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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-K
|
þ
|
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 | |
| For the Fiscal Year Ended December 31, 2006 | ||
| or | ||
|
o
|
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 | |
Commission File Number 1-16463
Peabody Energy Corporation
(Exact name of registrant as specified in its charter)
| Delaware | 13-4004153 | |
| (State or other jurisdiction of incorporation or organization) | (I.R.S. Employer Identification No.) | |
|
701 Market Street, St. Louis, Missouri
|
63101 | |
| (Address of principal executive offices) | (Zip Code) | |
(314) 342-3400
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 Preferred Share Purchase Rights |
New York Stock Exchange New York Stock Exchange |
Securities Registered Pursuant to Section 12(g) of the
Act:
None
Indicate by check mark if the registrant is a well-known
seasoned issuer, as defined in Rule 405 of the Securities
Act Yes þ No o
Indicate by check mark if the registrant is not required to file
reports pursuant to Section 13 or Section 15(d) of the
Act Yes o No þ
Indicate by check mark whether the registrant (1) has filed
all reports required to be filed by Section 13 or 15(d) of
the Securities Exchange Act of 1934 during the preceding
12 months (or for such shorter period that the registrant
was required to file such reports), and (2) has been
subject to such filing requirements for the past
90 days. Yes þ No o
Indicate by check mark if disclosure of delinquent filers
pursuant to Item 405 of
Regulation S-K is
not contained herein, and will not be contained, to the best of
registrant’s knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this
Form 10-K or any
amendment to this
Form 10-K. þ
Indicate by check mark whether the registrant is a large
accelerated filer, an accelerated filer, or a non-accelerated
filer. See definition of “accelerated filer and large
accelerated filer” in
Rule 12b-2 of the
Exchange Act. (Check one):
Large accelerated
filer þ Accelerated
filer o Non-accelerated
filer o
Indicate by check mark whether the registrant is a shell company
(as defined in
Rule 12b-2 of the
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, 2006: Common Stock, par value $0.01 per
share, $14.6 billion.
Number of shares outstanding of each of the Registrant’s
classes of Common Stock, as of February 16, 2007: Common
Stock, par value $0.01 per share, 264,685,954 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 Annual Meeting of Stockholders to be held on
May 1, 2007 (the “Company’s 2007 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.
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CAUTIONARY NOTICE REGARDING FORWARD-LOOKING STATEMENTS
This report includes statements of our expectations, intentions,
plans and beliefs that constitute “forward-looking
statements” within the meaning of Section 27A of the
Securities Act of 1933 and Section 21E of the Securities
Exchange Act of 1934 and are intended to come within the safe
harbor protection provided by those sections. These statements
relate to future events or our future financial performance,
including, without limitation, the section captioned
“Outlook.” We use words such as
“anticipate,” “believe,” “expect,”
“may,” “project,” “will” or other
similar words to identify forward-looking statements.
Without limiting the foregoing, all statements relating to our
future outlook, anticipated capital expenditures, future cash
flows and borrowings, and sources of funding are forward-looking
statements. These forward-looking statements are based on
numerous assumptions that we believe are reasonable, but are
subject to a wide range of uncertainties and business risks and
actual results may differ materially from those discussed in
these statements. Among the factors that could cause actual
results to differ materially are:
| • | ability to renew sales contracts; | |
| • | reductions of purchases by major customers; | |
| • | transportation performance and costs, including demurrage; | |
| • | geology, equipment and other risks inherent to mining; | |
| • | weather; | |
| • | legislation, regulations and court decisions; | |
| • | new environmental requirements affecting the use of coal including mercury and carbon dioxide related limitations; | |
| • | changes in postretirement benefit and pension obligations; | |
| • | changes to contribution requirements to multi-employer benefit funds; | |
| • | availability, timing of delivery and costs of key supplies, capital equipment or commodities such as diesel fuel, steel, explosives and tires; | |
| • | replacement of coal reserves; | |
| • | price volatility and demand, particularly in higher-margin products and in our trading and brokerage businesses; | |
| • | performance of contractors, third-party coal suppliers or major suppliers of mining equipment or supplies; | |
| • | negotiation of labor contracts, employee relations and workforce availability; | |
| • | availability and costs of credit, surety bonds and letters of credit; | |
| • | risks associated with customer contracts, including credit and performance risk; | |
| • | the effects of acquisitions or divestitures, including integration of new acquisitions; | |
| • | economic strength and political stability of countries in which we have operations or serve customers; | |
| • | risks associated with our Btu conversion or generation development initiatives; | |
| • | risks associated with the conversion of our current information systems; | |
| • | growth of domestic and international coal and power markets; | |
| • | coal’s market share of electricity generation; |
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| • | prices of fuels which compete with or impact coal usage, such as oil or natural gas; | |
| • | future worldwide economic conditions; | |
| • | successful implementation of business strategies; | |
| • | variation in revenues related to synthetic fuel production due to expiration of related tax credits at the end of 2007; | |
| • | the effects of changes in currency exchange rates, primarily the Australian dollar; | |
| • | inflationary trends, including those impacting materials used in our business; | |
| • | interest rate changes; | |
| • | litigation, including claims not yet asserted; | |
| • | terrorist attacks or threats; | |
| • | impacts of pandemic illnesses; | |
| • | 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. We do not undertake any obligation to update these
statements, except as required by federal securities laws.
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| 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. |
PART I
| Item 1. | Business. |
Overview
We are the largest private-sector coal company in the world.
During the year ended December 31, 2006, we sold
247.6 million tons of coal. During this period, we sold
coal to over 400 electricity generating and industrial plants in
20 countries. Our coal products fuel approximately 10% of all
U.S. electricity generation and 2% of worldwide electricity
generation. At December 31, 2006, we had 10.2 billion
tons of proven and probable coal reserves.
We own majority interests in 40 coal operations located
throughout all major U.S. coal producing regions and in
Australia. Additionally, we own a minority interest in one
Venezuelan mine through a joint venture arrangement. We shipped
75% of our U.S. mining operations’ coal sales from the
western United States during the year ended December 31,
2006 and the remaining 25% from the eastern United States. Most
of our production in the western United States is low-sulfur
coal from the Powder River Basin. Our overall western
U.S. coal production has increased from 127.0 million
tons in 2001, the year of our initial public offering, to
160.5 million tons during 2006, representing a compounded
annual growth rate of 5%. In the West, we own and operate mines
in Arizona, Colorado, New Mexico and Wyoming. In the East, we
own and operate mines in Illinois, Indiana, Kentucky and West
Virginia. We own six mines, including one late development-stage
mine in Queensland, Australia, and five mines, including one
late development-stage mine and one development-stage mine in
New South Wales, Australia. Our Australian production includes
both low-sulfur thermal coal and high Btu metallurgical coal. We
generated 86% of our production for the year ended
December 31, 2006 from non-union mines.
For the year ended December 31, 2006, 87% of our sales (by
volume) were to U.S. electricity generators, 9% were to
customers outside the United States and 4% were to the
U.S. industrial sector. Approximately 90% of our coal sales
during the year ended December 31, 2006 were under
long-term (one year or greater) contracts. Our sales backlog,
including backlog subject to price reopener and/or extension
provisions, was over one billion tons as of December 31,
2006. The average volume-weighted remaining term of our
long-term contracts was approximately 5 years, with
remaining terms ranging from one to 19 years. We are
targeting 2007 production of 240 to 260 million tons and
total sales volume of 265 to 285 tons, including 15 to
18 million tons of metallurgical coal. As of
December 31, 2006, our unpriced 2007 volumes for planned
produced tonnage were 5 to 15 million U.S. tons and
14 million Australia tons. Our total unpriced planned
production for 2008 is approximately 70 to 80 million tons
in the United States and 20 to 22 million tons in Australia.
In addition to our mining operations, we market, broker and
trade coal. Our total tons traded were 79.1 million for the
year ended December 31, 2006. In response to growing
international markets, we established an international trading
group in 2006 and added another operations office in Europe in
early 2007. We also have a business development, sales and
marketing office in Beijing, China to pursue potential long-term
growth opportunities in this market. Our other energy related
commercial activities include the development of mine-mouth
coal-fueled generating plants, the management of our vast coal
reserve and real estate holdings, coalbed methane production,
and Btu Conversion technologies, which are designed to convert
coal to natural gas and transportation fuels.
History
Peabody, Daniels and Co. was founded in 1883 as a retail coal
supplier, entering the mining business in 1888 as
Peabody & Co. with the opening of our first coal mine
in Illinois. In 1926, Peabody Coal
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Company was listed on the Chicago Stock Exchange and, beginning
in 1949, on the New York Stock Exchange.
In 1955, Peabody Coal Company, primarily an underground mine
operator, merged with Sinclair Coal Company, a major surface
mining company. Peabody Coal Company was acquired by Kennecott
Copper Company in 1968. The company was then sold to Peabody
Holding Company in 1977, which was formed by a consortium of
companies.
During the 1980s, Peabody grew through expansion and
acquisition, opening the North Antelope Mine in Wyoming’s
coal-rich Powder River Basin in 1983 and the Rochelle Mine in
1985, and completing the acquisitions of the West Virginia coal
properties of ARMCO Steel and Eastern Associated Coal Corp.,
which included seven operating mines and substantial low-sulfur
coal reserves in West Virginia.
In July 1990, Hanson, PLC acquired Peabody Holding Company. In
the 1990s, Peabody continued to grow through expansion and
acquisitions. In February 1997, Hanson spun off its
energy-related businesses, including Eastern Group and Peabody
Holding Company, into The Energy Group, plc. The Energy Group
was a publicly traded company in the United Kingdom and its
American Depository Receipts (ADRs) were publicly traded on the
New York Stock Exchange.
In May 1998, Lehman Brothers Merchant Banking Partners II
L.P. and affiliates (“Merchant Banking Fund”), an
affiliate of Lehman Brothers Inc. (“Lehman Brothers”),
purchased Peabody Holding Company and its affiliates, Peabody
Resources Limited and Citizens Power LLC in a leveraged buyout
transaction that coincided with the purchase by Texas Utilities
of the remainder of The Energy Group. In August 2000, Citizens
Power, our subsidiary that marketed and traded electric power
and energy-related commodity risk management products, was sold
to Edison Mission Energy and in January 2001, we sold our
Peabody Resources Limited (in Australia) operations to
Coal & Allied, a 71%-owned subsidiary of Rio Tinto
Limited.
In April 2001, we changed our name to Peabody Energy
Corporation, reflecting our position as a premier energy
supplier. In May 2001, we completed an initial public offering
of common stock, and our shares began trading on the New York
Stock Exchange under the ticker symbol “BTU,” the
globally recognized symbol for energy.
In April 2004, we acquired coal operations from RAG Coal
International AG, expanding our presence in both Australia and
Colorado. In December 2004, we completed the purchase of a 25.5%
equity interest in Carbones del Guasare from RAG Coal
International, S.A. Carbones del Guasare, a joint venture with
Anglo American plc and a Venezuelan governmental partner,
operates Venezuela’s largest coal mine, the Paso Diablo
mine in northwestern Venezuela.
In October 2006, we acquired Excel Coal Limited
(“Excel”), an independent coal company in Australia.
The Excel acquisition included three operating mines, two late
development-stage mines and a development-stage mine, along with
estimated proven and probable coal reserves in excess of
500 million tons.
Peabody has grown significantly in recent years through both
organic growth and acquisitions while transforming itself from a
high sulfur, high-cost coal company to a predominately low
sulfur, low-cost coal producer, marketer/ trader of coal and
manager of vast natural resources. Peabody remains focused on
areas identified as necessary for achieving future 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 that convert coal into natural gas, liquids and
hydrogen.
Mining Operations
We conduct business through three principal mining operating
segments: Western U.S. Mining, Eastern U.S. Mining,
and Australian Mining. Our Western U.S. Mining Operations
consist of our Powder River Basin, Southwest and Colorado
operations, and our Eastern U.S. Mining Operations consist
of our
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Appalachia and Midwest operations. The principal business of the
Western U.S. Mining segment is the mining, preparation and
sale of steam coal, sold primarily to electric utilities. The
principal business of the Eastern U.S. Mining segment is
the mining, preparation and sales of steam coal, sold primarily
to electric utilities, as well as the mining of some
metallurgical coal, sold to steel and coke producers.
Internationally, we operate mines in Queensland, Australia and
New South Wales, Australia and have a 25.5% investment in a
Venezuelan mine. All of our operating segments are discussed in
Note 25 to our consolidated financial statements.
The following describes the operating characteristics of the
principal mines and reserves of each of our business units and
affiliates. The maps below show mine locations as of
December 31, 2006. Included in the descriptions of our
mining operations are discussions of the subsidiaries which
manage the respective mining operation. The subsidiary that
manages a particular mining operation is not necessarily the
same as the subsidiary or subsidiaries which own the assets
utilized in that mining operation. Unless otherwise indicated,
we own 100% of the respective mining operations and related
assets.
U.S. Mining Operations
Powder River Basin Operations
We control approximately 3.5 billion tons of proven and
probable coal reserves in the Southern Powder River Basin, the
largest and fastest growing major U.S. coal-producing
region. Our subsidiaries, Powder River Coal, LLC and Caballo
Coal Company, manage three low-sulfur, non-union surface mining
complexes in Wyoming that sold 138.4 million tons of coal
during the year ended December 31, 2006, or approximately
56% of our total coal sales volume. The North Antelope Rochelle
and Caballo mines are serviced by both major western railroads,
the Burlington Northern Santa Fe (“BNSF”) Railway
and the Union Pacific Railroad. The Rawhide Mine is serviced by
the BNSF Railway.
Our Wyoming Powder River Basin reserves are classified as
surface mineable, subbituminous coal with seam thickness varying
from 60 to 115 feet. The sulfur content of the coal in
current production ranges from 0.2% to 0.4% and the heat value
ranges from 8,300 to 8,900 Btu’s per pound.
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| North Antelope Rochelle Mine |
The North Antelope Rochelle Mine is located 65 miles south
of Gillette, Wyoming. This mine is one of the largest in North
America, selling 88.5 million tons of compliance coal
(defined as having sulfur dioxide content of 1.2 pounds or less
per million Btu) during 2006. The North Antelope Rochelle
facility is capable of loading its production in up to
20 unit trains per day (a unit train generally consists of
100 to 150 cars, each of which holds 100 to 120 tons of coal).
The North Antelope Rochelle Mine produces premium quality coal
with a sulfur content averaging 0.2% and a heat value ranging
from 8,500 to 8,900 Btu per pound. The North Antelope Rochelle
Mine produces the lowest sulfur coal in the United States, using
two draglines along with six truck-and-shovel fleets. A third
dragline is under construction and is scheduled for completion
in mid-2007.
| Caballo Mine |
The Caballo Mine is located 20 miles south of Gillette,
Wyoming. During 2006, it sold 32.8 million tons of
compliance coal. Caballo is a cast/dozer/truck-and-shovel assist
operation with a coal handling system that includes two
12,000-ton silos and two 11,000-ton silos. The Caballo Mine is
capable of loading its production in up to nine unit trains per
day. The Caballo Mine produces compliance coal with a sulfur
content averaging 0.36% and a heat value averaging 8,500 Btu per
pound.
| Rawhide Mine |
The Rawhide Mine is located ten miles north of Gillette, Wyoming
and uses truck-and-shovel mining methods. During 2006, it sold
17.1 million tons of compliance coal. Rawhide is a
cast/dozer-push/truck-and-shovel assist operation with a coal
handling system that includes two 12,000-ton silos and four
11,000-ton silos. The Rawhide Mine is capable of loading its
production in up to six unit trains per day. The Rawhide Mine
produces compliance coal with a sulfur content averaging 0.38%
and a heat value averaging 8,300 Btu per pound.
Southwest Operations
We own three mines in our Southwest operations, and we are
currently operating two of these mines, one in Arizona and one
in New Mexico. The third mine in Arizona suspended operations as
of December 31, 2005. The Arizona mines are managed by our
Peabody Western Coal Company subsidiary. In New Mexico, we own
and manage, through our Peabody Natural Resources Company
subsidiary, the Lee Ranch Mine, which mines and produces
subbituminous medium sulfur coal. Together, these two mines sold
13.2 million tons of coal during 2006. We control
1.0 billion tons of proven and probable coal reserves in
our Southwest operations.
| Kayenta Mine |
The Kayenta Mine, located on the Navajo Nation and Hopi Tribe
lands in Arizona, uses four draglines in three mining areas. It
sold approximately 8.0 million tons of coal during 2006 and
supplies primarily bituminous compliance coal under a long-term
coal supply agreement to an electricity generating station in
the region. The Kayenta Mine coal is crushed, then carried
17 miles by conveyor belt to storage silos where it is
loaded onto a private rail line and transported 83 miles to
the Navajo Generating Station, operated by the Salt River
Project near Page, Arizona. The mine and railroad were designed
to deliver coal exclusively to the power plant, which has no
other source of coal. The Navajo coal supply agreement extends
until 2011. Hourly workers at this mine are members of the
United Mine Workers of America (“UMWA”).
| Lee Ranch Mine |
The Lee Ranch Mine, located near Grants, New Mexico, sold
approximately 5.2 million tons of medium sulfur coal during
2006. Lee Ranch shipped the majority of its coal to two
customers in Arizona and New Mexico under coal supply agreements
extending until 2020 and 2014, respectively. Lee Ranch is
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a non-union surface mine that uses a combination of dragline and
truck-and-shovel mining techniques and ships coal to its
customers via the BNSF Railway.
Colorado Operations
We control approximately 0.2 billion tons of proven and
probable coal reserves and currently have one operating mine in
the Colorado Region. Our Twentymile underground mine is managed
by our Twentymile Coal Company subsidiary. Our Seneca surface
mine is managed by our Seneca Coal Company subsidiary and ceased
mining operations at the end of 2005.
| Twentymile Mine |
The Twentymile Mine is located in Routt County, Colorado, and
sold 8.8 million tons of compliance, low-sulfur, steam coal
of above average heat content for the region to customers
throughout the United States during 2006. This mine uses both
longwall and continuous mining equipment. Our Twentymile Mine is
non-union and has been one of the largest and most productive
underground mines in the United States. Approximately 78% of all
coal shipped is loaded on the Union Pacific railroad; the
remainder is hauled by truck. This mine also provides coal to
the nearby Hayden Generating Station, operated by the Public
Service of Colorado, under a coal supply agreement that extends
until 2011.
Appalachia/ Highland Operations
The Appalachia/ Highland Operations consist of five wholly-owned
business units and related facilities, a joint venture in West
Virginia and one business unit in western Kentucky. Our
subsidiary, Pine Ridge Coal Company, LLC, manages the Big
Mountain Business Unit, and our subsidiary, Rivers Edge Mining,
Inc. manages our Rivers Edge Mine in our Wells Business Unit.
Our Eastern Associated Coal, LLC subsidiary manages the
remaining wholly-owned West Virginia facilities. In addition,
Highland Mining manages the Highland No. 9 Mine in western
Kentucky. During 2006, these operations sold approximately
18.8 million tons of compliance, medium-sulfur and
high-sulfur steam and metallurgical coal to customers in the
United States and abroad. Metallurgical coal from these
operations accounted for 5.6 million tons of total sales
for the year. In addition to our wholly-owned facilities, we own
a 73.9% interest in KE Ventures LLC, a joint venture which owns
and manages underground mining operations. We control
approximately 0.6 billion tons of proven and probable coal
reserves in our Appalachia operations. Our Appalachia Operations
also own a 30% interest in a partnership that leases a coal
export terminal from the Peninsula Port Authority of Virginia
and utilizes the terminal for exports.
| Big Mountain Business Unit and Contract Mines |
The Big Mountain Business Unit is based near Prenter, West
Virginia. This business unit’s primary source of coal
(approximately 55% of total shipments) is the Big Mountain
No. 16 operation with the remainder from contract mine
production from coal reserves we control. All production is
processed at the business unit’s preparation facility.
During 2006, the Big Mountain Business Unit sold approximately
2.0 million tons of steam coal. Big Mountain No. 16 is
an underground mine using continuous mining equipment. Processed
coal is loaded on the CSX railroad. Our hourly employees at the
Big Mountain Business Unit are represented by the UMWA.
| Harris Business Unit |
The Harris Business Unit is based near Bald Knob, West Virginia.
The business unit’s primary source of coal is the Harris
No. 1 Mine. The business unit also has a small amount of
contract mine production from a mine also located near Bald
Knob, West Virginia. The Harris Business Unit sold approximately
1.5 million tons of primarily metallurgical product during
2006. This mine uses both longwall and continuous mining
equipment. In 2006, the Harris Business Unit transitioned to the
James Creek reserves, allowing it to access additional
metallurgical coal. Hourly employees at the Harris Business Unit
are represented by the UMWA.
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| Rocklick Business Unit and Contract Mines |
The Rocklick preparation plant, located near Wharton, West
Virginia, processes metallurgical coal produced by the Harris
Business Unit and steam coal produced from contract mining
operations. This preparation plant shipped approximately
2.2 million tons of contract mine steam coal during 2006.
Processed coal is loaded at the plant site on the CSX railroad
or transferred via conveyor to our Kopperston loadout facility
and loaded on the Norfolk Southern railroad. Hourly employees at
the Rocklick preparation plant are represented by the UMWA.
| Wells Business Unit |
The Wells Business Unit, located near Wharton, West Virginia,
sold approximately 3.1 million tons of metallurgical and
steam coal during 2006. Wells operates a preparation plant and
processes coal production from the Rivers Edge Mine and contract
mines that use continuous mining equipment. The processed coal
is loaded on the CSX railroad. Hourly employees at the Wells
preparation plant and Rivers Edge Mine are represented by the
UMWA.
| Federal Business Unit |
The Federal Business Unit consists of the Federal No. 2
Mine, near Fairview, West Virginia, and uses longwall and
continuous mining equipment to extract coal. The business unit
operates a preparation plant which processed and shipped
approximately 4.5 million tons of steam coal during 2006.
Coal shipped from the Federal No. 2 Mine has sulfur content
only slightly above that of medium sulfur coal and has above
average heating content for the region. As a result, it is more
marketable than some other medium sulfur coals. The CSX and
Norfolk Southern railroads jointly serve the mine. Hourly
employees at the Federal Business Unit are represented by the
UMWA.
| Highland Business Unit |
The Highland No. 9 Mine, which uses continuous mining
equipment, is managed by our Highland Mining Company, LLC
subsidiary and is located near Waverly, Kentucky. The mine sold
3.5 million tons of steam coal during 2006. This business
unit also operates a preparation plant and barge loading
facility. Hourly employees at the Highland No. 9 Mine are
represented by the UMWA.
| KE Ventures Joint Venture |
We own a 73.9% interest in KE Ventures LLC, a joint venture
which owns and manages underground mining operations, a
preparation plant and barge-and-rail loading facilities near
Marmet, West Virginia. The mines are non-union and use
continuous mining equipment. The joint venture shipped
2.0 million tons during 2006.
Midwest Operations
Our Midwest Operations consist of 14 wholly-owned mines in the
Illinois Basin and are comprised of our Midwest Coal
Resources II, LLC, Indian Hill Company, Coulterville Coal
Company, LLC, Black Beauty Holding Company, LLC and Arclar LLC
subsidiaries. We control approximately 4.2 billion tons of
proven and probable coal reserves in the Midwest. In 2006, these
operations collectively sold 35.9 million tons of coal,
more than any other Midwestern coal producer. We ship coal from
these mines primarily to electricity generators in the
Midwestern United States and to industrial customers for power
generation.
| Midwest Coal Resources II, LLC |
Midwest Coal Resources II, LLC owns and manages three mines
in western Kentucky. Patriot, a surface mine, and Freedom, an
underground mine, are located in Henderson County, Kentucky, and
sold 1.4 million tons and 1.3 million tons of steam
coal, respectively, in 2006. The Big Run underground mine,
located in Ohio County, Kentucky, closed in December 2006 due to
loss of the mine’s sole customer. The
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mine sold 1.3 million tons of steam coal in 2006. The two
underground mines use continuous mining equipment and the
surface mine uses truck and shovel equipment. Midwest Coal
Resources II, LLC also owns and operates a preparation
plant and a coal loading dock. All Midwest Coal
Resources II, LLC employees are non-union.
| Indian Hill Company |
Indian Hill Company, our wholly-owned subsidiary, owns Dodge
Hill Holding JV, LLC, which manages Dodge Hill No. 1, an
underground mine located in Union County, Kentucky. Dodge Hill
No. 1 has non-union employees and sold 1.1 million
tons of steam coal in 2006.
| Coulterville Coal Company |
Coulterville Coal Company, LLC owns the Gateway Mine in Randolph
County, located in southwestern Illinois. During 2006, the
Gateway Mine sold 2.4 million tons of steam coal. The mine,
which has non-union employees, is managed and operated by our
wholly-owned subsidiary, Black Beauty Coal Company.
| Black Beauty Coal Company |
The Black Beauty Coal Company, LLC mines sold 22.5 million
tons of compliance, medium sulfur and high sulfur steam coal
during 2006. Black Beauty’s principal Indiana mines include
Air Quality, Farmersburg, Francisco and Somerville. Air Quality
is an underground coal mine located near Monroe City, Indiana
that sold 2.2 million tons of compliance coal during 2006.
Farmersburg is a surface mine located in Vigo and Sullivan
counties in Indiana that sold 3.8 million tons of medium
sulfur coal during 2006. The Francisco Mine Complex, located in
Gibson County, Indiana mines coal by utilizing both surface
mining and underground mining methods and sold 3.1 million
tons of medium sulfur coal during 2006. The Somerville Mine
Complex, also located in Gibson County, sold a total of
8.6 million tons of medium sulfur coal in 2006. Two other
surface mines located in Indiana, Viking and Miller Creek,
collectively sold 3.1 million tons of medium sulfur coal
during 2006.
Black Beauty’s Riola Mine Complex is an underground mining
facility in eastern central Illinois. The Riola Mine Complex
sold 1.7 million tons of medium sulfur coal during 2006.
Due to unforeseen geologic conditions, and for the safety of our
employees, Black Beauty reoriented its mine plan in 2006
resulting in the closure of the Riola Portal, with all
subsequent production coming from the Vermilion Grove Portal.
All Black Beauty Coal Company employees are non-union.
Black Beauty owns a 75% interest in United Minerals Company,
LLC. United Minerals, which utilizes a non-union workforce,
currently acts as a contract miner for Black Beauty on a portion
of the Somerville Mine Complex reserves and is a contract
operator for Black Beauty at the Evansville River Terminal coal
dock located on the Ohio River.
| Arclar Company LLC |
We operate the Wildcat Hills surface mine and Willow Lake
underground mining complex located in Gallatin and Saline
counties in southern Illinois. During 2006, these mines sold
2.4 million tons and 3.5 million tons, respectively,
of medium sulfur coal that is primarily shipped by barge to
downriver utility plants. An underground portal was added to the
Wildcat Hills operation in mid-2006. Black Beauty provides a
non-union contract workforce to mine the surface reserves at
Wildcat Hills. The hourly workforce at the Willow Lake
underground mine, which is represented under an International
Brotherhood of Boilermakers labor agreement, is supplied by our
Big Ridge, Inc. subsidiary. This labor agreement expired in
October 2006 and negotiations are continuing for a new labor
agreement. The hourly workforce is working under the provisions
of the previous labor agreement.
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Australian Mining Operations
In October 2006, we acquired Excel Coal Limited, an independent
coal company in Australia, which added three operating mines
(Wambo Open-Cut, Metropolitan and Chain Valley), two late
development-stage mines (Wilpinjong and Millennium) and a
development-stage mine (North Wambo Underground) to our
Australia operations. Following the acquisition, we manage six
mines in Queensland, Australia, and five mines in New South
Wales, Australia, through our wholly-owned subsidiary, Peabody
Pacific Pty Limited. During 2006, our Australian operations sold
11.0 million tons of coal, 6.5 millions tons of which
were metallurgical coal. Coal from the Queensland mines is
shipped via rail and truck from the mine to the Dalrymple Bay
Coal Terminal and the Ports of Gladstone and Brisbane, where the
coal is loaded onto ocean-going vessels while coal from the New
South Wales mines is shipped via rail and truck from the mine to
domestic customers and to the Ports of Newcastle and Kembla. The
majority of sales from our Australian mines are denominated in
U.S. dollars. Our Australian mines operate with
site-specific collective bargaining labor agreements. Our
Australian operations control 0.8 billion tons of proven
and probable coal reserves.
| Wilkie Creek Mine |
The Wilkie Creek Coal Mine, located in Queensland, Australia, is
a surface, truck-and-shovel operation. In 2006, the Wilkie Creek
Mine sold 2.0 million tons of steam coal, all of which was
sold to the Asia export market through the Port of Brisbane.
| Burton Mine |
The Burton Mine, located in Queensland, Australia, is a surface
mine using the truck-and-shovel terrace mining technique. We own
95% of the Burton operation and the remaining 5% interest is
owned by the contract miner that operates on reserves we
control. During 2006, we sold 3.5 million tons of
metallurgical coal and 0.6 million tons of steam coal from
the Burton Mine through the Dalrymple Bay Coal Terminal.
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| Millennium Mine |
The Millennium Mine, located in Queensland, Australia, is a
surface operation utilizing truck-and-shovel mining methods.
This mine is expected to begin shipments of metallurgical coal
through the Dalrymple Bay Coal Terminal in early 2007, with
production targeted at 1.6 million tons. We own an 84.6%
interest in the Millennium Mine and manage the operations
utilizing a contract miner.
| North Goonyella Mine |
The North Goonyella Mine, located in Queensland, Australia, is a
longwall underground operation. The North Goonyella Mine
operates in a difficult geologic environment and produces a
high-quality metallurgical coal product. During 2006, the North
Goonyella Mine sold 1.2 million tons of metallurgical coal
through the Dalrymple Bay Coal Terminal.
| Eaglefield Mine |
The Eaglefield Mine, located in Queensland, Australia, is a
surface operation utilizing truck-and-shovel mining methods. It
is adjacent to, and fulfills contract tonnages in conjunction
with the North Goonyella underground mine. Coal is mined by a
contractor from reserves that we control. During 2006, the
Eaglefield mine sold 1.4 million tons of metallurgical coal
through the Dalrymple Bay Coal Terminal.
| Baralaba Mine |
The Baralaba Mine, located in Queensland, Australia, is a
surface operation utilizing truck-and-shovel mining methods. The
mine produces steam coal and a pulverized coal
injection (“PCI”) product, a substitute for
metallurgical coal used primarily by steel makers. Shipments
through the Port of Gladstone commenced in the first quarter of
2006. During 2006, the Baralaba Mine sold 0.1 million tons
of steam coal and 0.1 million tons of PCI product. We own a
62.5% interest in the Baralaba Mine and manage the operations,
utilizing a contract miner.
| Wambo Open-Cut Mine |
The Wambo Open-Cut Mine, located in New South Wales, Australia,
is a surface operation utilizing truck-and-shovel mining
methods. In 2006, the Wambo Open-Cut Mine sold 4.6 million
tons of steam coal for the full year and sold 1.3 million
tons of steam coal since the acquisition. The coal from this
mine was shipped the through the Port of Newcastle. We own a 75%
interest in the Wambo Open-Cut Mine and manage the operations
utilizing a contract miner.
| North Wambo Underground Mine |
The North Wambo Underground Mine, located in New South Wales,
Australia, is under development and is expected to begin
shipments in mid to late 2007, with production targeted for
approximately 3 million tons per year over the next several
years. This longwall mining operation plans to produce steam
coal and semi-soft metallurgical coal for shipment to customers
through the Port of Newcastle. We own a 75% interest in the
Wambo Underground Mine.
| Metropolitan Mine |
The Metropolitan Mine, located in New South Wales, Australia, is
a longwall underground operation. In 2006, the Metropolitan Mine
sold 1.7 million tons of hard and semi-hard metallurgical
coal for the full year and sold 0.5 million tons of this
coal since the acquisition. Coal shipments from this mine are to
export customers through Port Kembla and to an Australian
domestic customer.
| Wilpinjong Mine |
The Wilpinjong Mine, located in New South Wales, Australia, is a
new open-cut mine that was under development until late 2006.
The mine is expected to produce 6-7 million tons of thermal
coal in 2007 for
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shipment to export customers through the Port of Newcastle in
addition to serving a domestic electricity generator. Coal is
mined by a contractor from reserves that we control.
| Chain Valley Mine |
The Chain Valley Mine located in New South Wales, Australia, is
a room and pillar underground operation. The Chain Valley Mine
produces thermal coal which is sold locally to power authorities
and to export customers through the Port of Newcastle. The mine
sold 0.8 million tons of thermal coal for the full year and
sold 0.3 million tons of thermal coal since it was acquired
in October 2006. We own 80% of the Chain Valley Mine.
Venezuelan Mining Operations
Our Venezuelan Operations consist of two joint ventures,
including one operating mine and one coal mine development
project.
| Carbones del Guasare, S.A. |
We own a 25.5% interest in Carbones del Guasare, S.A., a joint
venture that includes Anglo American plc and a Venezuelan
governmental partner. Carbones del Guasare operates the Paso
Diablo Mine in Venezuela. The Paso Diablo Mine is a surface
operation in northwestern Venezuela that produces approximately
6 to 8 million tons of steam coal annually for export
primarily to the United States and Europe. We are responsible
for our pro-rata share of sales from Paso Diablo; the joint
venture is responsible for production, processing and
transportation of coal to ocean-going vessels for delivery to
customers.
| Las Carmelitas Coal Project |
We own a 51.0% interest in Excelven Pty Ltd., which holds a
96.7% interest in Cosila Complejo Siderurgico Del Lago S.A.
(“Cosila”) and all of Transportes Coal-Sea de
Venezuela C.A. Cosila owns the Las Carmelitas coal mine
development project, which has approximately 30 million
tons of reserves in Venezuela. The other partners in this
project include Alpha Natural Resources and Triangle Resource
Fund. This project is currently in the exploratory stage. This
interest was obtained through the Excel acquisition in October
2006.
Resource Management
We hold approximately 10.2 billion tons of proven and
probable coal reserves and more than 350,000 acres of
surface property. Our resource development group constantly
reviews these reserves for opportunities to generate revenues
through the sale of non-strategic coal reserves and surface
land. In addition, we generate revenue through royalties from
coal reserves and oil and gas rights leased to third parties,
coalbed methane production and farm income from surface land
under third-party contracts.
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Sales and Marketing
Our sales, trading, brokerage and marketing operations include
COALSALES, LLC; COALSALES II, LLC; COALTRADE, LLC and
COALTRADE International, LLC. Through our sales, trading,
brokerage and marketing departments, we sell coal produced by
our diverse portfolio of operations, broker coal sales of other
coal producers both as principal and agent, trade coal and
emission allowances and provide transportation-related services.
As of December 31, 2006, we had 85 employees in our sales,
trading, brokerage, marketing and transportation operations,
including personnel dedicated to performing market research,
contract administration and risk management activities.
| International Expansion |
In response to growing international markets, we established an
international trading group in 2006. This group began trading in
international markets in May 2006 and added another operations
office in Europe in early 2007. The sales and marketing
operations also include our COALTRADE Australia operation that
brokers coal in the Australia and Pacific Rim markets, and is
based in Newcastle, Australia. We also have a business
development, sales and marketing office in Beijing, China to
pursue potential long-term growth opportunities in this market.
In 2006, Shenhua Group Corporation Limited and Peabody announced
that the two companies have signed a memorandum of understanding
to pursue business development opportunities of mutual interest.
The agreement formalizes the parties’ mutual interest in
working together in coal and coal-related projects and
initiatives. Shenhua Group Corporation Limited is the
wholly-state owned parent company of the Hong Kong stock
exchange-listed China Shenhua Energy Company Limited.
Long-Term Coal Supply Agreements
We currently have a sales backlog in excess of one billion tons
of coal, including backlog subject to price reopener and/or
extension provisions, and our coal supply agreements have
remaining terms ranging from one to 19 years and an average
volume-weighted remaining term of approximately 5 years.
For 2006, we sold approximately 90% of our sales volume under
long-term coal supply agreements. In 2006, we sold coal to over
400 electricity generating and industrial plants in 20
countries. Our primary customer base is in the United States,
although customers in the Pacific Rim and other international
locations represent an increasing portion of our revenue stream.
One of our largest coal supply agreements is the subject of
ongoing litigation and arbitration, as discussed in Item 3.
Legal Proceedings.
We expect to continue selling a significant portion of our coal
under long-term supply agreements. Our strategy is to
selectively renew, or enter into new, long-term coal supply
contracts when we can do so at prices we believe are favorable.
Long-term contracts are attractive for regions where market
prices are expected to remain stable, for cost-plus arrangements
serving captive electricity generating plants and for the sale
of high-sulfur coal to “scrubbed” generating plants.
To the extent we do not renew or replace expiring long-term coal
supply agreements, our future sales will be subject to market
fluctuations.
In January 2006, we signed a
19-year,
65-million-ton coal
supply agreement with Arizona Public Service Company
(“APS”). The contract is expected to generate revenue
in excess of $1 billion. When our planned 6 million
ton per year El Segundo Mine begins production in 2008, it will
serve APS’s Cholla Generating Station near Joseph City,
Arizona, and other customers. In December 2006, we signed a
10-year coal supply
agreement with Tennessee Valley Authority to supply
6 million tons per year of Illinois Basin coal. Coal sales
under the first five years of the agreement are expected to be
in excess of $1 billion. Assumed as part of the Excel Coal
Limited acquisition, we have a
19-year coal supply
agreement with Macquarie Generation, which runs through 2025 and
will supply approximately 127 million tons in total.
Typically, customers enter into coal supply agreements to secure
reliable sources of coal at predictable prices, while we seek
stable sources of revenue to support the investments required to
open, expand and maintain or improve productivity at the mines
needed to supply these contracts. The terms of coal supply
agreements result from competitive bidding and extensive
negotiations with customers. Consequently, the
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terms of these contracts vary significantly in many respects,
including price adjustment features, price reopener terms, coal
quality requirements, quantity parameters, permitted sources of
supply, treatment of environmental constraints, extension
options, force majeure, and termination and assignment
provisions.
Each contract sets a base price. Some contracts provide for a
predetermined adjustment to the base price at times specified in
the agreement. Base prices may also be adjusted quarterly,
annually or at other periodic intervals for changes in
production costs and/or changes due to inflation or deflation.
Changes in production costs may be measured by defined formulas
that may include actual cost experience at the mine as part of
the formula. The inflation/deflation adjustments are measured by
public indices, the most common of which is the implicit price
deflator for the gross domestic product as published by the
U.S. Department of Commerce. In most cases, the components
of the base price represented by taxes, fees and royalties which
are based on a percentage of the selling price are also adjusted
for any changes in the base price and passed through to the
customer. Some contracts allow the base price to be adjusted to
reflect the cost of capital.
Most contracts contain provisions to adjust the base price due
to new statutes, ordinances or regulations that impact our cost
of performance under the agreement. Additionally, some contracts
contain provisions that allow for the recovery of costs impacted
by the modifications or changes in the interpretation or
application of any existing statute by local, state or federal
government authorities. Some agreements provide that if the
parties fail to agree on a price adjustment caused by cost
increases due to changes in applicable laws and regulations,
either party may terminate the agreement.
Price reopener provisions are present in many of our multi-year
coal contracts. These provisions may allow either party to
commence a renegotiation of the contract price at various
intervals. In a limited number of agreements, if the parties do
not agree on a new price, the purchaser or seller has an option
to terminate the contract. Under some contracts, we have the
right to match lower prices offered to our customers by other
suppliers.
Quality and volumes for the coal are stipulated in coal supply
agreements, and in some limited instances buyers have the option
to vary annual or monthly volumes if necessary. Variations to
the quality and volumes of coal may lead to adjustments in the
contract price. Most coal supply agreements contain provisions
requiring us to deliver coal within certain ranges for specific
coal characteristics such as heat (Btu), sulfur, and ash
content, and for grindability and ash fusion temperature.
Failure to meet these specifications can result in economic
penalties, suspension or cancellation of shipments or
termination of the contracts. Coal supply agreements typically
stipulate procedures for quality control, sampling and weighing.
In the eastern United States, approximately half of our
customers require that the coal is sampled and weighed at the
destination, whereas in the western United States, samples and
weights are usually taken at the shipping source.
Contract provisions in some cases set out mechanisms for
temporary reductions or delays in coal volumes in the event of a
force majeure, including events such as strikes, adverse mining
conditions or serious transportation problems that affect the
seller or unanticipated plant outages that may affect the buyer.
More recent contracts stipulate that this tonnage can be made up
by mutual agreement. Buyers often negotiate similar clauses
covering changes in environmental laws. We often negotiate the
right to supply coal that complies with a new environmental
requirement to avoid contract termination. Coal supply
agreements typically contain termination clauses if either party
fails to comply with the terms and conditions of the contract,
although most termination provisions provide the opportunity to
cure defaults.
In some of our contracts, we have a right of substitution,
allowing us to provide coal from different mines, including
third-party production, as long as the replacement coal meets
the contracted quality specifications and will be sold at the
same delivered cost.
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Transportation
Usually coal consumed domestically is sold at the mine and
transportation costs are borne by the purchaser. Export coal is
usually sold at the loading port, with purchasers paying ocean
freight. Producers usually pay shipping costs from the mine to
the port, including any demurrage costs.
The majority of our sales volume is shipped by rail, but a
portion of our production is shipped by other modes of
transportation, including barge, truck and ocean-going vessels.
Our transportation department manages the loading of coal via
these transportation modes.
Approximately 12,000 unit trains are loaded each year to
accommodate the coal shipped by our mines overall. A unit train
generally consists of 100 to 150 cars, each of which can hold
100 to 120 tons of coal. We believe we have good relationships
with rail carriers and barge companies due, in part, to our
modern coal-loading facilities and the experience of our
transportation coordinators.
Suppliers
The main types of goods we purchase are mining equipment and
replacement parts, explosives, fuel, tires, steel-related
(including roof control) products and lubricants. Although we
have many well-established, strategic relationships with our key
suppliers, we do not believe that we are dependent on any of our
individual suppliers, except as noted below. The supplier base
providing mining materials has been relatively consistent in
recent years, although there continues to be some consolidation.
Consolidation of suppliers of explosives has limited the number
of sources for these materials. Although our current supply of
explosives is concentrated with one supplier, some alternative
sources are available to us in the regions where we operate.
Further consolidation of underground equipment suppliers has
resulted in a situation where purchases of certain underground
mining equipment are concentrated with one principal supplier;
however, supplier competition continues to develop. In recent
years, demand for certain surface and underground mining
equipment and
off-the-road tires has
increased. As a result, lead times for certain items have
generally increased, although no material impact is currently
expected to our financial condition, results of operations or
cash flows.
Technical Innovation
To support the continued growth and globalization of our
businesses, our Board of Directors approved a project to convert
our existing information systems across the major business
processes to an integrated information technology system
provided by SAP AG. This project will establish a single global
information platform for Peabody and will enable standard
processes and real-time capabilities in Finance, Materials,
Maintenance, Human Resources, Sales, Production, Transportation
and Quality across all of our domestic and Australia operations.
The project began in the first half of 2006 with development
activities, and implementation is targeted to occur mid-2007 in
the U.S. and late 2007 to early 2008 for Australia.
We continue to place great emphasis on the application of
technical innovation to improve new and existing equipment
performance. This research and development effort is typically
undertaken and funded by equipment manufacturers using our input
and expertise. Our engineering, maintenance and purchasing
personnel work together with manufacturers to design and produce
equipment that we believe will add value to the business.
We are continuing a major effort to improve the performance of
our dragline systems. The dragline improvement effort includes
more efficient bucket design, faster cycle times, improved swing
motion controls to increase component life and better monitors
to enable increased payloads. A dragline is being refurbished
and upgraded in Wyoming with many new design features including
a new trapezoidal boom, larger bucket, larger hoist motors and
additional drag and swing motors. The upgrade modifications are
expected to increase the dragline system capacity by 20% over
the original capacity. The dragline is expected to be
commissioned near the end of the first quarter of 2007. A large
dragline in Arizona was upgraded with many of the same
improvements in 2006. All draglines are equipped with stress and
performance monitoring equipment.
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Technology to quickly capture, analyze and transfer information
regarding safety, performance and maintenance conditions at our
operations is a priority. A wireless data acquisition system has
been installed at the North Antelope Rochelle Mine to more
efficiently dispatch mobile equipment and monitor performance
and condition of all major mining equipment on a real-time
basis. There are plans to rollout the system to other mining
operations. Proprietary software for hand-held Personal Digital
Assistant (“PDA”) devices was developed, and is being
used, for safety observations, audits and front-line supervisor
reports.
World-class maintenance standards based on condition-based
maintenance practices are being implemented at all operations.
Use of these techniques is expected to allow us to increase
equipment utilization and reduce capital spending by extending
the equipment life, while minimizing the risk of premature
failures. Lubrication is replaced and work is scheduled on
condition rather than time. Benefits from sophisticated
lubrication analysis and quality-control include lower
lubrication consumption, optimum equipment performance and
extended component life. Specialized maintenance reliability
software is currently being installed, on a phased schedule, to
better predict equipment condition in order to optimize
component replacement timing.
Our mines use sophisticated software to schedule and monitor
trains, mine and pit blending, quality and customer shipments.
The integrated software was developed in-house and provides a
competitive tool to differentiate our reliability and product
consistency. We are one of the largest users of advanced coal
quality analyzers among coal producers, according to the
manufacturer of this equipment. These analyzers allow continuous
analysis of certain coal quality parameters, such as sulfur
content. Their use helps ensure consistent product quality and
helps customers meet stringent air emission requirements.
We are also involved in the commercial development and
advancement of Btu Conversion technologies (See the Btu
Conversion discussion that follows for more details).
Competition
The markets in which we sell our coal are highly competitive.
According to the National Mining Association’s “2005
Coal Producer Survey,” the top 10 coal companies in the
United States produced approximately 67% of total domestic coal
in 2005. Our principal U.S. competitors are other large
coal producers, including Arch Coal, Inc., Rio Tinto Energy
America, CONSOL Energy Inc, Foundation Coal Corporation and
Massey Energy Company, which collectively accounted for
approximately 39% of total U.S. coal production in 2005.
Major international competitors include Rio Tinto,
Anglo-American PLC and BHP Billiton.
A number of factors beyond our control affect the markets in
which we sell our coal. Continued demand for our coal and the
prices obtained by us depend primarily on the coal consumption
patterns of the electricity and steel industries in the United
States, China, India and elsewhere around the world; the
availability, location, cost of transportation and price of
competing coal; and other electricity generation and fuel supply
sources such as natural gas, oil, nuclear and hydroelectric.
Coal consumption patterns are affected primarily by the demand
for electricity, environmental and other governmental
regulations, and technological developments. We compete on the
basis of coal quality, delivered price, customer service and
support, and reliability.
Generation Development
To maximize our coal assets and land holdings for long-term
growth, we continue to pursue the development of coal-fueled
generating projects in areas of the U.S. where electricity
demand is strong and where there is access to land, water,
transmission lines and low-cost coal. The projects involve
mine-mouth generating plants using our surface lands and coal
reserves. Our ultimate role in these projects could take
numerous forms, including, but not limited to, equity partner,
contract miner or coal lessor. The projects we are currently
pursuing, as further detailed below, include the 1,600
plus-megawatt Prairie State Energy Campus in Washington County,
Illinois and the 1,500-megawatt Thoroughbred Energy Campus in
Muhlenberg County, Kentucky.
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We are continuing to progress on the permitting processes,
transmission access agreements and contractor-related activities
for developing clean, low-cost mine-mouth generating plants
using our surface lands and coal reserves. Because coal costs
just a fraction of natural gas, mine-mouth generating plants can
provide low-cost electricity to satisfy growing baseload
generation demand. The plants will be designed to comply with
all current clean air standards using advanced emissions control
technologies. The plants, assuming all necessary permits and
financing are obtained and following selection of partners and
sale of a majority of the output of each plant, could be
operational following a four-year construction phase.
| Prairie State Energy Campus |
Our Prairie State Energy Campus (“Prairie State”) is a
planned 1,600 plus-megawatt coal-fueled electricity generation
project located in Washington County, Illinois. Prairie State
would be fueled by over six million tons of coal each year
produced from adjacent underground mining operations. In
February 2005, a group of Midwest rural electric cooperatives
and municipal joint action agencies entered into definitive
agreements to acquire approximately 47% of the project. This
group of investors is comprised of Soyland Power Cooperative,
Inc. (“SPCI”) (subsequently assigned to Prairie Power,
Inc.), Kentucky Municipal Power Agency (“KMPA”),
Wolverine Power Cooperative, Northern Illinois Municipal Power
Agency, Indiana Municipal Power Agency and the Missouri Joint
Municipal Electric Utility Commission (“MJMEUC”). In
October 2006, Prairie State entered into agreements with the
KMPA, the MJMEUC and the SPCI for the right to purchase an
additional 6% equity share of the project. Also in October 2006,
we entered an agreement with CMS Enterprises to equally share an
expected 30% equity interest in Prairie State and to oversee
development and operation of the generating plant. We also
signed a letter of intent with Bechtel Power Corporation in
October 2006 to provide engineering and procurement services for
development of the power-related facilities at Prairie State.
The above are all key milestones in the development of Prairie
State.
In January 2005, the State of Illinois issued the final air
permit for the electric generating station and adjoining coal
mine. After an initial appeal, the Illinois Environmental
Protection Agency reissued the air permit on April 28,
2005. The same parties who filed the earlier permit challenge
filed a new appeal on June 8, 2005. In the third quarter of
2006, the Prairie State Energy Campus received affirmation of
the air quality permit from the Environmental Appeals Board of
the U.S. Environmental Protection Agency; however, in the
fourth quarter of 2006, parties that had previously challenged
the permit filed a new appeal with the United States
7th Circuit Court of Appeals.
| Thoroughbred Energy Campus |
In 2003, the 1,500-megawatt Thoroughbred Energy Campus
(“Thoroughbred”) in Muhlenberg County, Kentucky
received a conditional Certificate to Construct from the
Commonwealth of Kentucky. We and the Commonwealth of Kentucky
defended the air permit granted to Thoroughbred in 2002 as
certain environmental groups challenged the permit, and in April
2006, we received a decision affirming the air permit for our
Thoroughbred Energy Campus. This milestone allows us to continue
advancing the development of that campus. Certain parties
subsequently challenged the favorable decision in Kentucky state
court. If successfully completed, the Thoroughbred Energy
project is expected to utilize approximately six million tons of
coal each year.
| FutureGen Industrial Alliance |
We are a founding member of the FutureGen Industrial Alliance
(“FutureGen”), a non-profit company that is partnering
with the U.S. Department of Energy (“DOE”) to
facilitate the design, construction and operation of the
world’s first near-zero emission coal-fueled power plant.
FutureGen is intended to demonstrate advanced coal-based
technologies to generate electricity and also produce hydrogen
to power fuel cells for transportation and other energy needs.
The technology is expected to integrate the capture of carbon
emissions with carbon sequestration, helping to address the
issue of climate change as energy demand continues to grow
worldwide. The alliance announced in December 2005 that it
entered into a cooperative agreement with the DOE to develop and
site in the United States the cleanest
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coal-fueled power plant in the world with a target of zero
emissions, hydrogen production and carbon dioxide sequestration
capabilities. Four candidate sites (two in Texas and two in
Illinois) are finalists to host FutureGen. The DOE will review
the candidate sites in accordance with the National
Environmental Policy Act prior to the Alliance’s selection
of a final site by late-summer 2007.
Btu Conversion
With the increase in domestic demand for natural gas and oil
based commodities, we have placed significant attention on
determining how we can participate in technologies to
economically convert our coal resources. Technology has advanced
over the last twenty years to convert coal to natural gas as
well as liquids, such as diesel fuel, gasoline and jet fuel.
In October 2005, we reached an agreement to acquire a 30%
interest in Econo-Power International Corporation
(“EPIC™”). We will invest up to $6 million
for the 30% interest and will assist in developing coal supply
options for customers of that technology. As of
December 31, 2006, we have funded $4.1 million under
this agreement and hold a 25.35% interest. EPIC™ systems
use air-blown gasifiers to convert coal into a synthetic gas
that is ideal for industrial applications.
In July 2006, we announced that we had entered into a joint
development agreement with Rentech, Inc. to evaluate sites in
the Midwest and Montana for
coal-to-liquids
projects that would transform coal into diesel and jet fuel.
Projects would be sited where we have large reserves and would
be designed using Rentech’s proprietary Fischer-Tropsch
coal-to-liquids
process. Plant production could range from 10,000 to
30,000 barrels of fuel per day (“bpd”). A
10,000 bpd plant would use 2 to 3 million tons of coal
annually and a 30,000 bpd plant would use 6 to
9 million tons of coal annually, dependent on the quality
of coal. With more than 10.2 billion tons of reserves, we
have numerous sites in the United States that have potential for
Btu Conversion projects.
Coalbed Methane and Oil and Gas Properties
We continue to evaluate the potential of the coalbed methane
business and will make acquisitions, develop our properties,
enter into joint operating agreements and ventures with other
companies or make property sales as appropriate. Our subsidiary,
Peabody Natural Gas, LLC, produces coalbed methane and
conventional gas and oil from its operations in the Southern
Powder River Basin near the Caballo Mine and North Antelope
Rochelle Mine. As of December 31, 2006, we operated 62
coalbed methane and conventional gas and oil wells with net
production of approximately 1.7 million cubic feet per day.
We are evaluating coalbed methane resources in several deep coal
seams in the Powder River Basin and continue to evaluate coalbed
methane and shale gas opportunities in southern Illinois and
Indiana, western Kentucky, and West Virginia.
Certain Liabilities
We have significant long-term liabilities for reclamation (also
called asset retirement obligations), work-related injuries and
illnesses, pensions and retiree health care. In addition, labor
contracts with the UMWA and voluntary arrangements with
non-union employees include long-term benefits, notably health
care coverage for retired employees and future retirees and
their dependents. The majority of our existing liabilities
relate to our past operations.
Asset Retirement Obligations. Asset retirement
obligations primarily represent the present value of future
anticipated costs to restore surface lands to productivity
levels equal to or greater than pre-mining conditions, as
required by the Surface Mining Control and Reclamation Act.
Expense (which includes liability accretion and asset
amortization) for the years ended December 31, 2006, 2005
and 2004 was $40.1 million, $35.9 million, and
$42.4 million, respectively. As of December 31, 2006,
our asset retirement obligations of $423.0 million included
$354.0 million related to locations with active mining
operations and $69.0 million related to locations that are
closed or inactive.
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Workers’ Compensation. These liabilities represent
the actuarial estimates for compensable, work-related injuries
(traumatic claims) and occupational disease, primarily black
lung disease (pneumoconiosis). The Federal Black Lung Benefits
Act requires employers to pay black lung awards to current and
former employees who filed claims after June 1973. Workers’
compensation liabilities were $264.4 million as of
December 31, 2006, $31.0 million of which was a
current liability. The adoption of the Financial Accounting
Standards Board’s recently issued Statement of Financial
Accounting Standard (“SFAS”) No. 158,
“Employers’ Accounting for Defined Benefit Pension and
Other Postretirement Plans”
(“SFAS No. 158”) on December 31, 2006
resulted in a decrease to our workers’ compensation
liability of $4.5 million and a decrease to accumulated
other comprehensive loss of $2.7 million, net of tax.
Therefore, in accordance with SFAS No. 158, the
$264.4 million liability as of December 31, 2006
represented the accumulated obligation related to our
workers’ compensation plans, including unrecognized
actuarial gains. Expense for the years ended December 31,
2006, 2005 and 2004 was $44.0 million, $56.1 million
and $59.2 million, respectively.
Pension-Related Provisions. Pension-related costs
represent the actuarially-estimated cost of pension benefits.
Annual minimum contributions to the pension plans are determined
by consulting actuaries based on the minimum funding standards
of the Employee Retirement Income Security Act of 1974, as
amended (“ERISA”), and an agreement with the Pension
Benefit Guaranty Corporation. Beginning on January 1, 2008,
new minimum funding standards will be required by the Pension
Protection Act of 2006. Pension-related liabilities were
$128.6 million as of December 31, 2006,
$1.3 million of which was a current liability. The adoption
of SFAS No. 158 on December 31, 2006 resulted in
an increase to our pension-related liability of
$14.9 million and an increase to accumulated other
comprehensive loss of $8.0 million, net of tax. Therefore,
in accordance with SFAS No. 158, the
$128.6 million liability as of December 31, 2006
represented the projected benefit obligation associated with our
pension plans, including unrecognized actuarial losses and prior
service cost, less the fair value of pension plan assets.
Expense for the years ended December 31, 2006, 2005 and
2004 was $26.3 million, $38.7 million and
$28.5 million, respectively.
Retiree Health Care. Consistent with
SFAS No. 106, “Employers’ Accounting for
Postretirement Benefits Other Than Pensions” we record a
liability representing the estimated cost of providing retiree
health care benefits to current retirees and active employees
who will retire in the future. Provisions for active employees
represent the amount recognized to date, based on their service
to date; additional amounts are accrued periodically so that the
total estimated liability is accrued when the employee retires.
Our retiree health care liabilities were $1.45 billion as
of December 31, 2006, $82.6 million of which was a
current liability. The adoption of SFAS No. 158 on
December 31, 2006 resulted in an increase to our retiree
health care liabilities of $395.5 million and an increase
to accumulated other comprehensive loss of $237.3 million,
net of tax. Therefore, in accordance with
SFAS No. 158, the $1.45 billion liability as of
December 31, 2006 represented the accumulated benefit
obligations of our retiree health care liabilities, including
any unrecognized actuarial losses and prior service cost.
Expense for the years ended December 31, 2006, 2005 and
2004 was $108.4 million, $99.0 million and
$58.4 million, respectively.
A second category of retiree health care obligations represents
the liability for future contributions to certain multi-employer
health funds. The United Mine Workers of America Combined Fund
was created by federal law in 1992. This multi-employer fund
provides health care benefits to a closed group of retirees
including our retired former employees who last worked prior to
1976, as well as orphaned beneficiaries of bankrupt companies
who were receiving benefits as orphans prior to the 1992 law. No
new retirees will be added to this group. The liability is
subject to increases or decreases in per capita health care
costs, offset by the mortality curve in this aging population of
beneficiaries. Another fund, the 1992 Benefit Plan created by
the same federal law in 1992, provides benefits to qualifying
retired former employees of bankrupt companies who have
defaulted in providing their former employees with retiree
medical benefits. Beneficiaries continue to be added to this
fund as employers default in providing their former employees
with retiree medical benefits, but the overall exposure for new
beneficiaries into this fund is limited to retirees covered
under their employer’s plan who retired prior to
October 1, 1994. A third fund, the 1993 Benefit Fund, was
established through collective bargaining and provides benefits
to qualifying retired
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former employees who retired after September 30, 1994 of
certain signatory companies who have gone out of business and
have defaulted in providing their former employees with retiree
medical benefits. Beneficiaries continue to be added to this
fund as employers go out of business.
On December 20, 2006, President Bush signed the Surface
Mining Control and Reclamation Act Amendments of 2006 (the
“2006 Act”). Prior to the enactment of this new law,
federal statutes required certain Peabody subsidiaries to make
contributions to two coal industry retiree health funds for
costs of “orphans” who are retirees and their
dependents of bankrupt companies that defaulted in providing
their health care benefits. These orphan benefits will be the
responsibility of the federal government on a phased-in basis.
The legislation authorizes $490 million per year in general
fund revenues to pay for these and other benefits under the
bill. In addition, future interest from the federal Abandoned
Mine Land (“AML”) trust fund and previous unused
interest from the AML trust fund will be available to offset
orphan retiree health care costs. Under current projections from
the health funds, these available resources are more than
adequate to cover all anticipated costs of orphan retirees.
These amounts are also in addition to any amounts that may be
appropriated by Congress at its discretion. The legislation also
reduces AML fees currently paid by us on coal production.
Beginning in October 2007, those fees will be reduced by ten
percent from current levels for five years, and then twenty
percent from current levels for ten years, at which point the
authority to collect fees will expire.
