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, 2010 | ||
|
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.
o
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, 2010: Common Stock, par value $0.01 per share,
$10.5 billion.
Number of shares outstanding of each of the Registrant’s
classes of Common Stock, as of February 11, 2011: Common
Stock, par value $0.01 per share, 270,560,221 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 2011 Annual Meeting of Shareholders (the
Company’s 2011 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 the United States (U.S.) and the Pacific Rim thermal and metallurgical coal seaborne markets; | |
| • | price volatility and demand, particularly in higher-margin products and in our trading and brokerage businesses; | |
| • | impact of weather on demand, production and transportation; | |
| • | reductions and/or deferrals of purchases by major customers and ability to renew sales contracts; | |
| • | credit and performance risks associated with customers, suppliers, co-shippers, and 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; | |
| • | 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 their related funding requirements; | |
| • | replacement and development of coal reserves; | |
| • | availability, access to and the related cost of capital and financial markets; | |
| • | 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 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 the 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 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.
We were incorporated in Delaware in 2001 and our history in the
coal mining business dates back to 1883. Over the past decade,
we have continually adjusted our business to focus on the
highest-growth regions in the U.S. and Asia-Pacific
markets. As part of this transformation, we have made strategic
acquisitions and divestitures in Australia and the
U.S. After re-entering the Australian market in 2002, we
expanded our presence there with acquisitions in 2004 and 2006.
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). We have also
continued to expand our Trading and Brokerage operations and now
have a global trading platform with offices in the U.S., Europe,
Australia and Asia.
Our future plans include advancing multiple organic growth
projects in Australia and the U.S. that involve new mines,
as well as the expansion and extension of existing mines. We
also have a number of initiatives underway to expand our
presence in the Asia-Pacific region, some of which include
sourcing coal to be sold through our Trading and Brokerage
segment and partnering with other companies to utilize our
mining experience for joint mine development.
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 technologies, including carbon capture and storage. |
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. Our operating segments are discussed in more detail
below with financial information contained in Note 22 to
our consolidated financial statements.
Mining
Segments
Our Western U.S. Mining operations consist of our Powder
River Basin, Southwest and Colorado mines, and our Midwestern
U.S. Mining operations consist of our Illinois and Indiana
mines. 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, 2010. Also noted are the primary ports
utilized in the U.S. and in Australia for our coal exports
and our corporate headquarters.
U.S.
Mining Operations
Australian
Mining Operations
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 2010. The
mines are sorted by tons sold within each mining segment.
|
2010
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||||||||||||||
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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 | Location | Type | Method | Type | Method | (In millions) | ||||||||
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Western U.S. Mining
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North Antelope Rochelle
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Wright, WY | S | DL, T/S | Thermal | R | 105.8 | ||||||||
|
Caballo
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Gillette, WY | S | D, T/S | Thermal | R | 23.5 | ||||||||
|
Rawhide
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Gillette, WY | S | D, T/S | Thermal | R | 11.3 | ||||||||
|
Twentymile
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Oak Creek, CO | U | LW | Thermal | R, T | 7.1 | ||||||||
|
Kayenta
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Kayenta, AZ | S | DL, T/S | Thermal | R | 7.8 | ||||||||
|
El Segundo
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Grants, NM | S | T/S | Thermal | R | 6.6 | ||||||||
|
Lee Ranch
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Grants, NM | S | DL, T/S | Thermal | R | 1.7 | ||||||||
|
Midwestern U.S. Mining
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||||||||||||||
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Somerville Central
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Oakland City, IN | S | DL, D, T/S | Thermal | R, T/R, T/B | 3.3 | ||||||||
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Viking — Corning Pit
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Cannelburg, IN | S | D, T/S | Thermal | T, T/R | 3.2 | ||||||||
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Gateway
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Coulterville, IL | U | CM | Thermal | T, R, R/B | 3.0 | ||||||||
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Willow Lake
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Equality, IL | U | CM | Thermal | T/B | 2.9 | ||||||||
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Bear Run
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Sullivan County, IN | S | DL, D, T/S | Thermal | T, R | 2.8 | ||||||||
|
Francisco Underground
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Francisco, IN | U | CM | Thermal | R | 2.7 | ||||||||
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Cottage Grove
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Equality, IL | S | D, T/S | Thermal | T/B | 2.1 | ||||||||
|
Somerville
North
(1)
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Oakland City, IN | S | D, T/S | Thermal | R, T/R, T/B | 2.0 | ||||||||
|
Somerville
South
(1)
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Oakland City, IN | S | D, T/S | Thermal | R, T/R, T/B | 1.7 | ||||||||
|
Air Quality
|
Vincennes, IN | U | CM | Thermal | T, T/R, T/B | 1.1 | ||||||||
|
Wildcat Hills Underground
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Eldorado, IL | U | CM | Thermal | T/B | 0.7 | ||||||||
|
Wild Boar
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Lynville, IN | S | D, T/S | Thermal | T, R, R/B | 0.1 | ||||||||
|
Other
(2)
|
— | — | — | — | — | 4.1 | ||||||||
|
Australian Mining
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||||||||||||||
|
Wilpinjong*
|
Wilpinjong, New South Wales | S | T/S | Thermal | R, EV | 9.2 | ||||||||
|
North Wambo
Underground
(1)
|
Warkworth, New South Wales | U | LW | Thermal/Met** | R, EV | 3.6 | ||||||||
|
Wambo
Open-Cut
(1)*
|
Warkworth, New South Wales | S | T/S | Thermal | R, EV | 3.0 | ||||||||
|
Burton*
(3)
|
Glenden, Queensland | S | T/S | Thermal/Met** | R, EV | 2.6 | ||||||||
|
North Goonyella
|
Glenden, Queensland | U | LW | Met** | R, EV | 2.5 | ||||||||
|
Wilkie Creek
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Macalister, Queensland | S | T/S | Thermal | R, EV | 1.7 | ||||||||
|
Metropolitan
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Helensburgh, New South Wales | U | LW | Met** | R, EV | 1.7 | ||||||||
|
Millennium*
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Moranbah, Queensland | S | T/S | Met** | R, EV | 1.6 | ||||||||
|
Eaglefield*
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Glenden, Queensland | S | T/S | Met** | R, EV | 1.1 | ||||||||
|
Legend:
|
||||||
|
S
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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 coals range from pulverized coal injection (PCI) to high quality hard coking coal on the heat value scale. |
| (1) | Represents mines that have non-controlling ownership interests. | |
| (2) | “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 2010. | |
| (3) | 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.
Our primary trading offices are in St. Louis, Missouri,
London, England, Newcastle, Australia and Singapore. We also
have sales, marketing and business development offices in
Beijing, China and Jakarta, Indonesia 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 14.1 million tons of throughput in
2010. 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 own a 17.7% interest in the Newcastle Coal Infrastructure
Group (NCIG), a coal transloading facility in Newcastle,
Australia. The total loading capacity for stage one is
33 million tons per year, of which our share is
5.8 millions tons. In 2010, stage one of construction was
substantially completed and operations commenced. NCIG is
currently operating at a reduced rate as part of its
ramp-up
to
full capability, which is anticipated to occur by late 2011.
Phase one of stage two construction has been approved and is
under way. When complete, it is expected to provide us with
approximately 2 million tons of additional annual
throughput capacity beginning in mid-2012.
We are currently investigating the potential for a west coast
port which will allow us to export Powder River Basin coal to
Asian markets.
Generation Development and Btu Conversion.
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. We are 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 facility is scheduled to
begin generating electricity in 2011. We currently expect to
market and sell our share of electricity generated by the
facility.
Btu Conversion involves 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 pursuing a project with
the government of Inner Mongolia and other Chinese partners to
explore development
5
Table of Contents
opportunities for a large surface mine and downstream coal
gasification facility that would produce methanol, chemicals or
fuel products.
Clean Coal Technology.
We continue to support
clean coal technology development and other “green
coal” initiatives seeking to reduce global atmospheric
levels of carbon dioxide and other emissions. We are the only
non-Chinese equity partner in GreenGen, which is constructing a
near-zero emissions coal-fueled power plant with carbon capture
and storage (CCS) near Tianjin, China. The first phase of
GreenGen operations is expected to be online in 2011. In
Australia, we made a
10-year
commitment to the Australian COAL21 Fund designed to support
clean coal technology demonstration projects and research in
Australia.
We are also a founding member of the Global Carbon Capture and
Storage Institute, an international initiative to accelerate
commercialization of CCS technologies through development of 20
integrated, industrial-scale demonstration projects, as well as
a participant 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 2010, we acquired an equity interest in Calera Corp., which
is developing proprietary technology that converts captured
carbon dioxide into building materials.
In the U.S., The Domenici-Barton Energy Policy Act of 2005
contained tax incentives and directed spending totaling an
estimated $14.1 billion intended to stimulate
U.S. supply-side energy growth and increased efficiency,
including a coal-related package estimated at nearly
$3 billion.
Clean coal technology development in the U.S. is being
accelerated by the American Recovery and Reinvestment Act of
2009, which targeted $3.4 billion for a 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.
Mongolia Joint Venture.
In 2009, we acquired a
50% interest in a joint venture with Polo Resources Limited
(Polo), which holds coal and mineral interests in Mongolia. In
2010, Winsway Coking Coal Holdings Ltd. (Winsway) purchased the
50% interest in the joint venture formerly owned by Polo and we
entered into a joint venture agreement with Winsway, creating
Peabody-Winsway Resources B.V. The joint venture is in the
development stage and plans to ship metallurgical and thermal
coal to Asian markets once developed. Winsway is one of the
leading suppliers in China of imported high-quality coking coal.
It distributes and transports coal from Mongolia and other
countries into China through its integrated service platform
which includes logistics parks, coal washing plants, and road
and railway transportation capabilities along the coast, rivers
and inland borders of China, including Inner Mongolia.
Paso Diablo Mine.
We own a 48.37% interest in
Carbones del Guasare S.A., which operates the Paso Diablo Mine,
a surface operation in northwestern Venezuela that produces
thermal coal for export primarily to the U.S. and Europe.
We began 2010 with a 25.5% ownership interest in the joint
venture. During 2010, we acquired Anglo American plc’s
25.5% ownership interest in the joint venture and transferred 2%
of our ownership interest to Carbones del Zulia S.A. as part of
the acquisition. 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.
Captive Insurance Entity.
A portion of our
insurance risks associated with workers’ compensation,
general liability and auto liability coverage is self-insured
through a wholly-owned captive insurance company.
6
Table of Contents
The captive entity invoices certain of our subsidiaries for the
premiums on these policies, pays the related claims, maintains
reserves for anticipated losses and invests funds to pay future
claims.
Coal
Supply Agreements
Our coal supply agreements are primarily with electricity
generators, industrial facilities and steel manufacturers. Most
of our sales (excluding trading transactions) are made under
long-term coal supply agreements (those with terms longer than
one year). Sales under such agreements comprised approximately
91%, 93% and 90% of our worldwide sales (by volume) for the
years ended December 31, 2010, 2009 and 2008, respectively.
For the year ended December 31, 2010, we derived 25% of our
total coal sales revenues from our five largest customers. Those
five customers were supplied primarily from 37 coal supply
agreements (excluding trading transactions) expiring at various
times from 2011 to 2016. The contract contributing the greatest
amount of annual revenue in 2010 was approximately
$279 million, or approximately 4% of our 2010 total revenue
base.
Our sales backlog includes coal supply agreements subject to
price reopener
and/or
extension provisions. As of January 31, 2011 and 2010, we
had a sales backlog of over 1 billion tons of coal.
Contracts in backlog have remaining terms ranging from one to
16 years, representing over four years of production based
on our 2010 production of 218.4 million tons. As of
January 31, 2011, approximately 78% of our backlog is
expected to be filled beyond one year.
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 Australian coal mining
activities accounted for 12% of our mining operations sales
volume in 2010 and 10% in 2009 and 2008. Our production is sold
primarily into the export metallurgical and thermal markets.
Historically, we predominately entered into multi-year
international coal agreements that contained provisions allowing
either party to commence a renegotiation of the agreement price
annually in the second quarter of each year. Current industry
practice, and our practice, is to negotiate pricing for
metallurgical coal contracts quarterly and seaborne thermal coal
contracts annually.
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). Demurrage continues to be
part of the shipping costs for our Australian exports as certain
ports continue to experience vessel queues due to factors such
as lower than expected rail performance, supply constraints,
adverse weather and delays in coal availability from
time-to-time
with those with whom we share vessels (co-shippers).
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.
One of our primary ports in the U.S. for exporting
metallurgical and thermal coal is through the Dominion Terminal
Associates coal terminal in Newport News, Virginia. In
Australia, our primary ports in Queensland through which we
export both metallurgical and thermal coal are the Dalrymple Bay
and Brisbane
7
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coal terminals. In New South Wales, our primary ports for
exporting metallurgical and thermal coal are at Port Kembla and
Newcastle, which includes the terminal operated by NCIG that
opened in 2010.
Suppliers
The main types of goods we purchase in support of our mining
activities are mining equipment and replacement parts, diesel
fuel, ammonium-nitrate and emulsion-based explosives,
off-the-road
(OTR) tires, steel-related (including roof control materials)
products, lubricants and electricity. For some of these goods,
there has been some consolidation in the supplier base providing
mining materials to the coal industry, such as with suppliers of
explosives and both surface and underground equipment, that has
limited the number of sources for these materials. In situations
where we have chosen to concentrate a large portion of purchases
with one supplier, it has been to take advantage of cost savings
from larger volumes of purchases and to ensure security of
supply. We have many well-established, strategic relationships
with our key suppliers of goods and do not believe we are
dependent on any of our individual suppliers.
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 due to the strategic and contractual
relationships we have with these suppliers.
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 and
explosive service providers. We do not believe that we are
dependent on any of our individual service providers.
Technical
Innovation
We continue to emphasize the application of technical innovation
to improve new and existing equipment performance. This effort
is typically undertaken and funded by equipment manufacturers
with our engineering, maintenance and purchasing personnel
providing input and expertise to the manufacturers that will
design and produce equipment that we believe will add value to
the business.
Since 2009 we have been upgrading 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. This effort continued in 2010 with
the commissioning of new shovels and ultra class haul trucks.
Our engineers continue to work with several major equipment
vendors to develop designs for in-pit crushing and conveying
systems to displace trucks and dozers to move large quantities
of overburden at a reduced cost and in a more environmentally
friendly manner. We are in the process of commissioning the
“Landmark” longwall automation technology at our North
Wambo Underground Mine and working with longwall original
equipment manufacturers to incorporate similar technology at our
Metropolitan 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.
In 2011, we will be testing a proximity detection system at our
Willow Lake Mine. The system is being designed to automatically
stop mining equipment if a person is detected within the
operating range of the equipment.
At our Metropolitan Mine, we continue with pilot testing of a
pumping system that will allow coal refuse from the mine to be
disposed of in abandoned areas of the underground workings
rather than transported to the surface. During 2010, test trials
were successfully completed on the backfill process and the
installation of the pumping system is nearing completion.
Underground emplacement is expected to commence in the first
quarter 2011.
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
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at three of our largest surface mines, North Antelope Rochelle,
Caballo and Bear Run, to dispatch mobile equipment more
efficiently and monitor performance and condition of all major
mining equipment on a real-time basis. In addition, data
historians are being installed at our North Antelope Rochelle
and Bear Run mines, to further analyze operational performance
in order to improve future performance.
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. 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. We
compete on the basis of coal quality, delivered price, customer
service and support and reliability. Demand for coal and the
prices that we will be able to obtain for our coal are
influenced by factors beyond our control, including the demand
for electricity and steel and the availability and price of
alternative fuels and energy sources. 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 40% of total U.S. coal production in 2009
(most recent publicly available data according to the National
Mining Association’s “2009 Coal Producer
Survey”). Major international competitors (listed
alphabetically) include
Anglo-American
PLC, BHP Billiton, China Coal, Rio Tinto, Shenhua Group and
Xstrata PLC.
Employees
As of December 31, 2010, we had approximately
7,200 employees, which included approximately
5,100 hourly employees. As of such date, approximately 28%
of our hourly employees were represented by organized labor
unions and generated 9% of 2010 coal production. In the U.S.,
those represented by organized labor unions include hourly
workers at our Kayenta Mine in Arizona and at our Willow Lake
Mine in Illinois. In Australia, the coal mining industry is
highly unionized and the majority of workers employed at our
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. Additional information on labor relations
is contained in Note 18 to our consolidated financial
statements.
Working
Capital
We generally fund our business operations through a combination
of available cash and equivalents and cash flow generated from
operations. In addition, our revolving credit facility
(Revolver) and our accounts receivable securitization program
are available for additional working capital needs. See
Liquidity and Capital Resources in Part II, Item 7 for
additional information regarding working capital.
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.
We are subject to
health and safety standards both at the federal and state level.
The regulations are comprehensive and affect numerous aspects of
mining operations, including training of mine personnel, mining
procedures, blasting, the equipment used in mining operations
and other matters.
The Mine Safety and Health Administration (MSHA) is the entity
responsible for monitoring compliance with the federal mine
health and safety standards. MSHA has various enforcement tools
that it can use, including the issuance of monetary penalties
and orders of withdrawal from a mine or part of a mine. Some,
but not all, of the costs of complying with existing regulations
and implementing new safety and health regulations may be passed
on to customers.
MSHA has recently taken a number of actions to identify mines
with safety issues, and has engaged in a number of targeted
enforcement, awareness, outreach and rulemaking activities to
reduce the number of mining fatalities, accidents and illnesses.
There has also been an industry-wide increase in the monetary
penalties assessed for citations of a similar nature.
In Item 9B. “Other Information,” we provide
additional details on how we monitor safety performance and MSHA
compliance, as well as provide the mine safety disclosures
required pursuant to the Dodd-Frank Wall Street Reform and
Consumer Protection Act (the Dodd-Frank Act).
Safety is a core value that is integrated into all areas of our
business. 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
accidents, incidents and losses to avoid reoccurrence. During
2010, we voluntarily idled our mines for one day to allow for
interactive safety discussions with our employees, local and
federal agency representatives and management, and to provide
additional comprehensive training on accident prevention,
violation awareness and reduction and emergency preparedness.
As part of our training, we collaborate with MSHA and other
government agencies to identify and test emerging safety
technologies.
We also partner with several companies and governmental agencies
to pursue new technologies that have the potential to improve
our safety performance and provide better safety protections for
our employees. We have signed letters of intent to field test a
new mine emergency vehicle under development by outside
companies. We will begin installation of a new communications
and tracking system at our U.S. underground mines, which
will allow persons on the surface to determine the location of
and communicate with all persons underground. In addition, we
are exploring the use of proximity detection and collision
avoidance systems to enhance the safety around our large
equipment fleets.
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.
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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.
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
waters of the U.S., including wetlands, and the U.S. Bureau
of Alcohol, Tobacco and Firearms regulates the use of explosive
blasting materials.
We do not believe there are any matters that pose a material
risk to maintaining our existing mining permits or that
materially hinder our ability to secure future mining permits.
It is our policy to comply 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 national 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 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, particulate matter and
other substances emitted by coal-based electricity generating
plants. Air emissions programs that may affect our operations,
directly or
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indirectly, include, but are not limited to, the Acid Rain
Program, NOx SIP Call, the Clean Air Interstate Rule (CAIR) as
well as the Transport Rule the EPA proposed in July 2010 to
replace it, Maximum Achievable Control Technology (MACT)
emissions limits for Hazardous Air Pollutants, the Regional Haze
program and New Source Review. In addition, in recent years the
EPA has adopted more stringent NAAQS for particulate matter,
nitrogen oxide and sulfur dioxide and has proposed a more
stringent NAAQS for ozone. EPA is under a court order to
promulgate new MACT rules for electric generating units by
November 16, 2011. Many of these programs and regulations
have resulted in litigation which has not been completely
resolved.
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. In May 2010, the EPA published final greenhouse
gas emission standards for new motor vehicles pursuant to the
Clean Air Act. Both the endangerment finding and motor vehicle
standards are the subject of litigation.
Because the Clean Air Act specifies that the prevention of
significant deterioration program applies once emissions of
regulated pollutants exceed either 100 or 250 tons per year
(depending on the type of source), millions of sources
previously unregulated under the Clean Air Act could be subject
to greenhouse gas reduction measures. The EPA published a rule
in June 2010 to limit the number of greenhouse gas sources that
would be subject to the prevention of significant deterioration
(PSD) program. In the so-called “tailoring rule,” the
EPA limited the regulation of greenhouse gases from certain
stationary sources to those that emit more than 75,000 tons of
greenhouse gases per year (for sources that would be subject to
PSD permitting regardless of greenhouse gas emissions due to
other air emissions) or 100,000 tons of greenhouse gases per
year (for sources not subject to PSD permitting for any other
air emissions), measured by “carbon dioxide
equivalent.” Whether the EPA has the statutory authority
under the Clean Air Act to adopt the tailoring rule also is the
subject of litigation.
In December 2010, EPA announced a settlement with states and
environmental groups that had filed litigation challenges to
EPA’s decisions not to establish greenhouse gas emission
standards for fossil fuel-fired power plants and for petroleum
refineries under section 111 of the Clean Air Act. In the
settlement, the EPA agreed: (1) to sign proposed new source
performance standards for new and modified electric utility
steam generating units under section 111(b), as well as
proposed guidelines for states’ development of emission
standards for existing electric utility steam generating units
under section 111(d), by July 26, 2011; and
(2) to take final action on the proposed
section 111(b) standards and section 111(d) guidelines
by May 26, 2012. Whatever the EPA determines the new source
performance standards to be, this will then be the minimum
requirement for best available control technology requirements
under the prevention of significant deterioration program.
Clean Water Act.
The Clean Water Act of 1972
affects U.S. coal mining operations by requiring both
technology-based and, if necessary, water quality-based effluent
limitations and treatment standards for wastewater 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 from mine-related point
sources into water. Section 404 of 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 apply “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 their water quality standards and other applicable
requirements in deciding whether or not to certify the activity.
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
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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
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 revisited its May 2000 determination
and proposed new requirements for coal combustion residue (CCR)
management on June 21, 2010. That proposal contains two
options: (1) to continue to regulate CCR as a non-hazardous
waste, or (2) to regulate CCR as special waste under the
hazardous waste regulations.
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.
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 affected 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.
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 federal regulatory
requirements.
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 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. There is also federal and state
legislation to prevent damage to Aboriginal cultural heritage
and archeological sites.
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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 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.
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.
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
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 or consumption limits in Australia
(controlling corporations) must comply with the NGER Act. 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
As noted above, we currently own a 50% interest in the
Peabody-Winsway Resources B.V. joint venture, which holds coal
and mineral interests in Mongolia and 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 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
In the U.S., Congress has considered legislation addressing
global climate issues and greenhouse gas emissions, but to date
nothing has been enacted. While it is possible that the
U.S. will adopt legislation in the future, the timing and
specific requirements of any such legislation are uncertain. In
the absence of new U.S. federal legislation, the EPA is
attempting to regulate greenhouse gas emissions pursuant to the
Clean Air
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Act. In response to the 2007 U.S. Supreme Court ruling in
Massachusetts v. EPA,
the EPA has commenced several
rulemaking projects as described above under “Regulatory
Matters-U.S. — Clean Air Act.”
A number of states in the U.S. have adopted programs 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, 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
into the Midwestern Regional Greenhouse Gas Reduction Accord to
establish voluntary regional greenhouse gas reduction targets
and develop a voluntary multi-sector
cap-and-trade
system to help meet the targets. Seven western states (Arizona,
California, Montana, New Mexico, Oregon, Utah and Washington)
and four Canadian provinces have entered into the Western
Climate Initiative (WCI) to establish a voluntary regional
greenhouse gas reduction goal and develop market-based
strategies to achieve emissions reductions. However, the only
two states prepared to go forward when the WCI begins on
January 1, 2012 are California and New Mexico. The Governor
of Arizona announced in February 2010 that Arizona will not
implement the greenhouse gas
cap-and-trade
proposal advanced by the WCI. 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. The California Air Resources Board is in the process
of finalizing regulations to implement a
cap-and-trade
program pursuant to the 2006 legislation, and that program is
expected to go into effect on January 1, 2012.
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 material at our mines.
The Kyoto Protocol, adopted in December 1997 by the signatories
to the 1992 Framework Convention on Climate Change, established
a binding set of emission targets for developed nations. The
U.S. signed the Kyoto Protocol but it was not ratified by
the U.S. Senate. Australia ratified the Kyoto Protocol in
December 2007 and became a full member in March 2008. There are
continuing discussions to develop a treaty to replace the Kyoto
Protocol after its expiration in 2012, including the Cancun
meetings in late 2010.
Australia’s Parliament has considered legislation that
would specifically address global climate issues and greenhouse
gas emissions, but to date nothing has been enacted. While it is
possible that Australia federal or state government may adopt
legislation in the future, the timing and specific requirements
of any such legislation are uncertain.
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
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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
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 quarterly and annual repricing of our metallurgical coal contracts; | |
| • | the supply of U.S. domestic and international thermal and metallurgical coal; | |
| • | adverse weather and natural disasters; | |
| • | competition within our industry and the availability and price of alternative fuels and energy sources; | |
| • | the proximity, capacity and cost of transportation; | |
| • | 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. |
In the U.S., 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. In Australia, the current practice for
metallurgical coal is quarterly contract pricing and for
seaborne thermal coal is annual contract pricing. 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 2010, 91% of our
worldwide sales volume was sold under long-term coal supply
agreements. At January 31, 2011, our sales backlog,
including backlog subject to price reopener
and/or
extension provisions, was over 1 billion tons, representing
over four years of current production in backlog based on our
2010 production of 218.4 million tons. Contracts in backlog
have remaining terms ranging from one to 16 years.
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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 provide assurance 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.
The
loss of, or significant reduction in, purchases by our largest
customers could adversely affect our revenues.
For the year ended December 31, 2010 we derived 25% of our
total coal sales revenues from our five largest customers. Those
five customers were supplied primarily from 37 coal supply
agreements (excluding trading transactions) expiring at various
times from 2011 to 2016. The contract contributing the greatest
amount of annual revenue in 2010 was approximately
$279 million, or approximately 4% of our 2010 total revenue
base. 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
operating results could be adversely affected by unfavorable
economic and financial market conditions.
In recent years, the global economic recession and the worldwide
financial and credit market disruptions had a negative impact on
us and on the coal industry generally. If any of these
conditions return or if there are downturns in economic
conditions in our key growth markets, particularly China and
India, our business, financial condition or results of
operations could be adversely affected. While we are focused on
cost control, productivity improvements, increased contributions
from our high-margin operations and capital discipline, there
can be no assurance that these actions, or any others we may
take, will be sufficient in response to downturns in economic
and financial conditions.
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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 in the U.S. as
utilities have sold their power plants to their non-regulated
affiliates or third parties, and with our continued expansion in
the Asia-Pacific region. These new customers may have credit
ratings that are below investment grade or not rated. If
deterioration of the creditworthiness of our customers occurs,
our 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, 2010, 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, non-performance
or delays by co-shippers, 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.
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, fuel, explosives, tires,
steel-related products (including roof control materials),
lubricants and electricity. There has been some consolidation in
the supplier base providing mining materials to the coal
industry, such as with suppliers of explosives and both surface
and underground equipment, that has limited the number of
sources for these materials. In situations where we have chosen
to concentrate a large portion of purchases with one supplier,
it has been to take advantage of cost savings from larger
volumes of purchases and to ensure security of supply. 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 or we could experience a delay or halt in our production.
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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 are 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
market price volatility of foreign currency (primarily the
Australian dollar), diesel fuel and explosives. Also, from time
to time, we manage the interest rate risk associated with our
variable and fixed rate borrowings using interest rate swaps.
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. In addition, to the
extent that we engage in hedging activities, we may be prevented
from realizing the benefits of future price decreases of foreign
currency, diesel fuel and explosives.
We also enter into derivative trading instruments, some of which
require us to post margin based on the value of those
instruments 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, particularly
personnel with mining experience. We cannot provide assurance
that key personnel will continue to be employed by us or that we
will be able to attract and retain qualified personnel in the
future. Failure to retain or attract key personnel could have a
material adverse effect on us.
We
could be negatively affected if we fail to maintain satisfactory
labor relations.
As of December 31, 2010, we had approximately
7,200 employees, which included approximately
5,100 hourly employees. Approximately 28% of our hourly
employees were represented by organized labor unions and
generated 9% of 2010 coal production. Additionally, those
employed through contract mining relationships in Australia are
also members of trade unions. Relations with our employees and,
where
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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. Also, if we fail to
maintain good relations with our union workforce, we could
experience labor disputes, work stoppages or other disruptions
in production that could negatively impact our profitability.
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 we use 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, 2010, we had $920.3 million of self
bonding in place for our reclamation obligations. As of
December 31, 2010, we also had outstanding surety bonds
with third parties, bank guarantees and letters of credit of
$1,117.1 million, of which $704.5 million was for
post-mining reclamation, $76.1 million related to
workers’ compensation obligations, $110.3 million was
for coal lease obligations and $226.2 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 us maintaining compliance under our two
primary facilities used for such items, which is our unsecured
credit facility (Credit Facility) and accounts receivable
securitization program. Our failure to retain, 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 Credit Facility; | |
| • | the exercise by third-party surety bond issuers of their right to refuse to renew the surety; and | |
| • | the 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.
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 new interpretations by the
relevant government authorities 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
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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 operations 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 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
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December 31, 2010, we leased a total of 63,657 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 have 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, Newcastle, Australia and Singapore. We also
have joint venture mining and exploration interests in Venezuela
and Mongolia and are exploring other projects that could expand
our presence in the Asia-Pacific region. 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 operations, 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 unsecured
credit agreement (the Credit Agreement).
As of December 31, 2010, we had $1.4 billion of
available borrowing capacity under our Credit Facility, net of
outstanding letters of credit. This committed facility, which
matures on June 18, 2015, 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. Although the Credit
Facility syndicate consists of over 40 financial institutions,
if one or more of these institutions 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, 2010, our total indebtedness was
$2.8 billion, and we had $1.4 billion of available
borrowing capacity under our Credit Facility net of outstanding
letters of credit. The indentures governing our Convertible
Junior Subordinated Debentures (the Debentures) and 7.375%,
7.875% and 6.5% Senior Notes do not limit the amount of
indebtedness that we may issue, and the indenture governing our
5.875% Senior Notes permits 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; |
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| • | requiring the dedication of a substantial portion of our cash flow from operations to the payment of principal and interest on our indebtedness, thereby reducing the availability of our cash flow to fund working capital, capital expenditures, business development, 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, business development, 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
Credit Agreement 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 complete 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 Credit Agreement and the indentures governing
our Senior Notes and Debentures impose restrictions that may
limit our operating and financial flexibility.
Our Credit Agreement, the indentures governing our 7.375%,
7.875%, 6.5% and 5.875% Senior Notes and our Debentures and
the instruments governing our other indebtedness contain certain
restrictions and covenants which restrict our ability to incur
liens
and/or
debt or provide guarantees in respect of obligations of any
other person. Under our Credit Agreement, 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.
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 Credit Agreement. If we violate these covenants
and are unable to obtain waivers from our lenders, our debt
under our Credit Facility, our 7.375%, 7.875%, 6.5% and
5.875% Senior Notes and our 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 or
on terms that are acceptable to us. If our debt is in default
for any reason, our business, financial condition and results of
operations could be materially and adversely affected. In
addition, complying with these covenants may also cause us to
take actions that are not favorable to holders of our other debt
or equity securities and may make it more difficult for us to
successfully execute our business strategy and compete against
companies who are not subject to such restrictions.
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
23
Table of Contents
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 $1,031.2 million as of December 31, 2010,
$67.3 million of which was a current liability. Net pension
liabilities were $109.4 million as of December 31,
2010, $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. In
addition, a decrease in the discount rate used to determine
pension obligations could result in an increase in the valuation
of pension obligations, which could affect the reported funding
status of our pension plans and future contributions, as well as
the periodic pension cost in subsequent fiscal years.
The decline in the stock market and real estate values in recent
years led to a decline in the value of our pension plan assets
which required increased contributions in 2009 and 2010. If we
experience poor financial performance in asset markets in future
years, we may be required to increase contributions further.
Concerns
about the environmental impacts of coal combustion, including
perceived impacts on global climate issues, 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 issues continue 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 issues. In
turn, increasing government attention is being paid to global
climate issues 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
24
Table of Contents
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 force 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.
