, net of taxes, which is expected to be
recognized over 3.2 years with a weighted-average period of
0.7 years.
In 2009 and 2008, the Company granted deferred stock units to
each of its non-employee directors. The fair value of these
units are equal to the market price of the Company’s common
stock at the date of grant and generally vest after one year. In
2007, the Company granted stock options and restricted stock to
each of its non-employee directors.
F-48
Table of Contents
PEABODY
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
Restricted
Stock Awards
Restricted stock awards are typically granted in January of each
year and generally cliff vest after three years of service. The
fair value of restricted stock is equal to the market price of
the Company’s common stock at the date of grant and is
amortized to expense ratably over the vesting period.
A summary of restricted stock award activity is as follows:
|
Weighted
|
||||||||
|
Year Ended
|
Average
|
|||||||
|
December 31,
|
Grant-Date
|
|||||||
| 2009 | Fair Value | |||||||
|
Nonvested at January 1, 2009
|
1,788,333 | $ | 38.13 | |||||
|
Granted
|
769,229 | 30.09 | ||||||
|
Vested
|
(308,760 | ) | 36.43 | |||||
|
Forfeited
|
(103,937 | ) | 37.49 | |||||
|
Nonvested at December 31, 2009
|
2,144,865 | $ | 35.51 | |||||
Stock
Options
Employee and director stock options granted since the
Company’s initial public offering (IPO) of common stock in
May 2001 generally vest ratably over three years and expire
after 10 years from the date of the grant, subject to
earlier termination upon discontinuation of an employee’s
service. Options granted prior to the IPO generally cliff vest
in 2010 and represented 0.8 million options of the
3.2 million options outstanding at December 31, 2009.
Option grants are typically made in January of each year or
following the inception of employment for employees hired during
the year who are eligible to participate in the plan.
The Company used the Black-Scholes option pricing model to
determine the fair value of stock options. The Company utilized
U.S. Treasury yields as of the grant date for its risk-free
interest rate assumption, matching the treasury yield terms to
the expected life of the option. The Company utilized historical
company data to develop its dividend yield, expected volatility
and expected option life assumptions.
A summary of outstanding option activity under the plans is as
follows:
|
Weighted
|
||||||||||||||||||||
|
Weighted
|
Average
|
|||||||||||||||||||
|
Year Ended
|
Average
|
Remaining
|
||||||||||||||||||
|
December 31,
|
Exercise
|
Contractual
|
Aggregate Intrinsic
|
|||||||||||||||||
| 2009 | Price | Life | Value (In millions) | |||||||||||||||||
|
Options Outstanding at January 1, 2009
|
3,250,857 | $ | 17.84 | |||||||||||||||||
|
Granted
|
481,498 | 26.84 | ||||||||||||||||||
|
Exercised
|
(463,490 | ) | 7.73 | |||||||||||||||||
|
Forfeited
|
(22,835 | ) | 43.37 | |||||||||||||||||
|
Options Outstanding at December 31, 2009
|
3,246,030 | $ | 20.44 | 4.7 | $ | 85.1 | ||||||||||||||
|
Vested and Exercisable
|
1,715,557 | $ | 20.78 | 4.6 | $ | 43.1 | ||||||||||||||
During the years ended December 31, 2009, 2008 and 2007,
the total intrinsic value of options exercised, defined as the
excess fair value of the underlying stock over the exercise
price of the options, was $14.7 million, $72.8 million
and $248.7 million, respectively. The weighted-average fair
values of the
F-49
Table of Contents
PEABODY
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
Company’s stock options and the assumptions used in
applying the Black-Scholes option pricing model (for grants
during the years ended December 31, 2009, 2008 and
2007) were as follows:
| December 31, | ||||||||||||
| 2009 | 2008 | 2007 | ||||||||||
|
Weighted-average fair value
|
$ | 26.84 | $ | 64.31 | $ | 37.93 | ||||||
|
Risk-free interest rate
|
1.5 | % | 3.3 | % | 4.6 | % | ||||||
|
Expected option life
|
5.0 years | 5.0 years | 5.0 years | |||||||||
|
Expected volatility
|
60 | % | 40 | % | 43 | % | ||||||
|
Dividend yield
|
0.9 | % | 0.5 | % | 0.6 | % | ||||||
Performance
Units
Performance units are typically granted annually in January and
vest over a three-year measurement period. Prior to 2009, the
performance units were usually subject to the achievement of two
goals, 50% based on stock price performance compared to both an
industry peer group and a S&P index (market condition) and
50% based on a return on capital target (performance condition).
For 2009, the units granted were only subject to the achievement
of the market condition. Three performance unit grants are
outstanding for any given year. The payouts related to all
active grants will be settled in the Company’s common stock.
A summary of performance unit activity is as follows:
|
Weighted
|
||||||||
|
Average
|
||||||||
|
Year Ended
|
Remaining
|
|||||||
|
December 31,
|
Contractual
|
|||||||
| 2009 | Life | |||||||
|
Nonvested at January 1, 2009
|
250,691 | 1.5 | ||||||
|
Granted
|
248,263 | |||||||
|
Forfeited
|
(9,195 | ) | ||||||
|
Vested
|
(133,315 | ) | ||||||
|
Nonvested at December 31, 2009
|
356,444 | 1.5 | ||||||
As of December 31, 2009, there were 133,315 performance
units vested that had an aggregate intrinsic value of
$8.7 million and a conversion price per share of $44.49.
The awards settled are accounted for based on their grant date
fair value. The performance condition awards were valued
utilizing the grant date fair values of the Company’s stock
adjusted for dividends foregone during the vesting period. The
market condition awards were valued utilizing a Monte Carlo
simulation which incorporates the total stockholder return
hurdles set for each grant. The assumptions used in the
valuations for grants during the years ended December 31,
2009 and 2008 were as follows:
| December 31, | ||||||||
| 2009 | 2008 | |||||||
|
Risk-free interest rate
|
1.3 | % | 2.9 | % | ||||
|
Expected volatility
|
60 | % | 40 | % | ||||
|
Dividend yield
|
0.9 | % | 0.5 | % | ||||
Employee
Stock Purchase Plans
The Company’s eligible full-time and part-time employees
are able to contribute up to 15% of their base compensation into
the employee stock purchase plans, subject to a limit of $25,000
per person per year.
F-50
Table of Contents
PEABODY
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
Employees are able to purchase Company common stock at a 15%
discount to the lower of the fair market value of the
Company’s common stock on the initial or final trading
dates of each six-month offering period. Offering periods begin
on January 1 and July 1 of each year. The Company uses the
Black-Scholes option pricing model to determine the fair value
of employee stock purchase plans share-based payments. The fair
value of the six-month “look-back” option in the
Company’s employee stock purchase plans is estimated by
adding the fair value of 0.15 of one share of stock to the fair
value of 0.85 of an option on one share of stock. The Company
utilized U.S. Treasury yields as of the grant date for its
risk-free interest rate assumption, matching the treasury yield
terms to the six-month offering period. The Company utilized
historical company data to develop its dividend yield and
expected volatility assumptions.
Shares purchased under the plans were 0.3 million for the
year ended December 31, 2009, 0.1 million for the year
ended December 31, 2008 and 0.2 million for the year
ended December 31, 2007.
| (18) | Accumulated Other Comprehensive Income (Loss) |
The following table sets forth the after-tax components of
comprehensive income (loss):
|
Net
|
||||||||||||||||||||||||
|
Actuarial Loss
|
||||||||||||||||||||||||
|
Associated with
|
||||||||||||||||||||||||
|
Postretirement
|
Prior Service
|
Total
|
||||||||||||||||||||||
|
Foreign
|
Plans and
|
Cost Associated
|
Accumulated
|
|||||||||||||||||||||
|
Currency
|
Workers’
|
with
|
Other
|
|||||||||||||||||||||
|
Translation
|
Compensation
|
Postretirement
|
Cash Flow
|
Comprehensive
|
||||||||||||||||||||
| Adjustment | Obligations | Plans | Hedges | Loss | ||||||||||||||||||||
| (Dollars in millions) | ||||||||||||||||||||||||
|
December 31, 2006
|
$ | 3.1 | $ | (288.8 | ) | $ | (7.0 | ) | $ | 43.5 | $ | (249.2 | ) | |||||||||||
|
Net increase in value of cash flow hedges
|
— | — | — | 83.7 | 83.7 | |||||||||||||||||||
|
Reclassification from other comprehensive income to earnings:
|
||||||||||||||||||||||||
|
Continuing operations
|
— | 24.3 | (0.1 | ) | (61.8 | ) | (37.6 | ) | ||||||||||||||||
|
Discontinued operations
|
— | 17.9 | (6.1 | ) | — | 11.8 | ||||||||||||||||||
|
Current period change
|
— | 64.2 | (13.0 | ) | — | 51.2 | ||||||||||||||||||
|
Patriot spin-off
|
— | 65.7 | 7.3 | — | 73.0 | |||||||||||||||||||
|
December 31, 2007
|
3.1 | (116.7 | ) | (18.9 | ) | 65.4 | (67.1 | ) | ||||||||||||||||
|
Net decrease in value of cash flow hedges
|
— | — | — | (194.5 | ) | (194.5 | ) | |||||||||||||||||
|
Reclassification from other comprehensive income to earnings
|
— | 14.1 | 0.2 | (23.4 | ) | (9.1 | ) | |||||||||||||||||
|
Current period change
|
— | (117.8 | ) | — | — | (117.8 | ) | |||||||||||||||||
|
December 31, 2008
|
3.1 | (220.4 | ) | (18.7 | ) | (152.5 | ) | (388.5 | ) | |||||||||||||||
|
Net increase in value of cash flow hedges
|
— | — | — | 235.2 | 235.2 | |||||||||||||||||||
|
Reclassification from other comprehensive income to earnings
|
— | 11.8 | 1.8 | 84.6 | 98.2 | |||||||||||||||||||
|
Current period change
|
— | (128.4 | ) | — | — | (128.4 | ) | |||||||||||||||||
|
December 31, 2009
|
$ | 3.1 | $ | (337.0 | ) | $ | (16.9 | ) | $ | 167.3 | $ | (183.5 | ) | |||||||||||
Comprehensive income (loss) differs from net income by the
amount of unrealized gain or loss resulting from valuation
changes of the Company’s cash flow hedges (which include
fuel and explosives hedges,
F-51
Table of Contents
PEABODY
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
currency forwards, traded coal index contracts and interest rate
swaps) and the change in actuarial loss and prior service cost
during the periods. The values of the Company’s cash flow
hedging instruments are affected by changes in interest rates,
crude oil, diesel fuel, natural gas and coal prices and the
U.S. dollar/Australian dollar exchange rate. The change in
the value of the cash flow hedges during 2009 was primarily due
to the strengthening of the Australian dollar against the
U.S. dollar.
| (19) | Guarantees and Financial Instruments With Off-Balance-Sheet Risk |
In the normal course of business, the Company is a party to
guarantees and financial instruments with off-balance-sheet
risk, such as bank letters of credit, performance or surety
bonds and other guarantees and indemnities, which are not
reflected in the accompanying consolidated balance sheets. Such
financial instruments are valued based on the amount of exposure
under the instrument and the likelihood of required performance.
In the Company’s past experience, virtually no claims have
been made against these financial instruments. Management does
not expect any material losses to result from these guarantees
or off-balance-sheet instruments.
Letters
of Credit and Bonding
The Company has letters of credit, surety bonds and corporate
guarantees (such as self bonds) in support of the Company’s
reclamation, coal lease obligations, and workers’
compensation 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. |
The Company owns 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, the Company’s maximum reimbursement
obligation to the commercial bank was in turn supported by four
letters of credit totaling $42.7 million.
The Company is party to an agreement with the PBGC and TXU
Europe Limited, an affiliate of the Company’s former parent
corporation, under which the Company is required to make special
contributions to two of the Company’s defined benefit
pension plans and to maintain a $37.0 million letter of
credit in favor of the PBGC. If the Company or the PBGC gives
notice of an intent to terminate one or more of the covered
pension plans in which liabilities are not fully funded, or if
the Company fails to maintain the letter of credit, the PBGC may
draw down on the letter of credit and use the proceeds to
satisfy liabilities under the Employee Retirement Income
Security Act of 1974, as amended. The PBGC, however, is required
to first apply amounts received from a $110.0 million
guarantee in place from TXU Europe Limited in favor of the PBGC
before it
F-52
Table of Contents
PEABODY
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
draws on the Company’s 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, the Company has 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 the Company’s Australian mines.
Other
Guarantees
The Company has a liability recorded of $52.3 million as of
December 31, 2009 and $61.8 million as of
December 31, 2008 related to reclamation and bonding
commitments associated with the purchase of approximately
427 million tons of coal reserves and surface lands in the
Illinois Basin in 2007.
The Company is the lessee under numerous equipment and property
leases. It is common in such commercial lease transactions for
the Company, as the lessee, to agree to indemnify the lessor for
the value of the property or equipment leased, should the
property be damaged or lost during the course of the
Company’s operations. The Company expects that losses with
respect to leased property would be covered by insurance
(subject to deductibles). The Company and certain of its
subsidiaries have guaranteed other subsidiaries’
performance under their various lease obligations. Aside from
indemnification of the lessor for the value of the property
leased, the Company’s maximum potential obligations under
its leases are equal to the respective future minimum lease
payments as presented in Note 9, and the Company assumes
that no amounts could be recovered from third parties.
A subsidiary of the Company owns a 5.06% undivided interest in
Prairie State, which is currently under construction. In
connection with the development of Prairie State, each owner,
including the Company’s subsidiary, has a guarantee for its
proportionate share of obligations to pay its percentage of the
construction costs under the Target Price Engineering,
Procurement and Construction Agreement with Bechtel Power
Corporation. The Company has capitalized development costs of
$126.5 million and $69.7 million that were recorded as
part of “Investments and other assets” in the
consolidated balance sheets as of December 31, 2009 and
2008, respectively. The Company spent $56.8 million during
the year ended December 31, 2009 representing its 5.06%
share of the construction costs. Total construction costs for
Prairie State are expected to be approximately $4 billion.