The 2006 Act specifically amended the federal laws establishing
the Combined Fund, the 1992 Benefit Plan and the 1993 Benefit
Plan. The 2006 Act provides new and additional funding to all
three programs, subject to the limitations described below. The
2006 Act guarantees full funding of all beneficiaries in the
Combined Fund by supplementing the annual transfers of interest
earned on the AML trust fund. The 2006 Act further provides
funding for the annual orphan health costs under the 1992
Benefit Plan on a phased-in basis: 25%, 50% and 75% in the years
2008, 2009 and 2010, respectively. Thereafter, federal funding
will pay for 100% of the orphan health costs. The coal producers
that signed the 1988 labor agreement, including some of our
subsidiaries, remain responsible for the costs of the 1992
Benefit Plan in 2007. The 2006 Act also included the 1993
Benefit Plan as one of the statutory funds and authorizes the
trustees of the 1993 Benefit Plan to determine the contribution
rates through 2010 for pre-2007 beneficiaries. During calendar
years 2008 through 2010, federal funding will pay a portion of
the 1993 Benefit Plan’s annual health costs on a phased-in
basis; 25%, 50% and 75% in the years 2008, 2009 and 2010,
respectively. The 1993 Benefit Plan trustees have set a
$2.00 per hour statutory contribution rate for 2007. Under
the 2006 Act, these new and additional federal expenditures to
the Combined Fund, 1992 Benefit Plan, 1993 Benefit Plan and
certain Abandoned Mine Land payments to the states and Indian
tribes are collectively limited by an aggregate annual cap of
$490 million. To the extent that (i) the annual
funding of the programs exceeds this amount (plus the amount of
interest from the AML trust fund paid with respect to the
Combined Benefit Fund), and (ii) Congress does not allocate
additional funds to cover the shortfall, contributing employers
and affiliates, including some of our subsidiaries, would be
responsible for the additional costs. Those of our subsidiaries
that have agreed to the 2007 National Bituminous Coal Wage
Agreement will pay $0.50 per hour worked to the 1993
Benefit Plan to provide benefits for post 2006 beneficiaries. To
the extent the $0.50 per hour payment exceeds the amount
needed for this purpose, the difference will be credited against
the $2.00 per hour statutory payment.
Obligations to the United Mine Workers of America Combined Fund
were $30.8 million as of December 31, 2006,
$5.2 million of which was a current liability. Expense for
the years ended December 31, 2006, 2005 and 2004 was
$2.5 million, $0.9 million and $4.9 million,
respectively. The 1992 Benefit Fund and the 1993 Benefit Fund
are expensed as payments are made and no liability is recorded
other than amounts due and unpaid. Expense related to these
funds was $5.7 million, $4.0 million and
$4.4 million for the years ended December 31, 2006,
2005 and 2004, respectively.
Employees
As of December 31, 2006, we had approximately 9,200
employees. Approximately 60% of our hourly employees were
non-union as of December 31, 2006 and they generated 86% of
our 2006 coal production. Relations with our employees and,
where applicable, organized labor are important to our success.
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We opened training centers in the eastern, midwest and western
regions of the United States under our “Workforce of the
Future” initiative. Due to our current employee
demographics, a significant portion of our current hourly
employees will retire over the next decade. Our training centers
are educating our workforce, particularly our most recent hires,
in our rigorous safety standards, the latest in mining
techniques and equipment, and the centers serve as centers for
dissemination of mining best practices across all of our
operations. Our training efforts exceed minimum government
standards for safety and technical expertise with the intent of
developing and retaining a world-class workforce. Additionally,
we are implementing a supervisor training program through our
training centers to develop both new and current supervisors, in
an effort to ensure the replenishment of our operating
management workforce over the next decade.
| United States Labor Relations |
Approximately 66% of our U.S. miners are non-union and are
employed in the states of Wyoming, Colorado, Indiana, New
Mexico, Illinois and Kentucky. The UMWA represented
approximately 26% of our subsidiaries’ hourly employees,
who generated 11% of our U.S. production during the year
ended December 31, 2006. An additional 5% of our hourly
employees are represented by labor unions other than the UMWA.
These employees generated 1% of our production during the year
ended December 31, 2006. Hourly workers at our mine in
Arizona are represented by the UMWA under the Western Surface
Agreement of 2000, which is effective through September 1,
2007. Our union workforce east of the Mississippi River is
primarily represented by the UMWA. The UMWA-represented workers
at one of our eastern mines operate under a contract that
expires on December 31, 2007. The remainder of our
UMWA-represented workers in the east operate under a recently
signed, five-year labor agreement expiring December 31,
2011. This contract replaced a contract that had expired on
December 31, 2006 and mirrors the 2007 National Bituminous
Coal Wage Agreement.
| Australia Labor Relations |
The Australian coal mining industry is unionized and the
majority of workers employed at our Australian Mining Operations
are members of trade unions. The Construction Forestry Mining
and Energy Union represents our hourly production employees. As
of December 31, 2006, our Australian hourly employees were
approximately 9% of our hourly workforce and generated 2% of our
total production in the year then ended. The labor agreement at
our Wilkie Creek Mine was renewed in June 2006 and that
agreement expires in June 2009. The North Goonyella Mine
operates under an agreement due to expire in 2008, and the
Metropolitan Mine operates under an agreement that expires in
June 2007.
Regulatory Matters — United States
Federal, state and local authorities regulate the U.S. coal
mining industry with respect to matters such as employee health
and safety, permitting and licensing requirements, air quality
standards, water pollution, plant and wildlife protection, the
reclamation and restoration of mining properties after mining
has been completed, the discharge of materials into the
environment, surface subsidence from underground mining and the
effects of mining on groundwater quality and availability. In
addition, the industry is affected by significant legislation
mandating certain benefits for current and retired coal miners.
Numerous federal, state and local governmental permits and
approvals are required for mining operations. We believe that we
have obtained all permits currently required to conduct our
present mining operations.
We endeavor to conduct our mining operations in compliance with
all applicable federal, state and local laws and regulations.
However, because of extensive and comprehensive regulatory
requirements, violations during mining operations occur from
time to time in the industry. None of the violations to date or
the monetary penalties assessed has been material.
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| Mine Safety and Health |
Our goal is to achieve excellent safety and health performance.
We measure our progress in this area primarily through the use
of accident frequency rates. 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 the establishment of safety
standards; and recording, reporting and investigating all
accidents, incidents and losses to avoid reoccurrence. A portion
of the annual performance incentives for our operating units is
tied to their safety record.
Our safety performance in 2006, as measured by accident
frequency rates, was 38% better than the U.S. average for
our industry. During 2006, we achieved our vision of zero
accidents at 12 of our facilities, which contributed to our
second best year ever in safety. We received multiple safety
awards during the year, including our third consecutive Holmes
Safety Association’s Green River Council award at our Big
Run Mine in Ohio County, Kentucky; our second consecutive Safe
Sam award at our North Antelope Rochelle Mine, Wyoming’s
safest mine and our most productive; and the Mountaineer
Guardian Award from the West Virginia Office of Miners’
Health, Safety and Training and the West Virginia Coal
Association for outstanding safety achievement at our Federal
No. 2 underground mine. Our training centers educate our
employees in safety best practices and reinforce our
company-wide belief that productivity and profitability follow
when safety is a cornerstone of all of our operations. See the
“Employees” section above for a discussion of our
Workforce of the Future initiative.
Stringent health and safety standards have been in effect since
Congress enacted the Coal Mine Health and Safety Act of 1969.
The Federal Mine Safety and Health Act of 1977 significantly
expanded the enforcement of safety and health standards and
imposed safety and health standards on all aspects of mining
operations. Congress enacted The Mine Improvement and New
Emergency Response Act of 2006 (“The Miner Act”) as a
result of the increase in fatal accidents primarily at
U.S. underground mines. Among the new requirements, each
miner must have at least two, one-hour Self Contained Self
Rescue (“SCSR”) devices for their use in the event of
an emergency (each miner had at least one SCSR device prior to
The Miner Act) and additional caches of rescuers in the escape
routes leading to the surface. Our cost for the additional SCSR
devices, storage boxes, training units and lifelines to assist
miners in potentially dangerous escape routes has exceeded
$10 million. Our evacuation training programs have been
expanded to include more comprehensive training with the SCSR
devices and frequent tours of the escape routes in their
entirety. The Miner Act also requires installation of two-way
communications systems that allows communication between rescue
workers and trapped miners following an accident as mine
operators must have the ability to locate each miner’s last
known position immediately before and after a disaster occurs.
Since these technologies are not yet available, our underground
mines currently locate miners with existing mine communications
telephone systems and we are working with the National Institute
for Occupational Safety and Health and several manufacturers to
develop new communications and location systems. The projected
costs for a new system are approximately $10 million. We
are also constructing rescue chambers for trapped miners who are
unable to use escape routes due to fires or obstructions and
providing at least two mine rescue teams located within thirty
minutes of each mine. See risks inherent to mining in
Item 1A. Risk Factors.
Most of the states in which we operate have state programs for
mine safety and health regulation and enforcement. Collectively,
federal and state safety and health regulation in the coal
mining industry is perhaps the most comprehensive and pervasive
system for protection of employee health and safety affecting
any segment of U.S. industry. As a result of the increase
in fatal accidents primarily at U.S. underground mines,
several states have adopted new safety regulations and the Mine
Safety and Health Administration has passed numerous emergency
regulations including emergency notification and response plans,
increased fines for violations and added mine rescue coverage
requirements. While these changes have had a significant effect
on our operating costs, our U.S. competitors with
underground mines are subject to the same degree of regulation.
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| Black Lung |
In the United States, 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.
| Coal Industry Retiree Health Benefit Act of 1992 |
The Coal Industry Retiree Health Benefit Act of 1992 (“Coal
Act”) provides for the funding of health benefits for
certain UMWA retirees. The Coal Act established the Combined
Fund into which “signatory operators” and
“related persons” are obligated to pay annual premiums
for beneficiaries. The Coal Act also created a second benefit
fund, the 1992 Benefit Plan, for miners who retired between
July 21, 1992, and September 30, 1994, and whose
former employers are no longer in business. Annual payments made
by certain of our subsidiaries under the Coal Act totaled
$13.5 million, $6.3 million $19.3 million,
respectively, during the years ended December 31, 2006,
2005 and 2004.
The 2006 Act specifically amended the federal laws establishing
the Combined Fund, the 1992 Benefit Plan and the 1993 Benefit
Plan. The 2006 Act provides new and additional funding to all
three programs, subject to the limitations described below. The
2006 Act guarantees full funding of all beneficiaries in the
Combined Fund by supplementing the annual transfers of interest
earned on the AML trust fund. The 2006 Act further provides
funding for the annual orphan health costs under the 1992
Benefit Plan on a phased-in basis: 25%, 50% and 75% in the years
2008, 2009 and 2010, respectively. Thereafter, federal funding
will pay for 100% of the orphan health costs. The coal producers
that signed the 1988 labor agreement, including some of our
subsidiaries, remain responsible for the costs of the 1992
Benefit Plan in 2007. The 2006 Act also included the 1993
Benefit Plan as one of the statutory funds and authorizes the
trustees of the 1993 Benefit Plan to determine the contribution
rates through 2010 for pre-2007 beneficiaries. During calendar
years 2008 through 2010, federal funding will pay a portion of
the 1993 Benefit Plan’s annual health costs on a phased-in
basis; 25%, 50% and 75% in the years 2008, 2009 and 2010,
respectively. The 1993 Benefit Plan trustees have set a
$2.00 per hour statutory contribution rate for 2007. Under
the 2006 Act, these new and additional federal expenditures to
the Combined Fund, 1992 Benefit Plan, 1993 Benefit Plan and
certain Abandoned Mine Land payments to the states and Indian
tribes are collectively limited by an aggregate annual cap of
$490 million. To the extent that (i) the annual
funding of the programs exceeds this amount (plus the amount of
interest from the AML trust fund paid with respect to the
Combined Benefit Fund), and (ii) Congress does not allocate
additional funds to cover the shortfall, contributing employers
and affiliates, including some of our subsidiaries, would be
responsible for the additional costs. Those of our subsidiaries
that have agreed to the 2007 National Bituminous Coal Wage
Agreement will pay $0.50 per hour worked to the 1993
Benefit Plan to provide benefits for post 2006 beneficiaries. To
the extent the $0.50 per hour payment exceeds the amount
needed for this purpose, the difference will be credited against
the $2.00 per hour statutory payment.
Our subsidiaries have been billed a retroactive assessment in
the amount of $7.4 million for periods prior to
October 1, 2003 as well as an increase of $0.7 million
for the period from October 1, 2003 through
September 30, 2004 and $0.6 million from October 2004
through August 15, 2005 as a result of the Social Security
Administration’s premium recalculation. These amounts were
paid as required by the Combined Fund Trustees, but were
paid under protest. In August 2005, a federal district court in
Maryland ruled in favor of our subsidiaries, and we suspended
payments to the Combined Fund to recoup our overpayment. On
December 2, 2005, the same federal court granted a stay of
payment recoupment, and we paid to the Combined Fund the amount
we recouped. In December 2006, the Fourth Circuit Court of
Appeals upheld the Maryland district court’s finding that
the Social Security Administration’s premium calculation was
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unlawful. Our subsidiaries are pursuing a refund of the
$8 million overpayment made to the Combined Fund.
| Environmental Laws |
We are subject to various federal, state and foreign
environmental laws. Some of these laws, discussed below, place
many requirements on our coal mining operations. Federal and
state regulations require regular monitoring of our mines and
other facilities to ensure compliance.
| Surface Mining Control and Reclamation Act |
In the United States, the Surface Mining Control and Reclamation
Act of 1977 (“SMCRA”), which is administered by the
Office of Surface Mining Reclamation and Enforcement
(“OSM”), establishes mining, environmental protection
and reclamation standards for all aspects of U.S. surface
mining as well as many aspects of deep mining. Mine operators
must obtain SMCRA permits and permit renewals for mining
operations from the OSM. Where state regulatory agencies have
adopted federal mining programs under the act, the state becomes
the regulatory authority. Except for Arizona, states in which we
have active mining operations have achieved primary control of
enforcement through federal authorization. In Arizona, we mine
on tribal lands and are regulated by OSM because the tribes do
not have SMCRA authorization.
SMCRA permit provisions include requirements for coal
prospecting; mine plan development; topsoil removal, storage and
replacement; selective handling of overburden materials; mine
pit backfilling and grading; protection of the hydrologic
balance; subsidence control for underground mines; surface
drainage control; mine drainage and mine discharge control and
treatment; and re-vegetation.
The U.S. mining permit application process is initiated by
collecting baseline data to adequately characterize the pre-mine
environmental condition of the permit area. This work includes
surveys of cultural resources, soils, vegetation, wildlife,
assessment of surface and ground water hydrology, climatology
and wetlands. In conducting this work, we collect geologic data
to define and model the soil and rock structures and coal that
we will mine. We develop mine and reclamation plans by utilizing
this geologic data and incorporating elements of the
environmental data. The mine and reclamation plan incorporates
the provisions of SMCRA, the state programs and the
complementary environmental programs that impact coal mining.
Also included in the permit application are documents defining
ownership and agreements pertaining to coal, minerals, oil and
gas, water rights, rights of way and surface land and documents
required of the OSM’s Applicant Violator System.
Once a permit application is prepared and submitted to the
regulatory agency, it goes through a completeness and technical
review. Public notice of the proposed permit is given for a
comment period before a permit can be issued. Some SMCRA mine
permits take over a year to prepare, depending on the size and
complexity of the mine and often take six months to two years to
be issued. Regulatory authorities have considerable discretion
in the timing of the permit issuance and the public has the
right to comment on and otherwise engage in the permitting
process, including public hearings and through intervention in
the courts.
Before a SMCRA permit is issued, a mine operator must submit a
bond or other form of financial security to guarantee the
performance of reclamation obligations. The Abandoned Mine Land
Fund, which is part of SMCRA, requires a fee on all coal
produced in the U.S. The proceeds are used to rehabilitate
lands mined and left unreclaimed prior to August 3, 1977
and to pay health care benefit costs of orphan beneficiaries of
the Combined Fund. The fee is $0.35 per ton of
surface-mined coal and $0.15 per ton of deep-mined coal,
effective through September 30, 2007. Pursuant to the Tax
Relief and Health Care Act of 2006, from October 1, 2007
through September 30, 2012, the fee will be $0.315 per
ton of surface-mined coal and $0.135 per ton of underground
mined coal. From October 1, 2012 through September 30,
2021, the fee will be $0.28 per ton of surface-mined coal
and $0.12 per ton of underground mined coal.
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SMCRA stipulates compliance with many other major environmental
programs. These programs include the Clean Air Act; Clean Water
Act; Resource Conservation and Recovery Act (“RCRA”);
and Comprehensive Environmental Response, Compensation, and
Liability Acts (“CERCLA”, commonly known as
“Superfund”). Besides OSM, other Federal regulatory
agencies are involved in monitoring or permitting specific
aspects of mining operations. The U.S. Environmental
Protection Agency (“EPA”) is the lead agency for
States or Tribes with no authorized programs under the Clean
Water Act, RCRA and CERCLA. The U.S. Army Corps of
Engineers regulates activities affecting navigable waters and
the U.S. Bureau of Alcohol, Tobacco and Firearms
(“ATF”) regulates the use of explosive blasting.
We do not believe there are any substantial matters that pose a
risk to maintaining our existing mining permits or hinder our
ability to acquire future mining permits. It is our policy to
comply in all material respects with the requirements of the
Surface Mining Control and Reclamation Act and the state and
tribal laws and regulations governing mine reclamation.
| Clean Air Act |
The Clean Air Act and the corresponding state laws that regulate
the emissions of materials into the air affect U.S. coal
mining operations both directly and indirectly. Direct impacts
on coal mining and processing operations may occur through Clean
Air Act permitting requirements and/or emission control
requirements relating to particulate matter. The Clean Air Act
indirectly, but more significantly, affects the coal industry by
extensively regulating the air emissions of sulfur dioxide,
nitrogen oxide, mercury and other compounds emitted by
coal-based electricity generating plants.
Title IV of the Clean Air Act places limits on sulfur
dioxide emissions from electric power generation plants. The
limits set baseline emission standards for these facilities.
Reductions in emissions occurred in Phase I in 1995 and in
Phase II in 2000 and apply to all coal-based power plants.
The affected electricity generators have been able to meet these
requirements by, among other ways, switching to lower sulfur
fuels; installing pollution control devices, such as flue gas
desulfurization systems, which are known as
“scrubbers;” reducing electricity generating levels;
or purchasing sulfur dioxide emission allowances. Emission
sources receive these sulfur dioxide emission allowances, which
can be traded or sold to allow other units to emit higher levels
of sulfur dioxide. Title IV also required that certain
categories of coal-based electric generating stations install
certain types of nitrogen oxide controls. Major changes in
Title IV were recently promulgated in the Clean Air
Interstate Rule (“CAIR”) discussed below.
In July 1997, the EPA adopted new, more stringent National
Ambient Air Quality Standards for very fine particulate matter
(PM2.5) and ozone. As a result, some states will be required to
change their existing implementation plans to attain and
maintain compliance with the new air quality standards. Our
mining operations and electricity generating customers are
likely to be directly affected when the revisions to the air
quality standards are implemented by the states. State and
federal regulations relating to implementation of the new air
quality standards may restrict our ability to develop new mines
or could require us to modify our existing operations.
In December 2003, the EPA proposed the CAIR, which is designed
to help bring the eastern half of the United States into
compliance with the National Ambient Air Quality Standards for
fine particulates and ozone. The rule became final in March 2005
and will require further reduction of sulfur dioxide and
nitrogen oxide emissions from electricity generating plants in
28 states and the District of Columbia although it is being
challenged. Once fully implemented, the rule will reduce sulfur
dioxide from power plants by approximately 73% from 2003 levels
and, by 2015, nitrogen oxide emissions by approximately 61% from
2003 levels. CAIR is currently under review in court on a number
of grounds, including the assertion that the regulation is
insufficiently stringent.
On September 21, 2006, EPA promulgated new National Ambient
Air Quality Standards revising and updating the 1997 particulate
matter standards. The new regulations made the
24-hour standard for
PM2.5 more stringent but left the annual PM2.5 standard
unchanged. It also left the
24-hour standard for
PM10 (particulate matter equal to 10 microns or more) unchanged
and terminated the annual PM10 standard. The change to the
24-hour PM2.5 standard
is expected to have an effect on the use of coal for electric
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generation, but it is impossible at this time to quantify that
effect. Lawsuits seeking to compel EPA to adopt more stringent
standards both for PM2.5 and PM10 have been filed and are
pending in court. It is not possible to determine the chances of
success for those lawsuits.
The Clean Air Act also requires electricity generators that
currently are major sources of nitrogen oxide in moderate or
higher ozone non-attainment areas (areas where the air quality
does not meet acceptable standards) to install reasonably
available control technology for nitrogen oxide, which is a
precursor of ozone. In 1997, the EPA promulgated the final
“NOx SIP Call” rules that require coal-fueled power
plants in 19 eastern states and Washington, D.C. to make
substantial reductions in nitrogen oxide emissions. These states
were required to submit their Phase II SIPs by April 2005.
Two additional states, Georgia and Missouri, were required to
submit a complete NOx SIP by April 2005 to address affected
portions of their states. In August 2005, EPA stayed the
applicability of the NOx SIP Call to Georgia, although the stay
may be reconsidered. Installation of additional control measures
required under the final rules has made and will continue to
make it more costly to operate coal-based electricity generating
plants.
The Justice Department, on behalf of the EPA, has filed a number
of lawsuits since November 1999, alleging that 12 electricity
generators violated the new source review provisions of the
Clean Air Act Amendments at power plants in the midwestern and
southern United States. Six electricity generators have
announced settlements with the Justice Department requiring the
installation of additional control equipment on selected
generating units, and at least one generator has received a
favorable court decision. If the remaining electricity
generators are found to be in violation, they could be subject
to civil penalties and be required to install the required
control equipment or cease operations. One of the currently
pending enforcement cases is now before the U.S. Supreme
Court, with a decision expected shortly. Another of these cases
was recently decided adversely to the utility, and the utility
has asked the Supreme Court to review the case. Our customers
are among the electricity generators subject to enforcement
actions and if found not to be in compliance, our customers
could be required to install additional control equipment at the
affected plants or they could decide to close some or all of
those plants. If our customers decide to install additional
pollution control equipment at the affected plants, we have the
ability to supply coal from various regions to meet any new coal
requirements.
In 2002 and again in 2003, EPA promulgated new regulations
clarifying and modifying its new source review regulations,
including with respect to electric generation sources that
utilize coal. These regulations have been litigated and
partially remanded to EPA, which has proposed new regulations
and is considering proposing others. There is also ongoing
litigation concerning aspects of the regulations. These
regulations could affect the pending new source review
enforcement cases, whether additional cases are brought, and the
extent to which other existing coal-based electric generating
units may undertake repairs, replacements and modifications
without triggering a requirement to install new pollution
control equipment. It is difficult to determine at this point
the exact configuration of the final new source review
regulations that ultimately will emerge and the impact they will
have on the utilization of coal for electric generation.
The Clean Air Act set a national goal of the prevention of any
future, and the remedying of any existing, impairment of
visibility in 156 national parks and wilderness areas across the
U.S. Under regulations issued by the EPA in 1999, states
were required to consider setting a goal of restoring natural
visibility conditions in Class I areas in their states by
2064 and to explain their reasons to the extent they determine
not to adopt this goal. The state plans must require the
application of “Best Available Retrofit Technology”
(“BART”) after 2010 on certain electric generating
stations reasonably anticipated to cause or contribute to
regional haze which impairs visibility in these areas. The
extent and nature of these BART requirements have been the
subject of litigation. As a result of the litigation, EPA
finalized amendments to the 1999 BART regulations in June 2005.
EPA included in the amendments guidelines for states to use in
determining which facilities must install controls and the types
of controls the facilities must use. States are required to
develop their implementation plans by December 2007. For
electric generating units subject to CAIR in states that adopt
the CAIR cap and trade program for sulfur dioxide and NOx, the
state is allowed to apply CAIR controls as a substitute for
those required by BART. The EPA regional haze regulations may
affect other (non-BART) sources to the extent determined
necessary to make reasonable progress towards the national
visibility improvement goal. Also, five western states
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have elected an option offered by the EPA of regulating
visibility-impairing emissions through a regional rather than a
source-by-source approach. However, this option was litigated
and the states’ rules were invalidated. On October 13,
2006, EPA promulgated new regulations that may allow these
western states and possibly others to adopt a regional approach.
The EPA’s regional haze regulations could cause our
customers to install equipment to control sulfur dioxide and
nitrogen oxide emissions. The requirement to install control
equipment could affect the amount of coal supplied to those
customers if they decide to switch to other sources of fuel to
lower emission of sulfur dioxide and nitrogen oxide.
In 2005, the EPA adopted the Clean Air Mercury Rule
(“CAMR”) to permanently cap and reduce nationwide
mercury emissions from coal-fired power plants. When fully
implemented, and after the appeals have been resolved, the rule
will reduce mercury emissions by nearly 70%. CAMR establishes
standards of performance limiting mercury emissions from new and
existing power plants and creates a cap-and-trade program, which
will reduce emissions in two phases. When fully implemented, the
cap on mercury emissions will be 15 tons per year. Some states
have adopted rules that are more stringent than the federal
program and other states are considering such rules.
Implementation of the federal program or the more stringent
state programs could cause our customers to switch to other
fuels to the extent it would be economically preferable for them
to do so, and could impact the completion or success of our
generation development projects. CAMR is currently under review
in court on a number of grounds, including the assertion by a
number of states and environmental groups that the regulation is
insufficiently stringent.
Legislation that would reduce emissions of sulfur dioxide,
nitrogen oxide and mercury and other greenhouse gases in phases
has been introduced in Congress. No such legislation has passed
either house of Congress. If this type of legislation were
enacted into law, it could impact the amount of coal supplied to
electricity generating customers if they decide to switch to
other sources of fuel whose use would result in lower emission
of sulfur dioxide, nitrogen oxide, mercury and carbon dioxide.
A small number of states have either proposed or adopted
legislation or regulations limiting emissions of sulfur dioxide,
nitrogen oxide and mercury from electric generating stations. A
smaller number of states have also proposed to limit emissions
of carbon dioxide from electric generating stations, with
California recently having adopted legislation and regulations
requiring that all fossil-fueled generation in the state or sold
into the state meet a greenhouse gas performance standard that
coal-based generation cannot meet without capturing and
sequestering a significant amount of carbon dioxide emissions.
Limitations imposed by states on emissions of any of these four
substances from electric generating stations could result in
fuel switching by the generators if they determined it to be
economically preferable to do so.
The U.S. Supreme Court in November 2006 heard oral
arguments in a case seeking to establish that EPA has authority
to regulate carbon dioxide emissions as a “pollutant”
under the Clean Air Act. A decision is expected early this year.
It is too soon to speculate on whether a decision in that case
could cause EPA to issue carbon dioxide regulations and, if so,
the character of those regulations.
| Clean Water Act |
The Clean Water Act of 1972 affects U.S. coal mining
operations by requiring effluent limitations and treatment
standards for waste water discharge through the National
Pollutant Discharge Elimination System (“NPDES”).
Regular monitoring, reporting requirements and performance
standards are requirements of NPDES permits that govern the
discharge of pollutants into water.
States are empowered to develop and enforce “in
stream” water quality standards. These standards are
subject to change and must be approved by the EPA. Discharges
must either meet state water quality standards or be authorized
through available regulatory processes such as alternate
standards or variances. “In stream” standards vary
from state to state. Additionally, through the Clean Water Act
section 401 certification program, states have approval
authority over federal permits or licenses that might result in
a discharge to their waters. States consider whether the
activity will comply with its water quality standards and other
applicable requirements in deciding whether or not to certify
the activity.
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Section 404 under the Clean Water Act requires mining
companies to obtain U.S. Army Corps of Engineers permits to
place material in streams for the purpose of creating slurry
ponds, water impoundments, refuse areas, valley fills or other
mining activities. These permits have been the subject of
multiple recent court cases, the results of which may affect
permitting costs or result in permitting delays.
Total Maximum Daily Load (“TMDL”) regulations
established a process by which states designate stream segments
as impaired (not meeting present water quality standards).
Industrial dischargers, including coal mines, may be required to
meet new TMDL effluent standards for these stream segments.
States are also adopting anti-degradation regulations in which a
state designates certain water bodies or streams as “high
quality/exceptional use.” These regulations would restrict
the diminution of water quality in these streams. Waters
discharged from coal mines to high quality/exceptional use
streams may be required to meet additional conditions or provide
additional demonstrations and/or justification. In general,
these Clean Water Act requirements could result in higher water
treatment and permitting costs or permit delays, which could
adversely affect our coal production costs or efforts.
| Resource Conservation and Recovery Act |
RCRA, which was enacted in 1976, affects U.S. coal mining
operations by establishing “cradle to grave”
requirements for the treatment, storage and disposal of
hazardous wastes. Typically, the only hazardous materials found
on a mine site are those contained in products used in vehicles
and for machinery maintenance. Coal mine wastes, such as
overburden and coal cleaning wastes, are not considered
hazardous waste materials under RCRA.
Subtitle C of RCRA exempted fossil fuel combustion wastes from
hazardous waste regulation until the EPA completed a report to
Congress and made a determination on whether the wastes should
be regulated as hazardous. In a 1993 regulatory determination,
the EPA addressed some high volume-low toxicity coal combustion
materials generated at electric utility and independent power
producing facilities. In May 2000, the EPA concluded that coal
combustion materials do not warrant regulation as hazardous
under RCRA. The EPA is retaining the hazardous waste exemption
for these materials. The EPA is evaluating national
non-hazardous waste guidelines for coal combustion materials
placed at a mine. National guidelines for mine-fills may affect
the cost of ash placement at mines.
| CERCLA (Superfund) |
CERCLA affects U.S. coal mining and hard rock operations by
creating liability for investigation and remediation in response
to releases of hazardous substances into the environment and for
damages to natural resources. Under Superfund, joint and several
liabilities may be imposed on waste generators, site owners or
operators and others regardless of fault. Under the EPA’s
Toxic Release Inventory process, companies are required annually
to report the use, manufacture or processing of listed toxic
materials that exceed defined thresholds, including chemicals
used in equipment maintenance, reclamation, water treatment and
ash received for mine placement from power generation customers.
| The Energy Policy Act of 2005 |
The Domenici-Barton Energy Policy Act of 2005
(“EPACT”) was signed by President Bush in August 2005.
EPACT contains tax incentives and directed spending totaling an
estimated $14.1 billion intended to stimulate supply-side
energy growth and increased efficiency. In addition to rules
affecting the leasing process of federal coal properties, EPACT
programs and incentives include funding to demonstrate advanced
coal technologies, including coal gasification; grants and a
loan guarantee program to encourage deployment of advanced clean
coal-based power generation technologies, including integrated
gasification combined cycle (“IGCC”); a federal loan
guarantee program for the cost of advanced fossil energy
projects, including coal gasification; funding for energy
research, development, demonstration and commercial application
programs relating to coal and power systems; and tax incentives
for IGCC, industrial gasification and other advanced coal-based
generation projects, as well as for coal sold from Indian lands.
Finally, certain sections of EPACT are potentially applicable to
the area of Btu Conversion,
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such as the aforementioned fossil energy project loan guarantee
program as well as a provision allowing taxpayers to capitalize
50% of the cost of refinery investments which increase the total
throughput of qualified fuels — including synthetic
fuels produced from coal — by at least 25%. In
addition, EPACT requires the Secretary of Defense to develop a
strategy to use fuel produced from coal, oil shale and tar sands
(“covered fuel”) to assist in meeting the fuel
requirements of the U.S. Department of Defense
(“DOD”). The law authorizes the DOD to enter into
multi-year contracts to procure a covered fuel to meet one or
more of its fuel requirements and to carry out an assessment of
potential locations for covered fuel sources.
Regulatory Matters — Australia
The Australian mining industry is regulated by Australian
federal, state and local governments with respect to
environmental issues such as land reclamation, water quality,
air quality, dust control, noise, planning issues (such as
approvals to expand existing mines or to develop new mines), and
health and safety issues. The Australian federal government
retains control over the level of foreign investment and export
approvals. Industrial relations are regulated under both federal
and state laws. Australian state governments also require coal
companies to post deposits or give other security against land
which is being used for mining, with those deposits being
returned or security released after satisfactory reclamation is
completed.
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. Surface rights are typically acquired directly
from landowners and, in the absence of agreement, there is an
arbitration provision in the mining law.
| COAL21 Fund |
Our subsidiary, Peabody Pacific, has committed to pay up to a
maximum of A$0.20/tonne (approximately US$0.15/tonne) of coal
sales for a period of five years to the Australian COAL21 Fund.
The COAL21 Fund is a voluntary coal industry fund to support
clean coal technology demonstration projects and research in
Australia. All major coal companies in Australia have committed
to this fund. The commitment to pay starts on April 1, 2007
with a levy of A$0.10/tonne of coal sales. This levy is expected
to rise to A$0.20/tonne on July 1, 2007.
| Native Title and Cultural Heritage |
Since 1992, the Australian courts have recognized that native
title to lands, as recognized under the laws and customs of the
Aboriginal inhabitants of Australia, may have survived the
process of European settlement. These developments are supported
by the Federal Native Title Act (“NTA”) which
recognizes and protects native title, and under which a national
register of native title claims has been established.
Native title rights do not extend to minerals; however, native
title rights can be affected by the mining process unless those
rights have previously been extinguished. Native title rights
can be extinguished either by a valid act of Government (as set
out in the NTA) or by the loss of connection between the land
and the group of Aboriginal peoples concerned.
The NTA provides that where native title rights still exist and
the mining project will affect those native title rights, it
will be necessary to consult with the relevant Aboriginal group
and to come to an agreement on issues such as the preservation
of sacred or important sites, the employment of members of the
group by the mine operator, and the payment of compensation for
the effect on native title of the mining project. In the absence
of agreement with the relevant Aboriginal group, there is an
arbitration provision in the NTA.
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There is also federal and state legislation to prevent damage to
Aboriginal cultural heritage and archeological sites. The NTA
and laws protecting Aboriginal cultural heritage and
archeological sites have had no impact on our current operations.
| Environmental |
The federal system requires that approval is obtained for any
activity which will have a significant impact on a matter of
national environmental significance. Matters of national
environmental significance include listed endangered species,
nuclear actions, World Heritage areas, National Heritage areas,
and migratory species. An application for such an approval may
require public consultation and may be approved, refused or
granted subject to conditions. Otherwise, responsibility for
environmental regulation in Australia is primarily vested in the
states.
Each state and territory in Australia has its own environmental
and planning regime for the development of mines. In addition,
each state and territory also has a specific act dealing with
mining in particular, regulating the granting of mining licenses
and leases. The mining legislation in each state and territory
operates concurrently with environmental and planning
legislation. The mining legislation governs mining licenses and
leases, including the restoration of land following the
completion of mining activities. Apart from the grant of rights
to mine (which are covered by the mining statutes), all
licensing, permitting, consent and approval requirements are
contained in the various state and territory environmental and
planning statutes.
The particular provisions of the various state and territory
environmental and planning statutes vary depending upon the
jurisdiction. Despite variation in details, each state and
territory has a system involving at least two major phases.
First, obtaining the developmental application and, if that is
granted, obtaining the detailed operational pollution control
licenses, which authorize emissions up to a maximum level; and
second, obtaining pollution control approvals, which authorize
the installation of pollution control equipment and devices. In
the first regulatory phase, an application to a regulatory
authority is filed. The relevant authority will either grant a
conditional consent, an unconditional consent, or deny the
application based on the details of the application and on any
submissions or objections lodged by members of the public. If
the developmental application is granted, the detailed pollution
control license may then be issued and such license may regulate
emissions to the atmosphere; emissions in waters; noise impacts,
including impacts from blasting; dust impacts; the generation,
handling, storage and transportation of waste; and requirements
for the rehabilitation and restoration of land.
Each state and territory in Australia also has either a specific
statute or certain sections in other environmental and planning
statutes relating to the contamination of land and vesting
powers in the various regulatory authorities in respect of the
remediation of contaminated land. Those statutes are based on
varying policies — the primary difference between the
statutes is that in certain states and territories, liability
for remediation is placed upon the occupier of the land,
regardless of the culpability of that occupier for the
contamination. In other states and territories, primary
liability for remediation is placed on the original polluter,
whether or not the polluter still occupies the land. If the
original polluter cannot itself carry out the remediation, then
a number of the statutes contain provisions which enable
recovery of the costs of remediation from the polluter as a debt.
Many of the environmental planning statutes across the states
and territories contain “third-party” appeal rights in
relation, particularly, to the first regulatory phase. This
means that any party has a right to take proceedings for a
threatened or actual breach of the statute, without first having
to establish that any particular interest of that person (other
than as a member of the public) stands to be affected by the
threatened or actual breach.
Accordingly, in most states and territories throughout
Australia, mining activities involve a number of regulatory
phases. Following exploratory investigations pursuant to a
mining lease, the activity proposed to be carried out must be
the subject of an application for the activity or development.
This phase of the regulatory process, as noted above, usually
involves the preparation of extensive documents to constitute
the application, addressing all of the environmental impacts of
the proposed activity. It also generally
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involves extensive notification and consultation with other
relevant statutory authorities and members of the public. Once a
decision is made to allow a mine to be developed by the grant of
a development consent, permit or other approval, then a formal
mining lease can be obtained under the mining statute. In
addition, operational licenses and approvals can then be applied
for and obtained in relation to pollution control devices and
emissions to the atmosphere, to waters and for noise. The
obtaining of licenses and approvals, during the operational
phase, generally does not involve any extensive notification or
consultation with members of the public, as most of these issues
are anticipated to be resolved in the first regulatory phase.
| Occupational Health And Safety |
The combined effect of various state and federal statutes
requires an employer to ensure that persons employed in a mine
are safe from injury by providing a safe working environment and
systems of work; safety machinery; equipment, plant and
substances; and appropriate information, instruction, training
and supervision.
In recognition of the specialized nature of mining and mining
activities, specific occupational health and safety obligations
have been mandated under state legislation that deals
specifically with the coal mining industry. Mining employers,
owners, directors and managers, persons in control of work
places, mine managers, supervisors and employees are all subject
to these duties.
It is mandatory for an employer to have insurance coverage with
respect to the compensation of injured workers; similar coverage
is in effect throughout Australia which is of a no fault nature
and which provide for benefits up to a prescribed level. The
specific benefits vary from jurisdiction to jurisdiction, but
generally include the payment of weekly compensation to an
incapacitated employee, together with payment of medical,
hospital and related expenses. The injured employee has a right
to sue his or her employer for further damages if a case of
negligence can be established.
Global Climate Change
Legislation was introduced in Congress in 2006 to reduce
greenhouse gas emissions in the United States. Such or similar
federal legislative action could be taken in 2007 or later
years. In addition, a number of states in the United States have
taken steps to regulate greenhouse gas emissions. For example,
seven northeastern states (New York, Vermont, New Hampshire,
Maine, Connecticut, Delaware and New Jersey) entered into the
Regional Greenhouse Gas Initiative (RGGI) agreement in
December 2005 to reduce carbon dioxide emissions from power
plants, and in August 2006 finalized a model rule to help
implement the agreement; Maryland has approved legislation that
may result in inclusion in the RGGI in 2007; in August 2006, the
California legislature approved legislation allowing the
imposition of statewide caps on, and cuts in, carbon dioxide
emissions; and Arizona’s governor signed an executive order
in September 2006 that calls for the state to reduce carbon
dioxide emissions. Greenhouse gas intensity measures the ratio
of greenhouse gas emissions, such as carbon dioxide, to economic
output. Passage of regulations regarding greenhouse gas
emissions by the United States or other actions to limit carbon
dioxide emissions could result in fuel switching, from coal to
other fuel sources, by electric generators.
In December 1997, in Kyoto, Japan, the signatories to the 1992
Framework Convention on Climate Change, which addresses
emissions of greenhouse gases, established a binding set of
emission targets for developed nations. The Australian Federal
Government has not signed the Kyoto Protocol but has indicated
interest in meeting the emissions reduction requirements of the
protocol. No legislation currently exists that restricts or
requires reduction in greenhouse emissions within Australia. The
Australian Federal Government has created significant incentives
for companies that are large energy users. The New South Wales
State Government requires certain businesses to prepare an
Energy Reduction Plan and is considering introducing mandatory
emissions reporting for all coal mines. None of these programs
mandate any greenhouse gas emission or energy usage reduction,
but seek disclosure of current emissions and voluntary reduction.
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Additional Information
We file annual, quarterly and current reports, and our
amendments to those reports, proxy statements and other
information with the Securities and Exchange Commission
(“SEC”). You may access and read our SEC filings free
of charge through our website, at www.peabodyenergy.com, or the
SEC’s website, at www.sec.gov. 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.
| If a substantial portion of our long-term coal supply agreements terminate, our revenues and operating profits could suffer if we were unable to find alternate buyers willing to purchase our coal on comparable terms to those in our contracts. |
Most of our sales are made under coal supply agreements, which
are important to the stability and profitability of our
operations. The execution of a satisfactory coal supply
agreement is frequently the basis on which we undertake the
development of coal reserves required to be supplied under the
contract. For the year ended December 31, 2006, 90% of our
sales volume was sold under long-term coal supply agreements. At
December 31, 2006, our coal supply agreements had remaining
terms ranging from one to 19 years and an average
volume-weighted remaining term of approximately 5 years.
Many of our coal supply agreements contain provisions that
permit the parties to adjust the contract price upward or
downward at specified times. We may adjust these contract prices
based on inflation or deflation and/or changes in the factors
affecting the cost of producing coal, such as taxes, fees,
royalties and changes in the laws regulating the mining,
production, sale or use of coal. In a limited number of
contracts, failure of the parties to agree on a price under
those provisions may allow either party to terminate the
contract. We sometimes experience a reduction in coal prices in
new long-term coal supply agreements replacing some of our
expiring contracts. Coal supply agreements also typically
contain force majeure provisions allowing temporary suspension
of performance by us or the customer during the duration of
specified events beyond the control of the affected party. Most
coal supply agreements contain provisions requiring us to
deliver coal meeting quality thresholds for certain
characteristics such as Btu, sulfur content, ash content,
grindability and ash fusion temperature. Failure to meet these
specifications could result in economic penalties, including
price adjustments, the rejection of deliveries or termination of
the contracts. Moreover, some of these agreements permit the
customer to terminate the contract if transportation costs,
which our customers typically bear, increase substantially. In
addition, some of these contracts allow our customers to
terminate their contracts in the event of changes in regulations
affecting our industry that increase the price of coal beyond
specified limits.
The operating profits we realize from coal sold under supply
agreements depend on a variety of factors. In addition, price
adjustment and other provisions may increase our exposure to
short-term coal price volatility provided by those contracts. If
a substantial portion of our coal supply agreements were
modified or terminated, we could be materially adversely
affected to the extent that we are unable to find alternate
buyers for our coal at the same level of profitability. Market
prices for coal vary by mining region and country. As a result,
we cannot predict the future strength of the coal market overall
or by mining region and cannot assure you that we will be able
to replace existing long-term coal supply agreements at the same
prices or with similar profit margins when they expire. In
addition, one of our largest coal supply agreements is the
subject of ongoing litigation and arbitration.
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| The loss of, or significant reduction in, purchases by our largest customers could adversely affect our revenues. |
For the year ended December 31, 2006, we derived 22% of our
total coal revenues from sales to our five largest customers. At
December 31, 2006, we had 123 coal supply agreements with
these customers expiring at various times from 2007 to 2016. We
are currently discussing the extension of existing agreements or
entering into new long-term agreements with some of these
customers, but these negotiations may not be successful and
those customers may not continue to purchase coal from us under
long-term coal supply agreements. If a number of these customers
significantly reduce their purchases of coal from us, or if we
are unable to sell coal to them on terms as favorable to us as
the terms under our current agreements, our financial condition
and results of operations could suffer materially.
| 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, 2006, certain coal supply agreements, which
account for less than 5% of our tons sold, permit the customer
to terminate the contract if the cost of transportation
increases by an amount over specified levels in any given
12-month period.
Coal producers depend upon rail, barge, trucking, overland
conveyor and ocean-going vessels to deliver coal to markets.
While our coal customers typically arrange and pay for
transportation of coal from the mine or port to the point of
use, disruption of these transportation services because of
weather-related problems, infrastructure damage, strikes,
lock-outs, lack of fuel or maintenance items, transportation
delays or other events could temporarily impair our ability to
supply coal to our customers and thus could adversely affect our
results of operations. For example, two primary railroads serve
the Powder River Basin mines. Due to the high volume of coal
shipped from all Powder River Basin mines, the loss of access to
rail capacity could create temporary congestion on the rail
systems servicing that region. We are also susceptible to port
congestion and demurrage fees. In Australia, we export our
Queensland production from Dalrymple Bay Coal Terminal and the
Ports of Gladstone and Brisbane. We export our New South Wales
production from the Ports of Newcastle and Kembla.
| 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.
| 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. In addition,
significant legislation mandating specified benefits for retired
coal miners affects our industry. Numerous governmental permits
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and approvals are required for mining operations. We are
required to prepare and present to federal, state or local
authorities data pertaining to the effect or impact that any
proposed exploration for or production of coal may have upon the
environment. The costs, liabilities and requirements associated
with these regulations may be costly and time-consuming and may
delay commencement or continuation of exploration or production.
The possibility exists that new legislation and/or regulations
and orders related to the environment or employee health and
safety may be adopted and may materially adversely affect our
mining operations, our cost structure and/or our customers’
ability to use coal. New legislation or administrative
regulations (or judicial interpretations of existing laws and
regulations), including proposals related to the protection of
the environment that would further regulate and tax the coal
industry, may also require us or our customers to change
operations significantly or incur increased costs. The majority
of our coal supply agreements contain provisions that allow a
purchaser to terminate its contract if legislation is passed
that either restricts the use or type of coal permissible at the
purchaser’s plant or results in specified increases in the
cost of coal or its use. These factors and legislation, if
enacted, could have a material adverse effect on our financial
condition and results of operations.
According to the Department of Energy’s Energy Information
Administration, “Emissions of Greenhouse Gases in the
United States 2003,” coal accounts for 31% of greenhouse
gas emissions in the United States, and efforts to control
greenhouse gas emissions could result in reduced use of coal if
electricity generators switch to lower carbon sources of fuel.
Legislation was introduced in Congress in 2006 to reduce
greenhouse gas emissions in the United States. Such or similar
federal legislative action could be taken in 2007 or later years
(see additional discussion in Item 1 under the heading
“Global Climate Change”). Further developments in
connection with legislation, regulations or other limits on
greenhouse emissions, both in the United States and in other
countries where we sell coal, could have a material adverse
effect on our financial condition or results of operations.
A number of laws, including in the U.S. the Comprehensive
Environmental Response, Compensation and Liability Act
(“CERCLA” or “Superfund”), impose liability
relating to contamination by hazardous substances. Such
liability may involve the costs of investigating or remediating
contamination and damages to natural resources, as well as
claims seeking to recover for property damage or personal injury
caused by hazardous substances. Such liability may arise from
conditions at formerly as well as currently owned or operated
properties, and at properties to which hazardous substances have
been sent for treatment, disposal, or other handling. Liability
under CERCLA and similar state statutes is without regard to
fault, and typically is joint and several, meaning that a person
may be held responsible for more than its share, or even all of,
the liability involved. Our mining operations involve some use
of hazardous materials. In addition, we have accrued for
liability arising out of contamination associated with Gold
Fields Mining, LLC (“Gold Fields”), a dormant,
non-coal-producing subsidiary of ours that was previously
managed and owned by Hanson PLC, or with Gold Fields’
former affiliates. A predecessor owner of ours, Hanson PLC
transferred ownership of Gold Fields to us in the February 1997
spin-off of its energy business. Gold Fields is currently a
defendant in several lawsuits and has received notices of
several other potential claims arising out of lead contamination
from mining and milling operations it conducted in northeastern
Oklahoma. Gold Fields is also involved in investigating or
remediating a number of other contaminated sites. Although we
have accrued for many of these liabilities known to us, the
amounts of other potential losses cannot be estimated.
Significant uncertainty exists as to whether claims will be
pursued against Gold Fields in all cases, and where they are
pursued, the amount of the eventual costs and liabilities, which
could be greater or less than our accrual. Although we believe
many of these liabilities are likely to be resolved without a
material adverse effect on us, future developments, such as new
information concerning areas known to be or suspected of being
contaminated for which we may be responsible, the discovery of
new contamination for which we may be responsible, or the
inability to share costs with other parties that may be
responsible for the contamination, could have a material adverse
effect on our financial condition or results of operations.
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| Our expenditures for postretirement benefit and pension obligations could be materially higher than we have predicted if our underlying assumptions prove to be incorrect. |
We provide postretirement health and life insurance benefits to
eligible union and non-union employees. We calculated the total
accumulated postretirement benefit obligation under
SFAS No. 106, “Employers’ Accounting for
Postretirement Benefits Other Than Pensions,” which we
estimate had a present value of $1.45 billion as of
December 31, 2006, $82.6 million of which was a
current liability. We have estimated these unfunded obligations
based on assumptions described in the notes to our consolidated
financial statements. If our assumptions do not materialize as
expected, cash expenditures and costs that we incur could be
materially higher. Moreover, regulatory changes could increase
our obligations to provide these or additional benefits.
We are party to an agreement with the Pension Benefit Guaranty
Corporation (the “PBGC”) and TXU Europe Limited, an
affiliate of our former parent corporation, under which we are
required to make specified contributions to two of our defined
benefit pension plans and to maintain a $37.0 million
letter of credit in favor of the PBGC. If we or the PBGC give
notice of an intent to terminate one or more of the covered
pension plans in which liabilities are not fully funded, or if
we fail to maintain the letter of credit, the PBGC may draw down
on the letter of credit and use the proceeds to satisfy
liabilities under the Employment Retirement Income Security Act
of 1974, as amended. The PBGC, however, is required to first
apply amounts received from a $110.0 million guaranty in
place from TXU Europe Limited in favor of the PBGC before it
draws on our letter of credit. On November 19, 2002, TXU
Europe Limited was placed under the administration process in
the United Kingdom (a process similar to bankruptcy proceedings
in the United States) and continues under this process as of
December 31, 2006.
In addition, certain of our subsidiaries participate in two
defined benefit multi-employer pension funds that were
established as a result of collective bargaining with the UMWA
pursuant to the National Bituminous Coal Wage Agreement as
periodically negotiated. The UMWA 1950 Pension Plan provides
pension and disability pension benefits to qualifying
represented employees retiring from a participating employer
where the employee last worked prior to January 1, 1976.
This is a closed group of beneficiaries with no new entrants.
The UMWA 1974 Pension Plan provides pension and disability
pension benefits to qualifying represented employees retiring
from a participating employer where the employee last worked
after December 31, 1975. In December 2006, the 2007
National Bituminous Coal Wage Agreement was signed, which
required funding of the 1974 Pension Plan through 2011 under a
phased funding schedule. The funding is based on an hourly rate
for certain UMWA workers. Under the labor contract, the per hour
funding rate increased from zero to $2.00 in 2007 and increased
each year thereafter until reaching $5.50 in 2011. Although our
subsidiaries are not a party to that labor agreement, they are
required to contribute to the 1974 Pension Plan at the new
hourly rates. During 2006, represented employees subject to the
new rate worked a total of approximately four million hours.
Contributions to these funds could increase as a result of
future collective bargaining with the UMWA, a shrinking
contribution base as a result of the insolvency of other coal
companies who currently contribute to these funds, lower than
expected returns on pension fund assets, higher medical and drug
costs or other funding deficiencies.
The United Mine Workers of America Combined Fund was created by
federal law in 1992. This multi-employer fund provides health
care benefits to a closed group of retirees including our
retired former employees who last worked prior to 1976, as well
as orphaned beneficiaries of bankrupt companies who were
receiving benefits as orphans prior to the 1992 law. No new
retirees will be added to this group. The liability is subject
to increases or decreases in per capita health care costs,
offset by the mortality curve in this aging population of
beneficiaries. Another fund, the 1992 Benefit Plan created by
the same federal law in 1992, provides benefits to qualifying
retired former employees of bankrupt companies who have
defaulted in providing their former employees with retiree
medical benefits. Beneficiaries continue to be added to this
fund as employers default in providing their former employees
with retiree medical benefits, but the overall exposure for new
beneficiaries into this fund is limited to retirees covered
under their employer’s plan who retired prior to
October 1, 1994. A third fund, the 1993 Benefit Plan, was
established
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through collective bargaining and provides benefits to
qualifying retired former employees who retired after
September 30, 1994 of certain signatory companies who have
gone out of business and have defaulted in providing their
former employees with retiree medical benefits. Beneficiaries
continue to be added to this fund as employers go out of
business.
The Surface Mining Control and Reclamation Act Amendments of
2006 (the “2006 Act”), which was enacted in December
2006, amended the federal laws establishing the Combined Fund,
1992 Benefit Plan and the 1993 Benefit Plan. Among other things,
the 2006 Act guarantees full funding of all beneficiaries in the
Combined Fund, provides funds on a phased-in basis for the 1992
Benefit Plan, and authorizes the trustees of the 1993 Benefit
Plan to determine the contribution rates through 2010 for
pre-2007 beneficiaries. The new and additional federal
expenditures to the Combined Fund, 1992 Benefit Plan, 1993
Benefit Plan and certain Abandoned Mine Land payments to the
states and Indian tribes are collectively limited by an
aggregate annual cap of $490 million. To the extent that
(i) the annual funding of the programs exceeds this amount
(plus the amount of interest from the AML trust fund paid with
respect to the Combined Benefit Fund), and (ii) Congress
does not allocate additional funds to cover the shortfall,
contributing employers and affiliates, including some of our
subsidiaries, would be responsible for the additional costs.
Based upon the enactment of the Medicare Prescription Drug,
Improvement and Modernization Act of 2003, we estimated future
cash savings which allowed us to reduce our projected
postretirement benefit obligations and related expense. Failure
to achieve these assumed future savings under all benefit plans
could adversely affect our financial condition, results of
operations and cash flows.
| A decrease in the availability or increase in costs of key supplies, capital equipment or commodities such as diesel fuel, steel, explosives and tires could decrease our anticipated profitability. |
Our mining operations require a reliable supply of replacement
parts, explosives, fuel, tires, steel-related products
(including roof control) and lubricants. If the cost of any of
these inputs increased significantly, or if a source for these
supplies or mining equipment were unavailable to meet our
replacement demands, our profitability could be reduced from our
current expectations. Recent consolidation of suppliers of
explosives has limited the number of sources for these
materials, and our current supply of explosives is concentrated
with one supplier. Further, our purchases of some items of
underground mining equipment are concentrated with one principal
supplier. Over the past few years, industry-wide demand growth
has exceeded supply growth for certain surface and underground
mining equipment and other capital equipment as well as
off-the-road tires. As
a result, lead times for some items have increased significantly.
| Our future success depends upon our ability to continue acquiring and developing coal reserves that are economically recoverable. |
Our recoverable reserves decline as we produce coal. We have not
yet applied for the permits required or developed the mines
necessary to use all of our reserves. Furthermore, we may not be
able to mine all of our reserves as profitably as we do at our
current operations. Our future success depends upon our
conducting successful exploration and development activities or
acquiring properties containing economically recoverable
reserves. Our current strategy includes increasing our reserves
through acquisitions of government and other leases and
producing properties and continuing to use our existing
properties. The federal government also leases natural gas and
coalbed methane reserves in the West, including in the Powder
River Basin. Some of these natural gas and coalbed methane
reserves are located on, or adjacent to, some of our Powder
River Basin reserves, potentially creating conflicting interests
between us and lessees of those interests. Other lessees’
rights relating to these mineral interests could prevent, delay
or increase the cost of developing our coal reserves. These
lessees may also seek damages from us based on claims that our
coal mining operations impair their interests. Additionally, the
federal government limits the amount of federal land that may be
leased by any company to 150,000 acres nationwide. As of
December 31, 2006, we leased a total of 63,463 acres
from the federal government. The limit could restrict
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our ability to lease additional federal lands. For additional
discussion of our federal leases see Item 2. Properties.
Our planned mine development projects and acquisition activities
may not result in significant additional reserves, and we may
not have continuing success developing additional mines. Most of
our mining operations are conducted on properties owned or
leased by us. Because title to most of our leased properties and
mineral rights are not thoroughly verified until a permit to
mine the property is obtained, our right to mine some of our
reserves may be materially adversely affected if defects in
title or boundaries exist. In addition, in order to develop our
reserves, we must receive various governmental permits. We
cannot predict whether we will continue to receive the permits
necessary for us to operate profitably in the future. We may not
be able to negotiate new leases from the government or from
private parties, obtain mining contracts for properties
containing additional reserves or maintain our leasehold
interest in properties on which mining operations are not
commenced during the term of the lease. From time to time, we
have experienced litigation with lessors of our coal properties
and with royalty holders.
| A decrease in the price or our production of metallurgical coal could decrease our anticipated profitability. |
We have annual capacity to produce approximately 15 to
18 million tons of metallurgical coal. Prices for
metallurgical coal at the end of 2005 and during 2006 were near
historically high levels. As a result, our margins from these
sales have increased significantly, and represented a larger
percentage of our overall revenues and profits and are expected
to continue to favorably contribute in the future. To the extent
we experience either production or transportation difficulties
that impair our ability to ship metallurgical coal to our
customers at anticipated levels, our profitability will be
reduced in 2007.
The majority of our 2007 metallurgical coal production will be
priced during the first quarter of 2007; however, early
indications are that prices will be down from historical highs.
As a result, a decrease in metallurgical coal prices could
decrease our profitability.
| Our financial performance could be adversely affected by our debt. |
Our financial performance could be affected by our indebtedness.
As of December 31, 2006, our total indebtedness was
$3.26 billion, and we had $1.29 billion of available
borrowing capacity under our revolving credit facility. The
indentures governing the convertible debentures and senior notes
do not limit the amount of indebtedness that we may issue, and
the indentures governing our other senior notes permit the
incurrence of additional indebtedness.
The degree to which we are leveraged could have important
consequences, including, but not limited to:
| • | making it more difficult for us to pay interest and satisfy our debt obligations; | |
| • | increasing our vulnerability to general adverse economic and industry conditions; | |
| • | requiring the dedication of a substantial portion of our cash flow from operations to the payment of principal of, and interest on, our indebtedness, thereby reducing the availability of the cash flow to fund working capital, capital expenditures, research and development or other general corporate uses; | |
| • | limiting our ability to obtain additional financing to fund future working capital, capital expenditures, research and development or other general corporate requirements; | |
| • | limiting our flexibility in planning for, or reacting to, changes in our business and in the coal industry; and | |
| • | placing us at a competitive disadvantage compared to less leveraged competitors. |
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In addition, our indebtedness subjects us to financial and other
restrictive covenants. Failure by us to comply with these
covenants could result in an event of default that, if not cured
or waived, could have a material adverse effect on us.
If our cash flows and capital resources are insufficient to fund
our debt service obligations, we may be forced to sell assets,
seek additional capital or seek to restructure or refinance our
indebtedness. These alternative measures may not be successful
and may not permit us to meet our scheduled debt service
obligations. In the absence of such operating results and
resources, we could face substantial liquidity problems and
might be required to sell material assets or operations to
attempt to meet our debt service and other obligations. The
senior unsecured credit facility and indentures governing
certain of our notes restrict our ability to sell assets and use
the proceeds from the sales. We may not be able to consummate
those sales or to obtain the proceeds which we could realize
from them and these proceeds may not be adequate to meet any
debt service obligations then due.
| The covenants in our senior unsecured credit facility and the indentures governing our senior notes and convertible debentures impose restrictions that may limit our operating and financial flexibility. |
Our senior unsecured credit facility, the indentures governing
our senior notes and convertible debentures and the instruments
governing our other indebtedness contain certain restrictions
and covenants which restrict our ability to incur liens and debt
or provide guarantees in respect of obligations of any other
person. Under our senior unsecured credit facility, we must
comply with certain financial covenants on a quarterly basis
including a minimum interest coverage ratio and a maximum
leverage ratio, as defined. The financial covenants also place
limitations on our investments in joint ventures, unrestricted
subsidiaries, indebtedness of non-loan parties and the
imposition of liens on our assets. These covenants and
restrictions are reasonable and customary and have not impacted
our business in the past.