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. 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, 2010. An estimated
7.8 billion tons of our proven and probable coal reserves
are in the U.S. and 1.2 billion tons are in Australia.
28% of our Australian proven and probable coal reserves, or
336 million tons, are metallurgical coal with the remainder
being thermal coal. 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 41% of these reserves and lease property
containing the remaining 59%. Compliance coal is defined by
Phase II of the Clean Air Act as coal having sulfur dioxide
content of 1.2
25
Table of Contents
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, 2010 (1) | ||||||||||||||
|
Owned
|
Leased
|
Total
|
||||||||||||
| Operating Regions | Locations | Tons | Tons | Tons | ||||||||||
| (Tons in millions) | ||||||||||||||
|
Midwest
|
Illinois, Indiana and Kentucky | 2,749 | 901 | 3,650 | ||||||||||
|
Powder River Basin
|
Wyoming and Montana | 67 | 2,805 | 2,872 | ||||||||||
|
Southwest
|
Arizona and New Mexico | 792 | 284 | 1,076 | ||||||||||
|
Colorado
|
Colorado | 44 | 186 | 230 | ||||||||||
|
Total United States
|
3,652 | 4,176 | 7,828 | |||||||||||
|
Australia
|
New South Wales | — | 418 | 418 | ||||||||||
|
Australia
|
Queensland | — | 767 | 767 | ||||||||||
|
Total Australia
|
— | 1,185 | 1,185 | |||||||||||
|
Total Proven and Probable Coal Reserves
|
3,652 | 5,361 | 9,013 | |||||||||||
| (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 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.
26
Table of Contents
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 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, 2010, we leased
11,328 acres of federal land in Colorado, 11,254 acres
in Montana and 41,075 acres in Wyoming, for a total of
63,657 nationwide.
Similar provisions govern three coal leases with the Navajo and
Hopi Indian tribes. These leases cover coal contained in
64,783 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.
27
Table of Contents
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 the sales price. 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.
28
Table of Contents
The following chart provides a summary, by mining complex, of
production for the years ended December 31, 2010, 2009 and
2008, 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, 2010 | |||||||||||||||||||||||||||||||||||||||||||
|
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 | 2010 | 2009 | 2008 | Coal | Million Btu | Million Btu | Million Btu | per pound (3) | Probable Reserves | Owned | Leased | Surface | Underground | |||||||||||||||||||||||||||||||||||||
|
Midwest:
|
||||||||||||||||||||||||||||||||||||||||||||||||||
|
Somerville Central
|
3.4 | 3.3 | 3.5 | Thermal | — | — | 9 | 11,200 | 9 | 7 | 2 | 9 | — | |||||||||||||||||||||||||||||||||||||
|
Gateway
|
3.2 | 3.3 | 3.2 | Thermal | — | — | 15 | 11,000 | 15 | 14 | 1 | — | 15 | |||||||||||||||||||||||||||||||||||||
|
Willow Lake
|
2.9 | 3.4 | 3.6 | Thermal | — | — | 25 | 12,100 | 25 | 16 | 9 | — | 25 | |||||||||||||||||||||||||||||||||||||
|
Bear Run
|
2.8 | — | — | Thermal | 6 | 26 | 227 | 11,500 | 259 | 135 | 124 | 259 | — | |||||||||||||||||||||||||||||||||||||
|
Francisco Underground
|
2.7 | 2.0 | 1.5 | Thermal | — | — | 43 | 11,300 | 43 | 8 | 35 | — | 43 | |||||||||||||||||||||||||||||||||||||
|
Cottage Grove
|
2.1 | 0.7 | 0.7 | Thermal | — | — | 23 | 12,300 | 23 | 15 | 8 | 23 | — | |||||||||||||||||||||||||||||||||||||
|
Somerville North
|
2.0 | 2.0 | 2.2 | Thermal | — | — | 3 | 10,600 | 3 | 3 | — | 3 | — | |||||||||||||||||||||||||||||||||||||
|
Viking — Knox Pit
|
1.7 | 2.0 | 1.9 | Thermal | — | — | — | NA | — | — | — | — | — | |||||||||||||||||||||||||||||||||||||
|
Somerville South
|
1.7 | 1.8 | 2.2 | Thermal | — | — | 3 | 11,100 | 3 | 3 | — | 3 | — | |||||||||||||||||||||||||||||||||||||
|
Farmersburg (Closed in 2010)
|
1.5 | 3.5 | 3.4 | Thermal | — | — | — | NA | — | — | — | — | — | |||||||||||||||||||||||||||||||||||||
|
Viking — Corning Pit
|
1.5 | 1.6 | 1.6 | Thermal | — | — | 5 | 11,500 | 5 | — | 5 | 5 | — | |||||||||||||||||||||||||||||||||||||
|
Air Quality
|
1.1 | 1.6 | 1.9 | Thermal | 22 | 2 | 33 | 11,300 | 57 | 4 | 53 | — | 57 | |||||||||||||||||||||||||||||||||||||
|
Wildcat Hills Underground
|
0.8 | 2.1 | 2.2 | Thermal | — | — | 19 | 12,200 | 19 | 13 | 6 | — | 19 | |||||||||||||||||||||||||||||||||||||
|
Wild Boar
|
0.1 | — | — | Thermal | — | — | 17 | 11,000 | 17 | 13 | 4 | 17 | — | |||||||||||||||||||||||||||||||||||||
|
Francisco Surface (Closed in 2009)
|
— | 1.4 | 1.9 | Thermal | — | — | — | NA | — | — | — | — | — | |||||||||||||||||||||||||||||||||||||
|
Total
|
27.5 | 28.7 | 29.8 | 28 | 28 | 422 | 478 | 231 | 247 | 319 | 159 | |||||||||||||||||||||||||||||||||||||||
|
Powder River Basin:
|
||||||||||||||||||||||||||||||||||||||||||||||||||
|
North Antelope Rochelle
|
105.8 | 98.3 | 97.6 | Thermal | 1,184 | — | 33 | 8,700 | 1,217 | — | 1,217 | 1,217 | — | |||||||||||||||||||||||||||||||||||||
|
Caballo
|
23.5 | 23.3 | 31.2 | Thermal | 669 | 130 | 23 | 8,200 | 822 | — | 822 | 822 | — | |||||||||||||||||||||||||||||||||||||
|
Rawhide
|
11.2 | 15.8 | 18.4 | Thermal | 293 | 72 | 4 | 8,300 | 369 | — | 369 | 369 | — | |||||||||||||||||||||||||||||||||||||
|
Total
|
140.5 | 137.4 | 147.2 | 2,146 | 202 | 60 | 2,408 | — | 2,408 | 2,408 | — | |||||||||||||||||||||||||||||||||||||||
|
Southwest:
|
||||||||||||||||||||||||||||||||||||||||||||||||||
|
Kayenta
|
7.8 | 7.5 | 8.0 | Thermal | 169 | 76 | 3 | 10,600 | 248 | — | 248 | 248 | — | |||||||||||||||||||||||||||||||||||||
|
El Segundo
|
6.6 | 5.1 | 3.3 | Thermal | 24 | 83 | 65 | 9,000 | 172 | 157 | 15 | 172 | — | |||||||||||||||||||||||||||||||||||||
|
Lee Ranch
|
1.6 | 1.8 | 3.3 | Thermal | 18 | 114 | 13 | 9,300 | 145 | 124 | 21 | 145 | — | |||||||||||||||||||||||||||||||||||||
|
Total
|
16.0 | 14.4 | 14.6 | 211 | 273 | 81 | 565 | 281 | 284 | 565 | — | |||||||||||||||||||||||||||||||||||||||
|
Colorado:
|
||||||||||||||||||||||||||||||||||||||||||||||||||
|
Twentymile
|
7.7 | 7.8 | 8.0 | Thermal | 44 | — | — | 11,200 | 44 | 8 | 36 | — | 44 | |||||||||||||||||||||||||||||||||||||
|
Australia:
|
||||||||||||||||||||||||||||||||||||||||||||||||||
|
Wilpinjong
|
9.6 | 8.4 | 7.5 | Thermal | — | 197 | — | 11,200 | 197 | — | 197 | 197 | — | |||||||||||||||||||||||||||||||||||||
|
Wambo
(4)
|
6.6 | 4.1 | 5.4 | Thermal/Met. | 178 | — | — | 12,200 | 178 | — | 178 | 30 | 148 | |||||||||||||||||||||||||||||||||||||
|
North Goonyella / Eaglefield
|
3.2 | 2.5 | 2.8 | Met. | 114 | — | — | 12,900 | 114 | — | 114 | 4 | 110 | |||||||||||||||||||||||||||||||||||||
|
Burton
(95%)
(5)
|
2.5 | 2.0 | 2.6 | Thermal/Met. | 45 | — | — | 12,700 | 45 | — | 45 | 45 | — | |||||||||||||||||||||||||||||||||||||
|
Metropolitan
|
1.6 | 1.5 | 1.5 | Met. | 43 | — | — | 12,600 | 43 | — | 43 | — | 43 | |||||||||||||||||||||||||||||||||||||
|
Wilkie Creek
|
1.6 | 2.3 | 2.6 | Thermal | 337 | — | — | 10,800 | 337 | — | 337 | 337 | — | |||||||||||||||||||||||||||||||||||||
|
Millennium
|
1.6 | 0.9 | 1.2 | Met. | 46 | — | — | 12,600 | 46 | — | 46 | 46 | — | |||||||||||||||||||||||||||||||||||||
|
Total
|
26.7 | 21.7 | 23.6 | 763 | 197 | — | 960 | — | 960 | 659 | 301 | |||||||||||||||||||||||||||||||||||||||
|
Total Continuing Operations
|
218.4 | 210.0 | 223.2 | 3,192 | 700 | 563 | 4,455 | 520 | 3,935 | 3,951 | 504 | |||||||||||||||||||||||||||||||||||||||
|
Discontinued Operations
|
— | 0.8 | 2.0 | — | — | — | — | — | — | — | — | |||||||||||||||||||||||||||||||||||||||
|
Total Assigned
|
218.4 | 210.8 | 225.2 | 3,192 | 700 | 563 | 4,455 | 520 | 3,935 | 3,951 | 504 | |||||||||||||||||||||||||||||||||||||||
29
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, 2010
AS OF DECEMBER 31, 2010
(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
|
82 | 2,266 | 2,348 | 1,208 | 1,140 | Thermal | — | — | 2,348 | 10,900 | 1,973 | 375 | 70 | 2,278 | ||||||||||||||||||||||||||||||||||||||||
|
Indiana
|
396 | 403 | 799 | 591 | 208 | Thermal | 27 | 38 | 734 | 11,400 | 472 | 327 | 430 | 369 | ||||||||||||||||||||||||||||||||||||||||
|
Kentucky
|
— | 503 | 503 | 265 | 238 | Thermal | — | — | 503 | 11,900 | 304 | 199 | 98 | 405 | ||||||||||||||||||||||||||||||||||||||||
|
Total
|
478 | 3,172 | 3,650 | 2,064 | 1,586 | 27 | 38 | 3,585 | 2,749 | 901 | 598 | 3,052 | ||||||||||||||||||||||||||||||||||||||||||
|
Powder River Basin:
|
||||||||||||||||||||||||||||||||||||||||||||||||||||||
|
Montana
|
— | 161 | 161 | 157 | 4 | Thermal | 9 | 121 | 31 | 8,500 | 67 | 94 | 161 | — | ||||||||||||||||||||||||||||||||||||||||
|
Wyoming
|
2,408 | 303 | 2,711 | 2,668 | 43 | Thermal | 2,450 | 202 | 59 | 8,500 | — | 2,711 | 2,711 | — | ||||||||||||||||||||||||||||||||||||||||
|
Total
|
2,408 | 464 | 2,872 | 2,825 | 47 | 2,459 | 323 | 90 | 67 | 2,805 | 2,872 | — | ||||||||||||||||||||||||||||||||||||||||||
|
Southwest:
|
||||||||||||||||||||||||||||||||||||||||||||||||||||||
|
Arizona
|
248 | — | 248 | 248 | — | Thermal | 169 | 76 | 3 | 10,600 | — | 248 | 248 | — | ||||||||||||||||||||||||||||||||||||||||
|
New Mexico
|
317 | 511 | 828 | 750 | 78 | Thermal | 156 | 402 | 270 | 8,700 | 792 | 36 | 804 | 24 | ||||||||||||||||||||||||||||||||||||||||
|
Total
|
565 | 511 | 1,076 | 998 | 78 | 325 | 478 | 273 | 792 | 284 | 1,052 | 24 | ||||||||||||||||||||||||||||||||||||||||||
|
Colorado
|
44 | 186 | 230 | 146 | 84 | Thermal | 227 | — | 3 | 10,700 | 44 | 186 | — | 230 | ||||||||||||||||||||||||||||||||||||||||
|
Australia:
|
||||||||||||||||||||||||||||||||||||||||||||||||||||||
|
New South Wales
|
418 | — | 418 | 335 | 83 | Thermal/Met. | 221 | 197 | — | 11,800 | — | 418 | 227 | 191 | ||||||||||||||||||||||||||||||||||||||||
|
Queensland
|
542 | 225 | 767 | 576 | 191 | Thermal/Met. | 767 | — | — | 11,600 | — | 767 | 657 | 110 | ||||||||||||||||||||||||||||||||||||||||
|
Total
|
960 | 225 | 1,185 | 911 | 274 | 988 | 197 | — | — | 1,185 | 884 | 301 | ||||||||||||||||||||||||||||||||||||||||||
|
Total Proven and Probable
|
4,455 | 4,558 | 9,013 | 6,944 | 2,069 | 4,026 | 1,036 | 3,951 | 3,652 | 5,361 | 5,406 | 3,607 | ||||||||||||||||||||||||||||||||||||||||||
30
Table of Contents
| (1) | Assigned reserves represent recoverable coal reserves that are controlled and accessible at active operations as of December 31, 2010. 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) | Wambo includes the Wambo Open-Cut Mine and the North Wambo Underground Mine. 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. | [Removed and Reserved] |
Executive
Officers of the Company
Set forth below are the names, ages as of February 18, 2011
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
|
56 | Chairman and Chief Executive Officer, Director | ||||
|
Richard A. Navarre
|
50 | President and Chief Commercial Officer | ||||
|
Michael C. Crews
|
43 | Executive Vice President and Chief Financial Officer | ||||
|
Sharon D. Fiehler
|
54 | Executive Vice President and Chief Administrative Officer | ||||
|
Eric Ford
|
56 | Executive Vice President and Chief Operating Officer | ||||
|
Alexander C. Schoch
|
56 | 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 directors of Marathon Oil Corporation. He is Chairman
of the National Mining Association and a member of the World
31
Table of Contents
Coal Association, 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
Business Council; Civic Progress in St. Louis; the Board of
Trustees of St. Louis Children’s Hospital; the Board
of Trustees of 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; and a member of the Board
of Directors of the Regional Chamber and Growth Association of
St. Louis. He is a Director of the United Way of Greater
St. Louis; Treasurer of the Missouri Historical Society; a
member of Financial Executives International; 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 serves on the Board of
Directors of Action for Autism in St. Louis. Mr. Crews
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; a member
of the Board of Trustees of the Missouri Botanical Garden; Chair
of the Board of Directors of Junior Achievement of Mississippi
Valley, Inc.; 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, the 2008 YWCA Leader of Distinction Award and the 2010
Logos School St. Louis Women of Distinction Award. She is
also a member of the Missouri Women’s Forum and the
St. Louis Forum.
Eric Ford was named our Executive Vice President and Chief
Operating Officer in March 2007. Mr. Ford has 39 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
32
Table of Contents
supplier of process-automation products, from August 2004 to
October 2006. Mr. Schoch also served in several legal
positions with Goodrich Corporation, a global supplier to the
aerospace and defense industries, from 1987 to 2004, including
Vice President, Associate General Counsel and Secretary. Prior
to that, he worked for Marathon Oil Company as an attorney in
its international exploration and production division.
Mr. Schoch holds a Juris Doctorate from Case Western
Reserve University in Ohio, as well as a Bachelor of Arts in
Economics from Kenyon College in Ohio. He is admitted to
practice law in several states, and is a member of the American
and International Bar Associations. Mr. Schoch serves as a
Trustee at Large on the Board of Trustees for the
Energy & Mineral Law Foundation and on the Board of
Directors of North Side Community School in St. Louis,
Missouri.
| 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 11, 2011, there
were 1,307 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 | ||||||||||
|
2010
|
||||||||||||
|
First Quarter
|
$ | 52.14 | $ | 39.88 | $ | 0.070 | ||||||
|
Second Quarter
|
50.25 | 34.89 | 0.070 | |||||||||
|
Third Quarter
|
49.94 | 38.08 | 0.070 | |||||||||
|
Fourth Quarter
|
64.59 | 48.76 | 0.085 | |||||||||
|
2009
|
||||||||||||
|
First Quarter
|
$ | 30.95 | $ | 20.17 | $ | 0.060 | ||||||
|
Second Quarter
|
37.44 | 23.56 | 0.060 | |||||||||
|
Third Quarter
|
41.54 | 27.19 | 0.060 | |||||||||
|
Fourth Quarter
|
48.21 | 34.54 | 0.070 | |||||||||
Dividend
Policy
We have declared and paid quarterly dividends since our initial
public offering in 2001. Most recently, our Board of Directors
declared a dividend of $0.085 per share of Common Stock on
January 27, 2011, payable on March 3, 2011, to
stockholders of record on February 10, 2011. 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
On October 24, 2008, we announced that our Board of
Directors 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
33
Table of Contents
December 31, 2010, we have made repurchases of
7.7 million shares at a cost of $299.6 million
($199.8 million and $99.8 million in 2008 and 2006,
respectively), leaving $700.4 million available for share
repurchases under the program.
The following table summarizes all share repurchases for the
three months ended December 31, 2010:
|
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, 2010
|
1,392 | $ | 50.53 | — | $ | 700.4 | ||||||||||
|
November 1 through November 30, 2010
|
11,122 | 53.91 | — | 700.4 | ||||||||||||
|
December 1 through December 31, 2010
|
70,087 | 63.98 | — | 700.4 | ||||||||||||
|
Total
|
82,601 | $ | 62.40 | — | ||||||||||||
| (1) | Represents shares withheld to cover the withholding taxes upon the vesting of restricted stock, which are not a part of the share repurchase program. |
| 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 2010,
2009 and 2008 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 Coal Limited (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, 2010, 2009, 2008, 2007 and
2006 from our audited financial statements. You should read the
following table in
34
Table of Contents
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.”
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. “Risk Factors” of
this report includes a discussion of risk factors that could
impact our future results of operations.
| Year Ended December 31, | ||||||||||||||||||||
| 2010 | 2009 | 2008 | 2007 | 2006 | ||||||||||||||||
| (In millions, except per share data) | ||||||||||||||||||||
|
Results of Operations Data
|
||||||||||||||||||||
|
Total revenues
|
$ | 6,860.0 | $ | 6,012.4 | $ | 6,561.0 | $ | 4,523.8 | $ | 4,045.6 | ||||||||||
|
Costs and expenses
|
5,534.3 | 5,167.6 | 5,164.7 | 3,924.1 | 3,432.8 | |||||||||||||||
|
Operating profit
|
1,325.7 | 844.8 | 1,396.3 | 599.7 | 612.8 | |||||||||||||||
|
Interest expense, net
|
212.5 | 193.1 | 217.0 | 228.8 | 127.8 | |||||||||||||||
|
Income from continuing operations before income taxes
|
1,113.2 | 651.7 | 1,179.3 | 370.9 | 485.0 | |||||||||||||||
|
Income tax provision (benefit)
|
308.1 | 193.8 | 191.4 | (70.7 | ) | (85.6 | ) | |||||||||||||
|
Income from continuing operations, net of income taxes
|
805.1 | 457.9 | 987.9 | 441.6 | 570.6 | |||||||||||||||
|
Income (loss) from discontinued operations, net of income taxes
|
(2.9 | ) | 5.1 | (28.8 | ) | (180.1 | ) | 30.7 | ||||||||||||
|
Net income
|
802.2 | 463.0 | 959.1 | 261.5 | 601.3 | |||||||||||||||
|
Less: net income (loss) attributable to noncontrolling interests
|
28.2 | 14.8 | 6.2 | (2.3 | ) | 0.6 | ||||||||||||||
|
Net income attributable to common stockholders
|
$ | 774.0 | $ | 448.2 | $ | 952.9 | $ | 263.8 | $ | 600.7 | ||||||||||
|
Basic earnings per share from continuing operations
|
$ | 2.89 | $ | 1.66 | $ | 3.63 | $ | 1.67 | $ | 2.15 | ||||||||||
|
Diluted earnings per share from continuing operations
|
$ | 2.86 | $ | 1.64 | $ | 3.60 | $ | 1.64 | $ | 2.11 | ||||||||||
|
Weighted average shares used in calculating basic earnings per
share
|
267.0 | 265.5 | 268.9 | 264.1 | 263.4 | |||||||||||||||
|
Weighted average shares used in calculating diluted earnings per
share
|
269.9 | 267.5 | 270.7 | 268.6 | 268.8 | |||||||||||||||
|
Dividends declared per share
|
$ | 0.295 | $ | 0.250 | $ | 0.240 | $ | 0.240 | $ | 0.240 | ||||||||||
|
Other Data
|
||||||||||||||||||||
|
Tons sold
|
245.9 | 243.6 | 255.0 | 235.5 | 221.2 | |||||||||||||||
|
Net cash provided by (used in) continuing operations:
|
||||||||||||||||||||
|
Operating activities
|
$ | 1,103.7 | $ | 1,055.8 | $ | 1,420.8 | $ | 465.0 | $ | 611.1 | ||||||||||
|
Investing activities
|
(703.6 | ) | (408.2 | ) | (419.3 | ) | (538.9 | ) | (2,055.6 | ) | ||||||||||
|
Financing activities
|
(77.1 | ) | (104.6 | ) | (498.0 | ) | 37.4 | 1,403.0 | ||||||||||||
|
Adjusted EBITDA
|
1,815.1 | 1,290.1 | 1,846.9 | 969.7 | 909.7 | |||||||||||||||
|
Balance Sheet Data (at period end)
|
||||||||||||||||||||
|
Total assets
|
$ | 11,363.1 | $ | 9,955.3 | $ | 9,695.6 | $ | 9,082.3 | $ | 9,504.7 | ||||||||||
|
Total long-term debt (including capital leases)
|
2,750.0 | 2,752.3 | 2,793.6 | 2,909.0 | 2,911.6 | |||||||||||||||
|
Total stockholders’ equity
|
4,689.3 | 3,755.9 | 3,119.5 | 2,735.3 | 2,587.0 | |||||||||||||||
35
Table of Contents
Adjusted EBITDA is calculated as follows (unaudited):
| Year Ended December 31, | ||||||||||||||||||||
| 2010 | 2009 | 2008 | 2007 | 2006 | ||||||||||||||||
| (Dollars in millions) | ||||||||||||||||||||
|
Income from continuing operations, net of income taxes
|
$ | 805.1 | $ | 457.9 | $ | 987.9 | $ | 441.6 | $ | 570.6 | ||||||||||
|
Income tax provision (benefit)
|
308.1 | 193.8 | 191.4 | (70.7 | ) | (85.6 | ) | |||||||||||||
|
Depreciation, depletion and amortization
|
440.9 | 405.2 | 402.4 | 346.3 | 282.7 | |||||||||||||||
|
Asset retirement obligation expense
|
48.5 | 40.1 | 48.2 | 23.7 | 14.2 | |||||||||||||||
|
Interest expense, net
|
212.5 | 193.1 | 217.0 | 228.8 | 127.8 | |||||||||||||||
|
Adjusted EBITDA
|
$ | 1,815.1 | $ | 1,290.1 | $ | 1,846.9 | $ | 969.7 | $ | 909.7 | ||||||||||
| 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 2010, we produced 218.4 million
tons of coal and sold 245.9 million tons of coal.
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 the U.S., we typically sell coal to utility customers under
long-term contracts (those with terms longer than one year). In
Australia, our production is sold primarily into the export
metallurgical and thermal markets with an increasing number of
the contracts negotiated with our customers on a quarterly
basis. During 2010, approximately 91% of our worldwide sales (by
volume) were under long-term contracts. For the year ended
December 31, 2010, 84% of our total sales (by volume) were
to U.S. electricity generators, 14% 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 Btu Conversion projects that expand the
uses of coal through CTL and CTG. Our participation in
generation development projects involves using our surface lands
and coal reserves as the basis for mine-mouth plants, such as
with our involvement in Prairie State. We are also advancing
several initiatives associated with clean coal technologies,
including CCS.
As discussed more fully in Item 1A. “Risk
Factors,” our results of operations in the near-term could
be negatively impacted by adverse weather conditions,
availability of transportation for coal shipments, unforeseen
geologic conditions or equipment problems at mining locations
and by the rate of the economic recovery. 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
36
Table of Contents
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, 2010 Compared to Year Ended
December 31, 2009
Summary
In the U.S., demand for coal rose approximately 75 million
tons in 2010, led by a 5.5% increase in coal-fueled generation
and an 18 million ton rise in exports. The international
coal markets strengthened in 2010 due to strong Asian demand
growth and weather-related generation recovery in the Atlantic
markets, coupled with supply challenges across the major coal
exporting nations of the Southern Hemisphere. Our analyses of
general business conditions indicate the following:
| • | Seaborne coal demand increased an estimated 13% in 2010, led by a 32% recovery in global metallurgical coal demand; | |
| • | Pacific thermal coal demand for electricity generation rose 15% in 2010, while the Atlantic market declined 10%; | |
| • | Benchmark pricing of high quality, hard coking coal in the seaborne market has ranged between $200 to $225 per tonne since April 2010; | |
| • | The benchmark prompt seaborne thermal coal price in Newcastle, Australia rose 34% in 2010; | |
| • | U.S. coal generation accounted for nearly two-thirds of the growth in total power output in 2010 due to new coal-fueled generation, favorable weather, and a partial reversal of 2009’s coal-to-gas switching; and | |
| • | Indexed U.S. coal prices rose in 2010 in all regions, with increases ranging from 30 to 50%. |
Our revenues increased compared to the prior year by
$847.6 million and Segment Adjusted EBITDA increased over
the prior year by $535.2 million, led by higher Australian
pricing and sales volumes in the current year despite
unfavorable weather-related volume impacts that occurred late in
2010.
Income from continuing operations, net of income taxes,
increased compared to the prior year by $347.2 million due
to the increase in Segment Adjusted EBITDA discussed above,
partially offset by increased income taxes, decreased Corporate
and Other Adjusted EBITDA, and increased depreciation, depletion
and amortization and interest expense.
We ended the year with total available liquidity of
$2.7 billion, as discussed further in “Liquidity and
Capital Resources.”
Tons
Sold
The following table presents tons sold by operating segment for
the years ended December 31, 2010 and 2009:
| Year Ended December 31, | Increase (Decrease) | |||||||||||||||
| 2010 | 2009 | Tons | % | |||||||||||||
| (Tons in millions) | ||||||||||||||||
|
Western U.S. Mining
|
163.8 | 160.1 | 3.7 | 2.3 | % | |||||||||||
|
Midwestern U.S. Mining
|
29.7 | 31.8 | (2.1 | ) | (6.6 | )% | ||||||||||
|
Australian Mining
|
27.0 | 22.3 | 4.7 | 21.1 | % | |||||||||||
|
Trading and Brokerage
|
25.4 | 29.4 | (4.0 | ) | (13.6 | )% | ||||||||||
|
Total tons sold
|
245.9 | 243.6 | 2.3 | 0.9 | % | |||||||||||
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Table of Contents
Revenues
The following table presents revenues for the years ended
December 31, 2010 and 2009:
|
Increase (Decrease)
|
||||||||||||||||
| Year Ended December 31, | to Revenues | |||||||||||||||
| 2010 | 2009 | $ | % | |||||||||||||
| (Dollars in millions) | ||||||||||||||||
|
Western U.S. Mining
|
$ | 2,706.3 | $ | 2,612.6 | $ | 93.7 | 3.6 | % | ||||||||
|
Midwestern U.S. Mining
|
1,320.6 | 1,303.8 | 16.8 | 1.3 | % | |||||||||||
|
Australian Mining
|
2,520.0 | 1,678.0 | 842.0 | 50.2 | % | |||||||||||
|
Trading and Brokerage
|
291.1 | 391.0 | (99.9 | ) | (25.5 | )% | ||||||||||
|
Corporate and Other
|
22.0 | 27.0 | (5.0 | ) | (18.5 | )% | ||||||||||
|
Total revenues
|
$ | 6,860.0 | $ | 6,012.4 | $ | 847.6 | 14.1 | % | ||||||||
The increase in Australian Mining operations’ revenues was
driven by a higher weighted average sales price of 23.9%, led by
increased pricing on seaborne metallurgical and thermal coals
and a higher mix of metallurgical coal shipments. Volumes also
increased in the current year (21.1%) driven by increased demand
for metallurgical coal (metallurgical coal shipments of
9.8 million tons were 2.9 million tons, or 42%,
greater than the prior year). These increases were muted to an
extent by the flooding in Queensland in late 2010 that
negatively impacted our production and also restricted
throughput due to damage to the port and rail systems. The
metallurgical coal demand increase reflects the strengthening of
the coal markets as discussed above, coupled with prior year
customer destocking of inventory and lower capacity utilization
at steel customers.
Western U.S. Mining operations’ revenues increased
compared to the prior year due to increased sales volume (2.3%)
driven by our Powder River Basin and Southwest regions due to
increased customer demand and a higher weighted average sales
price of 1.3%.
In the Midwestern U.S. Mining segment, revenue improvements
due to an increase in our weighted average sales price of 8.4%
from contractual price increases were largely offset by
decreased shipments (6.6%) on lower customer demand.
Trading and Brokerage revenues were down primarily due to lower
international brokerage revenues, unfavorable market movements
on freight positions that support our export volumes and weather
related shipment deferrals.
Segment
Adjusted EBITDA
The following table presents segment Adjusted EBITDA for the
years ended December 31, 2010 and 2009:
|
Increase (Decrease) to
|
||||||||||||||||
| Year Ended December 31, | Segment Adjusted EBITDA | |||||||||||||||
| 2010 | 2009 | $ | % | |||||||||||||
| (Dollars in millions) | ||||||||||||||||
|
Western U.S. Mining
|
$ | 816.7 | $ | 721.5 | $ | 95.2 | 13.2 | % | ||||||||
|
Midwestern U.S. Mining
|
322.1 | 281.9 | 40.2 | 14.3 | % | |||||||||||
|
Australian Mining
|
953.8 | 437.8 | 516.0 | 117.9 | % | |||||||||||
|
Trading and Brokerage
|
77.2 | 193.4 | (116.2 | ) | (60.1 | )% | ||||||||||
|
Total Segment Adjusted EBITDA
|
$ | 2,169.8 | $ | 1,634.6 | $ | 535.2 | 32.7 | % | ||||||||
Our Australian Mining segment benefitted from a higher weighted
average sales price ($413.0 million) and increased volumes
($127.9 million) as discussed above, and productivity
improvements at our North Goonyella and Wambo underground mines
along with fewer longwall move days in the current year
($116.0 million). Partially offsetting the above
improvements were net higher adverse weather impacts
38
Table of Contents
($47.0 million) driven by the flooding in late 2010,
unfavorable foreign currency impact on operating costs, net of
hedging ($34.5 million), increased royalty expense
associated with our higher-priced metallurgical coal shipments
($31.7 million) and increased demurrage costs
($10.7 million).
Western U.S. Mining operations’ Adjusted EBITDA
increased compared to the prior year due to the higher volumes
($49.8 million) and a higher weighted average sales price
($42.1 million) discussed above, lower repairs and
maintenance costs due to timing of repairs and improved
equipment efficiency ($35.0 million) and fewer longwall
move days at our Twentymile Mine in the current year
($10.0 million), partially offset by prior year customer
contract termination and restructuring agreements
($27.8 million) and increased commodity costs in the
current year ($20.8 million).
In the Midwestern U.S. Mining segment, a higher weighted
average sales price ($98.5 million), as discussed above,
was partially offset by lower volumes ($42.3 million) due
to decreased demand and increased costs on lower productivity
due to compliance measures and geological conditions at certain
underground mines.
Our Trading and Brokerage segment was down primarily due to the
lower revenues as discussed above.