The Company has provided financial guarantees under certain
long-term debt agreements entered into by its subsidiaries, and
substantially all of the Company’s subsidiaries provide
financial guarantees under long-term debt agreements entered
into by the Company. The maximum amounts payable under the
Company’s debt agreements are equal to the respective
principal and interest payments. See Note 12 for the
descriptions of the Company’s (and its subsidiaries’)
debt. Supplemental guarantor/non-guarantor financial information
is provided in Note 23.
As part of the Patriot spin-off, the Company agreed to maintain
in force several letters of credit that secured Patriot
obligations for certain employee benefits and workers’
compensation obligations. As of December 31, 2009, these
letters of credit were released as Patriot satisfied the
beneficiaries with alternate letters of credit or insurance.
A discussion of the Company’s accounts receivable
securitization program is included in Note 6 to the
consolidated financial statements.
F-53
Table of Contents
PEABODY
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
| (20) | Commitments and Contingencies |
Commitments
As of December 31, 2009, purchase commitments for capital
expenditures were $70.4 million. Commitments for
expenditures to be made under coal leases are reflected in
Note 9. The Company has also 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.
As of December 31, 2009, these commitments totaled
$1,864.4 million with $718.5 million obligated within
the next five years and $110.7 million obligated within the
next year.
From time to time, the Company or its subsidiaries are involved
in legal proceedings arising in the ordinary course of business
or related to indemnities or historical operations. The Company
believes it has recorded adequate reserves for these liabilities
and that there is no individual case pending that is likely to
have a material adverse effect on the Company’s financial
condition, results of operations or cash flows. The Company
discusses its significant legal proceedings below.
Litigation
Relating to Continuing Operations
Navajo Nation Litigation.
On June 18,
1999, the Navajo Nation served three of the Company’s
subsidiaries, including Peabody Western Coal Company (Peabody
Western), with a complaint that had been filed in the
U.S. District Court for the District of Columbia. The
Navajo Nation has alleged 16 claims, including Civil Racketeer
Influenced and Corrupt Organizations Act (RICO) violations and
fraud. The complaint alleges that the defendants jointly
participated in unlawful activity to obtain favorable coal lease
amendments. The plaintiff is seeking various remedies including
actual damages of at least $600 million, which could be
trebled under the RICO counts, punitive damages of at least
$1 billion, a determination that Peabody Western’s two
coal leases have terminated due to Peabody Western’s breach
of these leases and a reformation of these leases to adjust the
royalty rate to 20%. Subsequently, the court allowed the Hopi
Tribe to intervene in this lawsuit and the Hopi Tribe is also
seeking unspecified actual damages, punitive damages and
reformation of its coal lease. One of the Company’s
subsidiaries named as a defendant is now a subsidiary of
Patriot. However, the Company is responsible for this litigation
under the Separation Agreement entered into with Patriot in
connection with the spin-off. On April 6, 2009, the
U.S. Supreme Court ruled against the Navajo Nation in a
related case against the U.S. government, and remanded that
case to the lower court to dismiss the complaint. The
U.S. Supreme Court said that none of the sources relied on
by the Navajo Nation provided a basis for its
breach-of-trust
lawsuit against the U.S. government, which undermines some
of the claims the Navajo Nation asserts in its litigation
against the Company.
The outcome of this litigation is subject to numerous
uncertainties. Based on the Company’s evaluation of the
issues and their potential impact, the amount of any future loss
cannot be reasonably estimated. However, based on current
information, the Company believes this matter is likely to be
resolved without a material adverse effect on the Company’s
financial condition, results of operations or cash flows.
Gulf Power Company Litigation.
On
June 22, 2006, Gulf Power Company (Gulf Power) filed a
breach of contract lawsuit against a Company subsidiary in the
U.S. District Court, Northern District of Florida,
contesting the force majeure declaration by the Company’s
subsidiary under a coal supply agreement with Gulf Power and
seeking damages for alleged past and future tonnage shortfalls
of nearly 5 million tons under the agreement, which expired
on December 31, 2007. In February 2008, the court denied
the Company’s motion to dismiss the Florida lawsuit or to
transfer it to Illinois and retained jurisdiction over the case.
Gulf Power filed a motion for partial summary judgment on
liability, and the Company subsidiary filed a motion for summary
judgment seeking complete dismissal. On September 30, 2009,
the court granted Gulf Power’s motion for partial summary
judgment and denied the Company subsidiary’s motion for
summary judgment. In October 2009, the Company
F-54
Table of Contents
PEABODY
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
subsidiary filed a motion for reconsideration which the court
denied. The damages portion of the trial was held in February
2010; however, the court has not yet rendered its decision in
the case.
The outcome of this litigation is subject to numerous
uncertainties. Based on the Company’s evaluation of the
issues and their potential impact, the amount of any future loss
cannot reasonably be estimated. However, based on current
information, the Company believes this matter is likely to be
resolved without a material adverse effect on its financial
condition, results of operations or cash flows.
Claims
and Litigation Relating to Indemnities or Historical
Operations
Oklahoma Lead Litigation.
Gold Fields Mining,
LLC (Gold Fields) is a dormant, non-coal producing entity that
was previously managed and owned by Hanson PLC, the
Company’s predecessor owner. In a February 1997 spin-off,
Hanson PLC transferred ownership of Gold Fields to the Company,
despite the fact that Gold Fields had no ongoing operations and
the Company had no prior involvement in its past operations.
Gold Fields is currently one of the Company’s subsidiaries.
The Company indemnified TXU Group with respect to certain claims
relating to a former affiliate of Gold Fields. A predecessor of
Gold Fields formerly operated two lead mills near Picher,
Oklahoma prior to the 1950s and mined, in accordance with lease
agreements and permits, approximately 0.15% of the total amount
of the crude ore mined in the county.
Gold Fields and several other companies are defendants in two
property damage lawsuits arising from past operations near
Picher, Oklahoma. The plaintiffs are seeking compensatory
damages for diminution in property values and punitive damages.
These cases were originally filed as putative class actions, but
the court has denied class certification and the cases were
subsequently amended to include a number of individual
plaintiffs. In December 2003, the Quapaw Indian tribe and
certain Quapaw land owners filed a lawsuit against Gold Fields,
five other companies and the U.S. The plaintiffs are
seeking compensatory and punitive damages based on a variety of
theories. In December 2007, the court dismissed the tribe’s
medical monitoring claim. In July 2008, the court dismissed the
tribe’s claim for interim and lost use damages under the
Comprehensive Environmental Response, Compensation and Liability
Act without prejudice to refile at the point the
U.S. Environmental Protection Agency (EPA) selects a final
remedy for the site. Gold Fields has filed a third-party
complaint against the U.S. and other parties. In February
2005, the state of Oklahoma on behalf of itself and several
other parties sent a notice to Gold Fields and other companies
regarding a possible natural resources damage claim. All of the
lawsuits are pending in the U.S. District Court for the
Northern District of Oklahoma.
The outcome of litigation and these claims are subject to
numerous uncertainties. Based on the Company’s evaluation
of the issues and their potential impact, the amount of any
future loss cannot be reasonably estimated. However, based on
current information, the Company believes this matter is likely
to be resolved without a material adverse effect on its
financial condition, results of operations or cash flows.
Environmental
Claims and Litigation
Environmental claims have been asserted against Gold Fields
related to activities of Gold Fields or a former affiliate. Gold
Fields or the former affiliate has been named a potentially
responsible party (PRP) at five national priority list sites
based on the Superfund Amendments and Reauthorization Act of
1986. Claims were asserted at 12 additional sites, bringing the
total to 17, which have since been reduced to 11 by completion
of work, transfer or regulatory inactivity. The number of PRP
sites in and of itself is not a relevant measure of liability,
because the nature and extent of environmental concerns varies
by site, as does the estimated share of responsibility for Gold
Fields or the former affiliate. Undiscounted liabilities for
environmental cleanup-related costs for all of the sites noted
above were $49.5 million as of December 31, 2009 and
$45.3 million as of December 31, 2008,
$7.9 million and $7.6 million of which was reflected
as a current liability, respectively. These amounts represent
those costs that the Company believes are probable and
reasonably estimable. In September 2005, Gold Fields and other
PRPs received a letter from the
F-55
Table of Contents
PEABODY
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
U.S. Department of Justice alleging that the PRP’s
mining operations caused the EPA to incur approximately
$125 million in residential yard remediation costs at
Picher, Oklahoma and will cause the EPA to incur additional
remediation costs relating to historical mining sites. In
September 2008, Gold Fields and other PRPs received letters from
the U.S. Department of Justice and the EPA re-initiating
settlement negotiations. Gold Fields continues to participate in
the settlement discussions. Gold Fields believes it has
meritorious defenses to these claims. Gold Fields is involved in
other litigation in the Picher area, and the Company indemnified
TXU Group with respect to a defendant as is more fully discussed
under the “Oklahoma Lead Litigation” caption above.
Gold Fields has also been contacted by the state of Kansas
(Kansas Department of Health and Environment) and is in
negotiations for final resolution of natural resource damages
claims at two sites. Significant uncertainty exists as to
whether claims will be pursued against Gold Fields in all cases,
and where they are pursued, the amount of the eventual costs and
liabilities, which could be greater or less than the liabilities
recorded in the consolidated balance sheets. Based on the
Company’s evaluation of the issues and their potential
impact, the amount of any future loss cannot be reasonably
estimated. However, based on current information, the Company
believes these claims and litigation are likely to be resolved
without a material adverse effect on its financial condition,
results of operations or cash flows.
Comer, et al v. Murphy Oil Co., et
al.
In April 2006, residents and owners of land
and property along the Mississippi Gulf coast filed a purported
class action lawsuit in the U.S. District Court in the
Southern District of Mississippi against more than 45 oil,
chemical, utility and coal companies, including the Company. The
plaintiffs alleged that defendants’ greenhouse gas
emissions “were a proximate and direct cause of the
increase in the destructive capacity of Hurricane Katrina,”
and sought damages based on several legal theories. The
defendants filed motions to dismiss on the grounds of lack of
personal and subject matter jurisdiction. In August 2007, the
court granted defendants’ motion to dismiss for lack of
subject matter jurisdiction finding that plaintiffs’ claims
are barred by the political question doctrine and for lack of
standing. In October 2009, the U.S. Court of Appeals for
the Fifth Circuit reversed in part the decision of the trial
court, holding that the plaintiffs had standing to assert their
public and private nuisance, trespass and negligence claims. The
Fifth Circuit held that plaintiffs did not satisfy the
prudential standing requirement for their unjust enrichment,
fraudulent misrepresentation and civil conspiracy claims and
dismissed those claims. The case was remanded to the court for
further proceedings. The Company believes that this lawsuit is
without merit and intends to defend against and oppose it
vigorously, but cannot predict its outcome. Based on the
Company’s evaluation of the issues and their potential
impact, the amount of any future loss cannot be reasonably
estimated. However, based on current information, the Company
believes this matter is likely to be resolved without a
materially adverse effect on its financial condition, results of
operations or cash flows.
Native Village of Kivalina and City of Kivalina v.
ExxonMobil Corporation, et al.
In February 2008,
the Native Village of Kivalina and the City of Kivalina filed a
lawsuit in the U.S. District Court for the Northern
District of California against the Company, several owners of
electricity generating facilities and several oil companies. The
plaintiffs are the governing bodies of a village in Alaska that
they contend is being destroyed by erosion allegedly caused by
global warming that the plaintiffs attribute to emissions of
greenhouse gases by the defendants. The plaintiffs assert claims
for nuisance, and allege that the defendants have acted in
concert and are jointly and severally liable for the
plaintiffs’ damages. The suit seeks damages for lost
property values and for the cost of relocating the village. The
defendants filed motions to dismiss on the grounds of lack of
personal and subject matter jurisdiction. In September 2009, the
court granted defendants’ motion to dismiss for lack of
subject matter jurisdiction finding that plaintiffs’
federal claim for nuisance is barred by the political question
doctrine and for lack of standing. The plaintiffs are appealing
the court’s dismissal.
Other
In addition, at times the Company becomes a party to other
claims, lawsuits, arbitration proceedings and administrative
procedures in the ordinary course of business in the U.S.,
Australia and other countries where
F-56
Table of Contents
PEABODY
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
the Company does business. Based on current information, the
Company believes that the ultimate resolution of such other
pending or threatened proceedings is not reasonably likely to
have a material adverse effect on its financial position,
results of operations or liquidity.
New York Office of the Attorney General
Subpoena.