Operating results below current levels or other adverse factors,
including a significant increase in interest rates, could result
in our inability to comply with the financial covenants
contained in our senior unsecured credit facility. If we violate
these covenants and are unable to obtain waivers from our
lenders, our debt under these agreements would be in default and
could be accelerated by our lenders. If our indebtedness is
accelerated, we may not be able to repay our debt or borrow
sufficient funds to refinance it. Even if we are able to obtain
new financing, it may not be on commercially reasonable terms,
on terms that are acceptable to us or at all. If our debt is in
default for any reason, our business, financial condition and
results of operations could be materially and adversely
affected. In addition, complying with these covenants may also
cause us to take actions that are not favorable to holders of
our other debt or equity securities and may make it more
difficult for us to successfully execute our business strategy
and compete against companies who are not subject to such
restrictions.
| Our operations could be adversely affected if we fail to appropriately secure our obligations. |
U.S. federal and state laws and Australian laws require us to
secure certain of our obligations to reclaim lands used for
mining, to pay federal and state workers’ compensation, to
secure coal lease obligations and to satisfy other miscellaneous
obligations. The primary method for us to meet those obligations
is to post a corporate guarantee (i.e. self bond), provide a
third-party surety bond or provide a letter of credit. As of
December 31, 2006, we had $685.2 million of self bonds
in place primarily for our reclamation obligations. As of
December 31, 2006, we also had outstanding surety bonds
with third parties and letters of credit of $1.09 billion,
of which $445.6 million was for post-mining reclamation,
$188.5 million related to workers’ compensation
obligations, $119.4 was for retiree healthcare obligations,
$104.2 million was for coal lease obligations, and
$236.0 million was for other obligations, including
collateral for surety companies and bank guarantees, road
maintenance, and performance guarantees. Surety bonds are
typically renewable on a yearly basis. Surety bond issuers and
holders may not continue to renew the bonds or may demand
additional collateral upon those renewals. Letters of credit are
subject to our successful renewal of our bank revolving credit
facilities, which are currently set to expire in 2011. Our
failure to maintain, or inability to acquire, surety bonds, or
letters of credit, or to provide a suitable
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alternative would have a material adverse effect on us. That
failure could result from a variety of factors including the
following:
| • | lack of availability, higher expense or unfavorable market terms of new surety bonds; | |
| • | restrictions on the availability of collateral for current and future third-party surety bond issuers under the terms of our indentures or senior unsecured credit facility; | |
| • | the exercise by third-party surety bond issuers of their right to refuse to renew the surety; and | |
| • | inability to renew our credit facility. |
Our ability to self bond reduces our costs of providing
financial assurances. To the extent we are unable to maintain
our current level of self bonding, due to legislative or
regulatory changes or changes in our financial condition, our
costs would increase.
| The conversion of our outstanding convertible debentures may result in the dilution of the ownership interests of our existing stockholders. |
If the conditions permitting the conversion of our convertible
debentures are met and holders of the convertible debentures
exercise their conversion rights, any conversion value in excess
of the principal amount will be delivered in shares of our
common stock. If any common stock is issued in connection with a
conversion of our convertible debentures, our existing
stockholders will experience dilution in the voting power of
their common stock and earnings per share could be negatively
impacted.
| Provisions of our convertible debentures could discourage an acquisition of us by a third-party. |
Certain provisions of our convertible debentures could make it
more difficult or more expensive for a third-party to acquire
us. Upon the occurrence of certain transactions constituting a
“change of control” as defined in the indenture
relating to our convertible debentures, holders of our
convertible debentures will have the right, at their option, to
convert their convertible debentures and thereby require us to
pay the principal amount of such converted debentures in cash.
| An inability of contract miner or brokerage sources to fulfill the delivery terms of their contracts with us could reduce our profitability. |
In conducting our trading, brokerage and mining operations, we
utilize third-party sources of coal production, including
contract miners and brokerage sources, to fulfill deliveries
under our coal supply agreements. In Australia, the majority of
our mines utilize contract miners. Employee relations at mines
that use contract miners is the responsibility of the contractor.
Recently, certain of our brokerage sources and contract miners
in the United States have experienced adverse geologic mining,
escalated operating costs and/or financial difficulties that
have made their delivery of coal to us at the contracted price
difficult or uncertain. In some instances, the contract miners
and third-party suppliers have suspended mining operations, and
it has become increasing difficult to identify and retain
contract workers. Our profitability or exposure to loss on
transactions or relationships such as these is dependent upon
the reliability (including financial viability) and price of the
third-party supply, our obligation to supply coal to customers
in the event that adverse geologic mining conditions restrict
deliveries from our suppliers, our willingness to participate in
temporary cost increases experienced by our third-party coal
suppliers, our ability to pass on temporary cost increases to
our customers, the ability to substitute, when economical,
third-party coal sources with internal production or coal
purchased in the market, and other factors.
| If the coal industry experiences overcapacity in the future, our profitability could be impaired. |
During the mid-1970s and early 1980s, a growing coal market and
increased demand for coal attracted new investors to the coal
industry, spurred the development of new mines and resulted in
production capacity in excess of market demand throughout the
industry. Similarly, increases in future coal
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prices could encourage the development of expanded capacity by
new or existing coal producers. Recently, the coal industry
experienced lower demand as electricity usage was at lower than
historical growth levels. Therefore, as of December 2006, total
coal inventories of 130 to 140 million tons at generators
were above the five-year average.
| We could be negatively affected if we fail to maintain satisfactory labor relations. |
As of December 31, 2006, we had approximately 9,200
employees. As of December 31, 2006, approximately 40% of
our hourly employees were represented by unions and they
generated approximately 14% of our 2006 coal production.
Relations with our employees and, where applicable, organized
labor are important to our success.
Due to the higher labor costs and the increased risk of strikes
and other work-related stoppages that may be associated with
union operations in the coal industry, our competitors who
operate without union labor may have a competitive advantage in
areas where they compete with our unionized operations. If some
or all of our current non-union operations were to become
unionized, we could incur an increased risk of work stoppages,
reduced productivity and higher labor costs.
| United States Labor Relations |
Approximately 66% of our U.S. miners are non-union and are
employed in the states of Wyoming, Colorado, Indiana, New
Mexico, Illinois and Kentucky. The UMWA represented
approximately 26% of our subsidiaries’ hourly employees,
who generated 11% of our U.S. production during the year
ended December 31, 2006. An additional 5% of our hourly
employees are represented by labor unions other than the UMWA.
These employees generated 1% of our production during the year
ended December 31, 2006. Hourly workers at our mine in
Arizona are represented by the UMWA under the Western Surface
Agreement of 2000, which is effective through September 1,
2007. Our union workforce east of the Mississippi River is
primarily represented by the UMWA. The UMWA-represented workers
at one of our eastern mines operate under a contract that
expires on December 31, 2007. The remainder of our
UMWA-represented workers in the east operate under a recently
signed, five-year labor agreement expiring December 31,
2011. This contract replaced a contract that had expired on
December 31, 2006 and mirrors the 2007 National Bituminous
Coal Wage Agreement.
| Australia Labor Relations |
The Australian coal mining industry is unionized and the
majority of workers employed at our Australian Mining Operations
are members of trade unions. The Construction Forestry Mining
and Energy Union represents our hourly production employees. As
of December 31, 2006, our Australian hourly employees were
approximately 9% or our hourly workforce and generated 2% of our
total production in the year then ended. The labor agreement at
our Wilkie Creek Mine was renewed in June 2006 and that
agreement expires in June 2009. The North Goonyella Mine
operates under an agreement due to expire in 2008, and the
Metropolitan Mine operates under an agreement that expires in
June 2007.
| Our ability to operate our company effectively could be impaired if we lose key personnel or fail to attract qualified personnel. |
We manage our business with a number of key personnel, the loss
of a number of whom could have a material adverse effect on us.
In addition, as our business develops and expands, we believe
that our future success will depend greatly on our continued
ability to attract and retain highly skilled and qualified
personnel. We cannot assure you that key personnel will continue
to be employed by us or that we will be able to attract and
retain qualified personnel in the future. We do not have
“key person” life insurance to cover our executive
officers. Failure to retain or attract key personnel could have
a material adverse effect on us.
Due to the current demographics of our mining workforce, a high
portion of our current hourly employees are eligible to retire
over the next decade. Additionally, many of our mine sites are
in more
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secluded areas of the United States, such as the Native American
reservations of Arizona and the Southern Powder River Basin of
Wyoming. These geographic locations provide limited pools of
qualified resources, and it is challenging to locate resources
interested in working in some of these regions. Failure to
attract new employees to the mining workforce could have a
material adverse effect on us.
| Our ability to collect payments from our customers could be impaired if their creditworthiness deteriorates. |
Our ability to receive payment for coal sold and delivered
depends on the continued creditworthiness of our customers. Our
customer base has changed with deregulation as utilities have
sold their power plants to their non-regulated affiliates or
third parties. These new power plant owners or other customers
may have credit ratings that are below investment grade. If
deterioration of the creditworthiness of our customers occurs,
our $225.0 million accounts receivable securitization
program and our business could be adversely affected.
| Our certificate of incorporation and by-laws include provisions that may discourage a takeover attempt. |
Provisions contained in our certificate of incorporation and
by-laws and Delaware law could make it more difficult for a
third-party to acquire us, even if doing so might be beneficial
to our stockholders. Provisions of our by-laws and certificate
of incorporation impose various procedural and other
requirements that could make it more difficult for stockholders
to effect certain corporate actions. For example, a change of
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.
| The extent to which we are able to successfully integrate the newly acquired Excel operations and successfully complete the development of the new mine sites acquired from Excel will have a bearing on our future financial results. |
The process of integrating the operations of the Excel coal
mines could cause an interruption of, or loss of momentum in,
the activities of the business or the development of new mines.
We will need to make significant capital expenditures to utilize
and maintain the assets we acquired in the Excel acquisition.
There are currently three development-stage mines, two of which
are scheduled to begin production in early 2007. Delays in
optimizing the operations of the development-stage mines, and to
a lesser extent the existing Excel operations, could impact our
future financial results. Additionally, our ability to integrate
and manage the Excel operations will have a direct bearing on
the realization of anticipated cost savings and synergies.
Further, we may encounter unanticipated risks associated with
the Excel acquisition.
| Growth in our global operations increases our risks unique to international mining and trading operations. |
We currently have international mining operations in Australia
and Venezuela. We have recently opened a business development,
sales and marketing office in Beijing, China and an
international trading group in our trading and brokerage
operations. 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 domestic or Australian
operations. We are also challenged by political risks, including
expropriation and the inability to repatriate earnings on our
investment. In particular, the Venezuelan government has
suggested its desire to increase government ownership in
Venezuelan energy assets and natural resources. Actions to
nationalize Venezuelan coal properties could be detrimental to
our investments in the Paso Diablo Mine and Cosila development
project. During 2006, the Paso Diablo Mine contributed
$28.0 million to segment Adjusted EBITDA in “Corporate
and Other Adjusted EBITDA”
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(see Item 7) and paid a dividend of $18.2 million. At
December 31, 2006, our investment in Paso Diablo was
$60.1 million, recorded in “Investment and other
assets” on the consolidated balance sheet.
| As we continue to pursue development of Generation Development and Btu Conversion activities, we face challenges and risks that differ from those in our mining business. |
We continue to pursue the development of coal-fueled generating
projects in the U.S., including mine-mouth generating plants
using our surface lands and coal reserves. Our ultimate role in
these projects could take numerous forms, including, but not
limited to, equity partner, contract miner or coal sales. The
projects we are currently pursuing include the 1,600
plus-megawatt Prairie State Energy Campus in Washington County,
Illinois and the 1,500-megawatt Thoroughbred Energy Campus in
Muhlenberg County, Kentucky. We also continue to pursue
opportunities to participate in technologies to economically
convert our coal resources to natural gas and liquids, such as
diesel fuel, gasoline and jet fuel (Btu conversion).
As we move forward with all of these projects, we are exposed to
risks related to the performance of our partners, securing
required financing, obtaining necessary permits, meeting
stringent regulatory laws, maintaining strong supplier
relationships and managing (along with our partners) large
projects, including managing through long lead times for
ordering and obtaining capital equipment. Our work in new or
recently commercialized technologies could expose us to
unanticipated risks, evolving legislation and uncertainty
regarding the extent of future government support and funding.
| The extent of our success in converting our current information systems to our new enterprise resource planning system will directly impact our ability to perform functions critical to our day-to-day business. |
To support the continued growth and globalization of our
businesses, we are converting our existing information systems
across major business processes to an integrated information
technology system provided by SAP AG. The project began in the
first quarter of 2006 and certain phases of implementation are
expected to be completed in 2007. The successful conversion of
our information technology systems will have direct bearing on
our ability to perform certain
day-to-day functions
critical to our business, including billing, processing
invoices, certain Treasury functions, recordkeeping and
financial reporting.
Item 1B. Unresolved
Staff Comments.
None.
| Item 2. | Properties. |
Coal Reserves
We had an estimated 10.2 billion tons of proven and
probable coal reserves as of December 31, 2006. An
estimated 9.4 billion tons of our proven and probable coal
reserves are in the United States and 0.8 billion tons are
in Australia. Forty-three percent of our reserves, or
4.4 billion tons, are compliance coal and 57% are
non-compliance coal. We own approximately 42% of these reserves
and lease property containing the remaining 58%. Compliance coal
is defined by Phase II of the Clean Air Act as coal having
sulfur dioxide content of 1.2 pounds or less per million Btu.
Electricity generators are able to use coal that exceeds these
specifications by using emissions reduction technology, using
emission allowance credits or blending higher sulfur coal with
lower sulfur coal.
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Below is a table summarizing the locations and reserves of our
major operating regions.
| Proven and Probable | |||||||||||||||
| Reserves as of | |||||||||||||||
| December 31, 2006(1) | |||||||||||||||
| Owned | Leased | Total | |||||||||||||
| Operating Regions | Locations | Tons | Tons | Tons | |||||||||||
| (Tons in millions) | |||||||||||||||
|
Midwest
|
Illinois, Indiana and Kentucky | 3,270 | 900 | 4,170 | |||||||||||
|
Powder River Basin
|
Wyoming and Montana | 67 | 3,400 | 3,467 | |||||||||||
|
Southwest
|
Arizona and New Mexico | 617 | 363 | 980 | |||||||||||
|
Appalachia
|
West Virginia and Ohio | 249 | 306 | 555 | |||||||||||
|
Colorado
|
Colorado | 43 | 184 | 227 | |||||||||||
|
Total United States
|
4,246 | 5,153 | 9,399 | ||||||||||||
|
Australia
|
New South Wales | — | 466 | 466 | |||||||||||
|
Australia
|
Queensland | — | 337 | 337 | |||||||||||
|
Total Proven and Probable Coal Reserves
|
4,246 | 5,956 | 10,202 | ||||||||||||
| (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 geologists,
whose experience ranges from 10 to 30 years. We also have a
chief geologist of reserve reporting whose primary
responsibility is to track changes in reserve estimates,
supervise our other geologists and coordinate periodic
third-party reviews of our reserve estimates by qualified mining
consultants.
Our reserve estimates are predicated on information obtained
from our ongoing drilling program, which totals nearly 500,000
individual drill holes. We compile data from individual drill
holes in a computerized drill-hole database from which the
depth, thickness and, where core drilling is used, the
42
Table of Contents
quality of the coal are determined. The density of the drill
pattern determines whether the reserves will be classified as
proven or probable. The reserve estimates are then input into
our computerized land management system, which overlays the
geological data with data on ownership or control of the mineral
and surface interests to determine the extent of our reserves in
a given area. The land management system contains reserve
information, including the quantity and quality (where
available) of reserves as well as production rates, surface
ownership, lease payments and other information relating to our
coal reserves and land holdings. We periodically update our
reserve estimates to reflect production of coal from the
reserves and new drilling or other data received. Accordingly,
reserve estimates will change from time to time to reflect
mining activities, analysis of new engineering and geological
data, changes in reserve holdings, modification of mining
methods and other factors.
Our estimate of the economic recoverability of our reserves is
based upon a comparison of unassigned reserves to assigned
reserves currently in production in the same geologic setting to
determine an estimated mining cost. These estimated mining costs
are compared to existing market prices for the quality of coal
expected to be mined and taking into consideration typical
contractual sales agreements for the region and product. Where
possible, we also review production by competitors in similar
mining areas. Only reserves expected to be mined economically
are included in our reserve estimates. Finally, our reserve
estimates include reductions for recoverability factors to
estimate a saleable product.
We periodically engage independent mining and geological
consultants to review estimates of our coal reserves. The most
recent of these audits, which was completed in January 2007,
included a review of the procedures used by us to prepare our
internal estimates, verification of the accuracy of selected
property reserve estimates and retabulation of reserve groups
according to standard classifications of reliability. This audit
confirmed that we controlled approximately 10.2 billion
tons of proven and probable reserves as of December 31,
2006.
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. On
a regional basis, the expected degree of variance from reserve
estimate to tons produced is lower in the Powder River Basin,
Southwest and Illinois Basin due to the continuity of the coal
seams as confirmed by the mining history. Appalachia, however,
has a higher degree of risk due to the mountainous nature of the
topography which makes exploration drilling more difficult. Our
recovered reserves in Appalachia are less predictable and may
vary by an additional one to two percent above the threshold
discussed above.
We have numerous federal coal leases that are administered by
the U.S. Department of the Interior under the Federal Coal
Leasing Amendments Act of 1976. These leases cover our principal
reserves in Wyoming and other reserves in Montana and Colorado.
Each of these leases continues indefinitely, provided there is
diligent development of the property and continued operation of
the related mine or mines. The Bureau of Land Management has
asserted the right to adjust the terms and conditions of these
leases, including rent and royalties, after the first
20 years of their term and at
10-year intervals
thereafter. Annual rents on surface land under our federal coal
leases are now set at $3.00 per acre. Production royalties
on federal leases are set by statute at 12.5% of the gross
proceeds of coal mined and sold for surface-mined coal and 8%
for underground-mined coal. The federal government limits by
statute the amount of federal land that may be leased by any
company and its affiliates at any time to 75,000 acres in
any one state and 150,000 acres nationwide. As of
December 31, 2006, we leased 11,103 acres of federal
land in Colorado, 11,254 acres in Montana and
41,106 acres in Wyoming, for a total of 63,463 nationwide.
Similar provisions govern three coal leases with the Navajo and
Hopi Indian tribes. These leases cover coal contained in
65,000 acres of land in northern Arizona lying within the
boundaries of the Navajo Nation and Hopi Indian reservations. We
also lease coal-mining properties from various state governments.
Private 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 leases provide for royalties to be
paid to
43
Table of Contents
the lessor either as a fixed amount per ton or as a percentage
of the sales price. Many 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 leases are normally extended by active
production on or near the end of the lease term. Leases
containing undeveloped reserves may expire or these leases may
be renewed periodically. With a portfolio of approximately
10.2 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.
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.
44
Table of Contents
The following chart provides a summary, by mining complex, of
production for the years ended December 31, 2006 and 2005
and 2004, 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)
| Sulfur Content(2) | As of December 31, 2006 | |||||||||||||||||||||||||||||||||||||||||||||||||||
| Production | ||||||||||||||||||||||||||||||||||||||||||||||||||||
| <1.2 lbs. | >1.2 to 2.5 lbs. | >2.5 lbs. | As | Assigned | ||||||||||||||||||||||||||||||||||||||||||||||||
| Year Ended | Year Ended | Year Ended | sulfur dioxide | sulfur dioxide | sulfur dioxide | Received | Proven and | |||||||||||||||||||||||||||||||||||||||||||||
| Geographic Region/Mining | Dec. 31, | Dec. 31, | Dec. 31, | Type of | per | per | per | Btu per | Probable | |||||||||||||||||||||||||||||||||||||||||||
| Complex | 2006 | 2005 | 2004 | Coal | Million Btu | Million Btu | Million Btu | pound(3) | Reserves | Owned | Leased | Surface | Underground | |||||||||||||||||||||||||||||||||||||||
|
Appalachia:
|
||||||||||||||||||||||||||||||||||||||||||||||||||||
|
Federal
|
4.6 | 4.1 | 4.9 | Steam | — | — | 31 | 13,300 | 31 | 11 | 20 | — | 31 | |||||||||||||||||||||||||||||||||||||||
|
Big Mountain
|
2.0 | 1.9 | 1.9 | Steam | 4 | 30 | — | 12,300 | 34 | — | 34 | — | 34 | |||||||||||||||||||||||||||||||||||||||
|
Kanawha
Eagle(4)
|
1.9 | — | — | Steam/Met. | 31 | 22 | — | 13,100 | 53 | — | 53 | — | 53 | |||||||||||||||||||||||||||||||||||||||
|
Harris
|
1.6 | 2.0 | 3.0 | Steam/Met. | 5 | 3 | — | 13,800 | 8 | — | 8 | — | 8 | |||||||||||||||||||||||||||||||||||||||
|
Rocklick
|
2.2 | 2.6 | 2.0 | Steam/Met. | 5 | 7 | 1 | 13,100 | 13 | — | 13 | 3 | 10 | |||||||||||||||||||||||||||||||||||||||
|
Wells
|
2.3 | 2.6 | 2.6 | Steam/Met. | 20 | 29 | — | 12,800 | 49 | — | 49 | — | 49 | |||||||||||||||||||||||||||||||||||||||
|
Total
|
14.6 | 13.2 | 14.4 | 65 | 91 | 32 | 188 | 11 | 177 | 3 | 185 | |||||||||||||||||||||||||||||||||||||||||
|
Midwest:
|
||||||||||||||||||||||||||||||||||||||||||||||||||||
|
Highland
|
3.7 | 3.8 | 3.2 | Steam | — | — | 88 | 11,400 | 88 | 31 | 57 | — | 88 | |||||||||||||||||||||||||||||||||||||||
|
Patriot
|
3.9 | 4.2 | 4.1 | Steam | — | — | 41 | 10,800 | 41 | 4 | 37 | 3 | 38 | |||||||||||||||||||||||||||||||||||||||
|
Air Quality
|
2.2 | 2.1 | 1.8 | Steam | — | 25 | 33 | 10,700 | 58 | 5 | 53 | — | 58 | |||||||||||||||||||||||||||||||||||||||
|
Riola/ Vermilion Grove
|
1.7 | 2.3 | 2.3 | Steam | — | — | 19 | 10,500 | 19 | — | 19 | — | 19 | |||||||||||||||||||||||||||||||||||||||
|
Miller Creek
|
1.6 | 1.0 | 0.9 | Steam | — | 2 | 28 | 10,000 | 30 | 29 | 1 | 30 | — | |||||||||||||||||||||||||||||||||||||||
|
Francisco Surface
|
2.0 | 1.8 | 2.1 | Steam | — | — | 6 | 10,500 | 6 | 2 | 4 | 6 | — | |||||||||||||||||||||||||||||||||||||||
|
Francisco Underground
|
1.1 | 1.2 | 0.9 | Steam | — | — | 22 | 10,600 | 22 | 3 | 18 | — | 22 | |||||||||||||||||||||||||||||||||||||||
|
Farmersburg
|
3.8 | 3.8 | 4.2 | Steam | 1 | 11 | 95 | 10,300 | 107 | 93 | 14 | 107 | — | |||||||||||||||||||||||||||||||||||||||
|
Somerville Central
|
3.5 | 3.4 | 3.2 | Steam | — | — | 4 | 10,300 | 4 | 2 | 2 | 4 | — | |||||||||||||||||||||||||||||||||||||||
|
Somerville — North
|
2.4 | 2.4 | 2.1 | Steam | — | — | 7 | 10,500 | 7 | 6 | 1 | 7 | — | |||||||||||||||||||||||||||||||||||||||
|
Somerville — South
|
2.5 | 2.4 | 2.0 | Steam | — | — | 14 | 10,000 | 14 | 8 | 6 | 14 | — | |||||||||||||||||||||||||||||||||||||||
|
Viking
|
1.5 | 1.5 | 1.5 | Steam | — | 1 | 7 | 10,700 | 8 | — | 8 | 8 | — | |||||||||||||||||||||||||||||||||||||||
|
Wildcat Hills Surface/Underground
|
2.4 | 2.6 | 2.7 | Steam | — | — | 10 | 10,300 | 10 | 5 | 5 | 10 | — | |||||||||||||||||||||||||||||||||||||||
|
Willow Lake
|
3.6 | 3.7 | 3.4 | Steam | — | — | 64 | 11,200 | 64 | 48 | 17 | — | 64 | |||||||||||||||||||||||||||||||||||||||
|
Gateway
|
2.6 | 0.5 | — | Steam | — | — | 20 | 10,300 | 20 | 20 | — | — | 20 | |||||||||||||||||||||||||||||||||||||||
|
Dodge Hill
|
1.1 | 1.2 | 1.2 | Steam | — | — | 8 | 11,100 | 8 | 3 | 5 | — | 8 | |||||||||||||||||||||||||||||||||||||||
|
Total
|
39.6 | 37.9 | 35.6 | 1 | 39 | 466 | 506 | 259 | 247 | 189 | 317 | |||||||||||||||||||||||||||||||||||||||||
|
Powder River Basin:
|
||||||||||||||||||||||||||||||||||||||||||||||||||||
|
North Antelope/ Rochelle
|
88.6 | 82.7 | 82.5 | Steam | 1,171 | — | — | 8,800 | 1,171 | — | 1,171 | 1,171 | — | |||||||||||||||||||||||||||||||||||||||
|
Caballo
|
32.8 | 30.5 | 26.5 | Steam | 787 | 122 | 22 | 8,600 | 931 | — | 931 | 931 | — | |||||||||||||||||||||||||||||||||||||||
|
Rawhide
|
17.0 | 12.4 | 6.9 | Steam | 290 | 62 | 55 | 8,600 | 407 | — | 407 | 407 | — | |||||||||||||||||||||||||||||||||||||||
|
Total
|
138.4 | 125.6 | 115.9 | 2,248 | 184 | 77 | 2,509 | — | 2,509 | 2,509 | — | |||||||||||||||||||||||||||||||||||||||||
|
Southwest/ Colorado:
|
||||||||||||||||||||||||||||||||||||||||||||||||||||
|
Black Mesa
|
— | 3.9 | 4.8 | Steam | 10 | 1 | — | 10,600 | 11 | — | 11 | 11 | — | |||||||||||||||||||||||||||||||||||||||
|
Kayenta
|
8.2 | 8.2 | 8.2 | Steam | 185 | 82 | 3 | 11,000 | 270 | — | 270 | 270 | — | |||||||||||||||||||||||||||||||||||||||
|
Lee Ranch
|
5.5 | 5.3 | 5.8 | Steam | 20 | 123 | 12 | 10,000 | 155 | 88 | 67 | 155 | — | |||||||||||||||||||||||||||||||||||||||
|
Twentymile
|
8.6 | 9.4 | 6.4 | Steam | 73 | — | — | 10,800 | 73 | 14 | 59 | — | 73 | |||||||||||||||||||||||||||||||||||||||
|
Seneca
|
— | 1.1 | 1.5 | Steam | — | — | — | NA | — | — | — | — | — | |||||||||||||||||||||||||||||||||||||||
|
Total
|
22.3 | 27.9 | 26.7 | 288 | 206 | 15 | 509 | 102 | 407 | 436 | 73 | |||||||||||||||||||||||||||||||||||||||||
45
Table of Contents
| Sulfur Content(2) | As of December 31, 2006 | |||||||||||||||||||||||||||||||||||||||||||||||||||
| Production | ||||||||||||||||||||||||||||||||||||||||||||||||||||
| <1.2 lbs. | >1.2 to 2.5 lbs. | >2.5 lbs. | As | Assigned | ||||||||||||||||||||||||||||||||||||||||||||||||
| Year Ended | Year Ended | Year Ended | sulfur dioxide | sulfur dioxide | sulfur dioxide | Received | Proven and | |||||||||||||||||||||||||||||||||||||||||||||
| Geographic Region/Mining | Dec. 31, | Dec. 31, | Dec. 31, | Type of | per | per | per | Btu per | Probable | |||||||||||||||||||||||||||||||||||||||||||
| Complex | 2006 | 2005 | 2004 | Coal | Million Btu | Million Btu | Million Btu | pound(3) | Reserves | Owned | Leased | Surface | Underground | |||||||||||||||||||||||||||||||||||||||
|
Australia:
|
||||||||||||||||||||||||||||||||||||||||||||||||||||
|
North Goonyella/ Eaglefield
|
2.2 | 2.1 | 1.7 | Met. | 48 | — | — | 12,800 | 48 | — | 48 | 2 | 46 | |||||||||||||||||||||||||||||||||||||||
|
Metropolitan
|
0.4 | — | — | Met. | 40 | — | — | 12,700 | 40 | — | 40 | — | 40 | |||||||||||||||||||||||||||||||||||||||
|
Wilkie Creek
|
2.0 | 1.9 | 1.4 | Steam | 223 | — | — | 10,800 | 223 | — | 223 | 223 | — | |||||||||||||||||||||||||||||||||||||||
|
Chain Valley
(80.0%)(5)
|
0.2 | — | — | Steam | 17 | — | — | 11,900 | 17 | — | 17 | — | 17 | |||||||||||||||||||||||||||||||||||||||
|
Wambo Open
Cut(4)
|
1.2 | — | — | Steam | 106 | — | — | 12,400 | 106 | — | 106 | 106 | — | |||||||||||||||||||||||||||||||||||||||
|
Burton
(95.0%)(5)
|
4.3 | 4.4 | 3.2 | Steam/Met. | 38 | — | — | 12,400 | 38 | — | 38 | 38 | — | |||||||||||||||||||||||||||||||||||||||
|
Baralaba(4)
|
0.2 | — | — | Steam/Met. | — | 2 | — | 12,200 | 2 | — | 2 | 2 | — | |||||||||||||||||||||||||||||||||||||||
|
Wilpinjong
|
0.3 | — | — | Steam | — | 165 | — | 9,900 | 165 | — | 165 | 165 | — | |||||||||||||||||||||||||||||||||||||||
|
Millennium(4)
|
0.1 | — | — | Met. | 26 | — | — | 12,800 | 26 | — | 26 | 26 | — | |||||||||||||||||||||||||||||||||||||||
|
Total
|
10.9 | 8.4 | 6.3 | 498 | 167 | — | 665 | — | 665 | 562 | 103 | |||||||||||||||||||||||||||||||||||||||||
|
Total
|
225.8 | 213.0 | 198.9 | 4,377 | 4,377 | 4,377 | 4,377 | 4,377 | 4,377 | 4,377 | 4,377 | |||||||||||||||||||||||||||||||||||||||||
46
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, 2006
(Tons in millions)
| Sulfur Content(2) | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
| <1.2 lbs. | >1.2 to 2.5 lbs. | >2.5 lbs. | As | ||||||||||||||||||||||||||||||||||||||||||||||||||||
| Total Tons | Proven and | sulfur dioxide | sulfur dioxide | sulfur dioxide | Received | Reserve Control | Mining Method | ||||||||||||||||||||||||||||||||||||||||||||||||
| Probable | Type of | per | per | per | Btu per | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Coal Seam Location | Assigned | Unassigned | Reserves(6) | Proven | Probable | Coal | Million Btu | Million Btu | Million Btu | pound(3) | Owned | Leased | Surface | Underground | |||||||||||||||||||||||||||||||||||||||||
|
Appalachia:
|
|||||||||||||||||||||||||||||||||||||||||||||||||||||||
|
Ohio
|
— | 25 | 25 | 19 | 6 | Steam | — | — | 25 | 11,300 | 25 | — | — | 25 | |||||||||||||||||||||||||||||||||||||||||
|
West Virginia
|
188 | 342 | 530 | 310 | 220 | Steam/Met. | 141 | 190 | 199 | 13,000 | 224 | 306 | 15 | 515 | |||||||||||||||||||||||||||||||||||||||||
|
Appalachia
|
188 | 367 | 555 | 329 | 226 | 141 | 190 | 224 | 249 | 306 | 15 | 540 | |||||||||||||||||||||||||||||||||||||||||||
|
Midwest:
|
|||||||||||||||||||||||||||||||||||||||||||||||||||||||
|
Illinois
|
113 | 2,292 | 2,405 | 1,190 | 1,215 | Steam | 5 | 38 | 2,362 | 10,400 | 2,195 | 210 | 78 | 2,327 | |||||||||||||||||||||||||||||||||||||||||
|
Indiana
|
255 | 353 | 608 | 410 | 198 | Steam | 1 | 40 | 567 | 10,300 | 402 | 206 | 258 | 350 | |||||||||||||||||||||||||||||||||||||||||
|
Kentucky
|
138 | 1,019 | 1,157 | 622 | 535 | Steam | — | 1 | 1,156 | 10,800 | 673 | 484 | 105 | 1,052 | |||||||||||||||||||||||||||||||||||||||||
|
Midwest
|
506 | 3,664 | 4,170 | 2,222 | 1,948 | 6 | 79 | 4,085 | 3,270 | 900 | 441 | 3,729 | |||||||||||||||||||||||||||||||||||||||||||
|
Powder River Basin:
|
|||||||||||||||||||||||||||||||||||||||||||||||||||||||
|
Montana
|
— | 162 | 162 | 158 | 4 | Steam | 15 | 117 | 30 | 8,600 | 67 | 95 | 162 | — | |||||||||||||||||||||||||||||||||||||||||
|
Wyoming
|
2,509 | 796 | 3,305 | 3,226 | 79 | Steam | 3,020 | 183 | 102 | 8,700 | — | 3,305 | 3,305 | — | |||||||||||||||||||||||||||||||||||||||||
|
Powder River Basin
|
2,509 | 958 | 3,467 | 3,384 | 83 | 3,035 | 300 | 132 | 67 | 3,400 | 3,467 | — | |||||||||||||||||||||||||||||||||||||||||||
|
Southwest/ Colorado:
|
|||||||||||||||||||||||||||||||||||||||||||||||||||||||
|
Arizona
|
281 | — | 281 | 281 | — | Steam | 195 | 83 | 3 | 10,900 | — | 281 | 281 | — | |||||||||||||||||||||||||||||||||||||||||
|
Colorado
|
73 | 154 | 227 | 165 | 62 | Steam | 139 | — | 88 | 10,600 | 43 | 184 | — | 227 | |||||||||||||||||||||||||||||||||||||||||
|
New Mexico
|
155 | 544 | 699 | 636 | 63 | Steam | 91 | 344 | 264 | 9,200 | 617 | 82 | 699 | — | |||||||||||||||||||||||||||||||||||||||||
|
Southwest
|
509 | 698 | 1,207 | 1,082 | 125 | 425 | 427 | 355 | 660 | 547 | 980 | 227 | |||||||||||||||||||||||||||||||||||||||||||
|
Australia:
|
|||||||||||||||||||||||||||||||||||||||||||||||||||||||
|
New South Wales
|
328 | 138 | 466 | 253 | 213 | Steam/Met. | 466 | — | — | 12,400 | — | 466 | 271 | 195 | |||||||||||||||||||||||||||||||||||||||||
|
Queensland
|
337 | — | 337 | 104 | 233 | Steam/Met. | 335 | 2 | — | 11,200 | — | 337 | 291 | 46 | |||||||||||||||||||||||||||||||||||||||||
|
Australia
|
665 | 138 | 803 | 357 | 446 | 801 | 2 | — | — | 803 | 562 | 241 | |||||||||||||||||||||||||||||||||||||||||||
|
Total Proven and Probable
|
10,202 | 10,202 | 10,202 | 10,202 | 10,202 | 4,408 | 998 | 4,796 | 10,202 | 10,202 | 10,202 | 10,202 | |||||||||||||||||||||||||||||||||||||||||||
47
Table of Contents
| (1) | Assigned reserves represent recoverable coal reserves that we have committed to mine at locations operating as of December 31, 2006. Unassigned reserves represent coal at suspended locations and coal that has not been committed. These reserves would require new mine development, mining equipment or plant facilities before operations could begin on the property. |
| (2) | Compliance coal is defined by Phase II of the Clean Air Act as coal having sulfur dioxide content of 1.2 pounds or less per million Btu. Non-compliance coal is defined as coal having sulfur dioxide content in excess of this standard. Electricity generators are able to use coal that exceeds these specifications by using emissions reduction technology, using emissions allowance credits or blending higher sulfur coal with lower sulfur coal. |
| (3) | As-received Btu per pound includes the weight of moisture in the coal on an as sold basis. The following table reflects the average moisture content used in the determination of as-received Btu by region: |
|
Appalachia
|
6.0 | % | |||
|
Midwest:
|
|||||
|
Illinois
|
14.0 | % | |||
|
Indiana
|
15.0 | % | |||
|
Kentucky
|
12.5 | % | |||
|
Missouri/ Oklahoma
|
12.0 | % | |||
|
Powder River Basin:
|
|||||
|
Montana
|
26.5 | % | |||
|
Wyoming
|
27.5 | % | |||
|
Southwest:
|
|||||
|
Arizona
|
13.0 | % | |||
|
Colorado
|
14.0 | % | |||
|
New Mexico
|
15.5 | % | |||
|
Australia
|
10.0 | % | |||
| (4) | These joint ventures are consolidated in our results and their proven and probable coal reserves are reflected at 100%. Our effective percentage interest in each operation is as follows: Kanawha Eagle — 73.9%; Wambo Open-Cut — 75.0%; Baralaba — 62.5% and Millennium — 84.6%. |
| (5) | Proven and probable coal reserves for these joint ventures reflect our proportional ownership as indicated parenthetically. |
| (6) | Proven and probable reserves exclude approximately 30 million tons located in Zulia State, Venezuela, related to the Las Carmelitas Project, which is held through our 51% interest in Excelven Pty Ltd. |
| Item 3. | Legal Proceedings. |
From time to time, we or our subsidiaries are involved in legal
proceedings arising in the ordinary course of business or
related to indemnities or historical operations. We believe we
have recorded adequate reserves for these liabilities and that
there is no individual case pending that is likely to have a
material adverse effect on our financial condition, results of
operations or cash flows. We discuss our significant legal
proceedings below.
Litigation Relating to Continuing Operations
| Navajo Nation Litigation |
On June 18, 1999, the Navajo Nation served three of our
subsidiaries, including Peabody Western Coal Company
(“Peabody Western”), with a complaint that had been
filed in the U.S. District Court for the District of
Columbia. The Navajo Nation has alleged 16 claims, including
Civil Racketeer Influenced and Corrupt Organizations Act
(“RICO”) violations and fraud. The complaint alleges
that the defendants
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Table of Contents
jointly participated in unlawful activity to obtain favorable
coal lease amendments. The plaintiff is seeking various remedies
including actual damages of at least $600 million, which
could be trebled under the RICO counts, punitive damages of at
least $1 billion, a determination that Peabody
Western’s two coal leases have terminated due to Peabody
Western’s breach of these leases and a reformation of these
leases to adjust the royalty rate to 20%. Subsequently, the
court allowed the Hopi Tribe to intervene in this lawsuit and
the Hopi Tribe is also seeking unspecified actual damages,
punitive damages and reformation of its coal lease. On
March 4, 2003, the U.S. Supreme Court issued a ruling
in a companion lawsuit involving the Navajo Nation and the
United States rejecting the Navajo Nation’s allegation that
the United States breached its trust responsibilities to the
Tribe in approving the coal lease amendments. On
February 9, 2005, the U.S. District Court for the
District of Columbia granted a consent motion to stay the
litigation until further order of the court. Peabody Western,
the Navajo Nation, the Hopi Tribe and the owners of the power
plants served by the suspended Black Mesa mine and the Kayenta
mine are in mediation with respect to this litigation and other
business issues.
The outcome of this litigation, or the current mediation, is
subject to numerous uncertainties. Based on our evaluation of
the issues and their potential impact, the amount of any future
loss cannot be reasonably estimated. However, we believe this
matter is likely to be resolved without a material adverse
effect on our financial condition, results of operations or cash
flows.
| Salt River Project Agricultural Improvement and Power District — Mine Closing and Retiree Health Care |
Salt River Project and the other owners of the Navajo Generating
Station filed a lawsuit on September 27, 1996, in the
Superior Court of Maricopa County in Arizona seeking a
declaratory judgment that certain costs relating to final
reclamation, environmental monitoring work and mine
decommissioning and costs primarily relating to retiree health
care benefits are not recoverable by our subsidiary, Peabody
Western, under the terms of a coal supply agreement dated
February 18, 1977. The contract expires in 2011. The trial
court subsequently ruled that the mine decommissioning costs
were subject to arbitration but that the retiree health care
costs were not subject to arbitration. We have recorded a
receivable for mine decommissioning costs of $76.8 million
and $74.2 million included in “Investments and other
assets” in the consolidated balance sheets as of
December 31, 2006 and 2005, respectively.
The outcome of this litigation and arbitration is subject to
numerous uncertainties. Based on our evaluation of the issues
and their potential impact, the amount of any future loss cannot
be reasonably estimated. However, we believe this matter is
likely to be resolved without a material adverse effect on our
financial condition, results of operations or cash flows.
| Gulf Power Company Litigation |
On June 21, 2006, our subsidiary filed a complaint in the
U.S. District Court, Southern District of Illinois, seeking
a declaratory judgment upholding its declaration of a permanent
force majeure under a coal supply agreement with Gulf Power
Company. On June 22, 2006, Gulf Power Company filed a
breach of contract lawsuit against our subsidiary in the
U.S. District Court, Northern District of Florida,
contesting the force majeure declaration and seeking damages for
alleged past and future tonnage shortfalls of nearly
5 million tons under the coal supply agreement, which would
have expired on December 31, 2007. The parties have filed
motions to determine which court will hear the lawsuits. On
October 6, 2006, the Florida District Court stayed Gulf
Power’s lawsuit until the Illinois court decides whether it
has jurisdiction.
The outcome of this litigation is subject to numerous
uncertainties. Based on our evaluation of the issues and their
potential impact, the amount of any future loss cannot
reasonably be estimated. However, we believe this matter is
likely to be resolved without a material adverse effect on our
financial condition, results of operations or cash flows.
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Table of Contents
Claims and Litigation relating to Indemnities or Historical
Operations
| Citizens Power |
In connection with the August 2000 sale of our former
subsidiary, Citizens Power LLC (“Citizens Power”), we
have indemnified the buyer, Edison Mission Energy, from certain
losses resulting from specified power contracts and guarantees.
During the period that Citizens Power was owned by us, Citizens
Power guaranteed the obligations of two affiliates to make
payments to third parties for power delivered under fixed-priced
power sales agreements with terms that extend through 2008.
Edison Mission Energy has stated and we believe there will be
sufficient cash flow to pay the power suppliers, assuming timely
payment by the power purchasers. There is no pending litigation
with respect to these indemnities at this time.
| Oklahoma Lead Litigation |
Gold Fields Mining, LLC (“Gold Fields”) is a dormant,
non-coal producing entity that was previously managed and owned
by Hanson PLC, our predecessor owner. In a February 1997
spin-off, Hanson PLC transferred ownership of Gold Fields to us,
despite the fact that Gold Fields had no ongoing operations and
we had no prior involvement in its past operations. Today Gold
Fields is one of our subsidiaries. We indemnified TXU Group with
respect to certain claims relating to a former affiliate of Gold
Fields. A predecessor of Gold Fields formerly operated two lead
mills near Picher, Oklahoma prior to the 1950s and mined, in
accordance with lease agreements and permits, approximately
0.15% of the total amount of the crude ore mined in the county.
Gold Fields and two other companies are defendants in two class
action lawsuits. The plaintiffs have asserted claims predicated
on allegations of intentional lead exposure by the defendants
and are seeking compensatory damages, punitive damages and the
implementation of medical monitoring and relocation programs for
the affected individuals. Gold Fields is also a defendant, along
with other companies, in several personal injury lawsuits
involving over 50 children, arising out of the same lead mill
operations. Plaintiffs in these actions are seeking compensatory
and punitive damages for alleged personal injuries from lead
exposure. The first personal injury trial has been scheduled for
March 2007 and Gold Fields along with the former affiliate will
be the only defendants. In December 2003, the Quapaw Indian
tribe and certain Quapaw land owners filed a class action
lawsuit against Gold Fields and five other companies. The
plaintiffs are seeking compensatory and punitive damages based
on a variety of theories. Gold Fields has filed a third-party
complaint against the United States, and other parties. In
February 2005, the state of Oklahoma on behalf of itself and
several other parties sent a notice to Gold Fields and other
companies regarding a possible natural resources damage claim.
All of the lawsuits are pending in the U.S. District Court
for the Northern District of Oklahoma.
The outcome of litigation and these claims are subject to
numerous uncertainties. Based on our evaluation of the issues
and their potential impact, the amount of any future loss cannot
be reasonably estimated. However, we believe this matter is
likely to be resolved without a material adverse effect on our
financial condition, results of operations or cash flows.
Environmental Claims and Litigation
We are subject to applicable federal, state and local
environmental laws and regulations in those countries where we
conduct operations. Current and past mining operations in the
United States are primarily covered by the Surface Mining
Control and Reclamation Act of 1977, the Clean Water Act and the
Clean Air Act but also include the Comprehensive Environmental
Response, Compensation and Liability Act of 1980, as amended
(“CERCLA” or “Superfund”), the Superfund
Amendments and Reauthorization Act of 1986 and the Resource
Conservation and Recovery Act of 1976. Superfund and similar
state laws create liability for investigation and remediation in
response to releases of hazardous substances in the environment
and for damages to natural resources. Under that legislation and
many state Superfund statutes, joint and several liability may
be imposed on waste generators, site owners and operators and
others regardless of fault. These regulations could require us
to do some or all of the
50
Table of Contents
following: (i) remove or mitigate the effects on the
environment at various sites from the disposal or release of
certain substances; (ii) perform remediation work at such
sites; and (iii) pay damages for loss of use and non-use
values.
Our policy is to accrue environmental cleanup-related costs of a
non-capital nature when those costs are believed to be probable
and can be reasonably estimated. The quantification of
environmental exposures requires an assessment of many factors,
including the nature and extent of contamination, the timing,
extent and method of the remedial action, changing laws and
regulations, advancements in environmental technologies, the
quality of information available related to specific sites, the
assessment stage of each site investigation, preliminary
findings and the length of time involved in remediation or
settlement. We also assess the financial capability and
proportional share of costs of other PRPs and, where allegations
are based on tentative findings, the reasonableness of our
apportionment. We have not anticipated any recoveries from
insurance carriers in the estimation of liabilities recorded in
our consolidated balance sheets.
Although waste substances generated by coal mining and
processing are generally not regarded as hazardous substances
for the purposes of Superfund and similar legislation and are
generally covered by the Surface Mining Control and Reclamation
Act of 1977, some products used by coal companies in operations,
such as chemicals, and the disposal of these products are
governed by the Superfund statute. Thus, coal mines currently or
previously owned or operated by us, and sites to which we have
sent waste materials, may be subject to liability under
Superfund and similar state laws.
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”) based on CERCLA at five
sites, and claims have been asserted at 18 other sites. 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 $43.0 million as of
December 31, 2006 and $42.5 million as of
December 31, 2005, $14.4 million and
$23.6 million of which was reflected as a current
liability, respectively. These amounts represent those costs
that we believe are probable and reasonably estimable. In
September 2005, Gold Fields and other PRPs received a letter
from the U.S. Department of Justice alleging that the
PRPs’ mining operations caused the Environmental Protection
Agency (“EPA”) to incur approximately
$125 million in residential yard remediation costs at
Picher, Oklahoma and will cause the EPA to incur additional
remediation costs relating to historical mining sites. Gold
Fields has participated in the ongoing settlement discussions. 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
believes it has meritorious defenses to these claims. Gold
Fields is involved in other litigation in the Picher area, and
we indemnified TXU Group with respect to a defendant as is more
fully discussed under the “Oklahoma Lead Litigation”
caption above. Significant uncertainty exists as to whether
claims will be pursued against Gold Fields in all cases, and
where they are pursued, the amount of the eventual costs and
liabilities, which could be greater or less than this provision.
Other
In addition, at times we become a party to other claims,
lawsuits, arbitration proceedings and administrative procedures
in the ordinary course of business. Management believes that the
ultimate resolution of such other pending or threatened
proceedings is not reasonably likely to have a material adverse
effect on our financial position, results of operations or
liquidity.
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Table of Contents
| Item 4. | Submission of Matters to a Vote of Security Holders. |
No matters were submitted to a vote of security holders during
the quarter ended December 31, 2006.
Executive Officers of the Company
Set forth below are the names, ages as of February 16, 2007
and current positions of our executive officers. Executive
officers are appointed by, and hold office at, the discretion of
our Board of Directors.
| Name | Age | Position | ||||
|
Gregory H. Boyce
|
52 | President and Chief Executive Officer, Director | ||||
|
Sharon D. Fiehler
|
50 | Executive Vice President — Human Resources and Administration | ||||
|
Richard A. Navarre
|
46 | Chief Financial Officer and Executive Vice President of Corporate Development | ||||
|
Alexander C. Schoch
|
52 | Executive Vice President Law and Chief Legal Officer | ||||
|
Roger B. Walcott, Jr.
|
50 | Executive Vice President — Strategy and Business Services | ||||
|
Richard M. Whiting
|
52 | Executive Vice President and Chief Marketing Officer | ||||
|
Rick Bowen
|
51 | President, Generation and Btu Conversion | ||||
|
Ian S. Craig
|
53 | Managing Director — Australia Operations | ||||
|
Jiri Nemec
|
50 | Group Vice President — U.S. Eastern Operations | ||||
|
Kemal Williamson
|
47 | Group Vice President — U.S. Western Operations | ||||
Gregory H. Boyce has been a director of the Company since March
2005. Mr. Boyce was named Chief Executive Officer Elect of
the Company in March 2005, and assumed the position of Chief
Executive Officer in January 2006. He also serves as President
of the Company, a position he has held since October 2003. He
was Chief Operating Officer of the Company from October 2003 to
December 2005. He previously served as Chief
Executive — Energy of Rio Tinto plc (an international
natural resource company) from 2000 to 2003. Other prior
positions include President and Chief Executive Officer of
Kennecott Energy Company from 1994 to 1999 and President of
Kennecott Minerals Company from 1993 to 1994. He has extensive
engineering and operating experience with Kennecott and also
served as Executive Assistant to the Vice Chairman of Standard
Oil of Ohio from 1983 to 1984. Mr. Boyce is Co-Chairman of
the Coal Based Generation Stakeholders Group, and a member of
the Coal Industry Advisory Board of the International Energy
Agency, the Advisory Council of the University of Arizona’s
Department of Mining and Geological Engineering and the National
Council of the School of Engineering and Applied Science at
Washington University in St. Louis. He is a board member of
the Center for Energy and Economic Development, the National
Mining Association and the National Coal Council, and a past
board member of the Western Regional Council, Mountain States
Employers Council and Wyoming Business Council.
Sharon D. Fiehler has been our Executive Vice President of Human
Resources and Administration since April 2002, with executive
responsibility for employee development, benefits, compensation,
employee relations, affirmative action programs, information
services, flight services and facilities management. She joined
us in 1981 as Manager — Salary Administration and has
held a series of employee relations, compensation and salaried
benefits positions. Ms. Fiehler holds degrees in social
work and psychology and an MBA, and prior to joining Peabody was
a personnel representative for Ford Motor Company.
Ms. Fiehler is a member of the Executive Committee and
Board of Directors of Junior Achievement of St. Louis and a
Board member of the Chancellor’s Council of the University
of Missouri at St. Louis. She is also a member of the
Women’s Advisory Council of the University of Missouri at
St. Louis Executive Leadership Institute and the
St. Louis Women’s Forum.
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Table of Contents
Richard A. Navarre is our Chief Financial Officer and Executive
Vice President of Corporate Development. He has served as Chief
Financial Officer since October 1999. He also previously served
as President of Peabody’s COALSALES, LLC affiliate,
President of Peabody Energy Solutions, Inc., Vice President of
Finance and Vice President and Controller. He joined our
predecessor company in 1993. Prior to joining us,
Mr. Navarre was a senior manager with KPMG Peat Marwick.
Mr. Navarre is former Chairman of the Bituminous Coal
Operators’ Association. He serves on the Board of Advisors
to the College of Business for Southern Illinois University at
Carbondale and is a member of the International Business
Advisory Board, University of Missouri-St. Louis, College
of Business Administration. He is a member of Financial
Executives International. Mr. Navarre is on the Board of
Directors of the Missouri Historical Society.
Alexander C. Schoch was named our Executive Vice President Law
and Chief Legal Officer in October 2006, with responsibility for
all of our legal and corporate secretary functions. Prior to
joining us, Mr. Schoch served as Vice President and General
Counsel for Emerson Process Management, an operating segment of
Emerson Electric Company and leading supplier of
process-automation products. Mr. Schoch also served in
several legal positions with Goodrich Corporation, a global
supplier to the aerospace and defense industries, from 1987 to
2004, including Vice President, Associate General Counsel and
Secretary. Prior to that, he worked for Marathon Oil Company as
an attorney in its international exploration and production
division. Mr. Schoch holds a Juris Doctorate from Case
Western Reserve University in Ohio, as well as a Bachelor of
Arts in Economics from Kenyon College in Ohio. He is admitted to
practice law in several states, and is a member of the American
and International Bar Associations.
Roger B. Walcott, Jr. became Executive Vice
President — Strategy and Business Services in May
2006. Prior to that he was our Executive Vice
President — Resource Management and Strategic Planning
since July 2005 and our Executive Vice President —
Corporate Development since February 2001. He joined us in June
1998 as Executive Vice President. From 1987 to 1998, he was a
Senior Vice President and a director with The Boston Consulting
Group, where he served a variety of clients in strategy and
operational assignments. He joined Boston Consulting Group in
1981, and was Chairman of The Boston Consulting Group’s
Human Resource Capabilities Committee. Mr. Walcott holds a
MBA with high distinction from the Harvard Business School.
Richard M. Whiting became Executive Vice President and Chief
Marketing Officer in May 2006. Prior to that he was our
Executive Vice President — Sales, Marketing and
Trading since October 2002. Previously, Mr. Whiting served
as our President and Chief Operating Officer and President of
Peabody’s COALSALES, LLC affiliate. He joined our
predecessor company in 1976 and has held a number of operations,
sales and engineering positions both at the corporate offices
and at field locations. Mr. Whiting is the former Chairman
of the National Mining Association’s Safety and Health
Committee, the former Chairman of the Bituminous Coal
Operators’ Association, a past board member of the National
Coal Council and is a member of the Visiting Committee of West
Virginia University College of Engineering and Mineral Resources.
Rick Bowen became President of Generation and Btu Conversion in
July 2006, with responsibility for project and business
development for planned electric generating initiatives and
projects for technologies to transform the energy in coal into
other high-demand energy forms. He joined us in September 2004
as Corporate Senior Vice President and President of Generation.
Prior to joining us, Mr. Bowen served for 20 years
with Dynegy Inc. and its predecessor companies. Mr. Bowen
is a member of the Board of Directors of the Western Electric
Coordinating Council and the Industry Advisory Board, Consortium
for Electric Reliability Technology Solutions. He holds a
Bachelor of Science in Business Administration and a Master of
Business Administration from the University of Houston.
Ian S. Craig was named our Managing Director —
Australia Operations in September 2004. From May 2004 to August
2004, Mr. Craig served as Group Executive —
Technical Services. He was Group Executive — Powder
River Basin Operations from July 2001 to April 2004. Prior to
that, he was Managing Director of a former Peabody subsidiary in
Australia. Mr. Craig also held a number of management
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Table of Contents
positions within the subsidiary company and other Australian
mining organizations. He holds a Bachelor of Applied Science
Degree in Mineral Engineering from the South Australian
Institute of Technology. Mr. Craig is a Fellow of The
Australasian Institute of Mining and Metallurgy.
Jiri Nemec has been our Group Vice President —
U.S. Eastern Operations since July 2005. Previously,
Mr. Nemec was Group Executive of Appalachia and Highland
Operations from April 2004 to July 2005; Appalachia Operations
from January 2001 to April 2004; Midwest Operations from August
1999 to January 2001; and Northern Appalachia Operations from
July 1998 to August 1999. He has extensive experience in mining
engineering and operations, primarily with a Peabody subsidiary
in West Virginia. He holds a Bachelor of Science Degree in
Engineering from Pennsylvania State University and an MBA from
Washington University.
Kemal Williamson became our Group Vice President —
U.S. Western Operations in July 2005. After joining us in
September 2000, Mr. Williamson served as Group
Executive — Midwest Operations until April 2004, and
then was Group Executive — Powder River Basin
Operations until July 2005. He has extensive mining engineering
and operations experience in the United States and Australia.
Mr. Williamson holds a Bachelor of Science Degree in Mining
Engineering from Pennsylvania State University and an MBA from
Kellogg Graduate School of Management, Northwestern University.
PART II
| 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 16, 2007, there
were 952 holders of record of our common stock.
The table below sets forth the range of quarterly high and low
sales prices for our common stock (after giving retroactive
effect to the two-for-one stock split effective
February 22, 2006) on the New York Stock Exchange during
the calendar quarters indicated.
| High | Low | ||||||||
|
2005
|
|||||||||
|
First Quarter
|
$ | 25.47 | $ | 18.38 | |||||
|
Second Quarter
|
28.23 | 19.68 | |||||||
|
Third Quarter
|
43.03 | 26.01 | |||||||
|
Fourth Quarter
|
43.48 | 35.22 | |||||||
|
2006
|
|||||||||
|
First Quarter
|
$ | 52.54 | $ | 41.24 | |||||
|
Second Quarter
|
76.29 | 46.81 | |||||||
|
Third Quarter
|
59.90 | 32.94 | |||||||
|
Fourth Quarter
|
48.59 | 34.05 | |||||||
Dividend Policy
The quarterly dividend rate for Common Stock was increased 26%
by the Board of Directors to $0.06 per share (from
$0.0475 per share) on January 23, 2006, when a
dividend of $0.06 per share was declared on Common Stock,
payable on February 22, 2006, to stockholders of record on
February 7, 2006. We paid quarterly dividends totaling
$0.24 per share during the year ended December 31,
2006, and $0.17 per share during the year ended
December 31, 2005. Most recently, our Board of Directors
declared a dividend of $0.06 per share of Common Stock on
January 23, 2007, payable on February 27, 2007, to
stockholders of record on February 6, 2007. 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
54
Table of Contents
Directors; however, we presently expect that dividends will
continue to be paid. Limitations on our ability to pay dividends
imposed by our debt instruments are discussed in Item 7.
Management’s Discussion and Analysis of Financial Condition
and Results of Operations.
Stock Split
On February 22, 2006, we effected a two-for-one stock split
on all shares of our common stock. Shareholders of record at the
close of business on February 7, 2006, received a dividend
of one share of stock for every share held. The stock began
trading ex-split on February 23, 2006. On March 30,
2005, we effected a two-for-one stock split on all shares of our
common stock. Shareholders of record at the close of business on
March 16, 2005 received a dividend of one share of stock
for every share held. The stock began trading ex-split on
March 31, 2005. All share and per share amounts in this
Annual Report on
Form 10-K reflect
both two-for-one stock splits.
Share Repurchase Program
In July 2005, our Board of Directors authorized a share
repurchase program of up to 5% of the then outstanding shares of
our common stock, approximately 13.1 million shares. The
repurchases may be made from time to time based on an evaluation
of our outlook and general business conditions, as well as
alternative investment and debt repayment options. As of
December 31, 2006, there were approximately
10.9 million shares available for repurchase. There were no
share repurchases made in the three months ended
December 31, 2006.
55
Table of Contents
Stock Performance Graph
The following performance graph compares the cumulative total
return on our common stock with the cumulative total return of
the following indices: (i) the
S&P©
400 MidCap Stock Index; (ii) the
S&P©
500 Stock Index; (iii) a peer group comprised of Arch Coal
Inc., Massey Energy Company, CONSOL Energy, Inc. and
Westmoreland Coal Company (“Peer Group 1”) and
(iv) a peer group comprised of Arch Coal Inc., Massey
Energy Company, CONSOL Energy, Inc., Foundation Coal Holdings
Inc., Alpha Natural Resources, Inc. and International Coal
Group, Inc. (“Peer Group 2”). The companies included
in Peer Group 2 are listed in the Bloomberg U.S. Coal Index
as of December 31, 2006. In November 2006, we were added to
the
S&P©
500 Stock Index and we have accordingly changed our equity
market index to the
S&P©
500 Stock Index from the
S&P©
400 MidCap Stock Index. The graph assumes that the value of
the investment in our common stock and each index was $100 at
December 31, 2001. The graph also assumes that all
dividends were reinvested and that investments were held through
December 31, 2006. These indices are included for
comparative purposes only and do not necessarily reflect
management’s opinion that such indices are an appropriate
measure of the relative performance of the stock involved, and
are not intended to forecast or be indicative of possible future
performance of the common stock.
| Dec-01 | Dec-02 | Dec-03 | Dec-04 | Dec-05 | Dec-06 | ||||||||||||||||||||||||||
|
Peabody Energy Corporation
|
$ | 100 | $ | 105 | $ | 153 | $ | 299 | $ | 614 | $ | 605 | |||||||||||||||||||
|
S&P©
500 Stock Index
|
$ | 100 | $ | 78 | $ | 100 | $ | 111 | $ | 117 | $ | 135 | |||||||||||||||||||
|
S&P©
MidCap 400 Stock Index
|
$ | 100 | $ | 85 | $ | 116 | $ | 135 | $ | 152 | $ | 168 | |||||||||||||||||||
|
Peer Group 1
|
$ | 100 | $ | 71 | $ | 117 | $ | 175 | $ | 278 | $ | 229 | |||||||||||||||||||
|
Peer Group 2
|
$ | 100 | $ | 70 | $ | 116 | $ | 173 | $ | 246 | $ | 197 | |||||||||||||||||||
| 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 2006
and 2005 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. Adjusted EBITDA is defined as income from continuing
operations before deducting early debt extinguishment costs, net
interest expense, income taxes, minority interests, asset
retirement obligation expense and depreciation, depletion and
amortization.