Income
From Continuing Operations Before Income Taxes
The following table presents income from continuing operations
before income taxes for the years ended December 31, 2010
and 2009:
|
Increase (Decrease)
|
||||||||||||||||
| Year Ended December 31, | to Income | |||||||||||||||
| 2010 | 2009 | $ | % | |||||||||||||
| (Dollars in millions) | ||||||||||||||||
|
Total Segment Adjusted EBITDA
|
$ | 2,169.8 | $ | 1,634.6 | $ | 535.2 | 32.7 | % | ||||||||
|
Corporate and Other Adjusted
EBITDA
(1)
|
(354.7 | ) | (344.5 | ) | (10.2 | ) | (3.0 | )% | ||||||||
|
Depreciation, depletion and amortization
|
(440.9 | ) | (405.2 | ) | (35.7 | ) | (8.8 | )% | ||||||||
|
Asset retirement obligation expense
|
(48.5 | ) | (40.1 | ) | (8.4 | ) | (20.9 | )% | ||||||||
|
Interest expense
|
(222.1 | ) | (201.2 | ) | (20.9 | ) | (10.4 | )% | ||||||||
|
Interest income
|
9.6 | 8.1 | 1.5 | 18.5 | % | |||||||||||
|
Income from continuing operations before income taxes
|
$ | 1,113.2 | $ | 651.7 | $ | 461.5 | 70.8 | % | ||||||||
| (1) | Corporate and Other Adjusted EBITDA results include selling and administrative expenses, equity income (loss) from our joint ventures, net gains on asset disposals or exchanges, costs associated with past mining obligations and revenues and expenses related to our other commercial activities such as generation development and Btu Conversion development costs. |
Income from continuing operations before income taxes was higher
compared to the prior year primarily due to the higher Total
Segment Adjusted EBITDA discussed above, partially offset by
lower Corporate and Other Adjusted EBITDA and higher
depreciation, depletion and amortization expense and interest
expense as discussed below:
| • | Corporate and Other Adjusted EBITDA: higher expense was primarily driven by a current year increase in selling and administrative expenses due to costs to support our business development and international expansion (e.g. headcount, travel, professional services, legal). We also incurred increased post mining costs driven by higher retiree healthcare amortization of actuarial losses and interest cost. These items were partially offset by improved results from equity affiliates primarily due to prior year losses of $54.6 million related to our equity investment in Carbones del Guasare, which included a $34.7 million impairment loss and $19.9 million of operating losses. See Note 1 to our consolidated financial statements for additional information. |
39
Table of Contents
| • | Depreciation, depletion and amortization: higher compared to the prior year due to increased production at our Australian mines with higher per-ton depletion rates reflecting higher demand and additional depreciation expense associated with our new Bear Run Mine (commissioned in the second quarter of 2010). | |
| • | Interest expense: higher primarily due to refinancing charges ($9.3 million) associated with our new five-year Credit Facility and charges ($8.4 million) associated with the extinguishment and refinancing of $650.0 million of senior notes. |
Net
Income Attributable to Common Stockholders
The following table presents net income attributable to common
stockholders for the years ended December 31, 2010 and 2009:
|
Increase (Decrease)
|
||||||||||||||||
| Year Ended December 31, | to Income | |||||||||||||||
| 2010 | 2009 | $ | % | |||||||||||||
| (Dollars in millions) | ||||||||||||||||
|
Income from continuing operations before income taxes
|
$ | 1,113.2 | $ | 651.7 | $ | 461.5 | 70.8 | % | ||||||||
|
Income tax provision
|
(308.1 | ) | (193.8 | ) | (114.3 | ) | (59.0 | )% | ||||||||
|
Income from continuing operations, net of income taxes
|
805.1 | 457.9 | 347.2 | 75.8 | % | |||||||||||
|
Income (loss) from discontinued operations, net of income taxes
|
(2.9 | ) | 5.1 | (8.0 | ) | 156.9 | % | |||||||||
|
Net income
|
802.2 | 463.0 | 339.2 | 73.3 | % | |||||||||||
|
Net income attributable to noncontrolling interests
|
(28.2 | ) | (14.8 | ) | (13.4 | ) | (90.5 | )% | ||||||||
|
Net income attributable to common stockholders
|
$ | 774.0 | $ | 448.2 | $ | 325.8 | 72.7 | % | ||||||||
Net income attributable to common stockholders increased
compared to the prior year due to the increased income from
continuing operations before income taxes as discussed above.
Income tax provision was impacted by the following:
| • | Increased expense due to higher current year earnings ($161.5 million) and current year income tax resulting from foreign earnings repatriation ($84.5 million), partially offset by | |
| • | A change in the valuation allowance ($46.4 million) related primarily to alternative minimum tax credits, lower expense associated with the remeasurement of non-U.S. tax accounts as a result of the larger increase in the Australian exchange rate against the U.S. dollar in the prior year compared to the current year ($26.8 million) as set forth in the table below, the favorable rate difference resulting from higher foreign generated income in the current year ($42.5 million), and lower expense in the current year due to the reduction of our gross unrecognized tax benefit resulting from the completion of the Internal Revenue Service examination of the 2005 federal income tax year ($15.2 million). |
| December 31, | Rate Change | |||||||||||||||||||
| 2010 | 2009 | 2008 | 2010 | 2009 | ||||||||||||||||
|
Australian dollar to U.S. dollar exchange rate
|
$ | 1.0163 | $ | 0.8969 | $ | 0.6928 | $ | 0.1194 | $ | 0.2041 | ||||||||||
Income (loss) from discontinued operations for 2010 reflects a
loss of $2.9 million as compared to income of
$5.1 million in 2009 due primarily to a coal excise tax
refund receivable of approximately $35 million recorded in
2009, partially offset by operating losses and loss on disposal
of our Australian Chain Valley Mine in 2009.
40
Table of Contents
Other
The fair value of our foreign currency hedges increased
approximately $434 million in 2010 mostly due to the
strengthening of the Australian dollar against the
U.S. dollar in the current year. The increase is reflected
in “Other current assets” and “Investments and
other assets” in the consolidated balance sheets.
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 third highest in our
127-year
history, only trailing 2008 and 2010. We also ended 2009 with
total available liquidity of $2.5 billion. We continued 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.
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 | )% | ||||||||||
41
Table of Contents
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 | )% | ||||||||||
|
Corporate and 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 the 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 the 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 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. |
42
Table of Contents
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 the
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
(1)
|
(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 | )% | |||||||
43
Table of Contents
| (1) | Corporate and Other Adjusted EBITDA results include selling and administrative expenses, equity income (loss) from our joint ventures, net gains on asset disposals or exchanges, costs associated with past mining obligations and revenues and expenses related to our other commercial activities such as generation development and Btu Conversion development costs. |
Income from continuing operations before income taxes decreased
from the 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. | |
| • | 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 the prior year due to lower
variable interest rates on our Term Loan Facility and accounts
receivable securitization program and lower average borrowings
on our Revolver.
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)
|
||||||||||||||||
| Year Ended December 31, | 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 | )% | |||||||
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Table of Contents
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.
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.
Outlook
Near-Term
Outlook
The World Bank estimates global economic activity, as measured
by gross domestic product (GDP), expanded 3.9% in 2010. Global
GDP is projected to grow another 3.3% in 2011 and 3.6% in 2012,
with developing economies, led by China and India, expanding 6%
or more in each year, more than twice the growth expected for
high income countries. China’s GDP is projected by the
World Bank to grow 10.0% in 2010 and 8.7% in 2011. India, the
world’s second fastest growing economy, is projected by the
World Bank to grow 9.5% in 2010 and 8.4% in 2011.
| • | According to the World Steel Association (WSA), global steel use was expected to increase 13.1% in 2010, followed by another 5.3% in 2011 to a record 1.3 billion tonnes. The WSA forecasts India’s steel demand would rise 8.2% in 2010 and 13.6% in 2011. Similar trends are apparent in steel production. For 2010, global steel production exceeded prior year levels by 15%, led by Asia-based production (Japan, Taiwan, South Korea, China and India). Industry reports indicate China, the world’s largest steel consumer, is expected to grow its steel use 11% in 2010, and is projected to grow a further 8% to 9% in 2011. | |
| • | Industry reports forecast nearly 85 gigawatts of new coal-fueled generation globally were due to come on line during 2010; nearly 80% of which were in China and India. New global coal-fueled generation for 2010 is estimated to require approximately 290 million tons of coal annually. For 2011, approximately 90 gigawatts are expected to be under construction and/or come online, requiring more than 340 million tons of coal. China and India continue to make up the vast majority. | |
| • | Given the pace of coal demand in the Pacific throughout 2010, coupled with late-2010 weather-related demand increases in the Northern Hemisphere and supply constraints in key nations such as Australia, Indonesia, South Africa, South America and Canada, prices for seaborne metallurgical and thermal coal |
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| have been increasing. High quality, hard coking coal prices have increased from $129 per tonne for annual contracts commencing April 2009, to quarterly (April, July, October 2010) prices ranging between $200 and $225 per tonne, with January 2011 spot price exceeding $350 per tonne. Prompt index prices for Australian seaborne thermal coal rose 34% by year-end 2010, and have risen another 10% as of January 18, 2011. |
Accordingly to the Energy Information Administration’s
(EIA) Short-Term Energy Outlook, 2011 coal consumption, coal
production and utility coal stockpiles in the U.S. are
projected to be essentially on par with 2010. U.S. growth
is projected to resume in 2012, with the increased consumption
being matched by higher production, resulting in minimal change
to utility coal stockpiles.
U.S. natural gas consumption increased 5.5% and production
rose approximately 4% in 2010, according to the EIA. Rising
supplies combined with persistently high inventory levels have
resulted in subdued gas prices. The NYMEX — Henry Hub
spot price averaged $4.52 per thousand cubic feet in 2010, above
2009’s average $4.06 per thousand cubic feet yet 67% below
the 2007 — 2009 average.
The EIA also projects that natural gas consumption, production
and storage levels will decline slightly in 2011. Like coal,
natural gas consumption is expected to grow in 2012,
approximately 1.6% to 66.5 billion cubic feet. The
projected production decline in 2011 and higher natural gas
consumption in 2012 are expected to lead to strengthening
natural gas prices. As natural gas prices begin to rise, natural
gas production is expected to rebound, growing approximately 2%
in 2012.
U.S. shale natural gas development continues in the
U.S. accounting for approximately 20% of gas supply in 2010
and is estimated by the PIRA Energy Group to grow to over 30% of
gas supply over the next several years. This is expected to lead
to continued growth in gas-fired electricity in the U.S.
As of January 25, 2011, we had 7 to 8 million tons of
our targeted 2011 metallurgical coal volumes and 6 to
7 million tons of our planned seaborne thermal coal volumes
available for pricing in the last three quarters of 2011. For
2012, all of our expected metallurgical coal sales and 12 to
13 million tons of our estimated seaborne thermal coal
sales are available to price. In the U.S., we have modest
amounts of coal to price in 2011, 35% to 40% in 2012 and 75% to
85% in 2013. We may continue to adjust our production levels in
response to change in market demand.
We continue to manage costs and operating performance in an
effort to mitigate external cost pressures, geologic conditions
and potential shipping delays resulting from adverse port and
rail performance. We may have higher per ton costs as a result
of suboptimal 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. Reductions in the relative cost of other fuels,
including natural gas, could impact the use of coal for
electricity generation. See Cautionary Notice Regarding
Forward-Looking Statements and Item 1A. “Risk
Factors” of this report for additional considerations
regarding our outlook.
We rely on ongoing access to 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, bank guarantees, 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.
Dodd-Frank Act.
On July 21, 2010, President Obama
signed into law the Dodd-Frank Act, which includes a number of
provisions applicable to us in the areas of corporate
governance, executive compensation and mine safety and
extractive industries disclosure. In addition, the Dodd-Frank
Act imposes additional regulation
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of financial derivatives transactions that may apply to our
hedging and our Trading and Brokerage activities. Although the
Dodd-Frank Act became generally effective upon its enactment,
many provisions have extended implementation periods and delayed
effective dates and require further action by the federal
regulatory authorities. As a result, in many respects the
ultimate impact of the Dodd-Frank Act on us will not be fully
known for an extended period of time. We do expect that the
Dodd-Frank Act will increase compliance and transaction costs
associated with our hedging and Trading and Brokerage activities.
Minerals Resource Rent Tax.
On May 2,
2010, the Australian government released a report on
Australia’s Future Tax System, which included a
recommendation to replace the current resource taxing
arrangements imposed on non-renewable resources by the
Australian federal and state governments with a uniform resource
rent tax (the Resource Tax) imposed and administered by the
Australian government. As proposed, the Resource Tax would be
profit-based and would apply to non-renewable resources
projects, including existing projects. On July 2, 2010, the
Australian government announced changes to the Resource Tax and
proposed a new minerals resource rent tax (the MRRT). The MRRT
would still be profit-based, but measures were introduced to
lessen the impact of the MRRT. The Australian government and
major industry policy makers are actively engaged to work
through various structural aspects of the proposed MRRT together
with detailed implementation issues. The Committee charged with
consulting with industry and preparing recommendations as to the
final form of the MRRT submitted its report in late December
2010. The Committee’s recommendations largely endorse the
mining industry’s understanding as to what was agreed with
the federal government prior to the federal election. The
Committee’s recommendations notwithstanding, it remains to
be seen whether the federal government will adopt all
recommendations, in particular the recommendation that all state
royalties (current and future) are creditable against MRRT
payments. MRRT is not yet law in Australia; exposure draft
legislation is expected in mid-2011. Following the release of
the draft legislation, industry participants will engage in
further consultation with the federal government as required.
The draft law is expected to be presented to the Australian
Parliament in late 2011, and if the MRRT becomes law, it is
intended to become effective July 1, 2012. If the MRRT were
to become law, it may affect the financial performance of our
Australian operations from the effective date forward.
Long-Term
Outlook
Our long-term global outlook remains positive. According to the
BP Statistical Review of World Energy, coal has been the
fastest-growing fuel in the world for the past decade.
The International Energy Agency (IEA) estimates in its World
Energy Outlook issued in November 2010, current policies
scenario, that world primary energy demand will grow 47% between
2008 and 2035. Demand for coal is projected to rise 59%,
outpacing the growth rate of oil, natural gas, nuclear, hydro
and biomass. China and India alone account for more than 85% of
the 2008 — 2035 coal-based primary energy demand
growth.
Under the current policies scenario, the IEA expects coal to
retain its strong presence as a fuel for the power sector
worldwide. Coal’s share of the power generation mix was 41%
in 2008. By 2035, the IEA estimates coal’s fuel share to be
43% as it continues to have the largest share of worldwide
electric power production. Currently, we estimate approximately
390 gigawatts of coal-fueled electricity generating plants are
planned or under construction around the world, with expected
online dates ranging between 2011 and 2015. When complete, those
plants would require an estimated 1.4 billion tons of
annual coal demand. In the U.S., while some planned coal-based
plants have been cancelled, 13 gigawatts of new coal-based
generating capacity have been completed in 2010 or are under
construction with completion dates of 2011 — 2013,
representing approximately 55 million tons of annual coal
demand once they become operational.
The IEA projects global natural gas-fueled electricity
generation will have a compound annual growth rate of 2.5%, from
4.3 trillion kilowatt hours in 2008 to 8.3 trillion kilowatt
hours in 2035. The total amount of electricity generated from
natural gas is expected to be approximately one-half the total
for coal, even in 2035. Renewables are projected to comprise 23%
of the 2035 fuel mix versus 19% in 2008. Nuclear power is
expected to grow 52%, however its share of total generation is
expected to fall from 13.5% to 11% between
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2008 and 2035. Generation from liquid fuels is projected to
decline an average of 2.2% annually to 1.5% of the 2035
generation mix.
We believe that Btu Conversion applications such as CTG and CTL
plants represent an avenue for potential long-term industry
growth. Several CTG and CTL facilities are currently under
development in China and India.
We continue to support clean coal technology development toward
the ultimate goal of near-zero emissions, and we are advancing
more than a dozen projects and partnerships 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 five to ten commercial CCS projects by
2016.
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 force 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.
Liquidity
and Capital Resources
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.
Along with cash and cash equivalents, our liquidity includes the
available balances from our Revolver under the Credit Facility,
accounts receivable securitization program and a bank overdraft
facility in Australia. Our liquidity is also impacted by
activity under certain bilateral cash collateralization
arrangements. As of December 31, 2010, we had cash and cash
equivalents of $1.3 billion and our total available
liquidity was $2.7 billion. We currently expect that our
cash on hand, cash flow from operations and available liquidity
will be sufficient to meet our anticipated capital requirements
during the next 12 months and for the foreseeable future,
as described below in ’Capital Requirements.’ In
addition to the above items, alternative sources of liquidity
include the ability to offer and sell certain securities under
our shelf registration (as described below).
In 2010, we replaced our previous $1.8 billion revolving
credit facility with a $1.5 billion Revolver under a new
Credit Facility (as described below). Also, additional
information on our accounts receivable securitization program
and bilateral cash collateralization arrangements can be found
in the “Off-Balance Sheet Arrangements” section.
Credit Facility.
On June 18, 2010, we
entered into a Credit Agreement which established a
$2.0 billion Credit Facility and replaced our third amended
and restated credit agreement dated September 15, 2006. The
Credit Agreement provides for a $1.5 billion Revolver and a
$500.0 million term loan facility (Term Loan). We have the
option to request an increase in the capacity of the Credit
Facility (but no lender is obligated to increase its commitment
to us), provided the aggregate increase for the Revolver and
Term Loan does not exceed $250.0 million, the minimum
amount of the increase is $25.0 million, and certain other
conditions are met under the Credit Agreement. The Revolver also
includes a swingline
sub-facility
where up to $50.0 million is available for
same-day
borrowings. The Revolver commitments and the Term Loan under the
Credit Facility will mature on June 18, 2015. The Term Loan
is subject to quarterly repayment of 1.25% per quarter beginning
in the fourth quarter of 2010, with the final payment of all
amounts outstanding (including accrued interest) being due five
years from the date of the execution of the Credit Agreement.
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The Revolver replaced our previous $1.8 billion revolving
credit facility and the Term Loan replaced our previous term
loan facility (the previous term loan had a balance of
$490.3 million at the time of replacement and at
December 31, 2009). We recorded $21.9 million in
deferred financing costs which are being amortized to interest
expense over the five year term of the Credit Facility, and
incurred refinancing charges of $9.3 million, which is
classified as interest expense in the consolidated statements of
operations.
There were no borrowings outstanding under the Revolver in 2010
or 2009, or at December 31, 2010. However, we had
$67.6 million of outstanding letters of credit as of
December 31, 2010, which effectively reduced our borrowing
capacity under the Revolver by the same amount.
See Note 8 to our consolidated financial statements for
additional information on the new Credit Facility.
Shelf Registration.
We have an effective shelf
registration statement on file with the SEC for an indeterminate
number of securities that is effective for three years (expires
August 7, 2012), 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
Requirements
Our primary uses of cash include our cash costs of coal
production, capital expenditures, coal reserve lease and royalty
payments, debt service costs (interest and principal), lease
obligations, take or pay obligations and costs related to past
mining obligations. Future dividends and share repurchases,
among other restricted items, are subject to limitations imposed
in the covenants of certain of our debt instruments. We
generally fund our capital expenditure requirements with cash
generated from operations.
Capital Expenditures.
Capital expenditures for 2011 are
anticipated to be $900 to $950 million; including $500 to
$550 million earmarked for new mines, expansion and
extension projects. Approximately 70% of the growth and
expansion capital is targeted for various Australian projects
for metallurgical and thermal coal, with the remainder in the
U.S. Estimated capital expenditures also include funding
for our share of construction costs for Prairie State.
Prairie State.
We spent $76.0 million during 2010
representing our 5.06% share of the construction costs. Included
in “Investments and other assets” in the consolidated
balance sheets as of December 31, 2010 and 2009, are costs
of $202.5 million and $126.5 million, respectively.
Our share of total construction costs for Prairie State is
expected to be approximately $250 million, with most of the
remaining funding expected in 2011.
GreenGen.
During 2010, we spent $3.1 million
representing our 6.0% share of the construction costs, which is
reflected as capitalized development costs as part of
“Investments and other assets” in the consolidated
balance sheet. There were no expenditures for GreenGen for 2009.
Our share of total construction costs for GreenGen is expected
to be approximately $60 million.
Dividends.
We have declared and paid quarterly dividends
since our initial public offering in 2001. In January 2011, our
Board of Directors approved a dividend of $0.085 per share of
common stock, payable on March 3, 2011. 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.
Pension Contributions.
During 2010, we made contributions
of $112.6 million, which includes our estimate of required
contributions for 2011 (based on current assumptions).
Share Repurchase Program.
At December 31, 2010, our
available capacity for share repurchases was
$700.4 million, and our Chairman and Chief Executive
Officer has authority to direct us to repurchase up to
$100 million of our common stock outside of the share
repurchase program. While no such share repurchases were made in
2010, 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.
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NCIG.
Financing for phase one of stage two of
construction closed in 2010 with us providing our pro-rata share
of funding of $59.7 million Australian dollars
($54.8 million U.S. dollars). NCIG may further expand
the coal transloading facility’s capacity which could
require us to fund our pro-rata share in a similar manner.
Senior Notes.
On August 25, 2010, we completed a
$650.0 million offering of 6.5%
10-year
Senior Notes due September 2020 (the Notes). The Notes are
senior unsecured obligations and rank senior in right of payment
to any subordinated indebtedness; equally in right of payment
with any senior indebtedness; effectively junior in right of
payment to our future secured indebtedness, to the extent of the
value of the collateral securing that indebtedness; and
effectively junior to all the indebtedness and other liabilities
of our subsidiaries that do not guarantee the Notes. Interest
payments are scheduled to occur on March 15 and September 15 of
each year, commencing on March 15, 2011.
The Notes are jointly and severally guaranteed by nearly all of
our domestic subsidiaries, as defined in the note indenture. The
note indenture contains covenants that, among other things,
limit our ability to create liens and enter into sale and
lease-back transactions. The Notes are redeemable at a
redemption price equal to 100% of the principal amount of the
Notes being redeemed plus a make-whole premium and any accrued
unpaid interest to the redemption date.
We used the net proceeds from the issuance of the Notes, after
deducting underwriting discounts and expenses, and cash on hand,
to extinguish our previously outstanding $650.0 million
aggregate principal 6.875% Senior Notes formerly due in
March 2013 (the 2013 Notes). All of the 2013 Notes were either
tendered or redeemed in 2010. We recognized debt extinguishment
costs of $8.4 million, which are classified as interest
expense in the consolidated statements of operations. The
issuance of the Notes and the extinguishment of the 2013 Notes
allowed us to lengthen the maturity of our senior indebtedness
and lower the coupon rate.
See Note 8 to our consolidated financial statements for
additional information on the Notes.
Total Indebtedness.
Our total indebtedness as
of December 31, 2010 and 2009, consisted of the following:
| December 31, | ||||||||
| 2010 | 2009 | |||||||
| (Dollars in millions) | ||||||||
|
Term Loan
|
$ | 493.8 | $ | 490.3 | ||||
|
6.875% Senior Notes due March 2013
|
— | 650.0 | ||||||
|
5.875% Senior Notes due April 2016
|
218.1 | 218.1 | ||||||
|
7.375% Senior Notes due November 2016
|
650.0 | 650.0 | ||||||
|
6.5% Senior Notes due September 2020
|
650.0 | — | ||||||
|
7.875% Senior Notes due November 2026
|
247.2 | 247.1 | ||||||
|
6.34% Series B Bonds due December 2014
|
12.0 | 15.0 | ||||||
|
6.84% Series C Bonds due December 2016
|
33.0 | 33.0 | ||||||
|
Convertible Junior Subordinated Debentures due 2066
|
373.3 | 371.5 | ||||||
|
Capital lease obligations
|
69.6 | 67.5 | ||||||
|
Fair value hedge adjustment
|
2.2 | 8.4 | ||||||
|
Other
|
0.8 | 1.4 | ||||||
|
Total
|
$ | 2,750.0 | $ | 2,752.3 | ||||
We were in compliance with all of the covenants of the Credit
Facility, the 5.875% Senior Notes, the 7.375% Senior
Notes, the 6.5% Senior Notes, the 7.875% Senior Notes
and the Debentures as of December 31, 2010.
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Historical
Cash Flows
|
Increase (Decrease) to
|
||||||||||||||||
| Year Ended December 31, | Cash Flow | |||||||||||||||
| 2010 | 2009 | $ | % | |||||||||||||
| (Dollars in millions) | ||||||||||||||||
|
Net cash provided by operating activities
|
$ | 1,087.1 | $ | 1,050.2 | $ | 36.9 | 3.5 | % | ||||||||
|
Net cash used in investing activities
|
(703.6 | ) | (406.5 | ) | (297.1 | ) | 73.1 | % | ||||||||
|
Net cash used in financing activities
|
(77.1 | ) | (104.6 | ) | 27.5 | (26.3 | )% | |||||||||
Operating Activities.
The changes from the
prior year were driven by the following:
| • | Strong operating cash flows generated from our Australian Mining operations driven by higher volumes and pricing; partially offset by | |
| • | Increased margin posted for our derivative trading instruments; | |
| • | Lower utilization of our accounts receivable securitization program in the current year; and | |
| • | Higher pension payments in the current year. |
Investing Activities.
The changes from the
prior year were driven by the following:
| • | Higher current year capital spending of $296.4 million related primarily to our Bear Run Mine; | |
| • | Current year net cash outflows related to our pro-rata share of funding for the NCIG coal transloading facility; and | |
| • | The collection of a note receivable of $30.0 million in the prior year; partially offset by | |
| • | Federal coal lease expenditures of $123.6 million in the prior year. |
Financing Activities.
The increase compared to
the prior year was primarily due to the excess tax benefits
related to share-based compensation of $51.0 million,
partially offset by the payment of debt issuance costs of
$32.2 million in the current year related to our Credit
Facility refinancing and the offering of the Notes. The proceeds
from long-term debt include $500.0 million from the Term
Loan and $641.9 million of net proceeds from the issuance
of the Notes. These proceeds were used to pay off the
$490.3 million balance due on our previous term loan
facility and the previously outstanding $650.0 million 2013
Notes.
Other Long-Term Debt.
A description of our
other debt instruments is described in Note 8 to the
consolidated financial statements.
Contractual
Obligations
The following is a summary of our contractual obligations as of
December 31, 2010:
| Payments Due By Year | ||||||||||||||||||||
|
Less than
|
2 - 3
|
4 - 5
|
More than
|
|||||||||||||||||
| Total | 1 Year | Years | Years | 5 Years | ||||||||||||||||
| (Dollars in millions) | ||||||||||||||||||||
|
Long-term debt obligations (principal and interest)
|
$ | 5,621.6 | $ | 213.4 | $ | 436.6 | $ | 789.4 | $ | 4,182.2 | ||||||||||
|
Capital lease obligations (principal and interest)
|
74.6 | 17.0 | 42.1 | 15.5 | — | |||||||||||||||
|
Operating lease obligations
|
455.8 | 95.6 | 147.2 | 106.1 | 106.9 | |||||||||||||||
|
Unconditional purchase
obligations
(1)
|
458.2 | 406.7 | 51.5 | — | — | |||||||||||||||
|
Coal reserve lease and royalty obligations
|
62.0 | 7.2 | 14.3 | 10.2 | 30.3 | |||||||||||||||
|
Take or pay
obligations
(2)
|
2,892.9 | 217.5 | 465.9 | 425.7 | 1,783.8 | |||||||||||||||
|
Other long-term
liabilities
(3)
|
2,204.1 | 154.6 | 301.7 | 298.7 | 1,449.1 | |||||||||||||||
|
Total contractual cash obligations
|
$ | 11,769.2 | $ | 1,112.0 | $ | 1,459.3 | $ | 1,645.6 | $ | 7,552.3 | ||||||||||
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| (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. The purchase obligations for capital expenditures relate to new mines and expansion and extension projects in Australia and the U.S. | |
| (2) | Represents various long- and short-term take or pay arrangements associated with rail and port commitments for the delivery of coal including amounts relating to export facilities. | |
| (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. |
We do not expect any of the $111.0 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.
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, bank
guarantees and surety bonds and our accounts receivable
securitization program. 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.
Accounts Receivable Securitization.
We have an
accounts receivable securitization program (securitization
program) through our wholly-owned, bankruptcy-remote subsidiary
(Seller). Under the securitization program, beginning in 2010,
we contribute, on a revolving basis, trade receivables of most
of our U.S. subsidiaries to the Seller, which then sells
the receivables in their entirety to a consortium of
unaffiliated asset-backed commercial paper conduits (the
Conduits). After the sale, we, as servicer of the assets,
collect the receivables on behalf of the Conduits for a nominal
servicing fee. We utilize proceeds from the sale of our accounts
receivable as an alternative to short-term borrowings under our
Credit Facility, effectively managing our overall borrowing
costs and providing an additional source for working capital.
The securitization program was renewed in May 2009 and amended
in December 2009 in order to qualify for sale accounting under a
newly adopted accounting standard related to financial asset
transfers. Prior to amending the securitization program, we sold
senior undivided interests in certain of our accounts receivable
and retained subordinated interests in those receivables. The
current securitization program 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 Seller is a separate legal entity whose assets are available
first and foremost to satisfy the claims of its creditors. Of
the receivables sold to the Conduits, a portion of the amount
due to the Seller is deferred until the ultimate collection of
the underlying receivables. During the year ended
December 31, 2010, we received total consideration of
$4,576.3 million related to accounts receivable sold under
the securitization program, including $2,460.1 million of
cash up front from the sale of the receivables, an additional
$1,953.6 million of cash upon the collection of the
underlying receivables, and $162.6 million that had not
been collected at December 31, 2010 and was recorded at
fair value, which approximates carrying value. The reduction in
accounts receivable as a result of securitization activity with
the Conduits was $150.0 million at December 31, 2010
and $254.6 million at December 31, 2009.
The securitization activity has been reflected in the
consolidated statements of cash flows as operating activity
because both the cash received from the Conduits upon sale of
receivables as well as the cash received from the Conduits upon
the ultimate collection of receivables are not subject to
significantly different risks given the short-term nature of our
trade receivables. We recorded expense associated with
securitization
52
Table of Contents
transactions of $2.4 million, $4.0 million and
$10.8 million for the years ended December 31, 2010,
2009 and 2008, respectively.
Other Off-Balance Sheet Arrangements.
In 2010,
we added standalone credit facilities with multiple banks to
allow us to obtain letters of credit and bank guarantees in
support of certain operations outside the U.S. As of
December 31, 2010, the total capacity under these new
facilities, both committed and uncommitted, was approximately
$324 million, of which approximately $141 million was
utilized (based on the U.S. dollar exchange rate at
December 31, 2010). Also during 2010, we entered into a
bilateral cash collateralized agreement in support of certain
letters of credit whereby we posted cash collateral in lieu of
utilizing our Credit Facility. Such cash collateral is
classified within cash and cash equivalents given our ability to
substitute letters of credit at any time for this cash
collateral.
See Note 19 to our consolidated financial statements for a
discussion of our guarantees.
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 U.S. GAAP. We are also required under U.S. GAAP
to 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.
Postretirement Benefit and Pension
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 11 and 12 to our
consolidated financial statements. Liabilities for
postretirement benefit costs are not funded. Our pension
obligations are funded in accordance with the provisions of
applicable law. Expense for the year ended December 31,
2010 for pension and postretirement liabilities totaled
$115.6 million, while funding payments were
$187.9 million.
Each of these liabilities is 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)
|
$ | 7.8 | $ | (6.6 | ) | |||
|
Effect on total postretirement benefit
obligation
(1)
|
$ | 112.5 | $ | (94.4 | ) | |||
53
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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)
|
$ | (51.1 | ) | $ | 58.8 | |||
| (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 11.93 years at December 31, 2010. |
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, 2010 was $48.5 million, and
payments totaled $14.1 million. See Note 10 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 level hierarchy, Levels 1, 2 and 3.
Level 3 fair value measurements are those where inputs are
unobservable, or observable but cannot be market-corroborated,
requiring us to make assumptions about pricing by market
participants. 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
54
Table of Contents
forward pricing curve quotes from one to three reputable
brokers. Our valuation techniques also include basis 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, 2010 and 2009, 3% and 5%, respectively, of
our net financial assets were categorized as Level 3. See
Notes 4 and 5 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, 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 direct and brokered trading of coal, ocean freight
and fuel-related commodities in
over-the-counter
markets (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, 2010 and 2009.
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.