The New York Office of the Attorney
General sent a letter to the Company dated September 14,
2007 that referred to the Company’s “plans to build
new coal-fired electric generating units,” and said that
the “increase in
CO
2
emissions from the operation of these units, in combination with
Peabody Energy’s other coal-fired power plants, will
subject Peabody Energy to increased financial, regulatory, and
litigation risks.” The Company currently has no electricity
generating capacity in place. The letter included a subpoena
issued under New York state law, which seeks information and
documents relating to the Company’s analysis of the risks
associated with climate change and possible climate change
legislation or regulations, and its disclosure of such risks to
investors. The Company believes that it has made full and proper
disclosure of these potential risks.
| (21) | Summary Quarterly Financial Information (Unaudited) |
A summary of the unaudited quarterly results of operations for
the years ended December 31, 2009 and 2008 is presented
below. In the third quarter of 2009, the Company’s Chain
Valley Mine in Australia was held for sale and subsequently sold
in the fourth quarter of 2009. See Note 2 for additional
information regarding the sale. All periods presented below
reflect the Chain Valley Mine as a discontinued operation.
| Year Ended December 31, 2009 | ||||||||||||||||
| First Quarter | Second Quarter | Third Quarter | Fourth Quarter | |||||||||||||
| (In millions except per share data) | ||||||||||||||||
|
Revenues
|
$ | 1,453.0 | $ | 1,338.2 | $ | 1,667.0 | $ | 1,554.2 | ||||||||
|
Operating profit
|
219.7 | 215.4 | 220.3 | 189.4 | ||||||||||||
|
Income from continuing operations, net of income taxes
|
141.2 | 90.0 | 113.2 | 113.5 | ||||||||||||
|
Net income
|
175.2 | 82.0 | 110.8 | 95.0 | ||||||||||||
|
Net income attributable to common stockholders
|
170.0 | 79.2 | 106.8 | 92.2 | ||||||||||||
|
Basic earnings per share — continuing
operations
(1)
|
0.51 | 0.33 | 0.41 | 0.41 | ||||||||||||
|
Diluted earnings per share — continuing
operations
(1)
|
0.50 | 0.32 | 0.41 | 0.41 | ||||||||||||
|
Weighted average shares used in calculating basic earnings per
share
|
265.3 | 265.4 | 265.7 | 265.8 | ||||||||||||
|
Weighted average shares used in calculating diluted earnings per
share
|
267.3 | 267.1 | 267.3 | 267.7 | ||||||||||||
| (1) | Earnings per share for the quarters may not add to the amounts for the year as each period is computed on a discrete basis. |
F-57
Table of Contents
PEABODY
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
Operating profit in the second, third and fourth quarters
reflect lower contract pricing in Australia that began in the
second quarter. Operating profit in the fourth quarter included
an impairment loss of $34.7 million (see “Investments
in Joint Ventures” section of Note 1 for additional
information). Income from continuing operations, net of income
taxes in the first quarter included a benefit of
$0.9 million from the remeasurement of
non-U.S. income
tax accounts while the second, third and fourth quarters
included non-cash tax expense of $47.7 million,
$22.3 million, and $5.3 million, respectively. Net
income in the first quarter included a gain of approximately
$35 million (net of income taxes) related to a coal excise
tax refund (see Note 2 for additional information).
| Year Ended December 31, 2008 | ||||||||||||||||
| First Quarter | Second Quarter | Third Quarter | Fourth Quarter | |||||||||||||
| (In millions except per share data) | ||||||||||||||||
|
Revenues
|
$ | 1,259.9 | $ | 1,517.6 | $ | 1,889.6 | $ | 1,893.9 | ||||||||
|
Operating profit
|
185.0 | 346.0 | 496.6 | 368.7 | ||||||||||||
|
Income from continuing operations, net of income taxes
|
79.5 | 244.9 | 383.2 | 280.3 | ||||||||||||
|
Net income
|
57.9 | 235.8 | 371.8 | 293.6 | ||||||||||||
|
Net income attributable to common stockholders
|
57.0 | 233.3 | 369.5 | 293.1 | ||||||||||||
|
Basic earnings per share — continuing
operations
(1)
|
0.30 | 0.89 | 1.40 | 1.04 | ||||||||||||
|
Diluted earnings per share — continuing
operations
(1)
|
0.29 | 0.89 | 1.39 | 1.04 | ||||||||||||
|
Weighted average shares used in calculating basic earnings per
share
|
269.2 | 270.0 | 270.2 | 266.1 | ||||||||||||
|
Weighted average shares used in calculating diluted earnings per
share
|
271.5 | 271.9 | 271.8 | 267.2 | ||||||||||||
| (1) | Earnings per share for the quarters may not add to the amounts for the year as each period is computed on a discrete basis. |
Operating profit in the first quarter included a
$54.0 million gain on the sale of coal reserves and surface
lands (see Note 4 for information). The second, third and
fourth quarter operating profits reflect higher contract pricing
in Australia that began in the second quarter. The second
quarter operating profit also included revenue recovery of
$56.9 million on coal supply agreements. Income from
continuing operations, net of income taxes for the first and
second quarters included non-cash tax expense of
$15.8 million and $17.6 million, respectively, from
the remeasurement of
non-U.S. income
tax accounts while the third and fourth quarters included
non-cash tax benefits of $62.7 million and $35.9,
respectively. Income from continuing operations, net of income
taxes in the second quarter also included a tax benefit of
$45.3 million due to the reduction in net operating loss
valuation allowances (see Note 11 for information). Net
income in the first quarter included a loss of approximately
$12 million (net of income taxes) related to a coal excise
tax refund (see Note 2 for additional information).
| (22) | Segment Information |
The Company reports its operations primarily through the
following reportable operating segments: “Western
U.S. Mining,” “Midwestern U.S. Mining,”
“Australian Mining,” “Trading and Brokerage”
and “Corporate and Other.” Western U.S. Mining
operations reflect the aggregation of the Powder River Basin,
Southwest and Colorado mining operations, and Midwestern
U.S. Mining operations reflects the Company’s Illinois
and Indiana mining operations. In 2008, the Company renamed its
Eastern U.S. Mining segment to Midwestern U.S. Mining
segment to better reflect the geography of the continuing
operations of that region.
F-58
Table of Contents
PEABODY
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
The principal business of the Western U.S. Mining,
Midwestern U.S. Mining and Australian Mining segments is
the mining, preparation and sale of thermal coal, sold primarily
to electric utilities, and metallurgical coal, sold to steel and
coke producers. For the year ended December 31, 2009, 81%
of the Company’s 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.
Western U.S. Mining operations are characterized by
predominantly surface mining extraction processes, lower sulfur
content and Btu of coal and higher customer transportation costs
(due to longer shipping distances). Conversely, Midwestern
U.S. Mining operations are characterized by a mix of
surface and underground mining extraction processes, higher
sulfur content and Btu of coal and lower customer transportation
costs (due to shorter shipping distances). Geologically, Western
operations mine bituminous and subbituminous coal deposits, and
Midwestern operations mine bituminous coal deposits. Australian
Mining operations are characterized by both surface and
underground extraction processes, mining various qualities of
low-sulfur, high Btu coal (metallurgical coal) as well as
thermal coal primarily sold to an international customer base
with a small portion sold to Australian steel producers and
power generators. The Trading and Brokerage segment’s
principal business is the brokering of coal sales of other coal
producers both as principal and agent, and the trading of coal,
freight and freight-related contracts. Corporate and Other
includes selling and administrative expenses, net gains on
property disposals, costs associated with past mining
obligations, joint venture earnings (losses) and revenues and
expenses related to the Company’s other commercial
activities such as generation development, Btu Conversion, clean
coal technologies and resource management.
The Company’s chief operating decision maker uses Adjusted
EBITDA as the primary measure of segment profit and loss. The
Company defines Adjusted EBITDA as income from continuing
operations before deducting net interest expense, income taxes,
asset retirement obligation expense and depreciation, depletion
and amortization.
Operating segment results for the year ended December 31,
2009 were as follows:
|
Western
|
Midwestern
|
Australian
|
Trading and
|
Corporate
|
||||||||||||||||||||
| U.S. Mining | U.S. Mining | Mining | Brokerage | and Other | Consolidated | |||||||||||||||||||
| (Dollars in millions) | ||||||||||||||||||||||||
|
Revenues
|
$ | 2,612.6 | $ | 1,303.8 | $ | 1,678.0 | $ | 391.0 | $ | 27.0 | $ | 6,012.4 | ||||||||||||
|
Adjusted EBITDA
|
721.5 | 281.9 | 437.8 | 193.4 | (344.5 | ) | 1,290.1 | |||||||||||||||||
|
Total assets
|
3,061.3 | 334.3 | 3,386.8 | 673.0 | 2,499.9 | 9,955.3 | ||||||||||||||||||
|
Additions to property, plant, equipment and mine development
|
78.3 | 104.2 | 70.1 | 1.8 | 6.2 | 260.6 | ||||||||||||||||||
|
Federal coal lease expenditures
|
123.6 | — | — | — | — | 123.6 | ||||||||||||||||||
|
Income (loss) from equity affiliates
|
— | — | — | — | (69.1 | ) | (69.1 | ) | ||||||||||||||||
|
Additions to advance mining royalties
|
1.5 | 1.6 | — | — | 3.0 | 6.1 | ||||||||||||||||||
F-59
Table of Contents
PEABODY
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
Operating segment results for the year ended December 31,
2008 were as follows:
|
Western
|
Midwestern
|
Australian
|
Trading and
|
Corporate
|
||||||||||||||||||||
| U.S. Mining | U.S. Mining | Mining | Brokerage | and Other | Consolidated | |||||||||||||||||||
| (Dollars in millions) | ||||||||||||||||||||||||
|
Revenues
|
$ | 2,533.1 | $ | 1,154.6 | $ | 2,242.8 | $ | 601.8 | $ | 28.7 | $ | 6,561.0 | ||||||||||||
|
Adjusted EBITDA
|
681.3 | 177.3 | 1,016.6 | 218.9 | (247.2 | ) | 1,846.9 | |||||||||||||||||
|
Total assets
|
3,140.4 | 552.0 | 2,985.9 | 920.3 | 2,097.0 | 9,695.6 | ||||||||||||||||||
|
Additions to property, plant, equipment and mine development
|
140.4 | 30.3 | 62.8 | — | 30.6 | 264.1 | ||||||||||||||||||
|
Federal coal lease expenditures
|
178.5 | — | — | — | — | 178.5 | ||||||||||||||||||
|
Income (loss) from equity affiliates
|
— | — | — | — | — | — | ||||||||||||||||||
|
Additions to advance mining royalties
|
2.1 | 2.2 | — | — | 1.7 | 6.0 | ||||||||||||||||||
Operating segment results for the year ended December 31,
2007 were as follows:
|
Western
|
Midwestern
|
Australian
|
Trading and
|
Corporate
|
||||||||||||||||||||
| U.S. Mining | U.S. Mining | Mining | Brokerage | and Other | Consolidated | |||||||||||||||||||
| (Dollars in millions) | ||||||||||||||||||||||||
|
Revenues
|
$ | 2,063.2 | $ | 987.1 | $ | 1,117.6 | $ | 320.7 | $ | 35.2 | $ | 4,523.8 | ||||||||||||
|
Adjusted EBITDA
|
595.4 | 200.0 | 167.2 | 116.6 | (109.5 | ) | 969.7 | |||||||||||||||||
|
Total assets
|
2,893.8 | 529.6 | 3,033.3 | 346.8 | 2,278.8 | 9,082.3 | ||||||||||||||||||
|
Additions to property, plant, equipment and mine development
|
175.4 | 34.0 | 167.2 | — | 62.2 | 438.8 | ||||||||||||||||||
|
Federal coal lease expenditures
|
178.2 | — | — | — | — | 178.2 | ||||||||||||||||||
|
Income (loss) from equity affiliates
|
— | — | — | — | 14.5 | 14.5 | ||||||||||||||||||
|
Additions to advance mining royalties
|
1.5 | 2.7 | — | — | 3.9 | 8.1 | ||||||||||||||||||
A reconciliation of adjusted EBITDA to consolidated income from
continuing operations follows:
| Year Ended December 31, | ||||||||||||
| 2009 | 2008 | 2007 | ||||||||||
| (Dollars in millions) | ||||||||||||
|
Total adjusted EBITDA
|
$ | 1,290.1 | $ | 1,846.9 | $ | 969.7 | ||||||
|
Depreciation, depletion and amortization
|
(405.2 | ) | (402.4 | ) | (346.3 | ) | ||||||
|
Asset retirement obligation expense
|
(40.1 | ) | (48.2 | ) | (23.7 | ) | ||||||
|
Interest expense
|
(201.2 | ) | (227.0 | ) | (235.8 | ) | ||||||
|
Interest income
|
8.1 | 10.0 | 7.0 | |||||||||
|
Income tax (provision) benefit
|
(193.8 | ) | (191.4 | ) | 70.7 | |||||||
|
Income from continuing operations, net of income taxes
|
$ | 457.9 | $ | 987.9 | $ | 441.6 | ||||||
F-60
Table of Contents
PEABODY
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
| (23) | Supplemental Guarantor/Non-Guarantor Financial Information |
In accordance with the indentures governing the
6.875% Senior Notes due March 2013, the 5.875% Senior
Notes due March 2016, the 7.375% Senior Notes due November
2016 and the 7.875% Senior Notes due November 2026, certain
wholly-owned U.S. subsidiaries of the Company have fully
and unconditionally guaranteed these Senior Notes, on a joint
and several basis. Separate financial statements and other
disclosures concerning the Guarantor Subsidiaries are not
presented because management believes that such information is
not material to the Senior Note holders. The following
historical financial statement information is provided for the
Guarantor/Non-Guarantor Subsidiaries.