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Table of Contents
Adjusted EBITDA is used by management to measure operating
performance, and management also believes it is a useful
indicator of our ability to meet debt service and capital
expenditure requirements. Because Adjusted EBITDA is not
calculated identically by all companies, our calculation may not
be comparable to similarly titled measures of other companies.
In October 2006, we acquired Excel Coal Limited and our results
of operations for the year ended December 31, 2006 included
the results of operations of the three operating mines and three
development-stage mines in New South Wales, Australia and
Queensland, Australia from the date of acquisition.
On April 15, 2004, we acquired three coal operations from
RAG Coal International AG. Our results of operations for the
year ended December 31, 2004 include the results of
operations of the two mines in Queensland, Australia and the
results of operations of the Twentymile Mine in Colorado from
the April 15, 2004 purchase date.
Results of operations for the year ended December 31, 2003
include early debt extinguishment costs of $53.5 million
pursuant to our debt refinancing in the first half of 2003. In
addition, results included expense relating to the cumulative
effect of accounting changes, net of income taxes, of
$10.1 million. This amount represents the aggregate amount
of the recognition of accounting changes pursuant to the
adoption of SFAS No. 143, “Accounting for Asset
Retirement Obligations,” the change in method of
amortization of actuarial gains and losses related to net
periodic postretirement benefit costs and the effect of the
rescission of Emerging Issues Task Force
No. 98-10,
“Accounting for Contracts Involved in Energy Trading and
Risk Management Activities.”
We have derived the selected historical financial data as of and
for the years ended December 31, 2006, 2005, 2004, 2003 and
2002 from our audited financial statements. All share and per
share amounts included in the following consolidated financial
data have been retroactively adjusted to reflect the two-for-one
stock splits, effective February 22, 2006, and
March 30, 2005. You should read the following table in
conjunction with the financial statements, the related notes to
those financial statements and Item 7. Management’s
Discussion and Analysis of Financial Condition and Results of
Operations.
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Table of Contents
The results of operations for the historical periods included in
the following table are not necessarily indicative of the
results to be expected for future periods. In addition, the Risk
Factors section of Item 1A of this report includes a
discussion of risk factors that could impact our future results
of operations.
| Year Ended December 31, | ||||||||||||||||||||||
| 2006 | 2005 | 2004 | 2003 | 2002 | ||||||||||||||||||
| (Dollars in thousands, except share and per share data) | ||||||||||||||||||||||
|
Results of Operations Data
|
||||||||||||||||||||||
|
Revenues
|
||||||||||||||||||||||
|
Sales
|
$ | 5,144,925 | $ | 4,545,323 | $ | 3,545,027 | $ | 2,729,323 | $ | 2,630,371 | ||||||||||||
|
Other revenues
|
111,390 | 99,130 | 86,555 | 85,973 | 89,267 | |||||||||||||||||
|
Total revenues
|
5,256,315 | 4,644,453 | 3,631,582 | 2,815,296 | 2,719,638 | |||||||||||||||||
|
Costs and expenses
|
||||||||||||||||||||||
|
Operating costs and expenses
|
4,155,984 | 3,715,836 | 2,965,541 | 2,332,137 | 2,225,344 | |||||||||||||||||
|
Depreciation, depletion and amortization
|
377,210 | 316,114 | 270,159 | 234,336 | 232,413 | |||||||||||||||||
|
Asset retirement obligation expense
|
40,112 | 35,901 | 42,387 | 31,156 | — | |||||||||||||||||
|
Selling and administrative expenses
|
175,941 | 189,802 | 143,025 | 108,525 | 101,416 | |||||||||||||||||
|
Other operating income:
|
||||||||||||||||||||||
|
Net gain on disposal of assets
|
(132,162 | ) | (101,487 | ) | (23,829 | ) | (32,772 | ) | (15,763 | ) | ||||||||||||
|
(Income) loss from equity affiliates
|
(23,852 | ) | (30,096 | ) | (12,399 | ) | (2,872 | ) | 2,540 | |||||||||||||
|
Operating profit
|
663,082 | 518,383 | 246,698 | 144,786 | 173,688 | |||||||||||||||||
|
Interest expense
|
143,450 | 102,939 | 96,793 | 98,540 | 102,458 | |||||||||||||||||
|
Early debt extinguishment costs
|
1,396 | — | 1,751 | 53,513 | — | |||||||||||||||||
|
Interest income
|
(12,726 | ) | (10,641 | ) | (4,917 | ) | (4,086 | ) | (7,574 | ) | ||||||||||||
|
Income (loss) before income taxes and minority interests
|
530,962 | 426,085 | 153,071 | (3,181 | ) | 78,804 | ||||||||||||||||
|
Income tax provision (benefit)
|
(81,515 | ) | 960 | (26,437 | ) | (47,708 | ) | (40,007 | ) | |||||||||||||
|
Minority interests
|
11,780 | 2,472 | 1,282 | 3,035 | 13,292 | |||||||||||||||||
|
Income from continuing operations
|
600,697 | 422,653 | 178,226 | 41,492 | 105,519 | |||||||||||||||||
|
Loss from discontinued operations
|
— | — | (2,839 | ) | — | — | ||||||||||||||||
|
Income before accounting changes
|
600,697 | 422,653 | 175,387 | 41,492 | 105,519 | |||||||||||||||||
|
Cumulative effect of accounting changes
|
— | — | — | (10,144 | ) | — | ||||||||||||||||
|
Net income
|
$ | 600,697 | $ | 422,653 | $ | 175,387 | $ | 31,348 | $ | 105,519 | ||||||||||||
|
Basic earnings per share from continuing operations
|
$ | 2.28 | $ | 1.62 | $ | 0.72 | $ | 0.19 | $ | 0.51 | ||||||||||||
|
Diluted earnings per share from continuing operations
|
$ | 2.23 | $ | 1.58 | $ | 0.70 | $ | 0.19 | $ | 0.49 | ||||||||||||
|
Weighted average shares used in calculating basic earnings per
share
|
263,419,344 | 261,519,424 | 248,732,744 | 213,638,084 | 208,662,940 | |||||||||||||||||
|
Weighted average shares used in calculating diluted earnings per
share
|
269,166,005 | 268,013,476 | 254,812,632 | 219,342,512 | 215,287,040 | |||||||||||||||||
|
Dividends declared per share
|
$ | 0.24 | $ | 0.17 | $ | 0.13 | $ | 0.11 | $ | 0.10 | ||||||||||||
|
Other Data
|
||||||||||||||||||||||
|
Tons sold (in millions)
|
247.6 | 239.9 | 227.2 | 203.2 | 197.9 | |||||||||||||||||
|
Net cash provided by (used in):
|
||||||||||||||||||||||
|
Operating activities
|
$ | 595,726 | $ | 702,759 | $ | 283,760 | $ | 188,861 | $ | 234,804 | ||||||||||||
|
Investing activities
|
(2,143,818 | ) | (584,202 | ) | (705,030 | ) | (192,280 | ) | (144,078 | ) | ||||||||||||
|
Financing activities
|
1,371,325 | (4,915 | ) | 693,404 | 48,598 | (58,398 | ) | |||||||||||||||
|
Adjusted
EBITDA(1)
|
1,080,404 | 870,398 | 559,244 | 410,278 | 406,101 | |||||||||||||||||
|
Additions to property, plant, equipment & mine
development
|
477,721 | 384,304 | 151,944 | 156,443 | 208,562 | |||||||||||||||||
|
Federal coal lease expenditures
|
178,193 | 118,364 | 114,653 | — | — | |||||||||||||||||
|
Purchase of mining and related assets
|
— | 141,195 | — | — | — | |||||||||||||||||
|
Acquisitions, net
|
1,552,313 | — | 429,061 | 90,000 | 46,012 | |||||||||||||||||
|
Balance Sheet Data (at period end)
|
||||||||||||||||||||||
|
Total assets
|
$ | 9,514,056 | $ | 6,852,006 | $ | 6,178,592 | $ | 5,280,265 | $ | 5,125,949 | ||||||||||||
|
Total debt
|
3,263,826 | 1,405,506 | 1,424,965 | 1,196,539 | 1,029,211 | |||||||||||||||||
|
Total stockholders’ equity
|
2,338,526 | 2,178,467 | 1,724,592 | 1,132,057 | 1,081,138 | |||||||||||||||||
| (1) | Adjusted EBITDA is defined as income from continuing operations before deducting early debt extinguishment costs, net interest expense, income taxes, minority interests, asset retirement obligation expense and depreciation, depletion and amortization. Adjusted EBITDA is used by management to measure operating performance, and management also believes it is a useful indicator of our ability to meet debt service and capital expenditure requirements. Because Adjusted EBITDA is not calculated |
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| identically by all companies, our calculation may not be comparable to similarly titled measures of other companies. |
Adjusted EBITDA is calculated as follows (unaudited):
| Year Ended December 31, | ||||||||||||||||||||
| 2006 | 2005 | 2004 | 2003 | 2002 | ||||||||||||||||
| (Dollars in thousands) | ||||||||||||||||||||
|
Income from continuing operations
|
$ | 600,697 | $ | 422,653 | $ | 178,226 | $ | 41,492 | $ | 105,519 | ||||||||||
|
Income tax provision (benefit)
|
(81,515 | ) | 960 | (26,437 | ) | (47,708 | ) | (40,007 | ) | |||||||||||
|
Depreciation, depletion and amortization
|
377,210 | 316,114 | 270,159 | 234,336 | 232,413 | |||||||||||||||
|
Asset retirement obligation expense
|
40,112 | 35,901 | 42,387 | 31,156 | — | |||||||||||||||
|
Interest expense
|
143,450 | 102,939 | 96,793 | 98,540 | 102,458 | |||||||||||||||
|
Early debt extinguishment costs
|
1,396 | — | 1,751 | 53,513 | — | |||||||||||||||
|
Interest income
|
(12,726 | ) | (10,641 | ) | (4,917 | ) | (4,086 | ) | (7,574 | ) | ||||||||||
|
Minority interests
|
11,780 | 2,472 | 1,282 | 3,035 | 13,292 | |||||||||||||||
|
Adjusted EBITDA
|
$ | 1,080,404 | $ | 870,398 | $ | 559,244 | $ | 410,278 | $ | 406,101 | ||||||||||
| Item 7. | Management’s Discussion and Analysis of Financial Condition and Results of Operations. |
Overview
We are the largest private sector coal company in the world,
with majority interests in 40 coal operations located throughout
all major U.S. coal producing regions and internationally
in Australia and Venezuela. In 2006, we sold 247.6 million
tons of coal, which was approximately 38% greater than the sales
of our closest competitor. Our domestic sales represented 22% of
all U.S. coal sales and was approximately 80% greater than
the sales of our closest domestic competitor. Based on Energy
Information Administration (“EIA”) estimates, demand
for coal in the United States was approximately 1.1 billion
tons in 2006. Domestic coal consumption is expected to grow at
an average rate of 1.8% per year through 2030 when
U.S. coal demand is forecasted to be 1.8 billion tons.
The EIA expects demand for coal use at
coal-to-liquids
(“CTL”) plants to grow to 112 million tons by
2030. Coal-fueled generation is used in most cases to meet
baseload electricity requirements, and coal use generally grows
at the approximate rate of electricity growth, which is expected
to average 1.5% annually through 2030. Coal production
located west of the Mississippi River is projected to provide
most of the incremental growth as Western production increases
to an estimated 68% share of total production in 2030. In 2005,
coal’s share of electricity generation was approximately
50%, a share that the EIA projects will grow to 57% by 2030.
Our primary customers are U.S. utilities, which accounted
for 87% of our sales in 2006. We typically sell coal to utility
customers under long-term contracts (those with terms longer
than one year). During 2006, approximately 90% of our sales were
under long-term contracts. As of December 31, 2006,
production totaled 226.2 million tons and sales totaled
247.6 million tons. As discussed more fully in
Item 1A. Risk Factors, our results of operations in the
near-term could be negatively impacted by poor weather
conditions, unforeseen geologic conditions or equipment problems
at mining locations, and by the availability of transportation
for coal shipments. On a long-term basis, our results of
operations could be impacted by our ability to secure or acquire
high-quality coal reserves, find replacement buyers for coal
under contracts with comparable terms to existing contracts, or
the passage of new or expanded regulations that could limit our
ability to mine, increase our mining costs, or limit our
customers’ ability to utilize coal as fuel for electricity
generation. In the past, we have achieved production levels that
are relatively consistent with our projections.
We conduct business through four principal operating segments:
Western U.S. Mining, Eastern U.S. Mining, Australian
Mining, and Trading and Brokerage. Our Western U.S. Mining
operations consist of our Powder River Basin, Southwest and
Colorado operations, and our Eastern U.S. Mining operations
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Table of Contents
consist of our Appalachia and Midwest operations. The principal
business of the Western U.S. Mining segment is the mining,
preparation and sale of steam coal, sold primarily to electric
utilities. The principal business of the Eastern
U.S. Mining segment is the mining, preparation and sale of
steam coal, sold primarily to electric utilities, as well as the
mining of metallurgical coal, sold to steel and coke producers.
Geologically, Western operations mine bituminous and
subbituminous coal deposits and Eastern operations mine
bituminous coal deposits. Our Western U.S. Mining
operations are characterized by predominantly surface extraction
processes, lower sulfur content and Btu of coal, and higher
customer transportation costs (due to longer shipping
distances). Our Eastern U.S. Mining operations are
characterized by predominantly underground extraction processes,
higher sulfur content and Btu of coal, and lower customer
transportation costs (due to shorter shipping distances).
Australian Mining operations are characterized by both surface
and underground extraction processes, mining various qualities
of low-sulfur, high Btu coal (metallurgical coal) as well as
steam coal primarily sold to an international customer base with
a small portion sold to Australian steel producers and power
generators. In the second half of 2006, through two separate
transactions, we acquired Excel Coal Limited
(“Excel”), an independent coal company in Australia
for a total acquisition price of US$1.51 billion, net of
cash received, plus approximately US$293.0 million in
assumed debt. See Liquidity and Capital Resources for
information on the financing of the Excel transaction. Assets
acquired include three operating mines and three
development-stage mines, along with more than 500 million
tons of proven and probable coal reserves.
We own a 25.5% interest in Carbones del Guasare, which owns and
operates the Paso Diablo Mine in Venezuela. The Paso Diablo Mine
produces approximately 6 to 8 million tons of steam coal
annually for export to the United States and Europe. During
2006, the Paso Diablo Mine contributed $28.0 million to
segment Adjusted EBITDA in “Corporate and Other Adjusted
EBITDA” and paid a dividend of $18.2 million. At
December 31, 2006, our investment in Paso Diablo was
$60.1 million.
Metallurgical coal is produced primarily from four of our
Australian mines (two of which were acquired in the Excel
transaction) and two of our U.S. mines. Metallurgical coal
is approximately 5% of our total sales volume and approximately
3% of U.S. sales volume.
In addition to our mining operations, which comprised 87% of
revenues in 2006, our trading and brokerage operations (13% of
revenues), transactions utilizing our vast natural resource
position (selling non-core land holdings and mineral interests)
and other ventures generate revenues and additional cash flows.
We continue to pursue the development of coal-fueled generating
projects in areas of the U.S. where electricity demand is
strong and where there is access to land, water, transmission
lines and low-cost coal. The projects involve mine-mouth
generating plants using our surface lands and coal reserves. Our
ultimate role in these projects could take numerous forms,
including, but not limited to, equity partner, contract miner or
coal sales. The projects we are currently pursuing include the
1,600-megawatt Prairie State Energy Campus in Washington County,
Illinois and the 1,500-megawatt Thoroughbred Energy Campus in
Muhlenberg County, Kentucky. The plants, assuming all necessary
permits and financing are obtained and following selection of
partners and sale of a majority of the output of each plant,
could be operational following a four-year construction phase.
In October 2006, we entered an agreement with CMS Enterprises to
share equally an expected 30% equity interest in the Prairie
State Energy Campus and to oversee development and operation of
the generating plant and coal mine. In the third quarter of
2006, the Prairie State Energy Campus received affirmation of
the air quality permit from the U.S. Environmental
Protection Agency, and in the fourth quarter of 2006, parties
that had previously challenged the permit filed a new appeal.
The EIA projects that the high price of oil will lead to an
increase in demand for unconventional sources of transportation
fuel, including Btu conversion technologies, and that coal will
increase its share as a fuel for generation of electricity. We
are exploring several Btu conversion projects, which are
designed to
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Table of Contents
expand the uses of coal through various technologies, and we are
continuing to explore options particularly as they relate to Btu
conversion technologies such as
coal-to-liquids and
coal gasification.
Effective February 22, 2006, we implemented a two-for-one
stock split on all shares of our common stock. All share and per
share amounts in this annual report on
Form 10-K reflect
this split. In July 2005, our Board of Directors authorized a
share repurchase program of up to 5% of the outstanding shares
of our common stock. The repurchases may be made from time to
time based on an evaluation of our outlook and general business
conditions, as well as alternative investment and debt repayment
options. In 2006, we repurchased 2.2 million of our common
shares for $99.8 million under this repurchase program.
Results of Operations
| Adjusted EBITDA |
The discussion of our results of operations below includes
references to and analysis of our segments’ Adjusted EBITDA
results. Adjusted EBITDA is defined as income from continuing
operations before deducting early debt extinguishment costs, net
interest expense, income taxes, minority interests, asset
retirement obligation expense and depreciation, depletion and
amortization. Adjusted EBITDA is used by management primarily as
a measure of our segments’ operating performance. Because
Adjusted EBITDA is not calculated identically by all companies,
our calculation may not be comparable to similarly titled
measures of other companies. Adjusted EBITDA is reconciled to
its most comparable measure, under generally accepted accounting
principles, in Note 25 to our consolidated financial
statements.
Year Ended December 31, 2006 Compared to Year Ended
December 31, 2005
| Summary |
Higher average sales prices and increased volumes in the Eastern
U.S., Powder River Basin and Australian mining operations,
including the October 2006 acquisition of three mines in
Australia, contributed to a 13.2% increase in revenues to
$5.26 billion compared to 2005. Segment Adjusted EBITDA
increased 13.8% to $1.23 billion primarily on growth in
international volumes and higher sales prices from our
Australian mining operations and increased results from Trading
and Brokerage operations. Increases in sales volumes and prices
in our U.S. mining operations were partially offset by
operational challenges experienced during the period such as
ongoing shipping constraints from rail performance in the Powder
River Basin and port congestion in Australia; geologic,
equipment and third-party supply issues as well as mine closures
in our Western U.S. mining operations in late 2005. Net
income was $600.7 million in 2006, or $2.23 per
diluted share, an increase of 42.1% over 2005 net income of
$422.7 million, or $1.58 per diluted share.
| Tons Sold |
The following table presents tons sold by operating segment for
the year ended December 31, 2006 and 2005:
| Year Ended | Increase | ||||||||||||||||
| December 31, | (Decrease) | ||||||||||||||||
| 2006 | 2005 | Tons | % | ||||||||||||||
| (Tons in millions) | |||||||||||||||||
|
Western U.S. Mining Operations
|
160.5 | 154.3 | 6.2 | 4.0 | % | ||||||||||||
|
Eastern U.S. Mining Operations
|
54.7 | 52.5 | 2.2 | 4.2 | % | ||||||||||||
|
Australian Mining Operations
|
11.0 | 8.3 | 2.7 | 32.5 | % | ||||||||||||
|
Trading and Brokerage Operations
|
21.4 | 24.8 | (3.4 | ) | (13.7 | )% | |||||||||||
|
Total tons sold
|
247.6 | 239.9 | 7.7 | 3.2 | % | ||||||||||||
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Table of Contents
| Revenues |
The following table presents revenues for the year ended
December 31, 2006 and 2005:
| Increase to | |||||||||||||||||
| Year Ended December 31, | Revenues | ||||||||||||||||
| 2006 | 2005 | $ | % | ||||||||||||||
| (Dollars in thousands) | |||||||||||||||||
|
Sales
|
$ | 5,144,925 | $ | 4,545,323 | $ | 599,602 | 13.2 | % | |||||||||
|
Other revenues
|
111,390 | 99,130 | 12,260 | 12.4 | % | ||||||||||||
|
Total revenues
|
$ | 5,256,315 | $ | 4,644,453 | $ | 611,862 | 13.2 | % | |||||||||
In 2006, our total revenues were $5.26 billion, an increase
of $611.9 million, or 13.2%, compared to prior year, which
resulted from sales price increases in all regions, particularly
in our Eastern and Australian operations and demand-driven sales
volume increases in the Powder River Basin, Midwest and
Australian operations. Volumes related to the October 2006 Excel
acquisition accounted for 2.1 million tons of the increase
to tons sold and approximately 43% of the increase to sales in
Australia. Partially offsetting sales price increases were lower
regional sales due to late 2005 mine closures in the Western
U.S. Mining operations and lower brokerage volumes.
Sales increased $599.6 million, or 13.2%, to
$5.14 billion in 2006, which included increases of
$91.9 million in Western U.S. Mining sales,
$318.1 million in Eastern U.S. Mining sales and
$245.1 million in Australian Mining sales, partially offset
by a decrease of $55.5 million in our brokerage operations.
Overall, prices and volumes in our Western U.S. Mining
operations increased, mainly reflecting increases to sales
prices of over $0.70 per ton and volumes of
12.7 million tons in the Powder River Basin. These
increases at our Powder River Basin operations resulted from
strong demand for the mines’ low-sulfur products and
improved rail conditions compared to 2005, when the region was
dealing with major railroad maintenance. Despite rail
performance improvements relative to 2005, constrained rail
capacity continued to limit growth in the region in 2006.
Offsetting this increase was lower production due to the
cessation of mining operations at our Seneca and Black Mesa
mines in late 2005 and unfavorable geologic conditions and
equipment issues at our Twentymile Mine. On average, per ton
sales prices in our Eastern U.S. Mining operations
increased, driven by increases in metallurgical and steam coal
prices. Sales volumes increased due to a newly developed mine,
which began operation in late 2005, and the expansion of several
existing mines, partially offset by lower production at one of
our mines and at contract miner operations, as both managed
geologic, equipment and, in certain locations, supplier issues.
Sales from our Australian Mining operations were
$245.1 million, or 41.0%, higher than in 2005, primarily
due to higher international metallurgical coal prices, higher
production at our underground mine following installation of a
new longwall in the second quarter of 2006 and additional
volumes from our newly acquired mines ($105.1 million). A
higher per ton sales price reflected higher contract prices in
2006 for metallurgical coal as well as the slower realization of
metallurgical coal price increases in 2005 when we operated
under some lower priced carry-over contracts from 2004 through
most of the first nine months of 2005. Brokerage
operations’ sales decreased $55.5 million in 2006
compared to prior year due to lower sales volumes, partially
offset by higher sales prices.
Other revenues increased $12.3 million, or 12.4%, compared
to prior year. The increase includes proceeds of
$28.2 million from settlement of commitments by a
third-party coal producer following a brokerage contract
restructuring. Offsetting this increase were lower revenues
related to synthetic fuel facilities as customers idled their
synthetic fuel plants due to high crude oil prices.
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Table of Contents
| Segment Adjusted EBITDA |
Our total segment Adjusted EBITDA was $1.23 billion for the
year ended 2006, compared with $1.08 billion in the prior
year. Details were as follows:
| Increase to Segment | |||||||||||||||||
| Year Ended December 31, | Adjusted EBITDA | ||||||||||||||||
| 2006 | 2005 | $ | % | ||||||||||||||
| (Dollars in thousands) | |||||||||||||||||
|
Western U.S. Mining Operations
|
$ | 473,074 | $ | 459,039 | $ | 14,035 | 3.1 | % | |||||||||
|
Eastern U.S. Mining Operations
|
384,107 | 374,628 | 9,479 | 2.5 | % | ||||||||||||
|
Australian Mining Operations
|
278,411 | 202,582 | 75,829 | 37.4 | % | ||||||||||||
|
Trading and Brokerage Operations
|
92,604 | 43,058 | 49,546 | 115.1 | % | ||||||||||||
|
Total Segment Adjusted EBITDA
|
$ | 1,228,196 | $ | 1,079,307 | $ | 148,889 | 13.8 | % | |||||||||
Adjusted EBITDA from our Western U.S. Mining operations
increased $14.0 million, or 3.1%, during 2006 primarily
reflecting an increase in sales volumes of 12.7 million
tons at our Powder River Basin operations, which resulted from
continued strong demand and improved rail performance relative
to 2005. Western U.S. Mining operations sales price per ton
increased moderately due to mix changes resulting from ceasing
operations at our Black Mesa and Seneca mines. Western
U.S. Mining operations cost increases were driven by higher
fuel costs, an increase in revenue-based royalties and
production taxes, and the timing of major repairs. In addition,
we experienced unfavorable geologic conditions and equipment
issues related to the new longwall system at our Twentymile
Mine; however, a recovery of certain costs associated with the
equipment difficulties lessened the impact of these issues on
our 2006 results. The Western U.S. Mining operations were
also negatively impacted by the cessation of operations at the
Black Mesa mine in late 2005.
Eastern U.S. Mining operations’ Adjusted EBITDA
increased $9.5 million, or 2.5%, compared to prior year
primarily due to higher sales volumes partially offset by a
decrease in margin per ton. Results improved compared to prior
year as benefits of higher volumes, product mix and sales prices
were partially offset by higher costs. The Eastern
U.S. Mining operations experienced higher costs per ton due
to fuel costs, revenue-based royalties and production taxes as
well as higher costs associated with equipment, geologic and
contract miner issues. The 2006 results were also negatively
impacted by lower revenues from synthetic fuel facilities of
$10.1 million as customers idled their synthetic fuel
plants. Also impacting Eastern U.S. Mining results was
$8.9 million of income from a settlement related to
customer billings regarding coal quality.
Our Australian Mining operations’ Adjusted EBITDA increased
$75.8 million, or 37.4%, compared to prior year primarily
due to increased sales volumes following increased production
from the second quarter installation of a new longwall system at
our underground mine, higher metallurgical coal sales prices,
and a $19.7 million contribution from our newly acquired
mines.
Trading and Brokerage operations’ Adjusted EBITDA increased
$49.5 million from the prior year, as 2006 results included
proceeds from restructuring the brokerage contract mentioned
above, improved brokerage margins and contribution from the
newly established international operation, partially offset by
lower domestic trading results.
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Table of Contents
| Income Before Income Taxes and Minority Interests |
The following table presents income before income taxes and
minority interests for the years ended December 31, 2006
and 2005:
| Increase (Decrease) | |||||||||||||||||
| Year Ended December 31, | to Income | ||||||||||||||||
| 2006 | 2005 | $ | % | ||||||||||||||
| (Dollars in thousands) | |||||||||||||||||
|
Total Segment Adjusted EBITDA
|
$ | 1,228,196 | $ | 1,079,307 | $ | 148,889 | 13.8 | % | |||||||||
|
Corporate and Other Adjusted EBITDA
|
(147,792 | ) | (208,909 | ) | 61,117 | 29.3 | % | ||||||||||
|
Depreciation, depletion and amortization
|
(377,210 | ) | (316,114 | ) | (61,096 | ) | (19.3 | )% | |||||||||
|
Asset retirement obligation expense
|
(40,112 | ) | (35,901 | ) | (4,211 | ) | (11.7 | )% | |||||||||
|
Interest expense and early debt extinguishment costs
|
(144,846 | ) | (102,939 | ) | (41,907 | ) | (40.7 | )% | |||||||||
|
Interest income
|
12,726 | 10,641 | 2,085 | 19.6 | % | ||||||||||||
|
Income before income taxes and minority interests
|
$ | 530,962 | $ | 426,085 | $ | 104,877 | 24.6 | % | |||||||||
Income before income taxes and minority interests of
$531.0 million for 2006 is $104.9 million, or 24.6%,
higher than 2005 primarily due to improved segment Adjusted
EBITDA as discussed above.
Corporate and Other Adjusted EBITDA results include selling and
administrative expenses, equity income from our joint ventures,
net gains on asset disposals or exchanges, costs associated with
past mining obligations and revenues and expenses related to our
other commercial activities such as coalbed methane, generation
development, Btu conversion and resource management. The
$61.1 million improvement in Corporate and Other Adjusted
EBITDA (net expense) in 2006 compared to 2005 includes the
following:
| • | Higher gains on asset disposals and exchanges of $30.7 million. The 2006 activity included sales with a combined gain of $66.3 million from the sale of non-strategic coal reserves and surface lands located in Kentucky and West Virginia, a $39.2 million gain on an exchange with the Bureau of Land Management of approximately 63 million tons of leased coal reserves at our Caballo mining operation for approximately 46 million tons of coal reserves contiguous with our North Antelope Rochelle mining operation and other gains on asset disposals totaling $26.7 million. In comparison, activity in 2005 included a $37.4 million gain on exchange of coal reserves as part of a dispute settlement with a third-party supplier, a $31.1 million gain from sale of our remaining 0.838 million units of Penn Virginia Resource Partners, L.P., a $12.5 million gain from the sale of non-strategic coal reserves and properties, a $6.2 million gain on an asset exchange from which we received Illinois Basin coal and other gains on asset disposals of $14.3 million; | |
| • | Lower selling and administrative expenses of $13.9 million primarily associated with lower performance-based incentive costs, partially offset by increases to share-based compensation expense as a result of the new requirement to expense stock options, costs to support corporate and international growth initiatives and costs for the development and installation of a new enterprise resource planning system. The lower costs associated with the performance-based incentive plan related to a long-term, executive incentive plan that is driven by shareholder return and reflected lower stock price appreciation in 2006 than in the prior year; | |
| • | Higher equity income of $8.0 million from our 25.5% interest in Carbones del Guasare, which owns and operates the Paso Diablo Mine in Venezuela; and | |
| • | Lower net expenses of $4.7 million related to the development of the Prairie State Energy Campus due to a higher rate of cost reimbursement from the partners in 2006. |
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Depreciation, depletion and amortization increased
$61.1 million in 2006 due to higher production volume,
acquisitions and the impact of escalating costs and new capital,
including two new longwall installations and new mine
development. Also, 2005 depreciation, depletion and amortization
was net of amortization of acquired contract liabilities.
Interest expense and early debt extinguishment costs increased
$41.9 million primarily due to approximately
$1.7 billion in new debt issuances in the second half of
2006 to finance the Excel acquisition. See Liquidity and Capital
Resources for more details of the debt issued.
| Net Income |
The following table presents net income for the year ended
December 31, 2006 and 2005:
| Increase (Decrease) | |||||||||||||||||
| Year Ended December 31, | to Income | ||||||||||||||||
| 2006 | 2005 | $ | % | ||||||||||||||
| (Dollars in thousands) | |||||||||||||||||
|
Income before income taxes and minority interests
|
$ | 530,962 | $ | 426,085 | $ | 104,877 | 24.6 | % | |||||||||
|
Income tax benefit (provision)
|
81,515 | (960 | ) | 82,475 | n/a | ||||||||||||
|
Minority interests
|
(11,780 | ) | (2,472 | ) | (9,308 | ) | (376.5 | )% | |||||||||
|
Net income
|
$ | 600,697 | $ | 422,653 | $ | 178,044 | 42.1 | % | |||||||||
Net income increased $178.0 million in 2006 compared to
prior year due to the increase in income before income taxes and
minority interests discussed above and an income tax benefit
compared to an income tax provision in 2005. The income tax
benefit for the year ended 2006 related primarily to a reduction
in tax reserves no longer required due to the finalization of
various federal and state returns and expiration of applicable
statute of limitations, and a reduction in a portion of the
valuation allowance related to net operating loss
(“NOL”) carry-forwards. The reduction to the valuation
allowance resulted from an increase to estimated future taxable
income primarily resulting from long-term contracts signed in
late 2006 which increased our ability to realize these benefits
in the future. Minority interests increased primarily as a
result of acquiring an additional interest in a joint venture
near the end of the first quarter of 2006.
Year Ended December 31, 2005 Compared to Year Ended
December 31, 2004
| Summary |
Our 2005 revenues of $4.64 billion increased 27.9% over the
prior year. Revenues were driven higher by improved pricing in
all of our mining operations and increased sales volume with
239.9 million tons sold compared to 227.2 million tons
in 2004. Segment Adjusted EBITDA of $1.08 billion was a
39.5% increase over the prior year due to increases in sales
volumes and prices at our U.S. and Australian Mining Operations.
Results in our Western U.S. Mining Operations segment
include amounts for our April 15, 2004, acquisition of the
Twentymile Mine in Colorado. Results in our Australian Mining
Operations segment include amounts for our April 15, 2004,
acquisition of the Burton and North Goonyella Mines as well as
the opening of the Eaglefield Mine adjacent to the North
Goonyella Mine in the fourth quarter of 2004. Our Corporate and
Other segment includes results from our December 2004
acquisition of a 25.5% interest in Carbones del Guasare, which
owns and operates the Paso Diablo Mine in Venezuela. In
addition, higher gains on property transactions contributed to
higher year over year results. Net income was
$422.7 million in 2005, or $1.58 per diluted share, an
increase of 141.0% over 2004 net income of
$175.4 million, or $0.69 per diluted share.
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| Tons Sold |
The following table presents tons sold by operating segment for
the years ended December 31, 2005 and 2004:
| Year Ended | Increase | ||||||||||||||||
| December 31, | (Decrease) | ||||||||||||||||
| 2005 | 2004 | Tons | % | ||||||||||||||
| (Tons in millions) | |||||||||||||||||
|
Western U.S. Mining Operations
|
154.3 | 142.2 | 12.1 | 8.5 | % | ||||||||||||
|
Eastern U.S. Mining Operations
|
52.5 | 51.7 | 0.8 | 1.5 | % | ||||||||||||
|
Australian Mining Operations
|
8.3 | 6.1 | 2.2 | 36.1 | % | ||||||||||||
|
Trading and Brokerage Operations
|
24.8 | 27.2 | (2.4 | ) | (8.8 | )% | |||||||||||
|
Total tons sold
|
239.9 | 227.2 | 12.7 | 5.6 | % | ||||||||||||
| Revenues |
The table below presents revenues for the years ended
December 31, 2005 and 2004:
| Year Ended December 31, | Increase to Revenues | ||||||||||||||||
| 2005 | 2004 | $ | % | ||||||||||||||
| (Dollars in thousands) | |||||||||||||||||
|
Sales
|
$ | 4,545,323 | $ | 3,545,027 | $ | 1,000,296 | 28.2 | % | |||||||||
|
Other revenues
|
99,130 | 86,555 | 12,575 | 14.5 | % | ||||||||||||
|
Total revenues
|
$ | 4,644,453 | $ | 3,631,582 | $ | 1,012,871 | 27.9 | % | |||||||||
Our revenues increased by $1.01 billion, or 27.9%, to
$4.64 billion compared to prior year. The three mines we
acquired in the second quarter of 2004 contributed
$365.2 million of revenue growth due to the additional
105 days of operations in 2005 compared to the prior year.
The remaining $647.7 million of revenue growth was driven
by higher sales prices and volumes across all mining segments
and improved volumes in our brokerage operations.
Sales increased 28.2% to $4.55 billion in 2005, reflecting
increases in every operating segment. Western U.S. Mining
sales increased $222.2 million, Eastern U.S. Mining
sales were $224.0 million higher, sales in Australia Mining
improved $328.0 million and sales from our brokerage
operations increased $226.0 million. Sales in every segment
increased on improved pricing, and volumes were higher in every
segment other than Trading and Brokerage. Our average sales
price per ton increased 17.4% during 2005 due to increased
demand for all of our coal products, which drove pricing higher,
particularly in the regions where we produce metallurgical coal.
Prices for metallurgical coal and our ultra-low sulfur Powder
River Basin coal have been the subject of increasing demand. We
sell metallurgical coal from our Eastern U.S. and Australian
Mining operations. We sell ultra-low sulfur Powder River Basin
coal from our Western U.S. Mining operations. The sales mix
also improved due to an increase in sales from our Australian
Mining segment, where per ton prices are higher than in domestic
markets due primarily to a higher proportion of metallurgical
coal production in the Australian segment sales mix.
The increase in Eastern U.S. Mining operations sales was
primarily due to improved pricing for both steam and
metallurgical coal from the region. On average, prices in our
Eastern U.S. Mining operations increased 14.1% to
$33.10 per ton. Sales increased in our Western
U.S. Mining operations due to higher demand-driven volumes
and prices, particularly in the Powder River Basin. Overall,
prices in our Western U.S. Mining operations increased 6.6%
to $10.45 per ton. Powder River Basin production and sales
volumes were up as a result of increasingly strong demand for
the mines’ low-sulfur product, which continues to expand
its market area geographically. Powder River Basin operations
were able to ship record volumes during 2005 by overcoming train
derailments, weather and track maintenance disruptions on the
main shipping line out of the basin. Our Twentymile Mine,
acquired in April of 2004, contributed to higher sales in 2005
due to an additional four months of ownership, higher prices and
increased mine
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productivity. Sales from our Australian Mining operations were
$328.0 million, or 122.1%, higher than in 2004. The
increase in Australian sales was due primarily to a 63.3%
increase in per ton sales prices largely due to higher
international metallurgical coal prices, an increase in volumes
which included the opening of our Eaglefield surface mine at the
end of 2004, and $197.6 million of incremental sales from
the two mines we acquired in April 2004 due to 105 additional
days of operations in 2005 compared to 2004. Our Trading and
Brokerage operations sales increased $226.0 million in 2005
compared to prior year due to an increase in average per ton
prices and higher eastern U.S. and international brokerage
volumes.
Other revenues increased $12.6 million, or 14.5%, compared
to prior year primarily due to proceeds from a purchase contract
restructuring and higher synthetic fuel revenues in the Midwest.
| Segment Adjusted EBITDA |
Our total segment Adjusted EBITDA of $1.08 billion for 2005
was $305.5 million higher than 2004 segment Adjusted EBITDA
of $773.8 million, and was composed of the following:
| Increase to Segment | |||||||||||||||||
| Year Ended December 31, | Adjusted EBITDA | ||||||||||||||||
| 2005 | 2004 | $ | % | ||||||||||||||
| (Dollars in thousands) | |||||||||||||||||
|
Western U.S. Mining Operations
|
$ | 459,039 | $ | 402,052 | $ | 56,987 | 14.2 | % | |||||||||
|
Eastern U.S. Mining Operations
|
374,628 | 280,357 | 94,271 | 33.6 | % | ||||||||||||
|
Australian Mining Operations
|
202,582 | 50,372 | 152,210 | 302.2 | % | ||||||||||||
|
Trading and Brokerage Operations
|
43,058 | 41,039 | 2,019 | 4.9 | % | ||||||||||||
|
Total Segment Adjusted EBITDA
|
$ | 1,079,307 | $ | 773,820 | $ | 305,487 | 39.5 | % | |||||||||
Adjusted EBITDA from our Western U.S. Mining operations
increased $57.0 million during 2005 due to a margin per ton
increase of $0.15, or 5.3%, and a sales volume increase of
12.1 million tons. Results in the Powder River Basin
operations contributed to the increase in Western
U.S. Mining operations as it earned 12.3% higher per ton
margins while increasing volumes 8.5% in response to greater
demand for our low-sulfur products. Improved revenues overcame
increased unit costs that resulted from higher fuel and
explosives costs, lower than anticipated volume due to rail
difficulties and an increase in revenue-based royalties and
production taxes. The Twentymile Mine, acquired in April of
2004, contributed $25.4 million more to Adjusted EBITDA in
2005 than in 2004, due to four months of incremental ownership
and a 22.2% increase in per ton margin.
Eastern U.S. Mining operations’ Adjusted EBITDA
increased $94.3 million, or 33.6%, compared to prior year
primarily due to an increase in margin per ton of $1.71, or
31.5%. Our Eastern U.S. Mining operations’ Adjusted
EBITDA increased as a result of sales price increases, partially
offset by lower production at two of our mines and higher costs
related to geologic issues, contract mining, fuel, repair and
maintenance and the impact of heavy rainfall on surface
operations early in the year.
Our Australian Mining operations’ Adjusted EBITDA increased
$152.2 million in the current year, a 302.2% increase
compared to prior year due to an increase of $16.23, or 197.4%,
in margin per ton and 2.2 million additional tons shipped.
Our Australian operations produce mostly (75% to 85%) high
margin metallurgical coal. The two mines we acquired in April
2004 added $87.4 million to Adjusted EBITDA compared to
eight months of ownership in 2004. The remaining increase of
$64.8 million was primarily due to an increase in volume,
including tonnage from our surface operation opened at the end
of the prior year, and an increase of 63.3% in average per ton
sale price. While current year margins benefited from strong
sales prices, margin growth was limited by the impact of port
congestion, related demurrage costs and higher costs due to
geological problems at the underground mine.
Trading and Brokerage operations’ Adjusted EBITDA increased
$2.0 million from the prior year primarily due to higher
brokerage results. Results in 2005 included a net charge of
$4.0 million, primarily related to the breach of a coal
supply contract by a producer.
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| Reconciliation of Segment Adjusted EBITDA to Income Before Income Taxes and Minority Interests |
| Increase (Decrease) | |||||||||||||||||
| Year Ended December 31, | to Income | ||||||||||||||||
| 2005 | 2004 | $ | % | ||||||||||||||
| (Dollars in thousands) | |||||||||||||||||
|
Total Segment Adjusted EBITDA
|
$ | 1,079,307 | $ | 773,820 | $ | 305,487 | 39.5 | % | |||||||||
|
Corporate and Other Adjusted EBITDA
|
(208,909 | ) | (214,576 | ) | 5,667 | 2.6 | % | ||||||||||
|
Depreciation, depletion and amortization
|
(316,114 | ) | (270,159 | ) | (45,955 | ) | (17.0 | )% | |||||||||
|
Asset retirement obligation expense
|
(35,901 | ) | (42,387 | ) | 6,486 | 15.3 | % | ||||||||||
|
Interest expense and early debt extinguishment costs
|
(102,939 | ) | (98,544 | ) | (4,395 | ) | (4.5 | )% | |||||||||
|
Interest income
|
10,641 | 4,917 | 5,724 | 116.4 | % | ||||||||||||
|
Income before income taxes and minority interests
|
$ | 426,085 | $ | 153,071 | $ | 273,014 | 178.4 | % | |||||||||
Income before income taxes and minority interest of
$426.1 million for the current year is $273.0 million,
or 178.4%, higher than prior year primarily due to improved
segment Adjusted EBITDA as discussed above. Increases in
depreciation, depletion and amortization expense and interest
expense offset improvements in Corporate and Other Adjusted
EBITDA, asset retirement obligation expense, debt extinguishment
costs and interest income.
Corporate and Other Adjusted EBITDA results include selling and
administrative expenses, equity income from our Venezuelan joint
venture, net gains on asset disposals or exchanges, costs
associated with past mining obligations and revenues and
expenses related to our other commercial activities such as
coalbed methane, generation development and resource management.
The $5.7 million improvement in Corporate and Other
Adjusted EBITDA (net expense) in 2005 compared to 2004 included:
| • | net gains on asset sales that were $77.7 million higher than prior year primarily due to a $37.4 million gain from a property exchange related to settlement of a contract dispute with a third-party coal supplier (see Note 3 to our consolidated financial statements), sales of Penn Virginia Resource Partners, L.P. (“PVR”) units ($31.1 million) (see Note 9 to our consolidated financial statements), resource sales involving non-strategic coal assets and properties ($12.5 million), and an asset exchange in which we acquired Illinois Basin coal reserves ($6.2 million). The gain from PVR unit sales in 2005 was from the sale of all of our remaining 0.838 million units compared to a gain of $15.8 million on the sale of 0.775 million units in two separate transactions during 2004. All other gains on asset disposals in 2005 and 2004 were $14.3 million and $8.0 million, respectively; | |
| • | higher equity income of $18.7 million from our 25.5% interest in Carbones del Guasare (acquired in December 2004), which owns and operates the Paso Diablo Mine in Venezuela, and; | |
| • | lower net expenses related to generation development of $5.1 million, primarily due to reimbursements from the Prairie State Energy Campus partnership group. |
These improvements were partially offset by:
| • | a $36.0 million increase in past mining obligations expense, primarily related to higher retiree health care costs. The increase in retiree health care costs was actuarially driven by higher trend rates, and lower interest discount assumptions and higher amortization of actuarial losses in 2005, and; | |
| • | an increase of $46.8 million in selling and administrative expenses primarily related to accruals for higher short-term and long-term performance-based incentive plans ($32.2 million). These incentives are principally long-term plans that are driven by total shareholder returns. Our share price increased 104% during 2005, significantly outperforming industrial benchmarks and our coal |
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| peer group average. The remaining increase in selling and administrative expenses was due to higher personnel and outside services costs needed to advance our growth initiatives in areas such as China and BTU conversion, acquisitions and regulatory costs (e.g. Sarbanes-Oxley), and an increase in advertising costs related to an industry awareness campaign launched in late 2005. |
Depreciation, depletion and amortization increased
$46.0 million during 2005. Approximately 56% of the
increase was due to acquisitions completed during 2004 and the
remainder was from increased volumes at existing mines and
operations opened during 2005. Asset retirement obligation
expense decreased $6.5 million in 2005 due to additional
expenses incurred in 2004 to accelerate the planned reclamation
of certain closed mine sites. Interest expense increased
$6.1 million primarily related to a full year of interest
in 2005 on $250 million of 5.875% Senior Notes issued
in late March of 2004 and increases in the cost of floating rate
debt due to higher interest rates. Interest income improved
$5.7 million due to higher yields on short-term interest
rates and an increase in invested balances due to improved cash
flows during 2005.
| Net Income |
| Increase (Decrease) | |||||||||||||||||
| Year Ended December 31, | to Income | ||||||||||||||||
| 2005 | 2004 | $ | % | ||||||||||||||
| (Dollars in thousands) | |||||||||||||||||
|
Income before income taxes and minority interests
|
$ | 426,085 | $ | 153,071 | $ | 273,014 | 178.4% | ||||||||||
|
Income tax benefit (provision)
|
(960 | ) | 26,437 | (27,397 | ) | (103.6 | )% | ||||||||||
|
Minority interests
|
(2,472 | ) | (1,282 | ) | (1,190 | ) | (92.8 | )% | |||||||||
|
Income from continuing operations
|
422,653 | 178,226 | 244,427 | (137.1 | )% | ||||||||||||
|
Loss from discontinued operations
|
— | (2,839 | ) | 2,839 | n/a | ||||||||||||
|
Net income
|
$ | 422,653 | $ | 175,387 | $ | 247,266 | 141.0% | ||||||||||
Net income increased $247.3 million, or 141.0%, compared to
the prior year due to the increase in income before income taxes
and minority interests discussed above, partially offset by
increases in our income tax provision. The income tax benefit in
2004 included a $25.9 million reduction in the valuation
allowance on net operating loss carry-forwards and alternative
minimum tax credits. The income tax provision in 2005 was higher
based on the increase in pretax income which was partially
offset by the higher permanent benefit of percentage depletion
and the partial benefit of tax loss from a deemed liquidation of
a subsidiary arising as an indirect consequence of a
comprehensive and strategic internal restructuring we completed
during 2005. This restructuring resulted from efforts to better
align corporate ownership of subsidiaries on a geographic and
functional basis.
Outlook
| Events Impacting Near-Term Operations |
In October 2006, we acquired Excel Coal Limited, which included
three operating mines, two late development-stage mines and a
development-stage mine. These development-stage mines are
expected to begin shipments in 2007, and our 2007 results will
be impacted to the extent we complete ramp up activities at
these development-stage mines on time and at expected capacity.
Furthermore, our two primary Australian shipping points,
Dalrymple Bay Coal Terminal and Port of Newcastle, are
experiencing significant queues of vessels, which could result
in delayed shipments and demurrage charges.
Currently depressed Central Appalachian coal prices combined
with escalating costs of our third-party contractors could
adversely impact our saleable production as it becomes
uneconomic to mine.
Although we expect that the Twentymile longwall system will
allow for expanded capacity over the next several years, we
continue to manage equipment and lower coal quality issues at
our Twentymile mine.
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Shipments from our Powder River Basin mines improved in 2006,
but were still impacted by rail service disruptions. Rail
carriers are expected to continue improvements in 2007. Although
we currently expect to increase our shipment levels from our
Powder River Basin operations in 2007 compared with 2006, our
ability to reach these targeted shipment levels is dependent
upon the performance of the rail carriers.
Our union workforce east of the Mississippi River is primarily
represented by the UMWA. The UMWA-represented workers at one of
our eastern mines operate under a contract that expires on
December 31, 2007. The remainder of our UMWA-represented
workers in the east operate under a recently signed, five-year
labor agreement expiring December 31, 2011. The new
contract mirrors the 2007 National Bituminous Coal Wage
Agreement and stipulates a $1.50 per hour increase to wages
effective January 1, 2007 and a total wage increase of
$4.00 per hour over the life of the agreement. The contract
also calls for a $1,000 bonus for each of our UMWA-represented
employees.
| Long-Term Outlook |
Our outlook for the coal markets remains positive. We believe
strong coal markets will continue worldwide, as long as growth
continues in the U.S., Asia and other industrialized economies
that are increasing coal demand for electricity generation and
steelmaking. Approximately 115 gigawatts of new coal-fueled
electricity generating capacity is scheduled to come on line
around the world over the next three years, and the EIA projects
an additional 156 gigawatts of new U.S. coal-fueled
generation by 2030, which by itself represents more than
500 million tons of additional coal demand.
Global coal markets continued to grow, driven by increased
demand from growing economies. The U.S. economy grew at an
annual rate of 3.5% based on fourth quarter 2006 data as
reported by the U.S. Commerce Department, while
China’s economy grew 10.7% in 2006 as published by the
National Bureau of Statistics of China. Metallurgical coal
continued to sell at a significant premium to steam coal.
Metallurgical markets, while off record levels, remain strong as
seaborne metallurgical coal prices for the upcoming fiscal year
were settling from a reference price near $100 per metric
ton and as China steel production shows signs of continued
growth over 2005 levels. We expect to capitalize on the strong
global market for metallurgical coal primarily through
production and sales of metallurgical coal from our Appalachia
and Australian operations. In response to growing international
markets, we established an international trading group in 2006,
and added another operations office in Europe in early 2007.
Coal-to-gas and
coal-to-liquids
(“CTL”) plants represent a significant avenue for
long-term industry growth. The EIA continues to project an
increase in demand for unconventional sources of transportation
fuel, including
coal-to-liquids, and in
the
U.S. coal-to-liquid
technologies are receiving growing bipartisan support as
demonstrated by the newly introduced CTL bills such as the
“Coal-to-Liquid
Fuel Promotion Act” within the Senate. China and India are
developing coal-to-gas
and coal-to-liquids
facilities.
Demand for Powder River Basin coal remains strong, particularly
for our ultra-low sulfur products. The Powder River Basin
represents more than half of our production. We control
approximately 3.5 billion tons of proven and probable
reserves in the Southern Powder River Basin, and we sold
138.4 million tons of coal from this region during 2006, an
increase of 10.1% over the prior year.
We are targeting 2007 production of 240 to 260 million tons
and total sales volume of 265 to 285 tons, including 15 to
18 million tons of metallurgical coal. As of
December 31, 2006, our unpriced 2007 volumes for planned
produced tonnage were 5 to 15 million U.S. tons and
14 million Australia tons. Our total unpriced planned
production for 2008 is approximately 70 to 80 million tons
in the United States and 20 to 22 million tons in Australia.
Management plans to aggressively control costs and operating
performance to mitigate external cost pressures, geologic
conditions and potentially adverse port and rail performance. We
are experiencing increases in operating costs related to fuel,
explosives, steel, tires, contract mining and healthcare, and
have taken measures to mitigate the increases in these costs,
including a company-wide initiative to instill best
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practices at all operations. In addition, historically low
long-term interest rates also have a negative impact on expenses
related to our actuarially determined, employee-related
liabilities. We may also encounter poor geologic conditions,
lower third-party contract miner or brokerage source performance
or unforeseen equipment problems that limit our ability to
produce at forecasted levels. To the extent upward pressure on
costs exceeds our ability to realize sales increases, or if we
experience unanticipated operating or transportation
difficulties, our operating margins would be negatively
impacted. See “Cautionary Notice Regarding Forward-Looking
Statements” and Item 1A. Risk Factors for additional
considerations regarding our outlook.
Critical Accounting Policies and Estimates
Our discussion and analysis of our financial condition, results
of operations, liquidity and capital resources is based upon our
financial statements, which have been prepared in accordance
with accounting principles generally accepted in the United
States. Generally accepted accounting principles require that we
make estimates and judgments that affect the reported amounts of
assets, liabilities, revenues and expenses, and related
disclosure of contingent assets and liabilities. On an on-going
basis, we evaluate our estimates. We base our estimates on
historical experience and on various other assumptions that we
believe are reasonable under the circumstances, the results of
which form the basis for making judgments about the carrying
values of assets and liabilities that are not readily apparent
from other sources. Actual results may differ from these
estimates.
| Employee-Related Liabilities |
We have significant long-term liabilities for our
employees’ postretirement benefit costs, workers’
compensation obligations and defined benefit pension plans.
Detailed information related to these liabilities is included in
Notes 14, 15 and 16 to our consolidated financial
statements. The adoption of SFAS No. 158 on
December 31, 2006 resulted in each of these liabilities
recorded on the consolidated balance sheet as of
December 31, 2006 being equal to the funded status of the
plans. Liabilities for postretirement benefit costs and
workers’ compensation obligations are not funded. Our
pension obligations are funded in accordance with the provisions
of federal law. Expense for the year ended December 31,
2006, for these liabilities totaled $178.7 million, while
payments were $146.2 million.
Each of these liabilities are actuarially determined and we use
various actuarial assumptions, including the discount rate and
future cost trends, to estimate the costs and obligations for
these items. Our discount rate is determined by utilizing a
hypothetical bond portfolio model which approximates the future
cash flows necessary to service our liabilities.
We make assumptions related to future trends for medical care
costs in the estimates of retiree health care and work-related
injuries and illnesses obligations. Our medical trend assumption
is developed by annually examining the historical trend of our
cost per claim data. In addition, we make assumptions related to
future compensation increases and rates of return on plan assets
in the estimates of pension obligations.
If our assumptions do not materialize as expected, actual cash
expenditures and costs that we incur could differ materially
from our current estimates. Moreover, regulatory changes could
increase our obligation to satisfy these or additional
obligations. Our most significant employee liability is
postretirement health care, and assumed discount rates and
health care cost trend rates have a significant effect on the
expense and liability amounts reported for health care plans.
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Below we have provided two separate sensitivity analyses to
demonstrate the significance of these assumptions in relation to
reported amounts.
Health care cost trend rate:
| One-Percentage- | One-Percentage- | |||||||
| Point Increase | Point Decrease | |||||||
| (Dollars in thousands) | ||||||||
|
Effect on total service and interest cost
components(1)
|
$ | 9,501 | $ | (7,989 | ) | |||
|
Effect on total postretirement benefit
obligation(1)
|
$ | 179,264 | $ | (150,765 | ) | |||
Discount rate:
| One-Percentage- | One-Percentage- | |||||||
| Point Increase | Point Decrease | |||||||
| (Dollars in thousands) | ||||||||
|
Effect on total service and interest cost
components(1)
|
$ | 1,064 | $ | (1,496 | ) | |||
|
Effect on total postretirement benefit
obligation(1)
|
$ | (78,243 | ) | $ | 82,702 | |||
| (1) | In addition to the effect on total service and interest cost components of expense, changes in trend and discount rates would also increase or decrease the actuarial gain or loss amortization expense component. The gain or loss amortization would approximate the increase or decrease in the obligation divided by 8.47 years at December 31, 2006. |
| Asset Retirement Obligations |
Our asset retirement obligations primarily consist of spending
estimates for surface land reclamation and support facilities at
both surface and underground mines in accordance with federal
and state reclamation laws as defined by each mining permit.
Asset retirement obligations are determined for each mine using
various estimates and assumptions including, among other items,
estimates of disturbed acreage as determined from engineering
data, estimates of future costs to reclaim the disturbed
acreage, the timing of these cash flows, and a credit-adjusted,
risk-free rate. As changes in estimates occur (such as mine plan
revisions, changes in estimated costs, or changes in timing of
the reclamation activities), the obligation and asset are
revised to reflect the new estimate after applying the
appropriate credit-adjusted, risk-free rate. If our assumptions
do not materialize as expected, actual cash expenditures and
costs that we incur could be materially different than currently
estimated. Moreover, regulatory changes could increase our
obligation to perform reclamation and mine closing activities.
Asset retirement obligation expense for the year ended
December 31, 2006, was $40.1 million, and payments
totaled $36.6 million. See detailed information regarding
our asset retirement obligations in Note 13 to our
consolidated financial statements.
| Income Taxes |
We account for income taxes in accordance with
SFAS No. 109, “Accounting for Income Taxes”
(“SFAS No. 109”), which requires that
deferred tax assets and liabilities be recognized using enacted
tax rates for the effect of temporary differences between the
book and tax basis of recorded assets and liabilities.
SFAS No. 109 also requires that deferred tax assets be
reduced by a valuation allowance if it is more likely than not
that some portion or all of the deferred tax asset will not be
realized. In our annual evaluation of the need for a valuation
allowance, we take into account various factors, including the
expected level of future taxable income and available tax
planning strategies. If actual results differ from the
assumptions made in our annual evaluation of our valuation
allowance, we may record a change in valuation allowance through
income tax expense in the period such determination is made.
We establish reserves for tax contingencies when, despite the
belief that our tax return positions are fully supported,
certain positions are likely to be challenged and may not be
fully sustained. The tax contingency reserves are analyzed on a
quarterly basis and adjusted based upon changes in facts and
circumstances, such as the progress of federal and state audits,
case law and emerging legislation. Our effective tax rate
includes the impact of tax contingency reserves and changes to
the reserves, including
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related interest. We establish the reserves based upon
management’s assessment of exposure associated with
permanent tax differences (i.e. tax depletion expense, etc.) and
certain tax sharing agreements. We are subject to federal audits
for several open years due to our previous inclusion in multiple
consolidated groups and the various parties involved in
finalizing those years. Additional details regarding the effect
of income taxes on our consolidated financial statements is
available in Note 11.
Interpretation No. 48 “Accounting for Uncertainty in
Income Taxes — an interpretation of FASB Statement
No. 109” (“FIN No. 48”) prescribes
a recognition threshold and measurement attribute for the
financial statement recognition and measurement of a tax
position taken or expected to be taken in a tax return.
FIN No. 48 also provides guidance on derecognition,
classification, interest and penalties, accounting in interim
periods, disclosure and transition. This interpretation is
effective for fiscal years beginning after December 15,
2006 (January 1, 2007 for the Company).
| Revenue Recognition |
In general, we recognize revenues when they are realizable and
earned. We generated 98% of our revenue in 2006 from the sale of
coal to our customers. Revenue from coal sales is realized and
earned when risk of loss passes to the customer. Coal sales are
made to our customers under the terms of coal supply agreements,
most of which are long-term (greater than one year). Under the
typical terms of these coal supply agreements, title and risk of
loss transfer to the customer at the mine or port, where coal is
loaded to the rail, barge, ocean-going vessel, truck or other
transportation source(s) that delivers coal to its destination.
With respect to other revenues, other operating income, or gains
on asset sales recognized in situations unrelated to the
shipment of coal, we carefully review the facts and
circumstances of each transaction and apply the relevant
accounting literature as appropriate, and do not recognize
revenue until the following criteria are met: persuasive
evidence of an arrangement exists; delivery has occurred or
services have been rendered; the seller’s price to the
buyer is fixed or determinable; and collectibility is reasonably
assured.
| Trading Activities |
We engage in the buying and selling of coal in
over-the-counter
markets. Our coal trading contracts are accounted for on a fair
value basis under SFAS No. 133, “Accounting for
Derivative Instruments and Hedging Activities.” To
establish fair values for our trading contracts, we use bid/ask
price quotations obtained from multiple, independent third-party
brokers to value coal and emission allowance positions. Prices
from these sources are then averaged to obtain trading position
values. We could experience difficulty in valuing our market
positions if the number of third-party brokers should decrease
or market liquidity is reduced.