In 2010, we modified our VaR methodology to be in line with our
global trading strategy. The previous methodology used an
additive approach whereby the domestic portfolio and the
international portfolio were calculated separately and then
added together to arrive at our total global VaR. The new
methodology explicitly considers correlation measures between
the domestic and the international portfolios to consolidate our
total global VaR. The high, low and average VaR for the year
ended December 31, 2010 is set forth in the table below
under the previous and new methodology :
| Year Ended December 31, 2010 | Low | High | Average | |||||||||
| (Dollars in millions) | ||||||||||||
|
Previous Methodology
|
$ | 4.5 | $ | 37.6 | $ | 10.1 | ||||||
|
New Methodology
|
$ | 3.4 | $ | 18.8 | $ | 7.0 | ||||||
As of December 31, 2010, the timing of the estimated future
realization of the value of our trading portfolio was as follows:
|
Year of
|
Percentage of
|
|||
| Expiration | Portfolio Total | |||
|
2011
|
70 | % | ||
|
2012
|
21 | % | ||
|
2013
|
3 | % | ||
|
2014
|
4 | % | ||
|
2015
|
2 | % | ||
| 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
Coal Trading.
The fair value of our coal trading assets
and liabilities reflects adjustments for nonperformance and
credit risk. Our exposure is substantially with electric
utilities, 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
(margin), requiring prepayments for shipments or the
56
Table of Contents
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.
Non-Coal Trading.
The fair value of our non-coal trading
derivative assets and liabilities also reflects adjustments for
nonperformance and credit risk. We conduct our hedging
activities related to foreign currency, interest rate, fuel and
explosives exposures with a variety of highly-rated commercial
banks and closely monitor counterparty creditworthiness. To
reduce our credit exposure for these hedging activities, we seek
to enter into netting agreements with counterparties that permit
us to offset receivables and payables with such counterparties.
Foreign
Currency Risk
We utilize currency forwards to hedge currency risk associated
with anticipated Australian dollar expenditures. The accounting
for these derivatives is discussed in Note 4 to our
consolidated financial statements. Assuming we had no hedges in
place, our exposure in operating costs and expenses due to a
$0.10 change in the Australian dollar/U.S. dollar exchange
rate is approximately $208 million for 2011. However,
taking into consideration hedges currently in place, our net
exposure to the same rate change is approximately
$60 million for 2011. The table at the end of Item 7A
shows the notional amount of our hedge contracts as of
December 31, 2010.
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. From time to
time, we manage our debt to achieve a certain ratio of
fixed-rate debt and variable-rate debt as a percent of net debt
through the use of various hedging instruments, which are
discussed in detail in Note 4 to our consolidated financial
statements. As of December 31, 2010, we had
$2.3 billion of fixed-rate borrowings and $0.5 billion
of variable-rate borrowings outstanding and had no interest rate
swaps in place. A one percentage point increase in interest
rates would result in an annualized increase to interest expense
of approximately $5 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 $163 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. Sales under such agreements comprised
approximately 91%, 93% and 90% of our worldwide sales (by
volume) for the years ended December 31, 2010, 2009 and
2008, respectively. Substantially all of our coal in the U.S is
contracted in 2011 at planned production levels. We had 13 to
15 million tons remaining to be priced for 2011 in
Australia at January 25, 2011.
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 cost pass-through contracts and
derivatives, primarily swaps.
Notional amounts outstanding under fuel-related, derivative swap
contracts are noted in the table at the end of Item 7A. We
expect to consume 145 to 150 million gallons of diesel fuel
in 2011. 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 $36 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.
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Table of Contents
Notional amounts outstanding under explosives-related swap
contracts are noted in the table at the end of Item 7A. We
expect to consume 355,000 to 365,000 tons of explosives during
2011 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
$2 million.
Notional Amounts and Fair Value.
The following
summarizes our interest rate, foreign currency and commodity
positions at December 31, 2010:
| Notional Amount by Year of Maturity | ||||||||||||||||||||||||||||
| Total | 2011 | 2012 | 2013 | 2014 | 2015 | 2016 and thereafter | ||||||||||||||||||||||
|
Foreign Currency
|
||||||||||||||||||||||||||||
|
A$:US$ hedge contracts (A$ millions)
|
$ | 4,187.5 | $ | 1,484.2 | $ | 1,355.2 | $ | 926.6 | $ | 421.5 | $ | — | $ | — | ||||||||||||||
|
Commodity Contracts
|
||||||||||||||||||||||||||||
|
Diesel fuel hedge contracts (million gallons)
|
191.4 | 89.5 | 76.2 | 25.7 | — | — | — | |||||||||||||||||||||
|
U.S. explosives hedge contracts (million MMBtu)
|
8.4 | 3.9 | 3.0 | 1.5 | — | — | — | |||||||||||||||||||||
| Account Classification by | |||||||||||||||||
|
Cash flow
|
Fair value
|
Economic
|
Fair Value Asset
|
||||||||||||||
| hedge | hedge | hedge | (Liability) | ||||||||||||||
|
(Dollars in
|
|||||||||||||||||
| millions) | |||||||||||||||||
|
Foreign Currency
|
|||||||||||||||||
|
A$:US$ hedge contracts (A$ millions)
|
$ | 4,187.5 | $ | — | $ | — | $ | 640.1 | |||||||||
|
Commodity Contracts
|
|||||||||||||||||
|
Diesel fuel hedge contracts (million gallons)
|
191.4 | — | — | $ | 40.3 | ||||||||||||
|
U.S. explosives hedge contracts (million MMBtu)
|
8.4 | — | — | $ | (0.1 | ) | |||||||||||
| 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, 2010, 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, 2010, and concluded that such controls and
procedures are effective to provide reasonable assurance that
the desired control objectives were achieved.
58
Table of Contents
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 three months
ended December 31, 2010 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 was effective to provide reasonable assurance that the
desired control objectives were achieved as of December 31,
2010.
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 28, 2011
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, 2010, 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, 2010, 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, 2010 and 2009, 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, 2010 and our report dated February 28,
2011, expressed an unqualified opinion thereon.
/s/
Ernst &
Young LLP
St. Louis, Missouri
February 28, 2011
60
Table of Contents
| Item 9B. | Other Information. |
Mine Safety Disclosures
As discussed in Item 1. “Business,” our goal is
to operate free of injuries, occupational illnesses, property
damage and near misses. Safety is a core value that is
integrated into all areas of our business. One of the ways we
monitor safety performance is by incidence rate, which is
tracked through our safety tracking system. We compute the
incidence rate as the number of injuries (MSHA injury degree
code 1 to 6) divided into employee hours worked, multiplied
by 200,000 hours. Our incidence rate excludes the injuries
and hours associated with office workers. The following table
reflects our incidence rates and the comparable MSHA incidence
rates.
| Year Ended December 31, | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
|
U.S.
|
1.95 | 2.08 | 1.70 | |||||||||
|
Australia
|
4.03 | 4.43 | 7.24 | |||||||||
|
Total Peabody Energy Corporation
|
2.69 | 2.87 | 3.55 | |||||||||
|
MSHA
|
3.86 | 4.14 | 4.41 | |||||||||
For the U.S., the comparable MSHA incidence rate is from
MSHA’s Mine Injury and Worktime Operators report and
represents the all incidence rate for all U.S. coal mines,
excluding the impact of office workers (“All Incidence
Rate”). The 2010 MSHA all incidence rate of 3.86 reflected
above represents preliminary results as published by MSHA as of
February 18, 2011.
We monitor MSHA compliance using violations per inspection day
(in the U.S. only). We measure one inspection day for each
visit to one of our mines by a MSHA inspector. For the years
ended December 31, 2010, 2009 and 2008, our
U.S. violations per inspection day were 1.25, 1.51 and
1.49, respectively.
The following disclosures are provided pursuant to the recently
enacted Dodd-Frank Act, which requires certain disclosures by
companies required to file periodic reports under the Securities
Exchange Act of 1934, as amended, that operate coal mines
regulated under the Federal Mine Safety and Health Act of 1977
(the Mine Act). The disclosures reflect U.S. mining
operations only as the requirements of the Dodd-Frank Act do not
apply to our mines operated outside the U.S. Under the
Dodd-Frank Act, the SEC is authorized to issue rules and
regulations to carry out the purposes of these provisions. In
December 2010, the SEC issued a proposed rule for the mine
safety disclosures. As of the filing date of this report, the
proposed rule was still in the comment period phase.
Mine Safety Information.
Whenever MSHA
believes that a violation of the Mine Act, any health or safety
standard, or any regulation has occurred, it may issue a
citation which describes the violation and fixes a time within
which the operator must abate the violation. In some situations,
such as when MSHA believes that conditions pose a hazard to
miners, MSHA may issue an order removing miners from the area of
the mine affected by the condition until hazards are corrected.
Whenever MSHA issues a citation or order, it generally proposes
a civil penalty, or fine, as a result of the violation that the
operator is ordered to pay. Citations and orders can be
contested and appealed, and as part of that process, are often
reduced in severity and amount, and are sometimes dismissed. The
number of citations, orders and proposed assessments vary
depending on the size and type (underground or surface) of the
mine as well as by the MSHA inspector(s) assigned to that mine.
Since MSHA is a branch of the U.S. Department of Labor, its
jurisdiction applies only to our U.S. mines. While our
Australian mines are not required to report safety information
to MSHA, in 2008 we modified our injury reporting processes such
that our Australian operations began capturing safety data using
the same criteria as that of our U.S. operations. However,
the safety data for our Australian mines does not include MSHA
issued citations, orders and proposed assessments. As such, the
mine safety disclosures below contain no information for our
Australian mines.
The table that follows reflects citations and orders issued to
us by MSHA during the three months and year ended
December 31, 2010, as reflected in our safety tracking
system. Due to timing and other factors,
61
Table of Contents
our data may not agree with the mine data retrieval system
maintained by MSHA. The proposed assessments for the three
months ended December 31, 2010 were taken from the MSHA
system as of February 18, 2011.
Additional information follows about MSHA references used in the
table.
| • | Section 104 Citations: The total number of violations received from MSHA under section 104 of the Mine Act, which includes citations for health or safety standards that could significantly and substantially contribute to a serious injury if left unabated. | |
| • | Section 104(b) Orders: The total number of orders issued by MSHA under section 104(b) of the Mine Act, which represents a failure to abate a citation under section 104(a) within the period of time prescribed by MSHA. This results in an order of immediate withdrawal from the area of the mine affected by the condition until MSHA determines that the violation has been abated. | |
| • | Section 104(d) Citations and Orders: The total number of citations and orders issued by MSHA under section 104(d) of the Mine Act for unwarrantable failure to comply with mandatory health or safety standards. | |
| • | Section 110(b)(2) Violations: The total number of flagrant violations issued by MSHA under section 110(b)(2) of the Mine Act. | |
| • | Section 107(a) Orders: The total number of orders issued by MSHA under section 107(a) of the Mine Act for situations in which MSHA determined an imminent danger existed. |
Three Months Ended December 31, 2010
|
Section
|
Section
|
($)
|
||||||||||||||||||||||||||||||
|
Section
|
Section
|
104(d)
|
104(e)
|
Section
|
Section
|
Proposed
|
||||||||||||||||||||||||||
|
104
|
104(b)
|
Citations and
|
Potential pattern
|
110(b)(2)
|
107(a)
|
MSHA
|
||||||||||||||||||||||||||
| Mine (1) | Citations | Orders | Orders | of Violations | Violations | Orders | Assessments | Fatalities | ||||||||||||||||||||||||
| (In thousands) | ||||||||||||||||||||||||||||||||
|
Western U.S. Mining
|
||||||||||||||||||||||||||||||||
|
Caballo
|
1 | — | — | — | — | — | 0.1 | — | ||||||||||||||||||||||||
|
El Segundo
|
1 | — | — | — | — | — | 0.1 | — | ||||||||||||||||||||||||
|
Kayenta
|
10 | — | — | — | — | — | 14.5 | — | ||||||||||||||||||||||||
|
Lee Ranch
|
2 | — | — | — | — | — | 2.4 | — | ||||||||||||||||||||||||
|
North Antelope Rochelle
|
9 | — | — | — | — | — | 1.1 | — | ||||||||||||||||||||||||
|
Rawhide
|
5 | — | — | — | — | — | 2.0 | — | ||||||||||||||||||||||||
|
Twentymile (Foidel Creek)
|
55 | — | 1 | — | — | — | 45.9 | — | ||||||||||||||||||||||||
|
Midwestern U.S. Mining
|
||||||||||||||||||||||||||||||||
|
Air Quality
|
133 | 1 | — | — | — | — | 175.1 | — | ||||||||||||||||||||||||
|
Bear Run
|
13 | 1 | — | — | — | — | 1.7 | — | ||||||||||||||||||||||||
|
Francisco Underground
|
90 | 1 | 1 | — | — | — | 132.6 | — | ||||||||||||||||||||||||
|
Gateway
|
135 | — | 3 | — | — | — | 200.7 | — | ||||||||||||||||||||||||
|
Somerville Central
|
23 | — | — | — | — | — | 29.4 | — | ||||||||||||||||||||||||
|
Viking (Viking-Corning and Knot Pit)
|
9 | — | — | — | — | — | 12.0 | — | ||||||||||||||||||||||||
|
Wildcat Hills Underground
|
82 | — | — | — | — | — | 52.2 | |||||||||||||||||||||||||
|
Willow Lake (Willow Lake Portal and Central Preparation Plant)
|
185 | 2 | 1 | 1 | 1 | — | 347.3 | — | ||||||||||||||||||||||||
62
Table of Contents
Year Ended December 31, 2010
|
Section
|
Section
|
($)
|
||||||||||||||||||||||||||||||
|
Section
|
Section
|
104(d)
|
104(e)
|
Section
|
Section
|
Proposed
|
||||||||||||||||||||||||||
|
104
|
104(b)
|
Citations and
|
Potential pattern
|
110(b)
(2)
|
107(a)
|
MSHA
|
||||||||||||||||||||||||||
| Mine (1) | Citations | Orders | Orders | of Violations | Violations | Orders | Assessments | Fatalities | ||||||||||||||||||||||||
| (In thousands) | ||||||||||||||||||||||||||||||||
|
Western U.S. Mining
|
||||||||||||||||||||||||||||||||
|
Caballo
|
19 | — | — | — | — | — | 8.7 | — | ||||||||||||||||||||||||
|
El Segundo
|
14 | — | — | — | — | — | 3.3 | — | ||||||||||||||||||||||||
|
Kayenta
|
66 | — | — | — | — | 1 | 68.7 | — | ||||||||||||||||||||||||
|
Lee Ranch
|
22 | — | — | — | — | — | 33.2 | — | ||||||||||||||||||||||||
|
North Antelope Rochelle
|
49 | — | — | — | — | — | 69.8 | — | ||||||||||||||||||||||||
|
Rawhide
|
12 | — | — | — | — | 1 | 13.0 | — | ||||||||||||||||||||||||
|
Twentymile (Foidel Creek)
|
262 | — | 1 | — | — | 1 | 327.7 | — | ||||||||||||||||||||||||
|
Midwestern U.S. Mining
|
||||||||||||||||||||||||||||||||
|
Air Quality
|
497 | 2 | 8 | — | — | — | 922.0 | — | ||||||||||||||||||||||||
|
Bear Run
|
27 | 1 | — | — | — | — | 4.3 | — | ||||||||||||||||||||||||
|
Cottage Grove (Wildcat Hills-Cottage Grove Pit)
|
11 | — | — | — | — | — | 3.5 | — | ||||||||||||||||||||||||
|
Farmersburg
(2)
|
15 | — | — | — | — | — | 19.7 | — | ||||||||||||||||||||||||
|
Francisco Underground
|
427 | 2 | 9 | — | — | — | 586.6 | — | ||||||||||||||||||||||||
|
Francisco
Surface
(2)
|
17 | — | — | — | — | — | 50.1 | — | ||||||||||||||||||||||||
|
Gateway
|
481 | — | 9 | — | — | 1 | 1,172.8 | — | ||||||||||||||||||||||||
|
Midwest Repair Facility (Columbia Maintenance Services)
|
6 | — | — | — | — | — | 0.7 | — | ||||||||||||||||||||||||
|
Somerville Central
|
50 | — | — | — | — | — | 89.2 | — | ||||||||||||||||||||||||
|
Viking (Viking-Corning and Knot Pit)
|
47 | — | — | — | — | — | 55.3 | — | ||||||||||||||||||||||||
|
Wildcat Hills Underground
|
307 | — | — | — | — | — | 252.7 | — | ||||||||||||||||||||||||
|
Willow Lake (Willow Lake Portal and Central Preparation Plant)
|
904 | 3 | 17 | 1 | 1 | — | 2,213.5 | 1 | ||||||||||||||||||||||||
| (1) | The definition of mine under section 3 of the Mine Act includes the mine, as well as other items used in, or to be used in, or resulting from, the work of extracting coal, such as land, structures, facilities, equipment, machines, tools, and coal preparation facilities. Unless otherwise indicated, any of these other items associated with a single mine have been aggregated in the totals for that mine. Also, there are instances where the mine name per the MSHA system differs from the mine name utilized by us. Where applicable, we have parenthetically listed the name(s) of the mine per the MSHA system. | |
| (2) | The Francisco Surface Mine was closed in the fourth quarter of 2009 and the Farmersburg Mine was closed in the fourth quarter of 2010. |
Pattern or Potential Pattern of Violations.
On
November 19, 2010, we received a written notice from MSHA
that a potential pattern of violations exists at our Willow Lake
Mine. The notification was based upon a screening by MSHA of
compliance records and of accident and employment records at the
mine. During the three months ended December 31, 2010, no
other mines operated by us received written notice from MSHA of
(a) a pattern of violations of mandatory health or safety
standards that are of such nature as could have significantly
and substantially contributed to the cause and effect of coal
mine health or safety hazards under section 104(e) of the
Mine Act or (b) the potential to have such a pattern.
Pending Legal Actions.
The Federal Mine Safety
and Health Review Commission (the Commission) is an independent
adjudicative agency that provides administrative trial and
appellate review of legal disputes arising under the Mine Act.
These cases may involve, among other questions, challenges by
operators to citations, orders and penalties they have received
from MSHA, or complaints of discrimination by miners under
Section 105 of the Mine Act. The following is a brief
description of the types of legal actions that may be brought
before the Commission.
63
Table of Contents
| • | Contests of Citations and Orders — A contest proceeding may be filed with the Commission by operators, miners or miners’ representatives to challenge the issuance of a citation or order issued by MSHA. | |
| • | Contests of Proposed Penalties (Petitions for Assessment of Penalties) — A contest of a proposed penalty is an administrative proceeding before the Commission challenging a civil penalty that MSHA has proposed for the violation contained in a citation or order. | |
| • | Complaints for Compensation — A complaint for compensation may be filed with the Commission by miners entitled to compensation when a mine is closed by certain withdrawal orders issued by MSHA. The purpose of the proceeding is to determine the amount of compensation, if any, due miners idled by the orders. | |
| • | Complaints of Discharge, Discrimination or Interference — A discrimination proceeding is a case that involves a miner’s allegation that he or she has suffered a wrong by the operator because he or she engaged in some type of activity protected under the Mine Act, such as making a safety complaint. | |
| • | Temporary Reinstatement Proceedings — Temporary reinstatement proceedings involve cases in which a miner has filed a complaint with MSHA stating he or she has suffered discrimination and the miner has lost his or her position. | |
| • | Emergency Response Plan (ERP) Dispute Proceedings — ERP dispute proceedings are cases brought before the Commission when an operator is issued a citation because it has not agreed to include a certain provision in its ERP. |
The table that follows presents information by mine regarding
pending legal actions before the Commission at December 31,
2010. Each legal action is assigned a docket number by the
Commission and may have as its subject matter one or more
citations, orders, penalties or complaints.
|
Legal
|
||||
| Mine (1) | Actions | |||
|
Western U.S. Mining
|
||||
|
Caballo
|
1 | |||
|
Kayenta
|
7 | |||
|
Lee Ranch
|
1 | |||
|
North Antelope Rochelle
|
12 | |||
|
Rawhide
|
4 | |||
|
Twentymile (Foidel Creek)
|
27 | |||
|
Midwestern U.S. Mining
|
||||
|
Air Quality
|
26 | |||
|
Cottage Grove (Wildcat Hills-Cottage Grove Pit)
|
2 | |||
|
Francisco Underground
|
8 | |||
|
Gateway
|
12 | |||
|
Somerville Central
|
2 | |||
|
Vermilion Grove
|
1 | |||
|
Viking (Viking-Corning and Knot Pit)
|
1 | |||
|
Wildcat Hills Underground
|
1 | |||
|
Willow Lake (Willow Lake Portal and Central Preparation Plant)
|
42 | |||
| (1) | The definition of mine under section 3 of the Mine Act includes the mine, as well as other items used in, or to be used in, or resulting from, the work of extracting coal, such as land, structures, facilities, equipment, machines, tools and coal preparation facilities. Unless otherwise indicated, any of these other items associated with a single mine have been aggregated in the totals for that mine. Also, there are instances where the mine name per the MSHA system differs from the mine name utilized by us. Where applicable, we have parenthetically listed the name(s) of the mine per the MSHA system. |
64
Table of Contents
| 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 2011 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 2011 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 2011 Proxy Statement and is incorporated
herein by reference.
| Item 12. | Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters. |
The information required by Item 403 of
Regulation S-K
is included under the caption “Ownership of Company
Securities” in our 2011 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, 2010:
|
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
|
1,437,039 | (1) | $ | 27.61 | (2) | 13,541,829 | (3) | |||||
|
Equity compensation plans not approved
|
||||||||||||
|
by security holders
|
— | — | — | |||||||||
|
Total
|
1,437,039 | $ | 27.61 | 13,541,829 | ||||||||
| (1) | Includes 38,331 shares issuable pursuant to outstanding deferred stock units and 159,553 shares issuable pursuant to outstanding performance units. | |
| (2) | The weighted average exercise price shown in the table does not take into account outstanding deferred stock units or performance awards. | |
| (3) | Includes 2,310,734 shares available for issuance under our U.S. Employee Stock Purchase Plan and 976,823 shares available for issuance under our Australian Employee Stock Purchase Plan. |
65
Table of Contents
| 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 2011 Proxy Statement and is
incorporated herein by reference.
| Item 14. | Principal Accounting Fees and Services. |
The information required by Item 9(e) of Schedule 14A
is included under the caption “Fees Paid to Independent
Registered Public Accounting Firm” in our 2011 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 | ||||
|
Report of Independent Registered Public Accounting Firm
|
F-1 | |||
|
Consolidated Statements of Operations — Years Ended
December 31, 2010, 2009 and 2008
|
F-2 | |||
|
Consolidated Balance Sheets — December 31, 2010
and December 31, 2009
|
F-3 | |||
|
Consolidated Statements of Cash Flows — Years Ended
December 31, 2010, 2009 and 2008
|
F-4 | |||
|
Consolidated Statements of Changes in Stockholders’
Equity — Years Ended December 31, 2010, 2009 and
2008
|
F-5 | |||
|
Notes to Consolidated Financial Statements
|
F-6 | |||
(2) Financial Statement Schedule.
The following financial statement schedule of Peabody Energy
Corporation and the report thereon of the independent registered
public accounting firm are at the pages indicated:
| Page | ||||
|
Valuation and Qualifying Accounts
|
F-69 | |||
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% 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.
66
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 28, 2011
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 28, 2011 | ||||
|
/s/
MICHAEL
C. CREWS
|
Executive Vice President and Chief Financial Officer (principal financial and accounting officer) | February 28, 2011 | ||||
|
/s/
WILLIAM
A. COLEY
|
Director | February 28, 2011 | ||||
|
/s/
WILLIAM
E. JAMES
|
Director | February 28, 2011 | ||||
|
/s/
ROBERT
B. KARN III
|
Director | February 28, 2011 | ||||
|
/s/
M.
FRANCES KEETH
|
Director | February 28, 2011 | ||||
|
/s/
HENRY
E. LENTZ
|
Director | February 28, 2011 | ||||
|
/s/
ROBERT
A. MALONE
|
Director | February 28, 2011 | ||||
|
/s/
WILLIAM
C. RUSNACK
|
Director | February 28, 2011 | ||||
|
/s/
JOHN
F. TURNER
|
Director | February 28, 2011 | ||||
|
/s/
SANDRA
VAN TREASE
|
Director | February 28, 2011 | ||||
|
/s/
ALAN
H. WASHKOWITZ
|
Director | February 28, 2011 | ||||
67
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,
2010 and 2009, 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, 2010. Our audits included the financial
statement schedule listed in Item 15(a). These financial
statements are the responsibility of the Company’s
management. Our responsibility is to express an opinion on these
financial statements and schedule based on our audits.
We conducted our audits in accordance with the standards of the
Public Company Accounting Oversight Board (United States). Those
standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are
free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in
the financial statements. An audit also includes assessing the
accounting principles used and significant estimates made by
management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, the financial statements referred to above
present fairly, in all material respects, the consolidated
financial position of Peabody Energy Corporation at
December 31, 2010 and 2009, and the consolidated results of
its operations and its cash flows for each of the three years in
the period ended December 31, 2010, in conformity with
U.S. generally accepted accounting principles. Also, in our
opinion, the related financial statement schedule, when
considered in relation to the basic financial statements taken
as a whole, presents fairly in all material respects the
information set forth therein.
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, 2010, based on
criteria established in
Internal Control-Integrated Framework
issued by the Committee of Sponsoring Organizations of the
Treadway Commission and our report dated February 28, 2011,
expressed an unqualified opinion thereon.