F-61
Table of Contents
PEABODY
ENERGY CORPORATION
SUPPLEMENTAL
CONSOLIDATED STATEMENTS OF OPERATIONS
| Year Ended December 31, 2009 | ||||||||||||||||||||
|
Parent
|
Guarantor
|
Non-Guarantor
|
||||||||||||||||||
| Company | Subsidiaries | Subsidiaries | Eliminations | Consolidated | ||||||||||||||||
| (Dollars in millions) | ||||||||||||||||||||
|
Total revenues
|
$ | — | $ | 4,024.0 | $ | 2,312.5 | $ | (324.1 | ) | $ | 6,012.4 | |||||||||
|
Costs and expenses
|
||||||||||||||||||||
|
Operating costs and expenses
|
104.4 | 2,958.5 | 1,728.9 | (324.1 | ) | 4,467.7 | ||||||||||||||
|
Depreciation, depletion and amortization
|
— | 287.6 | 117.6 | — | 405.2 | |||||||||||||||
|
Asset retirement obligation expense
|
— | 33.3 | 6.8 | — | 40.1 | |||||||||||||||
|
Selling and administrative expenses
|
29.3 | 168.9 | 10.5 | — | 208.7 | |||||||||||||||
|
Other operating (income) loss:
|
||||||||||||||||||||
|
Net gain on disposal or exchange of assets
|
— | (17.1 | ) | (6.1 | ) | — | (23.2 | ) | ||||||||||||
|
(Income) loss from equity affiliates
|
(620.9 | ) | 6.3 | 62.8 | 620.9 | 69.1 | ||||||||||||||
|
Interest expense
|
198.4 | 52.6 | 16.2 | (66.0 | ) | 201.2 | ||||||||||||||
|
Interest income
|
(15.3 | ) | (28.9 | ) | (29.9 | ) | 66.0 | (8.1 | ) | |||||||||||
|
Income from continuing operations before income taxes
|
304.1 | 562.8 | 405.7 | (620.9 | ) | 651.7 | ||||||||||||||
|
Income tax provision (benefit)
|
(122.3 | ) | 184.1 | 132.0 | — | 193.8 | ||||||||||||||
|
Income from continuing operations, net of income taxes
|
426.4 | 378.7 | 273.7 | (620.9 | ) | 457.9 | ||||||||||||||
|
Income (loss) from discontinued operations, net of income taxes
|
21.8 | (2.7 | ) | (14.0 | ) | — | 5.1 | |||||||||||||
|
Net income
|
448.2 | 376.0 | 259.7 | (620.9 | ) | 463.0 | ||||||||||||||
|
Less: Net income attributable to noncontrolling interests
|
— | — | 14.8 | — | 14.8 | |||||||||||||||
|
Net income attributable to common stockholders
|
$ | 448.2 | $ | 376.0 | $ | 244.9 | $ | (620.9 | ) | $ | 448.2 | |||||||||
F-62
Table of Contents
PEABODY
ENERGY CORPORATION
SUPPLEMENTAL
CONSOLIDATED STATEMENTS OF OPERATIONS
| Year Ended December 31, 2008 | ||||||||||||||||||||
|
Parent
|
Guarantor
|
Non-Guarantor
|
||||||||||||||||||
| Company | Subsidiaries | Subsidiaries | Eliminations | Consolidated | ||||||||||||||||
| (Dollars in millions) | ||||||||||||||||||||
|
Total revenues
|
$ | — | $ | 3,788.4 | $ | 2,981.4 | $ | (208.8 | ) | $ | 6,561.0 | |||||||||
|
Costs and expenses
|
||||||||||||||||||||
|
Operating costs and expenses
|
(51.5 | ) | 3,034.7 | 1,810.8 | (208.8 | ) | 4,585.2 | |||||||||||||
|
Depreciation, depletion and amortization
|
— | 265.9 | 136.5 | — | 402.4 | |||||||||||||||
|
Asset retirement obligation expense
|
— | 42.8 | 5.4 | — | 48.2 | |||||||||||||||
|
Selling and administrative expenses
|
22.0 | 171.6 | 8.2 | — | 201.8 | |||||||||||||||
|
Other operating (income) loss:
|
||||||||||||||||||||
|
Net gain on disposal or exchange of assets
|
— | (72.7 | ) | (0.2 | ) | — | (72.9 | ) | ||||||||||||
|
(Income) loss from equity affiliates
|
(1,075.0 | ) | 5.7 | (5.7 | ) | 1,075.0 | — | |||||||||||||
|
Interest expense
|
220.5 | 22.4 | 42.0 | (57.9 | ) | 227.0 | ||||||||||||||
|
Interest income
|
(15.1 | ) | (24.2 | ) | (28.6 | ) | 57.9 | (10.0 | ) | |||||||||||
|
Income from continuing operations before income taxes
|
899.1 | 342.2 | 1,013.0 | (1,075.0 | ) | 1,179.3 | ||||||||||||||
|
Income tax provision (benefit)
|
(67.7 | ) | 101.3 | 157.8 | — | 191.4 | ||||||||||||||
|
Income from continuing operations, net of income taxes
|
966.8 | 240.9 | 855.2 | (1,075.0 | ) | 987.9 | ||||||||||||||
|
Income (loss) from discontinued operations, net of income taxes
|
(13.9 | ) | (27.9 | ) | 13.0 | — | (28.8 | ) | ||||||||||||
|
Net income
|
952.9 | 213.0 | 868.2 | (1,075.0 | ) | 959.1 | ||||||||||||||
|
Less: Net income (loss) attributable to noncontrolling interests
|
— | (0.1 | ) | 6.3 | — | 6.2 | ||||||||||||||
|
Net income attributable to common stockholders
|
$ | 952.9 | $ | 213.1 | $ | 861.9 | $ | (1,075.0 | ) | $ | 952.9 | |||||||||
F-63
Table of Contents
| Year Ended December 31, 2007 | ||||||||||||||||||||
|
Parent
|
Guarantor
|
Non-Guarantor
|
||||||||||||||||||
| Company | Subsidiaries | Subsidiaries | Eliminations | Consolidated | ||||||||||||||||
| (Dollars in millions) | ||||||||||||||||||||
|
Total revenues
|
$ | — | $ | 3,271.7 | $ | 1,414.0 | $ | (161.9 | ) | $ | 4,523.8 | |||||||||
|
Costs and expenses
|
||||||||||||||||||||
|
Operating costs and expenses
|
(72.2 | ) | 2,533.6 | 1,210.6 | (161.9 | ) | 3,510.1 | |||||||||||||
|
Depreciation, depletion and amortization
|
— | 236.0 | 110.3 | — | 346.3 | |||||||||||||||
|
Asset retirement obligation expense
|
— | 17.8 | 5.9 | — | 23.7 | |||||||||||||||
|
Selling and administrative expenses
|
21.5 | 121.4 | 4.2 | — | 147.1 | |||||||||||||||
|
Other operating (income) loss:
|
— | |||||||||||||||||||
|
Net (gain) loss on disposal or exchange of assets
|
— | (88.8 | ) | 0.2 | — | (88.6 | ) | |||||||||||||
|
(Income) loss from equity affiliates
|
(536.6 | ) | 6.7 | (21.2 | ) | 536.6 | (14.5 | ) | ||||||||||||
|
Interest expense
|
279.5 | 32.1 | 26.6 | (102.4 | ) | 235.8 | ||||||||||||||
|
Interest income
|
(17.5 | ) | (68.0 | ) | (23.9 | ) | 102.4 | (7.0 | ) | |||||||||||
|
Income (loss) from continuing operations before income taxes
|
325.3 | 480.9 | 101.3 | (536.6 | ) | 370.9 | ||||||||||||||
|
Income tax provision (benefit)
|
(83.8 | ) | (94.4 | ) | 107.5 | — | (70.7 | ) | ||||||||||||
|
Income (loss) from continuing operations, net of income taxes
|
409.1 | 575.3 | (6.2 | ) | (536.6 | ) | 441.6 | |||||||||||||
|
Loss from discontinued operations, net of income taxes
|
(145.3 | ) | (8.2 | ) | (26.6 | ) | — | (180.1 | ) | |||||||||||
|
Net income (loss)
|
263.8 | 567.1 | (32.8 | ) | (536.6 | ) | 261.5 | |||||||||||||
|
Less: Net income (loss) attributable to noncontrolling interests
|
— | 0.9 | (3.2 | ) | — | (2.3 | ) | |||||||||||||
|
Net income (loss) attributable to common stockholders
|
$ | 263.8 | $ | 566.2 | $ | (29.6 | ) | $ | (536.6 | ) | $ | 263.8 | ||||||||
F-64
Table of Contents
PEABODY
ENERGY CORPORATION
SUPPLEMENTAL
CONSOLIDATED BALANCE SHEETS
| December 31, 2009 | ||||||||||||||||||||
|
Parent
|
Guarantor
|
Non-Guarantor
|
Reclassifications/
|
|||||||||||||||||
| Company | Subsidiaries | Subsidiaries | Eliminations | Consolidated | ||||||||||||||||
| (Dollars in millions) | ||||||||||||||||||||
|
Assets
|
||||||||||||||||||||
|
Current assets
|
||||||||||||||||||||
|
Cash and cash equivalents
|
$ | 368.4 | $ | 0.2 | $ | 620.2 | $ | — | $ | 988.8 | ||||||||||
|
Accounts receivable, net
|
0.6 | 55.5 | 246.9 | — | 303.0 | |||||||||||||||
|
Inventories
|
— | 152.5 | 172.6 | — | 325.1 | |||||||||||||||
|
Assets from coal trading activities, net
|
— | 92.8 | 184.0 | — | 276.8 | |||||||||||||||
|
Deferred income taxes
|
11.6 | 56.5 | — | (28.1 | ) | 40.0 | ||||||||||||||
|
Other current assets
|
133.9 | 30.7 | 90.7 | — | 255.3 | |||||||||||||||
|
Total current assets
|
514.5 | 388.2 | 1,314.4 | (28.1 | ) | 2,189.0 | ||||||||||||||
|
Property, plant, equipment and mine development
|
||||||||||||||||||||
|
Land and coal interests
|
— | 4,807.3 | 2,750.0 | — | 7,557.3 | |||||||||||||||
|
Buildings and improvements
|
— | 783.4 | 124.6 | — | 908.0 | |||||||||||||||
|
Machinery and equipment
|
— | 1,117.3 | 273.9 | — | 1,391.2 | |||||||||||||||
|
Less: accumulated depreciation, depletion and amortization
|
— | (2,096.6 | ) | (498.4 | ) | — | (2,595.0 | ) | ||||||||||||
|
Property, plant, equipment and mine development, net
|
— | 4,611.4 | 2,650.1 | — | 7,261.5 | |||||||||||||||
|
Deferred income taxes
|
124.0 | — | — | (124.0 | ) | — | ||||||||||||||
|
Investments and other assets
|
8,893.5 | 110.5 | 32.0 | (8,531.2 | ) | 504.8 | ||||||||||||||
|
Total assets
|
$ | 9,532.0 | $ | 5,110.1 | $ | 3,996.5 | $ | (8,683.3 | ) | $ | 9,955.3 | |||||||||
|
Liabilities and Stockholders’ Equity
|
||||||||||||||||||||
|
Current liabilities
|
||||||||||||||||||||
|
Current maturities of long-term debt
|
$ | — | $ | — | $ | 14.1 | $ | — | $ | 14.1 | ||||||||||
|
Payables to (receivables from) affiliates, net
|
1,937.2 | (1,975.9 | ) | 38.7 | — | — | ||||||||||||||
|
Liabilities from coal trading activities, net
|
— | 45.1 | 65.5 | — | 110.6 | |||||||||||||||
|
Deferred income taxes
|
— | — | 28.1 | (28.1 | ) | — | ||||||||||||||
|
Accounts payable and accrued expenses
|
106.6 | 661.7 | 419.4 | — | 1,187.7 | |||||||||||||||
|
Total current liabilities
|
2,043.8 | (1,269.1 | ) | 565.8 | (28.1 | ) | 1,312.4 | |||||||||||||
|
Long-term debt, less current maturities
|
2,635.4 | 0.1 | 102.7 | — | 2,738.2 | |||||||||||||||
|
Deferred income taxes
|
— | 173.3 | 249.8 | (124.0 | ) | 299.1 | ||||||||||||||
|
Notes payable to (receivables from) affiliates, net
|
1,032.5 | (1,035.0 | ) | 2.5 | — | — | ||||||||||||||
|
Other noncurrent liabilities
|
70.6 | 1,667.8 | 111.3 | — | 1,849.7 | |||||||||||||||
|
Total liabilities
|
5,782.3 | (462.9 | ) | 1,032.1 | (152.1 | ) | 6,199.4 | |||||||||||||
|
Peabody Energy Corporation’s stockholders’ equity
|
3,749.7 | 5,573.0 | 2,958.2 | (8,531.2 | ) | 3,749.7 | ||||||||||||||
|
Noncontrolling interests
|
— | — | 6.2 | — | 6.2 | |||||||||||||||
|
Total stockholders’ equity
|
3,749.7 | 5,573.0 | 2,964.4 | (8,531.2 | ) | 3,755.9 | ||||||||||||||
|
Total liabilities and stockholders’ equity
|
$ | 9,532.0 | $ | 5,110.1 | $ | 3,996.5 | $ | (8,683.3 | ) | $ | 9,955.3 | |||||||||
F-65
Table of Contents
PEABODY
ENERGY CORPORATION
SUPPLEMENTAL
CONSOLIDATED BALANCE SHEETS
| December 31, 2008 | ||||||||||||||||||||
|
Parent
|
Guarantor
|
Non-Guarantor
|
Reclassifications/
|
|||||||||||||||||
| Company | Subsidiaries | Subsidiaries | Eliminations | Consolidated | ||||||||||||||||
| (Dollars in millions) | ||||||||||||||||||||
|
Assets
|
||||||||||||||||||||
|
Current assets
|
||||||||||||||||||||
|
Cash and cash equivalents
|
$ | 161.2 | $ | 4.5 | $ | 284.0 | $ | — | $ | 449.7 | ||||||||||
|
Accounts receivable, net
|
0.6 | 4.8 | 376.8 | — | 382.2 | |||||||||||||||
|
Inventories
|
— | 173.7 | 102.5 | — | 276.2 | |||||||||||||||
|
Assets from coal trading activities, net
|
— | 226.2 | 436.6 | — | 662.8 | |||||||||||||||
|
Deferred income taxes
|
43.7 | 21.7 | — | (63.7 | ) | 1.7 | ||||||||||||||
|
Other current assets
|
51.0 | 77.8 | 69.9 | — | 198.7 | |||||||||||||||
|
Total current assets
|
256.5 | 508.7 | 1,269.8 | (63.7 | ) | 1,971.3 | ||||||||||||||
|
Property, plant, equipment and mine development
|
||||||||||||||||||||
|
Land and coal interests
|
— | 4,655.5 | 2,693.9 | — | 7,349.4 | |||||||||||||||
|
Buildings and improvements
|
— | 748.6 | 109.5 | — | 858.1 | |||||||||||||||
|
Machinery and equipment
|
— | 1,016.1 | 229.0 | — | 1,245.1 | |||||||||||||||
|
Less: accumulated depreciation,
|
||||||||||||||||||||
|
depletion and amortization
|
— | (1,806.7 | ) | (348.6 | ) | — | (2,155.3 | ) | ||||||||||||