All of the contracts in our trading portfolio as of
December 31, 2006 were valued utilizing prices from
over-the-counter market
sources, adjusted for coal quality and traded transportation
differentials. As of December 31, 2006, 41% of the
estimated future value of our trading portfolio was scheduled to
be realized by the end of 2007 and 80% within 24 months.
See Note 5 to our consolidated financial statements for
additional details regarding assets and liabilities from our
coal trading activities.
Liquidity and Capital Resources
Our primary sources of cash include sales of our coal production
to customers, cash generated from our trading and brokerage
activities, sales of non-core assets and financing transactions,
including the sale of our accounts receivable (through our
securitization program). Our primary uses of cash include our
cash costs of coal production, capital expenditures, interest
costs and costs related to past mining obligations as well as
planned acquisitions. Our ability to pay dividends, service our
debt (interest and principal) and acquire new productive assets
or businesses is dependent upon our ability to continue to
generate cash from the primary sources noted above in excess of
the primary uses. Future dividends,
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among other things, are subject to limitations imposed by our
Senior Notes and Debenture covenants. We expect to fund all of
our capital expenditure requirements with cash generated from
operations.
Net cash provided by operating activities was
$595.7 million for the year ended December 31, 2006, a
decrease of $107.1 million compared to $702.8 million
provided by operating activities in the prior year. The decrease
was primarily related to the timing of working capital needs.
The decrease in cash from operating activities would have been
$30.4 million lower had 2006 and 2005 operating cash flows
been shown on a comparable basis. The 2006 operating cash flows
include a required reclassification of the excess tax benefit
related to stock option exercises ($33.2 million) from
operating to financing activities.
Net cash used in investing activities was $2.14 billion for
the year ended December 31, 2006 compared to
$584.2 million used in the prior year. The increase
reflects the acquisition of Excel for $1.51 billion, net of
cash acquired, higher capital expenditures of
$93.4 million, higher federal coal lease expenditures of
$59.8 million, the acquisition of an additional interest in
a joint venture for $44.5 million, and the receipt of notes
in lieu of payments on asset sales of $45.6 million,
partially offset by higher proceeds from asset disposals of
$46.9 million in 2006 and the purchase of mining and
related assets of $141.2 million in 2005. Capital
expenditures included longwall equipment and mine development at
our Australian mines (including our recently acquired Excel
operations), the opening of new mines and the purchase of
equipment for expansion. The $141.2 million purchase of
mining and related assets in 2005 included 70 million tons
of Illinois and Indiana coal reserves, surface properties and
equipment from Lexington Coal Company ($56.5 million) and
rail, loadout and surface facilities as well as other mining
assets for $84.7 million from another major coal producer.
Net cash provided by financing activities was $1.37 billion
during the year ended December 31, 2006, compared to a use
of $4.9 million in 2005. In 2006, we issued net borrowings
of $1.74 billion, which were utilized to fund the
$1.51 billion Excel acquisition, the repayment of
Excel’s bank facility and a portion of its outstanding
bonds, and other corporate purposes. See the detailed discussion
of our Senior Unsecured Credit Facility, Convertible Junior
Subordinated Debentures, Senior Notes offerings and borrowings
under our Senior Unsecured Credit Facility below. In addition to
the net issuance of debt related to the Excel acquisition, we
repaid $23.8 million of debt held by a majority-owned joint
venture, purchased $7.7 million of our 5.875% Senior
Notes in the open market, and made scheduled debt repayments of
$11.1 million on our 5% Subordinated Note and other
notes payable.
The 2006 activity compared to 2005 also reflected payments for
common stock repurchases of $99.8 million, debt issuance
costs of $40.6 million and higher dividends of
$18.9 million. During the year ended December 31,
2006, we repurchased 2.2 million of our common shares at a
cost of $99.8 million under our share repurchase program as
authorized by the Board of Directors. The 2006 activity included
a decrease in the usage of our accounts receivable
securitization program of $5.8 million compared to an
increase of $25.0 million in 2005. The 2006 activity
compared to 2005 also reflected $7.0 million lower proceeds
from the exercise of stock options as well as a
$33.2 million tax benefit related to stock option exercises
included in financing activity based on the newly adopted
accounting standard for share-based compensation (see
“Newly Adopted Accounting Pronouncements” below for
more discussion about the adoption of this standard). In 2005,
the tax benefit related to stock option exercises (totaling
$30.4 million) was included in operating activities.
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Our total indebtedness as of December 31, 2006 and 2005
consisted of the following:
| December 31, | |||||||||
| 2006 | 2005 | ||||||||
| (Dollars in thousands) | |||||||||
|
Term Loan under Senior Unsecured Credit Facility
|
$ | 547,000 | $ | — | |||||
|
Term Loan under Senior Secured Credit Facility
|
— | 442,500 | |||||||
|
Convertible Junior Subordinated Debentures due 2066
|
732,500 | — | |||||||
|
7.375% Senior Notes due 2016
|
650,000 | — | |||||||
|
6.875% Senior Notes due 2013
|
650,000 | 650,000 | |||||||
|
7.875% Senior Notes due 2026
|
246,897 | — | |||||||
|
5.875% Senior Notes due 2016
|
231,845 | 239,525 | |||||||
|
5.0% Subordinated Note
|
59,504 | 66,693 | |||||||
|
6.84% Series C Bonds due 2016
|
43,000 | — | |||||||
|
6.34% Series B Bonds due 2014
|
21,000 | — | |||||||
|
6.84% Series A Bonds due 2014
|
10,000 | — | |||||||
|
Capital lease obligations
|
56,707 | 1,529 | |||||||
|
Fair value of interest rate swaps
|
(13,784 | ) | (8,879 | ) | |||||
|
Other
|
29,157 | 14,138 | |||||||
|
Total
|
$ | 3,263,826 | $ | 1,405,506 | |||||
| Senior Unsecured Credit Facility |
In September 2006, we entered into a Third Amended and Restated
Credit Agreement, which established a $2.75 billion Senior
Unsecured Credit Facility and which amended and restated in full
our then existing $1.35 billion Senior Secured Credit
Facility. The Senior Unsecured Credit Facility provides a
$1.8 billion Revolving Credit Facility and a
$950.0 million Term Loan Facility. The Revolving
Credit Facility replaced our previous $900.0 million
revolving credit facility and the increased capacity is intended
to accommodate working capital needs, letters of credit, the
funding of capital expenditures and other general corporate
purposes. The Revolving Credit Facility also includes a
$50.0 million sub-facility available for same-day swingline
loan borrowings. In September 2006, we borrowed
$312.0 million under the Revolver in conjunction with the
Excel acquisition and repaid this $312.0 million
outstanding balance in December 2006 with net proceeds from the
Debentures.
The Term Loan Facility consisted of an unsecured
$440.0 million portion, which was drawn at closing to
replace the previous term loan ($437.5 million balance at
time of replacement; $442.5 million at December 31,
2005) issued under the Senior Secured Credit Facility. The Term
Loan Facility also included a Delayed Draw Term Loan
Sub-Facility of up to
$510.0 million, which was fully drawn in October 2006 in
connection with the Excel acquisition. In December 2006,
$403.0 million of the outstanding balance of the Term
Loan Facility ($950.0 million was outstanding at time
of repayment) was repaid with the net proceeds from the
Debentures. In conjunction with the establishment of the Senior
Unsecured Credit Facility, we incurred $8.6 million in
financing costs, of which $5.6 million related to the
Revolving Credit Facility and $3.0 million related to the
Term Loan Facility. These debt issuance costs will be
amortized to interest expense over five years, the term of the
Senior Unsecured Credit Facility.
Loans under the facility are available in U.S. dollars,
with a sub-facility under the Revolving Credit Facility
available in Australian dollars, pounds sterling and Euros.
Letters of credit under the Revolving Credit Facility are
available to us in U.S. dollars with a sub-facility
available in Australian dollars, pounds sterling and Euros. The
interest rate payable on the Revolving Credit Facility and the
Term Loan Facility under the Senior Unsecured Credit
Facility is LIBOR plus 1.0% with step-downs to LIBOR plus 0.50%
based on improvement in the leverage ratio, as defined in the
Third Amended and Restated Credit Agreement. The rate applicable
to the Term Loan Facility was 6.35% at December 31,
2006.
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Under the Senior Unsecured Credit Facility, we must comply with
certain financial covenants on a quarterly basis including a
minimum interest coverage ratio and a maximum leverage ratio, as
defined in the Third Amended and Restated Credit Agreement. The
financial covenants also place limitations on our investments in
joint ventures, unrestricted subsidiaries, indebtedness of
non-loan parties, and the imposition of liens on our assets. The
new facility is less restrictive with respect to limitations on
our dividend payments, capital expenditures, asset sales or
stock repurchases. The Senior Unsecured Credit Facility matures
on September 15, 2011.
As of December 31, 2006, we had no borrowings outstanding
under our Revolving Credit Facility. Our revolving line of
credit was primarily used for standby letters of credit until
September 2006, when we also used the revolving line of credit
to facilitate the Excel acquisition. As discussed above, the
$312.0 million outstanding under the revolving line of
credit was repaid in December 2006 with net proceeds from the
Debentures. The remaining available borrowing capacity
($1.29 billion as of December 31, 2006) will be used
to fund strategic acquisitions or meet other financing needs,
including standby letters of credit. During 2005, we had no
borrowings outstanding under our previous $900.0 million
revolving line of credit, which we used primarily for standby
letters of credit. We were in compliance with all of the
covenants of the Senior Unsecured Credit Facility, the
6.875% Senior Notes, the 5.875% Senior Notes, the
7.375% Senior Notes, the 7.875% Senior Notes, and the
Convertible Junior Subordinated Debentures as of
December 31, 2006.
| Convertible Junior Subordinated Debentures |
On December 20, 2006, we issued $732.5 million
aggregate principal amount of 4.75% Convertible Junior
Subordinated Debentures due 2066 (the “Debentures”),
including $57.5 million issued pursuant to the
underwriters’ exercise of their over-allotment option. Net
proceeds from the offering, after deducting underwriting
discounts and offering expenses, were $715.0 million and
were used to repay indebtedness under our Senior Unsecured
Credit Facility. The Debentures will pay interest semiannually
at a rate of 4.75% per year. We may elect to, and if and to
the extent that a mandatory trigger event (as defined in the
indenture governing the Debentures) has occurred and is
continuing will be required to, defer interest payments on the
Debentures. After five years of deferral at our option, or upon
the occurrence of a mandatory trigger event, we generally must
sell warrants or preferred stock with specified characteristics
and use the funds from that sale to pay deferred interest,
subject to certain limitations. In no event may we defer
payments of interest on the Debentures for more than ten years.
The Debentures are convertible at any time on or prior to
December 15, 2036 if any of the following conditions occur:
(i) our closing common stock price exceeds 140% of the then
applicable conversion price for the Debentures (currently
$86.73 per share) for at least 20 of the final 30 trading
days in any quarter; (ii) a notice of redemption is issued
with respect to the Debentures; (iii) a change of control,
as defined in the indenture governing the Debentures;
(iv) satisfaction of certain trading price conditions; and
(v) other specified corporate transactions described in the
indenture governing the Debentures. In addition, the Debentures
are convertible at any time after December 15, 2036 to
December 15, 2041, the scheduled maturity date. In the case
of conversion following a notice of redemption or upon a
non-stock change of control, as defined in the indenture
governing the Debentures, holders may convert their Debentures
into cash in the amount of the principal amount of their
Debentures and shares of our common stock for any conversion
value in excess of the principal amount. In all other conversion
circumstances, holders will receive perpetual preferred stock
(see Note 17 to our consolidated financial statements) with
a liquidation preference equal to the principal amount of their
Debentures, and any conversion value in excess of the principal
amount will be settled with our common stock. The consideration
delivered upon conversion will be based upon an initial
conversion rate of 16.1421 shares of common stock per
$1,000 principal amount of Debentures, subject to adjustment.
This conversion rate represents an initial conversion price of
approximately $61.95 per share, a 40% premium over the
closing stock price of $44.25 on December 14, 2006, the
date of the pricing of the offering of the Debentures.
The Debentures are unsecured obligations, ranking junior to all
existing and future senior and subordinated debt (excluding
trade accounts payable or accrued liabilities arising in the
ordinary course of
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business) except for any future debt that ranks equal to or
junior to the Debentures. The Debentures will rank equal in
right of payment with our obligations to trade creditors.
Substantially, all of our existing indebtedness is senior to the
Debentures. In addition, the Debentures will be effectively
subordinated to all indebtedness of our subsidiaries. The
indenture governing the Debentures places no limitation on the
amount of additional indebtedness that we or any of our
subsidiaries may incur (see Note 12 of our consolidated
financial statements for additional information on the
Debentures).
| 7.375% Senior Notes Due November 2016 and 7.875% Senior Notes Due November 2026 |
On October 12, 2006, we completed a $650 million
offering of 7.375%
10-year Senior Notes
due 2016 and $250 million of 7.875%
20-year Senior Notes
due 2026. The notes are general unsecured obligations and rank
senior in right of payment to any subordinated indebtedness;
equally in right of payment with any senior indebtedness;
effectively junior in right of payment to our existing and
future secured indebtedness, to the extent of the value of the
collateral securing that indebtedness; and effectively junior to
all the indebtedness and other liabilities of our subsidiaries
that do not guarantee the notes. Interest payments are scheduled
to occur on May 1 and November 1 of each year,
commencing on May 1, 2007.
The notes are guaranteed by our Subsidiary Guarantors, as
defined in the note indenture. The note indenture contains
covenants that, among other things, limit our ability to create
liens and enter into sale and lease-back transactions. The notes
are redeemable at a redemption price equal to 100% of the
principal amount of the notes being redeemed plus a make-whole
premium, if applicable, and any accrued unpaid interest to the
redemption date. Net proceeds from the offering, after deducting
underwriting discounts and expenses, were $886.1 million.
| Series Bonds |
As of December 31, 2006, we had $74.0 million in
Series Bonds outstanding, which were assumed as part of the
Excel acquisition. The 6.84% Series A Bonds have a balloon
maturity in December 2014. The 6.34% Series B Bonds mature
in December 2014 and are payable in installments beginning
December 2008. The 6.84% Series C Bonds mature in December
2016 and are payable in installments beginning December 2012.
Interest payments occur in June and December of each year.
| Interest Rate Swaps |
Prior to completion of the Senior Unsecured Credit Facility, we
had two $400.0 million interest rate swaps. A
$400.0 million notional amount
floating-to-fixed
interest rate swap was designated as a hedge of changes in
expected cash flows on the previous term loan under the Senior
Secured Credit Facility. Under this swap, we paid a fixed rate
of 6.764% and received a floating rate of LIBOR plus 2.5% that
reset each March 15, June 15, September 15 and
December 15 based upon the three-month LIBOR rate. A
$400.0 million notional amount
fixed-to-floating
interest rate swap was designated as a hedge of the changes in
the fair value of the 6.875% Senior Notes due 2013. Under
this swap, we paid a floating rate of LIBOR plus 1.97% that
reset each March 15, June 15, September 15 and
December 15 based upon the three-month LIBOR rate and received a
fixed rate of 6.875%.
In conjunction with the completion of the new Senior Unsecured
Credit Facility, the $400.0 million notional amount
floating-to-fixed
interest rate swap was terminated and resulted in payment to us
of $5.2 million. We recorded the $5.2 million fair
value of the swap in “Accumulated other comprehensive
loss” on the consolidated balance sheet and will amortize
this amount to interest expense over the remaining term of the
forecasted interest payments initially hedged. We then entered
into a $120.0 million notional amount
floating-to-fixed
interest rate swap with a fixed rate of 6.25% and a floating
rate of LIBOR plus 1.0%. This interest rate swap was designated
as a hedge of the variable interest payments on the Term Loan
under the new Senior Unsecured Credit Facility.
We also terminated $280.0 million of our
$400.0 million notional amount
fixed-to-floating
interest rate swap designated as a hedge of the changes in fair
value of the 6.875% Senior Notes due 2013. Reducing the
notional amount of the interest rate swap to $120.0 million
resulted in payment of $5.2 million to the
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counterparty. Reduction of the notional amount of the swap did
not affect our floating and fixed rates. The $5.2 million
of fair value associated with the termination of the
$280.0 million portion of the swap was recorded as an
adjustment to the carrying value of long-term debt and will be
amortized to interest expense through maturity of the
6.875% Senior Notes due 2013.
Because the critical terms of the swaps and the respective debt
instruments they hedge coincide, there was no hedge
ineffectiveness recognized in the consolidated statements of
operations during the years ended December 31, 2006 and
2005. At December 31, 2006 there was an unrealized loss
related to the cash flow hedge of $2.5 million and at
December 31, 2005 there was an unrealized gain related to
the cash flow hedge of $2.3 million. As of
December 31, 2006 and 2005, the net unrealized loss on the
fair value hedges discussed above were $13.8 million and
$8.9 million, respectively, which is reflected as an
adjustment to the carrying value of the Senior Notes (see table
above).
| Third-party Security Ratings |
In 2006, third-party rating agencies performed a comprehensive
review of our securities’ ratings based on our entrance
into the new senior unsecured credit facility and the issuance
of additional debt securities to facilitate the Excel
acquisition. The ratings for our senior unsecured credit
facility and our senior unsecured notes are as follows:
Moody’s issued a Ba1 rating, Standard &
Poor’s issued a BB rating and Fitch issued a BB+ rating.
The rating on our convertible junior subordinated debentures
issued in December 2006 were as follows: Moody’s issued a
Ba2 rating, Standard & Poor’s issued a B rating
and Fitch issued a BB- rating. These security ratings reflected
the views of the rating agency only. An explanation of the
significance of these ratings may be obtained from the rating
agency. Such ratings are not a recommendation to buy, sell or
hold securities, but rather an indication of creditworthiness.
Any rating can be revised upward or downward or withdrawn at any
time by a rating agency if it decides that the circumstances
warrant the change. Each rating should be evaluated
independently of any other rating.
| Shelf Registration Statement |
On July 28, 2006, we filed an automatic shelf registration
statement on
Form S-3 as a
well-known seasoned issuer with the Securities and Exchange
Commission. The registration was for an indeterminate number of
securities and is effective for three years, at which time we
can file an automatic shelf registration statement that would
become immediately effective for another three-year term. Under
this universal shelf registration statement, we have the
capacity to offer and sell from time to time securities,
including common stock, preferred stock, debt securities,
warrants and units. The Debentures, 7.375% Senior Notes due
2016 and 7.875% Senior Notes due 2026 were issued pursuant
to the shelf registration statement.
| Excel Transaction |
On July 5, 2006, we signed a merger implementation
agreement to acquire Excel Coal Limited (“Excel”), an
independent coal company, by means of a scheme of arrangement
transaction under Australian law. The merger implementation
agreement was amended on September 18, 2006, and we agreed
to pay A$9.50 per share (US$7.16 as of the amendment date)
for the outstanding shares of Excel. On September 20, 2006,
as part of the amended agreement, we acquired 19.99% of the
outstanding shares of Excel at A$9.50 per share, resulting
in payment of A$408.3 million, or US$307.8 million. In
October 2006, we acquired the remaining interest in Excel for
A$9.50 per share (US$7.07 per share), a total of
A$1.63 billion or US$1.21 billion. The total
acquisition price, including the advance purchase of 19.99% and
related costs, was US$1.54 billion in cash plus assumed
debt of US$293.0 million, less US$30.0 million of cash
acquired in the transaction, and was financed with borrowings
under our Senior Unsecured Credit Facility and Senior Notes due
2016 and 2026 (see Note 12 of our consolidated financial
statements for additional information on the financing of the
Excel acquisition). The Excel acquisition includes three
operating mines (Wambo Open-Cut Mine, Metropolitan Mine and
Chain Valley Mine) and three development-stage mines (North
Wambo Underground Mine, Wilpinjong Mine and Millennium Mine),
with more than 500 million tons of proven and probable coal
reserves. We also acquired a 51.0%
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interest in Excelven Pty Ltd., which owns Transportes Coal-Sea
de Venezuela C.A. and a 96.7% interest in Cosila Complejo
Siderurgico Del Lago S.A., which owns the Las Carmelitas coal
mine development project. The results of operations of Excel are
included in our Australian Mining Operations segment from
October 2006. The acquisition was accounted for as a purchase in
accordance with SFAS No. 141, “Business
Combinations” (see Note 4 of our consolidated
financial statements for additional information on the Excel
acquisition).
Contractual Obligations
The following is a summary of our contractual obligations as of
December 31, 2006:
| Payments Due By Year | |||||||||||||||||
| Within | After | ||||||||||||||||
| 1 Year | 2-3 Years | 4-5 Years | 5 Years | ||||||||||||||
| (Dollars in thousands) | |||||||||||||||||
|
Long-term debt obligations (principal and interest)
|
$ | 303,849 | $ | 481,974 | $ | 859,965 | $ | 4,323,807 | |||||||||
|
Capital lease obligations (principal and interest)
|
11,335 | 21,806 | 15,686 | 23,428 | |||||||||||||
|
Operating leases obligations
|
102,256 | 152,264 | 101,386 | 168,076 | |||||||||||||
|
Unconditional purchase
obligations(1)
|
125,791 | — | — | — | |||||||||||||
|
Coal reserve lease and royalty obligations
|
216,996 | 344,407 | 25,459 | 46,611 | |||||||||||||
|
Other long-term
liabilities(2)
|
170,716 | 337,809 | 396,113 | 1,362,711 | |||||||||||||
|
Total contractual cash obligations
|
$ | 930,943 | $ | 1,338,260 | $ | 1,398,609 | $ | 5,924,633 | |||||||||
| (1) | We have purchase agreements with approved vendors for most types of operating expenses. However, our specific open purchase orders (which have not been recognized as a liability) under these purchase agreements, combined with any other open purchase orders, are not material. The commitments in the table above relate to significant capital purchases. |
| (2) | Represents long-term liabilities relating to our postretirement benefit plans, work-related injuries and illnesses, defined benefit pension plans and mine reclamation and end of mine closure costs. |
As of December 31, 2006, we had $125.8 million of
purchase obligations for capital expenditures and
$479.8 million of obligations related to federal coal
reserve lease payments due over the next three years. Total
capital expenditures for 2007 are expected to range from
$450 million to $525 million, excluding federal coal
reserve lease payments, and relate to replacement, improvement,
or expansion of existing mines, particularly in Australia,
Appalachia and the Midwest, and growth initiatives such as
increasing capacity in the Powder River Basin. Approximately
$10 million of the expenditures relate to safety equipment
that will be utilized to comply with recently issued federal and
state regulations. Capital expenditures were funded primarily
through operating cash flow. Despite the acquisition of three
development stage mines in 2006, we will exercise capital
discipline in 2007, limiting capital expenditures to 2006 levels.
Our subsidiary, Peabody Pacific, has committed to pay up to a
maximum of A$0.20/tonne (approximately US$0.15/tonne) of coal
sales for a period of five years to the Australian COAL21 Fund.
The COAL21 Fund is a voluntary coal industry fund to support
clean coal technology demonstration projects and research in
Australia. All major coal companies in Australia have committed
to this fund. The commitment to pay starts on April 1, 2007
with a levy of A$0.10/tonne of coal sales. This levy is expected
to rise to A$0.20/tonne on July 1, 2007.
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
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as bank letters of credit and performance or surety bonds and
our accounts receivable securitization. Liabilities related to
these arrangements are not reflected in our consolidated balance
sheets, and we do not expect any material adverse effects on our
financial condition, results of operations or cash flows to
result from these off-balance sheet arrangements.
We use a combination of surety bonds, corporate guarantees (i.e.
self bonds) and letters of credit to secure our financial
obligations for reclamation, workers’ compensation,
postretirement benefits and coal lease obligations as follows as
of December 31, 2006:
| Workers’ | Retiree | |||||||||||||||||||||||
| Reclamation | Lease | Compensation | Healthcare | |||||||||||||||||||||
| Obligations | Obligations | Obligations | Obligations | Other(1) | Total | |||||||||||||||||||
| (Dollars in millions) | ||||||||||||||||||||||||
|
Self Bonding
|
$ | 685.3 | $ | — | $ | — | $ | — | $ | 2.9 | $ | 688.2 | ||||||||||||
|
Surety Bonds
|
441.5 | 83.9 | 31.7 | — | 27.2 | 584.3 | ||||||||||||||||||
|
Letters of Credit
|
4.1 | 20.3 | 156.8 | 119.4 | 208.8 | 509.4 | ||||||||||||||||||
| $ | 1,130.9 | $ | 104.2 | $ | 188.5 | $ | 119.4 | $ | 238.9 | $ | 1,781.9 | |||||||||||||
| (1) | Includes financial guarantees primarily related to joint venture debt, the Pension Benefit Guarantee Corporation and collateral for surety companies. |
As part of arrangements through which we obtain exclusive sales
representation agreements with small coal mining companies (the
“Counterparties”), we issued financial guarantees on
behalf of the Counterparties. These guarantees facilitate the
Counterparties’ efforts to obtain bonding or financing. In
July 2006, we issued $5.2 million of financial guarantees,
expiring at various dates through July 2013, on behalf of a
small coal producer to facilitate its efforts in obtaining
financing. In the event of default, we have multiple recourse
options, including the ability to assume the loans and procure
title and use of the equipment purchased through the loans. If
default occurs, we have the ability and intent to exercise our
recourse options, so the liability associated with the guarantee
has been valued at zero. We have also guaranteed bonding for a
partnership in which we formerly held an interest. The aggregate
amount guaranteed for all such Counterparties was
$12.1 million, and the fair value of the guarantees
recognized as a liability was $0.4 million as of
December 31, 2006. Our obligations under the guarantees
extend to September 2015. In March 2006, we issued a guarantee
for certain equipment lease arrangements on behalf of one of the
sales representation parties with maximum potential future
payments totaling $2.7 million at December 31, 2006,
and with lease terms that extend to April 2010. See Note 21
to our consolidated financial statements included in this report
for a discussion of our guarantees.
Under our accounts receivable securitization program, undivided
interests in a pool of eligible trade receivables contributed to
our wholly-owned, bankruptcy-remote subsidiary are sold, without
recourse, to a multi-seller, asset-backed commercial paper
conduit (“Conduit”). Purchases by the Conduit are
financed with the sale of highly rated commercial paper. We
utilize proceeds from the sale of our accounts receivable as an
alternative to other forms of debt, effectively reducing our
overall borrowing costs. The funding cost of the securitization
program was $1.9 million and $2.5 million for the
years ended December 31, 2006 and 2005, respectively. The
securitization program is scheduled to expire in September 2009.
The securitization transactions have been recorded as sales,
with those accounts receivable sold to the Conduit removed from
the consolidated balance sheets. The amount of undivided
interests in accounts receivable sold to the Conduit was
$219.2 million and $225.0 million as of
December 31, 2006 and 2005 (see Note 6 to our
consolidated financial statements for additional information on
accounts receivable securitization).
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The following is a summary of specified types of commercial
commitments available to us as of December 31, 2006:
| Expiration Per Year | ||||||||||||||||||||
| Total Amounts | Within | Over | ||||||||||||||||||
| Committed | 1 Year | 2-3 Years | 4-5 Years | 5 Years | ||||||||||||||||
| (Dollars in thousands) | ||||||||||||||||||||
|
Lines of credit and/ or standby letters of credit
|
$ | 1,800,000 | $ | — | $ | — | $ | 1,800,000 | $ | — | ||||||||||
Newly Adopted Accounting Pronouncements
We adopted Emerging Issues Task Force (“EITF”) Issue
No. 04-6,
“Accounting for Stripping Costs in the Mining
Industry” (“EITF Issue
No. 04-6”) on
January 1, 2006 and utilized the cumulative effect
adjustment approach whereby a cumulative effect adjustment
reduced retained earnings by $150.3 million, net of tax.
EITF Issue
No. 04-6 states
“that stripping costs incurred during the production phase
of a mine are variable production costs that should be included
in the costs of the inventory produced during the period that
the stripping costs are incurred.” Advance stripping costs
include those costs necessary to remove overburden above an
unmined coal seam as part of the surface mining process and
prior to the adoption were included as the
“work-in-process”
component of “Inventories” in the consolidated balance
sheet. EITF Issue
No. 04-6 and its
interpretations require stripping costs incurred during a period
to be attributed only to the inventory costs of the coal that is
extracted during that same period, and therefore, advance
stripping costs are no longer separately classified as a
component of inventory.
On January 1, 2006, we adopted SFAS No. 123
(revised 2004), “Share-Based Payment”
(“SFAS No. 123(R)”), which is a revision of
SFAS No. 123, “Accounting for Stock-Based
Compensation” (“SFAS No. 123”).
SFAS No. 123(R) supersedes Accounting Principles Board
(“APB”) Opinion No. 25, “Accounting for
Stock Issued to Employees” (“APB Opinion
No. 25”) and amends SFAS No. 95,
“Statement of Cash Flows.” Prior to January 1,
2006, we applied APB Opinion No. 25 and related
interpretations in accounting for our stock option plans, as
permitted under SFAS No. 123 and
SFAS No. 148 “Accounting for Stock-Based
Compensation-Transition and Disclosure.” We applied
SFAS No. 123(R) through use of the modified
prospective method, in which compensation cost is recognized
beginning with the effective date (a) based on the
requirements of SFAS No. 123(R) for all share-based
payments granted or modified after the effective date and
(b) based on the requirements of SFAS No. 123 for
all awards granted to employees prior to the effective date of
SFAS No. 123(R) that remain unvested on the effective
date. SFAS No. 123(R) requires all share-based
payments to employees, including grants of employee stock
options, to be recognized in the income statement based on their
fair values at the grant date. SFAS No. 123(R) also
requires that the excess income tax benefits from stock options
exercised be recorded as financing cash inflow on the statements
of cash flows. The excess income tax benefit from stock option
exercises during 2005 and 2004 are included in operating cash
flows, netted in deferred tax activity.
For share-based payment instruments excluding restricted stock,
we recognized $17.7 million (or $0.07 per diluted
share), $24.8 million (or $0.09 per diluted share) and
$12.8 million (or $0.05 per diluted share) of expense,
net of taxes, for the years ended December 31, 2006, 2005
and 2004, respectively. As a result of adopting
SFAS No. 123(R), our net income for the year ended
December 31, 2006 was $4.4 million (or $0.02 per
diluted share) lower than if we had continued to account for
share-based compensation under APB Opinion No. 25.
Share-based compensation expense is recorded in “Selling
and administrative expenses” in the consolidated statements
of operations. We used the Black-Scholes option pricing model to
determine the fair value of stock options and employee stock
purchase plan share-based payments made before and after the
adoption of SFAS No. 123(R). We began utilizing
restricted stock as part of our equity-based compensation
strategy in January 2005. Accounting for restricted stock awards
was not changed by the adoption of SFAS No. 123(R). As
of December 31, 2006, the total unrecognized compensation
cost related to nonvested awards was $24.0 million, net of
taxes, which is expected to be
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recognized over 5.0 years with a weighted-average period of
1.3 years. See Note 18 to our consolidated financial
statements for further discussion of our share-based
compensation plans.
In September 2006, the Financial Accounting Standards Board
(“FASB”) issued SFAS No. 158,
“Employers’ Accounting for Defined Benefit Pension and
Other Postretirement Plans”
(“SFAS No. 158”). For fiscal years ending
after December 15, 2006, SFAS No. 158 requires
recognition of the funded status of pension and other
postretirement benefit plans (an asset for overfunded status or
a liability for underfunded status) in a company’s balance
sheet. In addition, the standard requires recognition of
actuarial gains and losses, prior service cost, and any
remaining transition amounts from the initial application of
SFAS No. 87, “Employers’ Accounting for
Pensions” (“SFAS No. 87”) and
SFAS No. 106, “Employers’ Accounting for
Postretirement Benefits Other Than Pensions”
(“SFAS No. 106”) when determining a
plan’s funded status, with a corresponding charge to
accumulated other comprehensive income (loss).
We adopted SFAS No. 158 on December 31, 2006, and
as a result, recorded a noncurrent liability of
$376.1 million, which reflected the total underfunded
status of the pension, retiree healthcare and workers’
compensation plans. The funded status of each plan was measured
as the difference between the fair value of the assets and the
projected benefit obligation (the “funded status”).
SFAS No. 158 did not impact net income. The impact to
the balance sheet was as follows (see Notes 14, 15,
and 16 to our consolidated financial statements for additional
details):
| After Application | ||||||||||||
| Before Application | of | |||||||||||
| of SFAS No. 158 | Adjustments | SFAS No. 158 | ||||||||||
| (Dollars in thousands) | ||||||||||||
|
Workers’ compensation obligations
|
$ | 237,965 | $ | (4,558 | ) | $ | 233,407 | |||||
|
Accrued postretirement benefit costs
|
973,164 | 395,522 | 1,368,686 | |||||||||
|
Other noncurrent liabilities (includes long-term pension and
UMWA Combined Fund liabilities)
|
375,485 | (14,855 | ) | 360,630 | ||||||||
|
Deferred income taxes (long-term liability)
|
344,712 | (149,499 | ) | 195,213 | ||||||||
|
Total liabilities
|
6,915,583 | 226,610 | 7,142,193 | |||||||||
|
Accumulated other comprehensive loss
|
(22,448 | ) | (226,610 | ) | (249,058 | ) | ||||||
|
Total stockholders’ equity
|
2,565,136 | (226,610 | ) | 2,338,526 | ||||||||
Accounting Pronouncements Not Yet Implemented
In June 2006, the FASB issued FIN No. 48. This
interpretation prescribes a recognition threshold and
measurement attribute for the financial statement recognition
and measurement of a tax position taken or expected to be taken
in a tax return. FIN No. 48 also provides guidance on
derecognition, classification, interest and penalties,
accounting in interim periods, disclosure and transition. This
interpretation is effective for fiscal years beginning after
December 15, 2006 (January 1, 2007 for the Company).
Any adjustments required upon the adoption of this
interpretation must be recorded directly to retained earnings in
the year of adoption and reported as a change in accounting
principle. We expect the adoption of FIN No. 48 will
not have a material impact on our financial position.
| Item 7A. | Quantitative and Qualitative Disclosures About Market Risk. |
The potential for changes in the market value of our coal
trading, interest rate and currency portfolios is referred to as
“market risk.” Market risk related to our coal trading
portfolio is evaluated using a value at risk analysis (described
below). Value at risk analysis is not used to evaluate our
non-trading interest rate and currency portfolios. A description
of each market risk category is set forth below. We attempt to
manage market risks through diversification, controlling
position sizes, and executing hedging strategies. Due to lack of
quoted market prices and the long term, illiquid nature of the
positions, we have not quantified market risk related to our
non-trading, long-term coal supply agreement portfolio.
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Coal Trading Activities and Related Commodity Price Risk
We engage in
over-the-counter and
direct trading of coal. These activities give rise to commodity
price risk, which represents the potential loss that can be
caused by an adverse change in the market value of a particular
commitment. We actively measure, monitor and adjust traded
position levels to remain within risk limits prescribed by
management. For example, we have policies in place that limit
the amount of total exposure, in value at risk terms, that we
may assume at any point in time.
We account for coal trading using the fair value method, which
requires us to reflect financial instruments with third parties,
such as forwards, options and swaps, at market value in our
consolidated financial statements. Our trading portfolio
included forwards and swaps as of December 31, 2006 and
forwards as of December 31, 2005.
We perform a value at risk analysis on our coal trading
portfolio, which includes
over-the-counter and
brokerage trading of coal. The use of value at risk allows us to
quantify in dollars, on a daily basis, the price risk inherent
in our trading portfolio. Value at risk represents the potential
loss in value of our
mark-to-market
portfolio due to adverse market movements over a defined time
horizon (liquidation period) within a specified confidence
level. Our value at risk model is based on the industry standard
variance/co-variance approach. This captures our exposure
related to both option and forward positions. Our value at risk
model assumes a 15-day
holding period and a 95% one-tailed confidence interval. This
means that there is a one in 20 statistical chance that the
portfolio would lose more than the value at risk estimates
during the liquidation period.
The use of value at risk allows management to aggregate pricing
risks across products in the portfolio, compare risk on a
consistent basis and identify the drivers of risk. Due to the
subjectivity in the choice of the liquidation period, reliance
on historical data to calibrate the models and the inherent
limitations in the value at risk methodology, we perform regular
stress and scenario analysis to estimate the impacts of market
changes on the value of the portfolio. Additionally,
back-testing is regularly performed to monitor the effectiveness
of our value at risk measure. The results of these analyses are
used to supplement the value at risk methodology and identify
additional market-related risks.
We use historical data to estimate our value at risk and to
better reflect current asset and liability volatilities. Given
our reliance on historical data, value at risk is effective in
estimating risk exposures in markets in which there are not
sudden fundamental changes or shifts in market conditions. An
inherent limitation of value at risk is that past changes in
market risk factors may not produce accurate predictions of
future market risk. Value at risk should be evaluated in light
of this limitation.
During the year ended December 31, 2006, the actual low,
high, and average values at risk for our coal trading portfolio
were $0.7 million, $2.7 million, and
$1.4 million, respectively. As of December 31, 2006,
the timing of the estimated future realization of the value of
our trading portfolio was as follows:
| Percentage | ||||
| Year of Expiration | of Portfolio | |||
|
2007
|
41 | % | ||
|
2008
|
39 | % | ||
|
2009
|
15 | % | ||
|
2010
|
5 | % | ||
| 100 | % | |||
We also monitor other types of risk associated with our coal
trading activities, including credit, market liquidity and
counterparty nonperformance.
Credit Risk
Our concentration of credit risk is substantially with energy
producers and marketers and electric utilities. Our policy is to
independently evaluate each customer’s creditworthiness
prior to entering into
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transactions and to constantly monitor the credit extended. In
the event that we engage in a transaction with a counterparty
that does not meet our credit standards, we will protect our
position by requiring the counterparty to provide appropriate
credit enhancement. When appropriate (as determined by our
credit management function), we have taken steps to reduce our
credit exposure to customers or counterparties whose credit has
deteriorated and who may pose a higher risk of failure to
perform under their contractual obligations. These steps include
obtaining letters of credit or cash collateral, requiring
prepayments for shipments or the creation of customer trust
accounts held for our benefit to serve as collateral in the
event of a failure to pay. To reduce our credit exposure related
to trading and brokerage activities, we seek to enter into
netting agreements with counterparties that permit us to offset
receivables and payables with such counterparties. Counterparty
risk with respect to interest rate swap and foreign currency
forwards and options transactions is not considered to be
significant based upon the creditworthiness of the participating
financial institutions.
Foreign Currency Risk
We utilize currency forwards to hedge currency risk associated
with anticipated Australian dollar expenditures. Our currency
hedging program for 2007 targets hedging approximately 70% of
our anticipated, non-capital Australian dollar-denominated
expenditures. As of December 31, 2006, we had in place
forward contracts designated as cash flow hedges with notional
amounts outstanding totaling A$1.35 billion of which
A$764.2 million, A$359.7 million, A$196.7 million
and A$28.8 million will expire in 2007, 2008, 2009, and
2010, respectively. The accounting for these derivatives is
discussed in Note 2 to our consolidated financial
statements. Our current expectation for 2007 non-capital,
Australian dollar-denominated cash expenditures is approximately
$1.37 billion. An increase or decrease in the Australian
dollar/ U.S. dollar exchange rate of US$0.01 (ignoring the
effects of hedging) would result in an increase or decrease,
respectively, in our “Operating costs and expenses” of
$13.7 million per year.
Interest Rate Risk
Our objectives in managing exposure to interest rate changes are
to limit the impact of interest rate changes on earnings and
cash flows and to lower overall borrowing costs. To achieve
these objectives, we manage fixed-rate debt as a percent of net
debt through the use of various hedging instruments, which are
discussed in detail in Note 12 to our consolidated
financial statements. As of December 31, 2006, after taking
into consideration the effects of interest rate swaps, we had
$2.61 billion of fixed-rate borrowings and
$649.3 million of variable-rate borrowings outstanding. A
one percentage point increase in interest rates would result in
an annualized increase to interest expense of $6.5 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 $0.2 million decrease in the estimated
fair value of these borrowings.
Other Non-trading Activities
We manage our commodity price risk for our non-trading,
long-term coal contract portfolio through the use of long-term
coal supply agreements, rather than through the use of
derivative instruments. We sold 90% of our sales volume under
long-term coal supply agreements during 2006 and 2005. As of
December 31, 2006, we had 5 to 15 million tons of
expected U.S. production unpriced for 2007. We had
14 million tons remaining to be priced in Australia at
December 31, 2006. We have approximately 70 to
80 million tons of expected U.S. production unpriced
for 2008, with an additional 20 to 22 million tons of
expected Australia coal production.
Some of the products used in our mining activities, such as
diesel fuel and explosives, are subject to commodity price risk.
To manage this risk, we use a combination of forward contracts
with our suppliers and financial derivative contracts, primarily
swap contracts with financial institutions. As of
December 31, 2006, we had derivative contracts outstanding
that are designated as cash flow hedges of anticipated purchases
of fuel and explosives.
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Notional amounts outstanding under fuel-related, derivative swap
contracts were 11.6 million gallons of heating oil
scheduled to expire through 2007 and 83.2 million gallons
of crude oil scheduled to expire through 2009. At
December 31, 2006, we had outstanding option contracts
designated as a collar of crude oil prices with notional amounts
of 43.1 million gallons, expiring through 2007. We expect
to consume 100 to 105 million gallons of fuel next year. On
a per gallon basis, based on this usage, a change in fuel prices
of one cent per gallon (ignoring the effects of hedging) would
result in an increase or decrease in our operating costs of
approximately $1 million per year. Alternatively, a one
dollar per barrel change in the price of crude oil would
increase or decrease our annual fuel costs (ignoring the effects
of hedging) by approximately $2.4 million.
Notional amounts outstanding under explosives-related swap
contracts, scheduled to expire through 2009, were 5.7 mmbtu of
natural gas. We expect to consume 315,000 to 325,000 tons of
explosives per year. Through our natural gas hedge contracts, we
have fixed prices for approximately 46% of our anticipated
explosives requirements for 2007. Based on our expected usage, a
change in natural gas prices of ten cents per mmbtu (ignoring
the effects of hedging) would result in an increase or decrease
in our operating costs of approximately $0.6 million per
year.
| Item 8. | Financial Statements and Supplementary Data. |
See Part IV, Item 15 of this report for information
required by this Item.
| Item 9. | Changes in and Disagreements with Accountants on Accounting and Financial Disclosure. |
None.
| Item 9A. | Controls and Procedures. |
Evaluation of Disclosure Controls and Procedures
As of the end of the period covered by this Annual Report on
Form 10-K, we
carried out an evaluation of the effectiveness of the design and
operation of our disclosure controls and procedures. Based upon
that evaluation, the Chief Executive Officer and the Chief
Financial Officer concluded that our disclosure controls and
procedures were effective in timely alerting them to material
information relating to our company and its consolidated
subsidiaries required to be included in our periodic SEC filings.
Changes in Internal Control Over Financial Reporting
There were no changes in our internal control over financial
reporting identified during the last fiscal quarter 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,
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management concluded that the Company’s internal control
over financial reporting was effective as of December 31,
2006.
Management’s assessment of internal control over financial
reporting excludes the operations of Excel Coal Limited acquired
during 2006, as allowed by SEC guidance related to internal
controls of recently acquired entities. These operations
constituted $2.34 billion and $1.58 billion of total
and net assets, respectively; and $105.1 million and
$8.4 million of revenues and operating profits,
respectively; and such amounts are included in our consolidated
financial statements as of and for the year ended
December 31, 2006. Management did not assess the
effectiveness of internal control over financial reporting at
these operations because we continue to integrate these
operations into our control environment, thus making it
impractical to complete an assessment by December 31, 2006.
Our Independent Registered Public Accounting Firm,
Ernst & Young LLP, has audited this assessment of our
internal control over financial reporting, as stated in their
attestation report included herein.
| /s/ GREGORY H. BOYCE | /s/ RICHARD A. NAVARRE | |
| Gregory H. Boyce | Richard A. Navarre | |
| President and Chief Executive Officer |
Chief Financial Officer and Executive Vice President of Corporate Development |
February 20, 2007
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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Directors and Stockholders
Peabody Energy Corporation
We have audited management’s assessment, included in the
accompanying Management’s Report on Internal Controls, that
Peabody Energy Corporation maintained effective internal control
over financial reporting as of December 31, 2006, 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. Our responsibility is to express an opinion
on management’s assessment and an opinion on the
effectiveness of 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, evaluating
management’s assessment, testing and evaluating the design
and operating effectiveness of internal control, 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.
As indicated in the accompanying Management’s Report on
Internal Control Over Financial Reporting, management’s
assessment of and conclusion on the effectiveness of internal
control over financial reporting did not include the internal
controls over Excel Coal Limited acquired in 2006, which is
included in the December 31, 2006, consolidated financial
statements of Peabody Energy Corporation and constituted
$2.34 billion and $1.58 billion of total and net
assets, respectively, as of December 31, 2006, and
$105.1 million and $8.4 million of revenues and
operating profits, respectively, for the year then ended. Our
audit of internal control over financial reporting of Peabody
Energy Corporation also did not include an evaluation of the
internal control over financial reporting of Excel Coal Limited.
In our opinion, management’s assessment that Peabody Energy
Corporation maintained effective internal control over financial
reporting as of December 31, 2006, is fairly stated, in all
material respects, based on the COSO criteria. Also, in our
opinion, Peabody Energy Corporation maintained, in all material
respects, effective internal control over financial reporting as
of December 31, 2006, based on the COSO criteria.
We have also 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
87
Table of Contents
December 31, 2006 and 2005, 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, 2006, and our report dated February 20,
2007, expressed an unqualified opinion thereon.
| /s/ Ernst & Young LLP |
St. Louis, Missouri
February 20, 2007
88
Table of Contents
| Item 9B. | Other Information. |
None.
PART III
| Item 10. | Directors, Executive Officers and Corporate Governance. |
The information required by Item 401 of
Regulation S-K is
included under the caption “Election of Directors” in
our 2007 Proxy Statement and in Part I of this report under
the caption Executive Officers of the Company. The information
required by Item 405, 406 and 407(c)(3), (d)(4) and (d)(5)
of Regulation S-K
is included under the captions “Ownership of Company
Securities — Section 16(a) Beneficial Ownership
Reporting Compliance,” “Corporate Governance
Matters” and “Information Regarding Board of Directors
and Committees” in our 2007 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 2007 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 2007 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, 2006:
| Number of Securities | ||||||||||||
| (a) | Remaining Available for | |||||||||||
| Number of Securities | Future Issuance Under | |||||||||||
| to be Issued upon | Weighted-Average | Equity Compensation | ||||||||||
| Exercise of | Exercise Price of | Plans (Excluding | ||||||||||
| Outstanding Options, | Outstanding Options, | Securities Reflected in | ||||||||||
| Plan Category | Warrants and Rights | Warrants and Rights | Column (a)) | |||||||||
|
Equity compensation plans approved by security holders
|
9,320,718 | $ | 8.16 | 14,967,519 | ||||||||
|
Equity compensation plans not approved by security holders
|
— | — | — | |||||||||
|
Total
|
9,320,718 | $ | 8.16 | 14,967,519 | ||||||||
| Item 13. | Certain Relationships and Related Transactions, and Director Independence. |
The information required by Items 404 and 407(a) of
Regulation S-K is
included under the captions “Certain Transactions and
Relationships” and “Information Regarding Board of
Directors and Committees” in our 2007 Proxy Statement and
is incorporated herein by reference.
89
Table of Contents
| Item 14. | Principal Accounting Fees and Services. |
The information required by Item 9(e) of Schedule 14A
is included under the caption “Appointment of Independent
Registered Public Accounting Firm and Fees” in our 2007
Proxy Statement and is incorporated herein by reference.
PART IV
| Item 15. | Exhibits and Financial Statement Schedules. |
(a) Documents Filed as Part of the Report
| (1) Financial Statements. | |
| The following consolidated financial statements of Peabody Energy Corporation are included herein on the pages indicated: |
| Page | ||||
|
Report of Independent Registered Public Accounting Firm
|
F-1 | |||
|
Consolidated Statements of Operations — Years Ended
December 31, 2006, 2005 and 2004
|
F-2 | |||
|
Consolidated Balance Sheets — December 31, 2006
and December 31, 2005
|
F-3 | |||
|
Consolidated Statements of Cash Flows — Years Ended
December 31, 2006, 2005 and 2004
|
F-4 | |||
|
Consolidated Statements of Changes in Stockholders’
Equity — Years Ended December 31, 2006, 2005 and
2004
|
F-5 | |||
|
Notes to Consolidated Financial Statements
|
F-6 | |||
| (2) Financial Statement Schedule. | |
| The following financial statement schedule of Peabody Energy Corporation and the report thereon of the independent registered public accounting firm are at the pages indicated: |
| Page | ||||
|
Report of Independent Registered Public Accounting Firm on
Financial Statement Schedule
|
F-72 | |||
|
Valuation and Qualifying Accounts
|
F-73 | |||
| 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. |
90
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 | |
| President, Chief Executive Officer and Director |
Date: February 28, 2007
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 |
President, Chief Executive Officer and Director (principal executive officer) | February 28, 2007 | ||||
|
/s/ RICHARD A. NAVARRE |
Chief Financial Officer and Executive Vice President of Corporate Development (principal financial and accounting officer) | February 28, 2007 | ||||
|
/s/ IRL F. ENGELHARDT |
Chairman | February 28, 2007 | ||||
|
/s/ B.R. BROWN |
Director | February 28, 2007 | ||||
|
/s/ WILLIAM A. COLEY |
Director | February 28, 2007 | ||||
|
/s/ HENRY
GIVENS, JR., PhD |
Director | February 28, 2007 | ||||
|
/s/ WILLIAM E. JAMES |
Director | February 28, 2007 | ||||
|
/s/ ROBERT B.
KARN III |
Director | February 28, 2007 | ||||
|
/s/ HENRY E. LENTZ |
Director | February 28, 2007 | ||||
|
/s/ WILLIAM C. RUSNACK |
Director | February 28, 2007 | ||||
91
Table of Contents
| Signature | Title | Date | ||||
|
/s/ JAMES R. SCHLESINGER,
PhD |
Director | February 28, 2007 | ||||
|
/s/ BLANCHE M. TOUHILL,
PhD |
Director | February 28, 2007 | ||||
|
/s/ JOHN F. TURNER |
Director | February 28, 2007 | ||||
|
/s/ SANDRA VAN TREASE |
Director | February 28, 2007 | ||||
|
/s/ ALAN H. WASHKOWITZ |
Director | February 28, 2007 | ||||
92
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 as of December 31, 2006 and
2005, 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, 2006.
These financial statements are the responsibility of the
Company’s management. Our responsibility is to express an
opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the
Public Company Accounting Oversight Board (United States). Those
standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are
free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in
the financial statements. An audit also includes assessing the
accounting principles used and significant estimates made by
management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, the financial statements referred to above
present fairly, in all material respects, the consolidated
financial position of Peabody Energy Corporation at
December 31, 2006 and 2005, and the consolidated results of
its operations and its cash flows for each of the three years in
the period ended December 31, 2006, in conformity with
U.S. generally accepted accounting principles.
As discussed in Note 1 to the consolidated financial
statements, on January 1, 2006, the Company changed its
method of accounting for stripping costs and share-based
payments, and on December 31, 2006, the Company changed its
method of accounting for defined pension benefit and other
postretirement plans.
We also have audited, in accordance with the standards of the
Public Company Accounting Oversight Board (United States), the
effectiveness of Peabody Energy Corporation’s internal
control over financial reporting as of December 31, 2006,
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 20, 2007, expressed an unqualified opinion thereon.