/s/
Ernst &
Young LLP
St. Louis, Missouri
February 28, 2011
See accompanying notes to consolidated financial statements
F-1
Table of Contents
PEABODY
ENERGY CORPORATION
| Year Ended December 31, | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
| (Dollars in millions, except per share data) | ||||||||||||
|
Revenues
|
||||||||||||
|
Sales
|
$ | 6,331.3 | $ | 5,468.1 | $ | 6,004.0 | ||||||
|
Other revenues
|
528.7 | 544.3 | 557.0 | |||||||||
|
Total revenues
|
6,860.0 | 6,012.4 | 6,561.0 | |||||||||
|
Costs and expenses
|
||||||||||||
|
Operating costs and expenses
|
4,841.0 | 4,472.6 | 4,589.7 | |||||||||
|
Depreciation, depletion and amortization
|
440.9 | 405.2 | 402.4 | |||||||||
|
Asset retirement obligation expense
|
48.5 | 40.1 | 48.2 | |||||||||
|
Selling and administrative expenses
|
232.2 | 203.8 | 197.3 | |||||||||
|
Other operating (income) loss:
|
||||||||||||
|
Net gain on disposal or exchange of assets
|
(30.0 | ) | (23.2 | ) | (72.9 | ) | ||||||
|
Loss from equity affiliates
|
1.7 | 69.1 | — | |||||||||
|
Operating profit
|
1,325.7 | 844.8 | 1,396.3 | |||||||||
|
Interest expense
|
222.1 | 201.2 | 227.0 | |||||||||
|
Interest income
|
(9.6 | ) | (8.1 | ) | (10.0 | ) | ||||||
|
Income from continuing operations before income taxes
|
1,113.2 | 651.7 | 1,179.3 | |||||||||
|
Income tax provision
|
308.1 | 193.8 | 191.4 | |||||||||
|
Income from continuing operations, net of income taxes
|
805.1 | 457.9 | 987.9 | |||||||||
|
Income (loss) from discontinued operations, net of income taxes
|
(2.9 | ) | 5.1 | (28.8 | ) | |||||||
|
Net income
|
802.2 | 463.0 | 959.1 | |||||||||
|
Less: Net income attributable to noncontrolling interests
|
28.2 | 14.8 | 6.2 | |||||||||
|
Net income attributable to common stockholders
|
$ | 774.0 | $ | 448.2 | $ | 952.9 | ||||||
|
Income From Continuing Operations
|
||||||||||||
|
Basic earnings per share
|
$ | 2.89 | $ | 1.66 | $ | 3.63 | ||||||
|
Diluted earnings per share
|
$ | 2.86 | $ | 1.64 | $ | 3.60 | ||||||
|
Net Income Attributable to Common Stockholders
|
||||||||||||
|
Basic earnings per share
|
$ | 2.88 | $ | 1.68 | $ | 3.52 | ||||||
|
Diluted earnings per share
|
$ | 2.85 | $ | 1.66 | $ | 3.50 | ||||||
|
Dividends declared per share
|
$ | 0.295 | $ | 0.250 | $ | 0.240 | ||||||
See accompanying notes to consolidated financial statements
F-2
Table of Contents
PEABODY
ENERGY CORPORATION
| December 31, | ||||||||
| 2010 | 2009 | |||||||
|
(Amounts in millions,
|
||||||||
| except per share data) | ||||||||
|
ASSETS
|
||||||||
|
Current assets
|
||||||||
|
Cash and cash equivalents
|
$ | 1,295.2 | $ | 988.8 | ||||
|
Accounts receivable, net of allowance for doubtful accounts of
$30.3 at
|
||||||||
|
December 31, 2010 and $18.3 at December 31, 2009
|
558.2 | 303.0 | ||||||
|
Inventories
|
332.9 | 325.1 | ||||||
|
Assets from coal trading activities, net
|
192.5 | 276.8 | ||||||
|
Deferred income taxes
|
120.4 | 40.0 | ||||||
|
Other current assets
|
459.0 | 255.3 | ||||||
|
Total current assets
|
2,958.2 | 2,189.0 | ||||||
|
Property, plant, equipment and mine development
|
||||||||
|
Land and coal interests
|
7,657.0 | 7,557.3 | ||||||
|
Buildings and improvements
|
1,079.8 | 908.0 | ||||||
|
Machinery and equipment
|
1,699.3 | 1,391.2 | ||||||
|
Less: accumulated depreciation, depletion and amortization
|
(3,010.0 | ) | (2,595.0 | ) | ||||
|
Property, plant, equipment and mine development, net
|
7,426.1 | 7,261.5 | ||||||
|
Investments and other assets
|
978.8 | 504.8 | ||||||
|
Total assets
|
$ | 11,363.1 | $ | 9,955.3 | ||||
| LIABILITIES AND STOCKHOLDERS’ EQUITY | ||||||||
|
Current liabilities
|
||||||||
|
Current maturities of long-term debt
|
$ | 43.2 | $ | 14.1 | ||||
|
Liabilities from coal trading activities, net
|
181.7 | 110.6 | ||||||
|
Accounts payable and accrued expenses
|
1,288.8 | 1,187.7 | ||||||
|
Total current liabilities
|
1,513.7 | 1,312.4 | ||||||
|
Long-term debt, less current maturities
|
2,706.8 | 2,738.2 | ||||||
|
Deferred income taxes
|
539.8 | 299.1 | ||||||
|
Asset retirement obligations
|
501.3 | 452.1 | ||||||
|
Accrued postretirement benefit costs
|
963.9 | 914.1 | ||||||
|
Other noncurrent liabilities
|
448.3 | 483.5 | ||||||
|
Total liabilities
|
6,673.8 | 6,199.4 | ||||||
|
Stockholders’ equity
|
||||||||
|
Preferred Stock — $0.01 per share par value;
10.0 shares authorized, no shares issued or outstanding as
of December 31, 2010 or December 31, 2009
|
— | — | ||||||
|
Series A Junior Participating Preferred Stock —
1.5 shares authorized, no shares issued or outstanding as
of December 31, 2010 or December 31, 2009
|
— | — | ||||||
|
Perpetual Preferred Stock — 0.8 shares
authorized, no shares issued or outstanding as of
December 31, 2010 or December 31, 2009
|
— | — | ||||||
|
Series Common Stock — $0.01 per share par value;
40.0 shares authorized, no shares issued or outstanding as
of December 31, 2010 or December 31, 2009
|
— | — | ||||||
|
Common Stock — $0.01 per share par value;
800.0 shares authorized, 279.1 shares issued and
270.2 shares outstanding as of December 31, 2010 and
276.8 shares issued and 268.2 shares outstanding as of
December 31, 2009
|
2.8 | 2.8 | ||||||
|
Additional paid-in capital
|
2,182.0 | 2,067.7 | ||||||
|
Retained earnings
|
2,878.4 | 2,183.8 | ||||||
|
Accumulated other comprehensive loss
|
(67.9 | ) | (183.5 | ) | ||||
|
Treasury shares, at cost: 8.9 shares as of
December 31, 2010 and 8.6 shares as of
December 31, 2009
|
(334.6 | ) | (321.1 | ) | ||||
|
Peabody Energy Corporation’s stockholders’ equity
|
4,660.7 | 3,749.7 | ||||||
|
Noncontrolling interests
|
28.6 | 6.2 | ||||||
|
Total stockholders’ equity
|
4,689.3 | 3,755.9 | ||||||
|
Total liabilities and stockholders’ equity
|
$ | 11,363.1 | $ | 9,955.3 | ||||
See accompanying notes to consolidated financial statements
F-3
Table of Contents
PEABODY
ENERGY CORPORATION
| Year Ended December 31, | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
| (Dollars in millions) | ||||||||||||
|
Cash Flows From Operating Activities
|
||||||||||||
|
Net income
|
$ | 802.2 | $ | 463.0 | $ | 959.1 | ||||||
|
(Income) loss from discontinued operations, net of income taxes
|
2.9 | (5.1 | ) | 28.8 | ||||||||
|
Income from continuing operations, net of income taxes
|
805.1 | 457.9 | 987.9 | |||||||||
|
Adjustments to reconcile income from continuing operations, net
of income taxes
|
||||||||||||
|
to net cash provided by operating activities:
|
||||||||||||
|
Depreciation, depletion and amortization
|
440.9 | 405.2 | 402.4 | |||||||||
|
Deferred income taxes
|
71.7 | 131.1 | (33.3 | ) | ||||||||
|
Share-based compensation
|
41.1 | 38.8 | 34.9 | |||||||||
|
Net gain on disposal or exchange of assets
|
(30.0 | ) | (23.2 | ) | (72.9 | ) | ||||||
|
Loss from equity affiliates
|
1.7 | 69.1 | — | |||||||||
|
Revenue recovery on coal supply agreement
|
— | — | (56.9 | ) | ||||||||
|
Dividends received from equity affiliates
|
— | — | 19.9 | |||||||||
|
Changes in current assets and liabilities:
|
||||||||||||
|
Accounts receivable
|
(149.2 | ) | 101.8 | (114.7 | ) | |||||||
|
Change in receivable from accounts receivable securitization
program
|
(104.6 | ) | (20.4 | ) | — | |||||||
|
Inventories
|
(7.7 | ) | (48.9 | ) | (13.2 | ) | ||||||
|
Net assets from coal trading activities
|
(109.6 | ) | 70.9 | (43.0 | ) | |||||||
|
Other current assets
|
(28.5 | ) | (3.2 | ) | 2.3 | |||||||
|
Accounts payable and accrued expenses
|
223.3 | (121.6 | ) | 245.7 | ||||||||
|
Asset retirement obligations
|
32.5 | 27.7 | 32.9 | |||||||||
|
Workers’ compensation obligations
|
(8.9 | ) | 3.0 | 10.3 | ||||||||
|
Accrued postretirement benefit costs
|
23.1 | 7.2 | 13.6 | |||||||||
|
Contributions to pension plans
|
(112.6 | ) | (38.7 | ) | (21.3 | ) | ||||||
|
Other, net
|
15.4 | (0.9 | ) | 26.2 | ||||||||
|
Net cash provided by continuing operations
|
1,103.7 | 1,055.8 | 1,420.8 | |||||||||
|
Net cash used in discontinued operations
|
(16.6 | ) | (5.6 | ) | (123.0 | ) | ||||||
|
Net cash provided by operating activities
|
1,087.1 | 1,050.2 | 1,297.8 | |||||||||
|
Cash Flows From Investing Activities
|
||||||||||||
|
Additions to property, plant, equipment and mine development
|
(557.0 | ) | (260.6 | ) | (264.1 | ) | ||||||
|
Investment in Prairie State Energy Campus
|
(76.0 | ) | (56.8 | ) | (40.9 | ) | ||||||
|
Federal coal lease expenditures
|
— | (123.6 | ) | (178.5 | ) | |||||||
|
Proceeds from disposal of assets, net of notes receivable
|
19.2 | 53.9 | 72.8 | |||||||||
|
Investments in equity affiliates and joint ventures
|
(18.8 | ) | (15.0 | ) | (2.6 | ) | ||||||
|
Investments in debt and equity securities
|
(74.6 | ) | — | — | ||||||||
|
Proceeds from sale of debt securities
|
12.4 | — | — | |||||||||
|
Other, net
|
(8.8 | ) | (6.1 | ) | (6.0 | ) | ||||||
|
Net cash used in continuing operations
|
(703.6 | ) | (408.2 | ) | (419.3 | ) | ||||||
|
Net cash provided by discontinued operations
|
— | 1.7 | 23.9 | |||||||||
|
Net cash used in investing activities
|
(703.6 | ) | (406.5 | ) | (395.4 | ) | ||||||
|
Cash Flows From Financing Activities
|
||||||||||||
|
Change in revolving line of credit
|
— | — | (97.7 | ) | ||||||||
|
Proceeds from long-term debt
|
1,150.0 | — | — | |||||||||
|
Payments of long-term debt
|
(1,167.3 | ) | (37.1 | ) | (32.7 | ) | ||||||
|
Common stock repurchase
|
— | — | (199.8 | ) | ||||||||
|
Dividends paid
|
(79.4 | ) | (66.8 | ) | (64.9 | ) | ||||||
|
Repurchase of employee common stock relinquished for tax
withholding
|
(13.5 | ) | (2.3 | ) | (11.0 | ) | ||||||
|
Payment of debt issuance costs
|
(32.2 | ) | — | — | ||||||||
|
Excess tax benefits related to share-based compensation
|
51.0 | — | — | |||||||||
|
Proceeds from stock options exercised
|
16.4 | 3.6 | 14.1 | |||||||||
|
Acquisition of noncontrolling interests (Millennium Mine)
|
— | — | (110.1 | ) | ||||||||
|
Other, net
|
(2.1 | ) | (2.0 | ) | 4.1 | |||||||
|
Net cash used in financing activities
|
(77.1 | ) | (104.6 | ) | (498.0 | ) | ||||||
|
Net change in cash and cash equivalents
|
306.4 | 539.1 | 404.4 | |||||||||
|
Cash and cash equivalents at beginning of year
|
988.8 | 449.7 | 45.3 | |||||||||
|
Cash and cash equivalents at end of year
|
$ | 1,295.2 | $ | 988.8 | $ | 449.7 | ||||||
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, 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 | |||||||||||||||||||||
|
Repurchase of employee common stock relinquished for tax
withholding
|
— | — | (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 | |||||||||||||||||||||
|
Repurchase of employee common stock relinquished for tax
withholding
|
— | — | (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 | ||||||||||||
|
Comprehensive income:
|
||||||||||||||||||||||||||||
|
Net income
|
— | — | — | 774.0 | — | 28.2 | 802.2 | |||||||||||||||||||||
|
Increase in fair value of cash flow hedges
|
||||||||||||||||||||||||||||
|
(net of $129.5 tax provision)
|
— | — | — | — | 127.5 | — | 127.5 | |||||||||||||||||||||
|
Postretirement plans and workers’ compensation obligations
(net of $2.1 tax benefit)
|
— | — | — | — | (11.9 | ) | — | (11.9 | ) | |||||||||||||||||||
|
Comprehensive income
|
774.0 | 115.6 | 28.2 | 917.8 | ||||||||||||||||||||||||
|
Dividends paid
|
— | — | — | (79.4 | ) | — | — | (79.4 | ) | |||||||||||||||||||
|
Share-based compensation
|
— | 41.1 | — | — | — | — | 41.1 | |||||||||||||||||||||
|
Excess tax benefits related to share based compensation
|
— | 51.0 | — | — | — | — | 51.0 | |||||||||||||||||||||
|
Stock options exercised
|
— | 16.4 | — | — | — | — | 16.4 | |||||||||||||||||||||
|
Employee stock purchases
|
— | 5.8 | — | — | — | — | 5.8 | |||||||||||||||||||||
|
Repurchase of employee common stock relinquished for tax
withholding
|
— | — | (13.5 | ) | — | — | — | (13.5 | ) | |||||||||||||||||||
|
Distributions to noncontrolling interests
|
— | — | — | — | — | (5.8 | ) | (5.8 | ) | |||||||||||||||||||
|
December 31, 2010
|
$ | 2.8 | $ | 2,182.0 | $ | (334.6 | ) | $ | 2,878.4 | $ | (67.9 | ) | $ | 28.6 | $ | 4,689.3 | ||||||||||||
See accompanying notes to consolidated financial statements
F-5
Table of Contents
PEABODY
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS
| (1) | Summary of Significant Accounting Policies Discussion |
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 coal sales of other coal producers both as
principal and agent, and trades coal, freight and
freight-related contracts. 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 and Accounting Standards Not Yet
Implemented
In December 2010, the Financial Accounting Standards Board
(FASB) issued an update to guidance on accounting for Business
Combinations that clarified a public entity’s disclosure
requirements for pro forma presentation of revenue and earnings
related to a business combination. The new guidance requires
that if comparative statements are presented, the public entity
should disclose revenue and earnings of the combined entity as
though the business combination that occurred during the year
had occurred as of the beginning of the comparable prior annual
reporting period only. The guidance also requires the
supplemental pro forma disclosures to include a description of
the nature and amount of material nonrecurring pro forma
adjustments directly attributable to the business combination
included in the reported pro forma revenue and earnings. The
guidance is effective prospectively for business combinations
for which the acquisition date is on or after the beginning of
the first annual reporting period beginning on or after
December 15, 2010 (January 1, 2011 for the Company),
though early adoption is permitted. The guidance, should it
become applicable, will impact the Company’s disclosures
but it will not impact the Company’s results of operations,
financial condition or cash flows.
In January 2010, the FASB issued accounting guidance that
requires new fair value disclosures, including significant
transfers in and out of Level 1 and Level 2 fair-value
measurements and a description of the reasons for the transfers.
In addition, the guidance requires new disclosures regarding
activity in Level 3 fair value measurements, including a
gross basis reconciliation. The new disclosure requirements
became effective for interim and annual periods beginning
January 1, 2010, except for the disclosure of activity
within Level 3 fair value measurements, which is effective
for fiscal years beginning after December 15, 2010
(January 1, 2011 for the Company). While the adoption of
the guidance had an impact on the Company’s disclosures, it
did not affect the Company’s results of operations,
financial condition or cash flows. Further, the adoption of the
gross presentation of Level 3 activity will also impact the
Company’s disclosures, but will not affect its results of
operations, financial condition or cash flows.
In June 2009, the FASB issued accounting guidance on
consolidations which 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
F-6
Table of Contents
PEABODY
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
involvement in variable interest entities and any associated
changes in risk exposure. The guidance became effective
January 1, 2010, at which time there was no impact on the
Company’s results of operations, financial condition or
cash flows. The Company will continue monitoring and assessing
its business ventures in accordance with the guidance.
In June 2009, the FASB issued accounting guidance 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 guidance, which became effective
January 1, 2010, had an impact on the Company’s
disclosures for its accounts receivable securitization program,
but did 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 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 net revenues from coal trading activities
as discussed in Note 5 and coal revenues that were derived
from the Company’s mining operations and sold through the
Company’s coal trading business. Also included are revenues
from contract termination or restructuring payments, royalties
related to coal lease agreements, sales agency commissions, farm
income, property and facility rentals and generation development
activities. 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.
F-7
Table of Contents
PEABODY
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
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 2010, 2009 and 2008 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 are charged to operating costs as incurred.
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 nonmonetary exchanges of reserves or businesses. The net book
value of coal reserves totaled $5.0 billion as of
December 31, 2010 and $5.3 billion as of
December 31, 2009. These coal reserves include mineral
rights for leased coal interests and advance royalties that had
a net book value of $3.7 billion as of December 31,
2010 and $4.0 billion as of December 31, 2009. The
remaining net book value of coal reserves of $1.3 billion
at December 31, 2010 and $1.3 billion at
December 31, 2009 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 $1.3 billion as of
December 31, 2010 and $1.4 billion as of
December 31, 2009.
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. The estimated useful lives by category of assets
are as follows:
| Years | ||||
|
Building and improvements
|
10 to 20 | |||
|
Machinery and equipment
|
3 to 33 | |||
|
Leasehold improvements
|
Life of Lease | |||
Included in machinery and equipment are certain assets that are
depreciated using the straight-line method over the estimated
life of the mine, which varies from one to 33 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
F-8
Table of Contents
PEABODY
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
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, and the income (loss) from its equity affiliates:
|
Income (Loss) from Equity
|
||||||||||||||||||||
|
Affiliates for the Year Ended
|
||||||||||||||||||||
| Book Value at December 31, | December 31, | |||||||||||||||||||
| 2010 | 2009 | 2010 | 2009 | 2008 | ||||||||||||||||
| (Dollars in millions) | ||||||||||||||||||||
|
Interest in Carbones del Guasare
|
$ | — | $ | — | $ | — | $ | (54.6 | ) | $ | 5.7 | |||||||||
|
Other equity method investments
|
2.7 | 5.1 | (1.7 | ) | (14.5 | ) | (5.7 | ) | ||||||||||||
|
Total equity method investments
|
$ | 2.7 | $ | 5.1 | $ | (1.7 | ) | $ | (69.1 | ) | $ | — | ||||||||
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
Accruals for other environmental matters 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. The current
portion of these accruals is included in “Accounts payables
and accrued expenses” and the long-term portion is included
in “Other noncurrent liabilities” in the consolidated
balance sheets.
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 recognizes 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
F-9
Table of Contents
PEABODY
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
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 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.
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 Notes 4 and 5.
Non-derivative contracts and derivative contracts for which the
Company has elected to apply the normal purchases and normal
sales exception are accounted for on an accrual basis.
Use of
Estimates in the Preparation of the Consolidated Financial
Statements
The preparation of financial statements in conformity with
U.S. generally accepted accounting principles (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.
F-10
Table of Contents
PEABODY
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
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, 2010, 2009 or 2008.
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 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 total foreign
currency remeasurement losses for the years ended
December 31, 2010 and 2009 were $38.5 million and
$55.4 million, respectively. The total foreign currency
remeasurement gain for the year ended December 31, 2008 was
$71.1 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. See Note 14 for
information related to share-based compensation.
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.
F-11
Table of Contents
PEABODY
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
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 |
Discontinued operations reflect the spin off of Patriot Coal
Corporation (Patriot) and other operations recently divested, as
well as certain non-strategic Midwestern mining assets held for
sale where the Company has committed to the divestiture of such
assets.
Revenues resulting from discontinued operations (including
assets held for sale) were $84.2 million,
$301.5 million and $513.0 million for the years ended
December 31, 2010, 2009 and 2008, respectively. Nearly all
of these revenues pertain to supply agreements the Company
entered into with Patriot to meet commitments under
non-assignable pre-existing customer agreements sourced from
Patriot mining operations. Income (loss) before income taxes
from discontinued operations reflects a loss of
$4.7 million and $60.6 million for the years ended
December 31, 2010 and December 31, 2008, respectively,
and income of $14.4 million for the year ended
December 31, 2009. The income tax provision (benefit)
resulting from discontinued operations reflects a benefit of
$1.8 million and $31.8 million for the years ended
December 31, 2010 and December 31, 2008, respectively,
and a provision of $9.3 million for the year ended
December 31, 2009.
Total assets related to discontinued operations were
$15.7 million and $40.6 million as of
December 31, 2010 and 2009, respectively. Total liabilities
associated with discontinued operations were $14.8 million
and $47.1 million as of December 31, 2010 and 2009,
respectively.
| (3) | Inventories |
Inventories consisted of the following:
| December 31, | ||||||||
| 2010 | 2009 | |||||||
| (Dollars in millions) | ||||||||
|
Materials and supplies
|
$ | 97.1 | $ | 106.5 | ||||
|
Raw coal
|
55.4 | 80.5 | ||||||
|
Saleable coal
|
180.4 | 138.1 | ||||||
|
Total
|
$ | 332.9 | $ | 325.1 | ||||
| (4) | Derivatives and Fair Value Measurements |
Risk
Management — Non Coal Trading Activities
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. From time to time, the Company manages the interest rate
risk associated with the fair value of its fixed rate borrowings
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 result
F-12
Table of Contents
PEABODY
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
from market interest rate changes. From time to time, 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. As of
December 31, 2010, the Company had no interest rate swaps
in place.
Foreign Currency Hedges.
The Company is
exposed to foreign currency exchange rate risk, primarily 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. As of
December 31, 2010, the Company had only forward contracts
in place.
Diesel Fuel and Explosives Hedges.
The Company
is exposed to commodity price risk associated with diesel fuel
and explosives in the U.S. and Australia. This risk is
managed through the use of cost pass-through 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. In
Australia, the explosives costs and a portion of the diesel fuel
costs are not hedged as they are usually included in the fees
paid to the Company’s contract miners.
Notional Amounts and Fair Value.
The following
summarizes the Company’s foreign currency and commodity
positions at December 31, 2010:
| Notional Amount by Year of Maturity | ||||||||||||||||||||||||||||
|
2016 and
|
||||||||||||||||||||||||||||
| Total | 2011 | 2012 | 2013 | 2014 | 2015 | thereafter | ||||||||||||||||||||||
|
Foreign Currency
|
||||||||||||||||||||||||||||
|
A$:US$ hedge contracts (A$ millions)
|
$ | 4,187.5 | $ | 1,484.2 | $ | 1,355.2 | $ | 926.6 | $ | 421.5 | $ | — | $ | — | ||||||||||||||
|
Commodity Contracts
|
||||||||||||||||||||||||||||
|
Diesel fuel hedge contracts (million gallons)
|
191.4 | 89.5 | 76.2 | 25.7 | — | — | — | |||||||||||||||||||||
|
U.S. explosives hedge contracts (million MMBtu)
|
8.4 | 3.9 | 3.0 | 1.5 | — | — | — | |||||||||||||||||||||
| Account Classification by | |||||||||||||||||
|
Cash
|
Fair
|
||||||||||||||||
|
flow
|
value
|
Economic
|
Fair Value
|
||||||||||||||
| hedge | hedge | hedge | Asset (Liability) | ||||||||||||||
| (Dollars in millions) | |||||||||||||||||
|
Foreign Currency
|
|||||||||||||||||
|
A$:US$ hedge contracts (A$ millions)
|
$ | 4,187.5 | $ | — | $ | — | $ | 640.1 | |||||||||
|
Commodity Contracts
|
|||||||||||||||||
|
Diesel fuel hedge contracts (million gallons)
|
191.4 | — | — | $ | 40.3 | ||||||||||||
|
U.S. explosives hedge contracts (million MMBtu)
|
8.4 | — | — | $ | (0.1 | ) | |||||||||||
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.
F-13
Table of Contents
PEABODY
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
A measure of ineffectiveness is inherent in hedging future
diesel fuel purchases with derivative positions based on crude
oil and refined petroleum products as a result of location and
product differences.
The Company’s derivative positions for the hedging of
future explosives purchases are based on natural gas, which is
the primary price component of explosives. However, a small
measure of ineffectiveness exists as the contractual purchase
price includes manufacturing fees that are subject to periodic
adjustments. In addition, other fees, such as transportation
surcharges, can result in ineffectiveness, but have historically
changed infrequently and comprise a small portion of the total
explosives cost.
With respect to the interest rate swaps, there was no hedge
ineffectiveness recognized in the consolidated statements of
operations during the years ended December 31, 2010, 2009
or 2008.
The tables below show the classification and amounts of pre-tax
gains and losses related to the Company’s non-trading
hedges during the years ended December 31, 2010 and 2009:
| Year Ended December 31, 2010 | ||||||||||||||||||
|
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 | $ | (8.5 | ) | $ | 0.8 | $ | (0.5 | ) | $ | — | |||||||
|
Diesel fuel hedge contracts:
|
||||||||||||||||||
|
- Cash flow hedges
|
Operating costs and expenses | — | 34.1 | (27.3 | ) | (1.1 | ) | |||||||||||
|
Explosives cash flow hedge contracts:
|
||||||||||||||||||
|
- Cash flow hedges
|
Operating costs and expenses | — | (4.2 | ) | (8.9 | ) | — | |||||||||||
|
Foreign currency cash flow hedge contracts
|
Operating costs and expenses | — | 622.2 | 188.2 | — | |||||||||||||
|
Total
|
$ | (8.5 | ) | $ | 652.9 | $ | 151.5 | $ | (1.1 | ) | ||||||||
| (1) | Amounts relate to swaps that were de-designated and terminated in conjunction with the refinancing of the Company’s previous credit facility. |
F-14
Table of Contents
PEABODY
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
| Year Ended December 31, 2009 | ||||||||||||||||||
|
Gain (loss)
|
Gain (loss)
|
|||||||||||||||||
|
Gain (loss)
|
reclassified
|
reclassified
|
||||||||||||||||
|
recognized in
|
from other
|
from other
|
||||||||||||||||
|
Gain (loss)
|
other
|
comprehensive
|
comprehensive
|
|||||||||||||||
|
recognized in
|
comprehensive
|
income into
|
income into
|
|||||||||||||||
|
Income Statement
|
income on non-
|
income on
|
income
|
income
|
||||||||||||||
|
Classification
|
designated
|
derivative
|
(effective
|
(ineffective
|
||||||||||||||
| Financial Instrument | Gains (Losses) - Realized | derivatives (2) | (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 | ||||||||
| (2) | Amounts relate to diesel fuel and explosives hedge derivatives that were de-designated in 2009. |
Based on their fair value at December 31, 2010, the amount
of gains to be realized in 2011 associated with the
Company’s foreign currency and diesel fuel hedge programs
are expected be approximately $274 million and
$13 million, respectively. The losses to be realized under
the explosives hedge program are expected to be less than
$1 million.
The classification and amount of derivatives presented on a
gross basis as of December 31, 2010 and 2009 are as follows:
| Fair Value as of December 31, 2010 | ||||||||||||||||
|
Current
|
Noncurrent
|
Current
|
Noncurrent
|
|||||||||||||
| Financial Instrument | Assets | Assets | Liabilities | Liabilities | ||||||||||||
| (Dollars in millions) | ||||||||||||||||
|
Diesel fuel cash flow hedge contracts
|
$ | 25.3 | $ | 26.9 | $ | 11.9 | $ | — | ||||||||
|
Explosives cash flow hedge contracts
|
0.5 | 0.1 | 0.1 | 0.6 | ||||||||||||
|
Foreign currency cash flow hedge contracts
|
273.5 | 366.6 | — | — | ||||||||||||
|
Total
|
$ | 299.3 | $ | 393.6 | $ | 12.0 | $ | 0.6 | ||||||||
| Fair Value as of December 31, 2009 | ||||||||||||||||
|
Current
|
Noncurrent
|
Current
|
Noncurrent
|
|||||||||||||
| Financial Instrument | Assets | Assets | Liabilities | Liabilities | ||||||||||||
| (Dollars in millions) | ||||||||||||||||
|
Interest rate swaps:
|
||||||||||||||||
|
- Fair value hedges
|
$ | — | $ | 1.5 | $ | — | $ | — | ||||||||
|
- Cash flow hedges
|
— | — | — | 9.8 | ||||||||||||
|
Diesel fuel cash flow hedge contracts
|
6.7 | 18.0 | 31.3 | 15.6 | ||||||||||||
|
Explosives cash flow hedge contracts
|
0.1 | — | 4.9 | — | ||||||||||||
|
Foreign currency cash flow hedge contracts
|
110.6 | 100.2 | 1.6 | 3.1 | ||||||||||||
|
Total
|
$ | 117.4 | $ | 119.7 | $ | 37.8 | $ | 28.5 | ||||||||
F-15
Table of Contents
PEABODY
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
After netting by counterparty where permitted, the fair values
of the respective derivatives are reflected in “Other
current assets,” “Investments and other assets,”
“Accounts payable and accrued expenses” and
“Other noncurrent liabilities” in the consolidated
balance sheets.
The Company elected the trading exemption 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. See Note 5 for information related to the
Company’s coal trading activities.
Fair
Value Measurements
Fair Value Measured on a Recurring Basis.
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 , 2010 | ||||||||||||||||
| Level 1 | Level 2 | Level 3 | Total | |||||||||||||
| (Dollars in millions) | ||||||||||||||||
|
Investment in debt securities
|
$ | 17.9 | $ | — | $ | — | $ | 17.9 | ||||||||
|
Commodity swaps and options — diesel fuel
|
— | 40.3 | — | 40.3 | ||||||||||||
|
Commodity swaps and options — explosives
|
— | (0.1 | ) | — | (0.1 | ) | ||||||||||
|
Foreign currency hedge contracts
|
— | 640.1 | — | 640.1 | ||||||||||||
|
Total net financial assets
|
$ | 17.9 | $ | 680.3 | $ | — | $ | 698.2 | ||||||||
| December 31, 2009 | ||||||||||||||||
| Level 1 | Level 2 | Level 3 | Total | |||||||||||||
| (Dollars in millions) | ||||||||||||||||
|
Commodity swaps and options — diesel fuel
|
$ | — | $ | (22.2 | ) | $ | — | $ | (22.2 | ) | ||||||
|
Commodity swaps and options — explosives
|
— | (4.8 | ) | — | (4.8 | ) | ||||||||||
|
Interest rate swaps
|
— | (8.3 | ) | — | (8.3 | ) | ||||||||||
|
Foreign currency hedge contracts
|
— | 206.1 | — | 206.1 | ||||||||||||
|
Total net financial assets
|
$ | — | $ | 170.8 | $ | — | $ | 170.8 | ||||||||
For Level 1 and 2 financial assets and liabilities, the
Company utilizes both direct and indirect observable price
quotes, including interest rate yield curves, exchange indices,
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:
| • | Investment in debt securities: valued based on quoted prices in active markets (Level 1). | |
| • | Commodity swaps and options — diesel fuel and explosives: generally valued based on a valuation that is corroborated by the use of market-based pricing (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). |
F-16
Table of Contents
PEABODY
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
The Company did not have any transfers between levels during
2010 for its non-coal trading positions. The Company’s
policy is to value all transfers between levels using the
beginning of period valuation. This represents a change in
policy from those in effect at December 31, 2009.
Previously, the end of the period values were used for transfers
into Level 3 and beginning of period values for transfers
out of Level 3.
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, 2010 and 2009:
| • | Cash and cash equivalents, accounts receivable, including accounts receivable within the Company’s securitization program, 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. | |
| • | Investments and other assets in the consolidated balance sheets includes the Company’s investments in debt and equity securities related to the Company’s pro-rata share of funding in the Newcastle Coal Infrastructure Group (NCIG). The investments are recorded at cost, which approximate fair value. See Note 20 for additional information related to NCIG. | |
| • | 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, 2010 | December 31, 2009 | |||||||||||||||
|
Carrying
|
Estimated
|
Carrying
|
Estimated
|
|||||||||||||
| Amount | Fair Value | Amount | Fair Value | |||||||||||||
| (Dollars in millions) | ||||||||||||||||
|
Long-term debt
|
$ | 2,750.0 | $ | 2,960.0 | $ | 2,752.3 | $ | 2,828.8 | ||||||||
Nonperformance
and Credit Risk
The fair value of the Company’s non-coal trading derivative
assets and liabilities reflects adjustments for nonperformance
and credit risk. The Company conducts its hedging activities
related to foreign currency, interest rate, fuel and explosives
exposures with a variety of highly-rated commercial banks and
closely monitors counterparty creditworthiness. To reduce its
credit exposure for these hedging activities, the Company seeks
to enter into netting agreements with counterparties that permit
the Company to offset asset and liability positions with such
counterparties.
| (5) | Coal Trading |
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
its derivative trading contracts that are eligible to be cleared
on an exchange, the Company utilizes exchange-published
settlement prices and forward curves. For other derivative
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
F-17
Table of Contents
PEABODY
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
and therefore the valuing of its market positions should the
number of third-party brokers decrease or if market liquidity is
reduced.
The Company elected the trading exemption 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. 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.
| Year Ended December 31, | ||||||||
| Trading Revenue by Type of Instrument | 2010 | 2009 | ||||||
| (Dollars in millions) | ||||||||
|
Commodity swaps and options
|
$ | 23.2 | $ | 176.5 | ||||
|
Physical commodity purchase / sale contracts
|
135.5 | 85.0 | ||||||
|
Total trading revenue
|
$ | 158.7 | $ | 261.5 | ||||
Hedge Ineffectiveness.
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, has different quality
specifications, 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.
Fair
Value Measurements
The fair value of assets and liabilities from coal trading
activities is set forth below:
| December 31, | ||||||||||||||||
| 2010 | 2009 | |||||||||||||||
| Gross Basis | Net Basis | Gross Basis | Net Basis | |||||||||||||
| (Dollars in millions) | ||||||||||||||||
|
Assets from coal trading activities
|
$ | 1,706.2 | $ | 192.5 | $ | 949.8 | $ | 276.8 | ||||||||
|
Liabilities from coal trading activities
|
(1,843.5 | ) | (181.7 | ) | (779.3 | ) | (110.6 | ) | ||||||||
|
Subtotal
|
(137.3 | ) | 10.8 | 170.5 | 166.2 | |||||||||||
|
Net margin posted
(held)
(1)
|
148.1 | — | (4.3 | ) | — | |||||||||||
|
Net value of coal trading positions
|
$ | 10.8 | $ | 10.8 | $ | 166.2 | $ | 166.2 | ||||||||
| (1) | Represents margin posted with counterparties of $148.2 million, net of margin held from counterparties of $0.1 million at December 31, 2010; and margin held from counterparties of $22.4 million, net of margin posted with counterparties of $18.1 million at December 31, 2009. |
As previously discussed in Note 4, 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.
F-18
Table of Contents
PEABODY
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
The following tables set forth the hierarchy of the
Company’s net financial asset (liability) trading positions
for which fair value is measured on a recurring basis:
| December 31 , 2010 | ||||||||||||||||
| Level 1 | Level 2 | Level 3 | Total | |||||||||||||
| (Dollars in millions) | ||||||||||||||||
|
Commodity swaps and options
|
$ | 10.7 | $ | (76.2 | ) | $ | — | $ | (65.5 | ) | ||||||
|
Physical commodity purchase/sale contracts
|
— | 57.7 | 18.6 | 76.3 | ||||||||||||
|
Total net financial assets (liabilities)
|
$ | 10.7 | $ | (18.5 | ) | $ | 18.6 | $ | 10.8 | |||||||
| December 31, 2009 | ||||||||||||||||
| Level 1 | Level 2 | Level 3 | Total | |||||||||||||
| (Dollars in millions) | ||||||||||||||||
|
Commodity swaps and options
|
$ | (1.7 | ) | $ | 80.7 | $ | — | $ | 79.0 | |||||||
|
Physical commodity purchase/sale contracts
|
— | 70.2 | 17.0 | 87.2 | ||||||||||||
|
Total net financial assets (liabilities)
|
$ | (1.7 | ) | $ | 150.9 | $ | 17.0 | $ | 166.2 | |||||||
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 (NYMEX), Intercontinental Exchange indices (ICE), NOS
Clearing ASA, LCH.Clearnet (formerly known as the London
Clearing House), 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 — 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). | |
| • | Physical commodity purchase/sale contracts — purchases and sales at locations with significant market activity corroborated by market-based information (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 Company did not have any significant transfers between
Level 1 and Level 2 during 2010. In addition, there
were no significant transfers in or out of Level 3 during
2010. The Company’s policy is to value all transfers
between levels using the beginning of period valuation. This
represents a change in policy from that in effect at
December 31, 2009. Previously, the end of the period values
were used for transfers into Level 3 and beginning of
period values for transfers out of Level 3.
F-19
Table of Contents
PEABODY
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
The following table summarizes the changes in the Company’s
recurring Level 3 net financial assets:
| Year Ended December 31, | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
| (Dollars in millions) | ||||||||||||
|
Beginning of year
|
$ | 17.0 | $ | 37.8 | $ | 128.7 | ||||||
|
Total gains or losses (realized/unrealized):
|
||||||||||||
|
Included in earnings
|
2.1 | (2.9 | ) | (9.8 | ) | |||||||
|
Included in other comprehensive income
|
(0.5 | ) | (1.6 | ) | 3.4 | |||||||
|
Purchases, issuances and settlements
|
(0.1 | ) | (20.5 | ) | (58.8 | ) | ||||||
|
Net transfers in (out)
|
0.1 | 4.2 | (25.7 | ) | ||||||||
|
End of year
|
$ | 18.6 | $ | 17.0 | $ | 37.8 | ||||||
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 year:
| Year Ended December 31, | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
| (Dollars in millions) | ||||||||||||
|
Changes in unrealized gains
(losses)
(1)
|
$ | 6.7 | $ | 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. |
The Company’s trading assets and liabilities are generally
made up of forward contracts, financial swaps and margin. The
net fair value of coal trading positions designated as cash flow
hedges of anticipated future sales was a liability of
$125.4 million as of December 31, 2010 and an asset of
$93.0 million as of December 31, 2009.