|
Property, plant, equipment and mine development, net
|
— | 4,613.5 | 2,683.8 | — | 7,297.3 | |||||||||||||||
|
Deferred income taxes
|
191.3 | — | — | (191.3 | ) | — | ||||||||||||||
|
Investments and other assets
|
8,439.1 | 375.2 | 25.9 | (8,413.2 | ) | 427.0 | ||||||||||||||
|
Total assets
|
$ | 8,886.9 | $ | 5,497.4 | $ | 3,979.5 | $ | (8,668.2 | ) | $ | 9,695.6 | |||||||||
|
Liabilities and Stockholders’ Equity
|
||||||||||||||||||||
|
Current liabilities
|
||||||||||||||||||||
|
Current maturities of long-term debt
|
$ | — | $ | — | $ | 17.0 | $ | — | $ | 17.0 | ||||||||||
|
Payables to (receivables from) affiliates, net
|
1,610.5 | (1,632.7 | ) | 22.2 | — | — | ||||||||||||||
|
Liabilities from coal trading activities, net
|
— | 109.3 | 194.9 | — | 304.2 | |||||||||||||||
|
Deferred income taxes
|
— | — | 63.7 | (63.7 | ) | — | ||||||||||||||
|
Accounts payable and accrued expenses
|
376.7 | 725.9 | 432.4 | — | 1,535.0 | |||||||||||||||
|
Total current liabilities
|
1,987.2 | (797.5 | ) | 730.2 | (63.7 | ) | 1,856.2 | |||||||||||||
|
Long-term debt, less current maturities
|
2,640.4 | 0.2 | 136.0 | — | 2,776.6 | |||||||||||||||
|
Deferred income taxes
|
— | 20.1 | 192.0 | (191.3 | ) | 20.8 | ||||||||||||||
|
Notes payable to (receivables from) affiliates, net
|
819.2 | (819.2 | ) | — | — | — | ||||||||||||||
|
Other noncurrent liabilities
|
322.0 | 1,517.2 | 83.3 | — | 1,922.5 | |||||||||||||||
|
Total liabilities
|
5,768.8 | (79.2 | ) | 1,141.5 | (255.0 | ) | 6,576.1 | |||||||||||||
|
Peabody Energy Corporation’s stockholders’ equity
|
3,118.1 | 5,576.6 | 2,836.6 | (8,413.2 | ) | 3,118.1 | ||||||||||||||
|
Noncontrolling interests
|
— | — | 1.4 | — | 1.4 | |||||||||||||||
|
Total stockholders’ equity
|
3,118.1 | 5,576.6 | 2,838.0 | (8,413.2 | ) | 3,119.5 | ||||||||||||||
|
Total liabilities and stockholders’ equity
|
$ | 8,886.9 | $ | 5,497.4 | $ | 3,979.5 | $ | (8,668.2 | ) | $ | 9,695.6 | |||||||||
F-66
Table of Contents
PEABODY
ENERGY CORPORATION
SUPPLEMENTAL
CONSOLIDATED STATEMENTS OF CASH FLOWS
| Year Ended December 31, 2009 | ||||||||||||||||
|
Parent
|
Guarantor
|
Non-Guarantor
|
||||||||||||||
| Company | Subsidiaries | Subsidiaries | Consolidated | |||||||||||||
| (Dollars in millions) | ||||||||||||||||
|
Cash Flows From Operating Activities
|
||||||||||||||||
|
Net cash provided by (used in) continuing operations
|
$ | (215.9 | ) | $ | 792.7 | $ | 476.7 | $ | 1,053.5 | |||||||
|
Net cash provided by (used in) discontinued operations
|
7.4 | (5.3 | ) | (7.7 | ) | (5.6 | ) | |||||||||
|
Net cash provided by (used in) operating activities
|
(208.5 | ) | 787.4 | 469.0 | 1,047.9 | |||||||||||
|
Cash Flows From Investing Activities
|
||||||||||||||||
|
Additions to property, plant, equipment and
|
||||||||||||||||
|
mine development
|
— | (189.7 | ) | (70.9 | ) | (260.6 | ) | |||||||||
|
Investment in Prairie State Energy Campus
|
— | (56.8 | ) | — | (56.8 | ) | ||||||||||
|
Federal coal lease expenditures
|
— | (123.6 | ) | — | (123.6 | ) | ||||||||||
|
Proceeds from disposal of assets, net of notes receivable
|
— | 43.8 | 10.1 | 53.9 | ||||||||||||
|
Additions to advance mining royalties
|
— | (5.8 | ) | (0.3 | ) | (6.1 | ) | |||||||||
|
Investment in equity affiliates and joint ventures
|
— | (5.0 | ) | (10.0 | ) | (15.0 | ) | |||||||||
|
Net cash used in continuing operations
|
— | (337.1 | ) | (71.1 | ) | (408.2 | ) | |||||||||
|
Net cash provided by discontinued operations
|
— | — | 1.7 | 1.7 | ||||||||||||
|
Net cash used in investing activities
|
— | (337.1 | ) | (69.4 | ) | (406.5 | ) | |||||||||
|
Cash Flows From Financing Activities
|
||||||||||||||||
|
Payments of long-term debt
|
— | — | (37.1 | ) | (37.1 | ) | ||||||||||
|
Dividends paid
|
(66.8 | ) | — | — | (66.8 | ) | ||||||||||
|
Proceeds from stock options exercised
|
3.6 | — | — | 3.6 | ||||||||||||
|
Net proceeds from borrowings
|
— | — | 0.8 | 0.8 | ||||||||||||
|
Other, net
|
5.1 | — | (7.9 | ) | (2.8 | ) | ||||||||||
|
Transactions with affiliates, net
|
473.9 | (454.6 | ) | (19.3 | ) | — | ||||||||||
|
Net cash provided by (used in) financing activities
|
415.8 | (454.6 | ) | (63.5 | ) | (102.3 | ) | |||||||||
|
Net change in cash and cash equivalents
|
207.3 | (4.3 | ) | 336.1 | 539.1 | |||||||||||
|
Cash and cash equivalents at beginning of year
|
161.2 | 4.5 | 284.0 | 449.7 | ||||||||||||
|
Cash and cash equivalents at end of year
|
$ | 368.5 | $ | 0.2 | $ | 620.1 | $ | 988.8 | ||||||||
F-67
Table of Contents
PEABODY
ENERGY CORPORATION
SUPPLEMENTAL
CONSOLIDATED STATEMENTS OF CASH FLOWS
| Year Ended December 31, 2008 | ||||||||||||||||
|
Parent
|
Guarantor
|
Non-Guarantor
|
||||||||||||||
| Company | Subsidiaries | Subsidiaries | Consolidated | |||||||||||||
| (Dollars in millions) | ||||||||||||||||
|
Cash Flows From Operating Activities
|
||||||||||||||||
|
Net cash provided by continuing operations
|
$ | 17.7 | $ | 465.6 | $ | 926.5 | $ | 1,409.8 | ||||||||
|
Net cash used in discontinued operations
|
(94.5 | ) | (17.3 | ) | (11.2 | ) | (123.0 | ) | ||||||||
|
Net cash provided by (used in) operating activities
|
(76.8 | ) | 448.3 | 915.3 | 1,286.8 | |||||||||||
|
Cash Flows From Investing Activities
|
||||||||||||||||
|
Additions to property, plant, equipment and
|
||||||||||||||||
|
mine development
|
— | (198.0 | ) | (66.1 | ) | (264.1 | ) | |||||||||
|
Investment in Prairie State Energy Campus
|
— | (40.9 | ) | — | (40.9 | ) | ||||||||||
|
Federal coal lease expenditures
|
— | (178.5 | ) | — | (178.5 | ) | ||||||||||
|
Proceeds from disposal of assets, net of notes receivable
|
— | 72.3 | 0.5 | 72.8 | ||||||||||||
|
Additions to advance mining royalties
|
— | (5.7 | ) | (0.3 | ) | (6.0 | ) | |||||||||
|
Investments in equity affiliates and joint ventures
|
— | (2.6 | ) | — | (2.6 | ) | ||||||||||
|
Net cash used in continuing operations
|
— | (353.4 | ) | (65.9 | ) | (419.3 | ) | |||||||||
|
Net cash provided by (used in) discontinued operations
|
(0.4 | ) | 24.3 | 23.9 | ||||||||||||
|
Net cash used in investing activities
|
— | (353.8 | ) | (41.6 | ) | (395.4 | ) | |||||||||
|
Cash Flows From Financing Activities
|
||||||||||||||||
|
Change in revolving line of credit
|
(97.7 | ) | — | — | (97.7 | ) | ||||||||||
|
Payments of long-term debt
|
(18.8 | ) | — | (13.9 | ) | (32.7 | ) | |||||||||
|
Common stock repurchase
|
(199.8 | ) | — | — | (199.8 | ) | ||||||||||
|
Dividends paid
|
(64.9 | ) | — | — | (64.9 | ) | ||||||||||
|
Proceeds from stock options exercised
|
14.1 | — | — | 14.1 | ||||||||||||
|
Acquisition of noncontrolling interests (Millennium Mine)
|
— | — | (110.1 | ) | (110.1 | ) | ||||||||||
|
Other, net
|
5.2 | — | (1.1 | ) | 4.1 | |||||||||||
|
Transactions with affiliates, net
|
592.9 | (93.9 | ) | (499.0 | ) | — | ||||||||||
|
Net cash provided by (used in) financing activities
|
231.0 | (93.9 | ) | (624.1 | ) | (487.0 | ) | |||||||||
|
Net change in cash and cash equivalents
|
154.2 | 0.6 | 249.6 | 404.4 | ||||||||||||
|
Cash and cash equivalents at beginning of year
|
7.0 | 3.9 | 34.4 | 45.3 | ||||||||||||
|
Cash and cash equivalents at end of year
|
$ | 161.2 | $ | 4.5 | $ | 284.0 | $ | 449.7 | ||||||||
F-68
Table of Contents
PEABODY
ENERGY CORPORATION
SUPPLEMENTAL
CONSOLIDATED STATEMENTS OF CASH FLOWS
| Year Ended December 31, 2007 | ||||||||||||||||
|
Parent
|
Guarantor
|
Non-Guarantor
|
||||||||||||||
| Company | Subsidiaries | Subsidiaries | Consolidated | |||||||||||||
| (Dollars in millions) | ||||||||||||||||
|
Cash Flows From Operating Activities
|
||||||||||||||||
|
Net cash provided by (used in) continuing operations
|
$ | 1.6 | $ | 686.9 | $ | (227.8 | ) | $ | 460.7 | |||||||
|
Net cash used in discontinued operations
|
(25.5 | ) | (7.1 | ) | (108.7 | ) | (141.3 | ) | ||||||||
|
Net cash provided by (used in) operating activities
|
(23.9 | ) | 679.8 | (336.5 | ) | 319.4 | ||||||||||
|
Cash Flows From Investing Activities
|
||||||||||||||||
|
Additions to property, plant, equipment and mine development
|
(25.0 | ) | (244.3 | ) | (169.5 | ) | (438.8 | ) | ||||||||
|
Investment in Prairie State Energy Campus
|
— | (28.8 | ) | — | (28.8 | ) | ||||||||||
|
Federal coal lease expenditures
|
— | (178.2 | ) | — | (178.2 | ) | ||||||||||
|
Proceeds from disposal of assets, net of notes receivable
|
— | 118.3 | 1.3 | 119.6 | ||||||||||||
|
Additions to advance mining royalties
|
— | (8.1 | ) | — | (8.1 | ) | ||||||||||
|
Investments in equity affiliates and joint ventures
|
— | (4.6 | ) | — | (4.6 | ) | ||||||||||
|
Net cash used in continuing operations
|
(25.0 | ) | (345.7 | ) | (168.2 | ) | (538.9 | ) | ||||||||
|
Net cash used in discontinued operations
|
— | (1.8 | ) | (34.6 | ) | (36.4 | ) | |||||||||
|
Net cash used in investing activities
|
(25.0 | ) | (347.5 | ) | (202.8 | ) | (575.3 | ) | ||||||||
|
Cash Flows From Financing Activities
|
||||||||||||||||
|
Change in revolving line of credit
|
97.7 | — | — | 97.7 | ||||||||||||
|
Payments of long-term debt
|
(51.1 | ) | (60.9 | ) | (5.8 | ) | (117.8 | ) | ||||||||
|
Dividends paid
|
(63.7 | ) | — | — | (63.7 | ) | ||||||||||
|
Payment of debt issuance costs
|
— | (0.8 | ) | — | (0.8 | ) | ||||||||||
|
Excess tax benefit related to stock options exercised
|
96.7 | — | — | 96.7 | ||||||||||||
|
Proceeds from stock options exercised
|
26.2 | — | — | 26.2 | ||||||||||||
|
Other, net
|
6.4 | — | (3.0 | ) | 3.4 | |||||||||||
|
Transactions with affiliates, net
|
(261.5 | ) | (270.4 | ) | 531.9 | — | ||||||||||
|
Net cash provided by (used in) continuing operations
|
(149.3 | ) | (332.1 | ) | 523.1 | 41.7 | ||||||||||
|
Net cash used in discontinued operations
|
(67.0 | ) | — | — | (67.0 | ) | ||||||||||
|
Net cash provided by (used in) financing activities
|
(216.3 | ) | (332.1 | ) | 523.1 | (25.3 | ) | |||||||||
|
Net change in cash and cash equivalents
|
(265.2 | ) | 0.2 | (16.2 | ) | (281.2 | ) | |||||||||
|
Cash and cash equivalents at beginning of year
|
272.2 | 3.7 | 50.6 | 326.5 | ||||||||||||
|
Cash and cash equivalents at end of year
|
$ | 7.0 | $ | 3.9 | $ | 34.4 | $ | 45.3 | ||||||||
F-69
Table of Contents
REPORT OF
INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Directors and Stockholders
Peabody Energy Corporation
We have audited the consolidated financial statements of Peabody
Energy Corporation (the Company) as of December 31, 2009
and 2008, and for each of the three years in the period ended
December 31, 2009, and have issued our report thereon dated
February 24, 2010. Our audits also included the financial
statement schedule listed in Item 15(a). This schedule is
the responsibility of the Company’s management. Our
responsibility is to express an opinion based on our audits.
In our opinion, the financial statement schedule referred to
above, when considered in relation to the basic financial
statements taken as a whole, presents fairly in all material
respects the information set forth therein.