| /s/ Ernst & Young LLP |
St. Louis, Missouri
February 20, 2007
F-1
Table of Contents
PEABODY ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS
| Year Ended December 31, | ||||||||||||||
| 2006 | 2005 | 2004 | ||||||||||||
| (Dollars in thousands, except share and per share data) | ||||||||||||||
|
Revenues
|
||||||||||||||
|
Sales
|
$ | 5,144,925 | $ | 4,545,323 | $ | 3,545,027 | ||||||||
|
Other revenues
|
111,390 | 99,130 | 86,555 | |||||||||||
|
Total revenues
|
5,256,315 | 4,644,453 | 3,631,582 | |||||||||||
|
Costs and Expenses
|
||||||||||||||
|
Operating costs and expenses
|
4,155,984 | 3,715,836 | 2,965,541 | |||||||||||
|
Depreciation, depletion and amortization
|
377,210 | 316,114 | 270,159 | |||||||||||
|
Asset retirement obligation expense
|
40,112 | 35,901 | 42,387 | |||||||||||
|
Selling and administrative expenses
|
175,941 | 189,802 | 143,025 | |||||||||||
|
Other operating income:
|
||||||||||||||
|
Net gain on disposal or exchange of assets
|
(132,162 | ) | (101,487 | ) | (23,829 | ) | ||||||||
|
Income from equity affiliates
|
(23,852 | ) | (30,096 | ) | (12,399 | ) | ||||||||
|
Operating Profit
|
663,082 | 518,383 | 246,698 | |||||||||||
|
Interest expense
|
143,450 | 102,939 | 96,793 | |||||||||||
|
Early debt extinguishment costs
|
1,396 | — | 1,751 | |||||||||||
|
Interest income
|
(12,726 | ) | (10,641 | ) | (4,917 | ) | ||||||||
|
Income From Continuing Operations Before Income Taxes and
Minority Interests
|
530,962 | 426,085 | 153,071 | |||||||||||
|
Income tax provision (benefit)
|
(81,515 | ) | 960 | (26,437 | ) | |||||||||
|
Minority interests
|
11,780 | 2,472 | 1,282 | |||||||||||
|
Income From Continuing Operations
|
600,697 | 422,653 | 178,226 | |||||||||||
|
Loss from discontinued operations, net of income tax benefit of
$1,893
|
— | — | (2,839 | ) | ||||||||||
|
Net Income
|
$ | 600,697 | $ | 422,653 | $ | 175,387 | ||||||||
|
Basic Earnings Per Share
|
||||||||||||||
|
Income from continuing operations
|
$ | 2.28 | $ | 1.62 | $ | 0.72 | ||||||||
|
Loss from discontinued operations
|
— | — | (0.01 | ) | ||||||||||
|
Net income
|
$ | 2.28 | $ | 1.62 | $ | 0.71 | ||||||||
|
Weighted Average Shares Outstanding — Basic
|
263,419,344 | 261,519,424 | 248,732,744 | |||||||||||
|
Diluted Earnings Per Share
|
||||||||||||||
|
Income from continuing operations
|
$ | 2.23 | $ | 1.58 | $ | 0.70 | ||||||||
|
Loss from discontinued operations
|
— | — | (0.01 | ) | ||||||||||
|
Net income
|
$ | 2.23 | $ | 1.58 | $ | 0.69 | ||||||||
|
Weighted Average Shares Outstanding — Diluted
|
269,166,005 | 268,013,476 | 254,812,632 | |||||||||||
|
Dividends Declared Per Share
|
$ | 0.24 | $ | 0.17 | $ | 0.13 | ||||||||
See accompanying notes to consolidated financial statements
F-2
Table of Contents
PEABODY ENERGY CORPORATION
CONSOLIDATED BALANCE SHEETS
| December 31, | |||||||||||
| 2006 | 2005 | ||||||||||
| (Dollars in thousands, except | |||||||||||
| share and per share data) | |||||||||||
| ASSETS | |||||||||||
|
Current assets
|
|||||||||||
|
Cash and cash equivalents
|
$ | 326,511 | $ | 503,278 | |||||||
|
Accounts receivable, net of allowance for doubtful accounts of
$11,144 and $10,853 at December 31, 2006 and 2005,
respectively
|
358,242 | 202,134 | |||||||||
|
Inventories
|
215,384 | 389,771 | |||||||||
|
Assets from coal trading activities
|
150,373 | 146,596 | |||||||||
|
Deferred income taxes
|
106,967 | 9,027 | |||||||||
|
Other current assets
|
116,863 | 54,431 | |||||||||
|
Total current assets
|
1,274,340 | 1,305,237 | |||||||||
|
Property, plant, equipment and mine development
|
|||||||||||
|
Land and coal interests
|
7,127,385 | 4,775,126 | |||||||||
|
Buildings and improvements
|
893,049 | 793,254 | |||||||||
|
Machinery and equipment
|
1,516,765 | 1,237,184 | |||||||||
|
Less accumulated depreciation, depletion and amortization
|
(1,985,682 | ) | (1,627,856 | ) | |||||||
|
Property, plant, equipment and mine development, net
|
7,551,517 | 5,177,708 | |||||||||
|
Goodwill
|
240,667 | — | |||||||||
|
Investments and other assets
|
447,532 | 369,061 | |||||||||
|
Total assets
|
$ | 9,514,056 | $ | 6,852,006 | |||||||
| LIABILITIES AND STOCKHOLDERS’ EQUITY | |||||||||||
|
Current liabilities
|
|||||||||||
|
Current maturities of long-term debt
|
$ | 95,757 | $ | 22,585 | |||||||
|
Liabilities from coal trading activities
|
126,731 | 132,373 | |||||||||
|
Accounts payable and accrued expenses
|
1,145,043 | 867,965 | |||||||||
|
Total current liabilities
|
1,367,531 | 1,022,923 | |||||||||
|
Long-term debt, less current maturities
|
3,168,069 | 1,382,921 | |||||||||
|
Deferred income taxes
|
195,213 | 338,488 | |||||||||
|
Asset retirement obligations
|
423,031 | 399,203 | |||||||||
|
Workers’ compensation obligations
|
233,407 | 237,574 | |||||||||
|
Accrued postretirement benefit costs
|
1,368,686 | 959,222 | |||||||||
|
Other noncurrent liabilities
|
386,256 | 330,658 | |||||||||
|
Total liabilities
|
7,142,193 | 4,670,989 | |||||||||
|
Minority interests
|
33,337 | 2,550 | |||||||||
|
Stockholders’ equity
|
|||||||||||
|
Preferred Stock — $0.01 per share par value;
10,000,000 shares authorized, no shares issued or
outstanding as of December 31, 2006 or 2005
|
— | — | |||||||||
|
Series A Junior Participating Preferred Stock —
1,500,000 shares authorized, no shares issued or
outstanding as of December 31, 2006 or 2005
|
— | — | |||||||||
|
Perpetual Preferred Stock — 750,000 shares
authorized, no shares issued or outstanding as of
December 31, 2006 or 2005
|
— | — | |||||||||
|
Series Common Stock — $0.01 per share par
value; 40,000,000 shares authorized, no shares issued or
outstanding as of December 31, 2006 or 2005
|
— | — | |||||||||
|
Common Stock — $0.01 per share par value;
800,000,000 shares authorized, 266,554,157 shares
issued and 263,846,839 shares outstanding as of
December 31, 2006 and 400,000,000 shares authorized,
263,879,762 shares issued and 263,357,402 shares
outstanding as of December 31, 2005
|
2,666 | 2,638 | |||||||||
|
Additional paid-in capital
|
1,572,614 | 1,497,454 | |||||||||
|
Retained earnings
|
1,115,994 | 729,086 | |||||||||
|
Accumulated other comprehensive loss
|
(249,058 | ) | (46,795 | ) | |||||||
|
Treasury shares, at cost: 2,707,318 shares as of
December 31, 2006 and 522,360 shares as of
December 31, 2005
|
(103,690 | ) | (3,916 | ) | |||||||
|
Total stockholders’ equity
|
2,338,526 | 2,178,467 | |||||||||
|
Total liabilities and stockholders’ equity
|
$ | 9,514,056 | $ | 6,852,006 | |||||||
See accompanying notes to consolidated financial statements
F-3
Table of Contents
PEABODY ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
| Year Ended December 31, | ||||||||||||||
| 2006 | 2005 | 2004 | ||||||||||||
| (Dollars in thousands) | ||||||||||||||
|
Cash Flows From Operating Activities
|
||||||||||||||
|
Net income
|
$ | 600,697 | $ | 422,653 | $ | 175,387 | ||||||||
|
Loss from discontinued operations
|
— | — | 2,839 | |||||||||||
|
Income from continuing operations
|
600,697 | 422,653 | 178,226 | |||||||||||
|
Adjustments to reconcile income from continuing operations to
net cash provided by operating activities:
|
||||||||||||||
|
Depreciation, depletion and amortization
|
377,210 | 316,114 | 270,159 | |||||||||||
|
Deferred income taxes
|
(189,243 | ) | (24,962 | ) | (31,925 | ) | ||||||||
|
Amortization of debt discount and debt issuance costs
|
7,410 | 6,938 | 8,330 | |||||||||||
|
Net gain on disposal or exchange of assets
|
(132,162 | ) | (101,487 | ) | (23,829 | ) | ||||||||
|
Income from equity affiliates
|
(23,852 | ) | (30,096 | ) | (12,399 | ) | ||||||||
|
Dividends received from equity affiliates
|
28,063 | 7,552 | 13,614 | |||||||||||
|
Changes in current assets and liabilities, net of acquisitions:
|
||||||||||||||
|
Accounts receivable, net of sale
|
(103,399 | ) | (52,757 | ) | (34,649 | ) | ||||||||
|
Inventories
|
(38,208 | ) | (67,125 | ) | (57,781 | ) | ||||||||
|
Net assets from coal trading activities
|
(9,419 | ) | 11,377 | (3,583 | ) | |||||||||
|
Other current assets
|
(24,108 | ) | (10,769 | ) | (1,438 | ) | ||||||||
|
Accounts payable and accrued expenses
|
88,014 | 173,919 | 66,576 | |||||||||||
|
Asset retirement obligations
|
(52 | ) | (981 | ) | (6,571 | ) | ||||||||
|
Workers’ compensation obligations
|
391 | 11,390 | 10,479 | |||||||||||
|
Accrued postretirement benefit costs
|
13,942 | 19,719 | (32,499 | ) | ||||||||||
|
Contributions to pension plans
|
(6,146 | ) | (7,162 | ) | (62,082 | ) | ||||||||
|
Other, net
|
6,588 | 28,436 | 3,132 | |||||||||||
|
Net cash provided by operating activities
|
595,726 | 702,759 | 283,760 | |||||||||||
|
Cash Flows From Investing Activities
|
||||||||||||||
|
Acquisition of Excel Coal, net of cash acquired
|
(1,507,775 | ) | — | — | ||||||||||
|
Other acquisitions, net
|
(44,538 | ) | — | (429,061 | ) | |||||||||
|
Additions to property, plant, equipment and mine development
|
(477,721 | ) | (384,304 | ) | (151,944 | ) | ||||||||
|
Purchase of mining and related assets
|
— | (141,195 | ) | — | ||||||||||
|
Federal coal lease expenditures
|
(178,193 | ) | (118,364 | ) | (114,653 | ) | ||||||||
|
Proceeds from disposal of assets, net of notes receivable
|
77,579 | 76,227 | 39,339 | |||||||||||
|
Additions to advance mining royalties
|
(11,021 | ) | (14,566 | ) | (16,239 | ) | ||||||||
|
Investments in joint ventures
|
(2,149 | ) | (2,000 | ) | (32,472 | ) | ||||||||
|
Net cash used in investing activities
|
(2,143,818 | ) | (584,202 | ) | (705,030 | ) | ||||||||
|
Cash Flows From Financing Activities
|
||||||||||||||
|
Proceeds from long-term debt
|
2,580,295 | 11,734 | 700,013 | |||||||||||
|
Payments of long-term debt
|
(1,045,973 | ) | (20,198 | ) | (482,924 | ) | ||||||||
|
Common stock repurchase
|
(99,774 | ) | — | — | ||||||||||
|
Dividends paid
|
(63,456 | ) | (44,535 | ) | (32,568 | ) | ||||||||
|
Payment of debt issuance costs
|
(40,611 | ) | — | (12,875 | ) | |||||||||
|
Excess tax benefit related to stock options exercised
|
33,173 | — | — | |||||||||||
|
Net proceeds from equity offering
|
— | — | 383,125 | |||||||||||
|
Proceeds from stock options exercised
|
15,617 | 22,573 | 27,266 | |||||||||||
|
Distributions to minority interests
|
(6,664 | ) | (2,498 | ) | (1,007 | ) | ||||||||
|
Increase (decrease) of securitized interests in accounts
receivable
|
(5,800 | ) | 25,000 | 110,000 | ||||||||||
|
Proceeds from employee stock purchases
|
4,518 | 3,009 | 2,374 | |||||||||||
|
Net cash provided by (used in) financing activities
|
1,371,325 | (4,915 | ) | 693,404 | ||||||||||
|
Net increase (decrease) in cash and cash equivalents
|
(176,767 | ) | 113,642 | 272,134 | ||||||||||
|
Cash and cash equivalents at beginning of year
|
503,278 | 389,636 | 117,502 | |||||||||||
|
Cash and cash equivalents at end of year
|
$ | 326,511 | $ | 503,278 | $ | 389,636 | ||||||||
See accompanying notes to consolidated financial statements
F-4
Table of Contents
PEABODY ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS’
EQUITY
| Accumulated | |||||||||||||||||||||||||||||||
| Additional | Other | Other | Total | ||||||||||||||||||||||||||||
| Common | Paid-In | Employee | Comprehensive | Retained | Treasury | Stockholders’ | |||||||||||||||||||||||||
| Stock | Capital | Stock Loans | Loss | Earnings | Stock | Equity | |||||||||||||||||||||||||
| (Dollars in thousands) | |||||||||||||||||||||||||||||||
|
December 31, 2003
|
$ | 2,190 | $ | 1,007,008 | $ | (31 | ) | $ | (81,572 | ) | $ | 208,149 | $ | (3,687 | ) | $ | 1,132,057 | ||||||||||||||
|
Comprehensive income:
|
|||||||||||||||||||||||||||||||
|
Net income
|
— | — | — | — | 175,387 | — | 175,387 | ||||||||||||||||||||||||
|
Increase in fair value of cash flow hedges (net of $9,945 tax
provision)
|
— | — | — | 14,915 | — | — | 14,915 | ||||||||||||||||||||||||
|
Minimum pension liability adjustment (net of $4,026 tax
provision)
|
— | — | — | 6,039 | — | — | 6,039 | ||||||||||||||||||||||||
|
Comprehensive income
|
— | 196,341 | |||||||||||||||||||||||||||||
|
Issuance of common stock in connection with equity offering, net
of expenses
|
352 | 382,773 | — | — | — | — | 383,125 | ||||||||||||||||||||||||
|
Dividends paid
|
— | — | — | — | (32,568 | ) | — | (32,568 | ) | ||||||||||||||||||||||
|
Loan repayments
|
— | — | 31 | — | — | — | 31 | ||||||||||||||||||||||||
|
Stock options exercised
|
54 | 27,621 | — | — | — | — | 27,675 | ||||||||||||||||||||||||
|
Income tax benefits from stock options exercised
|
— | 15,718 | — | — | — | — | 15,718 | ||||||||||||||||||||||||
|
Employee stock purchases
|
— | 2,343 | — | — | — | — | 2,343 | ||||||||||||||||||||||||
|
Employee stock grants
|
— | — | — | — | — | — | — | ||||||||||||||||||||||||
|
Share-based compensation
|
— | 99 | — | — | — | — | 99 | ||||||||||||||||||||||||
|
Shares repurchased
|
— | — | — | — | — | (229 | ) | (229 | ) | ||||||||||||||||||||||
|
December 31, 2004
|
$ | 2,596 | $ | 1,435,562 | $ | — | $ | (60,618 | ) | $ | 350,968 | $ | (3,916 | ) | $ | 1,724,592 | |||||||||||||||
|
Comprehensive income:
|
|||||||||||||||||||||||||||||||
|
Net income
|
— | — | — | — | 422,653 | — | 422,653 | ||||||||||||||||||||||||
|
Increase in fair value of cash flow hedges (net of $7,613 tax
provision)
|
— | — | — | 11,421 | — | — | 11,421 | ||||||||||||||||||||||||
|
Minimum pension liability adjustment (net of $1,601 tax
provision)
|
— | — | — | 2,402 | — | — | 2,402 | ||||||||||||||||||||||||
|
Comprehensive income
|
— | 436,476 | |||||||||||||||||||||||||||||
|
Dividends paid
|
— | — | — | — | (44,535 | ) | — | (44,535 | ) | ||||||||||||||||||||||
|
Stock options exercised
|
36 | 22,627 | — | — | — | — | 22,663 | ||||||||||||||||||||||||
|
Income tax benefits from stock options exercised
|
— | 30,437 | — | — | — | — | 30,437 | ||||||||||||||||||||||||
|
Employee stock purchases
|
2 | 3,007 | — | — | — | — | 3,009 | ||||||||||||||||||||||||
|
Employee stock grants
|
4 | (4 | ) | — | — | — | — | — | |||||||||||||||||||||||
|
Share-based compensation
|
— | 5,825 | — | — | — | — | 5,825 | ||||||||||||||||||||||||
|
December 31, 2005
|
$ | 2,638 | $ | 1,497,454 | $ | — | $ | (46,795 | ) | $ | 729,086 | $ | (3,916 | ) | $ | 2,178,467 | |||||||||||||||
|
Comprehensive income:
|
|||||||||||||||||||||||||||||||
|
Net income
|
— | — | — | — | 600,697 | — | 600,697 | ||||||||||||||||||||||||
|
Increase in fair value of cash flow hedges (net of $16,230 tax
provision)
|
— | — | — | 24,347 | — | — | 24,347 | ||||||||||||||||||||||||
|
Minimum pension liability adjustment (net of $16,842 tax
provision)
|
— | — | — | 22,377 | — | — | 22,377 | ||||||||||||||||||||||||
|
Comprehensive income
|
647,421 | ||||||||||||||||||||||||||||||
|
Postretirement plans and workers’ compensation obligations
(net of $149,499 tax benefit):
|
|||||||||||||||||||||||||||||||
|
Accumulated actuarial loss, net of tax
|
— | — | — | (241,954 | ) | — | — | ||||||||||||||||||||||||
|
Prior service cost, net of tax
|
— | — | — | (7,033 | ) | — | — | ||||||||||||||||||||||||
| (248,987 | ) | (248,987 | ) | ||||||||||||||||||||||||||||
|
Dividends paid
|
— | — | — | — | (63,456 | ) | — | (63,456 | ) | ||||||||||||||||||||||
|
Stock options exercised
|
20 | 15,600 | — | — | — | — | 15,620 | ||||||||||||||||||||||||
|
Share-based compensation
|
— | 21,877 | — | — | — | — | 21,877 | ||||||||||||||||||||||||
|
Income tax benefits from stock options exercised
|
— | 33,173 | — | — | — | — | 33,173 | ||||||||||||||||||||||||
|
Employee stock purchases
|
2 | 4,516 | — | — | — | — | 4,518 | ||||||||||||||||||||||||
|
Employee stock grants
|
6 | (6 | ) | — | — | — | — | — | |||||||||||||||||||||||
|
Advance stripping adjustment (net of $95,189 tax benefit)
|
— | — | — | — | (150,333 | ) | — | (150,333 | ) | ||||||||||||||||||||||
|
Shares repurchased
|
— | — | — | — | — | (99,774 | ) | (99,774 | ) | ||||||||||||||||||||||
|
December 31, 2006
|
$ | 2,666 | $ | 1,572,614 | $ | — | $ | (249,058 | ) | $ | 1,115,994 | $ | (103,690 | ) | $ | 2,338,526 | |||||||||||||||
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 |
| Basis of Presentation |
The consolidated financial statements include the accounts of
Peabody Energy Corporation (“the Company”) and its
affiliates. All intercompany transactions, profits and balances
have been eliminated in consolidation.
| Description of Business |
The Company is engaged in the mining of steam coal for sale
primarily to electric utilities and metallurgical coal for sale
to industrial customers. The Company’s mining operations
are located in the United States and Australia, and include an
equity interest in mining operations in Venezuela. In addition
to the Company’s mining operations, the Company markets,
brokers and trades coal. The Company’s other energy related
commercial activities include the development of mine-mouth
coal-fueled generating plants, the management of its vast coal
reserve and real estate holdings, coalbed methane production and
Btu conversion technologies. The Company’s Btu conversion
projects are designed to expand the uses of coal through various
technologies such as
coal-to-liquids and
coal gasification.
| New Accounting Pronouncements |
In September 2006, the Financial Accounting Standards Board
(“FASB”) issued Statement of Financial Accounting
Standard (“SFAS”) No. 158, “Employers’
Accounting for Defined Benefit Pension and Other Postretirement
Plans” (“SFAS No. 158”). For fiscal
years ending after December 15, 2006,
SFAS No. 158 requires recognition of the funded status
of pension and other postretirement benefit plans (an asset for
overfunded status or a liability for underfunded status) in a
company’s balance sheet. In addition, the standard requires
recognition of actuarial gains and losses, prior service cost,
and any remaining transition amounts from the initial
application of SFAS No. 87, “Employers’
Accounting for Pensions”
(“SFAS No. 87”) and SFAS No. 106,
“Employers’ Accounting for Postretirement Benefits
Other Than Pensions” (“SFAS No. 106”)
when determining a plan’s funded status, with a
corresponding charge to accumulated other comprehensive income
(loss).
The Company adopted SFAS No. 158 on December 31,
2006, and as a result, recorded a noncurrent liability of
$376.1 million, which reflected the net underfunded status
of the pension, retiree healthcare and workers’
compensation plans. The funded status of each plan was measured
as the difference between the fair value of the assets and the
projected benefit obligation (the “funded status”).
SFAS No. 158 did not impact net income. The impact to
the balance sheet was as follows (see Notes 14, 15,
and 16 for additional details):
| Before Application | After Application | |||||||||||
| of SFAS No. 158 | Adjustments | of SFAS No. 158 | ||||||||||
| (Dollars in thousands) | ||||||||||||
|
Workers’ compensation obligations
|
$ | 237,965 | $ | (4,558 | ) | $ | 233,407 | |||||
|
Accrued postretirement benefit costs
|
973,164 | 395,522 | 1,368,686 | |||||||||
|
Other noncurrent liabilities (includes long-term pension and
UMWA Combined Fund liabilities)
|
375,485 | (14,855 | ) | 360,630 | ||||||||
|
Deferred income taxes (long-term liability)
|
344,712 | (149,499 | ) | 195,213 | ||||||||
|
Total liabilities
|
6,915,583 | 226,610 | 7,142,193 | |||||||||
|
Accumulated other comprehensive loss
|
(22,448 | ) | (226,610 | ) | (249,058 | ) | ||||||
|
Total stockholders’ equity
|
2,565,136 | (226,610 | ) | 2,338,526 | ||||||||
F-6
Table of Contents
PEABODY ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
In June 2006, the FASB issued Interpretation No. 48,
“Accounting for Uncertainty in Income Taxes — an
interpretation of FASB Statement No. 109”
(“FIN No. 48”). This interpretation
prescribes a recognition threshold and measurement attribute for
the financial statement recognition and measurement of a tax
position taken or expected to be taken in a tax return.
FIN No. 48 also provides guidance on derecognition,
classification, interest and penalties, accounting in interim
periods, disclosure and transition. This interpretation is
effective for fiscal years beginning after December 15,
2006 (January 1, 2007 for the Company). Any adjustments
required upon the adoption of this interpretation must be
recorded directly to retained earnings in the year of adoption
and reported as a change in accounting principle. The Company
expects the adoption of FIN No. 48 will not have a
material impact on its results of operations or financial
position.
In March 2005, the Emerging Issues Task Force (“EITF”)
issued EITF Issue
No. 04-6,
“Accounting for Stripping Costs in the Mining
Industry” (“EITF Issue
No. 04-6”).
EITF Issue
No. 04-6 and its
interpretations require stripping costs incurred during a period
to be attributed only to the inventory costs of the coal that is
extracted during that same period. The Company adopted EITF
Issue No. 04-6 on
January 1, 2006 and utilized the cumulative effect
adjustment approach whereby the cumulative effect adjustment
reduced retained earnings by $150.3 million, net of tax.
This non-cash item is excluded from the consolidated statements
of cash flows. Advance stripping costs are primarily expensed as
incurred.
In December 2004, the FASB issued SFAS No. 123
(revised 2004), “Share-Based Payment”
(“SFAS No. 123(R)”), which is a revision of
SFAS No. 123, “Accounting for Stock-Based
Compensation” (“SFAS No. 123”).
SFAS No. 123(R) supersedes APB Opinion No. 25,
“Accounting for Stock Issued to Employees” (“APB
Opinion No. 25”) and amends FASB Statement
No. 95, “Statement of Cash Flows.” Generally, the
approach in SFAS No. 123(R) is similar to the approach
described in SFAS No. 123. However,
SFAS No. 123(R) requires all share-based payments to
employees, including employee stock options, to be recognized in
the income statement based on their fair values at the grant
date.
The Company adopted SFAS No. 123(R) on January 1,
2006 and used the modified prospective method, in which
compensation cost is recognized beginning with the effective
date (a) based on the requirements of
SFAS No. 123(R) for all share-based payments granted
or modified after the effective date and (b) based on the
requirements of SFAS No. 123 for all awards granted to
employees prior to the effective date of
SFAS No. 123(R) that remain unvested on the effective
date. Prior to January 1, 2006, the Company had elected to
apply APB Opinion No. 25 and related interpretations in
accounting for its stock option plans, as permitted under
SFAS No. 123 and SFAS No. 148
“Accounting for Stock-Based Compensation-Transition and
Disclosure.” Beginning in 2006, SFAS No. 123(R)
also requires that excess income tax benefits from stock options
exercised be recorded as financing cash inflow on the statements
of cash flows. The excess income tax benefit from stock option
exercises during 2005 and 2004 is included in operating cash
flows, netted in deferred tax activity.
| Sales |
The Company’s revenue from coal sales is realized and
earned when risk of loss passes to the customer. Coal sales are
made to the Company’s customers under the terms of coal
supply agreements, most of which are long-term (greater than one
year). Under the typical terms of these coal supply agreements,
title and risk of loss transfer to the customer at the mine or
port, where coal is loaded to the rail, barge, ocean-going
vessel, truck or other transportation source(s) that serves each
of the Company’s mines. The Company incurs certain
“add-on” taxes and fees on coal sales. Coal sales are
reported including taxes and fees charged by various federal and
state governmental bodies.
F-7
Table of Contents
PEABODY ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
| Other Revenues |
Other revenues include royalties related to coal lease
agreements, sales agency commissions, farm income, coalbed
methane revenues, property and facility rentals, generation
development activities, net revenues from coal trading
activities accounted for under SFAS No. 133,
“Accounting for Derivative Instruments and Hedging
Activities” (“SFAS No. 133”), as
amended, and contract termination or restructuring payments.
Royalty income generally results from the lease or sublease of
mineral rights to third parties, with payments based upon a
percentage of the selling price or an amount per ton of coal
produced. Certain agreements require minimum annual lease
payments regardless of the extent to which minerals are produced
from the leasehold. The terms of these agreements generally
range from specified periods of five to 15 years, or can be
for an unspecified period until all reserves are depleted.
| Discontinued Operations |
The Company classifies items within discontinued operations in
the consolidated statements of operations when the operations
and cash flows of a particular component (defined as operations
and cash flows that can be clearly distinguished, operationally
and for financial reporting purposes, from the rest of the
entity) of the Company have been (or will be) eliminated from
the ongoing operations of the Company as a result of a disposal
transaction, and the Company will no longer have any significant
continuing involvement in the operations of that component.
Discontinued operations for the year ended December 31,
2004, reflected a $2.8 million loss, net of taxes, related
to the Company’s former Citizens Power subsidiary.
| 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. Prior to the adoption of EITF
Issue No. 04-6,
advance stripping consisted of the costs to remove overburden
above an unmined coal seam as part of the surface mining
process. As a result of the adoption of EITF Issue
No. 04-6 on
January 1, 2006, advance stripping costs are primarily
expensed as incurred.
| Assets and Liabilities from Coal Trading Activities |
The Company’s coal trading activities are evaluated under
SFAS No. 133, as amended. Trading contracts that meet
the SFAS No. 133 definition of a derivative are
accounted for at fair value, while contracts that do not qualify
as derivatives are accounted for under the accrual method. All
trading contracts are recorded subject to the requirements of
EITF Issue
No. 02-3,
“Issues Involved in Accounting for Derivative Contracts
Held for Trading Purposes and Contracts Involved in Energy
Trading and Risk Management Activities” (“EITF Issue
No. 02-3”).
The Company’s trading contracts are reflected at fair value
and are included in “Assets and liabilities from coal
trading activities” in the consolidated balance sheets as
of December 31, 2006 and 2005. Under EITF Issue
No. 02-3, all
mark-to-market gains
and losses on energy trading contracts (including derivatives
and hedged contracts) are presented on a net basis in the
statement of operations, even if
F-8
Table of Contents
PEABODY ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
settled physically. The Company’s consolidated statements
of operations reflect revenues related to all
mark-to-market trading
contracts on a net basis in “Other revenues.”
| Property, Plant, Equipment and Mine Development |
Property, plant, equipment and mine development are recorded at
cost. Interest costs applicable to major asset additions are
capitalized during the construction period, including
$3.0 million, $0.1 million and $0.2 million for
the years ended December 31, 2006, 2005 and 2004,
respectively.
Expenditures which extend the useful lives of existing plant and
equipment assets are capitalized. Maintenance and repairs are
charged to operating costs as incurred. Costs incurred to
develop coal mines or to expand the capacity of operating mines
are capitalized. Costs incurred to maintain current production
capacity at a mine and exploration expenditures are charged to
operating costs as incurred. Costs to acquire computer hardware
and the development and/or purchase of software for internal use
are capitalized and depreciated over the estimated useful lives.
Coal reserves are recorded at cost, or at fair value in the case
of acquired businesses. As of December 31, 2006 and 2005,
the net book value of coal reserves totaled $5.2 billion
and $3.7 billion, respectively. These amounts included
$2.1 billion and $1.8 billion at December 31,
2006 and 2005, respectively, attributable to properties where
the Company was not currently engaged in mining operations or
leasing to third parties and, therefore, the coal reserves were
not currently being depleted. Included in the book value of coal
reserves are mineral rights for leased coal interests including
advance royalties and the net book value of these mineral rights
was $3.5 billion and $2.1 billion at December 31,
2006 and 2005, respectively.
Depletion of coal reserves and amortization of advance royalties
is computed using the
units-of-production
method utilizing only proven and probable reserves in the
depletion base. Mine development costs are principally amortized
over the estimated lives of the mines using the straight-line
method.
Depreciation of plant and equipment (excluding life of mine
assets) is computed using the straight-line method over the
estimated useful lives as follows:
| Years | ||||
|
Building and improvements
|
10 to 30 | |||
|
Machinery and equipment
|
3 to 30 | |||
|
Leasehold improvements
|
Life of Lease | |||
In addition, certain plant and equipment assets associated with
mining are depreciated using the straight-line method over the
estimated life of the mine, which varies from one to
33 years.
| Goodwill and Intangible Assets |
Assets and liabilities acquired in business combinations are
accounted for using the purchase method and recorded at their
respective fair values. Substantially all goodwill is assigned
to the reporting unit that acquires a business. A reporting unit
is an operating segment as defined in SFAS No. 131,
“Disclosures about Segments of an Enterprise and Related
Information,” or a business one level below an operating
segment if discrete financial information is prepared and
regularly reviewed by the segment manager. The Company conducts
a formal impairment test of goodwill on an annual basis and
between annual tests if an event occurs or circumstances change
that would more likely than not reduce the fair value of a
reporting unit below its carrying value. Under the impairment
test, if a reporting unit’s carrying amount exceeds its
estimated fair value, a goodwill impairment is recognized to the
extent that the reporting unit’s carrying amount of
goodwill exceeds the implied fair value of the goodwill.
F-9
Table of Contents
PEABODY ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
All of the Company’s intangibles (other than goodwill) are
subject to amortization. Intangibles consist of contractual
obligations and are amortized based on tons sold. These
intangibles are also subject to evaluation for potential
impairment if an event occurs or circumstances change that
indicate the carrying amount may not be recoverable.
| 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 from equity affiliates.” The book value of the
Company’s equity method investments as of December 31,
2006 and 2005 was $65.5 million and $97.2 million,
respectively, and is reported in “Investments and other
assets” in the consolidated balance sheets. Included in the
Company’s equity method investments was its 25.5% interest
in Carbones del Guasare, which owns and operates the Paso Diablo
Mine in Venezuela. The Company’s investment in Paso Diablo
was $60.1 million and $50.3 million as of
December 31, 2006 and 2005, respectively. The Company
recorded income from this equity affiliate of
$28.0 million, $20.0 million and $1.2 million for
the years ended December 31, 2006, 2005 and 2004,
respectively, which is reported in “Income from equity
affiliates” in the consolidated statements of operations.
| Generation Development Costs |
Development costs related to coal-based electricity generation,
including expenditures for permitting and licensing, are
capitalized at cost under the guidelines in
SFAS No. 142, “Goodwill and Other Intangible
Assets.” Start-up
costs, as defined in Statement of Position (“SOP”)
No. 98-5,
“Reporting on the Costs of
Start-up
Activities,” are expensed as incurred. Development costs of
$21.4 million and $22.4 million were recorded as part
of “Investments and other assets” in the consolidated
balance sheets as of December 31, 2006 and 2005,
respectively.
| Asset Retirement Obligations |
SFAS No. 143, “Accounting for Asset Retirement
Obligations” (“SFAS No. 143”) addresses
financial accounting and reporting for obligations associated
with the retirement of tangible long-lived assets and the
associated asset retirement costs. The Company’s asset
retirement obligation (“ARO”) liabilities primarily
consist of spending estimates related to reclaiming surface land
and support facilities at both surface and underground mines in
accordance with federal and state reclamation laws 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 credit-
F-10
Table of Contents
PEABODY ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
adjusted risk-free rate. The Company also recognizes an
obligation for contemporaneous reclamation liabilities incurred
as a result of surface mining. Contemporaneous reclamation
consists primarily of grading, topsoil replacement and
revegetation of backfilled pit areas.
| Environmental Liabilities |
Included in “Other noncurrent liabilities” are
accruals for other environmental matters that are recorded in
operating expenses when it is probable that a liability has been
incurred and the amount of the liability can be reasonably
estimated. Accrued liabilities are exclusive of claims against
third parties and are not discounted. In general, costs related
to environmental remediation are charged to expense.
| Income Taxes |
Income taxes are accounted for using a balance sheet approach in
accordance with SFAS No. 109, “Accounting for
Income Taxes.” The Company accounts for deferred income
taxes by applying statutory tax rates in effect at the date of
the balance sheet to differences between the book and tax basis
of assets and liabilities. A valuation allowance is established
if it is “more likely than not” that the related tax
benefits will not be realized. In determining the appropriate
valuation allowance, the Company considers projected realization
of tax benefits based on expected levels of future taxable
income, available tax planning strategies, and the overall
deferred tax position.
| Postretirement Health Care and Life Insurance Benefits |
The Company accounts for postretirement benefits other than
pensions in accordance with SFAS No. 106, which
requires the costs of benefits to be provided to be accrued over
the employees’ period of active service. These costs are
determined on an actuarial basis. As a result of the adoption of
SFAS No. 158 on December 31, 2006, the
Company’s consolidated balance sheet as of
December 31, 2006 reflects the funded status of
postretirement benefits.
| Multi-Employer Benefit Plans |
The Company has an obligation to contribute to two plans
established by the Coal Industry Retiree Health Benefits Act of
1992 (the “Coal Act”) — the “Combined
Fund” and the “1992 Benefit Plan”. A third fund,
the 1993 Benefit Fund (the “1993 Benefit Plan”), was
originally established through collective bargaining, but is now
a statutory plan under the terms of the 2006 Tax Relief and
Health Care Act. The Combined Fund obligations are accounted for
in accordance with EITF Issue
No. 92-13,
“Accounting for Estimated Payments in Connection with the
Coal Industry Retiree Health Benefit Act of 1992,” as
determined on an actuarial basis. The 1992 Benefit Plan and 1993
Benefit Plan qualify as multi-employer plans under
SFAS No. 106 and expense is recognized as
contributions are made.
| Pension Plans |
The Company sponsors non-contributory defined benefit pension
plans accounted for in accordance with SFAS No. 87,
which requires that the cost to provide the benefits be accrued
over the employees’ period of active service. These costs
are determined on an actuarial basis. SFAS No. 158
amended SFAS No. 87 and as a result of the adoption of
SFAS No. 158 on December 31, 2006, the
Company’s consolidated balance sheet as of that date
reflects the funded status of the defined benefit pension plans.
The Company also participates in two multi-employer pension
plans, the United Mine Workers of America 1950 Pension Plan (the
“1950 Plan”) and the United Mine Workers of America
1974 Pension Plan (the “1974 Plan”). These plans
qualify as multi-employer plans under SFAS No. 87 and
expense is recognized as contributions are made.
F-11
Table of Contents
PEABODY ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
| Postemployment Benefits |
The Company provides postemployment benefits to qualifying
employees, former employees and dependents and accounts for
these benefits on the accrual basis in accordance with
SFAS No. 112 “Employers’ Accounting for
Postemployment Benefits.” Postemployment benefits include
workers’ compensation occupational disease, which is
accounted for on the actuarial basis over the employees’
period of active service; workers’ compensation traumatic
injury claims, which are accounted for based on estimated loss
rates applied to payroll and claim reserves determined by
independent actuaries and claims administrators; disability
income benefits, which are accrued when a claim occurs; and
continuation of medical benefits, which are recognized when the
obligation occurs. As a result of the adoption of
SFAS No. 158 on December 31, 2006, the
Company’s consolidated balance sheet as of
December 31, 2006 reflects the funded status of
postemployment benefits.
| Derivatives |
SFAS No. 133, as amended, requires the recognition at
fair value of all derivatives as assets or liabilities on the
consolidated balance sheets. Gains or losses from derivative
financial instruments designated as fair value hedges are
recognized immediately in the consolidated statements of
operations, along with the offsetting gain or loss related to
the underlying hedged item.
Gains or losses on derivative financial instruments designated
as cash flow hedges are recorded as a separate component of
stockholders’ equity until settlement (or until hedge
ineffectiveness is determined), whereby gains or losses are
reclassified to the consolidated statements of operations in
conjunction with the recognition of the underlying hedged item.
To the extent that the periodic changes in the fair value of the
derivatives are not effective, or if the hedge ceases to qualify
for hedge accounting, the ineffective portion of the periodic
non-cash changes are recorded in “Operating costs and
expenses” in the consolidated statement of operations in
the period of the change. The potential for hedge
ineffectiveness is only present in the design of the hedge
relationship in the Company’s cash flow hedges of
anticipated fuel purchases (see Note 2 for additional
details).
| Use of Estimates in the Preparation of the Consolidated Financial Statements |
The preparation of financial statements in conformity with
generally accepted accounting principles requires management to
make estimates and assumptions that affect the reported amounts
of assets and liabilities and disclosure of contingent assets
and liabilities at the date of the financial statements and
reported amounts of revenues and expenses during the reporting
period. Actual results could differ from those estimates.
In particular, the Company has significant long-term liabilities
relating to retiree health care, work-related injuries and
illnesses and defined benefit pension plans. Each of these
liabilities is actuarially determined and the Company uses
various actuarial assumptions, including the discount rate and
future cost trends, to estimate the costs and obligations for
these items. In addition, the Company has significant asset
retirement obligations that involve estimations of costs to
remediate mining lands and the timing of cash outlays for such
costs. If these assumptions do not materialize as expected,
actual cash expenditures and costs incurred could differ
materially from current estimates. Moreover, regulatory changes
could increase the obligation to satisfy these or additional
obligations.
Finally, in evaluating the valuation allowance related to the
Company’s deferred tax assets, the Company takes into
account various factors, including the expected level of future
taxable income and available tax planning strategies. If actual
results differ from the assumptions made in the evaluation of
the valuation allowance, the Company may record a change in
valuation allowance through income tax expense in the period
such determination is made.
F-12
Table of Contents
PEABODY ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
| Impairment of Long-Lived Assets |
The Company records impairment losses on long-lived assets used
in operations when events and circumstances indicate that assets
might be impaired and the undiscounted cash flows estimated to
be generated by those assets under various assumptions are less
than the carrying amounts of the assets. Impairment losses are
measured by comparing the estimated fair value of the impaired
asset to its carrying amount. There were no impairment losses
recorded during the periods covered by the consolidated
financial statements.
| Fair Value of Financial Instruments |
SFAS No. 107, “Disclosures About Fair Value of
Financial Instruments,” defines the fair value of a
financial instrument as the amount at which the instrument could
be exchanged in a current transaction between willing parties,
other than in a forced or liquidation sale. See Note 22 for
additional information.
| Foreign Currency Translation |
For the Company’s foreign subsidiaries where the functional
currency is the U.S. dollar, monetary assets and
liabilities are translated at year-end exchange rates while
non-monetary items are translated at historical rates. Income
and expense accounts are translated at the average rates in
effect during the year, except for those expenses related to
balance sheet amounts that are remeasured at historical exchange
rates. The Company has foreign subsidiaries whose functional
currency is the U.S. dollar during the years ended
December 31, 2006, 2005, and 2004. Gains and losses from
foreign currency remeasurement are included in the consolidated
statements of operations. The foreign currency remeasurement
loss for the year ended December 31, 2006 was
$12.8 million. Gains and losses from foreign currency
remeasurement did not have a material impact on the
Company’s consolidated financial position or results of
operations for the years ended December 31, 2005 and 2004.
| (2) | Risk Management and Derivative Financial Instruments |
The Company is exposed to various types of risk in the normal
course of business, including fluctuations in commodity prices,
interest rates and foreign currency exchange rates. These risks
are actively monitored to ensure compliance with the risk
management policies of the Company. In most cases, commodity
price risk (excluding coal trading activities) related to the
sale of coal is mitigated through the use of long-term,
fixed-price contracts rather than financial instruments, while
commodity price risk related to materials used in production is
managed through the use of fixed price and cost plus contracts
and derivatives. Interest rate and foreign currency exchange
risk are managed through the use of forward contracts, swaps and
options. The Company’s usage of interest rate swaps is
discussed in Note 12.
| Trading Activities |
The Company performs a value at risk analysis of its trading
portfolio, which includes
over-the-counter and
brokerage trading of coal. The use of value at risk allows
management to quantify, in dollars, on a daily basis, the price
risk inherent in its trading portfolio. The Company’s value
at risk model is based on the industry standard
variance/co-variance approach. This captures exposure related to
both option and forward positions. During the year ended
December 31, 2006, the low, high, and average values at
risk for the Company’s coal trading portfolio were
$0.7 million, $2.7 million and $1.4 million,
respectively. Further discussion of the Company’s coal
trading assets and liabilities is included in Note 5.
The Company also monitors other types of risk associated with
its coal trading activities, including credit, market liquidity
and counterparty nonperformance.
F-13
Table of Contents
PEABODY ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
| Commodity Price Risk |
In addition to the derivatives related to trading activities,
the Company manages its exposure to price volatility of
materials used in production, including diesel fuel and
explosives, through various contractual arrangements. As of
December 31, 2006, the Company had designated derivative
contracts as cash flow hedges for 137.9 million gallons of
anticipated fuel usage with contract maturities extending
through 2009. The consolidated balance sheet at
December 31, 2006 reflects unrealized gains on these cash
flow hedges of $12.9 million, which is recorded net of a
$5.2 million tax provision in “Accumulated other
comprehensive loss” (see Note 19).
A measure of ineffectiveness is inherent in hedging future
diesel fuel purchases with derivative positions based on crude
oil or other mid-distillate commodities. The amount of
ineffectiveness in the Company’s hedge of physical fuel
purchases with heating oil derivatives has historically been
insignificant and is expected to remain minimal because the
hedged diesel fuel contracts are priced based on the derivative
underlying, heating oil, adjusted for a fixed transportation
differential. Due to the market volatility of crude oil prices
and refining spreads, the measured ineffectiveness in the
Company’s hedges of physical diesel fuel purchases with
crude oil derivatives has historically been greater than for
hedging contracts based on heating oil. Due to the implicit
market volatility of crude and heating oil prices and refining
crack spreads, the Company is unable to predict the amount of
ineffectiveness that may occur in future periods, including the
loss of hedge accounting (which could be determined on a
derivative by derivative basis or in the aggregate), which may
result in increased volatility in the Company’s future
results.
Due to the inherent ineffectiveness that occurs when the price
of a derivative contract does not perfectly mirror the value of
the hedged instrument or transaction, SFAS No. 133
permits a degree of ineffectiveness within a narrowly defined
corridor, provided that critical terms of the hedge contract and
the hedged activity are sufficiently matched, including maturity
and notional amount, and provided that historical and expected
future prices are sufficiently correlated. During 2006, the
Company did not recognize any impact due to ineffectiveness of
hedging contracts that exceeded the defined corridor stipulated
in SFAS No. 133. During 2005, the Company recognized
approximately $0.1 million of lower operating costs and
expenses related to the ineffectiveness of its diesel fuel
hedges. Hedge ineffectiveness had no effect on results of
operations for the year ended December 31, 2004.
The notional amounts outstanding of 137.9 million gallons
included derivative swap contracts for 11.6 million gallons
of heating oil and 83.2 million gallons of crude oil and
collar contracts for 43.1 million gallons of crude oil that
were designated as cash flow hedges of future anticipated diesel
fuel purchases as of December 31, 2006. The heating oil
contracts are used to hedge fuel purchases in the Company’s
Eastern mining operations, and the crude oil swaps are used to
hedge incremental fuel purchases in the Company’s Eastern
mining operations with any excess over Eastern requirements
allocated to Western operations. The crude collar contracts
hedge the Company’s remaining expected diesel fuel usage in
excess of the crude and heating oil derivative swap contracts in
the Eastern and Western mining operations.
In addition to the derivatives related to trading activities and
diesel fuel, the Company enters contracts to manage its exposure
to the price volatility of explosives. As of December 31,
2006, the Company had derivative contracts designated as cash
flow hedges with notional amounts outstanding totaling
5.7 million MMBtu of natural gas, with maturities extending
through May 2009. The consolidated balance sheet as of
December 31, 2006, reflects unrealized losses on these cash
flow hedges of $6.6 million, which is recorded net of a
$2.6 million tax benefit in “Accumulated other
comprehensive loss” (see Note 19). The Company’s
hedge of explosives with natural gas is perfectly effective by
design since the contractual purchase of explosives is fixed to
the previous month’s closing price for natural gas, which
occurs in a constant ratio of MMBtu per ton in the manufacture
of explosives, plus a fixed surcharge.
F-14
Table of Contents
PEABODY ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
| Credit Risk |
The Company’s concentration of credit risk is substantially
with energy producers and marketers and electric utilities,
although it also has exposure to international steel producers,
brokerage sources and trading counterparties. The Company’s
policy is to independently evaluate each customer’s
creditworthiness prior to entering into transactions and to
constantly monitor the credit extended. In the event that the
Company engages into a transaction with a counterparty that does
not meet its credit standards, the Company may protect its
position by requiring the counterparty to provide appropriate
credit enhancement.
When appropriate, the Company has taken steps to reduce the
Company’s credit exposure to customers or counterparties
whose credit has deteriorated and who may pose a higher risk, as
determined by the Company’s credit management function, of
failure to perform under their contractual obligations. These
steps include obtaining letters of credit or cash collateral,
requiring prepayments for shipments or the creation of customer
trust accounts held for the Company’s benefit to fund
payment for coal under existing coal supply agreements.
To reduce the Company’s credit exposure related to its
trading and brokerage activities, the Company seeks to enter
into netting agreements with counterparties that permit the
Company to offset receivables and payables with such
counterparties. Counterparty risk with respect to interest rate
swap and foreign currency forwards transactions is not
considered to be significant based upon the creditworthiness of
the participating financial institutions.
| Foreign Currency Risk |
The Company utilizes currency forwards to hedge currency risk
associated with anticipated Australian dollar expenditures. As
of December 31, 2006, the Company had forward contracts
designated as cash flow hedges with notional amounts outstanding
totaling approximately A$1.35 billion, with maturities
extending through 2010. The consolidated balance sheet as of
December 31, 2006, reflects unrealized gains on the cash
flow hedges of $64.1 million, which is recorded net of a
$25.6 million tax benefit in “Accumulated other
comprehensive loss” (see Note 19).
| Employees |
As of December 31, 2006, the Company had approximately
9,200 employees. As of December 31, 2006, approximately 40%
of the Company’s hourly employees were represented by
organized labor unions and generated 14% of the 2006 coal
production. Relations with its employees and, where applicable,
organized labor are important to the Company’s success.
| United States Labor Relations |
The United Mine Workers of America (“UMWA”)
represented approximately 26% of the Company’s
subsidiaries’ hourly employees, who generated 11% of the
Company’s domestic production during the year ended
December 31, 2006. An additional 5% of the hourly employees
are represented by labor unions other than the UMWA. These
employees generated 1% of the Company’s domestic production
during the year ended December 31, 2006. Hourly workers at
the Company’s mine in Arizona are represented by the UMWA
under the Western Surface Agreement of 2000, which is effective
through September 1, 2007. The Company’s union
workforce east of the Mississippi River is primarily represented
by the UMWA. The UMWA-represented workers at one of the
Company’s eastern mines operate under a contract that
expires on December 31, 2007. The remainder of the
Company’s UMWA-represented workers in the east operate
under a recently signed, five-year labor agreement expiring
December 31, 2011. This contract replaced a contract that
had expired on December 31, 2006 and mirrors the 2007
National Bituminous Coal Wage Agreement.
F-15
Table of Contents
PEABODY ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
| Australia 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
hourly production employees. As of December 31, 2006, the
Company’s Australian hourly employees were approximately 9%
of its hourly workforce and generated 2% of its total production
in the year then ended. The labor agreement at the Wilkie Creek
Mine was renewed in June 2006 and that agreement expires in June
2009. The North Goonyella Mine operates under an agreement due
to expire in 2008, and the Metropolitan Mine operates under an
agreement that expires in June 2007.
| (3) | Resource Management and Other Commercial Events |
During 2006, the Company sold non-strategic coal reserves and
surface lands located in Kentucky and West Virginia for proceeds
of $75.3 million and recognized a gain of
$58.9 million. In June 2006, the Company exchanged with the
Bureau of Land Management approximately 63 million tons of
leased coal reserves at its Caballo mining operation for
approximately 46 million tons of coal reserves contiguous
with its North Antelope Rochelle mining operation. Based on the
fair value of the coal reserves exchanged, the Company
recognized a gain on assets exchanged totaling
$39.2 million. This non-cash addition is not included in
“Additions to property, plant, equipment and mine
development” in the consolidated statement of cash flows.
The gains from these transactions are included in “Net gain
on disposal or exchange of assets” in the consolidated
statements of operations.
The Company recognized $35.8 million during the year ended
December 31, 2006 in gains related to the settlement of
commitments by a third-party coal producer following a brokerage
contract restructuring. The gains are included in “Other
revenues” in the consolidated statements of operations.
In the fourth quarter of 2005, the Company acquired rail,
loadout and surface facilities as well as other mining assets
from another major coal producer for $84.7 million and
exchanged 60 million ton blocks of leased coal reserves in
the Powder River Basin. The Company plans to utilize these
reserves and infrastructure to accelerate the development of a
new mine, which will include adjoining Company-leased reserves.
In the first quarter of 2005, the Company purchased mining
assets from Lexington Coal Company for $61.0 million, of
which $56.5 million was recorded in “Property, plant,
equipment and mine development” and the remainder recorded
primarily to “Inventories” in the consolidated balance
sheet. The Company used the acquired assets to open a new mine
that produced 2.4 million tons of coal during 2006 and to
provide other synergies to existing properties.
In the third quarter of 2005, the Company exchanged certain idle
steam coal reserves for steam and metallurgical coal reserves as
part of a contractual dispute settlement. Under the settlement,
the Company received $10.0 million in cash, a new coal
supply agreement that partially replaced the disputed coal
supply agreement, and exchanged the idle steam coal reserves. As
a result of the final settlement and based on the fair values of
the items exchanged in the overall settlement transaction, the
Company recorded net contract losses of $4.0 million and a
gain on assets exchanged of $37.4 million. The fair value
of assets exchanged exceeded the book value by
$33.4 million and this non-cash addition is not included in
“Additions to property, plant, equipment and mine
development” in the consolidated statements of cash flows.
The gain from this transaction is included in “Net gain on
disposal or exchange of assets” in the consolidated
statements of operations.
| (4) | Business Combinations |
The results of operations for each of the acquired entities
discussed below are included in the Company’s consolidated
statements of operations from the effective date of each
acquisition. Had the
F-16
Table of Contents
PEABODY ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
results of operations for Dodge Hill Holding JV, LLC and
Carbones del Guasare been included in the Company’s results
of operations since January 1 of the year acquired, there
would have been no material effect on the Company’s
consolidated statements of operations, financial position or
cash flows.
| Excel Coal Limited |
On July 5, 2006, the Company signed a Merger Implementation
Agreement (the “Merger Implementation Agreement”) to
acquire Excel Coal Limited (“Excel”), an independent
coal company, by means of a scheme of arrangement transaction
under Australian law (the “Transaction”). The Merger
Implementation Agreement was amended on September 18, 2006,
and the Company agreed to pay A$9.50 per share (US$7.16 as
of the amendment date) for the outstanding shares of Excel. On
September 20, 2006, as part of the amended agreement, the
Company acquired 19.99% of the outstanding shares of Excel at
A$9.50 per share (the “Advance Purchase”),
resulting in payment of A$408.3 million, or
US$307.8 million. In October 2006, the Company acquired the
remaining interest in Excel for A$9.50 per share
(US$7.07 per share), a total of A$1.63 billion or
US$1.21 billion. The total acquisition price, including the
Advance Purchase and related costs, was US$1.54 billion in
cash plus assumed debt of US$293.0 million, less
US$30.0 million of cash acquired in the transaction, and
was financed with borrowings under the Company’s Senior
Unsecured Credit Facility and Senior Notes due 2016 and 2026 as
discussed in Note 12. The Excel acquisition includes three
operating mines (Wambo Open-Cut Mine, Metropolitan Mine and
Chain Valley Mine) and three development-stage mines (North
Wambo Underground Mine, Wilpinjong Mine and Millennium Mine),
with more than 500 million tons of proven and probable coal
reserves. The Company also acquired a 51.0% interest in Excelven
Pty Ltd., which owns Transportes Coal-Sea de Venezuela C.A. and
a 96.7% interest in Cosila Complejo Siderurgico Del Lago S.A.,
which owns the Las Carmelitas coal mine development project. The
results of operations of Excel are included in the
Company’s Australian Mining Operations segment from October
2006. The acquisition was accounted for as a purchase in
accordance with SFAS No. 141, “Business
Combinations.”
The preliminary purchase accounting allocations related to the
acquisition have been recorded in the accompanying consolidated
financial statements as of, and for periods subsequent to,
October 2006. The final valuation of the net assets acquired is
expected to be finalized once third-party appraisals are
completed. The following table summarizes the preliminary
estimated fair values of the assets acquired and the liabilities
assumed at the date of acquisition:
| (Dollars in thousands) | ||||
|
Accounts receivable, net
|
$ | 18,700 | ||
|
Inventories
|
32,044 | |||
|
Other current assets
|
5,336 | |||
|
Property, plant, equipment and mine development, net
|
1,897,672 | |||
|
Goodwill
|
240,667 | |||
|
Current maturities of long-term debt
|
(17,090 | ) | ||
|
Accounts payable and accrued expenses
|
(135,474 | ) | ||
|
Long-term debt less current maturities
|
(275,934 | ) | ||
|
Deferred income taxes, net
|
(179,026 | ) | ||
|
Other noncurrent assets and liabilities, net
|
(60,857 | ) | ||
|
Minority interests
|
(18,263 | ) | ||
|
Total purchase price, net of cash received of $29,995
|
$ | 1,507,775 | ||
F-17
Table of Contents
PEABODY ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
The preliminary amount allocated to goodwill reflects the excess
of the purchase price of acquiring Excel over the net fair value
of assets acquired and liabilities assumed and is primarily
attributable to customer relations and the Company’s
ability to acquire and develop coal reserves adjacent to certain
operations. The Company is conducting drilling and reserve
studies on the acquired properties, the outcome of which will
determine the fair value to be allocated to reserve assets.
Goodwill will be adjusted upon the final valuation of the net
acquired assets and allocated to reporting units. Also, in
connection with the Excel acquisition, the Company acquired
contract based intangibles consisting solely of coal supply
agreement obligations (customer contracts) that were unfavorable
based upon current market prices for similar coal in October
2006. These below market obligations were recorded at their
preliminarily determined fair value when allocating the purchase
price, resulting in a $27.7 million liability. The
liability will be amortized as the coal is shipped over an
average amortization period of approximately five years.
The following unaudited pro forma financial information presents
the combined results of operations of the Company and Excel, on
a pro forma basis, as though the companies had been combined as
of the beginning of each period presented. The pro forma
financial information does not necessarily reflect the results
of operations that would have occurred had the Company and Excel
constituted a single entity during those periods:
| Year Ended December 31, | |||||||||
| 2006 | 2005 | ||||||||
| (Dollars in thousands, | |||||||||
| except per share data) | |||||||||
|
Revenues:
|
|||||||||
|
As reported
|
$ | 5,256,315 | $ | 4,644,453 | |||||
|
Pro forma
|
5,551,347 | 4,972,791 | |||||||
|
Net income:
|
|||||||||
|
As reported
|
$ | 600,697 | $ | 422,653 | |||||
|
Pro forma
|
568,582 | 362,884 | |||||||
|
Basic earnings per share — net income:
|
|||||||||
|
As reported
|
$ | 2.28 | $ | 1.62 | |||||
|
Pro forma
|
2.16 | 1.39 | |||||||
|
Diluted earnings per share — net income:
|
|||||||||
|
As reported
|
$ | 2.23 | $ | 1.58 | |||||
|
Pro forma
|
2.11 | 1.35 | |||||||
| RAG Coal International AG |
On April 15, 2004, the Company purchased, through two
separate agreements, all of the equity interests in three coal
operations from RAG Coal International AG. The combined purchase
price, including related costs and fees, of $442.2 million
was funded from equity and debt offerings. The purchases
included two mines in Queensland, Australia that collectively
produce 6 to 7 million tons per year of metallurgical coal
and the Twentymile Mine in Colorado, which produces 8 to
9 million tons per year of steam coal. The results of
operations of the two mines in Queensland, Australia are
included in the Company’s Australian Mining Operations
segment and the results of operations of the Twentymile Mine are
included in the Company’s Western U.S. Mining
Operations segment from the April 15, 2004, purchase date.
The acquisition was accounted for as a purchase.
In connection with the acquisition of the assets of the
Australian mines and the Twentymile Mine, the Company acquired
contract based intangibles consisting solely of coal supply
agreement obligations (customer contracts) that were unfavorable
based upon current market prices for similar coal as of
F-18
Table of Contents
PEABODY ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
April 15, 2004. These below market obligations were
recorded at fair value as part of the purchase price allocation
resulting in a $46.8 million liability, which is amortized
as the coal is shipped. As of December 31, 2006, the
carrying value of these acquired contract liabilities is
$8.1 million and the estimated amortization (reduction to
“Depreciation, depletion and amortization” in the
consolidated statements of operations) is $6.5 million,
$1.0 million and $0.6 million for the years ending
December 31, 2007, 2008, and 2009, respectively.
| Dodge Hill Holding JV, LLC |
On December 29, 2004, the Company purchased the remaining
55% interest in Dodge Hill Holding JV, LLC for $7.0 million
of assumed debt that was repaid immediately upon closing,
$2.8 million of cash and contingent earn-out payments based
on annual and cumulative EBIT (as defined in the purchase
agreement) through 2007. Dodge Hill Holding JV, LLC is located
in Kentucky and operates an underground operation which mines
approximately 1.5 million tons per year. The acquisition
was accounted for as a purchase.
| Carbones del Guasare |
On December 2, 2004, the Company acquired a 25.5% equity
interest in Carbones del Guasare, S.A., from RAG Coal
International AG for a net purchase price of $32.5 million.
Carbones del Guasare, a joint venture that includes Anglo
American plc and a Venezuelan governmental partner, operates the
Paso Diablo surface mine in northwestern Venezuela. In 2006, the
mine produced approximately 6 million tons of steam coal
for electricity generators and steel producers primarily in
North America and Europe. The Company accounted for the purchase
under the equity method of accounting.
| (5) | Assets and Liabilities from Coal Trading Activities |
The Company’s coal trading portfolio included forward and
swap contracts as of December 31, 2006 and forward
contracts as of December 31, 2005. The fair value of coal
trading derivatives and related hedge contracts is set forth
below:
| December 31, 2006 | December 31, 2005 | |||||||||||||||
| Assets | Liabilities | Assets | Liabilities | |||||||||||||
| (Dollars in thousands) | ||||||||||||||||
|
Forward contracts
|
$ | 142,105 | $ | 120,718 | $ | 146,596 | $ | 131,988 | ||||||||
|
Financial swaps
|
8,268 | 6,013 | — | — | ||||||||||||
|
Other
|
— | — | — | 385 | ||||||||||||
|
Total
|
$ | 150,373 | $ | 126,731 | $ | 146,596 | $ | 132,373 | ||||||||
All of the contracts in the Company’s trading portfolio as
of December 31, 2006 were valued utilizing prices from
over-the-counter market
sources, adjusted for coal quality and traded transportation
differentials.
F-19
Table of Contents
PEABODY ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
As of December 31, 2006, the estimated future realization
of the value of the Company’s trading portfolio was as
follows:
| Percentage | ||||
| Year of Expiration | of Portfolio | |||
|
2007
|
41 | % | ||
|
2008
|
39 | % | ||
|
2009
|
15 | % | ||
|
2010
|
5 | % | ||
| 100 | % | |||
At December 31, 2006, 62% of the Company’s credit
exposure related to coal trading activities was with investment
grade counterparties and 38% was with non-investment grade
counterparties. The Company’s coal trading operations
traded 79.1 million tons, 36.2 million tons and
33.4 million tons for the years ended December 31,
2006, 2005 and 2004, respectively.
| (6) | Accounts Receivable Securitization |
The Company has established an accounts receivable
securitization program through its wholly-owned,
bankruptcy-remote subsidiary (“Seller”). Under the
program, the Company contributes undivided interests in a pool
of eligible trade receivables to the Seller, which then sells,
without recourse, to a multi-seller, asset-backed commercial
paper conduit (“Conduit”). Purchases by the Conduit
are financed with the sale of highly rated commercial paper. The
Company utilizes proceeds from the sale of its accounts
receivable as an alternative to other forms of debt, effectively
reducing its overall borrowing costs. The funding cost of the
securitization program was $1.9 million, $2.5 million
and $1.7 million for the years ended December 31,
2006, 2005 and 2004, respectively. The securitization program is
currently scheduled to expire in September 2009.
The securitization transactions have been recorded as sales,
with those accounts receivable sold to the Conduit removed from
the consolidated balance sheets. The amount of undivided
interests in accounts receivable sold to the Conduit was
$219.2 million and $225.0 million as of
December 31, 2006 and 2005, respectively.
The Seller is a separate legal entity whose assets are available
first and foremost to satisfy the claims of its creditors.
Eligible receivables, as defined in the securitization
agreement, consist of trade receivables from most of the
Company’s domestic subsidiaries, and are reduced for
certain items such as past due balances and concentration
limits. Of the eligible pool of receivables contributed to the
Seller, undivided interests in only a portion of the pool are
sold to the Conduit. The Company (the Seller) continues to own
$166.4 million of receivables as of December 31, 2006,
that represents collateral supporting the securitization
program. The Seller’s interest in these receivables is
subordinate to the Conduit’s interest in the event of
default under the securitization agreement. If the Company
defaulted under the securitization agreement or if its pool of
eligible trade receivables decreased significantly, the Company
could be prohibited from selling any additional receivables in
the future under the agreement.
F-20
Table of Contents
PEABODY ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
| (7) | Earnings per Share |
A reconciliation of weighted-average shares outstanding follows:
| Year Ended December 31, | ||||||||||||
| 2006 | 2005 | 2004 | ||||||||||
|
Weighted-average shares outstanding — basic
|
263,419,344 | 261,519,424 | 248,732,744 | |||||||||
|
Dilutive impact of stock options, restricted stock units and
performance units
|
5,746,661 | 6,494,052 | 6,079,888 | |||||||||
|
Weighted-average shares outstanding — diluted
|
269,166,005 | 268,013,476 | 254,812,632 | |||||||||
For the year ended December 31, 2004, options for three
thousand shares were excluded from the diluted earnings per
share calculations for the Company’s common stock because
they were anti-dilutive.
| (8) | Inventories |
Inventories consisted of the following:
| December 31, | |||||||||
| 2006 | 2005 | ||||||||
| (Dollars in thousands) | |||||||||
|
Materials and supplies
|
$ | 85,242 | $ | 65,942 | |||||
|
Raw coal
|
42,693 | 14,033 | |||||||
|
Saleable coal
|
87,449 | 64,274 | |||||||
|
Advance stripping
|
— | 245,522 | |||||||
|
Total
|
$ | 215,384 | $ | 389,771 | |||||
Due to an accounting change that was effective on
January 1, 2006, advance stripping costs are no longer a
separate component of inventory (see Note 1).
| (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 $106.9 million,
$108.6 million and $108.1 million for the years ended
December 31, 2006, 2005 and 2004, respectively. The net
book value of property, plant, equipment and mine development
assets under capital leases was $56.7 million and
$1.5 million as of December 31, 2006 and 2005,
respectively, related primarily to the leasing of mining
equipment.
The Company also leases coal reserves under agreements that
require royalties to be paid as the coal is mined. Certain
agreements also require minimum annual royalties to be paid
regardless of the amount of coal mined during the year. Total
royalty expense was $336.8 million, $288.1 million and
$233.9 million for the years ended December 31, 2006,
2005 and 2004, respectively.
A substantial amount of the coal mined by the Company is
produced from mineral reserves leased from the owner. One of the
major lessors is the U.S. government, from which the
Company leases substantially all of the coal it mines in Wyoming
and Colorado under terms set by Congress and administered by the
U.S. Bureau of Land Management. These leases are generally
for an initial term of ten years but may be extended by diligent
development and mining of the reserve until all economically
recoverable reserves are depleted. The Company has met the
diligent development requirements for substantially all of these
federal leases either directly through production or by
including the lease as a
F-21
Table of Contents
PEABODY ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
part of a logical mining unit with other leases upon which
development has occurred. Annual production on these federal
leases must total at least 1.0% of the original amount of coal
in the entire logical mining unit. In addition, royalties are
payable monthly at a rate of 12.5% of the gross realization from
the sale of the coal mined using surface mining methods and at a
rate of 8.0% of the gross realization for coal produced using
underground mining methods. The Company also leases coal
reserves in Arizona from The Navajo Nation and the Hopi Tribe
under leases that are administered by the U.S. Department
of the Interior. These leases expire upon exhaustion of the
leased reserves or upon the permanent ceasing of all mining
activities on the related reserves as a whole. The royalty rates
are also generally based upon a percentage of the gross
realization from the sale of coal. These rates are subject to
redetermination every ten years under the terms of the leases.
The remainder of the leased coal is generally leased from state
governments, land holding companies and various individuals. The
duration of these leases varies greatly. Typically, the lease
terms are automatically extended as long as active mining
continues. Royalty payments are generally based upon a specified
rate per ton or a percentage of the gross realization from the
sale of the coal.
Future minimum lease and royalty payments as of
December 31, 2006, are as follows:
| Capital | Operating | Coal | ||||||||||
| Year Ended December 31, | Leases | Leases | Reserves | |||||||||
| (Dollars in thousands) | ||||||||||||
|
2007
|
$ | 11,335 | $ | 102,256 | $ | 216,996 | ||||||
|
2008
|
9,986 | 86,358 | 201,839 | |||||||||
|
2009
|
11,820 | 65,906 | 142,568 | |||||||||
|
2010
|
7,843 | 56,666 | 14,664 | |||||||||
|
2011
|
7,843 | 44,720 | 10,795 | |||||||||
|
2012 and thereafter
|
23,428 | 168,076 | 46,611 | |||||||||
|
Total minimum lease payments
|
$ | 72,255 | $ | 523,982 | $ | 633,473 | ||||||
|
Less interest
|
15,548 | |||||||||||
|
Present value of minimum capital lease payments
|
$ | 56,707 | ||||||||||
During 2002, the Company entered into a transaction with Penn
Virginia Resource Partners, L.P. (“PVR”) whereby the
Company sold 120 million tons of coal reserves in exchange
for $72.5 million in cash and 2.76 million units, or
15%, of the PVR master limited partnership. The Company’s
subsidiaries leased back the coal and pay royalties as the coal
is mined. No gain or loss was recorded at the inception of this
transaction. In 2005 and 2004, the Company sold
0.838 million and 0.775 million, respectively, of the
PVR units received in the original transaction. As of
December 31, 2006 and 2005, the Company had no remaining
ownership in PVR. The PVR unit sales were accounted for under
SFAS No. 66, “Sales of Real Estate”, and
gains of $31.1 million and $15.8 million were
recognized in the years ended December 31, 2005 and 2004,
respectively. The remaining deferred gain from the sales of the
reserves and units of $13.3 million at December 31,
2006 is intended to provide for the Company’s potential
exposure to loss resulting from its continuing involvement in
the properties and will be amortized over the minimum term of
the leases.