As of December 31, 2010, the timing of the estimated future
realization of the value of the Company’s trading portfolio
was as follows:
|
Year of
|
Percentage of
|
|||
| Expiration | Portfolio Total | |||
|
2011
|
70 | % | ||
|
2012
|
21 | % | ||
|
2013
|
3 | % | ||
|
2014
|
4 | % | ||
|
2015
|
2 | % | ||
| 100 | % | |||
At December 31, 2010, 50% of the Company’s credit
exposure related to coal trading activities with investment
grade counterparties and 50% with non-investment grade
counterparties.
Nonperformance and Credit Risk.
The fair value
of the Company’s coal trading assets and liabilities
reflects adjustments for nonperformance and credit risk. The
Company’s exposure is substantially with electric
utilities, 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
F-20
Table of Contents
PEABODY
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
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 (margin),
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 asset and
liability positions with such counterparties and, to the extent
required, will post or receive margin amounts associated with
exchange-cleared positions.
Performance Assurances and Collateral.
Certain
of the Company’s derivative trading instruments require the
parties to provide additional performance assurances whenever a
material adverse event jeopardizes one party’s ability to
perform under the instrument. If the Company were to sustain a
material adverse event (using commercially reasonable
standards), the counterparties could request collateralization
on derivative trading instruments in net liability positions
which, based on an aggregate fair value at December 31,
2010 and 2009, would have amounted to collateral postings of
approximately $160 million and $84 million,
respectively, to its counterparties. As of December 31,
2010, $5.8 million of collateral was posted to
counterparties for such positions while zero was posted at
December 31, 2009 (reflected in “Liabilities from coal
trading activities, net”).
Certain of the Company’s other derivative trading
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 derivative trading instruments typically require
additional collateralization, which is commensurate with the
severity of the credit downgrade. If a credit downgrade were to
have occurred below contractually specified levels, the
Company’s additional collateral requirement owed to its
counterparties would have been zero at December 31, 2010
and approximately $16 million at December 31, 2009
based on the aggregate fair value of all derivative trading
instruments with such features that are in a net liability
position. As of December 31, 2009, the Company posted
$0.8 million for such instruments in a net liability
position. As of December 31, 2010, $5.0 million of
margin was posted with a counterparty due to timing and market
fluctuations (reflected in “Liabilities from coal trading
activities, net”).
The Company is required to post collateral on positions that are
in a net liability position with an exchange, known as variation
margin, which was $137.4 million as of December 31,
2010 and $18.1 million as of December 31, 2009
(reflected in “Liabilities from coal trading activities,
net”).
In addition, the Company is required by the exchange to post
certain additional collateral, known as initial margin, which
represents an estimate of potential future adverse price
movements across the Company’s portfolio under normal
market conditions. As of December 31, 2010 and 2009, the
Company had posted initial margin of $39.5 million and
$29.7 million, respectively (reflected in “Other
current assets”). In addition, the Company posted
$4.4 million and $5.5 million of margin in excess of
the exchange-required variation and initial margin discussed
above as of December 31, 2010 and 2009, respectively (also
reflected in “Other current assets”).
F-21
Table of Contents
PEABODY
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
| (6) | Income Taxes |
Income from continuing operations before income taxes consisted
of the following:
| Year Ended December 31, | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
| (Dollars in millions) | ||||||||||||
|
U.S.
|
$ | 535.5 | $ | 281.4 | $ | 185.2 | ||||||
|
Non U.S.
|
577.7 | 370.3 | 994.1 | |||||||||
|
Total
|
$ | 1,113.2 | $ | 651.7 | $ | 1,179.3 | ||||||
Total income tax provision consisted of the following:
| Year Ended December 31, | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
| (Dollars in millions) | ||||||||||||
|
Current:
|
||||||||||||
|
U.S. federal
|
$ | 113.9 | $ | (0.7 | ) | $ | — | |||||
|
Non U.S.
|
70.5 | 61.7 | 224.7 | |||||||||
|
State
|
1.0 | 1.7 | — | |||||||||
|
Total current
|
185.4 | 62.7 | 224.7 | |||||||||
|
Deferred:
|
||||||||||||
|
U.S. federal
|
47.9 | 56.0 | 47.1 | |||||||||
|
Non U.S.
|
69.1 | 74.4 | (81.7 | ) | ||||||||
|
State
|
5.7 | 0.7 | 1.3 | |||||||||
|
Total deferred
|
122.7 | 131.1 | (33.3 | ) | ||||||||
|
Total provision
|
$ | 308.1 | $ | 193.8 | $ | 191.4 | ||||||
The following is a reconciliation of the expected statutory
federal income tax provision to the Company’s actual income
tax provision:
| Year Ended December 31, | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
| (Dollars in millions) | ||||||||||||
|
Expected income tax provision at federal statutory rate
|
$ | 389.6 | $ | 228.1 | $ | 412.7 | ||||||
|
Excess depletion
|
(53.5 | ) | (44.0 | ) | (40.1 | ) | ||||||
|
Foreign earnings provision differential
|
(121.4 | ) | (83.6 | ) | (119.7 | ) | ||||||
|
Foreign earnings repatriation
|
84.5 | — | — | |||||||||
|
Remeasurement of foreign income tax accounts
|
47.6 | 74.4 | (65.2 | ) | ||||||||
|
State income taxes, net of U.S. federal tax benefit
|
(4.8 | ) | 3.4 | (1.6 | ) | |||||||
|
General business tax credits
|
(17.0 | ) | (12.2 | ) | (12.6 | ) | ||||||
|
Changes in valuation allowance
|
(28.7 | ) | 17.3 | (44.2 | ) | |||||||
|
Changes in tax reserves
|
— | 5.9 | 34.4 | |||||||||
|
Other, net
|
11.8 | 4.5 | 27.7 | |||||||||
|
Total provision
|
$ | 308.1 | $ | 193.8 | $ | 191.4 | ||||||
F-22
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, | ||||||||
| 2010 | 2009 | |||||||
| (Dollars in millions) | ||||||||
|
Deferred tax assets:
|
||||||||
|
Tax credits and loss carryforwards
|
$ | 425.2 | $ | 557.1 | ||||
|
Postretirement benefit obligations
|
427.7 | 474.7 | ||||||
|
Intangible tax asset and purchased contract rights
|
15.1 | 30.9 | ||||||
|
Accrued reclamation and mine closing liabilities
|
97.8 | 57.0 | ||||||
|
Accrued long-term workers’ compensation liabilities
|
15.5 | 23.1 | ||||||
|
Employee benefits
|
53.5 | 80.3 | ||||||
|
Hedge activities
|
30.6 | — | ||||||
|
Financial guarantee
|
18.8 | 20.1 | ||||||
|
Others
|
45.4 | 39.5 | ||||||
|
Total gross deferred tax assets
|
1,129.6 | 1,282.7 | ||||||
|
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
|
1,241.5 | 1,221.0 | ||||||
|
Unamortized discount on Convertible Junior Subordinated
Debentures
|
135.5 | 139.6 | ||||||
|
Hedge activities
|
— | 29.2 | ||||||
|
Investments and other assets
|
107.0 | 64.8 | ||||||
|
Total gross deferred tax liabilities
|
1,484.0 | 1,454.6 | ||||||
|
Valuation allowance
|
(65.0 | ) | (87.2 | ) | ||||
|
Net deferred tax liability
|
$ | (419.4 | ) | $ | (259.1 | ) | ||
|
Deferred taxes are classified as follows:
|
||||||||
|
Current deferred income taxes
|
$ | 120.4 | $ | 40.0 | ||||
|
Noncurrent deferred income taxes
|
(539.8 | ) | (299.1 | ) | ||||
|
Net deferred tax liability
|
$ | (419.4 | ) | $ | (259.1 | ) | ||
The Company’s tax credits and loss carryforwards included
alternative minimum tax (AMT), foreign tax and general business
credits of $317.0 million, state net operating loss (NOL)
carryforwards of $23.8 million and foreign loss
carryforwards of $84.4 million as of December 31,
2010. The AMT credits and foreign NOL and capital loss
carryforwards have no expiration date. The foreign tax and
general business credits begin to expire in 2020 and 2027,
respectively. The state NOL carryforwards begin to expire in the
year 2011. In assessing the near term use of NOLs and tax
credits and corresponding valuation allowance adjustments, the
Company evaluated the overall deferred tax position, available
tax strategies and future taxable income. The $28.7 million
change in the valuation allowance due to the 2010 assessment
included a $48.8 million decrease on AMT credits, an
$11.7 million increase on state NOLs and an
$8.4 million increase on foreign deferred assets. The
remaining valuation allowance at December 31, 2010 of
$65.0 million represents a reserve for state NOLs and
certain foreign deferred tax assets.
F-23
Table of Contents
PEABODY
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
Unrecognized
Tax Benefits
The total amount of the net unrecognized tax benefits was
$107.9 million ($111.0 million gross) at
December 31, 2010 and was $109.2 million
($113.2 million gross) at December 31, 2009. The
amount of the Company’s gross unrecognized tax benefits has
decreased by $2.2 million since January 1, 2010
primarily as a result of the Company’s Internal Revenue
Service (IRS) audit for the 2005 and 2006 tax years. A
reconciliation of the beginning and ending amount of gross
unrecognized tax benefits is as follows (dollars in millions):
| Year Ended December 31, | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
|
Balance at beginning of period
|
$ | 113.2 | $ | 186.3 | $ | 152.6 | ||||||
|
Additions for current year tax positions
|
3.4 | 2.7 | 30.3 | |||||||||
|
Additions for prior year positions
|
13.8 | 15.7 | 3.4 | |||||||||
|
Reductions for settlements with tax authorities
|
(19.4 | ) | (88.5 | ) | — | |||||||
|
Reductions for expirations of statute of limitations
|
— | (3.0 | ) | — | ||||||||
|
Balance at end of period
|
$ | 111.0 | $ | 113.2 | $ | 186.3 | ||||||
The amount of the net unrecognized tax benefits that, if
recognized, would directly affect the effective tax rate is
$107.9 million at December 31, 2010 and
$109.2 million at December 31, 2009. The Company does
not expect any significant changes to its net unrecognized tax
benefits within 12 months of this reporting date.
The Company recognizes interest and penalties accrued related to
unrecognized tax benefits in its income tax provision. The
Company has recognized $8.2 million of interest for the
year ended December 31, 2010. The Company had
$14.6 million and $6.4 million of accrued interest
related to uncertain tax positions at December 31, 2010 and
2009, respectively. The Company has considered the application
of penalties on its unrecognized tax benefits and determined,
based upon several factors, that no accrual of penalties is
required.
Tax
Returns Subject to Examination
The Company’s federal income tax returns are under
examination by the IRS for the 2006 through 2008 income tax
years. The Company and the IRS did not reach an agreement on the
adjustment of interest income accrued by a foreign subsidiary
through the alternative dispute resolution program (Fast Track
Settlement) for the 2006 federal income tax year. The Company
and the IRS are proceeding with the formal IRS appeals process
to resolve the remaining issue, which could take one to two
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 NOL carryforwards are reduced. The IRS began an
examination of the Company’s federal income tax returns for
the 2007 and 2008 income tax years during 2010. Notwithstanding
these audit cycles, the years
1999-2001,
2003 through 2004 and 2009 remain potentially subject to
examination due to NOL carryforwards. The Company’s state
income tax returns for the tax years 1996 and beyond remain
potentially subject to examination by various state taxing
authorities due to NOL carryforwards. In December 2010, the
Australian Tax Office began an examination of the Company’s
Australian income tax returns for the tax years 2004 through
2009.
Foreign
Earnings
The total amount of undistributed earnings of foreign
subsidiaries for income tax purposes was $1.1 billion at
December 31, 2010 and $1.4 billion at
December 31, 2009. During 2010, the Company recorded tax
expense of $84.5 million related to the repatriation of
certain earnings of
non-U.S. subsidiaries.
The Company has not provided deferred taxes on foreign earnings
of $1.1 billion for 2010 and $1.3 billion for 2009
because
F-24
Table of Contents
PEABODY
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
such earnings are considered 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 statements of operations of up to
$382.0 million could occur.
Tax
Payments
The following table summarizes the Company’s tax payments:
| Year Ended December 31, | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
| (Dollars in millions) | ||||||||||||
|
U.S. — federal
|
$ | 65.0 | $ | — | $ | — | ||||||
|
U.S. — state and local
|
0.4 | 0.9 | — | |||||||||
|
Non U.S.
|
83.0 | 169.7 | 65.8 | |||||||||
|
Total tax payments
|
$ | 148.4 | $ | 170.6 | $ | 65.8 | ||||||
| (7) | Accounts Payable and Accrued Expenses |
Accounts payable and accrued expenses consisted of the following:
| December 31, | ||||||||
| 2010 | 2009 | |||||||
| (Dollars in millions) | ||||||||
|
Trade accounts payable
|
$ | 467.1 | $ | 387.6 | ||||
|
Other accrued expenses
|
193.3 | 160.0 | ||||||
|
Accrued taxes other than income
|
185.4 | 172.3 | ||||||
|
Accrued payroll and related benefits
|
155.7 | 135.0 | ||||||
|
Accrued health care
|
85.9 | 78.7 | ||||||
|
Accrued royalties
|
74.7 | 51.1 | ||||||
|
Income taxes payable
|
59.6 | 80.7 | ||||||
|
Accrued interest
|
30.5 | 31.7 | ||||||
|
Workers’ compensation obligations
|
14.6 | 8.7 | ||||||
|
Accrued environmental
|
6.3 | 7.9 | ||||||
|
Other accrued benefits
|
4.2 | 4.0 | ||||||
|
Commodity hedge contracts
|
2.9 | 29.4 | ||||||
|
Liabilities associated with discontinued operations
|
8.6 | 40.6 | ||||||
|
Total accounts payable and accrued expenses
|
$ | 1,288.8 | $ | 1,187.7 | ||||
F-25
Table of Contents
PEABODY
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
| (8) |
|
The Company’s total indebtedness as of December 31,
2010 and 2009 consisted of the following:
| December 31, | ||||||||
| 2010 | 2009 | |||||||
| (Dollars in millions) | ||||||||
|
Term Loan
|
$ | 493.8 | $ | 490.3 | ||||
|
6.875% Senior Notes due March 2013
|
— | 650.0 | ||||||
|
5.875% Senior Notes due April 2016
|
218.1 | 218.1 | ||||||
|
7.375% Senior Notes due November 2016
|
650.0 | 650.0 | ||||||
|
6.5% Senior Notes due September 2020
|
650.0 | — | ||||||
|
7.875% Senior Notes due November 2026
|
247.2 | 247.1 | ||||||
|
6.34% Series B Bonds due December 2014
|
12.0 | 15.0 | ||||||
|
6.84% Series C Bonds due December 2016
|
33.0 | 33.0 | ||||||
|
Convertible Junior Subordinated Debentures due 2066
|
373.3 | 371.5 | ||||||
|
Capital lease obligations
|
69.6 | 67.5 | ||||||
|
Fair value hedge adjustment
|
2.2 | 8.4 | ||||||
|
Other
|
0.8 | 1.4 | ||||||
|
Total
|
$ | 2,750.0 | $ | 2,752.3 | ||||
Credit
Facility
On June 18, 2010, the Company entered into an unsecured
credit agreement (the Credit Agreement) which established a
$2.0 billion credit facility (the Credit Facility) and
replaced the Company’s third amended and restated credit
agreement dated as of September 15, 2006. The Credit
Agreement provides for a $1.5 billion revolving credit
facility (the Revolver) and a $500.0 million term loan
facility (the Term Loan). The Company has the option to request
an increase in the capacity of the Credit Facility, provided the
aggregate increase for the Revolver and Term Loan does not
exceed $250.0 million, the minimum amount of the increase
is $25.0 million, and certain other conditions are met
under the Credit Agreement. The Revolver also includes a
swingline sub-facility under which up to $50.0 million is
available for
same-day
borrowings. The Revolver commitments and the Term Loan under the
Credit Facility will mature on June 18, 2015.
The Revolver replaced the Company’s previous
$1.8 billion revolving credit facility and the Term Loan
replaced the Company’s previous term loan facility (the
previous term loan had a balance of $490.3 million at the
time of replacement and at December 31, 2009). The Company
recorded $21.9 million in deferred financing costs, which
are being amortized to interest expense over the five-year term
of the Credit Facility. The Company also recorded refinancing
charges of $9.3 million, which was recorded in
“Interest expense” in the consolidated statements of
operations. The $500.0 million of proceeds from the Term
Loan was used to repay the balance due on the Company’s
previous term loan facility.
All borrowings under the Credit Agreement (other than swingline
borrowings and borrowings denominated in currencies other than
U.S. dollars) bear interest, at the Company’s option,
at either a “base rate” or a “eurocurrency
rate”, as defined in the Credit Agreement, plus in each
case, a rate adjustment based on the Company’s leverage
ratio, as defined in the Credit Agreement, ranging from 2.50% to
1.25% per year for borrowings bearing interest at the “base
rate” and from 3.50% to 2.25% per year for borrowings
bearing interest at the “eurocurrency rate” (such rate
added to the “eurocurrency rate,” the
“Eurocurrency Margin”). Swingline borrowings bear
interest at a “BBA LIBOR” rate equal to the rate at
which deposits in U.S. dollars for a one month term are
offered in the interbank eurodollar market, as determined by the
administrative
F-26
Table of Contents
PEABODY
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
agent, plus the Eurocurrency Margin. Borrowings denominated in
currencies other than U.S. dollars will bear interest at
the “eurocurrency rate” plus the Eurocurrency Margin.
The Company pays a usage-dependent commitment fee under the
Revolver, which is dependent upon the Company’s leverage
ratio, as defined in the Credit Agreement, and ranges from
0.500% to 0.375% of the available unused commitment. Swingline
loans are not considered usage of the revolving credit facility
for purposes of calculating the commitment fee. The fee accrues
quarterly in arrears.
In addition, the Company pays a letter of credit fee calculated
at a rate dependent on the Company’s leverage ratio, as
defined in the Credit Agreement, ranging from 3.50% to 2.25% per
year of the undrawn amount of each letter of credit and a
fronting fee equal to 0.125% per year of the face amount of each
letter of credit. These fees are payable quarterly in arrears.
The $500.0 million Term Loan is subject to quarterly
repayment of 1.25% per quarter commencing on December 31,
2010, with the final payment of all amounts outstanding
(including accrued interest) being due on June 18, 2015.
Under the Credit Agreement, the Company must comply with certain
financial covenants on a quarterly basis including a minimum
interest coverage ratio and a maximum leverage ratio. The Credit
Agreement also includes various affirmative and negative
covenants that place limitations on the Company’s ability
to, among other things, incur debt; make loans, investments,
advances and acquisitions; sell assets; make redemptions and
repurchase of capital stock; engage in mergers or
consolidations; engage in affiliate transactions; and restrict
distributions from subsidiaries. When in compliance with the
financial covenants and customary default provisions, the
Company is not restricted in its ability to pay dividends, sell
assets and make redemptions or repurchase capital stock provided
that the Company may only redeem and repurchase capital stock
with the proceeds received from the concurrent issue of capital
stock or indebtedness permitted under the Credit Agreement.
Nearly all of the Company’s direct and indirect domestic
subsidiaries guarantee all loans under the Credit Agreement.
Certain of the Company’s foreign subsidiaries also, to the
extent permitted by applicable law and existing contractual
obligations, would be guarantors of loans made to one of the
Company’s Dutch subsidiaries.
As of December 31, 2010, the Company had no borrowings on
the Revolver, but had $67.6 million of letters of credit
outstanding. The remaining capacity on the Revolver at
December 31, 2010 was $1.4 billion.
The interest rate payable on the Revolver and the Term Loan was
LIBOR plus 2.25%, or 2.51%, at December 31, 2010.
6.5% Senior
Notes
On August 25, 2010, the Company completed a
$650.0 million offering of 6.5%
10-year
Senior Notes due September 2020 (the Notes). The Notes are
senior unsecured obligations and rank senior in right of payment
to any subordinated indebtedness; equally in right of payment
with any senior indebtedness; would be effectively junior in
right of payment to the Company’s 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 its subsidiaries that do
not guarantee the Notes. Interest payments are scheduled to
occur on March 15 and September 15 of each year, commencing on
March 15, 2011.
The Notes are jointly and severally guaranteed by nearly all of
the Company’s domestic subsidiaries, 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 and
any accrued unpaid interest to the redemption date.
F-27
Table of Contents
PEABODY
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
The Company used the net proceeds of $641.9 million from
the issuance of the Notes, after deducting underwriting
discounts and expenses, and cash on hand to extinguish its
previously outstanding $650.0 million aggregate principal
6.875% Senior Notes formerly due in March 2013 (the 2013
Notes). All of the 2013 Notes were either tendered or redeemed
during 2010. The Company recognized debt extinguishment costs of
$8.4 million, which was recorded in “Interest
expense” in the consolidated statements of operations. The
issuance of the Notes and the extinguishment of the 2013 Notes
allowed the Company to extend the maturity of its senior
indebtedness and lower the coupon rate.
6.875% Senior
Notes
The notes, which were tendered or redeemed during 2010 and are
no longer outstanding, were senior unsecured obligations of the
Company and ranked equally with all of the Company’s other
senior unsecured indebtedness. Interest payments were scheduled
to occur on March 15 and September 15 of each year. The notes
were guaranteed by the Company’s Subsidiary Guarantors as
defined in the note 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.
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 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.
Series Bonds
The Series Bonds were assumed as part of the Excel Coal
Limited 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”
in the consolidated statements of operations. 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-28
Table of Contents
PEABODY
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
Convertible
Junior Subordinated Debentures
As of December 31, 2010, 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 $81.64 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 13) 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, the conversion rate was adjusted. The
conversion rate has also been adjusted when there has been a
change in the Company’s dividend distribution rate. The
current conversion rate is 17.1493 shares of common stock
per $1,000 principal amount of Debentures effective
February 7, 2011. This adjusted conversion rate represents
a conversion price of $58.31.
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 (currently $75.80 per share). 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.
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
F-29
Table of Contents
PEABODY
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
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.
The Company 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, | ||||||||
| 2010 | 2009 | |||||||
| (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
|
(359.2 | ) | (361.0 | ) | ||||
|
Net carrying amount
|
$ | 373.3 | $ | 371.5 | ||||
The following table illustrates the effective interest rate and
the interest expense related to the Debentures:
| Year Ended December 31, | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
| (Dollars in millions) | ||||||||||||
|
Effective interest rate
|
4.9 | % | 4.9 | % | 4.9 | % | ||||||
|
Interest expense — contractual interest coupon
|
$ | 34.8 | $ | 34.8 | $ | 34.5 | ||||||
|
Interest expense — amortization of debt discount
|
1.8 | 1.6 | 1.5 | |||||||||
The remaining period over which the discount will be amortized
is 31 years as of December 31, 2010.
Interest
Rate Swaps
As of December 31, 2010, the Company had no interest rate
swaps in place. At December 31, 2009, there was an
unrealized loss of $9.8 million related to a cash flow
hedge then in place. The swap was cancelled in 2010 in
connection with the refinancing of the Credit Facility as
discussed above. The unrealized loss was recorded in
“Interest expense” in the consolidated statements of
operations at the time of cancellation.
F-30
Table of Contents
PEABODY
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
At December 31, 2009, there was a net unrealized gain of
$1.5 million on two fair value hedges then in place. The
swaps were cancelled in 2010 in connection with the
extinguishment of the 2013 Notes as discussed above.
Additionally, at December 31, 2009 there was a fair value
hedge adjustment of $3.5 million on the 2013 Notes. These
net unrealized gains were reflected as a reduction in
“Interest expense” in the consolidated statements of
operations at the time of extinguishment.
The fair value hedge adjustment, which represents the
unamortized portion of terminated fair value hedges
($2.2 million and $8.4 million at December 31,
2010 and 2009, respectively), is reflected as an adjustment to
the carrying value of the related debt.
Because the critical terms of the swaps and the respective debt
instruments they hedged coincided, there was no hedge
ineffectiveness recognized in the consolidated statements of
operations during the years ended December 31, 2010, 2009,
or 2008.
Capital
Lease Obligations
Capital lease obligations are for mining equipment (see
Note 9 for additional information).
Debt
Maturities, Interest Paid, and Financing Costs
The aggregate amounts of long-term debt maturities (excluding
unamortized debt discounts) subsequent to December 31,
2010, including capital lease obligations, were as follows:
| Year of Maturity | (Dollars in millions) | |||
|
2011
|
$ | 43.2 | ||
|
2012
|
50.2 | |||
|
2013
|
58.8 | |||
|
2014
|
50.0 | |||
|
2015
|
400.4 | |||
|
2016 and thereafter
|
2,147.4 | |||
|
Total
|
$ | 2,750.0 | ||
Interest paid on long-term debt was $197.9 million,
$201.6 million and $226.0 million for the years ended
December 31, 2010, 2009 and 2008, 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, 2010 was $52.0 million, of which
$35.5 million will be amortized to interest expense over
the next five years.
| (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 $181.7 million,
$127.8 million and $121.3 million for the years ended
December 31, 2010, 2009 and 2008, respectively. The gross
value of property, plant, equipment and mine development assets
under capital leases was $109.5 million and
$98.4 million as of December 31, 2010 and 2009,
respectively, related primarily to the leasing of mining
equipment. The accumulated depreciation for these items was
$39.5 million and $31.0 million at December 31,
2010 and 2009, 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
F-31
Table of Contents
PEABODY
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
mined during the year. Total royalty expense was
$548.7 million, $439.4 million and $506.4 million
for the years ended December 31, 2010, 2009 and 2008,
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 a majority of the coal it mines in Colorado under terms set
by Congress and administered by the U.S. Bureau of Land
Management. These leases are generally for an initial term of
ten years but may be extended by diligent development and mining
of the 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, by including the lease as a
part of a logical mining unit with other leases upon which
development has occurred, or by paying advance royalty in lieu
of continued operations. 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 executed 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 the sales price. 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 the loss of access to
the land where the landowner retains the surface rights, and the
amount and type of compensation can be determined by agreement
or arbitration as provided in the mining law. Surface rights are
typically acquired directly from landowners by mutual agreement.
F-32
Table of Contents
PEABODY
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
Future minimum lease and royalty payments as of
December 31, 2010 are as follows:
|
Coal Lease
|
||||||||||||
|
and
|
||||||||||||
|
Capital
|
Operating
|
Royalty
|
||||||||||
| Year Ending December 31, | Leases | Leases | Obligations | |||||||||
| (Dollars in millions) | ||||||||||||
|
2011
|
$ | 17.0 | $ | 95.6 | $ | 7.2 | ||||||
|
2012
|
17.0 | 78.7 | 6.9 | |||||||||
|
2013
|
25.1 | 68.5 | 7.4 | |||||||||
|
2014
|
15.5 | 59.0 | 6.2 | |||||||||
|
2015
|
— | 47.1 | 4.0 | |||||||||
|
2016 and thereafter
|
— | 106.9 | 30.3 | |||||||||
|
Total minimum lease payments
|
$ | 74.6 | $ | 455.8 | $ | 62.0 | ||||||
|
Less interest
|
5.0 | |||||||||||
|
Present value of minimum capital lease payments
|
$ | 69.6 | ||||||||||
As of December 31, 2010, certain of the Company’s
lease obligations were secured by outstanding surety bonds
totaling $110.3 million.
| (10) | Asset Retirement Obligations |
Reconciliations of the Company’s ARO liability are as
follows:
| December 31, | ||||||||
| 2010 | 2009 | |||||||
| (Dollars in millions) | ||||||||
|
Balance at beginning of year
|
$ | 452.1 | $ | 418.7 | ||||
|
Liabilities incurred or acquired
|
8.2 | 0.4 | ||||||
|
Liabilities settled or disposed
|
(7.9 | ) | (8.1 | ) | ||||
|
Accretion expense
|
26.7 | 24.0 | ||||||
|
Revisions to estimates
|
22.2 | 17.1 | ||||||
|
Balance at end of year
|
$ | 501.3 | $ | 452.1 | ||||
|
Balance at end of year — active locations
|
$ | 465.4 | $ | 422.0 | ||||
|
Balance at end of year — closed or inactive locations
|
$ | 35.9 | $ | 30.1 | ||||
The credit-adjusted, risk-free interest rates were 6.37%, 7.92%,
and 7.91% at December 31, 2010, 2009 and 2008, respectively.
As of December 31, 2010 and 2009, the Company had
$704.4 million and $772.3 million, respectively, in
surety bonds and bank guarantees outstanding to secure
reclamation obligations or activities. The amount of reclamation
self-bonding in certain states in which the Company qualifies
was $920.3 million and $821.9 million as of
December 31, 2010 and 2009, respectively. Additionally, the
Company had $0.1 million and $34.9 million of letters
of credit in support of reclamation obligations or activities as
of December 31, 2010 and 2009, respectively.
F-33
Table of Contents
PEABODY
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
| (11) | 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, | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
| (Dollars in millions) | ||||||||||||
|
Service cost for benefits earned
|
$ | 12.9 | $ | 10.5 | $ | 10.1 | ||||||
|
Interest cost on accumulated postretirement benefit obligation
|
58.2 | 55.2 | 54.0 | |||||||||
|
Amortization of prior service cost
|
2.6 | 1.5 | 0.4 | |||||||||
|
Amortization of actuarial loss
|
24.9 | 14.5 | 17.3 | |||||||||
|
Net periodic postretirement benefit cost
|
$ | 98.6 | $ | 81.7 | $ | 81.8 | ||||||
The following includes amounts recognized in accumulated other
comprehensive loss:
| Year Ended December 31, | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
| (Dollars in millions) | ||||||||||||
|
Net actuarial (gain) loss arising during year
|
$ | 45.3 | $ | 165.2 | $ | (18.3 | ) | |||||
|
Prior service cost arising during year
|
7.9 | (10.5 | ) | — | ||||||||
|
Amortization:
|
||||||||||||
|
Actuarial loss
|
(24.9 | ) | (14.5 | ) | (17.3 | ) | ||||||
|
Prior service cost
|
(2.6 | ) | (1.5 | ) | (0.4 | ) | ||||||
|
Total recognized in other comprehensive loss
|
25.7 | 138.7 | (36.0 | ) | ||||||||
|
Net periodic postretirement benefit cost
|
98.6 | 81.7 | 81.8 | |||||||||
|
Total recognized in net periodic postretirement benefit cost and
other comprehensive loss
|
$ | 124.3 | $ | 220.4 | $ | 45.8 | ||||||
The Company amortizes actuarial gain and loss using a 0%
corridor with an amortization period that covers the average
remaining service period of active employees (11.93 years
and 10.92 years at January 1, 2010 and 2009,
respectively). The estimated net actuarial loss and prior
service cost that will be amortized from accumulated other
comprehensive loss into net periodic postretirement benefit cost
during the year ended December 31, 2011 are
$26.9 million and $2.8 million, respectively.