/s/ Ernst &
Young LLP
St. Louis, Missouri
February 24, 2010
F-70
Table of Contents
PEABODY
ENERGY CORPORATION
SCHEDULE II —
VALUATION AND QUALIFYING ACCOUNTS
|
Balance at
|
Charged to
|
Balance
|
||||||||||||||||||
|
Beginning
|
Costs and
|
at End
|
||||||||||||||||||
|
Description
|
of Period | Expenses | Deductions (1) | Other | of Period | |||||||||||||||
| (Dollars in millions) | ||||||||||||||||||||
|
Year ended December 31, 2009
|
||||||||||||||||||||
|
Reserves deducted from asset accounts:
|
||||||||||||||||||||
|
Advance royalty recoupment reserve
|
$ | 17.2 | $ | 1.6 | $ | (2.2 | ) | $ | 0.6 | (2) | $ | 17.2 | ||||||||
|
Reserve for materials and supplies
|
4.9 | 3.6 | (2.3 | ) | — | 6.2 | ||||||||||||||
|
Allowance for doubtful accounts
|
24.8 | 7.7 | (3.6 | ) | (10.6 | ) (3) | 18.3 | |||||||||||||
|
Year ended December 31, 2008
|
||||||||||||||||||||
|
Reserves deducted from asset accounts:
|
||||||||||||||||||||
|
Advance royalty recoupment reserve
|
$ | 13.6 | $ | 4.0 | $ | (3.0 | ) | $ | 2.6 | (2) | $ | 17.2 | ||||||||
|
Reserve for materials and supplies
|
4.3 | 1.7 | (1.1 | ) | — | 4.9 | ||||||||||||||
|
Allowance for doubtful accounts
|
11.9 | 13.9 | (1.0 | ) | — | 24.8 | ||||||||||||||
|
Year ended December 31, 2007
|
||||||||||||||||||||
|
Reserves deducted from asset accounts:
|
||||||||||||||||||||
|
Advance royalty recoupment reserve
|
$ | 12.0 | $ | — | $ | — | $ | 1.6 | (2) | $ | 13.6 | |||||||||
|
Reserve for materials and supplies
|
3.2 | 0.5 | (0.7 | ) | 1.3 | (2) | 4.3 | |||||||||||||
|
Allowance for doubtful accounts
|
10.9 | 1.1 | (0.1 | ) | — | 11.9 | ||||||||||||||
| (1) | Reserves utilized, unless otherwise indicated. | |
| (2) | Balances transferred (to) from other accounts or reserves recorded as part of a property transaction or acquisition. | |
| (3) | Reflects subsequent recovery of amounts previously reserved. |
F-71
Table of Contents
EXHIBIT INDEX
The exhibits below are numbered in accordance with the
Exhibit Table of Item 601 of
Regulation S-K.
|
Exhibit No.
|
Description of Exhibit
|
|||
| 2 | .1 | Merger Implementation Agreement, dated as of July 6, 2006, between the Registrant and Excel Coal Limited (Incorporated by reference to Exhibit 2.1 of the Registrant’s Current Report on Form 8-K, filed July 7, 2006). | ||
| 2 | .2 | Deed of Variation — Merger Implementation Agreement, dated as of September 18, 2006, between the Registrant and Excel Coal Limited (Incorporated by reference to Exhibit 2.2 of the Registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2006). | ||
| 3 | .1 | Third Amended and Restated Certificate of Incorporation of the Registrant, as amended (Incorporated by reference to Exhibit 3.1 of the Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2008). | ||
| 3 | .2 | Amended and Restated By-Laws of the Registrant (Incorporated by reference to Exhibit 3.1 of the Registrant’s Current Report on Form 8-K, filed September 16, 2008). | ||
| 4 | .1 | Rights Agreement, dated as of July 24, 2002, between the Registrant and EquiServe Trust Company, N.A., as Rights Agent (which includes the form of Certificate of Designations of Series A Junior Preferred Stock of the Registrant as Exhibit A, the form of Right Certificate as Exhibit B and the Summary of Rights to Purchase Preferred Shares as Exhibit C) (Incorporated herein by reference to Exhibit 4.1 to the Registrant’s Registration Statement on Form 8-A, filed July 24, 2002). | ||
| 4 | .2 | Certificate of Designations of Series A Junior Participating Preferred Stock of the Registrant, filed with the Secretary of State of the State of Delaware on July 24, 2002 (Incorporated herein by reference to Exhibit 3.1 to the Registrant’s Registration Statement on Form 8-A, filed July 24, 2002). | ||
| 4 | .3 | Certificate of Adjustment delivered by the Registrant to Equiserve Trust Company, N.A., as Rights Agent, on March 29, 2005 (Incorporated by reference to Exhibit 4.2 to Amendment No. 1 to the Registrant’s Registration Statement on Form 8-A/A, filed March 29, 2005). | ||
| 4 | .4 | Certificate of Adjustment delivered by the Registrant to American Stock Transfer & Trust Company, as Rights Agent, on February 22, 2006 (Incorporated by reference to Exhibit 4.2 to Amendment No. 2 to the Registrant’s Registration Statement on Form 8-A/A, filed February 22, 2006). | ||
| 4 | .5 | Specimen of stock certificate representing the Registrant’s common stock, $.01 par value (Incorporated by reference to Exhibit 4.13 to Amendment No. 4 to the Registrant’s Form S-1 Registration Statement No. 333-55412, filed May 1, 2001). | ||
| 4 | .6 | 6 7 / 8 % Senior Notes Due 2013 Indenture, dated as of March 21, 2003, between the Registrant and U.S. Bank National Association, as trustee (Incorporated by reference to Exhibit 4.27 of the Registrant’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2003). | ||
| 4 | .7 | 6 7 / 8 % Senior Notes Due 2013 First Supplemental Indenture, dated as of May 7, 2003, among the Registrant, the Guaranteeing Subsidiaries (as defined therein), and U.S. Bank National Association, as trustee (Incorporated by reference to Exhibit 4.3 of the Registrant’s Form S-4 Registration Statement No. 333-106208, filed June 17, 2006). | ||
| 4 | .8 | 6 7 / 8 % Senior Notes Due 2013 Second Supplemental Indenture, dated as of September 30, 2003, among the Registrant, the Guaranteeing Subsidiaries (as defined therein), and U.S. Bank National Association, as trustee (Incorporated by reference to Exhibit 4.198 of the Registrant’s Form S-3 Registration Statement No. 333-109906, filed October 22, 2003). | ||
| 4 | .9 | 6 7 / 8 % Senior Notes Due 2013 Third Supplemental Indenture, dated as of February 24, 2004, among the Registrant, the Guaranteeing Subsidiaries (as defined therein), and U.S. Bank National Association, as trustee (Incorporated by reference to Exhibit 4.211 to Amendment No. 1 to the Registrant’s Form S-3 Registration Statement No. 333-109906, filed March 4, 2004). | ||
| 4 | .10 | 6 7 / 8 % Senior Notes Due 2013 Fourth Supplemental Indenture, dated as of April 22, 2004, among the Registrant, the Guaranteeing Subsidiaries (as defined therein), and U.S. Bank National Association, as trustee (Incorporated by reference to Exhibit 10.57 of the Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2004). | ||
Table of Contents
|
Exhibit No.
|
Description of Exhibit
|
|||
| 4 | .11 | 6 7 / 8 % Senior Notes Due 2013 Fifth Supplemental Indenture, dated as of October 18, 2004, among the Registrant, the Guaranteeing Subsidiaries (as defined therein), and U.S. Bank National Association, as trustee (Incorporated by reference to Exhibit 4.9 of the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2004). | ||
| 4 | .12 | 6 7 / 8 % Senior Notes Due 2013 Sixth Supplemental Indenture, dated as of January 20, 2005, among the Registrant, the Guaranteeing Subsidiaries (as defined therein), and U.S. Bank National Association, as trustee (Incorporated by reference to Exhibit 4.1 of the Registrant’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2005). | ||
| 4 | .13 | 6 7 / 8 % Senior Notes Due 2013 Seventh Supplemental Indenture, dated as of September 30, 2005, among the Registrant, the Guaranteeing Subsidiaries (as defined therein), and U.S. Bank National Association, as trustee (as defined therein), and U.S. Bank National Association, as trustee (Incorporated by reference to Exhibit 4.1 of the Registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2005). | ||
| 4 | .14 | 6 7 / 8 % Senior Notes Due 2013 Eighth Supplemental Indenture, dated as of January 20, 2006, among the Registrant, the Guaranteeing Subsidiaries (as defined therein), and U.S. Bank National Association, as trustee (Incorporated by reference to Exhibit 4.14 of the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2005). | ||
| 4 | .15 | 6 7 / 8 % Senior Notes Due 2013 Ninth Supplemental Indenture, dated as of June 13, 2006, among the Registrant, the Guaranteeing Subsidiaries (as defined therein), and U.S. Bank National Association, as trustee (Incorporated by reference to Exhibit 4.1 of the Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2006). | ||
| 4 | .16 | 6 7 / 8 % Senior Notes Due 2013 Tenth Supplemental Indenture, dated as of June 30, 2006, among the Registrant, the Guaranteeing Subsidiaries (as defined therein), and U.S. Bank National Association, as trustee (Incorporated by reference to Exhibit 4.2 of the Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2006). | ||
| 4 | .17 | 6 7 / 8 % Senior Notes Due 2013 Eleventh Supplemental Indenture, dated as of September 29, 2006, among the Registrant, the Guaranteeing Subsidiaries (as defined therein), and U.S. Bank National Association, as trustee (Incorporated by reference to Exhibit 4.2 of the Registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2006). | ||
| 4 | .18 | 6 7 / 8 % Senior Notes Due 2013 Twelfth Supplemental Indenture, dated as of November 10, 2006, among the Registrant, the Guaranteeing Subsidiaries (as defined therein), and U.S. Bank National Association, as trustee. (Incorporated by reference to Exhibit 4.18 of the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2006). | ||
| 4 | .19 | 6 7 / 8 % Senior Notes Due 2013 Thirteenth Supplemental Indenture, dated as of January 31, 2007, among the Registrant, the Guaranteeing Subsidiaries (as defined therein), and U.S. Bank National Association, as trustee (Incorporated by reference to Exhibit 4.19 of the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2006). | ||
| 4 | .20 | 6 7 / 8 % Senior Notes Due 2013 Fourteenth Supplemental Indenture, dated as of June 14, 2007, among the Registrant, the Guaranteeing Subsidiaries (as defined therein), and U.S. Bank National Association, as trustee (Incorporated by reference to Exhibit 4.1 of the Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2007). | ||
| 4 | .21 | 6 7 / 8 % Senior Notes Due 2013 Fifteenth Supplemental Indenture, dated as of November 14, 2007, among the Registrant, the Guaranteeing Subsidiaries (as defined therein), and U.S. Bank National Association, as trustee (Incorporated by reference to Exhibit 4.21 of the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2007). | ||
| 4 | .22 | 6 7 / 8 % Senior Notes Due 2013 Eighteenth Supplemental Indenture, dated as of March 13, 2009, among the Registrant, the Guaranteeing Subsidiaries (as defined therein), and U.S. Bank National Association, as trustee (Incorporated by reference to Exhibit 4.4 of the Registrant’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2009). | ||
| 4 | .23 | 5 7 / 8 % Senior Notes Due 2016 Indenture, dated as of March 19, 2004, between the Registrant and U.S. Bank National Association, as trustee (Incorporated by reference to Exhibit 4.12 of the Registrant’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2004). | ||
| 4 | .24 | 5 7 / 8 % Senior Notes Due 2016 First Supplemental Indenture, dated as of March 23, 2004, between the Registrant and U.S. Bank National Association, as trustee (Incorporated by reference to Exhibit 4.1 of the Registrant’s Current Report on Form 8-K, filed March 25, 2004). | ||
Table of Contents
|
Exhibit No.
|
Description of Exhibit
|
|||
| 4 | .25 | 5 7 / 8 % Senior Notes Due 2016 Second Supplemental Indenture, dated as of April 22, 2004, among the Registrant, the Guaranteeing Subsidiaries (as defined therein), and U.S. Bank National Association, as trustee (Incorporated by reference to Exhibit 10.58 of the Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2004). | ||
| 4 | .26 | 5 7 / 8 % Senior Notes Due 2016 Third Supplemental Indenture, dated as of October 18, 2004, among the Registrant, the Guaranteeing Subsidiaries (as defined therein), and U.S. Bank National Association, as trustee (Incorporated by reference to Exhibit 4.13 of the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2004). | ||
| 4 | .27 | 5 7 / 8 % Senior Notes Due 2016 Fourth Supplemental Indenture, dated as of January 20, 2005, among the Registrant, the Guaranteeing Subsidiaries (as defined therein), and U.S. Bank National Association, as trustee (Incorporated by reference to Exhibit 4.2 of the Registrant’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2005). | ||
| 4 | .28 | 5 7 / 8 % Senior Notes Due 2016 Fifth Supplemental Indenture, dated as of September 30, 2005, among the Registrant, the Guaranteeing Subsidiaries (as defined therein), and U.S. Bank National Association, as trustee (Incorporated by reference to Exhibit 4.2 of the Registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2005). | ||
| 4 | .29 | 5 7 / 8 % Senior Notes Due 2016 Sixth Supplemental Indenture, dated as of January 20, 2006, among the Registrant, the Guaranteeing Subsidiaries (as defined therein), and U.S. Bank National Association, as trustee (Incorporated by reference to Exhibit 4.21 of the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2005). | ||
| 4 | .30 | 5 7 / 8 % Senior Notes Due 2016 Seventh Supplemental Indenture, dated as of June 13, 2006, among the Registrant, the Guaranteeing Subsidiaries (as defined therein), and U.S. Bank National Association, as trustee (Incorporated by reference to Exhibit 4.3 of the Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2006). | ||
| 4 | .31 | 5 7 / 8 % Senior Notes Due 2016 Eighth Supplemental Indenture, dated as of June 30, 2006, among the Registrant, the Guaranteeing Subsidiaries (as defined therein), and U.S. Bank National Association, as trustee (Incorporated by reference to Exhibit 4.4 of the Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2006). | ||
| 4 | .32 | 5 7 / 8 % Senior Notes Due 2016 Ninth Supplemental Indenture, dated as of September 29, 2006, among the Registrant, the Guaranteeing Subsidiaries (as defined therein), and U.S. Bank National Association, as trustee (Incorporated by reference to Exhibit 4.1 of the Registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2006). | ||
| 4 | .33 | 5 7 / 8 % Senior Notes Due 2016 Twelfth Supplemental Indenture, dated as of November 10, 2006, among the Registrant, the Guaranteeing Subsidiaries (as defined therein), and U.S. Bank National Association, as trustee. (Incorporated by reference to Exhibit 4.30 of the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2006). | ||
| 4 | .34 | 5 7 / 8 % Senior Notes Due 2016 Fifteenth Supplemental Indenture, dated as of January 31, 2007, among the Registrant, the Guaranteeing Subsidiaries (as defined therein), and U.S. Bank National Association, as trustee. (Incorporated by reference to Exhibit 4.31 of the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2006). | ||
| 4 | .35 | 5 7 / 8 % Senior Notes Due 2016 Eighteenth Supplemental Indenture, dated as of June 14, 2007, among the Registrant, the Guaranteeing Subsidiaries (as defined therein), and U.S. Bank National Association, as trustee (Incorporated by reference to Exhibit 4.2 of the Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2007). | ||
| 4 | .36 | 5 7 / 8 % Senior Notes Due 2016 Twenty-First Supplemental Indenture, dated as of November 14, 2007, among the Registrant, the Guaranteeing Subsidiaries (as defined therein), and U.S. Bank National Association, as trustee (Incorporated by reference to Exhibit 4.35 of the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2007). | ||
| 4 | .37 | 5 7 / 8 % Senior Notes Due 2016 Thirtieth Supplemental Indenture, dated as of March 13, 2009, among the Registrant, the Guaranteeing Subsidiaries (as defined therein), and U.S. Bank National Association, as trustee (Incorporated by reference to Exhibit 4.1 of the Registrant’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2009). | ||
Table of Contents
|
Exhibit No.