As of December 31, 2006, certain of the Company’s
lease obligations were secured by outstanding surety bonds and
letters of credit totaling $104.2 million.
F-22
Table of Contents
PEABODY ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
| (10) | Accounts Payable and Accrued Expenses |
Accounts payable and accrued expenses consisted of the following:
| December 31, | |||||||||
| 2006 | 2005 | ||||||||
| (Dollars in thousands) | |||||||||
|
Trade accounts payable
|
$ | 462,553 | $ | 348,320 | |||||
|
Accrued taxes other than income
|
128,336 | 111,997 | |||||||
|
Accrued payroll and related benefits
|
130,306 | 110,675 | |||||||
|
Accrued health care
|
88,472 | 78,523 | |||||||
|
Workers’ compensation obligations
|
30,966 | 34,312 | |||||||
|
Other accrued benefits
|
11,647 | 21,939 | |||||||
|
Accrued royalties
|
53,260 | 50,344 | |||||||
|
Accrued environmental
|
14,390 | 23,619 | |||||||
|
Income taxes payable — Australia
|
94,692 | 23,409 | |||||||
|
Accrued interest
|
38,189 | 21,260 | |||||||
|
Other accrued expenses
|
92,232 | 43,567 | |||||||
|
Total accounts payable and accrued expenses
|
$ | 1,145,043 | $ | 867,965 | |||||
| (11) | Income Taxes |
Income before income tax provision (benefit), minority interests
and loss from discontinued operations consisted of the following:
| Year Ended December 31, | |||||||||||||
| 2006 | 2005 | 2004 | |||||||||||
| (Dollars in thousands) | |||||||||||||
|
U.S.
|
$ | 292,079 | $ | 253,329 | $ | 118,076 | |||||||
|
Non U.S.
|
238,883 | 172,756 | 34,995 | ||||||||||
|
Total
|
$ | 530,962 | $ | 426,085 | $ | 153,071 | |||||||
F-23
Table of Contents
PEABODY ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
Total income tax provision (benefit) consisted of the following:
| Year Ended December 31, | |||||||||||||
| 2006 | 2005 | 2004 | |||||||||||
| (Dollars in thousands) | |||||||||||||
|
Current:
|
|||||||||||||
|
U.S. federal
|
$ | 6,585 | $ | — | $ | 655 | |||||||
|
Non U.S.
|
67,565 | 25,622 | 4,533 | ||||||||||
|
State
|
405 | 300 | 300 | ||||||||||
|
Total current
|
74,555 | 25,922 | 5,488 | ||||||||||
|
Deferred:
|
|||||||||||||
|
U.S. federal
|
(159,536 | ) | (18,475 | ) | (33,275 | ) | |||||||
|
Non U.S.
|
4,094 | 22,997 | (328 | ) | |||||||||
|
State
|
(628 | ) | (29,484 | ) | 1,678 | ||||||||
|
Total deferred
|
(156,070 | ) | (24,962 | ) | (31,925 | ) | |||||||
|
Total provision (benefit)
|
$ | (81,515 | ) | $ | 960 | $ | (26,437 | ) | |||||
The income tax rate differed from the U.S. federal
statutory rate as follows:
| Year Ended December 31, | |||||||||||||
| 2006 | 2005 | 2004 | |||||||||||
| (Dollars in thousands) | |||||||||||||
|
Federal statutory rate
|
$ | 185,837 | $ | 149,130 | $ | 53,575 | |||||||
|
Depletion
|
(64,964 | ) | (59,412 | ) | (43,488 | ) | |||||||
|
Foreign earnings rate differential
|
(16,649 | ) | (12,279 | ) | (8,043 | ) | |||||||
|
State income taxes, net of U.S. federal tax benefit
|
6,160 | (29,288 | ) | 1,872 | |||||||||
|
Deemed liquidation of subsidiary
|
— | (314,071 | ) | — | |||||||||
|
Changes in valuation allowance
|
(165,481 | ) | 216,908 | (25,863 | ) | ||||||||
|
Changes in tax reserves
|
(28,658 | ) | 44,968 | — | |||||||||
|
Other, net
|
2,240 | 5,004 | (4,490 | ) | |||||||||
|
Total provision (benefit)
|
$ | (81,515 | ) | $ | 960 | $ | (26,437 | ) | |||||
F-24
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, | ||||||||||
| 2006 | 2005 | |||||||||
| (Dollars in thousands) | ||||||||||
|
Deferred tax assets:
|
||||||||||
|
Postretirement benefit obligations
|
$ | 630,124 | $ | 410,905 | ||||||
|
Tax credits and loss carryforwards
|
610,333 | 579,549 | ||||||||
|
Accrued long-term workers’ compensation liabilities
|
103,353 | 101,346 | ||||||||
|
Additional minimum pension liability
|
— | 46,931 | ||||||||
|
Accrued reclamation and mine closing liabilities
|
56,066 | 46,139 | ||||||||
|
Intangible tax asset and purchased contract rights
|
60,956 | 35,405 | ||||||||
|
Obligation to industry fund
|
11,197 | 12,112 | ||||||||
|
Others
|
85,703 | 71,311 | ||||||||
|
Total gross deferred tax assets
|
1,557,732 | 1,303,698 | ||||||||
|
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
|
1,423,693 | 1,168,470 | ||||||||
|
Inventory
|
— | 77,824 | ||||||||
|
Others
|
— | 1,021 | ||||||||
|
Total gross deferred tax liabilities
|
1,423,693 | 1,247,315 | ||||||||
|
Valuation allowance
|
(222,285 | ) | (385,844 | ) | ||||||
|
Net deferred tax liability
|
$ | (88,246 | ) | $ | (329,461 | ) | ||||
|
Deferred taxes consisted of the following:
|
||||||||||
|
Current deferred income taxes
|
$ | 106,967 | $ | 9,027 | ||||||
|
Noncurrent deferred income taxes
|
(195,213 | ) | (338,488 | ) | ||||||
|
Net deferred tax liability
|
$ | (88,246 | ) | $ | (329,461 | ) | ||||
The Company’s deferred tax assets included alternative
minimum tax (“AMT”) credits of $32.8 million and
$26.2 million, U.S. net operating loss
(“NOL”) carryforwards of $538.0 million and
$553.1 million and foreign NOL and capital loss
carryforwards of $39.6 million and $0.2 million as of
December 31, 2006 and 2005, respectively. The AMT credits
and foreign NOL and capital loss carryforwards have no
expiration date and the U.S. NOL carryforwards begin to
expire in the year 2019. Utilization of these AMT credits and
U.S. NOL carryforwards is subject to various limitations
because of previous changes in ownership (as defined in the
Internal Revenue Code) of the Company, and ultimate realization
could be negatively impacted by market conditions and other
variables not known or anticipated at this time. The AMT credits
and U.S. NOL carryforwards are offset by a valuation
allowance of $215.7 million. The valuation allowance was
reduced by $169.9 million and $25.9 million for the
years ended December 31, 2006 and 2004, respectively. The
valuation allowance was increased by $216.9 million for the
year ended December 31, 2005, to correspond with an
increase in available NOLs. The Company evaluated and assessed
the expected near-term utilization of NOLs, book and taxable
income trends, available tax strategies and the overall deferred
tax position to determine the amount and timing of valuation
allowance adjustments. The foreign capital loss carryforwards
and a deferred tax asset related to
F-25
Table of Contents
PEABODY ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
certain coal reserves are offset by a valuation allowance of
$6.6 million. The valuation allowance was increased by
$6.3 million for the year ended December 31, 2006.
During 2005, the Company completed a comprehensive and strategic
internal corporate restructuring project. This restructuring
focused on realigning the Company’s subsidiary ownership on
a geographic and functional basis and facilitated the
consolidation of assets in a tax-efficient manner, better
positioning the Company to execute future strategic
transactions. One of the indirect consequences of the internal
corporate restructuring was a deduction for a deemed liquidation
of a subsidiary for tax purposes, which, as a result, increased
the Company’s NOLs by $1.0 billion.
The Company establishes reserves for tax contingencies when,
despite the belief that the Company’s tax return positions
are fully supported, certain positions are likely to be
challenged and may not be fully sustained. The tax contingency
reserves are analyzed on a quarterly basis and adjusted based
upon changes in facts and circumstances, such as the progress of
federal and state audits, case law and emerging legislation. The
Company’s effective tax rate includes the impact of tax
contingency reserves and changes to the reserves, including
related interest, as considered appropriate by management. The
Company establishes the reserves based upon management’s
assessment of exposure associated with permanent tax differences
(e.g., tax depletion expense). The tax contingency reserve was
decreased for the year ended December 31, 2006, by
$28.7 million reflecting the reduction in exposure due to
the completion of federal and state audits. The tax contingency
reserve was increased by $45.0 million for the tax year
ended December 31, 2005.
The total amount of undistributed earnings of foreign
subsidiaries for income tax purposes was approximately
$318.9 million and $156.0 million at December 31,
2006 and 2005, respectively. The Company has not provided
deferred taxes on foreign earnings because such earnings were
intended to be indefinitely reinvested outside the United
States. Should the Company repatriate all of these earnings, a
one-time income tax charge to the Company’s consolidated
results of operations of up to $110 million could occur.
The Company made U.S. Federal tax payments totaling
$3.9 million and $1.4 million for the years ended
December 31, 2006 and 2004, respectively. The Company made
no U.S. Federal tax payments for the year ended
December 31, 2005. The Company paid state and local income
taxes totaling $0.5 million, $0.3 million and
$0.3 million for the years ended December 31, 2006,
2005 and 2004, respectively. The Company made
non-U.S. tax
payments totaling $23.1 million, $2.8 million and
$6.3 million for the years ended December 31, 2006,
2005 and 2004, respectively.
F-26
Table of Contents
PEABODY ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
| (12) | Long-Term Debt |
The Company’s total indebtedness as of December 31,
2006 and 2005, consisted of the following:
| December 31, | |||||||||
| 2006 | 2005 | ||||||||
| (Dollars in thousands) | |||||||||
|
Term Loan under Senior Unsecured Credit Facility
|
$ | 547,000 | $ | — | |||||
|
Term Loan under Senior Secured Credit Facility
|
— | 442,500 | |||||||
|
Convertible Junior Subordinated Debentures due 2066
|
732,500 | — | |||||||
|
7.375% Senior Notes due 2016
|
650,000 | — | |||||||
|
6.875% Senior Notes due 2013
|
650,000 | 650,000 | |||||||
|
7.875% Senior Notes due 2026
|
246,897 | — | |||||||
|
5.875% Senior Notes due 2016
|
231,845 | 239,525 | |||||||
|
5.0% Subordinated Note
|
59,504 | 66,693 | |||||||
|
6.84% Series C Bonds due 2016
|
43,000 | — | |||||||
|
6.34% Series B Bonds due 2014
|
21,000 | — | |||||||
|
6.84% Series A Bonds due 2014
|
10,000 | — | |||||||
|
Capital lease obligations
|
56,707 | 1,529 | |||||||
|
Fair value of interest rate swaps
|
(13,784 | ) | (8,879 | ) | |||||
|
Other
|
29,157 | 14,138 | |||||||
|
Total
|
$ | 3,263,826 | $ | 1,405,506 | |||||
| Senior Unsecured Credit Facility |
On September 15, 2006, the Company entered into a Third
Amended and Restated Credit Agreement (the
“Agreement”), which established a $2.75 billion
Senior Unsecured Credit Facility (the “Senior Unsecured
Credit Facility”) and which amended and restated in full
the Company’s then existing $1.35 billion Senior
Secured Credit Facility (the “Senior Secured Credit
Facility”). The Senior Unsecured Credit Facility provides a
$1.8 billion Revolving Credit Facility (the
“Revolver”) and a $950.0 million Term
Loan Facility (the “Term Loan Facility”).
The Revolver replaced the Company’s previous
$900.0 million revolving credit facility, and the increased
capacity is intended to accommodate working capital needs,
letters of credit, the funding of capital expenditures and other
general corporate purposes. The Revolver also includes a
$50.0 million sub-facility available for same-day swingline
loan borrowings. In September 2006, the Company borrowed
$312.0 million under the Revolver in conjunction with the
Excel acquisition and repaid this $312.0 million
outstanding balance in December 2006 with net proceeds from the
Debentures. As of December 31, 2006, the remaining
available borrowing capacity under the Revolver was
$1.29 billion.
The Term Loan Facility consisted of an unsecured
$440.0 million portion (the “Term Loan”), which
was drawn at closing to replace the previous term loan
($437.5 million balance at time of replacement;
$442.5 million at December 31, 2005) issued under the
Senior Secured Credit Facility. The Term Loan Facility also
includes a Delayed Draw Term Loan
Sub-Facility of up to
$510.0 million, which was fully drawn in October 2006 in
connection with the Excel acquisition. In December 2006,
$403.0 million of the outstanding balance of the Term
Loan Facility ($950.0 million was outstanding at time
of repayment) was repaid with the net proceeds from the
Debentures. In conjunction with the establishment of the Senior
Unsecured Credit Facility, the Company incurred
$8.6 million in financing costs, of which
F-27
Table of Contents
PEABODY ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
$5.6 million related to the Revolver and $3.0 million
related to the Term Loan. These debt issuance costs are being
amortized to interest expense over five years, the term of the
Senior Unsecured Credit Facility.
Loans under the facility are available to the Company in
U.S. dollars, with a sub-facility under the Revolver
available in Australian dollars, pounds sterling and Euros.
Letters of credit under the Revolver are available to the
Company in U.S. dollars with a sub-facility available in
Australian dollars, pounds sterling and Euros. The interest rate
payable on the Revolver and the Term Loan under the Senior
Unsecured Credit Facility is LIBOR plus 1.0% with step-downs to
LIBOR plus 0.50% based on improvement in the leverage ratio, as
defined in the Agreement. The rate applicable to the Term
Loan Facility was 6.35% at December 31, 2006.
Under the Senior Unsecured Credit Facility, the Company must
comply with certain financial covenants on a quarterly basis
including a minimum interest coverage ratio and a maximum
leverage ratio, as defined in the Agreement. The financial
covenants also place limitations on the Company’s
investments in joint ventures, unrestricted subsidiaries,
indebtedness of non-loan parties and the imposition of liens on
Company assets. The new facility is less restrictive with
respect to limitations on the Company’s dividend payments,
capital expenditures, asset sales and stock repurchases. The
Senior Unsecured Credit Facility matures on September 15,
2011.
| Convertible Junior Subordinated Debentures |
On December 20, 2006, the Company issued
$732.5 million aggregate principal amount of
4.75% Convertible Junior Subordinated Debentures due 2066
(the “Debentures”), including $57.5 million
issued pursuant to the underwriters’ exercise of their
over-allotment option. Net proceeds from the offering, after
deducting underwriting discounts and offering expenses, were
$715.0 million and were used to repay indebtedness under
the Company’s Senior Unsecured Credit Facility.
The Debentures will pay interest semiannually at a rate of
4.75% per year. The Company may elect to, and if and to the
extent that a mandatory trigger event (as defined in the
indenture governing the Debentures) has occurred and is
continuing will be required to, defer interest payments on the
Debentures. After five years of deferral at the 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 ten 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 $86.73 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 17) with a liquidation preference
equal to the principal amount of their Debentures, and any
conversion value in excess of the principal amount will be
settled with the Company’s common stock. The consideration
delivered upon conversion will be based upon an initial
conversion rate of 16.1421 shares of common stock per
$1,000 principal amount of Debentures, subject to adjustment.
This conversion rate represents an
F-28
Table of Contents
PEABODY ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
initial conversion price of approximately $61.95 per share,
a 40% premium over the closing stock price of $44.25 on
December 14, 2006, the date of the pricing of the offering
of the Debentures.
The Debentures are not subject to redemption prior to
December 20, 2011. Between December 20, 2011 and
December 19, 2036 the Company may redeem the Debentures, in
whole or in part, if for at least 20 out of the 30 consecutive
trading days immediately prior to the date on which notice of
redemption is given, the Company’s closing common stock
price has exceeded 130% of the then applicable conversion price
for the Debentures. On or after December 20, 2036, whether
or not the redemption condition is satisfied, the Company may
redeem the Debentures, in whole or in part. The Company may not
redeem any Debentures unless (i) all accrued and unpaid
interest on the Debentures has been paid in full on or prior to
the redemption date and (ii) if any perpetual preferred
stock is outstanding, the Company has first given notice to
redeem the perpetual preferred stock in the same proportion as
the redemption of the Debentures. Any redemption of the
Debentures will be at a cash redemption price of 100% of the
principal amount of the Debentures to be redeemed, plus accrued
and unpaid interest to the date of redemption.
On December 15, 2041, the scheduled maturity date, the
Company will use commercially reasonable efforts, subject to the
occurrence of a market disruption event, as defined in the
indenture governing the Debentures, to issue securities of
equivalent equity content in an amount sufficient to pay the
principal amount of the Debentures, together with accrued and
unpaid interest. The final maturity date of the Debentures is
December 15, 2066, on which date the entire principal
amount of the Debentures will mature and become due and payable,
together with accrued and unpaid interest.
In connection with the issuance of the Debentures, the Company
entered into a Capital Replacement Covenant (the
“CRC”). Pursuant to the CRC, the Company covenanted
for the benefit of holders of covered debt, as defined in the
CRC (currently the Company’s 7.875% Senior Notes due
2026, issued in the aggregate principal amount of
$250.0 million), that neither the Company nor any of its
subsidiaries shall repay, redeem or repurchase all or any part
of the Debentures on or after December 15, 2041 and prior
to December 15, 2046, except to the extent that the total
repayment, redemption or repurchase price does not exceed the
sum of: (i) 400% of the 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.
| 7.375% Senior Notes Due November 2016 and 7.875% Senior Notes Due November 2026 |
On October 12, 2006, the Company completed a
$650 million offering of 7.375%
10-year Senior Notes
due 2016 and $250 million of 7.875%
20-year Senior Notes
due 2026. The notes are general unsecured obligations of the
Company and rank senior in right of payment to any subordinated
indebtedness of the Company; equally in right of payment with
any senior indebtedness of the Company; effectively junior in
right of payment to the Company’s existing and future
secured indebtedness, to the
F-29
Table of Contents
PEABODY ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
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, commencing on
May 1, 2007.
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. Net
proceeds from the offering, after deducting underwriting
discounts and expenses, were $886.1 million.
| 6.875% Senior Notes Due March 2013 |
On March 21, 2003, the Company issued $650.0 million
of 6.875% Senior Notes due March 2013. The notes are senior
unsecured obligations of the Company and rank equally with all
of the Company’s other senior unsecured indebtedness.
Interest payments are scheduled to occur on March 15 and
September 15 of each year. The notes are guaranteed by the
Company’s Subsidiary Guarantors as defined in the note
indenture. The note indenture contains covenants which, among
other things, limit the Company’s ability to incur
additional indebtedness and issue preferred stock, pay dividends
or make other distributions, make other restricted payments and
investments, create liens, sell assets and merge or consolidate
with other entities. The notes are redeemable prior to
March 15, 2008, at a redemption price equal to 100% of the
principal amount plus a make-whole premium (as defined in the
indenture) and on or after March 15, 2008, at fixed
redemption prices as set forth in the indenture.
| 5.875% Senior Notes Due March 2016 |
On March 23, 2004, the Company completed an offering of
$250.0 million of 5.875% Senior Notes due March 2016.
The notes are senior unsecured obligations of the Company and
rank equally with all of the Company’s other senior
unsecured indebtedness. Interest payments are scheduled to occur
on April 15 and October 15 of each year, and commenced on
April 15, 2004. The notes are guaranteed by the
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 prior to
April 15, 2009, at a redemption price equal to 100% of the
principal amount plus a make-whole premium (as defined in the
indenture) and on or after April 15, 2009, at fixed
redemption prices as set forth in the indenture. Net proceeds
from the offering, after deducting underwriting discounts and
expenses, were $244.7 million.
| 5.0% Subordinated Note |
The 5.0% Subordinated Note is recorded net of discount with
interest and principal payable each March 1. The Company repaid
$10.0 million of principal in March 2006, with the
remaining $60.0 million due March 1, 2007. The
5.0% Subordinated Note is expressly subordinated in right
of payment to all prior indebtedness as disclosed above.
| Series Bonds |
As of December 31, 2006, the Company had $74.0 million
in Series Bonds outstanding, which were assumed as part of
the Excel acquisition. The 6.84% Series A Bonds have a
balloon maturity in December 2014. The 6.34% Series B Bonds
mature in December 2014 and are payable in installments beginning
F-30
Table of Contents
PEABODY ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
December 2008. The 6.84% Series C Bonds mature in December
2016 and are payable in installments beginning December 2012.
Interest payments occur in June and December of each year.
| Interest Rate Swaps |
Prior to completion of the Senior Unsecured Credit Facility, the
Company had two $400.0 million interest rate swaps. A
$400.0 million notional amount
floating-to-fixed
interest rate swap was designated as a hedge of changes in
expected cash flows on the previous term loan under the Senior
Secured Credit Facility. Under this swap, the Company paid a
fixed rate of 6.764% and received a floating rate of LIBOR plus
2.5% that reset each March 15, June 15, September 15
and December 15 based upon the three-month LIBOR rate. A
$400.0 million notional amount
fixed-to-floating
interest rate swap was designated as a hedge of the changes in
the fair value of the 6.875% Senior Notes due 2013. Under
this swap, the Company paid a floating rate of LIBOR plus 1.97%
that reset each March 15, June 15, September 15 and
December 15 based upon the three-month LIBOR rate and received a
fixed rate of 6.875%.
In conjunction with the completion of the new Senior Unsecured
Credit Facility, the $400.0 million notional amount
floating-to-fixed
interest rate swap was terminated and resulted in payment to the
Company of $5.2 million. The Company recorded the
$5.2 million fair value of the swap in “Accumulated
other comprehensive loss” on the consolidated balance sheet
and will amortize this amount to interest expense over the
remaining term of the forecasted interest payments initially
hedged. The Company then entered into a $120.0 million
notional amount
floating-to-fixed
interest rate swap with a fixed rate of 6.25% and a floating
rate of LIBOR plus 1.0%. This interest rate swap was designated
as a hedge of the variable interest payments on the Term Loan
under the new Senior Unsecured Credit Facility.
The Company also terminated $280.0 million of its
$400.0 million notional amount
fixed-to-floating
interest rate swap designated as a hedge of the changes in fair
value of the 6.875% Senior Notes due 2013. Reducing the
notional amount of the interest rate swap to $120.0 million
resulted in payment of $5.2 million to the counterparty.
Reduction of the notional amount of the swap did not affect its
floating and fixed rates. The $5.2 million of fair value
associated with the termination of the $280.0 million
portion of the swap was recorded as an adjustment to the
carrying value of long-term debt and will be amortized to
interest expense through maturity of the 6.875% Senior
Notes due 2013.
Because the critical terms of the swaps and the respective debt
instruments they hedge coincide, there was no hedge
ineffectiveness recognized in the consolidated statements of
operations during the years ended December 31, 2006 and
2005. At December 31, 2006 there was an unrealized loss
related to the cash flow hedge of $2.5 million and at
December 31, 2005 there was an unrealized gain related to
the cash flow hedge of $2.3 million. As of
December 31, 2006 and 2005, net unrealized loss on the fair
value hedges discussed above was $13.8 million and
$8.9 million, respectively, which is reflected as an
adjustment to the carrying value of the Senior Notes (see table
above).
| Capital Lease Obligations and Other |
Capital lease obligations include obligations assumed from the
Excel acquisition, primarily for mining equipment (see
Note 9 for additional information on the Company’s
capital lease obligations).
Other long-term debt, which consists principally of notes
payable, is due in installments through 2016. The
weighted-average effective interest rate of this debt was 3.98%
as of December 31, 2006.
F-31
Table of Contents
PEABODY ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
The aggregate amounts of long-term debt maturities subsequent to
December 31, 2006, including capital lease obligations,
were as follows:
| Year of Maturity | |||||
| (Dollars in thousands) | |||||
|
2007
|
$ | 95,757 | |||
|
2008
|
47,078 | ||||
|
2009
|
40,504 | ||||
|
2010
|
37,051 | ||||
|
2011
|
445,842 | ||||
|
2012 and thereafter
|
2,597,594 | ||||
|
Total
|
$ | 3,263,826 | |||
Interest paid on long-term debt was $114.6 million,
$94.2 million and $87.4 million for the years ended
December 31, 2006, 2005 and 2004, respectively. The Company
paid interest expense of $3.3 million on the Revolver in
2006 and no interest was paid on the Revolver in 2005 or 2004.
| Early Debt Extinguishment Costs |
For the year ended December 31, 2006, the Company recorded
net early debt extinguishment costs of $1.4 million,
primarily related to the repayment of borrowings under the Term
Loan Facility.
In 2004, the Company recorded a net charge for early debt
extinguishment of $1.8 million. In connection with the
refinancing of the Senior Secured Credit Facility on
October 27, 2004, the Company incurred a non-cash charge of
$2.4 million to write-off unamortized debt issuance costs
related to the term loan. In connection with the July 2004
repurchase of $10.5 million of 5.875% Senior Notes due
March 2016, the Company realized a gain of $0.6 million.
| Shelf Registration Statement |
On July 28, 2006, the Company filed an automatic shelf
registration statement on
Form S-3 as a
well-known seasoned issuer with the Securities and Exchange
Commission. The registration was for an indeterminate number of
securities and is effective for three years, at which time the
Company can file an automatic shelf registration statement that
would become immediately effective for another three-year term.
Under this universal shelf registration statement, the Company
has the capacity to offer and sell from time to time securities,
including common stock, preferred stock, debt securities,
warrants and units. The Debentures, 7.375% Senior Notes due
2016 and 7.875% Senior Notes due 2026 were issued pursuant
to the shelf registration statement.
F-32
Table of Contents
PEABODY ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
| (13) | Asset Retirement Obligations |
Reconciliations of the Company’s liability for asset
retirement obligations were as follows:
| December 31, | |||||||||
| 2006 | 2005 | ||||||||
| (Dollars in thousands) | |||||||||
|
Balance at beginning of year
|
$ | 399,203 | $ | 396,022 | |||||
|
Liabilities incurred or acquired
|
18,573 | 24,101 | |||||||
|
Liabilities settled or disposed
|
(40,621 | ) | (40,341 | ) | |||||
|
Accretion expense
|
29,480 | 24,095 | |||||||
|
Revisions to estimate
|
16,396 | (4,674 | ) | ||||||
|
Balance at end of year
|
$ | 423,031 | $ | 399,203 | |||||
As of December 31, 2006, asset retirement obligations of
$423.0 million consisted of $354.0 million related to
locations with active mining operations and $69.0 million
related to locations that are closed or inactive. As of
December 31, 2005, asset retirement obligations of
$399.2 million consisted of $340.7 million related to
locations with active mining operations and $58.5 million
related to locations that are closed or inactive. The
credit-adjusted risk-free interest rates were 6.16% and 5.81% at
January 1, 2006 and 2005, respectively.
In 2006, the Company assumed $7.2 million of asset
retirement obligations with the Excel acquisition (see
Note 4) and incurred additional obligations related to the
opening of new mine pits. For the year ended December 31,
2005, the Company recorded a $9.2 million reduction in its
asset retirement obligations associated with the disposal of
non-strategic properties and the assumption of the related
reclamation liabilities by the purchaser. Also during 2005, the
Company recorded $21.6 million for asset retirement
obligations associated with assets acquired from Lexington Coal
Company (see Note 3).
As of December 31, 2006 and 2005, the Company had
$441.5 million and $323.6 million, respectively, in
surety bonds outstanding to secure reclamation obligations or
activities. The amount of reclamation self-bonding in certain
states in which the Company qualifies was $685.2 million
and $671.8 million as of December 31, 2006 and 2005,
respectively. Additionally, the Company had $4.1 million
and $0.1 million of letters of credit in support of
reclamation obligations or activities as of December 31,
2006 and 2005, respectively.
| (14) | Workers’ Compensation Obligations |
Certain subsidiaries of the Company are subject to the Federal
Coal Mine Health and Safety Act of 1969 and the related
workers’ compensation laws in the states in which they
operate. These laws require the subsidiaries to pay benefits for
occupational disease resulting from coal workers’
pneumoconiosis (“occupational disease”). Changes to
the federal regulations became effective in August 2001, and the
revised regulations could ultimately result in higher costs,
although experience to date has not resulted in higher claims
costs. Provisions for occupational disease costs are based on
determinations by independent actuaries or claims administrators.
The Company provides income replacement and medical treatment
for work related traumatic injury claims as required by
applicable state law. Provisions for estimated claims incurred
are recorded based on estimated loss rates applied to payroll
and claim reserves determined by independent actuaries or claims
administrators. Certain subsidiaries of the Company are required
to contribute to state workers’ compensation funds for
second injury and other costs incurred by the state fund based
on a payroll-based assessment by the applicable state.
Provisions are recorded based on the payroll-based assessment
criteria.
F-33
Table of Contents
PEABODY ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
The workers’ compensation provision consisted of the
following components:
| Year Ended December 31, | ||||||||||||
| 2006 | 2005 | 2004 | ||||||||||
| (Dollars in thousands) | ||||||||||||
|
Service cost
|
$ | 4,175 | $ | 4,491 | $ | 4,346 | ||||||
|
Interest cost
|
10,327 | 10,425 | 11,568 | |||||||||
|
Net amortization
|
(1,894 | ) | (1,213 | ) | 742 | |||||||
|
Total occupational disease
|
12,608 | 13,703 | 16,656 | |||||||||
|
Traumatic injury claims
|
20,743 | 25,610 | 27,141 | |||||||||
|
State assessment taxes
|
10,676 | 16,820 | 15,365 | |||||||||
|
Total provision
|
$ | 44,027 | $ | 56,133 | $ | 59,162 | ||||||
The weighted-average assumptions used to determine the
workers’ compensation provision were as follows:
| Year Ended December 31, | ||||||||||||
| 2006 | 2005 | 2004 | ||||||||||
|
Discount rate
|
5.90% | 6.10% | 6.40% | |||||||||
|
Inflation rate
|
3.50% | 3.50% | 3.50% | |||||||||
Workers’ compensation obligations consist of amounts
accrued for loss sensitive insurance premiums, uninsured claims
and related taxes and assessments under black lung and traumatic
injury workers’ compensation programs.
The workers’ compensation obligations consisted of the
following:
| December 31, | |||||||||
| 2006 | 2005 | ||||||||
| (Dollars in thousands) | |||||||||
|
Occupational disease costs
|
$ | 187,477 | $ | 190,347 | |||||
|
Traumatic injury claims
|
76,896 | 81,539 | |||||||
|
Total obligations
|
264,373 | 271,886 | |||||||
|
Less current portion (included in Accounts payable and accrued
expenses)
|
(30,966 | ) | (34,312 | ) | |||||
|
Noncurrent obligations (included in Workers’ compensation
obligations)
|
$ | 233,407 | $ | 237,574 | |||||
As a result of the adoption of SFAS No. 158 on
December 31, 2006, the accrued workers’ compensation
liability on the consolidated balance sheet at December 31,
2006 reflects the accumulated obligation less any portion that
is currently funded. The adoption of SFAS No. 158
decreased liabilities by $4.6 million and “Accumulated
other comprehensive loss” by $2.7 million at
December 31, 2006.
As of December 31, 2006 and 2005, the Company had
$188.5 million and $163.8 million, respectively, in
surety bonds and letters of credit outstanding to secure
workers’ compensation obligations.
F-34
Table of Contents
PEABODY ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
The reconciliation of changes in the occupational disease
liability benefit obligation were as follows:
| December 31, | ||||||||||
| 2006 | 2005 | |||||||||
| (Dollars in thousands) | ||||||||||
|
Change in benefit obligation:
|
||||||||||
|
Beginning of year obligation
|
$ | 187,907 | $ | 199,346 | ||||||
|
Service cost
|
4,175 | 4,491 | ||||||||
|
Interest cost
|
10,327 | 10,425 | ||||||||
|
Net actuarial gain
|
(6,122 | ) | (16,071 | ) | ||||||
|
Benefit and administrative payments
|
(8,810 | ) | (10,284 | ) | ||||||
|
Net obligation at end of year
|
187,477 | 187,907 | ||||||||
|
Change in plan assets:
|
||||||||||
|
Fair value of plan assets at beginning of period
|
— | — | ||||||||
|
Employer contributions
|
8,810 | 10,284 | ||||||||
|
Benefits paid
|
(8,810 | ) | (10,284 | ) | ||||||
|
Fair value of plan assets at end of period
|
— | — | ||||||||
|
Funded status at end of period
|
(187,477 | ) | (187,907 | ) | ||||||
|
Unrecognized actuarial gain
|
— | (2,440 | ) | |||||||
|
Accrued cost
|
$ | (187,477 | ) | $ | (190,347 | ) | ||||
The liability for occupational disease claims represents the
actuarially-determined present value of known claims and an
estimate of future claims that will be awarded to current and
former employees. The liability for occupational disease claims
was based on a discount rate of 6.0% and 5.9% at
December 31, 2006 and 2005, respectively. Traumatic injury
workers’ compensation obligations are estimated from both
case reserves and actuarial determinations of historical trends,
discounted at 5.9% and 6.1% for the years ended
December 31, 2006 and 2005, respectively.
| Federal Black Lung Excise Tax Refund Claims |
In addition to the obligations discussed above, certain
subsidiaries of the Company are required to pay black lung
excise taxes to the Federal Black Lung Trust Fund (the
“Trust Fund”). The Trust Fund pays
occupational disease benefits to entitled former miners who
worked prior to July 1, 1973. Excise taxes are based on the
selling price of coal, up to a maximum of $1.10 per ton for
underground mines and $0.55 per ton for surface mines. The
Company had a receivable for excise tax refunds of
$19.4 million as of December 31, 2006 and 2005. In a
January 2007 decision, a federal appellate court ruled that the
Company is also entitled to collect interest on the
$19.4 million refund from the federal government.
| (15) | Pension and Savings Plans |
One of the Company’s subsidiaries, Peabody Investments
Corp., sponsors a defined benefit pension plan covering certain
U.S. salaried employees and eligible hourly employees at
certain Peabody Investments Corp. subsidiaries (the
“Peabody Plan”). A Peabody Investments Corp.
subsidiary also has a defined benefit pension plan covering
eligible employees who are represented by the UMWA under the
Western Surface Agreement of 2000 (the “Western
Plan”). Peabody Investments Corp. also sponsors an unfunded
supplemental retirement plan to provide senior management with
benefits in excess of limits under the federal tax law.
F-35
Table of Contents
PEABODY ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
Annual contributions to the plans are made as determined by
consulting actuaries based upon the Employee Retirement Income
Security Act of 1974 minimum funding standard. In May 1998, the
Company entered into an agreement with the Pension Benefit
Guaranty Corporation which requires the Company to maintain
certain minimum funding requirements. Beginning on
January 1, 2008, new minimum funding standards will be
required by the Pension Protection Act of 2006. Assets of the
plans are primarily invested in various marketable securities,
including U.S. government bonds, corporate obligations and
listed stocks.
Net periodic pension costs included the following components:
| Year Ended December 31, | ||||||||||||
| 2006 | 2005 | 2004 | ||||||||||
| (Dollars in thousands) | ||||||||||||
|
Service cost for benefits earned
|
$ | 12,234 | $ | 11,853 | $ | 12,275 | ||||||
|
Interest cost on projected benefit obligation
|
46,034 | 45,499 | 43,658 | |||||||||
|
Expected return on plan assets
|
(54,587 | ) | (52,812 | ) | (49,813 | ) | ||||||
|
Other amortizations and deferrals
|
22,653 | 24,588 | 22,366 | |||||||||
|
Net periodic pension costs
|
26,334 | 29,128 | 28,486 | |||||||||
|
Curtailment charges
|
— | 9,527 | — | |||||||||
|
Total net periodic pension costs
|
$ | 26,334 | $ | 38,655 | $ | 28,486 | ||||||
The Company amortizes actuarial gains and losses using a 5%
corridor with a five-year amortization period. The estimated net
actuarial loss and prior service cost that will be amortized
from accumulated other comprehensive income (loss) into net
periodic pension costs during the year ended December 31,
2007 are $19.2 million and less than $0.1 million,
respectively.
The 2005 curtailment loss resulted from the termination of
operations at two of the three operating mines that participate
in the Western Plan during 2005. The loss is actuarially
determined and consists of an increase in the actuarial
liability, the accelerated recognition of previously unamortized
prior service cost and contractual termination benefits under
the Western Plan resulting from the termination of operations.
During the period ended March 31, 1999, the Company made an
amendment to phase out the Peabody Plan. Effective
January 1, 2001, certain employees no longer accrue future
service under the plan while other employees accrue reduced
service under the plan based on their age and years of service
as of December 31, 2000. For plan benefit calculation
purposes, employee earnings are also frozen as of
December 31, 2000. The Company has adopted an enhanced
savings plan contribution structure in lieu of benefits formerly
accrued under the defined benefit pension plan.
F-36
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, | |||||||||
| 2006 | 2005 | ||||||||
| (Dollars in thousands) | |||||||||
|
Change in benefit obligation:
|
|||||||||
|
Projected benefit obligation at beginning of period
|
$ | 801,818 | $ | 759,283 | |||||
|
Service cost
|
12,234 | 11,853 | |||||||
|
Interest cost
|
46,034 | 45,499 | |||||||
|
Plan amendments
|
— | (225 | ) | ||||||
|
Curtailments
|
— | (1,309 | ) | ||||||
|
Special termination benefits
|
— | 7,896 | |||||||
|
Benefits paid
|
(40,323 | ) | (38,315 | ) | |||||
|
Actuarial loss
|
13,037 | 17,136 | |||||||
|
Projected benefit obligation at end of period
|
832,800 | 801,818 | |||||||
|
Change in plan assets:
|
|||||||||
|
Fair value of plan assets at beginning of period
|
654,023 | 642,400 | |||||||
|
Actual return on plan assets
|
84,326 | 42,707 | |||||||
|
Employer contributions
|
6,146 | 7,231 | |||||||
|
Benefits paid
|
(40,323 | ) | (38,315 | ) | |||||
|
Fair value of plan assets at end of period
|
704,172 | 654,023 | |||||||
|
Funded status at end of year
|
(128,628 | ) | (147,795 | ) | |||||
|
Unrecognized actuarial loss
|
— | 141,517 | |||||||
|
Unrecognized prior service cost
|
— | 346 | |||||||
|
Accrued pension liability
|
$ | (128,628 | ) | $ | (5,932 | ) | |||
|
Amounts recognized in the consolidated balance sheets:
|
|||||||||
|
Accrued benefit liability
|
$ | (128,628 | ) | $ | (125,622 | ) | |||
|
Intangible asset
|
— | 2,362 | |||||||
|
Additional minimum pension liability, included in other
comprehensive income
|
— | 117,328 | |||||||
|
Net amount recognized
|
$ | (128,628 | ) | $ | (5,932 | ) | |||
Prior to being amended by SFAS No. 158, the provisions
of SFAS No. 87 required the recognition of an
additional minimum liability and related intangible asset to the
extent that accumulated benefits exceed plan assets. As of
December 31, 2005, the Company had recorded
$117.3 million to reflect the Company’s minimum
liability. SFAS No. 158, which was adopted on
December 31, 2006, eliminated the need to recognize an
additional minimum pension liability and related intangible
asset.
The current portion of the Company’s pension liability as
reflected in “Accounts payable and accrued expenses”
at December 31, 2006 and 2005 was $1.3 million and
$7.9 million, respectively. The noncurrent portion of the
Company’s pension liability as reflected in “Other
noncurrent liabilities” at December 31, 2006 and 2005
was $127.3 million and $115.4 million, respectively.
F-37
Table of Contents
PEABODY ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
As a result of the adoption of SFAS No. 158 on
December 31, 2006, the accrued pension liability recorded
on the consolidated balance sheet at December 31, 2006
reflects the projected benefit obligation less any portion of
the obligation currently funded. The accumulated actuarial loss
and prior service cost that had not yet been reflected in net
periodic pension costs were included in “Accumulated other
comprehensive loss” at December 31, 2006 as follows:
| (Dollars in thousands) | ||||
|
Accumulated actuarial loss
|
$ | (102,060 | ) | |
|
Prior service cost
|
(379 | ) | ||
|
Accumulated other comprehensive loss
|
$ | (102,439 | ) | |
The change in “Accumulated other comprehensive loss”
due to the application of SFAS No. 158 was as follows:
| December 31, | ||||||||
| 2006 | 2005 | |||||||
| (Dollars in thousands) | ||||||||
|
Additional minimum pension liability (before
SFAS No. 158)
|
$ | (78,110 | ) | $ | (117,328 | ) | ||
|
Intangible asset (before SFAS No. 158)
|
1,908 | 2,362 | ||||||
|
Accumulated other comprehensive loss (before
SFAS No. 158)
|
(76,202 | ) | (114,966 | ) | ||||
|
Net decrease in accumulated other comprehensive loss due to the
adoption of SFAS No. 158
|
(26,237 | ) | — | |||||
|
Accumulated other comprehensive loss
|
$ | (102,439 | ) | $ | (114,966 | ) | ||
The weighted-average assumptions used to determine the benefit
obligations as of the end of each year were as follows:
| Year Ended December 31, | ||||||||
| 2006 | 2005 | |||||||
|
Discount rate
|
6.00% | 5.90% | ||||||
|
Rate of compensation increase
|
3.50% | 3.50% | ||||||
|
Measurement date
|
December 31, 2006 | December 31, 2005 | ||||||
The weighted-average assumptions used to determine net periodic
benefit cost were as follows:
| Year Ended December 31, | ||||||||||||
| 2006 | 2005 | 2004 | ||||||||||
|
Discount rate
|
5.90% | 6.10% | 6.40% | |||||||||
|
Expected long-term return on plan assets
|
8.75% | 8.75% | 8.75% | |||||||||
|
Rate of compensation increase
|
3.50% | 3.50% | 3.75% | |||||||||
|
Measurement date
|
December 31, 2005 | December 31, 2004 | December 31, 2003 | |||||||||
The expected rate of return on plan assets is determined by
taking into consideration expected long-term returns associated
with each major asset class (net of inflation) based on
long-term historical ranges, inflation assumptions and the
expected net value from active management of the assets based on
actual results.
F-38
Table of Contents
PEABODY ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
The projected benefit obligation and the accumulated benefit
obligation exceeded plan assets for all plans as of
December 31, 2006 and 2005. The accumulated benefit
obligation for all pension plans was $808.4 million and
$779.6 million as of December 31, 2006, and 2005,
respectively.
| Plan Assets |
Assets of the Peabody Plan and the Western Plan are commingled
in the Peabody Investment Corporation Master Trust (the
“Master Trust”) and are invested in accordance with
investment guidelines that have been established by the
Company’s Retirement Committee (the “Retirement
Committee”) after consultation with outside investment
advisors and actuaries.
As of the year ended December 31, 2006, Master Trust assets
totaled $704.2 million and were invested in the following
major asset categories:
| Percentage | ||||||||
| Allocation of | Target | |||||||
| Total Assets | Allocation | |||||||
|
Equity securities
|
58.5 | % | 55.0 | % | ||||
|
Fixed income
|
32.9 | % | 35.0 | % | ||||
|
Real estate
|
7.6 | % | 10.0 | % | ||||
|
Cash fund
|
1.0 | % | 0.0 | % | ||||
|
Total
|
100.0 | % | 100.0 | % | ||||
As of the year ended December 31, 2005, Master Trust assets
totaled $654.0 million and were invested in the following
major asset categories:
| Percentage | ||||
| Allocation of | ||||
| Total Assets | ||||
|
Equity securities
|
55.1 | % | ||
|
Fixed income
|
37.9 | % | ||
|
Real estate
|
6.9 | % | ||
|
Cash fund
|
0.1 | % | ||
|
Total
|
100.0 | % | ||
The asset allocation targets have been set with the expectation
that the plan’s assets will fund the plan’s expected
liabilities with an appropriate level of risk. To determine the
appropriate target asset allocations, the Retirement Committee
considers the demographics of the plan participants, the funding
status of the plan, the business and financial profile of the
Company and other associated risk preferences. These allocation
targets are reviewed by the Retirement Committee on a regular
basis and revised as necessary. Periodically, assets are
rebalanced among major asset categories to maintain the
allocations within a range of plus or minus 5% of the target
allocation.
Plan assets are either under active management by third-party
investment advisors or in index funds, all selected and
monitored by the Retirement Committee. The Retirement Committee
has established specific investment guidelines for each major
asset class including performance benchmarks, allowable and
prohibited investment types and concentration limits. In
general, the plan investment guidelines do not permit leveraging
the Master Trust’s assets. Equity investment guidelines do
not permit entering into put or call options (except as deemed
appropriate to manage currency risk), and futures contracts are
permitted only to the extent necessary to equitize cash holdings.
F-39
Table of Contents
PEABODY ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
| Contributions |
The Company expects to contribute $6.9 million to its
funded pension plans and make $1.3 million in expected
benefit payments attributable to its unfunded pension plans
during 2007.
| Estimated Future Benefit Payments |
The following benefit payments (net of retiree contributions),
which reflect expected future service, as appropriate, are
expected to be paid by the Master Trust:
| Pension | ||||
| Benefits | ||||
| (Dollars in | ||||
| thousands) | ||||
|
2007
|
$ | 42,757 | ||
|
2008
|
44,970 | |||
|
2009
|
46,531 | |||
|
2010
|
48,453 | |||
|
2011
|
51,014 | |||
|
Years 2012-2016
|
301,257 | |||
| Multi-Employer Pension Plans |
Certain subsidiaries participate in multi-employer pension plans
(the 1950 Plan and the 1974 Plan), which provide defined
benefits to substantially all hourly coal production workers
represented by the UMWA other than those covered by the Western
Plan. Benefits under the UMWA plans are computed based on
service with the subsidiaries or other signatory employers.
There were no contributions to the multi-employer pension plans
during the years ended December 31, 2006, 2005 or 2004. In
December 2006, the 2007 National Bituminous Coal Wage Agreement
was signed, which required funding of the 1974 Plan through 2011
under a phased funding schedule. The funding is based on an
hourly rate for certain UMWA workers. Under the labor contract,
the per hour funding rate increased to $2.00 in 2007 and
increases each year thereafter until reaching $5.50 in 2011.
During 2006, represented employees subject to the new rate
worked a total of approximately four million hours.
| Defined Contribution Plans |
The Company sponsors employee retirement accounts under three
401(k) plans for eligible salaried U.S. employees. The
Company matches voluntary contributions to each plan up to
specified levels. The expense for these plans was
$16.5 million, $10.7 million and $10.2 million
for the years ended December 31, 2006, 2005 and 2004,
respectively. A performance contribution feature allows for
additional contributions from the Company based upon meeting
specified Company performance targets, and the performance
contributions made by the Company were $10.5 million,
$11.4 million and $6.7 million for the years ended
December 31, 2006, 2005 and 2004, respectively.
| (16) | Postretirement Health Care and Life Insurance Benefits |
The Company currently provides health care and life insurance
benefits to qualifying salaried and hourly retirees and their
dependents from defined benefit plans established by the
Company. Plan coverage for health and life insurance benefits is
provided to future hourly retirees in accordance with the
applicable labor agreement.
F-40
Table of Contents
PEABODY ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
Net periodic postretirement benefit costs included the following
components:
| Year Ended December 31, | ||||||||||||
| 2006 | 2005 | 2004 | ||||||||||
| (Dollars in thousands) | ||||||||||||
|
Service cost for benefits earned
|
$ | 8,077 | $ | 5,343 | $ | 4,430 | ||||||
|
Interest cost on accumulated postretirement benefit obligation
|
73,803 | 72,673 | 63,635 | |||||||||
|
Amortization of prior service cost
|
(4,836 | ) | (5,339 | ) | (13,230 | ) | ||||||
|
Amortization of actuarial losses
|
31,342 | 26,304 | 3,575 | |||||||||
|
Net periodic postretirement benefit costs
|
$ | 108,386 | $ | 98,981 | $ | 58,410 | ||||||
The Company amortizes actuarial gains and losses using a 0%
corridor with an amortization period that covers the average
remaining service period of active employees (8.47 years
and 8.99 years at January 1, 2006 and 2005,
respectively). The estimated net actuarial loss and prior
service cost that will be amortized from accumulated other
comprehensive income (loss) into net periodic postretirement
benefit costs during the year ended December 31, 2007 are
$43.3 million and $3.1 million, respectively.
F-41
Table of Contents
PEABODY ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
The following table sets forth the plans’ combined funded
status reconciled with the amounts shown in the consolidated
balance sheets:
| December 31, | |||||||||
| 2006 | 2005 | ||||||||
| (Dollars in thousands) | |||||||||
|
Change in benefit obligation:
|
|||||||||
|
Accumulated postretirement benefit obligation at
beginning of period |
$ | 1,288,955 | $ | 1,234,185 | |||||
|
Service cost
|
8,077 | 5,343 | |||||||
|
Interest cost
|
73,803 | 72,673 | |||||||
|
Participant contributions
|
1,800 | 1,716 | |||||||
|
Plan amendments
|
24,439 | — | |||||||
|
Benefits paid
|
(88,667 | ) | (87,250 | ) | |||||
|
Actuarial loss
|
142,910 | 62,288 | |||||||
|
Accumulated postretirement benefit obligation at end of period
|
1,451,317 | 1,288,955 | |||||||
|
Change in plan assets:
|
|||||||||
|
Fair value of plan assets at beginning of period
|
— | — | |||||||
|
Employer contributions
|
86,867 | 85,534 | |||||||
|
Participant contributions
|
1,800 | 1,716 | |||||||
|
Benefits paid
|
(88,667 | ) | (87,250 | ) | |||||
|
Fair value of plan assets at end of period
|
— | — | |||||||
|
Funded status at end of year
|
(1,451,317 | ) | (1,288,955 | ) | |||||
|
Unrecognized actuarial loss
|
— | 272,617 | |||||||
|
Unrecognized prior service cost
|
— | (17,932 | ) | ||||||
|
Accrued postretirement benefit obligation
|
(1,451,317 | ) | (1,034,270 | ) | |||||
|
Less current portion (included in Accounts payable
and accrued expenses) |
82,631 | 75,048 | |||||||
|
Noncurrent obligation (included in Accrued postretirement
benefit costs) |
$ | (1,368,686 | ) | $ | (959,222 | ) | |||
As a result of the adoption of SFAS No. 158 on
December 31, 2006, the accrued postretirement benefit
liability recorded on the consolidated balance sheet at
December 31, 2006 reflects the accumulated postretirement
benefit obligation less any portion that is currently funded.
The accumulated actuarial loss and prior service costs that had
not yet been reflected in net periodic postretirement benefit
costs were included in “Accumulated other comprehensive
loss” at December 31, 2006, as follows:
| (Dollars in thousands) | ||||
|
Accumulated actuarial loss
|
$ | (384,179 | ) | |
|
Prior service cost
|
(11,343 | ) | ||
|
Accumulated other comprehensive loss
|
$ | (395,522 | ) | |
F-42
Table of Contents
PEABODY ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
The weighted-average assumptions used to determine the benefit
obligations as of the end of each year were as follows:
| Year Ended December 31, | ||||||||
| 2006 | 2005 | |||||||
|
Discount rate
|
6.00% | 5.90% | ||||||
|
Rate of compensation increase
|
3.50% | 3.50% | ||||||
|
Measurement date
|
December 31, 2006 | December 31, 2005 | ||||||
The weighted-average assumptions used to determine net periodic
benefit cost were as follows:
| Year Ended December 31, | ||||||||||||
| 2006 | 2005 | 2004 | ||||||||||
|
Discount rate
|
5.90% | 6.10% | 6.40% | |||||||||
|
Rate of compensation increase
|
3.50% | 3.50% | 3.75% | |||||||||
|
Measurement date
|
December 31, 2005 | December 31, 2004 | December 31, 2003 | |||||||||
The following presents information about the assumed health care
cost trend rate:
| Year Ended | ||||||||
| December 31, | ||||||||
| 2006 | 2005 | |||||||
|
Health care cost trend rate assumed for next year
|
7.50% | 7.00% | ||||||
|
Rate to which the cost trend is assumed to decline (the ultimate
trend rate)
|
4.75% | 4.75% | ||||||
|
Year that the rate reaches the ultimate trend rate
|
2012 | 2011 | ||||||
Assumed health care cost trend rates have a significant effect
on the amounts reported for health care plans. A
one-percentage-point change in the assumed health care cost
trend would have the following effects:
| One-Percentage- | One-Percentage- | |||||||
| Point Increase | Point Decrease | |||||||
| (Dollars in thousands) | ||||||||
|
Effect on total service and interest cost components
|
$ | 9,501 | $ | (7,989 | ) | |||
|
Effect on total postretirement benefit obligation
|
$ | 179,264 | $ | (150,765 | ) | |||
F-43
Table of Contents
PEABODY ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
| 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 thousands) | ||||
|
2007
|
$ | 82,631 | ||
|
2008
|
87,710 | |||
|
2009
|
91,683 | |||
|
2010
|
95,985 | |||
|
2011
|
100,312 | |||
|
Years 2012-2016
|
568,391 | |||
| Medicare and Other Plan Changes |
Effective November 15, 2006, the medical premium
reimbursement plan was changed for salaried employees who
retired after December 31, 2004. The plan change did not
apply to Powder River or Lee Ranch employees. The amendment
resulted in a $20.6 million increase to the retiree health
care liability. The Company began recognizing the effect of the
plan amendment over 10.25 years beginning November 15,
2006. The effect was $0.3 million for the year ended
December 31, 2006, and is estimated to be $2.0 million
for the full year ended December 31, 2007.
On December 8, 2003, the Medicare Prescription Drug,
Improvement and Modernization Act of 2003 (the “Act”)
was signed into law. The Company elected not to defer the
effects of the Act as discussed in FASB Staff Position 106-1,
“Accounting and Disclosure Requirements Related to the
Medicare Prescription Drug, Improvement and Modernization Act of
2003.” Additionally, the Company did not elect the federal
subsidy provisions of the Act; rather the Company coordinated
benefits with available Medicare coverage considered the primary
payer, whether or not the beneficiary enrolled and paid the
required premiums.
The Company recognized a reduction in the benefit obligation on
two distinct components. For plans that required amendment to
incorporate the Act, the Company recognized a liability
reduction of $19.1 million. This reduction was treated as a
negative plan amendment and is being amortized to income over
six years beginning December 15, 2003. For plans that did
not require amendment, the Company recognized a liability
reduction of $162.4 million. The reduction was treated as a
change in the estimated cost to provide benefits to Medicare
eligible beneficiaries constituting a component of the
cumulative actuarial gain or loss subject to amortization in
accordance with the Company’s amortization method.
In July 2001, the Company adopted changes to the prescription
drug program. Effective January 1, 2002, an incentive mail
order and comprehensive utilization management program was added
to the prescription drug program. At the time of adoption, the
effect of the change on the retiree health care liability was
$38.4 million. The Company began recognizing the effect of
the plan amendment over three years beginning July 1, 2001.
Net periodic postretirement benefit costs were reduced by
$6.4 million for the year ended December 31, 2004, for
this change.
In January 1999, the Company adopted reductions to the salaried
employee medical coverage levels for employees retiring before
January 1, 2003, which was changed to January 1, 2005,
in 2002. For
F-44
Table of Contents
PEABODY ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
employees retiring on or after January 1, 2005, the
previous medical plan was replaced with a medical premium
reimbursement plan. This plan change did not apply to Powder
River or Lee Ranch salaried employees. The change in the retiree
health care plan resulted in a $22.4 million reduction to
the salaried retiree health care liability. The Company began
recognizing the effect of the plan amendment over nine years
beginning January 1, 1999. The effect was
$1.0 million, $1.0 million and $2.5 million for
the years ended December 31, 2006, 2005 and 2004,
respectively.
| Multi-Employer Benefit Plans |
Retirees formerly employed by certain subsidiaries and their
predecessors, who were members of the UMWA, last worked before
January 1, 1976 and were receiving health benefits on
July 20, 1992, receive health benefits provided by the
Combined Fund, a fund created by the Coal Act. The Coal Act
requires former employers (including certain subsidiaries of the
Company) and their affiliates to contribute to the Combined Fund
according to a formula.
The Company has recorded an actuarially determined liability
representing the amounts anticipated to be due to the Combined
Fund. The noncurrent portion related to this obligation as
reflected within “Other noncurrent liabilities” in the
consolidated balance sheets as of December 31, 2006 and
2005, was $25.6 million and $27.9 million,
respectively. The current portion related to this obligation
reflected in “Accounts payable and accrued expenses”
in the consolidated balance sheets as of December 31, 2006
and 2005, was $5.2 million and $8.8 million,
respectively.
Expense of $2.5 million was recognized related to the
Combined Fund for the year ended December 31, 2006, and
consisted of interest discount of $2.4 million and
amortization of actuarial loss of $0.1 million. Expense of
$0.9 million was recognized related to the Combined Fund
for the year ended December 31, 2005, and consisted of
interest discount of $1.0 million and amortization of
actuarial gain of $0.1 million. Expense of
$4.9 million was recognized related to the Combined Fund
for the year ended December 31, 2004, and consisted of
interest discount of $3.8 million and amortization of
actuarial loss of $1.1 million. The Company made
contributions of $8.3 million, $4.0 million and
$16.6 million to the Combined Fund for the years ended
December 31, 2006, 2005 and 2004, respectively.
The Coal Act also established the 1992 Benefit Plan, which
provides medical and death benefits to persons who are not
eligible for the Combined Fund, who retired prior to
October 1, 1994 and whose employer and any affiliates are
no longer in business. A prior national labor agreement
established the 1993 Benefit Plan to provide health benefits for
retired miners not covered by the Coal Act. The 1993 Benefit
Plan provides benefits to qualifying retired former employees,
who retired after September 30, 1994, of certain signatory
companies which have gone out of business and defaulted in
providing their former employees with retiree medical benefits.
Beneficiaries continue to be added to this fund as employers go
out of business. The 1992 Benefit Plan and the 1993 Benefit Plan
qualify under SFAS No. 106 as multi-employer benefit
plans, which allows the Company to recognize expense as
contributions are made. The expense related to these funds was
$5.7 million, $4.0 million and $4.4 million for
the years ended December 31, 2006, 2005 and 2004,
respectively.
The Surface Mining Control and Reclamation Act Amendments of
2006 (the “2006 Act”), which was enacted in December
2006, amended the federal laws establishing the Combined Fund,
1992 Benefit Plan and the 1993 Benefit Plan. Among other things,
the 2006 Act guarantees full funding of all beneficiaries in the
Combined Fund, provides funds on a phased-in basis for the 1992
Benefit Plan, and authorizes the trustees of the 1993 Benefit
Plan to determine the contribution rates through 2010 for
pre-2007 beneficiaries. The new and additional federal
expenditures to the Combined Fund, 1992 Benefit Plan, 1993
Benefit Plan and certain Abandoned Mine Land payments to the
states and Indian tribes are collectively limited by an
aggregate annual cap of $490 million. To the extent that
(i) the annual funding of the programs exceeds this amount
(plus the amount of interest from the Abandoned Mine Land trust
F-45
Table of Contents
PEABODY ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
fund paid with respect to the Combined Benefit Fund), and
(ii) Congress does not allocate additional funds to cover
the shortfall, contributing employers and affiliates, including
some of the Company’s subsidiaries, would be responsible
for the additional costs.
Pursuant to the provisions of the Coal Act and the 1992 Benefit
Plan, the Company was required to provide security in an amount
equal to three times the annual cost of providing health care
benefits for all individuals receiving benefits from the 1992
Benefit Plan who are attributable to the Company, plus all
individuals receiving benefits from an individual employer plan
maintained by the Company who are entitled to receive such
benefits. In accordance with the 1992 Benefit Plan, the Company
had outstanding letters of credit of $119.4 million as of
December 31, 2006, to secure the Company’s obligation.
Beginning in 2007, the amount of security the Company is
required to provide for the 1992 Plan is reduced to one times
the annual cost to provide the above mentioned health care
benefits.
| (17) | Stockholders’ Equity |
| Common Stock |
The Company has 800.0 million authorized shares of
$0.01 par value common stock. Holders of common stock are
entitled to one vote per share on all matters to be voted upon
by the stockholders. The holders of common stock do not have
cumulative voting rights in the election of directors. Holders
of common stock are entitled to receive ratably dividends if, as
and when dividends are declared from time to time by the Board
of Directors out of funds legally available for that purpose,
after payment of dividends required to be paid on outstanding
preferred stock or series common stock. Upon liquidation,
dissolution or winding up, any business combination or a sale or
disposition of all or substantially all of the assets, the
holders of common stock are entitled to receive ratably the
assets available for distribution to the stockholders after
payment of liabilities and accrued but unpaid dividends and
liquidation preferences on any outstanding preferred stock or
series common stock. The common stock has no preemptive or
conversion rights and is not subject to further calls or
assessment by the Company. There are no redemption or sinking
fund provisions applicable to the common stock.