F-34
Table of Contents
PEABODY
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
The following table sets forth the plan’s funded status
reconciled with the amounts shown in the consolidated balance
sheets:
| December 31, | ||||||||
| 2010 | 2009 | |||||||
| (Dollars in millions) | ||||||||
|
Change in benefit obligation:
|
||||||||
|
Accumulated postretirement benefit obligation at beginning of
period
|
$ | 982.2 | $ | 833.4 | ||||
|
Service cost
|
12.9 | 10.5 | ||||||
|
Interest cost
|
58.2 | 55.2 | ||||||
|
Participant contributions
|
2.1 | 1.2 | ||||||
|
Plan
amendments
(1)
|
7.9 | (10.5 | ) | |||||
|
Benefits paid
|
(77.4 | ) | (72.8 | ) | ||||
|
Actuarial loss
|
45.3 | 165.2 | ||||||
|
Accumulated postretirement benefit obligation at end of period
|
1,031.2 | 982.2 | ||||||
|
Change in plan assets:
|
||||||||
|
Fair value of plan assets at beginning of period
|
— | — | ||||||
|
Employer contributions
|
75.3 | 71.6 | ||||||
|
Participant contributions
|
2.1 | 1.2 | ||||||
|
Benefits paid and administrative fees (net of Medicare
Part D reimbursements)
|
(77.4 | ) | (72.8 | ) | ||||
|
Fair value of plan assets at end of period
|
— | — | ||||||
|
Funded status at end of year
|
(1,031.2 | ) | (982.2 | ) | ||||
|
Less current portion (included in Accounts payable and accrued
expenses)
|
67.3 | 68.1 | ||||||
|
Noncurrent obligation (included in Accrued postretirement
benefit costs)
|
$ | (963.9 | ) | $ | (914.1 | ) | ||
| (1) | Effective January 1, 2011, certain plans were modified to ensure consistency of benefits across the Company, the impact of which is reflected in the December 31, 2010 figures above. Effective January 1, 2010, the benefits provided to certain salaried retirees were capped at a fixed level, which resulted in a decrease to the retiree health care liability of $7.3 million, the impact of which is reflected in the December 31, 2009 figures above. The Company began 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, | ||||||||
| 2010 | 2009 | |||||||
|
Discount rate
|
5.81 | % | 6.14 | % | ||||
|
Rate of compensation increase
|
3.50 | % | 3.50 | % | ||||
|
Measurement date
|
December 31, 2010 | December 31, 2009 | ||||||
F-35
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, | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
|
Discount rate
|
6.14 | % | 6.85 | % | 6.60 | % | ||||||
|
Rate of compensation increase
|
3.50 | % | 3.50 | % | 3.50 | % | ||||||
|
Measurement date
|
December 31, 2009 | December 31, 2008 | December 31, 2007 | |||||||||
The following presents information about the assumed health care
cost trend rate:
| Year Ended December 31, | ||||||||
| 2010 | 2009 | |||||||
|
Health care cost trend rate assumed for next year
|
9.00 | % | 7.50 | % | ||||
|
Rate to which the cost trend is assumed to decline (the ultimate
trend rate)
|
5.00 | % | 5.00 | % | ||||
|
Year that the rate reaches the ultimate trend rate
|
2017 | 2016 | ||||||
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
|
$ | 7.8 | $ | (6.6 | ) | |||
|
Effect on total postretirement benefit obligation
|
$ | 112.5 | $ | (94.4 | ) | |||
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) | ||||
|
2011
|
$ | 67.3 | ||
|
2012
|
68.8 | |||
|
2013
|
72.6 | |||
|
2014
|
74.6 | |||
|
2015
|
76.5 | |||
|
Years
2016-2020
|
402.2 | |||
| (12) | 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 United Mine
Workers of America (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.
F-36
Table of Contents
PEABODY
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
Effective May 31, 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.
Net periodic pension cost included the following components:
| Year Ended December 31, | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
| (Dollars in millions) | ||||||||||||
|
Service cost for benefits earned
|
$ | 1.5 | $ | 1.4 | $ | 2.0 | ||||||
|
Interest cost on projected benefit obligation
|
50.5 | 51.3 | 51.0 | |||||||||
|
Expected return on plan assets
|
(58.3 | ) | (60.9 | ) | (60.6 | ) | ||||||
|
Amortization of prior service cost
|
1.4 | 1.4 | 1.3 | |||||||||
|
Amortization of actuarial (gains) losses
|
21.9 | 1.9 | (0.5 | ) | ||||||||
|
Net periodic pension costs
|
17.0 | (4.9 | ) | (6.8 | ) | |||||||
|
Curtailment gain
|
— | — | (0.6 | ) | ||||||||
|
Total net periodic pension (benefit) cost
|
$ | 17.0 | $ | (4.9 | ) | $ | (7.4 | ) | ||||
The following includes amounts recognized in accumulated other
comprehensive loss:
| Year Ended December 31, | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
| (Dollars in millions) | ||||||||||||
|
Net actuarial loss arising during year
|
$ | 13.1 | $ | 46.1 | $ | 199.2 | ||||||
|
Amortization:
|
||||||||||||
|
Actuarial gain (loss)
|
(21.9 | ) | (1.9 | ) | 0.5 | |||||||
|
Prior service cost
|
(1.4 | ) | (1.4 | ) | (0.7 | ) | ||||||
|
Total recognized in other comprehensive loss
|
(10.2 | ) | 42.8 | 199.0 | ||||||||
|
Net periodic pension (benefit) cost
|
17.0 | (4.9 | ) | (6.8 | ) | |||||||
|
Total recognized in net periodic pension cost and other
comprehensive loss
|
$ | 6.8 | $ | 37.9 | $ | 192.2 | ||||||
The Company amortizes actuarial gain and loss 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 cost during the year ended December 31, 2011 are
$30.1 million and $1.0 million, respectively.
F-37
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, | ||||||||
| 2010 | 2009 | |||||||
| (Dollars in millions) | ||||||||
|
Change in benefit obligation:
|
||||||||
|
Projected benefit obligation at beginning of period
|
$ | 844.9 | $ | 768.6 | ||||
|
Service cost
|
1.5 | 1.4 | ||||||
|
Interest cost
|
50.5 | 51.3 | ||||||
|
Benefits paid
|
(50.4 | ) | (48.3 | ) | ||||
|
Actuarial loss
|
34.5 | 71.9 | ||||||
|
Projected benefit obligation at end of period
|
881.0 | 844.9 | ||||||
|
Change in plan assets:
|
||||||||
|
Fair value of plan assets at beginning of period
|
629.6 | 552.6 | ||||||
|
Actual return on plan assets
|
79.8 | 86.6 | ||||||
|
Employer contributions
|
112.6 | 38.7 | ||||||
|
Benefits paid
|
(50.4 | ) | (48.3 | ) | ||||
|
Fair value of plan assets at end of period
|
771.6 | 629.6 | ||||||
|
Funded status at end of year
|
$ | (109.4 | ) | $ | (215.3 | ) | ||
|
Amounts recognized in the consolidated balance sheets:
|
||||||||
|
Current obligation (included in Accounts payable and accrued
expenses)
|
$ | (1.8 | ) | $ | (1.8 | ) | ||
|
Noncurrent obligation (included in Other noncurrent liabilities)
|
(107.6 | ) | (213.5 | ) | ||||
|
Net amount recognized
|
$ | (109.4 | ) | $ | (215.3 | ) | ||
The weighted-average assumptions used to determine the benefit
obligations as of the end of each year were as follows:
| Year Ended December 31, | ||||||||
| 2010 | 2009 | |||||||
|
Discount rate
|
5.84 | % | 6.19 | % | ||||
|
Rate of compensation increase
|
N/A | N/A | ||||||
|
Measurement date
|
December 31, 2010 | December 31, 2009 | ||||||
The weighted-average assumptions used to determine net periodic
benefit cost were as follows:
| Year Ended December 31, | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
|
Discount rate
|
6.19 | % | 6.90 | % | 6.75 | % | ||||||
|
Expected long-term return on plan assets
|
8.25 | % | 8.75 | % | 8.75 | % | ||||||
|
Measurement date
|
December 31, 2010 | December 31, 2009 | December 31, 2008 | |||||||||
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. 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
F-38
Table of Contents
PEABODY
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
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, 2010 and 2009. The accumulated benefit
obligation for all pension plans was $881.0 million and
$844.9 million as of December 31, 2010 and 2009,
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.
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 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. U.S. equity securities are
not subject to liquidity redemption restrictions.
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 are
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
F-39
Table of Contents
PEABODY
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
on a national securities exchange. Redemptions of the
common/collective trust and 103-12 investment entity can only
occur as of the last business day of the month with a
notification period of six business days and three business days
before the end of the month, respectively.
Debt securities.
Investment vehicles include
U.S. government and agency securities and various
institutional mutual funds that hold mortgage-backed debt
securities, international debt securities and corporate debt
securities. Institutional mutual funds are invested in various
diversified portfolios of fixed-income instruments, and the NAV
for each institutional mutual fund is calculated daily in
actively traded markets by an independent custodian for the
investment manager. The U.S. government and agency
securities are classified within the Level 1 valuation
hierarchy since fair value is based on public price quotations
in active markets. The institutional mutual funds are classified
within the Level 2 valuation hierarchy since fair value
inputs are derived prices in active markets and the
institutional mutual funds are not publicly traded on a national
securities exchange. Debt securities are not subject to
liquidity redemption restrictions.
Short-term investments.
Investment vehicles
primarily include institutional mutual funds. Short-term
investments include a diversified portfolio of liquid,
short-term instruments of varying maturities. The institutional
mutual funds are classified within the Level 2 valuation
hierarchy since fair value inputs are derived prices in active
markets and the institutional mutual funds are not publicly
traded on a national securities exchange.
Interests in real estate.
Investments in real
estate represent interests in several limited partnerships,
which invest in various real estate 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 methodologies used for
valuing investments are not necessarily an indication of the
risk associated with investing in those investments.
The following tables present the fair value of assets in the
Master Trust by asset category and by fair value hierarchy:
| December 31, 2010 | ||||||||||||||||
| Level 1 | Level 2 | Level 3 | Total | |||||||||||||
| (Dollars in millions) | ||||||||||||||||
|
U.S. equity securities
|
$ | 82.6 | $ | 250.5 | $ | — | $ | 333.1 | ||||||||
|
International equity securities
|
— | 118.9 | — | 118.9 | ||||||||||||
|
Mortgage-backed debt securities
|
— | 108.2 | — | 108.2 | ||||||||||||
|
U.S. debt securities
|
0.6 | 60.2 | — | 60.8 | ||||||||||||
|
International debt securities
|
— | 25.7 | — | 25.7 | ||||||||||||
|
Corporate debt securities
|
— | 46.1 | — | 46.1 | ||||||||||||
|
Short-term investments
|
— | 31.1 | — | 31.1 | ||||||||||||
|
Interests in real estate
|
— | — | 47.7 | 47.7 | ||||||||||||
|
Total assets at fair value
|
$ | 83.2 | $ | 640.7 | $ | 47.7 | $ | 771.6 | ||||||||
F-40
Table of Contents
PEABODY
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
| 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 | ||||||||
The table below sets forth a summary of changes in the fair
value of the Master Trust’s Level 3 investments.
| Year Ended December 31, | ||||||||
| Interests in Real Estate | 2010 | 2009 | ||||||
| (Dollars in millions) | ||||||||
|
Beginning of year
|
$ | 47.4 | $ | 62.2 | ||||
|
Assets held at the reporting date:
|
||||||||
|
Realized loss
|
(0.1 | ) | (0.8 | ) | ||||
|
Unrealized gain (loss)
|
1.3 | (19.3 | ) | |||||
|
Purchases, sales and settlements, net
|
(0.9 | ) | 5.3 | |||||
|
End of year
|
$ | 47.7 | $ | 47.4 | ||||
Contributions
Annual contributions to the Plans are made as recommended 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 required by
the Pension Protection Act of 2006 (the Pension Protection Act)
increased the long-term funding targets for single employer
pension plans from 90% to 100%. The Pension Protection Act also
introduced “benefit restriction” and
“at-risk” penalties for plans that fail to meet
certain funded status thresholds (generally 80%). As of
December 31, 2010, the Company’s qualified plans are
expected to be at or above these Pension Protection Act
thresholds, and therefore, avoid benefit restrictions and
at-risk penalties for 2011. The Company does not anticipate any
contributions to the qualified plans during 2011.
F-41
Table of Contents
PEABODY
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
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) | ||||
|
2011
|
$ | 55.7 | ||
|
2012
|
57.0 | |||
|
2013
|
58.5 | |||
|
2014
|
60.6 | |||
|
2015
|
62.7 | |||
|
Years
2016-2020
|
330.7 | |||
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 $51.3 million,
$47.9 million and $50.5 million for the years ended
December 31, 2010, 2009 and 2008, respectively. A
performance contribution feature allows for additional
contributions from the Company based upon meeting specified
Company performance targets. Performance contributions related
to the years ended December 31, 2010, 2009 and 2008 were
$20.6 million, $20.3 million and $18.7 million,
respectively.
| (13) | 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.
F-42
Table of Contents
PEABODY
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
The following table summarizes common stock activity
January 1, 2008 to December 31, 2010:
| 2010 | 2009 | 2008 | ||||||||||
|
Shares outstanding at the beginning of the year
|
268,203,815 | 266,644,979 | 270,066,621 | |||||||||
|
Stock options exercised
|
1,529,501 | 463,490 | 1,388,174 | |||||||||
|
Stock grants to employees
|
585,897 | 794,213 | 788,895 | |||||||||
|
Employee stock purchases
|
179,611 | 374,548 | 119,737 | |||||||||
|
Stock grants to non-employee directors
|
5,740 | 4,788 | 2,870 | |||||||||
|
Shares repurchased
|
— | — | (5,524,574 | ) | ||||||||
|
Shares relinquished
|
(268,308 | ) | (78,203 | ) | (196,744 | ) | ||||||
|
Shares outstanding at the end of the year
|
270,236,256 | 268,203,815 | 266,644,979 | |||||||||
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, both with a
$0.01 per share par value. 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, 2010.
Perpetual
Preferred Stock
As discussed in Note 8, the Company had $732.5 million
aggregate principal amount of Debentures outstanding as of
December 31, 2010. 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, 2010.
F-43
Table of Contents
PEABODY
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
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 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, 2010.
Treasury
Stock
Share repurchase program.
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, 2010, the
Company made repurchases under the program of 7.7 million
shares at a cost of $299.6 million ($199.8 million in
2008 and $99.8 million in 2006), leaving
$700.4 million available for share repurchase under the
program.
Shares relinquished.
During the year ended
December 31, 2010, the Company received 268,308 shares
of common stock to pay estimated taxes as consideration for 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.
| (14) | Share-Based Compensation |
The Company has 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 24.8 million shares of the
Company’s common stock available for grant, with
10.3 million shares available for grant as of
December 31, 2010. 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 Australian employees.
Share-Based
Compensation Expense and Cash Flows
The Company’s share-based compensation expense is recorded
in “Selling and administrative expenses” in the
consolidated statements of operations. The cash received by the
Company upon the exercise of stock
F-44
Table of Contents
PEABODY
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
options and when employees purchase stock under the employee
stock purchase plans is reflected as a financing activity in the
consolidated statements of cash flows. Share-based compensation
expense and cash flow amounts were as follows:
| Year Ended December 31, | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
| (Dollars in millions) | ||||||||||||
|
Share-based compensation expense
|
$ | 41.1 | $ | 38.8 | $ | 34.9 | ||||||
|
Tax benefit
|
15.4 | 15.0 | 13.5 | |||||||||
|
Share-based compensation expense, net of tax benefit
|
25.7 | 23.8 | 21.4 | |||||||||
|
Cash received upon the exercise of stock options and from
employee stock purchases
|
22.2 | 8.7 | 19.3 | |||||||||
|
Excess tax benefits related to share-based compensation
|
51.0 | — | — | |||||||||
As of December 31, 2010, the total unrecognized
compensation cost related to nonvested awards was
$23.0 million, net of taxes, which is expected to be
recognized over 3.5 years with a weighted-average period of
0.8 years.
Deferred
Stock Units
In 2010, 2009 and 2008, the Company granted deferred stock units
to each of its non-employee directors. The fair value of these
units is equal to the market price of the Company’s common
stock at the date of grant. These deferred stock units generally
vest after one year and are settled in common stock on the
specified distribution date elected by each non-employee
director.
Restricted
Stock Awards
The primary share-based compensation tool used by the Company
for its employee base is through awards of restricted stock. The
majority of restricted stock awards are typically granted in
January of each year with a lesser portion granted in the first
month of the subsequent three quarters. Awards 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, net of estimated forfeitures.
A summary of restricted stock award activity is as follows:
|
Weighted
|
||||||||
|
Year Ended
|
Average
|
|||||||
|
December 31,
|
Grant-Date
|
|||||||
| 2010 | Fair Value | |||||||
|
Nonvested at December 31, 2009
|
2,144,865 | $ | 35.51 | |||||
|
Granted
|
493,360 | 47.18 | ||||||
|
Vested
|
(643,828 | ) | 31.86 | |||||
|
Forfeited
|
(100,098 | ) | 39.40 | |||||
|
Nonvested at December 31, 2010
|
1,894,299 | $ | 39.32 | |||||
The total fair value of restricted stock awards granted during
the years ended December 31, 2010, 2009 and 2008, was
$23.3 million, $23.1 million and $20.4 million,
respectively. The total fair value of restricted stock awards
vested during the years ended December 31, 2010, 2009 and
2008, was $20.5 million, $11.2 million and
$2.8 million, respectively.
F-45
Table of Contents
PEABODY
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
Stock
Options
Over the past few years, the Company’s stock option awards
have been primarily limited to senior management personnel. All
stock options are granted at an exercise price equal to the
market price of the Company’s common stock at the date of
grant. Stock options generally vest in one-third increments over
a period of three years or cliff vest after three years, and
expire after 10 years from the date of grant. Expense is
recognized ratably over the vesting period, net of estimated
forfeitures. Option grants are typically made in January of each
year or upon hire for eligible plan participants.
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
|
Aggregate
|
||||||||||||||
|
Year Ended
|
Average
|
Remaining
|
Intrinsic
|
|||||||||||||
|
December 31,
|
Exercise
|
Contractual
|
Value (in
|
|||||||||||||
| 2010 | Price | Life | millions) | |||||||||||||
|
Options Outstanding at December 31, 2009
|
3,246,030 | $ | 20.44 | 4.7 | $ | 85.1 | ||||||||||
|
Granted
|
257,375 | 47.87 | ||||||||||||||
|
Exercised
|
(1,310,059 | ) | 11.88 | |||||||||||||
|
Forfeited
|
(277,045 | ) | 3.30 | |||||||||||||
|
Options Outstanding at December 31, 2010
|
1,916,301 | $ | 32.25 | 5.9 | $ | 61.2 | ||||||||||
|
Vested and Exercisable
|
1,239,155 | $ | 27.61 | 4.6 | $ | 45.1 | ||||||||||
During the years ended December 31, 2010, 2009 and 2008,
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 $53.7 million, $14.7 million
and $72.8 million, respectively. The weighted-average fair
values of the Company’s stock options and the assumptions
used in applying the Black-Scholes option pricing model were as
follows:
| Year Ended December 31, | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
|
Weighted-average fair value
|
$ | 25.70 | $ | 26.84 | $ | 64.31 | ||||||
|
Risk-free interest rate
|
2.8 | % | 1.5 | % | 3.3 | % | ||||||
|
Expected option life
|
5.0 years | 5.0 years | 5.0 years | |||||||||
|
Expected volatility
|
64 | % | 60 | % | 40 | % | ||||||
|
Dividend yield
|
0.6 | % | 0.9 | % | 0.5 | % | ||||||
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 and 2010, 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.
F-46
Table of Contents
PEABODY
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
A summary of performance unit activity is as follows:
|
Weighted
|
||||||||
|
Average
|
||||||||
|
Year Ended
|
Remaining
|
|||||||
|
December 31,
|
Contractual
|
|||||||
| 2010 | Life | |||||||
|
Nonvested at December 31, 2009
|
356,444 | 1.5 | ||||||
|
Granted
|
138,399 | |||||||
|
Forfeited
|
— | |||||||
|
Vested
|
(108,181 | ) | ||||||
|
Nonvested at December 31, 2010
|
386,662 | 1.5 | ||||||
As of December 31, 2010, there were 108,181 performance
units vested that had an aggregate intrinsic value of
$10.0 million and a conversion price per share of $62.36.
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
were as follows:
| Year Ended December 31, | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
|
Risk-free interest rate
|
1.7 | % | 1.3 | % | 2.9 | % | ||||||
|
Expected volatility
|
64 | % | 60 | % | 40 | % | ||||||
|
Dividend yield
|
0.6 | % | 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. 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 0.2 million for the
year ended December 31, 2010, 0.3 million for the year
ended December 31, 2009 and 0.1 million for the year
ended December 31, 2008.
F-47
Table of Contents
PEABODY
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
| (15) | 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, 2007
|
$ | 3.1 | $ | (116.7 | ) | $ | (18.9 | ) | $ | 65.4 | $ | (67.1 | ) | |||||||||||
|
Net decrease in fair 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 fair 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
|
— | (134.9 | ) | 6.5 | — | (128.4 | ) | |||||||||||||||||
|
December 31, 2009
|
3.1 | (343.5 | ) | (10.4 | ) | 167.3 | (183.5 | ) | ||||||||||||||||
|
Net increase in fair value of cash flow hedges
|
— | — | — | 229.9 | 229.9 | |||||||||||||||||||
|
Reclassification from other comprehensive income to earnings
|
— | 31.8 | 2.5 | (102.4 | ) | (68.1 | ) | |||||||||||||||||
|
Current period change
|
— | (46.2 | ) | — | — | (46.2 | ) | |||||||||||||||||
|
December 31, 2010
|
$ | 3.1 | $ | (357.9 | ) | $ | (7.9 | ) | $ | 294.8 | $ | (67.9 | ) | |||||||||||
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 (see Note 4
and Note 5 for information related to the Company’s
cash flow hedges) 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 2010 was primarily due to the strengthening of the
Australian dollar against the U.S. dollar.
| (16) | 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.
F-48
Table of Contents
PEABODY
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
| (17) | Earnings per Share |
The Company’s restricted stock awards are considered
participating securities. As such, the Company uses the
two-class method to compute basic and diluted EPS. The following
illustrates the earnings allocation method utilized in the
calculation of basic and diluted EPS. Diluted EPS includes any
dilutive impact of share-based compensation and the Debentures.
| Year Ended December 31, | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
| (In millions, except per share amounts) | ||||||||||||
|
EPS numerator:
|
||||||||||||
|
Income from continuing operations, net of income taxes
|
$ | 805.1 | $ | 457.9 | $ | 987.9 | ||||||
|
Less: Net income attributable to noncontrolling interests
|
28.2 | 14.8 | 6.2 | |||||||||
|
Income from continuing operations attributable to common
stockholders before allocation of earnings to participating
securities
|
776.9 | 443.1 | 981.7 | |||||||||
|
Less: Earnings allocated to participating securities
|
(5.6 | ) | (2.9 | ) | (5.5 | ) | ||||||
|
Income from continuing operations attributable to common
stockholders, after earnings allocated to participating
securities
(1)
|
771.3 | 440.2 | 976.2 | |||||||||
|
Income (loss) from discontinued operations, net of income taxes
|
(2.9 | ) | 5.1 | (28.8 | ) | |||||||
|
Net income attributable to common stockholders, after earnings
allocated to participating
securities
(1)
|
$ | 768.4 | $ | 445.3 | $ | 947.4 | ||||||
|
EPS denominator:
|
||||||||||||
|
Weighted average shares outstanding — basic
|
267.0 | 265.5 | 268.9 | |||||||||
|
Impact of dilutive securities
|
2.9 | 2.0 | 1.8 | |||||||||
|
Weighted average shares outstanding —
diluted
(2)
|
269.9 | 267.5 | 270.7 | |||||||||
|
Basic EPS attributable to common stockholders:
|
||||||||||||
|
Income from continuing operations
|
$ | 2.89 | $ | 1.66 | $ | 3.63 | ||||||
|
Income (loss) from discontinued operations
|
(0.01 | ) | 0.02 | (0.11 | ) | |||||||
|
Net income
|
$ | 2.88 | $ | 1.68 | $ | 3.52 | ||||||
|
Diluted EPS attributable to common stockholders:
|
||||||||||||
|
Income from continuing operations
|
$ | 2.86 | $ | 1.64 | $ | 3.60 | ||||||
|
Income (loss) from discontinued operations
|
(0.01 | ) | 0.02 | (0.10 | ) | |||||||
|
Net income
|
$ | 2.85 | $ | 1.66 | $ | 3.50 | ||||||
| (1) | The reallocation adjustment for participating securities to arrive at the numerator used to calculate diluted EPS was less than $0.1 million for the periods presented. | |
| (2) | Weighted average shares outstanding excludes anti-dilutive shares that totaled 0.2 million for the years ended December 31, 2010 and 2009 and 0.1 million for the year ended December 31, 2008. |
F-49
Table of Contents
PEABODY
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
| (18) | Risk Management — Labor Relations |
As of December 31, 2010, the Company had approximately
7,200 employees, which included approximately
5,100 hourly employees. As of December 31, 2010,
approximately 28% of the Company’s hourly employees were
represented by organized labor unions and generated 9% of its
2010 coal production. The Company could experience labor
disputes, work stoppages or other disruptions in production that
could negatively impact the Company’s profitability.
U.S. Labor Relations.
Hourly workers at
the Company’s Kayenta Mine in Arizona are represented by
the 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, 2010.
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; the Company expects to begin negotiations prior to
expiration of the existing contract. This agreement covers
approximately 10% 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, 2010.
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 Construction Forestry Mining and
Energy Union represents the Company’s Australian
subsidiaries’ hourly production and engineering employees,
including those employed through contract mining relationships.
All the Australian subsidiaries’ mine sites have enterprise
bargaining agreements. In 2010, the Company successfully
renegotiated new labor agreements at its North Goonyella, Wilkie
Creek and Metropolitan mines. The North Goonyella Mine agreement
will expire in 2012 and the Wilkie Creek and Metropolitan Mine
agreements will expire in 2013. The labor agreement for the
Wambo coal handling plant expires in April 2011; negotiations
for a new agreement are expected to commence in March 2011. The
labor agreement for the North Wambo Underground Mine was renewed
in early 2009 and will expire in April 2012.
| (19) | Financial Instruments and Guarantees 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.
F-50
Table of Contents
PEABODY
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
Financial
Instruments with Off-Balance Sheet Risk
The Company has letters of credit, bank guarantees, surety bonds
and corporate guarantees (such as self bonds) in support of the
Company’s reclamation, coal lease and workers’
compensation obligations as follows as of December 31, 2010:
|
Workers’
|
||||||||||||||||||||
|
Reclamation
|
Lease
|
Compensation
|
||||||||||||||||||
| Obligations | Obligations | Obligations | Other (1) | Total | ||||||||||||||||
| (Dollars in millions) | ||||||||||||||||||||
|
Self bonding
|
$ | 920.3 | $ | — | $ | — | $ | — | $ | 920.3 | ||||||||||
|
Surety bonds
|
577.2 | 110.3 | 7.3 | 10.5 | 705.3 | |||||||||||||||
|
Bank guarantees
|
127.2 | — | — | 128.3 | 255.5 | |||||||||||||||
|
Letters of credit
|
0.1 | — | 68.8 | 87.4 | 156.3 | |||||||||||||||
| $ | 1,624.8 | $ | 110.3 | $ | 76.1 | $ | 226.2 | $ | 2,037.4 | |||||||||||
| (1) | Other includes letter of credit obligations described below and an additional $138.9 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, 2010, the Company’s maximum reimbursement
obligation to the commercial bank was in turn supported by four
letters of credit totaling $42.7 million. During 2010, the
Company entered into a bilateral cash collateralized agreement
for these letters of credit whereby the Company posted cash
collateral in lieu of utilizing the Company’s Credit
Facility. Such cash collateral is classified within cash and
cash equivalents given the Company has the ability to substitute
letters of credit at any time for this cash collateral and it is
therefore readily available to the Company.
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 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, 2010. 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, 2010, the Company had a $7.6 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.
F-51
Table of Contents
PEABODY
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
Accounts
Receivable Securitization
The Company has an accounts receivable securitization program
(securitization program) through its wholly-owned,
bankruptcy-remote subsidiary (Seller). Under the securitization
program, beginning in 2010, the Company contributes, on a
revolving basis, trade receivables of most of the Company’s
U.S. subsidiaries to the Seller, which then sells the
receivables in their entirety to a consortium of unaffiliated
asset-backed commercial paper conduits (the Conduits). After the
sale, the Company, as servicer of the assets, collects the
receivables on behalf of the Conduits for a nominal servicing
fee. The Company utilizes proceeds from the sale of its accounts
receivable as an alternative to short-term borrowings under the
Company’s Credit Facility, effectively managing its overall
borrowing costs and providing an additional source for working
capital. The securitization program was renewed in May 2009 and
amended in December 2009 in order to qualify for sale accounting
under a newly adopted accounting standard related to financial
asset transfers. Prior to amending the securitization program,
the Company sold senior undivided interests in certain of its
accounts receivable and retained subordinated interests in those
receivables. The current securitization program 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 Seller is a separate legal entity whose assets are available
first and foremost to satisfy the claims of its creditors. Of
the receivables sold to the Conduits, a portion of the amount
due to the Seller is deferred until the ultimate collection of
the underlying receivables. During the year ended
December 31, 2010, the Company received total consideration
of $4,576.3 million related to accounts receivable sold
under the securitization program, including
$2,460.1 million of cash up front from the sale of the
receivables, an additional $1,953.6 million of cash upon
the collection of the underlying receivables, and
$162.6 million that had not been collected at
December 31, 2010 and was recorded at fair value which
approximates carrying value. The reduction in accounts
receivable as a result of securitization activity with the
Conduits was $150.0 million at December 31, 2010 and
$254.6 million at December 31, 2009.
The securitization activity has been reflected in the
consolidated statements of cash flows as operating activity
because both the cash received from the Conduits upon sale of
receivables as well as the cash received from the Conduits upon
the ultimate collection of receivables are not subject to
significantly different risks given the short-term nature of the
Company’s trade receivables. The Company recorded expense
associated with securitization transactions of
$2.4 million, $4.0 million and $10.8 million for
the years ended December 31, 2010, 2009 and 2008,
respectively.
Other
The Company had a liability recorded of $50.2 million as of
December 31, 2010 and $52.3 million as of
December 31, 2009 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, and the Company assumes that no amounts could be
recovered from third parties.
In connection with the development of the Prairie State Energy
Campus (Prairie State), a 1,600 megawatt coal-fuel electricity
generation project currently under construction, each owner,
including one of the
F-52
Table of Contents
PEABODY
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
Company’s subsidiaries, has issued a guarantee for its
proportionate share (5.06% for the Company) of the construction
costs under the Target Price Engineering, Procurement and
Construction Agreement with Bechtel Power Corporation.
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.
| (20) | Commitments and Contingencies |
Commitments
As of December 31, 2010, purchase commitments for capital
expenditures were $458.2 million, all of which is obligated
within the next three years with $406.7 million obligated
in the next year. The purchase commitments for capital
expenditures represent an increase of $386.5 million over
amounts committed as of December 31, 2009 and primarily
relate to new mines and expansion and extension projects in
Australia and the U.S. Commitments made for expenditures
under coal leases as reflected in Note 9. The Company also
has various long- and short-term take or pay arrangements
associated with rail and port commitments in Australia for the
delivery of coal including amounts relating to export
facilities. As of December 31, 2010, these commitments
totaled $2,892.9 million with $1,109.1 million
obligated within the next five years, of which
$217.5 million was obligated within the next year. During
2010, the Company recognized approximately $145 million of
expense, reflected in “Operating costs and expenses”
in the consolidated statements of operations, related to these
take or pay arrangements.
The Company controls a 17.7% interest in NCIG, a coal
transloading facility in Newcastle, Australia that is backed by
take or pay agreements. The total loading capacity for stage one
is 33 million tons per year, of which the Company’s
share is 5.8 millions tons. In the second quarter of 2010,
stage one of construction was substantially completed and
operations commenced. NCIG is currently operating at a reduced
rate as part of its
ramp-up
to
full capability, which is anticipated to occur by late 2011.
Phase one of stage two construction has been approved and is
under way. When complete, it is expected to provide the Company
with approximately 2 million tons of additional annual
throughput capacity beginning in mid-year 2012. Financing for
phase one of stage two of construction closed in the third
quarter of 2010 with the Company providing its pro-rata share of
funding of $59.7 million Australian dollars
($54.8 million U.S. dollars) where the Company
received underlying debt and equity securities of NCIG for its
contributions. Subsequent to the funding, the Company sold a
portion of the debt securities for $10.6 million.
A subsidiary of the Company owns a 5.06% undivided interest in
Prairie State. The Company invested $76.0 million,
$56.8 million and $40.9 million during the years ended
December 31, 2010, 2009 and 2008, respectively,
representing its 5.06% share of the construction costs for those
periods. Included in “Investments and other assets” in
the consolidated balance sheets as of December 31, 2010 and
December 31, 2009, are costs of $202.5 million and
$126.5 million, respectively. The Company’s share of
total construction costs for Prairie State is expected to be
approximately $250 million with most of the remaining
funding expected in 2011.