|
Description of Exhibit
|
|||
| 4 | .38 | 7 3 / 8 % Senior Notes Due 2016 Tenth Supplemental Indenture, dated as of October 12, 2006 among the Registrant, the Guaranteeing Subsidiaries (as defined therein), and U.S. Bank National Association, as trustee (Incorporated by reference to Exhibit 4.1 of the Registrant’s Current Report on Form 8-K, filed October 13, 2006). | ||
| 4 | .39 | 7 3 / 8 % Senior Notes Due 2016 Thirteenth Supplemental Indenture, dated as of November 10, 2006 among the Registrant, the Guaranteeing Subsidiaries (as defined therein), and U.S. Bank National Association, as trustee (Incorporated by reference to Exhibit 4.33 of the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2006). | ||
| 4 | .40 | 7 3 / 8 % Senior Notes Due 2016 Sixteenth Supplemental Indenture, dated as of January 31, 2007 among the Registrant, the Guaranteeing Subsidiaries (as defined therein), and U.S. Bank National Association, as trustee (Incorporated by reference to Exhibit 4.34 of the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2006). | ||
| 4 | .41 | 7 3 / 8 % Senior Notes Due 2016 Nineteenth Supplemental Indenture, dated as of June 14, 2007 among the Registrant, the Guaranteeing Subsidiaries (as defined therein), and U.S. Bank National Association, as trustee (Incorporated by reference to Exhibit 4.3 of the Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2007). | ||
| 4 | .42 | 7 3 / 8 % Senior Notes Due 2016 Thirty-First Supplemental Indenture, dated as of March 13, 2009, among the Registrant, the Guaranteeing Subsidiaries (as defined therein), and U.S. Bank National Association, as trustee (Incorporated by reference to Exhibit 4.2 of the Registrant’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2009). | ||
| 4 | .43 | 7 3 / 8 % Senior Notes Due 2016 Twenty-Second Supplemental Indenture, dated as of November 14, 2007 among the Registrant, the Guaranteeing Subsidiaries (as defined therein), and U.S. Bank National Association, as trustee (Incorporated by reference to Exhibit 4.40 of the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2007). | ||
| 4 | .44 | 7 7 / 8 % Senior Notes Due 2026 Eleventh Supplemental Indenture, dated as of October 12, 2006, among the Registrant, the Guaranteeing Subsidiaries (as defined therein), and U.S. Bank National Association, as trustee (Incorporated by reference to Exhibit 4.2 of the Registrant’s Current Report on Form 8-K, filed October 13, 2006). | ||
| 4 | .45 | 7 7 / 8 % Senior Notes Due 2026 Fourteenth Supplemental Indenture, dated as of November 10, 2006, among the Registrant, the Guaranteeing Subsidiaries (as defined therein), and U.S. Bank National Association, as trustee (Incorporated by reference to Exhibit 4.36 of the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2006). | ||
| 4 | .46 | 7 7 / 8 % Senior Notes Due 2026 Seventeenth Supplemental Indenture, dated as of January 31, 2007, among the Registrant, the Guaranteeing Subsidiaries (as defined therein), and U.S. Bank National Association, as trustee (Incorporated by reference to Exhibit 4.37 of the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2006). | ||
| 4 | .47 | 7 7 / 8 % Senior Notes Due 2026 Twentieth Supplemental Indenture, dated as of June 14, 2007, among the Registrant, the Guaranteeing Subsidiaries (as defined therein), and U.S. Bank National Association, as trustee (Incorporated by reference to Exhibit 4.4 of the Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2007). | ||
| 4 | .48 | 7 7 / 8 % Senior Notes Due 2026 Twenty-Third Supplemental Indenture, dated as of November 14, 2007, among the Registrant, the Guaranteeing Subsidiaries (as defined therein), and U.S. Bank National Association, as trustee (Incorporated by reference to Exhibit 4.45 of the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2007). | ||
| 4 | .49 | 7 7 / 8 % Senior Notes Due 2026 Thirty-Second Supplemental Indenture, dated as of March 13, 2009, among the Registrant, the Guaranteeing Subsidiaries (as defined therein), and U.S. Bank National Association, as trustee (Incorporated by reference to Exhibit 4.3 of the Registrant’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2009). | ||
| 4 | .50 | Subordinated Indenture, dated as of December 20, 2006, between the Registrant and U.S. Bank National Association, as trustee (Incorporated by reference to Exhibit 4.1 of the Registrant’s Current Report on Form 8-K, filed December 20, 2006). | ||
| 4 | .51 | 4.75% Convertible Junior Subordinated Debentures Due 2066 First Supplemental Indenture, dated as December 20, 2006, among the Registrant and U.S. Bank National Association, as trustee (Incorporated by reference to Exhibit 4.2 of the Registrant’s Current Report on Form 8-K, filed December 20, 2006). | ||
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| 4 | .52 | Capital Replacement Covenant dated December 19, 2006 (Incorporated by reference to Exhibit 99.1 of the Registrant’s Current Report on Form 8-K, filed December 20, 2006). | ||
| 4 | .53 | Notice of Adjustment of Conversion Rate of 4.75% Convertible Junior Subordinated Debentures Due 2066, dated November 26, 2007 (Incorporated by reference to Exhibit 4.49 of the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2007). | ||
| 4 | .54 | Notice of Adjustment of Conversion Rate of 4.75% Convertible Junior Subordinated Debentures Due 2066, dated February 8, 2009 (Incorporated by reference to Exhibit 4.5 of the Registrant’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2009). | ||
| 10 | .1 | Third Amended and Restated Credit Agreement, dated as of September 15, 2006, among the Registrant, Bank of America, N.A., as administrative agent, Citibank, N.A., as syndication agent, and the lenders named therein (Incorporated by reference to Exhibit 10.1 of the Registrant’s Current Report on Form 8-K, filed September 18, 2006). | ||
| 10 | .2 | Amendment No. 1 to Third Amended and Restated Credit Agreement, dated as of September 27, 2006, among the Registrant, the Lenders named therein, and Bank of America, N.A., as Administrative Agent (Incorporated by reference to Exhibit 10.3 of the Registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2006). | ||
| 10 | .3 | Amended and Restated Guarantee, dated as of September 15, 2006, among the Registrant and the Guarantors (as defined therein) in favor of Bank of America, N.A., as administrative agent under the Third Amended and Restated Credit Agreement dated as of September 15, 2006 (Incorporated by reference to Exhibit 10.2 of the Registrant’s Current Report on Form 8-K, filed September 18, 2006). | ||
| 10 | .4 | Federal Coal Lease WYW0321779: North Antelope/Rochelle Mine (Incorporated by reference to Exhibit 10.3 of the Registrant’s Form S-4 Registration Statement No. 333-59073). | ||
| 10 | .5 | Federal Coal Lease WYW119554: North Antelope/Rochelle Mine (Incorporated by reference to Exhibit 10.4 of the Registrant’s Form S-4 Registration Statement No. 333-59073, filed July 14, 1998). | ||
| 10 | .6 | Federal Coal Lease WYW5036: Rawhide Mine (Incorporated by reference to Exhibit 10.5 of the Registrant’s Form S-4 Registration Statement No. 333-59073, filed July 14, 1998). | ||
| 10 | .7 | Federal Coal Lease WYW3397: Caballo Mine (Incorporated by reference to Exhibit 10.6 of the Registrant’s Form S-4 Registration Statement No. 333-59073, filed July 14, 1998). | ||
| 10 | .8 | Federal Coal Lease WYW83394: Caballo Mine (Incorporated by reference to Exhibit 10.7 of the Registrant’s Form S-4 Registration Statement No. 333-59073, filed July 14, 1998). | ||
| 10 | .9 | Federal Coal Lease WYW136142 (Incorporated by reference to Exhibit 10.8 of Amendment No. 1 to the Registrant’s Form S-4 Registration Statement No. 333-59073, filed September 8, 1998). | ||
| 10 | .10 | Royalty Prepayment Agreement by and among Peabody Natural Resources Company, Gallo Finance Company and Chaco Energy Company, dated September 30, 1998 (Incorporated by reference to Exhibit 10.9 of the Registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 1998). | ||
| 10 | .11 | Federal Coal Lease WYW154001: North Antelope Rochelle South (Incorporated by reference to Exhibit 10.68 of the Registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2004). | ||
| 10 | .12 | Federal Coal Lease WYW150210: North Antelope Rochelle Mine (Incorporated by reference to Exhibit 10.8 of the Registrant’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2005). | ||
| 10 | .13 | Federal Coal Lease WYW151134 effective May 1, 2005: West Roundup (Incorporated by reference to Exhibit 10.1 of the Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2005). | ||
| 10 | .14 | Separation Agreement, Plan of Reorganization and Distribution, dated October 22, 2007, between the Registrant and Patriot Coal Corporation (Incorporated by reference to Exhibit 10.1 of the Registrant’s Current Report on Form 8-K, filed October 25, 2007). | ||
| 10 | .15 | Tax Separation Agreement, dated October 22, 2007, between the Registrant and Patriot Coal Corporation (Incorporated by reference to Exhibit 10.2 of the Registrant’s Current Report on Form 8-K, filed October 25, 2007). | ||
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| 10 | .16 | Coal Act Liabilities Assumption Agreement, dated October 22, 2007, among Patriot Coal Corporation, Peabody Holding Company, LLC and the Registrant (Incorporated by reference to Exhibit 10.3 of the Registrant’s Current Report on Form 8-K, filed October 25, 2007). | ||
| 10 | .17 | NBCWA Liabilities Assumption Agreement, dated October 22, 2007, among Patriot Coal Corporation, Peabody Holding Company, LLC, Peabody Coal Company, LLC and the Registrant (Incorporated by reference to Exhibit 10.4 of the Registrant’s Current Report on Form 8-K, filed October 25, 2007). | ||
| 10 | .18 | Salaried Employee Liabilities Assumption Agreement, dated October 22, 2007, among Patriot Coal Corporation, Peabody Holding Company, LLC, Peabody Coal Company, LLC and the Registrant (Incorporated by reference to Exhibit 10.5 of the Registrant’s Current Report on Form 8-K, filed October 25, 2007). | ||
| 10 | .19 | Coal Supply Agreement, dated October 22, 2007, between Patriot Coal Sales LLC and COALSALES II, LLC (Incorporated by reference to Exhibit 10.6 of the Registrant’s Current Report on Form 8-K, filed October 25, 2007). | ||
| 10 | .20* | 1998 Stock Purchase and Option Plan for Key Employees of the Registrant (Incorporated by reference to Exhibit 4.9 of the Registrant’s Form S-8 Registration Statement No. 333-105456, filed May 21, 2003). | ||
| 10 | .21* | Amendment to the 1998 Stock Purchase and Option Plan for Key Employees of the Registrant (Incorporated by reference to Exhibit 10.4 of the Registrant’s Current Report on Form 8-K, filed October 17, 2007). | ||
| 10 | .22* | Amendment No. 2 to the 1998 Stock Purchase and Option Plan for Key Employees of the Registrant (Incorporated by reference to Exhibit 10.2 of the Registrant’s Current Report on Form 8-K, filed December 11, 2007). | ||
| 10 | .23* | Form of Non-Qualified Stock Option Agreement under the Registrant’s 1998 Stock Purchase and Option Plan for Key Employees (Incorporated by reference to Exhibit 10.15 of the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2003). | ||
| 10 | .24* | Form of Amendment to Non-Qualified Stock Option Agreement under the Registrant’s 1998 Stock Purchase and Option Plan for Key Employees (Incorporated by reference to Exhibit 10.16 of the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2003). | ||
| 10 | .25* | Form of Amendment, dated as of June 15, 2004, to Non-Qualified Stock Option Agreement under the Registrant’s 1998 Stock Purchase and Option Plan for Key Employees (Incorporated by reference to Exhibit 10.65 of the Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2004). | ||
| 10 | .26* | Form of Incentive Stock Option Agreement under the Registrant’s 1998 Stock Purchase and Option Plan for Key Employees (Incorporated by reference to Exhibit 10.17 of the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2003). | ||
| 10 | .27* | Long-Term Equity Incentive Plan of the Registrant (Incorporated by reference to Exhibit 99.2 of the Registrant’s Form S-8 Registration Statement No. 333-61406, filed May 22, 2001). | ||
| 10 | .28* | Amendment to the Registrant’s 2001 Long-Term Equity Incentive Plan (Incorporated by reference to Exhibit 10.3 of the Registrant’s Current Report on Form 8-K, filed October 17, 2007). | ||
| 10 | .29* | The Registrant’s 2004 Long-Term Equity Incentive Plan (Incorporated by reference to Annex A to the Registrant’s Proxy Statement for the 2004 Annual Meeting of Stockholders, filed April 2, 2004). | ||
| 10 | .30* | Amendment No. 1 to the Registrant’s 2004 Long Term Equity Incentive Plan (Incorporated by reference to Exhibit 10.67 of the Registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2004). | ||
| 10 | .31* | Amendment No. 2 to the Registrant’s 2004 Long-Term Equity Incentive Plan (Incorporated by reference to Exhibit 10.1 of the Registrant’s Current Report on Form 8-K, filed October 17, 2007). | ||
| 10 | .32* | Amendment No. 3 to the Registrant’s 2004 Long-Term Equity Incentive Plan (Incorporated by reference to Exhibit 10.2 of the Registrant’s Current Report on Form 8-K, filed October 17, 2007). | ||
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| 10 | .33* | Amendment No. 4 to the Registrant’s 2004 Long-Term Equity Incentive Plan (Incorporated by reference to Exhibit 10.1 of the Registrant’s Current Report on Form 8-K, filed December 11, 2007). | ||
| 10 | .34* | Form of Non-Qualified Stock Option Agreement under the Registrant’s 2004 Long-Term Equity Incentive Plan (Incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K, filed January 7, 2005). | ||
| 10 | .35* | Form of Performance Units Agreement under the Registrant’s 2004 Long-Term Equity Incentive Plan (Incorporated by reference to Exhibit 10.2 of the Registrant’s Current Report on Form 8-K, filed January 7, 2005). | ||
| 10 | .36* | Form of Performance Units Agreement under the Registrant’s 2004 Long-Term Equity Incentive Plan. (Incorporated by reference to Exhibit 10.36 of the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2007). | ||