The Company is an equity partner in GreenGen, a partnership to
fund the construction in China of a near-zero emissions
coal-fueled power plant with carbon capture and storage. During
the year ended December 31, 2010, the Company spent
$3.1 million representing its 6.0% share of the
construction costs, which is reflected as capitalized
development costs as part of “Investments and other
assets” in the consolidated balance sheets. There were no
expenditures for GreenGen for 2009 or 2008. The Company’s
share of total construction costs for GreenGen is expected to be
approximately $60 million.
F-53
Table of Contents
PEABODY
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
Contingencies
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 alleged 16 claims, including Civil Racketeer
Influenced and Corrupt Organizations Act (RICO) violations and
fraud. On April 12, 2010, the Navajo Nation filed an
amended complaint to substantially narrow the scope of its
claims by removing the RICO allegations but leaving the other 12
common law tort and contractual claims. 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, punitive damages of at least $1 billion,
a determination that Peabody Western’s two coal leases
terminated due to Peabody Western’s breach of these leases
and a reformation of these leases to adjust the royalty rate to
20%. The court allowed the Hopi Tribe to intervene in this
lawsuit, and the Hopi Tribe sought 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. The U.S. Supreme
Court has 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.
In October 2010, the Company and the other defendants settled
the Hopi claims, and the court dismissed those claims. The court
ordered the Navajo Nation and the defendants to mediate the
case, and mediation commenced in November 2010.
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 five million tons under the agreement, which expired
on December 31, 2007. 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
June 30, 2009, the court granted Gulf Power’s motion
for partial summary judgment and denied the Company
subsidiary’s motion for summary judgment. The damages
portion of the trial was held in February 2010. On
September 30, 2010, the court entered its order on damages,
awarding Gulf Power zero dollars in damages and the Company its
costs to defend the lawsuit. The Company is also seeking its
reasonable attorney’s fees incurred since October 15,
2008. On November 1, 2010, Gulf Power filed a motion to
alter or amend the judgment, contesting the trial court’s
damages order, to which the Company objected. The court has not
yet ruled on the motion.
F-54
Table of Contents
PEABODY
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
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 pending in the U.S. District Court
for the Northern District of Oklahoma 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 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 separate lawsuit in the U.S. District
Court for the Northern District of Oklahoma against Gold Fields,
five other companies and the U.S. The plaintiffs sought
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 filed a third-party complaint
against the U.S. and other parties. In October 2010, the
parties entered into a settlement agreement and the case was
dismissed.
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.
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 13 additional sites, bringing the
total to 18, 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 $51.1 million as of December 31, 2010 and
$49.5 million as of December 31, 2009,
$6.3 million and $7.9 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 June 2005, Gold Fields and other PRPs
received a letter from the U.S. Department of
F-55
Table of Contents
PEABODY
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
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 June 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 total 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 putative
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, a three-judge panel of the
U.S. Court of Appeals for the Fifth Circuit (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 court held that
plaintiffs did not satisfy the prudential standing requirement
for their unjust enrichment, fraudulent misrepresentation and
civil conspiracy claims and dismissed those claims and ordered
that the case be remanded to the district court for further
proceedings. In March 2010, the Fifth Circuit vacated the panel
opinion and ordered a hearing en banc before the full Fifth
Circuit to consider plaintiffs’ appeal. After the en banc
court was properly constituted, a recusal by one of the judges
resulted in the en banc court losing its quorum. On May 28,
2010, the Fifth Circuit issued an order indicating that the
court had no authority to reinstate the panel decision and
directing the clerk to dismiss the appeal. Plaintiffs filed a
Petition for Mandamus with the U.S. Supreme Court. On
January 10, 2011, the U.S. Supreme Court denied the
plaintiffs’ Petition for Mandamus. As a result, the trial
court’s dismissal of the case is final.
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 June 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 to the U.S. Court of Appeals for
the Ninth Circuit. The parties have filed their respective
briefs with the court.
F-56
Table of Contents
PEABODY
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
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 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 June 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, 2010 and 2009 is presented
below.
| Year Ended December 31, 2010 | ||||||||||||||||
| First Quarter | Second Quarter | Third Quarter | Fourth Quarter | |||||||||||||
| (In millions except per share data) | ||||||||||||||||
|
Revenues
|
$ | 1,515.6 | $ | 1,661.4 | $ | 1,864.7 | $ | 1,818.3 | ||||||||
|
Operating profit
|
242.2 | 324.4 | 444.7 | 314.4 | ||||||||||||
|
Income from continuing operations, net of income taxes
|
137.1 | 214.7 | 237.6 | 215.7 | ||||||||||||
|
Net income
|
136.7 | 214.2 | 236.3 | 215.0 | ||||||||||||
|
Net income attributable to common stockholders
|
133.7 | 206.2 | 224.1 | 210.0 | ||||||||||||
|
Basic earnings per share — continuing
operations
(1)
|
0.50 | 0.77 | 0.84 | 0.78 | ||||||||||||
|
Diluted earnings per share — continuing
operations
(1)
|
$ | 0.50 | $ | 0.76 | $ | 0.83 | $ | 0.77 | ||||||||
|
Weighted average shares used in calculating basic earnings per
share
|
266.5 | 266.6 | 267.1 | 267.7 | ||||||||||||
|
Weighted average shares used in calculating diluted earnings per
share
|
268.2 | 268.3 | 268.6 | 270.3 | ||||||||||||
| (1) | Earnings per share for the quarters may not sum to the amounts for the year as each period is computed on a discrete basis. |
Operating profit in the second, third and fourth quarters
reflects higher contract pricing in Australia. Operating profit
for the fourth quarter includes an adverse impact related to
flooding in Queensland, Australia and lower results from the
Company’s Trading and Brokerage operations. Income from
continuing operations, net of income taxes in the first, third
and fourth quarters included non-cash tax expense of
$5.4 million, $42.7 million, and $18.8 million,
respectively, from the remeasurement of
non-U.S. income
tax accounts, while the second quarter included a non-cash
benefit of $19.3 million.
F-57
Table of Contents
PEABODY
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
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. 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 sum to the amounts for the year as each period is computed on a discrete basis. |
Operating profit in the second, third and fourth quarters
reflects 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 non-cash 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.
| (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. 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. The business of the Company’s 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. For the year
ended December 31, 2010, 84% of the Company’s total
sales (by volume) were to U.S. electricity generators, 14%
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
F-58
Table of Contents
PEABODY
ENERGY CORPORATION
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
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
metallurgical and thermal coal. The Company’s Trading and
Brokerage segment brokers coal sales of other coal producers
both as principal and agent, and trades 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,
2010 were as follows (total assets as of December 31, 2010):
|
Western
|
Midwestern
|
Australian
|
Trading and
|
Corporate
|
||||||||||||||||||||
| U.S. Mining | U.S. Mining | Mining | Brokerage | and Other | Consolidated | |||||||||||||||||||
| (Dollars in millions) | ||||||||||||||||||||||||
|
Revenues
|
$ | 2,706.3 | $ | 1,320.6 | $ | 2,520.0 | $ | 291.1 | $ | 22.0 | $ | 6,860.0 | ||||||||||||
|
Adjusted EBITDA
|
816.7 | 322.1 | 953.8 | 77.2 | (354.7 | ) | 1,815.1 | |||||||||||||||||
|
Total assets
|
3,008.4 | 608.0 | 3,603.4 | 398.2 | 3,745.1 | 11,363.1 | ||||||||||||||||||
|
Additions to property, plant, equipment and mine development
|
143.3 | 224.9 | 147.8 | 0.9 | 40.1 | 557.0 | ||||||||||||||||||
|
Federal coal lease expenditures
|
— | — | — | — | — | — | ||||||||||||||||||
|
Loss from equity affiliates
|
— | — | — | — | 1.7 | 1.7 | ||||||||||||||||||
|
Additions to advance mining royalties
|
1.3 | 1.3 | — | — | 3.1 | 5.7 | ||||||||||||||||||
Operating segment results for the year ended December 31,
2009 were as follows (total assets as of December 31, 2009):
|
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
|
3,087.6 | 444.4 | 3,386.8 | 673.0 | 2,363.5 | 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 (total assets as of December 31, 2008):
|
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 | ||||||||||||||||||
A reconciliation of adjusted EBITDA to consolidated income from
continuing operations follows:
| Year Ended December 31, | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
| (Dollars in millions) | ||||||||||||
|
Total adjusted EBITDA
|
$ | 1,815.1 | $ | 1,290.1 | $ | 1,846.9 | ||||||
|
Depreciation, depletion and amortization
|
(440.9 | ) | (405.2 | ) | (402.4 | ) | ||||||
|
Asset retirement obligation expense
|
(48.5 | ) | (40.1 | ) | (48.2 | ) | ||||||
|
Interest expense
|
(222.1 | ) | (201.2 | ) | (227.0 | ) | ||||||
|
Interest income
|
9.6 | 8.1 | 10.0 | |||||||||
|
Income tax provision
|
(308.1 | ) | (193.8 | ) | (191.4 | ) | ||||||
|
Income from continuing operations, net of income taxes
|
$ | 805.1 | $ | 457.9 | $ | 987.9 | ||||||
| (23) | Supplemental Guarantor/Non-Guarantor Financial Information |
In accordance with the indentures governing the
6.875% Senior Notes due March 2013 (extinguished in 2010),
the 5.875% Senior Notes due March 2016, the
7.375% Senior Notes due November 2016, the 6.5% Senior
Notes due September 2020 and the 7.875% Senior Notes due
November 2026 (collectively the Senior Notes), 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 holders of the Senior Notes. The following
historical financial statement information is provided for the
Guarantor/Non-Guarantor Subsidiaries.
F-60
Table of Contents
PEABODY
ENERGY CORPORATION
SUPPLEMENTAL
CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
| Year Ended December 31, 2010 | ||||||||||||||||||||
|
Parent
|
Guarantor
|
Non-Guarantor
|
||||||||||||||||||
| Company | Subsidiaries | Subsidiaries | Eliminations | Consolidated | ||||||||||||||||
| (Dollars in millions) | ||||||||||||||||||||
|
Total revenues
|
$ | — | $ | 3,716.2 | $ | 3,916.9 | $ | (773.1 | ) | $ | 6,860.0 | |||||||||
|
Costs and expenses
|
||||||||||||||||||||
|
Operating costs and expenses
|
(145.1 | ) | 2,616.4 | 3,142.8 | (773.1 | ) | 4,841.0 | |||||||||||||
|
Depreciation, depletion and amortization
|
— | 297.9 | 143.0 | — | 440.9 | |||||||||||||||
|
Asset retirement obligation expense
|
— | 33.2 | 15.3 | — | 48.5 | |||||||||||||||
|
Selling and administrative expenses
|
31.6 | 194.3 | 6.3 | — | 232.2 | |||||||||||||||
|
Other operating (income) loss:
|
||||||||||||||||||||
|
Net (gain) loss on disposal or exchange of assets
|
— | (34.5 | ) | 4.5 | — | (30.0 | ) | |||||||||||||
|
(Income) loss from equity affiliates
|
(838.4 | ) | 7.1 | 6.0 | 827.0 | 1.7 | ||||||||||||||
|
Interest expense
|
219.7 | 52.8 | 17.9 | (68.3 | ) | 222.1 | ||||||||||||||
|
Interest income
|
(18.8 | ) | (21.8 | ) | (37.3 | ) | 68.3 | (9.6 | ) | |||||||||||
|
Income from continuing operations before income taxes
|
751.0 | 570.8 | 618.4 | (827.0 | ) | 1,113.2 | ||||||||||||||
|
Income tax provision (benefit)
|
(24.2 | ) | 176.0 | 156.3 | — | 308.1 | ||||||||||||||
|
Income from continuing operations, net of income taxes
|
775.2 | 394.8 | 462.1 | (827.0 | ) | 805.1 | ||||||||||||||
|
Loss from discontinued operations, net of income taxes
|
(1.2 | ) | (1.7 | ) | — | — | (2.9 | ) | ||||||||||||
|
Net income
|
774.0 | 393.1 | 462.1 | (827.0 | ) | 802.2 | ||||||||||||||
|
Less: Net income attributable to noncontrolling interests
|
— | — | 28.2 | — | 28.2 | |||||||||||||||
|
Net income attributable to common stockholders
|
$ | 774.0 | $ | 393.1 | $ | 433.9 | $ | (827.0 | ) | $ | 774.0 | |||||||||
F-61
Table of Contents
PEABODY
ENERGY CORPORATION
SUPPLEMENTAL
CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
| Year Ended December 31, 2009 | ||||||||||||||||||||
|
Parent
|
Guarantor
|
Non-Guarantor
|
||||||||||||||||||
| Company | Subsidiaries | Subsidiaries | Eliminations | Consolidated | ||||||||||||||||
| (Dollars in millions) | ||||||||||||||||||||
|
Total revenues
|
$ | — | $ | 4,449.3 | $ | 2,312.5 | $ | (749.4 | ) | $ | 6,012.4 | |||||||||
|
Costs and expenses
|
||||||||||||||||||||
|
Operating costs and expenses
|
104.4 | 3,383.8 | 1,733.8 | (749.4 | ) | 4,472.6 | ||||||||||||||
|
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 | 5.6 | — | 203.8 | |||||||||||||||
|
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
CONDENSED CONSOLIDATING 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 | 1,815.3 | (208.8 | ) | 4,589.7 | |||||||||||||
|
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 | 3.7 | — | 197.3 | |||||||||||||||
|
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
PEABODY
ENERGY CORPORATION
SUPPLEMENTAL
CONDENSED CONSOLIDATING BALANCE SHEETS
| December 31, 2010 | ||||||||||||||||||||
|
Parent
|
Guarantor
|
Non-Guarantor
|
Reclassifications/
|
|||||||||||||||||
| Company | Subsidiaries | Subsidiaries | Eliminations | Consolidated | ||||||||||||||||
| (Dollars in millions) | ||||||||||||||||||||
|
Assets
|
||||||||||||||||||||
|
Current assets
|
||||||||||||||||||||
|
Cash and cash equivalents
|
$ | 903.8 | $ | 5.2 | $ | 386.2 | $ | — | $ | 1,295.2 | ||||||||||
|
Accounts receivable, net
|
2.1 | 5.5 | 550.6 | — | 558.2 | |||||||||||||||
|
Inventories
|
— | 168.0 | 164.9 | — | 332.9 | |||||||||||||||
|
Assets from coal trading activities, net
|
— | 23.8 | 168.7 | — | 192.5 | |||||||||||||||
|
Deferred income taxes
|
— | 78.6 | 47.9 | (6.1 | ) | 120.4 | ||||||||||||||
|
Other current assets
|
307.9 | 30.7 | 120.4 | — | 459.0 | |||||||||||||||
|
Total current assets
|
1,213.8 | 311.8 | 1,438.7 | (6.1 | ) | 2,958.2 | ||||||||||||||
|
Property, plant, equipment and mine development
|
||||||||||||||||||||
|
Land and coal interests
|
— | 4,860.7 | 2,796.3 | — | 7,657.0 | |||||||||||||||
|
Buildings and improvements
|
— | 945.8 | 134.0 | — | 1,079.8 | |||||||||||||||
|
Machinery and equipment
|
— | 1,300.6 | 398.7 | — | 1,699.3 | |||||||||||||||
|
Less: accumulated depreciation, depletion and amortization
|
— | (2,374.4 | ) | (635.6 | ) | — | (3,010.0 | ) | ||||||||||||
|
Property, plant, equipment and mine development, net
|
— | 4,732.7 | 2,693.4 | — | 7,426.1 | |||||||||||||||
|
Investments and other assets
|
9,331.0 | 179.8 | 99.1 | (8,631.1 | ) | 978.8 | ||||||||||||||
|
Total assets
|
$ | 10,544.8 | $ | 5,224.3 | $ | 4,231.2 | $ | (8,637.2 | ) | $ | 11,363.1 | |||||||||
|
Liabilities and Stockholders’ Equity
|
||||||||||||||||||||
|
Current liabilities
|
||||||||||||||||||||
|
Current maturities of long-term debt
|
$ | 25.0 | $ | — | $ | 18.2 | $ | — | $ | 43.2 | ||||||||||
|
Payables to (receivables from) affiliates, net
|
2,225.3 | (2,528.3 | ) | 303.0 | — | — | ||||||||||||||
|
Liabilities from coal trading activities, net
|
— | 29.5 | 152.2 | — | 181.7 | |||||||||||||||
|
Deferred income taxes
|
6.1 | — | — | (6.1 | ) | — | ||||||||||||||
|
Accounts payable and accrued expenses
|
47.4 | 777.2 | 464.2 | — | 1,288.8 | |||||||||||||||
|
Total current liabilities
|
2,303.8 | (1,721.6 | ) | 937.6 | (6.1 | ) | 1,513.7 | |||||||||||||
|
Long-term debt, less current maturities
|
2,609.6 | 0.1 | 97.1 | — | 2,706.8 | |||||||||||||||
|
Deferred income taxes
|
93.2 | 135.4 | 311.2 | — | 539.8 | |||||||||||||||
|
Notes payable to (receivables from) affiliates, net
|
818.9 | (825.3 | ) | 6.4 | — | — | ||||||||||||||
|
Other noncurrent liabilities
|
58.6 | 1,652.8 | 202.1 | — | 1,913.5 | |||||||||||||||
|
Total liabilities
|
5,884.1 | (758.6 | ) | 1,554.4 | (6.1 | ) | 6,673.8 | |||||||||||||
|
Peabody Energy Corporation’s stockholders’ equity
|
4,660.7 | 5,982.9 | 2,648.2 | (8,631.1 | ) | 4,660.7 | ||||||||||||||
|
Noncontrolling interests
|
— | — | 28.6 | — | 28.6 | |||||||||||||||
|
Total stockholders’ equity
|
4,660.7 | 5,982.9 | 2,676.8 | (8,631.1 | ) | 4,689.3 | ||||||||||||||
|
Total liabilities and stockholders’ equity
|
$ | 10,544.8 | $ | 5,224.3 | $ | 4,231.2 | $ | (8,637.2 | ) | $ | 11,363.1 | |||||||||
F-64
Table of Contents
PEABODY
ENERGY CORPORATION
SUPPLEMENTAL
CONDENSED CONSOLIDATING 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
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
| Year Ended December 31, 2010 | ||||||||||||||||
|
Parent
|
Guarantor
|
Non-Guarantor
|
||||||||||||||
| Company | Subsidiaries | Subsidiaries | Consolidated | |||||||||||||
| (Dollars in millions) | ||||||||||||||||
|
Cash Flows From Operating Activities
|
||||||||||||||||
|
Net cash provided by (used in) continuing operations
|
$ | (126.4 | ) | $ | 1,090.6 | $ | 139.5 | $ | 1,103.7 | |||||||
|
Net cash provided by (used in) discontinued operations
|
(14.2 | ) | (2.4 | ) | — | (16.6 | ) | |||||||||
|
Net cash provided by (used in) operating activities
|
(140.6 | ) | 1,088.2 | 139.5 | 1,087.1 | |||||||||||
|
Cash Flows From Investing Activities
|
||||||||||||||||
|
Additions to property, plant, equipment and
|
||||||||||||||||
|
mine development
|
— | (404.5 | ) | (152.5 | ) | (557.0 | ) | |||||||||
|
Investment in Prairie State Energy Campus
|
— | (76.0 | ) | — | (76.0 | ) | ||||||||||
|
Proceeds from disposal of assets, net of notes receivable
|
— | 14.1 | 5.1 | 19.2 | ||||||||||||
|
Investment in equity affiliates and joint ventures
|
— | (15.0 | ) | (3.8 | ) | (18.8 | ) | |||||||||
|
Investments in debt and equity securities
|
— | — | (74.6 | ) | (74.6 | ) | ||||||||||
|
Proceeds from sale of debt securities
|
— | — | 12.4 | 12.4 | ||||||||||||
|
Other, net
|
— | (8.7 | ) | (0.1 | ) | (8.8 | ) | |||||||||
|
Net cash used in investing activities
|
— | (490.1 | ) | (213.5 | ) | (703.6 | ) | |||||||||
|
Cash Flows From Financing Activities
|
||||||||||||||||
|
Proceeds from long-term debt
|
1,150.0 | — | — | 1,150.0 | ||||||||||||
|
Payments of long-term debt
|
(1,146.8 | ) | — | (20.5 | ) | (1,167.3 | ) | |||||||||
|
Dividends paid
|
(79.4 | ) | — | — | (79.4 | ) | ||||||||||
|
Repurchase of employee common stock relinquished for tax
withholding
|
(13.5 | ) | — | — | (13.5 | ) | ||||||||||
|
Payment of debt issuance costs
|
(32.2 | ) | — | — | (32.2 | ) | ||||||||||
|
Excess tax benefits related to share-based compensation
|
51.0 | — | — | 51.0 | ||||||||||||
|
Proceeds from stock options exercised
|
16.4 | — | — | 16.4 | ||||||||||||
|
Other, net
|
5.9 | (5.9 | ) | (2.1 | ) | (2.1 | ) | |||||||||
|
Transactions with affiliates, net
|
724.6 | (587.2 | ) | (137.4 | ) | — | ||||||||||
|
Net cash provided by (used in) financing activities
|
676.0 | (593.1 | ) | (160.0 | ) | (77.1 | ) | |||||||||
|
Net change in cash and cash equivalents
|
535.4 | 5.0 | (234.0 | ) | 306.4 | |||||||||||
|
Cash and cash equivalents at beginning of year
|
368.4 | 0.2 | 620.2 | 988.8 | ||||||||||||
|
Cash and cash equivalents at end of year
|
$ | 903.8 | $ | 5.2 | $ | 386.2 | $ | 1,295.2 | ||||||||
F-66
Table of Contents
PEABODY
ENERGY CORPORATION
SUPPLEMENTAL
CONDENSED CONSOLIDATING 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
|
$ | (213.7 | ) | $ | 792.7 | $ | 476.8 | $ | 1,055.8 | |||||||
|
Net cash provided by (used in) discontinued operations
|
7.4 | (5.3 | ) | (7.7 | ) | (5.6 | ) | |||||||||
|
Net cash provided by (used in) operating activities
|
(206.3 | ) | 787.4 | 469.1 | 1,050.2 | |||||||||||
|
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 | ||||||||||||
|
Investment in equity affiliates and joint ventures
|
— | (5.0 | ) | (10.0 | ) | (15.0 | ) | |||||||||
|
Other, net
|
— | (5.8 | ) | (0.3 | ) | (6.1 | ) | |||||||||
|
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 | ||||||||||||
|
Repurchase of employee common stock relinquished for tax
withholding
|
(2.3 | ) | — | — | (2.3 | ) | ||||||||||
|
Other, net
|
5.1 | — | (7.1 | ) | (2.0 | ) | ||||||||||
|
Transactions with affiliates, net
|
473.9 | (454.6 | ) | (19.3 | ) | — | ||||||||||
|
Net cash provided by (used in) financing activities
|
413.5 | (454.6 | ) | (63.5 | ) | (104.6 | ) | |||||||||
|
Net change in cash and cash equivalents
|
207.2 | (4.3 | ) | 336.2 | 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
|
$ | 368.4 | $ | 0.2 | $ | 620.2 | $ | 988.8 | ||||||||
F-67
Table of Contents
PEABODY
ENERGY CORPORATION
SUPPLEMENTAL
CONDENSED CONSOLIDATING 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
|
$ | 28.7 | $ | 465.6 | $ | 926.5 | $ | 1,420.8 | ||||||||
|
Net cash used in discontinued operations
|
(94.5 | ) | (17.3 | ) | (11.2 | ) | (123.0 | ) | ||||||||
|
Net cash provided by (used in) operating activities
|
(65.8 | ) | 448.3 | 915.3 | 1,297.8 | |||||||||||
|
Net cash provided by continuing operations
|
||||||||||||||||
|
Net cash provided by (used in) discontinued operations
|
||||||||||||||||
|
Net cash provided by operating activities
|
— | (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 | ||||||||||||
|
Investments in equity affiliates and joint ventures
|
— | (2.6 | ) | — | (2.6 | ) | ||||||||||
|
Other, net
|
— | (5.7 | ) | (0.3 | ) | (6.0 | ) | |||||||||
|
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 | ) | ||||||||||
|
Repurchase of employee common stock relinquished for tax
withholding
|
(11.0 | ) | — | — | (11.0 | ) | ||||||||||
|
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
|
220.0 | (93.9 | ) | (624.1 | ) | (498.0 | ) | |||||||||
|
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
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, 2010
|
||||||||||||||||||||
|
Reserves deducted from asset accounts:
|
||||||||||||||||||||
|
Advance royalty recoupment reserve
|
$ | 17.2 | $ | 1.9 | $ | (0.2 | ) | $ | 1.0 | (2) | $ | 19.9 | ||||||||
|
Reserve for materials and supplies
|
6.2 | 0.9 | (0.9 | ) | — | 6.2 | ||||||||||||||
|
Allowance for doubtful accounts
|
18.3 | 26.7 | (6.9 | ) | (7.8 | ) (3) | 30.3 | |||||||||||||
|
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 | ||||||||||||||
| (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-69
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 | |||
| 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 | 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 | .7 | 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). | ||
| 4 | .8 | 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 | .9 | 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 | .10 | 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 | .11 | 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). | ||
Table of Contents
| Exhibit No. | Description of Exhibit | |||
| 4 | .12 | 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 | .13 | 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 | .14 | 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 | .15 | 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 | .16 | 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 | .17 | 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 | .18 | 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 | .19 | 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 | .20 | 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). | ||
| 4 | .21 | 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 | .22 | 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 | .23 | 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 | .24 | 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). | ||
Table of Contents
| Exhibit No. | Description of Exhibit | |||
| 4 | .25 | 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 | .26 | 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 | .27 | 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 | .28 | 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 | .29 | 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 | .30 | 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 | .31 | 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 | .32 | 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 | .33 | Thirty-Third Supplemental Indenture, dated as of August 25, 2010, among Peabody Energy Corporation, the guarantors named therein and U.S. Bank National Association, as trustee, relating to the 6.500% Senior Notes due 2020 (Incorporated by reference to Exhibit 4.1 of the Registrant’s Current Report on Form 8-K filed on August 27, 2010). | ||
| 4 | .34 | 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 | .35 | 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). | ||
| 4 | .36 | 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 | .37 | 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 | .38 | 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). | ||
| 4 | .39 | Notice of Adjustment of Conversion Rate of 4.75% Convertible Junior Subordinated Debentures due 2066, dated February 8, 2010 (Incorporated by reference to Exhibit 4.1 of the Registrant’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2010). | ||
Table of Contents
| Exhibit No. | Description of Exhibit | |||
| 10 | .1 | Credit Agreement, dated as of June 18, 2010, by and among the Company, Bank of America, N.A., as administrative agent, swing line lender and L/C issuer, and Banc of America Securities LLC, Citigroup Global Markets, Inc. and HSBC Securities (USA) Inc., as joint lead arrangers and joint book managers, and the lenders named therein (Incorporated by reference to Exhibit 10.1 of the Registrant’s Current Report on Form 8-K filed on June 24, 2010). | ||
| 10 | .2 | 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 | .3 | 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 | .4 | 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 | .5 | 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 | .6 | 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 | .7 | 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 | .8 | 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 | .9 | 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 | .10 | 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 | .11 | 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 | .12 | 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 | .13 | 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). | ||
| 10 | .14 | 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 | .15 | 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 | .16 | 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 | .17 | 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). | ||
Table of Contents
| Exhibit No. | Description of Exhibit | |||
| 10 | .18* | 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 | .19* | 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 | .20* | 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 | .21* | 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 | .22* | 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 | .23* | 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 | .24* | 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 | .25* | 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 | .26* | 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 | .27* | 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 | .28* | 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 | .29* | 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 | .30* | 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). | ||
| 10 | .31* | 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 | .32* | 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 | .33* | 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 | .34* | 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 | .35* | 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). | ||
Table of Contents
| Exhibit No. | Description of Exhibit | |||
| 10 | .36* | 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 | .37* | 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 | .38* | 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 | .39* | 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 | .40* | 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 | .41* | 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 | .42* | 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 | .43*† | Form of Deferred Stock Units Agreement for Non-Employee Directors. | ||
| 10 | .44* | 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 (Incorporated by reference to Exhibit 10.45 of the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2009). | ||
| 10 | .45* | 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 (Incorporated by reference to Exhibit 10.46 of the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2009). | ||
| 10 | .46* | 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 (Incorporated by reference to Exhibit 10.47 of the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2009). | ||
| 10 | .47* | 2009 Amendment entered into effective December 31, 2009 to the Performance Units Agreement dated January 2, 2008 between the Registrant and Gregory H. Boyce (Incorporated by reference to Exhibit 10.48 of the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2009). | ||
| 10 | .48* | 2009 Amendment entered into effective December 31, 2009 to the Performance Units Agreement dated January 5, 2009 between the Registrant and Gregory H. Boyce (Incorporated by reference to Exhibit 10.49 of the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2009). | ||
| 10 | .49* | 2010 Amendment entered into effective March 17, 2010, to the 2008 Performance Units Award Agreement dated January 2, 2008 between the Registrant and Gregory H. Boyce (Incorporated by reference to Exhibit 10.3 of the Registrant’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2010). | ||
| 10 | .50* | 2010 Amendment entered into effective March 17, 2010, to the 2009 Performance Units Award Agreement dated January 5, 2009 between the Registrant and Gregory H. Boyce (Incorporated by reference to Exhibit 10.4 of the Registrant’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2010). | ||
| 10 | .51* | 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). | ||
Table of Contents
| Exhibit No. | Description of Exhibit | |||
| 10 | .52* | Amendment to the Amended and Restated Employee Stock Purchase Plan of the Registrant (Incorporated by reference to Exhibit 10.51 of the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2009). | ||
| 10 | .53* | 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). | ||
| 10 | .54* | Amendment to the Amended and Restated Australian Employee Stock Purchase Plan of the Registrant (Incorporated by reference to Exhibit 10.53 of the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2009). | ||
| 10 | .55* | 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 | .56* | 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 | .57* | 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 | .58* | 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 | .59* | 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 | .60* | 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 | .61* | 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 | .62* | 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 | .63* | 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 | .64* | 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 | .65* | 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 | .66* | 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 | .67* | 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 | .68* | 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 | .69* | 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 | .70* | 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). | ||
Table of Contents
| Exhibit No. | Description of Exhibit | |||
| 10 | .71* | 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 | .72* | 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). | ||
| 10 | .73* | 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 | .74* | 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 | .75* | 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 | .76* | 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 | .77* | 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 | .78* | 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 | .79* | 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 | .80* | 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 | .81* | 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 | .82* | 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 | .83* | 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 | .84* | 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 | .85* | 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 | .86 | Third Amended and Restated Receivables Purchase Agreement, dated as of January 25, 2010, by and among P&L Receivables Company, LLC, Peabody Energy Corporation, the various Sub-Servicers listed on the signature pages thereto, all Conduit Purchasers listed on the signature pages thereto, all Related Committed Purchasers listed on the signature pages thereto, all Purchaser Agents listed on the signature pages thereto, 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 January 27, 2010). | ||
Table of Contents
| Exhibit No. | Description of Exhibit | |||
| 10 | .87 | First Amendment to Third Amended and Restated Receivables Purchase Agreement, dated as of March 1, 2010, by and among P&L Receivables Company, LLC, Peabody Energy Corporation, the various Sub-Servicers listed on the signature pages thereto, all Conduit Purchasers listed on the signature pages thereto, all Related Committed Purchasers listed on the signature pages thereto, all Purchaser Agents listed on the signature pages thereto, 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 10.2 of the Registrant’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2010). | ||
| 10 | .88 | Second Amendment to Third Amended and Restated Receivables Purchase Agreement, dated as of May 11, 2010, by and among P&L Receivables Company, LLC, Peabody Energy Corporation, the various Sub-Servicers listed on the signature pages thereto, all Conduit Purchasers listed on the signature pages thereto, all Related Committed Purchasers listed on the signature pages thereto, all Purchaser Agents listed on the signature pages thereto, 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 May 17, 2010). | ||
| 10 | .89 | Third Amendment to Third Amended and Restated Receivables Purchase Agreement, dated as of September 16, 2010, by and among P&L Receivables Company, LLC, Peabody Energy Corporation, the various Sub-Servicers listed on the signature pages thereto, all Conduit Purchasers listed on the signature pages thereto, all Related Committed Purchasers listed on the signature pages thereto, all Purchaser Agents listed on the signature pages thereto, 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 Quarterly Report on Form 10-Q for the quarter ended September 30, 2010). | ||
| 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. | ||
| 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, 2010 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. [removed and Reserved]Part 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