| 10 | .37* | Equity Incentive Plan for Non-Employee Directors of the Registrant (Incorporated by reference to Exhibit 99.3 of the Registrant’s Form S-8 Registration Statement No. 333-61406, filed May 22, 2001). | ||
| 10 | .38* | Form of Non-Qualified Stock Option Agreement for Outside Directors under the Registrant’s Long-Term Equity Incentive Plan (Incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K, filed December 14, 2005). | ||
| 10 | .39* | Form of Non-Qualified Stock Option Agreement under the Registrant’s Long-Term Equity Incentive Plan (Incorporated by reference to Exhibit 10.18 of the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2003). | ||
| 10 | .40* | Form of Performance Unit Award Agreement under the Registrant’s Long-Term Equity Incentive Plan (Incorporated by reference to Exhibit 10.19 of the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2003). | ||
| 10 | .41* | Form of Non-Qualified Stock Option Agreement under the Registrant’s Equity Incentive Plan for Non-Employee Directors (Incorporated by reference to Exhibit 10.20 of the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2003). | ||
| 10 | .42* | Form of Restricted Stock Agreement under the Registrant’s Equity Incentive Plan for Non-Employee Directors (Incorporated by reference to Exhibit 10.21 of the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2003). | ||
| 10 | .43* | Form of Restricted Stock Award Agreement for Outside Directors under the Registrant’s Long-Term Equity Incentive Plan (Incorporated by reference to Exhibit 10.2 to the Registrant’s Current Report on Form 8-K, filed December 14, 2005). | ||
| 10 | .44* | Form of Performance Unit Award Agreement under the Registrant’s 2004 Long-Term Equity Incentive Plan (Incorporated by reference to Exhibit 10.2 of the Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2009). | ||
| 10 | .45*† | 2009 Amendment entered into effective December 31, 2009 to the Stock Grant Agreement dated as of October 1, 2003 between the Registrant and Gregory H. Boyce. | ||
| 10 | .46*† | 2009 Amendment entered into effective December 31, 2009 to the Non-Qualified Stock Option Agreement dated January 2, 2008 between the Registrant and Gregory H. Boyce. | ||
| 10 | .47*† | 2009 Amendment entered into effective December 31, 2009 to the Non-Qualified Stock Option Agreement dated January 5, 2009 between the Registrant and Gregory H. Boyce. | ||
| 10 | .48*† | 2009 Amendment entered into effective December 31, 2009 to the Performance Units Agreement dated January 2, 2008 between the Registrant and Gregory H. Boyce. | ||
| 10 | .49*† | 2009 Amendment entered into effective December 31, 2009 to the Performance Units Agreement dated January 5, 2009 between the Registrant and Gregory H. Boyce. | ||
| 10 | .50* | Amended and Restated Employee Stock Purchase Plan of the Registrant (Incorporated by reference to Exhibit 10.44 of the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2008). | ||
| 10 | .51*† | Amendment to the Amended and Restated Employee Stock Purchase Plan of the Registrant. | ||
| 10 | .52* | Amended and Restated Australian Employee Stock Purchase Plan of the Registrant (Incorporated by reference to Exhibit 10.45 of the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2008). | ||
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| 10 | .53*† | Amendment to the Amended and Restated Australian Employee Stock Purchase Plan of the Registrant. | ||
| 10 | .54* | Management Annual Incentive Compensation Plan (Incorporated by reference to Exhibit 10.61 of the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2007). | ||
| 10 | .55* | 2008 Management Annual Incentive Compensation Plan (Incorporated by reference to Appendix B to the Registrant’s Proxy Statement for the 2008 Annual Meeting of Shareholders, filed March 27, 2008). | ||
| 10 | .56* | The Registrant’s Deferred Compensation Plan (Incorporated by reference to Exhibit 10.30 of the Registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2001). | ||
| 10 | .57* | First Amendment to the Registrant’s Deferred Compensation Plan (Incorporated by reference to Exhibit 10.49 of the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2004). | ||
| 10 | .58* | Letter Agreement, dated as of March 1, 2005, by and between the Registrant and Gregory H. Boyce (Incorporated by reference to Exhibit 10.1 of the Registrant’s Current Report on Form 8-K, filed March 4, 2005). | ||
| 10 | .59* | Restated Employment Agreement effective December 31, 2009 by and between the Registrant and Gregory H. Boyce (Incorporated by reference to Exhibit 10.1 of the Registrant’s Current Report on Form 8-K, filed December 24, 2009). | ||
| 10 | .60* | Restated Employment Agreement entered into as of December 31, 2008 by and between the Registrant and Richard A. Navarre (Incorporated by reference to Exhibit 10.2 of the Registrant’s Current Report on Form 8-K, filed December 31, 2008). | ||
| 10 | .61* | Employment Agreement entered into as of December 31, 2008 by and between the Registrant and Michael C. Crews (Incorporated by reference to Exhibit 10.3 of the Registrant’s Current Report on Form 8-K, filed December 31, 2008). | ||
| 10 | .62* | Restated Employment Agreement entered into as of December 31, 2008 by and between the Registrant and Sharon D. Fiehler (Incorporated by reference to Exhibit 10.4 of the Registrant’s Current Report on Form 8-K, filed December 31, 2008). | ||
| 10 | .63* | Letter Agreement, dated as of December 22, 2006, by and between the Registrant and Eric Ford (Incorporated by reference to Exhibit 10.1 of the Registrant’s Current Report on Form 8-K, filed December 29, 2006). | ||
| 10 | .64* | Form of Restricted Stock Agreement — Exhibit A (Incorporated by reference to Exhibit 10.3 of the Registrant’s Current Report on Form 8-K, filed December 29, 2006). | ||
| 10 | .65* | Form of Restricted Stock Agreement — Exhibit B (Incorporated by reference to Exhibit 10.4 of the Registrant’s Current Report on Form 8-K, filed December 29, 2006). | ||
| 10 | .66* | Restated Employment Agreement entered into as of December 31, 2008 by and between the Registrant and Eric Ford (Incorporated by reference to Exhibit 10.5 of the Registrant’s Current Report on Form 8-K, filed December 31, 2008). | ||
| 10 | .67* | Restated Employment Agreement entered into as of December 31, 2008 by and between the Registrant and Alexander C. Schoch (Incorporated by Reference to Exhibit 10.59 of the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2008). | ||
| 10 | .68* | Indemnification Agreement, dated as of December 5, 2002, by and between Registrant and William E. James (Incorporated by reference to Exhibit 10.34 of the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2002). | ||
| 10 | .69* | Indemnification Agreement dated as of December 5, 2002, by and between Registrant and Henry E. Lentz (Incorporated by reference to Exhibit 10.35 of the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2002). | ||
| 10 | .70* | Indemnification Agreement dated as of December 5, 2002, by and between Registrant and William C. Rusnack (Incorporated by reference to Exhibit 10.36 of the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2002). | ||
| 10 | .71* | Indemnification Agreement dated as of December 5, 2002, by and between Registrant and Alan H. Washkowitz (Incorporated by reference to Exhibit 10.39 of the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2002). | ||
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| 10 | .72* | Indemnification Agreement dated as of December 5, 2002, by and between Registrant and Richard A. Navarre (Incorporated by reference to Exhibit 10.40 of the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2002). | ||
| 10 | .73* | Indemnification Agreement dated as of January 16, 2003, by and between Registrant and Robert B. Karn III (Incorporated by reference to Exhibit 10.41 of the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2002). | ||
| 10 | .74* | Indemnification Agreement dated as of January 16, 2003, by and between Registrant and Sandra A. Van Trease (Incorporated by reference to Exhibit 10.42 of the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2002). | ||
| 10 | .75* | Indemnification Agreement dated as of March 22, 2004, by and between Registrant and William A. Coley (Incorporated by reference to Exhibit 10.53 of the Registrant’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2004). | ||
| 10 | .76* | Indemnification Agreement dated as of April 8, 2005, by and between the Registrant and Gregory H. Boyce (Incorporated by reference to Exhibit 10.1 of the Registrant’s Current Report on Form 8-K, filed April 14, 2005). | ||
| 10 | .77* | Indemnification Agreement dated July 21, 2005, by and between the Registrant and John F. Turner (Incorporated by reference to Exhibit 10.1 of the Registrant’s Current Report on Form 8-K, filed August 5, 2005). | ||
| 10 | .78* | Indemnification Agreement dated as of March 2, 2009 by and between the Registrant and M. Frances Keeth (Incorporated by reference to Exhibit 10.1 of the Registrant’s Current Report on Form 8-K filed on March 2, 2009). | ||
| 10 | .79* | Indemnification Agreement dated as of July 23, 2009 by and between Peabody Energy Corporation and Robert A. Malone (Incorporated by reference to Exhibit 10.1 of the Registrant’s Current Report on Form 8-K filed on July 23, 2009). | ||
| 10 | .80* | Indemnification Agreement dated as of June 19, 2008, by and between the Registrant and Michael C. Crews (Incorporated by reference to Exhibit 10.1 of the Registrant’s Current Report on Form 8-K, filed July 29, 2008). | ||
| 10 | .81* | Indemnification Agreement dated as of October 22, 2008, by and between the Registrant and Sharon D. Fiehler (Incorporated by reference to Exhibit 10.72 of the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2008). | ||
| 10 | .82* | Indemnification Agreement dated as of October 22, 2008, by and between the Registrant and Eric Ford (Incorporated by reference to Exhibit 10.73 of the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2008). | ||
| 10 | .83* | Indemnification Agreement dated as of October 22, 2008, by and between the Registrant and Alexander C. Schoch (Incorporated by reference to Exhibit 10.74 of the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2008). | ||
| 10 | .84* | Peabody Investments Corp. Supplemental Employee Retirement Account (Incorporated by reference to Exhibit 10.1 of the Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2007). | ||
| 10 | .85 | Second Amended and Restated Receivables Purchase Agreement, dated as of December 15, 2009, by and among P&L Receivables Company, LLC, Peabody Energy Corporation, the various Sub-Servicers listed on the signature pages thereto, Market Street Funding LLC, as Issuer, all LC Participants listed on the signature pages thereto, and PNC Bank, National Association, as Administrator and as LC Bank (Incorporated by reference to Exhibit 10.1 of the Registrant’s Current Report on Form 8-K filed on December 21, 2009). | ||
| 21 | † | List of Subsidiaries. | ||
| 23 | † | Consent of Ernst & Young LLP, Independent Registered Public Accounting Firm. | ||
| 31 | .1† | Certification of periodic financial report by the Registrant’s Chief Executive Officer pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934, as amended pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. | ||
| 31 | .2† | Certification of periodic financial report by the Registrant’s Chief Financial Officer pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934, as amended pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. | ||
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| 32 | .1† | Certification of periodic financial report pursuant to 18 U.S.C. Section 1350, adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, by the Registrant’s Chief Executive Officer. | ||
| 32 | .2† | Certification of periodic financial report pursuant to 18 U.S.C. Section 1350, adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, by the Registrant’s Chief Financial Officer. | ||
| 101† | Interactive Data File (Form 10-K for the year ended December 31, 2009 furnished in XBRL). Users of this data are advised in accordance with Rule 406T of Regulation S-T promulgated by the Securities and Exchange Commission that this Interactive Data File is deemed not filed or part of a registration statement or prospectus for purposes of sections 11 or 12 of the Securities Act of 1933, is deemed not filed for purposes of section 18 of the Securities Exchange Act of 1934, and otherwise is not subject to liability under these sections. The financial information contained in the XBRL-related documents is “unaudited” and “unreviewed.” | |||
| * | These exhibits constitute all management contracts, compensatory plans and arrangements required to be filed as an exhibit to this form pursuant to Item 15(a)(3) and 15(b) of this report. | |
| † | Filed herewith. |
TABLE OF CONTENTS
Part IItem 1. BusinessItem 1A. Risk FactorsItem 1B. Unresolved Staff CommentsItem 2. PropertiesItem 3. Legal ProceedingsItem 4. Submission Of Matters To A Vote Of Security HoldersPart IIItem 5. Market For Registrant S Common Equity, Related Stockholder Matters and Issuer Purchases Of Equity SecuritiesItem 6. Selected Financial DataItem 7. Management S Discussion and Analysis Of Financial Condition and Results Of OperationsItem 7A. Quantitative and Qualitative Disclosures About Market RiskItem 8. Financial Statements and Supplementary DataItem 9. Changes in and Disagreements with Accountants on Accounting and Financial DisclosureItem 9A. Controls and ProceduresItem 9B. Other InformationPart IIIItem 10. Directors, Executive Officers and Corporate GovernanceItem 11. Executive CompensationItem 12. Security Ownership Of Certain Beneficial Owners and Management and Related Stockholder MattersItem 13. Certain Relationships and Related Transactions, and Director IndependenceItem 14. Principal Accounting Fees and ServicesPart IVItem 15. Exhibit, Financial Statement Schedules