Effective February 22, 2006, the Company implemented a
two-for-one stock split on all shares of its common stock. The
Company had a similar two-for-one stock split on March 30,
2005. All share and per share amounts in these consolidated
financial statements and related notes reflect the stock splits.
On March 23, 2004, the Company completed an offering of
35.3 million shares of the Company’s common stock,
priced at $11.25 per share. Net proceeds from the offering,
after deducting underwriting discounts and commissions and other
expenses, were $383.1 million, and were primarily used, as
discussed in Note 4, to fund the acquisition of three coal
operations from RAG Coal International AG.
F-46
Table of Contents
PEABODY ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
The following table summarizes common share activity from
December 31, 2003 to December 31, 2006:
| Shares | |||||
| Outstanding | |||||
|
December 31, 2003
|
218,587,016 | ||||
|
Equity offering
|
35,300,000 | ||||
|
Stock options exercised
|
4,953,868 | ||||
|
Employee stock purchases
|
297,648 | ||||
|
Stock grants to non-employee directors
|
17,512 | ||||
|
Shares repurchased
|
(20,136 | ) | |||
|
December 31, 2004
|
259,135,908 | ||||
|
Stock options exercised
|
3,633,750 | ||||
|
Stock grants to employees
|
375,400 | ||||
|
Employee stock purchases
|
210,750 | ||||
|
Stock grants to non-employee directors
|
1,594 | ||||
|
December 31, 2005
|
263,357,402 | ||||
|
Stock options exercised
|
1,940,539 | ||||
|
Stock grants to employees
|
566,631 | ||||
|
Employee stock purchases
|
156,785 | ||||
|
Stock grants to non-employee directors
|
10,440 | ||||
|
Shares repurchased
|
(2,184,958 | ) | |||
|
December 31, 2006
|
263,846,839 | ||||
| Preferred Stock and Series Common Stock |
In addition to the common stock, the Board of Directors is
authorized to issue up to 10.0 million shares of preferred
stock and up to 40.0 million shares of series common stock.
The Board of Directors is authorized to determine the terms and
rights of each series, including the number of authorized
shares, whether dividends (if any) will be cumulative or
non-cumulative and the dividend rate of the series, redemption
or sinking fund provisions, conversion terms, prices and rates,
and amounts payable on shares of the series in the event of any
voluntary or involuntary liquidation, dissolution or winding up
of the affairs of the Company. The Board of Directors may also
determine restrictions on the issuance of shares of the same
series or of any other class or series, and the voting rights
(if any) of the holders of the series. There were no outstanding
shares of preferred stock or series common stock as of
December 31, 2006.
| Perpetual Preferred Stock |
As discussed in Note 12, the Company issued
$732.5 million aggregate principal amount of Debentures on
December 20, 2006. Perpetual preferred stock issued upon a
conversion of Debentures will be fully paid and non-assessable,
and holders will have no preemptive or preferential right to
purchase any of the 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. After the
Company has failed to pay dividends on the perpetual preferred
stock for five years, or upon the occurrence of a mandatory
trigger event, as defined in the certificate of designations
governing
F-47
Table of Contents
PEABODY ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
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 ten 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, 2006.
| 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, 2006.
| Treasury Stock |
In July 2005, the Company’s Board of Directors authorized a
share repurchase program of up to 5% of the then outstanding
shares of its common stock, or approximately 13.1 million
shares. The repurchases may be made from time to time based on
an evaluation of the Company’s outlook and general business
conditions, as well as alternative investment and debt repayment
options. During the year ended December 31, 2006, the
Company repurchased 2,184,958 of its common shares at a cost of
$99.8 million.
During the year ended December 31, 2004, the Company
received 20,136 shares of common stock as consideration for
employees’ exercise of stock options. The value of the
common stock tendered by employees to exercise stock options was
based upon the closing price on the dates of the respective
transactions. The common stock tenders were in accordance with
the provisions of the 1998 Stock Purchase and Option Plan, which
was previously approved by the Company’s Board of Directors.
F-48
Table of Contents
PEABODY ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
| (18) | Share-Based Compensation |
The Company recognizes share-based compensation expense in
accordance with SFAS No. 123(R), which it adopted on
January 1, 2006, and utilizes restricted stock,
nonqualified stock options, performance units, and an employee
stock purchase plan as part of its share-based compensation
program. The Company has four equity incentive plans for
employees and non-employee directors that in the aggregate allow
for the issuance of share-based compensation in the form of
stock appreciation rights, restricted stock, performance awards,
incentive stock options, nonqualified stock options and stock
units. Members of the Company’s Board of Directors are
eligible for stock option and restricted stock grants at the
date of their election and annually in January. These plans made
47.4 million shares of the Company’s common stock
available for grant, with 15.0 million shares available for
grant as of December 31, 2006. Additionally, in 2001, the
Company established an employee stock purchase plan that
provided for the purchase of up to 6.0 million shares of
the Company’s common stock.
The Company began utilizing restricted stock as part of its
equity-based compensation strategy in January 2005. Accounting
for restricted stock awards was not changed by the adoption of
SFAS No. 123(R). The Company recognized
$4.2 million and $0.9 million of expense, net of
taxes, for the years ended December 31, 2006 and 2005,
respectively, related to restricted stock. For share-based
payment instruments excluding restricted stock, the Company
recognized $17.7 million (or $0.07 per diluted share),
$24.8 million (or $0.09 per diluted share) and
$12.8 million (or $0.05 per diluted share) of expense,
net of taxes, for the years ended December 31, 2006, 2005
and 2004, respectively. As a result of adopting
SFAS No. 123(R), the Company’s net income for the
year ended December 31, 2006 was $4.4 million (or
$0.02 per diluted share) lower than if it had continued to
account for share-based compensation under APB Opinion
No. 25. Share-based compensation expense is recorded in
“Selling and administrative expenses” in the
consolidated statements of operations. As of December 31,
2006, the total unrecognized compensation cost related to
nonvested awards was $24.0 million, net of taxes, which is
expected to be recognized over 5.0 years with a
weighted-average period of 1.3 years.
The Company used the Black-Scholes option pricing model to
determine the fair value of stock options and employee stock
purchase plan share-based payments made before and after the
adoption of SFAS No. 123(R). The Company utilized
U.S. Treasury yields as of the grant date for its risk-free
interest rate assumption, matching the treasury yield terms to
the expected life of the option or vesting period of the
performance unit awards. The Company utilized historical,
company data to develop its dividend yield, expected volatility
and expected option life assumptions.
| Stock Options |
Employee and director stock options granted since the
Company’s initial public offering (“IPO”) of
common stock in May 2001 generally vest ratably over three years
and expire after ten years from the date of the grant, subject
to earlier termination upon discontinuation of an
employee’s service. Options granted prior to the IPO
generally cliff vest in 2007 and 2010. Of the 9.3 million
options outstanding at December 31, 2006, 4.1 million
options cliff vest in November 2007. Option grants are typically
made in January of each year or following the inception of
employment for employees hired during the year who are eligible
to participate in the plan. The fair value of each option grant
is estimated on the date of grant using the Black-Scholes
option-pricing model. The Company recognized expense, net of
taxes, of $4.7 million, $0.1 million and
$0.2 million for the years ended December 31, 2006,
2005 and 2004, respectively, related to stock option grants to
employees and non-employee directors.
F-49
Table of Contents
PEABODY ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
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 | ||||||||||||||
| 2006 | Price | Life | (in millions) | ||||||||||||||
|
Beginning balance
|
10,783,786 | $ | 6.37 | ||||||||||||||
|
Granted
|
542,784 | 43.08 | |||||||||||||||
|
Exercised
|
(1,940,539 | ) | 8.05 | ||||||||||||||
|
Forfeited
|
(65,313 | ) | 5.69 | ||||||||||||||
|
Outstanding
|
9,320,718 | $ | 8.16 | 4.0 | $ | 302.0 | |||||||||||
|
Vested and Exercisable
|
2,515,670 | $ | 8.39 | 5.9 | $ | 80.6 | |||||||||||
|
Outstanding options:
|
|||||||||||||||||
|
Granted Pre-IPO
|
5,584,616 | ||||||||||||||||
|
Granted Post-IPO
|
3,736,102 | ||||||||||||||||
| 9,320,718 | |||||||||||||||||
|
Vested and exercisable options:
|
|||||||||||||||||
|
Granted Pre-IPO
|
235,720 | ||||||||||||||||
|
Granted Post-IPO
|
2,279,950 | ||||||||||||||||
| 2,515,670 | |||||||||||||||||
During the years ended December 31, 2006, 2005 and 2004,
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 $84.2 million, $77.6 million
and $40.5 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 (for
grants during the years ended December 31, 2006, 2005 and
2004) were as follows:
| December 31, | ||||||||||||
| 2006 | 2005 | 2004 | ||||||||||
|
Weighted-average fair value
|
$ | 16.52 | $ | 8.03 | $ | 4.46 | ||||||
|
Risk-free interest rate
|
4.3% | 3.6% | 3.9% | |||||||||
|
Expected option life
|
6.0 years | 5.7 years | 5.9 years | |||||||||
|
Expected volatility
|
36% | 40% | 40% | |||||||||
|
Dividend yield
|
0.8% | 1.0% | 1.0% | |||||||||
Prior to adopting SFAS No. 123(R), the Company applied
APB Opinion No. 25 and related interpretations to account
for its equity incentive plans. The following table reflects
2005 and 2004 pro forma net income and basic and diluted
earnings per share had compensation cost been determined for the
F-50
Table of Contents
PEABODY ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
Company’s non-qualified and incentive stock options based
on the fair value at the grant dates consistent with the
methodology set forth under SFAS No. 123:
| Year Ended December 31, | |||||||||
| 2005 | 2004 | ||||||||
| (Dollars in thousands | |||||||||
| except per share data) | |||||||||
|
Net income:
|
|||||||||
|
As reported
|
$ | 422,653 | $ | 175,387 | |||||
|
Pro forma
|
418,704 | 168,628 | |||||||
|
Basic earnings per share:
|
|||||||||
|
As reported
|
$ | 1.62 | $ | 0.71 | |||||
|
Pro forma
|
1.60 | 0.68 | |||||||
|
Diluted earnings per share:
|
|||||||||
|
As reported
|
$ | 1.58 | $ | 0.69 | |||||
|
Pro forma
|
1.56 | 0.66 | |||||||
| Performance Units |
Performance units, which are typically granted annually in
January, vest over a three-year measurement period, subject to
the achievement of performance goals and stock price performance
at the conclusion of the three years. Three performance unit
grants were outstanding during 2006 (the 2004, 2005 and 2006
grants) and 2005 (the 2003, 2004 and 2005 grants). The payout
related to the 2003 grant (which was settled in cash in February
2006) was based on the Company’s stock price performance
compared to both an industry peer group and a S&P index. The
payouts related to the 2004 grant (which will be settled in cash
in January 2007) and 2005 and 2006 grants (which will be settled
in common stock in 2008 and 2009, respectively) are based 50% on
stock price performance compared to both an industry peer group
and a S&P index (a “market condition” under
SFAS No. 123(R)) and 50% on a return on capital target
(a “performance condition” under
SFAS No. 123(R)). During the years ended
December 31, 2006, 2005, and 2004, the Company granted
0.2 million, 0.2 million and 0.5 million
performance units in each period, respectively. Under APB
Opinion No. 25, all of the performance unit awards were
accounted for as variable awards. Under
SFAS No. 123(R), the awards settled in cash are
accounted for as liability awards and adjusted to fair value at
each period-end, and the awards settled in common stock are
accounted for based on their grant date fair value. The
performance condition awards were valued utilizing the grant
date fair values of the 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 shareholder return hurdles set for
each grant. The Company recognized expense, net of taxes, of
$11.7 million, $24.7 million, and $12.6 million
for the years ended December 31, 2006, 2005, and 2004,
respectively, related to performance units. The assumptions used
in the valuations for grants during the years ended
December 31, 2006 and 2005 were as follows:
| December 31, | ||||||||
| 2006 | 2005 | |||||||
|
Risk-free interest rate
|
4.3% | 3.3% | ||||||
|
Expected volatility
|
36% | 40% | ||||||
|
Dividend yield
|
0.8% | 1.0% | ||||||
F-51
Table of Contents
PEABODY ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
| Employee Stock Purchase Plan |
Based on the Company’s employee stock purchase plan,
eligible full-time and part-time employees are able to
contribute up to 15% of their base compensation into this plan,
subject to a limit of $25,000 per person per year.
Employees are able to purchase Company common stock at a 15%
discount to the lower of the fair market value of the
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 fair value of the
six-month “look-back” option in the Company’s
employee stock purchase plan is estimated by adding the fair
value of 0.15 of one share of stock to the fair value of 0.85 of
an option on one share of stock. The Company recognized expense,
net of taxes, of $1.3 million for the year ended
December 31, 2006 related to its employee stock purchase
plan. Shares purchased under the plan were 0.2 million,
0.2 million and 0.3 million for the years ended
December 31, 2006, 2005 and 2004, respectively.
| (19) | Accumulated Other Comprehensive Income (Loss) |
The following table sets forth the after-tax components of
comprehensive income (loss):
| Net | ||||||||||||||||||||||||
| Actuarial Loss | ||||||||||||||||||||||||
| Associated with | ||||||||||||||||||||||||
| Postretirement | Prior Service | Total | ||||||||||||||||||||||
| Foreign | Minimum | Plans and | Cost Associated | Accumulated | ||||||||||||||||||||
| Currency | Pension | Workers’ | with | Other | ||||||||||||||||||||
| Translation | Liability | Compensation | Postretirement | Cash Flow | Comprehensive | |||||||||||||||||||
| Adjustment | Adjustment | Obligations | Plans | Hedges | Loss | |||||||||||||||||||
| (Dollars in thousands) | ||||||||||||||||||||||||
|
December 31, 2003
|
$ | 3,153 | $ | (77,684 | ) | $ | — | $ | — | $ | (7,041 | ) | $ | (81,572 | ) | |||||||||
|
Net increase in value of cash flow hedges
|
— | — | — | — | 17,329 | 17,329 | ||||||||||||||||||
|
Reclassification from other comprehensive income to earnings
|
— | — | — | — | (2,414 | ) | (2,414 | ) | ||||||||||||||||
|
Current period change
|
— | 6,039 | — | — | — | 6,039 | ||||||||||||||||||
|
December 31, 2004
|
$ | 3,153 | $ | (71,645 | ) | $ | — | $ | — | $ | 7,874 | $ | (60,618 | ) | ||||||||||
|
Net increase in value of cash flow hedges
|
— | — | — | — | 36,154 | 36,154 | ||||||||||||||||||
|
Reclassification from other comprehensive income to earnings
|
— | — | — | — | (24,733 | ) | (24,733 | ) | ||||||||||||||||
|
Current period change
|
— | 2,402 | — | — | — | 2,402 | ||||||||||||||||||
|
December 31, 2005
|
$ | 3,153 | $ | (69,243 | ) | $ | — | $ | — | $ | 19,295 | $ | (46,795 | ) | ||||||||||
|
Net increase in value of cash flow hedges
|
— | — | — | — | 45,799 | 45,799 | ||||||||||||||||||
|
Reclassification from other comprehensive income to earnings
|
— | — | — | — | (21,452 | ) | (21,452 | ) | ||||||||||||||||
|
Current period change
|
— | 22,377 | — | — | — | 22,377 | ||||||||||||||||||
|
Adjustment to initially apply SFAS No. 158
|
— | 46,866 | (288,820 | ) | (7,033 | ) | — | (248,987 | ) | |||||||||||||||
|
December 31, 2006
|
$ | 3,153 | $ | — | $ | (288,820 | ) | $ | (7,033 | ) | $ | 43,642 | $ | (249,058 | ) | |||||||||
F-52
Table of Contents
PEABODY ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
Comprehensive income differs from net income by the amount of
unrealized gain or loss resulting from valuation changes of the
Company’s cash flow hedges (which include fuel and natural
gas hedges, currency forwards and interest rate swaps) during
the periods, and for the year ended December 31, 2006, the
adjustment required by SFAS No. 158 to record the
funded status of the Company’s pension and other
post-retirement benefit plans. The values of the Company’s
cash flow hedging instruments are affected by changes in
interest rates, crude oil, heating oil and natural gas prices
and the U.S. dollar/ Australian dollar exchange rate.
| (20) | Related Party Transactions |
On March 23, 2004, August 4, 2003, and May 7,
2003, Lehman Brothers Merchant Banking Partners II L.P. and
affiliates (“Merchant Banking Fund”), the
Company’s largest stockholder as of those dates, sold
41.1 million, 21.6 million, and 22.5 million
shares, respectively, of the Company’s common stock. The
Company did not receive any proceeds from the sales of shares by
Merchant Banking Fund. The March 2004 offering completed
Merchant Banking Fund’s planned exit strategy and
eliminated the remaining portion of their beneficial ownership
of the Company.
Lehman Brothers Inc. (“Lehman Brothers”) is an
affiliate of the Merchant Banking Fund. In March 2004, Morgan
Stanley and Lehman Brothers served as joint managers in
connection with the secondary equity offering discussed above.
Lehman Brothers received from third parties customary
underwriting discounts and commissions from the offering. The
Company paid no fees to Lehman Brothers related to the secondary
equity offerings.
Lehman Brothers served as lead underwriter in connection with
the Company’s sale of limited partner interests in PVR in
March 2004 and December 2003, as discussed in Note 9 above.
Lehman Brothers received customary fees, plus reimbursement of
certain expenses, for those services.
| (21) | Guarantees and Financial Instruments With Off-Balance-Sheet Risk |
In the normal course of business, the Company is a party to
guarantees and financial instruments with off-balance-sheet
risk, such as bank letters of credit, performance or surety
bonds and other guarantees and indemnities, which are not
reflected in the accompanying consolidated balance sheets. Such
financial instruments are valued based on the amount of exposure
under the instrument and the likelihood of required performance.
In the Company’s past experience, virtually no claims have
been made against these financial instruments. Management does
not expect any material losses to result from these guarantees
or off-balance-sheet instruments.
| Letters of Credit and Bonding |
The Company has letters of credit, surety bonds and corporate
guarantees (such as self bonds) in support of the Company’s
reclamation, lease, workers’ compensation, retiree
healthcare and other obligations as follows as of
December 31, 2006:
| Workers’ | Retiree | |||||||||||||||||||||||
| Reclamation | Lease | Compensation | Healthcare | |||||||||||||||||||||
| Obligations | Obligations | Obligations | Obligations | Other(1) | Total | |||||||||||||||||||
| (Dollars in thousands) | ||||||||||||||||||||||||
|
Self Bonding
|
$ | 685,235 | $ | — | $ | — | $ | — | $ | 2,917 | $ | 688,152 | ||||||||||||
|
Surety Bonds
|
441,524 | 83,877 | 31,646 | — | 27,245 | 584,292 | ||||||||||||||||||
|
Letters of Credit
|
4,125 | 20,282 | 156,826 | 119,397 | 208,783 | 509,413 | ||||||||||||||||||
| $ | 1,130,884 | $ | 104,159 | $ | 188,472 | $ | 119,397 | $ | 238,945 | $ | 1,781,857 | |||||||||||||
F-53
Table of Contents
PEABODY ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
| (1) | Other includes the three letter of credit obligations described below and an additional $54.1 million in self- bonding, letters of credit and surety bonds related to collateral for surety companies, road maintenance, performance guarantees and other operations. |
The Company owns a 30.0% interest in a partnership that leases a
coal export terminal from the Peninsula Ports Authority of
Virginia under a
30-year lease that
permits the partnership to purchase the terminal at the end of
the lease term for a nominal amount. The partners have severally
(but not jointly) agreed to make payments under various
agreements which in the aggregate provide the partnership with
sufficient funds to pay rents and to cover the principal and
interest payments on the floating-rate industrial revenue bonds
issued by the Peninsula Ports Authority, and which are supported
by letters of credit from a commercial bank. As of
December 31, 2006, the Company’s maximum reimbursement
obligation to the commercial bank was in turn supported by a
letter of credit totaling $42.8 million.
The Company is party to an agreement with the Pension Benefit
Guarantee Corporation (“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 United States) and continues
under this process as of December 31, 2006. 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.
In conjunction with the acquisition of Excel, the Company issued
a $105.0 million letter of credit as collateral for bank
guarantees issued with respect to certain reclamation and
performance obligations.
| Other Guarantees |
As part of arrangements through which the Company obtains
exclusive sales representation agreements with small coal mining
companies (the “Counterparties”), the Company issued
financial guarantees on behalf of the Counterparties. These
guarantees facilitate the Counterparties’ efforts to obtain
bonding or financing. In July 2006, the Company issued
$5.2 million of financial guarantees, expiring at various
dates through July 2013, on behalf of a certain Counterparty to
facilitate its efforts in obtaining financing. In the event of
default, the Company has multiple recourse options, including
the ability to assume the loans and procure title and use of the
equipment purchased through the loans. If default occurs, the
Company has the ability and intent to exercise its recourse
options, so the liability associated with the guarantee has been
valued at zero. The Company also guaranteed bonding for a
partnership in which it formerly held an interest. The aggregate
amount guaranteed by the Company for all such Counterparties was
$12.1 million, and the fair value of the guarantees
recognized as a liability was $0.4 million as of
December 31, 2006. The Company’s obligations under the
guarantees extend to September 2015.
In March 2006, the Company issued a guarantee for certain
equipment lease arrangements on behalf of one of the sales
representation parties with maximum potential future payments
totaling $2.7 million at December 31, 2006, and with
lease terms that extend to April 2010. The Company has multiple
recourse options in the event of default, including the ability
to assume the lease and procure use of the equipment
F-54
Table of Contents
PEABODY ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
or to settle the lease and take title to the assets. If default
occurs, the Company has the ability and intent to exercise its
recourse options, so the liability associated with the guarantee
has been valued at zero.
The Company is the lessee under numerous equipment and property
leases. It is common in such commercial lease transactions for
the Company, as the lessee, to agree to indemnify the lessor for
the value of the property or equipment leased, should the
property be damaged or lost during the course of the
Company’s operations. The Company expects that losses with
respect to leased property would be covered by insurance
(subject to deductibles). The Company and certain of its
subsidiaries have guaranteed other subsidiaries’
performance under their various lease obligations. Aside from
indemnification of the lessor for the value of the property
leased, the Company’s maximum potential obligations under
its leases are equal to the respective future minimum lease
payments as presented in Note 9, and the Company assumes
that no amounts could be recovered from third parties.
The Company has provided financial guarantees under certain
long-term debt agreements entered into by its subsidiaries, and
substantially all of the Company’s subsidiaries provide
financial guarantees under long-term debt agreements entered
into by the Company. The maximum amounts payable under the
Company’s debt agreements are equal to the respective
principal and interest payments. See Note 12 for the
descriptions of the Company’s (and its subsidiaries’)
debt. Supplemental guarantor/non-guarantor financial information
is provided in Note 26.
In connection with the sale of Citizens Power LLC
(“Citizens Power”), the Company has indemnified the
buyer from certain losses resulting from specified power
contracts and guarantees. The indemnity is described in detail
in Note 23. A discussion of the Company’s accounts
receivable securitization is included in Note 6 to the
consolidated financial statements.
| (22) | Fair Value of Financial Instruments |
The following methods and assumptions were used by the Company
in estimating its fair value disclosures for financial
instruments as of December 31, 2006 and 2005:
| • | Cash and cash equivalents, accounts receivable and accounts payable and accrued expenses have carrying values which approximate fair value due to the short maturity or the financial nature of these instruments. | |
| • | The fair value of the Company’s coal trading assets and liabilities was determined as described in Note 5. | |
| • | Long-term debt fair value estimates are based on observed prices for securities with an active trading market when available, and otherwise on estimated borrowing rates to discount the cash flows to their present value. The 7.875% Senior Notes due 2026 and the 5.0% Subordinated Note carrying amount are net of unamortized note discount. | |
| • | The fair values of interest rate swap contracts, currency forward contracts, explosives hedge contracts and fuel hedge contracts were provided by the respective contract counterparties, and were based on benchmark transactions entered into on terms substantially similar to those entered into by the Company and the contract counterparties. Based on these estimates as of December 31, 2006, the Company would have paid $10.9 million and $6.6 million, respectively, upon liquidation of its interest rate swaps and explosives hedges and would have received $64.1 million and $12.9 million, respectively, upon liquidation of its currency forwards and diesel fuel hedges. | |
| • | At December 31, 2005, “Other noncurrent liabilities” included a deferred purchase obligation related to the prior purchase of a mine facility. The fair value estimate was based on the same assumption as long-term debt. This obligation was paid in full during 2006. |
F-55
Table of Contents
PEABODY ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
The carrying amounts and estimated fair values of the
Company’s debt and deferred purchase obligation are
summarized as follows:
| December 31, 2006 | December 31, 2005 | |||||||||||||||
| Carrying | Estimated | Carrying | Estimated | |||||||||||||
| Amount | Fair Value | Amount | Fair Value | |||||||||||||
| (Dollars in thousands) | ||||||||||||||||
|
Long-term debt
|
$ | 3,263,826 | $ | 3,297,384 | $ | 1,405,506 | $ | 1,389,666 | ||||||||
|
Deferred purchase obligation
|
— | — | 1,397 | 1,402 | ||||||||||||
See Note 2 for a discussion of the Company’s
derivative financial instruments.
| (23) | Commitments and Contingencies |
| Commitments |
As of December 31, 2006, purchase commitments for capital
expenditures were $125.8 million. Commitments for
expenditures to be made under coal leases are reflected in
Note 9.
| Litigation Relating to Continuing Operations |
| Navajo Nation Litigation |
On June 18, 1999, the Navajo Nation served three of the
Company’s subsidiaries, including Peabody Western Coal
Company (“Peabody Western”), with a complaint that had
been filed in the U.S. District Court for the District of
Columbia. The Navajo Nation has alleged 16 claims, including
Civil Racketeer Influenced and Corrupt Organizations Act
(“RICO”) violations and fraud. The complaint alleges
that the defendants jointly participated in unlawful activity to
obtain favorable coal lease amendments. The plaintiff is seeking
various remedies including actual damages of at least
$600 million, which could be trebled under the RICO counts,
punitive damages of at least $1 billion, a determination
that Peabody Western’s two coal leases have terminated due
to Peabody Western’s breach of these leases and a
reformation of these leases to adjust the royalty rate to 20%.
Subsequently, the court allowed the Hopi Tribe to intervene in
this lawsuit and the Hopi Tribe is also seeking unspecified
actual damages, punitive damages and reformation of its coal
lease. On March 4, 2003, the U.S. Supreme Court issued
a ruling in a companion lawsuit involving the Navajo Nation and
the United States rejecting the Navajo Nation’s allegation
that the United States breached its trust responsibilities to
the Tribe in approving the coal lease amendments. On
February 9, 2005, the U.S. District Court for the
District of Columbia granted a consent motion to stay the
litigation until further order of the court. Peabody Western,
the Navajo Nation, the Hopi Tribe and the owners of the power
plants served by the suspended Black Mesa mine and the Kayenta
mine are in mediation with respect to this litigation and other
business issues.
The outcome of this litigation, or the current mediation, 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, the
Company believes this matter is likely to be resolved without a
material adverse effect on its financial condition, results of
operations or cash flows.
| Salt River Project Agricultural Improvement and Power District — Mine Closing and Retiree Health Care |
Salt River Project and the other owners of the Navajo Generating
Station filed a lawsuit on September 27, 1996, in the
Superior Court of Maricopa County in Arizona seeking a
declaratory judgment that certain costs relating to final
reclamation, environmental monitoring work and mine
decommissioning and costs primarily relating to retiree health
care benefits are not recoverable by the Company’s
subsidiary, Peabody Western, under the terms of a coal supply
agreement dated February 18, 1977. The contract
F-56
Table of Contents
PEABODY ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
expires in 2011. The trial court subsequently ruled that the
mine decommissioning costs were subject to arbitration but that
the retiree health care costs were not subject to arbitration.
The Company has recorded a receivable for mine decommissioning
costs of $76.8 million and $74.2 million included in
“Investments and other assets” in the consolidated
balance sheets as of December 31, 2006 and 2005,
respectively.
The outcome of this litigation and arbitration 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, 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.
| Gulf Power Company Litigation |
On June 21, 2006, the Company’s subsidiary filed a
complaint in the U.S. District Court, Southern District of
Illinois, seeking a declaratory judgment upholding its
declaration of a permanent force majeure under a coal supply
agreement with Gulf Power Company. On June 22, 2006, Gulf
Power Company filed a breach of contract lawsuit against the
Company’s subsidiary in the U.S. District Court,
Northern District of Florida, contesting the force majeure
declaration and seeking damages for alleged past and future
tonnage shortfalls of nearly 5 million tons under the coal
supply agreement, which would have expired on December 31,
2007. The parties have filed motions to determine which court
will hear the lawsuits. On October 6, 2006, the Florida
District Court stayed Gulf Power’s lawsuit until the
Illinois court decides whether it has jurisdiction.
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, 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 |
| Citizens Power |
In connection with the August 2000 sale of the Company’s
former subsidiary, Citizens Power LLC (“Citizens
Power”), the Company has indemnified the buyer, Edison
Mission Energy, from certain losses resulting from specified
power contracts and guarantees. During the period that Citizens
Power was owned by the Company, Citizens Power guaranteed the
obligations of two affiliates to make payments to third parties
for power delivered under fixed-priced power sales agreements
with terms that extend through 2008. Edison Mission Energy has
stated and the Company believes there will be sufficient cash
flow to pay the power suppliers, assuming timely payment by the
power purchasers. There is no pending litigation with respect to
these indemnities at this time. In 2004, the Company incurred
costs related to restructuring one of the indemnified power
purchase agreements of $2.8 million, net of a tax benefit
of $1.9 million. These amounts are classified within
discontinued operations in the statement of 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. Today Gold Fields is 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
F-57
Table of Contents
PEABODY ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
two lead mills near Picher, Oklahoma prior to the 1950s and
mined, in accordance with lease agreements and permits,
approximately 0.15% of the total amount of the crude ore mined
in the county.
Gold Fields and two other companies are defendants in two class
action lawsuits. The plaintiffs have asserted claims predicated
on allegations of intentional lead exposure by the defendants
and are seeking compensatory damages, punitive damages and the
implementation of medical monitoring and relocation programs for
the affected individuals. Gold Fields is also a defendant, along
with other companies, in several personal injury lawsuits
involving over 50 children, arising out of the same lead mill
operations. Plaintiffs in these actions are seeking compensatory
and punitive damages for alleged personal injuries from lead
exposure. The first personal injury trial has been scheduled for
March 2007 and Gold Fields along with the former affiliate will
be the only defendants. In December 2003, the Quapaw Indian
tribe and certain Quapaw land owners filed a class action
lawsuit against Gold Fields and five other companies. The
plaintiffs are seeking compensatory and punitive damages based
on a variety of theories. Gold Fields has filed a third-party
complaint against the United States, and other parties. In
February 2005, the state of Oklahoma on behalf of itself and
several other parties sent a notice to Gold Fields and other
companies regarding a possible natural resources damage claim.
All of the lawsuits are pending in the U.S. District Court
for the Northern District of Oklahoma.
The outcome of litigation and these claims are subject to
numerous uncertainties. Based on the Company’s evaluation
of the issues and their potential impact, the amount of any
future loss cannot be reasonably estimated. However, 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 |
The Company is subject to applicable federal, state and local
environmental laws and regulations in those countries where it
conducts operations. Current and past mining operations in the
United States are primarily covered by the Surface Mining
Control and Reclamation Act of 1977, the Clean Water Act and the
Clean Air Act but also include the Comprehensive Environmental
Response, Compensation and Liability Act of 1980, as amended
(“CERCLA” or “Superfund”), the Superfund
Amendments and Reauthorization Act of 1986 and the Resource
Conservation and Recovery Act of 1976. Superfund and similar
state laws create liability for investigation and remediation in
response to releases of hazardous substances in the environment
and for damages to natural resources. Under that legislation and
many state Superfund statutes, joint and several liability may
be imposed on waste generators, site owners and operators and
others regardless of fault. These regulations could require us
to do some or all of the following: (i) remove or mitigate
the effects on the environment at various sites from the
disposal or release of certain substances; (ii) perform
remediation work at such sites; and (iii) pay damages for
loss of use and non-use values.
The Company’s policy is to accrue environmental
cleanup-related costs of a non-capital nature when those costs
are believed to be probable and can be reasonably estimated. The
quantification of environmental exposures requires an assessment
of many factors, including the nature and extent of
contamination, the timing, extent and method of the remedial
action, changing laws and regulations, advancements in
environmental technologies, the quality of information available
related to specific sites, the assessment stage of each site
investigation, preliminary findings and the length of time
involved in remediation or settlement. The Company also assesses
the financial capability and proportional share of costs of
other PRPs and, where allegations are based on tentative
findings, the reasonableness of its apportionment. The Company
has not anticipated any recoveries from insurance carriers in
the estimation of liabilities recorded in its consolidated
balance sheets.
Although waste substances generated by coal mining and
processing are generally not regarded as hazardous substances
for the purposes of Superfund and similar legislation and are
generally covered by
F-58
Table of Contents
PEABODY ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
the Surface Mining Control and Reclamation Act of 1977, some
products used by coal companies in operations, such as
chemicals, and the disposal of these products are governed by
the Superfund statute. Thus, coal mines currently or previously
owned or operated by the Company, and sites to which the Company
has sent waste materials, may be subject to liability under
Superfund and similar state laws.
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”) based on CERCLA at five
sites, and claims have been asserted at 18 other sites. 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 $43.0 million as of
December 31, 2006 and $42.5 million as of
December 31, 2005, $14.4 million and
$23.6 million of which was reflected as a current
liability, respectively. These amounts represent those costs
that the Company believes are probable and reasonably estimable.
In September 2005, Gold Fields and other PRPs received a letter
from the U.S. Department of Justice alleging that the
PRPs’ mining operations caused the Environmental Protection
Agency (“EPA”) to incur approximately
$125 million in residential yard remediation costs at
Picher, Oklahoma and will cause the EPA to incur additional
remediation costs relating to historical mining sites. Gold
Fields has participated in the ongoing settlement discussions. 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
believes it has meritorious defenses to these claims. Gold
Fields is involved in other litigation in the Picher area, and
the Company indemnified TXU Group with respect to a defendant as
is more fully discussed under the “Oklahoma Lead
Litigation” caption above. Significant uncertainty exists
as to whether claims will be pursued against Gold Fields in all
cases, and where they are pursued, the amount of the eventual
costs and liabilities, which could be greater or less than this
provision.
| 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. 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.
F-59
Table of Contents
PEABODY ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
| (24) | Summary Quarterly Financial Information (Unaudited) |
A summary of the unaudited quarterly results of operations for
the years ended December 31, 2006 and 2005, is presented
below. Peabody Energy common stock is listed on the New York
Stock Exchange under the symbol “BTU.”
| Year Ended December 31, 2006 | ||||||||||||||||
| First Quarter | Second Quarter | Third Quarter | Fourth Quarter | |||||||||||||
| (Dollars in thousands except per share and stock price data) | ||||||||||||||||
|
Revenues
|
$ | 1,311,810 | $ | 1,316,388 | $ | 1,264,988 | $ | 1,363,129 | ||||||||
|
Operating profit
|
171,241 | 175,695 | 173,004 | 143,142 | ||||||||||||
|
Net income
|
130,222 | 153,434 | 142,008 | 175,033 | ||||||||||||
|
Basic earnings per share
|
$ | 0.49 | $ | 0.58 | $ | 0.54 | $ | 0.67 | ||||||||
|
Diluted earnings per share
|
$ | 0.48 | $ | 0.57 | $ | 0.53 | $ | 0.65 | ||||||||
|
Weighted average shares used in calculating basic earnings per
share
|
263,491,072 | 263,958,590 | 263,444,254 | 262,790,879 | ||||||||||||
|
Weighted average shares used in calculating diluted earnings per
share
|
269,358,728 | 269,756,666 | 268,822,681 | 268,137,610 | ||||||||||||
|
Stock price — high and low prices
|
$ | 52.54-$41.24 | $ | 76.29-$46.81 | $ | 59.90-$32.94 | $ | 48.59-$34.05 | ||||||||
|
Dividends per share
|
$ | 0.06 | $ | 0.06 | $ | 0.06 | $ | 0.06 | ||||||||
Second quarter operating profit included $39.2 million of
gains resulting from exchanges of coal reserves (see Note 3
for information). Net income for the second quarter included the
tax benefit related to a reduction in tax reserves due to the
favorable finalization of former parent companies federal tax
audits, partially offset by higher pretax earnings in 2006.
Operating profit in the third and fourth quarters of 2006
included $30.0 million and $28.9 million,
respectively, of gains from the sale of non-strategic coal
reserves and surface lands (see Note 3 for information).
Operating profit for the third quarter of 2006 benefited from
lower performance-based compensation expense of
$20.6 million. Net income for the fourth
F-60
Table of Contents
PEABODY ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
quarter of 2006 included a tax benefit related to the partial
reduction in net operating loss valuation allowances (see
Note 11 for information).
| Year Ended December 31, 2005 | ||||||||||||||||
| First Quarter | Second Quarter | Third Quarter | Fourth Quarter | |||||||||||||
| (Dollars in thousands except per share and stock price data) | ||||||||||||||||
|
Revenues
|
$ | 1,077,480 | $ | 1,108,786 | $ | 1,223,510 | $ | 1,234,677 | ||||||||
|
Operating profit
|
80,803 | 129,309 | 150,885 | 157,386 | ||||||||||||
|
Net income
|
51,890 | 95,254 | 113,340 | 162,169 | ||||||||||||
|
Basic earnings per share
|
$ | 0.20 | $ | 0.36 | $ | 0.43 | $ | 0.62 | ||||||||
|
Diluted earnings per share
|
$ | 0.19 | $ | 0.36 | $ | 0.42 | $ | 0.60 | ||||||||
|
Weighted average shares used in calculating basic earnings per
share
|
260,693,518 | 261,630,146 | 262,432,394 | 263,076,194 | ||||||||||||
|
Weighted average shares used in calculating diluted earnings per
share
|
266,801,306 | 267,620,416 | 268,521,976 | 268,975,324 | ||||||||||||
|
Stock price — high and low prices
|
$ | 25.47-$18.38 | $ | 28.23-$19.68 | $ | 43.03-$26.01 | $ | 43.48-$35.22 | ||||||||
|
Dividends per share
|
$ | 0.0375 | $ | 0.0375 | $ | 0.0475 | $ | 0.0475 | ||||||||
Operating profit for the first quarter of 2005 included a
$31.1 million gain on the sale of PVR common units as
discussed in Note 9 offset by $34.0 million of
contract losses primarily related to a breach of a coal supply
contract by a producer. Second quarter operating profit included
$12.5 million of gains from property sales and a
$12.5 million reduction of estimated contract losses
recorded in the first quarter of 2005. Operating profit in the
third quarter of 2005 included $43.6 million of gains
resulting from exchanges of assets and an additional
$6.7 million recovery of the contract losses recorded in
the first quarter. Operating profit for the third quarter and
fourth quarter of 2005 included charges related to long-term
compensation plans of $18.6 million and $11.6 million,
respectively. Net income for the fourth quarter of 2005 included
the tax benefit realized from the deemed liquidation of a
subsidiary as discussed in Note 11 partially offset by an
increase in the valuation allowance on NOL carryforwards.
| (25) | Segment Information |
The Company reports its operations primarily through the
following reportable operating segments: “Western
U.S. Mining,” “Eastern U.S. Mining,”
“Australian Mining” and “Trading and
Brokerage.” Western U.S. Mining operations reflect the
aggregation of the Powder River Basin, Southwest and Colorado
operating segments, and Eastern U.S. Mining operations
reflect the aggregation of the Appalachia and Midwest operating
segments. The principal business of the Western
U.S. Mining, Eastern U.S. Mining and Australian Mining
segments is the mining, preparation and sale of steam coal, sold
primarily to electric utilities, and metallurgical coal, sold to
steel and coke producers. For the year ended December 31,
2006, 87% of the Company’s sales were to
U.S. electricity generators, 4% were to the
U.S. industrial sector, and 9% were to customers outside
the United States. Western U.S. Mining operations are
characterized by predominantly surface mining extraction
processes, lower sulfur content and Btu of coal and longer
shipping distances from the mine to the customer. Conversely,
Eastern U.S. Mining operations are characterized by a
majority of underground mining extraction processes, higher
sulfur content and Btu of coal and shorter shipping distances
from the mine to the customer. Geologically, Western operations
mine bituminous and subbituminous coal deposits, and Eastern
operations mine bituminous coal deposits. Australian Mining
operations are characterized by both surface and underground
extraction processes, mining low-sulfur, high Btu coal
(metallurgical coal) as well as steam coal primarily
F-61
Table of Contents
PEABODY ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
sold to an international customer base with a small portion sold
to Australian steel producers and power generators. The Trading
and Brokerage segment’s principal business is the
marketing, brokerage and trading of coal. “Corporate and
Other” includes selling and administrative expenses, net
gains on property disposals, costs associated with past mining
obligations, joint venture earnings related to the
Company’s 25.5% investment in a Venezuelan mine and
revenues and expenses related to the Company’s other
commercial activities such as coalbed methane, generation
development and resource management.
The Company’s chief operating decision maker uses Adjusted
EBITDA as the primary measure of segment profit and loss.
Adjusted EBITDA is defined as income from continuing operations
before deducting early debt extinguishment costs, net interest
expense, income taxes, minority interests, asset retirement
obligation expense and depreciation, depletion and amortization.
Operating segment results for the year ended December 31,
2006 were as follows:
| Western | Eastern | Australian | Trading and | Corporate | ||||||||||||||||||||
| U.S. Mining | U.S. Mining | Mining | Brokerage | and Other | Consolidated | |||||||||||||||||||
| (Dollars in thousands) | ||||||||||||||||||||||||
|
Revenues
|
$ | 1,703,445 | $ | 2,035,841 | $ | 843,194 | $ | 652,029 | $ | 21,806 | $ | 5,256,315 | ||||||||||||
|
Adjusted EBITDA
|
473,074 | 384,107 | 278,411 | 92,604 | (147,792 | ) | 1,080,404 | |||||||||||||||||
|
Total assets
|
2,628,070 | 1,420,795 | 2,784,922 | 240,329 | 2,439,940 | 9,514,056 | ||||||||||||||||||
|
Additions to property, plant, equipment and mine development
|
151,572 | 142,739 | 123,242 | 1,045 | 59,123 | 477,721 | ||||||||||||||||||
|
Federal coal lease expenditures
|
178,193 | — | — | — | — | 178,193 | ||||||||||||||||||
|
Income (loss) from equity affiliates
|
15 | (3,778 | ) | — | — | 27,615 | 23,852 | |||||||||||||||||
Operating segment results for the year ended December 31,
2005 were as follows:
| Western | Eastern | Australian | Trading and | Corporate | ||||||||||||||||||||
| U.S. Mining | U.S. Mining | Mining | Brokerage | and Other | Consolidated | |||||||||||||||||||
| (Dollars in thousands) | ||||||||||||||||||||||||
|
Revenues
|
$ | 1,611,587 | $ | 1,738,681 | $ | 598,085 | $ | 679,176 | $ | 16,924 | $ | 4,644,453 | ||||||||||||
|
Adjusted EBITDA
|
459,039 | 374,628 | 202,582 | 43,058 | (208,909 | ) | 870,398 | |||||||||||||||||
|
Total assets
|
2,566,034 | 1,136,738 | 426,810 | 212,550 | 2,509,874 | 6,852,006 | ||||||||||||||||||
|
Additions to property, plant, equipment and mine development
|
113,047 | 88,320 | 85,335 | — | 97,602 | 384,304 | ||||||||||||||||||
|
Federal coal lease expenditures
|
118,364 | — | — | — | — | 118,364 | ||||||||||||||||||
|
Purchase of mining and related assets
|
84,695 | 34,988 | — | — | 21,512 | 141,195 | ||||||||||||||||||
|
Income from equity affiliates
|
14 | 9,718 | — | — | 20,364 | 30,096 | ||||||||||||||||||
F-62
Table of Contents
PEABODY ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS — (Continued)
Operating segment results for the year ended December 31,
2004 were as follows:
| Western | Eastern | Australian | Trading and | Corporate | ||||||||||||||||||||
| U.S. Mining | U.S. Mining | Mining | Brokerage | and Other | Consolidated | |||||||||||||||||||
| (Dollars in thousands) | ||||||||||||||||||||||||
|
Revenues
|
$ | 1,393,622 | $ | 1,501,352 | $ | 270,926 | $ | 454,537 | $ | 11,145 | $ | 3,631,582 | ||||||||||||
|
Adjusted EBITDA
|
402,052 | 280,357 | 50,372 | 41,039 | (214,576 | ) | 559,244 | |||||||||||||||||
|
Additions to property, plant, equipment and mine development
|
52,541 | 66,418 | 19,665 | 23 | 13,297 | 151,944 | ||||||||||||||||||
|
Federal coal lease expenditures
|
114,653 | — | — | — | — | 114,653 | ||||||||||||||||||
|
Income from equity affiliates
|
21 | 8,666 | — | — | 3,712 | 12,399 | ||||||||||||||||||
A reconciliation of adjusted EBITDA to consolidated income from
continuing operations follows:
| Year Ended December 31, | ||||||||||||
| 2006 | 2005 | 2004 | ||||||||||
| (Dollars in thousands) | ||||||||||||
|
Total adjusted EBITDA
|
$ | 1,080,404 | $ | 870,398 | $ | 559,244 | ||||||
|
Depreciation, depletion and amortization
|
(377,210 | ) | (316,114 | ) | (270,159 | ) | ||||||
|
Asset retirement obligation expense
|
(40,112 | ) | (35,901 | ) | (42,387 | ) | ||||||
|
Interest expense
|
(143,450 | ) | (102,939 | ) | (96,793 | ) | ||||||
|
Early debt extinguishment costs
|
(1,396 | ) | — | (1,751 | ) | |||||||
|
Interest income
|
12,726 | 10,641 | 4,917 | |||||||||
|
Income tax (provision) benefit
|
81,515 | (960 | ) | 26,437 | ||||||||
|
Minority interests
|
(11,780 | ) | (2,472 | ) | (1,282 | ) | ||||||
|
Income from continuing operations
|
$ | 600,697 | $ | 422,653 | $ | 178,226 | ||||||
| (26) | Supplemental Guarantor/ Non-Guarantor Financial Information |
In accordance with the indentures governing the
6.875% Senior Notes due March 2013, the 5.875% Senior
Notes due March 2016, the 7.375% Senior Notes due November
2016 and the 7.875% Senior Notes due November 2026, certain
wholly-owned U.S. subsidiaries of the Company have fully
and unconditionally guaranteed these Senior Notes, on a joint
and several basis. Separate financial statements and other
disclosures concerning the Guarantor Subsidiaries are not
presented because management believes that such information is
not material to the Senior Note holders. The following
historical financial statement information is provided for the
Guarantor/ Non-Guarantor Subsidiaries.
F-63
Table of Contents
PEABODY ENERGY CORPORATION
SUPPLEMENTAL CONSOLIDATED STATEMENTS OF OPERATIONS
| Year Ended December 31, 2006 | ||||||||||||||||||||||
| Parent | Guarantor | Non-Guarantor | ||||||||||||||||||||
| Company | Subsidiaries | Subsidiaries | Eliminations | Consolidated | ||||||||||||||||||
| (Dollars in thousands) | ||||||||||||||||||||||
|
Total revenues
|
$ | — | $ | 3,978,220 | $ | 1,384,186 | $ | (106,091 | ) | $ | 5,256,315 | |||||||||||
|
Costs and expenses:
|
||||||||||||||||||||||
|
Operating costs and expenses
|
(15,307 | ) | 3,239,215 | 1,038,167 | (106,091 | ) | 4,155,984 | |||||||||||||||
|
Depreciation, depletion and amortization
|
— | 301,363 | 75,847 | — | 377,210 | |||||||||||||||||
|
Asset retirement obligation expense
|
— | 39,483 | 629 | — | 40,112 | |||||||||||||||||
|
Selling and administrative expenses
|
17,188 | 155,221 | 3,532 | — | 175,941 | |||||||||||||||||
|
Other operating income:
|
||||||||||||||||||||||
|
Net gain on disposal or exchange of assets
|
— | (121,705 | ) | (10,457 | ) | — | (132,162 | ) | ||||||||||||||
|
(Income) loss from equity affiliates
|
— | 4,167 | (28,019 | ) | — | (23,852 | ) | |||||||||||||||
|
Interest expense
|
197,130 | 56,372 | 16,716 | (126,768 | ) | 143,450 | ||||||||||||||||
|
Early debt extinguishment costs
|
1,396 | — | — | — | 1,396 | |||||||||||||||||
|
Interest income
|
(21,426 | ) | (91,272 | ) | (26,796 | ) | 126,768 | (12,726 | ) | |||||||||||||
|
Income (loss) before income taxes and minority interests
|
(178,981 | ) | 395,376 | 314,567 | — | 530,962 | ||||||||||||||||
|
Income tax provision (benefit)
|
(59,661 | ) | (83,903 | ) | 62,049 | — | (81,515 | ) | ||||||||||||||
|
Minority interests
|
— | — | 11,780 | — | 11,780 | |||||||||||||||||
|
Net income (loss)
|
$ | (119,320 | ) | $ | 479,279 | $ | 240,738 | $ | — | $ | 600,697 | |||||||||||
F-64
Table of Contents
PEABODY ENERGY CORPORATION
SUPPLEMENTAL CONSOLIDATED STATEMENTS OF OPERATIONS
| Year Ended December 31, 2005 | ||||||||||||||||||||||
| Parent | Guarantor | Non-Guarantor | ||||||||||||||||||||
| Company | Subsidiaries | Subsidiaries | Eliminations | Consolidated | ||||||||||||||||||
| (Dollars in thousands) | ||||||||||||||||||||||
|
Total revenues
|
$ | — | $ | 3,698,928 | $ | 1,037,449 | $ | (91,924 | ) | $ | 4,644,453 | |||||||||||
|
Costs and expenses:
|
||||||||||||||||||||||
|
Operating costs and expenses
|
(30,188 | ) | 3,022,125 | 815,823 | (91,924 | ) | 3,715,836 | |||||||||||||||
|
Depreciation, depletion and amortization
|
— | 282,234 | 33,880 | — | 316,114 | |||||||||||||||||
|
Asset retirement obligation expense
|
— | 35,230 | 671 | — | 35,901 | |||||||||||||||||
|
Selling and administrative expenses
|
3,683 | 176,731 | 9,388 | — | 189,802 | |||||||||||||||||
|
Other operating income:
|
||||||||||||||||||||||
|
Net gain on disposal or exchange of assets
|
— | (101,227 | ) | (260 | ) | — | (101,487 | ) | ||||||||||||||
|
Income from equity affiliates
|
— | (10,097 | ) | (19,999 | ) | — | (30,096 | ) | ||||||||||||||
|
Interest expense
|
154,307 | 57,060 | 21,175 | (129,603 | ) | 102,939 | ||||||||||||||||
|
Interest income
|
(22,759 | ) | (90,995 | ) | (26,490 | ) | 129,603 | (10,641 | ) | |||||||||||||
|
Income (loss) before income taxes and minority interests
|
(105,043 | ) | 327,867 | 203,261 | — | 426,085 | ||||||||||||||||
|
Income tax provision (benefit)
|
(28,961 | ) | (11,015 | ) | 40,936 | — | 960 | |||||||||||||||
|
Minority interests
|
— | — | 2,472 | — | 2,472 | |||||||||||||||||
|
Net income (loss)
|
$ | (76,082 | ) | $ | 338,882 | $ | 159,853 | $ | — | $ | 422,653 | |||||||||||
F-65
Table of Contents
PEABODY ENERGY CORPORATION
SUPPLEMENTAL CONSOLIDATED STATEMENTS OF OPERATIONS
| Year Ended December 31, 2004 | ||||||||||||||||||||||
| Parent | Guarantor | Non-Guarantor | ||||||||||||||||||||
| Company | Subsidiaries | Subsidiaries | Eliminations | Consolidated | ||||||||||||||||||
| (Dollars in thousands) | ||||||||||||||||||||||
|
Total revenues
|
$ | — | $ | 3,170,683 | $ | 529,222 | $ | (68,323 | ) | $ | 3,631,582 | |||||||||||
|
Costs and expenses:
|
||||||||||||||||||||||
|
Operating costs and expenses
|
(5,230 | ) | 2,577,028 | 462,066 | (68,323 | ) | 2,965,541 | |||||||||||||||
|
Depreciation, depletion and amortization
|
— | 257,027 | 13,132 | — | 270,159 | |||||||||||||||||
|
Asset retirement obligation expense
|
— | 41,081 | 1,306 | — | 42,387 | |||||||||||||||||
|
Selling and administrative expenses
|
1,460 | 136,031 | 5,534 | — | 143,025 | |||||||||||||||||
|
Other operating income:
|
||||||||||||||||||||||
|
Net gain on disposal or exchange of assets
|
— | (23,386 | ) | (443 | ) | — | (23,829 | ) | ||||||||||||||
|
Income from equity affiliates
|
— | (11,161 | ) | (1,238 | ) | — | (12,399 | ) | ||||||||||||||
|
Interest expense
|
143,790 | 88,806 | 12,090 | (147,893 | ) | 96,793 | ||||||||||||||||
|
Early debt extinguishment costs
|
1,751 | — | — | — | 1,751 | |||||||||||||||||
|
Interest income
|
(51,977 | ) | (81,132 | ) | (19,701 | ) | 147,893 | (4,917 | ) | |||||||||||||
|
Income (loss) from continuing operations before income taxes and
minority interests
|
(89,794 | ) | 186,389 | 56,476 | — | 153,071 | ||||||||||||||||
|
Income tax provision (benefit)
|
(25,364 | ) | (4,677 | ) | 3,604 | — | (26,437 | ) | ||||||||||||||
|
Minority interests
|
— | 275 | 1,007 | — | 1,282 | |||||||||||||||||
|
Income (loss) from continuing operations
|
(64,430 | ) | 190,791 | 51,865 | — | 178,226 | ||||||||||||||||
|
Loss from discontinued operations, net of taxes
|
— | (2,839 | ) | — | — | (2,839 | ) | |||||||||||||||
|
Net income (loss)
|
$ | (64,430 | ) | $ | 187,952 | $ | 51,865 | $ | — | $ | 175,387 | |||||||||||
F-66
Table of Contents
PEABODY ENERGY CORPORATION
SUPPLEMENTAL CONSOLIDATED BALANCE SHEETS
| December 31, 2006 | ||||||||||||||||||||||
| Parent | Guarantor | Non-Guarantor | ||||||||||||||||||||
| Company | Subsidiaries | Subsidiaries | Eliminations | Consolidated | ||||||||||||||||||
| (Dollars in thousands) | ||||||||||||||||||||||
| ASSETS | ||||||||||||||||||||||
|
Current assets
|
||||||||||||||||||||||
|
Cash and cash equivalents
|
$ | 272,226 | $ | 3,652 | $ | 50,633 | $ | — | $ | 326,511 | ||||||||||||
|
Accounts receivable
|
— | 41,199 | 317,043 | — | 358,242 | |||||||||||||||||
|
Inventories
|
— | 146,920 | 68,464 | — | 215,384 | |||||||||||||||||
|
Assets from coal trading activities
|
— | 150,373 | — | — | 150,373 | |||||||||||||||||
|
Deferred income taxes
|
— | 106,967 | — | — | 106,967 | |||||||||||||||||
|
Other current assets
|
54,007 | 41,221 | 21,635 | — | 116,863 | |||||||||||||||||
|
Total current assets
|
326,233 | 490,332 | 457,775 | — | 1,274,340 | |||||||||||||||||
|
Property, plant, equipment and mine development
|
||||||||||||||||||||||
|
Land and coal interests
|
— | 4,974,446 | 2,152,939 | — | 7,127,385 | |||||||||||||||||
|
Buildings and improvements
|
— | 769,770 | 123,279 | — | 893,049 | |||||||||||||||||
|
Machinery and equipment
|
— | 1,220,670 | 296,095 | — | 1,516,765 | |||||||||||||||||
|
Less accumulated depreciation, depletion and amortization
|
— | (1,794,823 | ) | (190,859 | ) | — | (1,985,682 | ) | ||||||||||||||
|
Property, plant, equipment and mine development, net
|
— | 5,170,063 | 2,381,454 | — | 7,551,517 | |||||||||||||||||
|
Goodwill
|
— | — | 240,667 | — | 240,667 | |||||||||||||||||
|
Investments and other assets
|
7,235,765 | 34,195 | 100,115 | (6,922,543 | ) | 447,532 | ||||||||||||||||
|
Total assets
|
$ | 7,561,998 | $ | 5,694,590 | $ | 3,180,011 | $ | (6,922,543 | ) | $ | 9,514,056 | |||||||||||
| LIABILITIES AND STOCKHOLDERS’ EQUITY | ||||||||||||||||||||||
|
Current liabilities
|
||||||||||||||||||||||
|
Current maturities of long-term debt
|
$ | 27,350 | $ | 60,522 | $ | 7,885 | $ | — | $ | 95,757 | ||||||||||||
|
Payables and notes payable to affiliates, net
|
2,025,605 | (2,170,567 | ) | 144,962 | — | — | ||||||||||||||||
|
Liabilities from coal trading activities
|
— | 126,731 | — | — | 126,731 | |||||||||||||||||
|
Accounts payable and accrued expenses
|
46,748 | 759,002 | 339,293 | — | 1,145,043 | |||||||||||||||||
|
Total current liabilities
|
2,099,703 | (1,224,312 | ) | 492,140 | — | 1,367,531 | ||||||||||||||||
|
Long-term debt, less current maturities
|
3,017,107 | 12,373 | 138,589 | — | 3,168,069 | |||||||||||||||||
|
Deferred income taxes
|
29,094 | (25,077 | ) | 191,196 | — | 195,213 | ||||||||||||||||
|
Other noncurrent liabilities
|
20,411 | 2,294,247 | 96,722 | — | 2,411,380 | |||||||||||||||||
|
Total liabilities
|
5,166,315 | 1,057,231 | 918,647 | — | 7,142,193 | |||||||||||||||||
|
Minority interests
|
— | — | 33,337 | — | 33,337 | |||||||||||||||||
|
Stockholders’ equity
|
2,395,683 | 4,637,359 | 2,228,027 | (6,922,543 | ) | 2,338,526 | ||||||||||||||||
|
Total liabilities and stockholders’ equity
|
$ | 7,561,998 | $ | 5,694,590 | $ | 3,180,011 | $ | (6,922,543 | ) | $ | 9,514,056 | |||||||||||
F-67
Table of Contents
PEABODY ENERGY CORPORATION
SUPPLEMENTAL CONSOLIDATED BALANCE SHEETS
| December 31, 2005 | ||||||||||||||||||||||
| Parent | Guarantor | Non-Guarantor | ||||||||||||||||||||
| Company | Subsidiaries | Subsidiaries | Eliminations | Consolidated | ||||||||||||||||||
| (Dollars in thousands) | ||||||||||||||||||||||
| ASSETS | ||||||||||||||||||||||
|
Current assets
|
||||||||||||||||||||||
|
Cash and cash equivalents
|
$ | 494,232 | $ | 2,471 | $ | 6,575 | $ | — | $ | 503,278 | ||||||||||||
|
Accounts receivable
|
4,260 | 59,137 | 138,737 | — | 202,134 | |||||||||||||||||
|
Inventories
|
— | 329,116 | 60,655 | — | 389,771 | |||||||||||||||||
|
Assets from coal trading activities
|
— | 146,596 | — | — | 146,596 | |||||||||||||||||
|
Deferred income taxes
|
— | 9,027 | — | — | 9,027 | |||||||||||||||||
|
Other current assets
|
21,817 | 23,347 | 9,267 | — | 54,431 | |||||||||||||||||
|
Total current assets
|
520,309 | 569,694 | 215,234 | — | 1,305,237 | |||||||||||||||||
|
Property, plant, equipment and mine development
|
||||||||||||||||||||||
|
Land and coal interests
|
— | 4,395,485 | 379,641 | — | 4,775,126 | |||||||||||||||||
|
Buildings and improvements
|
— | 696,427 | 96,827 | — | 793,254 | |||||||||||||||||
|
Machinery and equipment
|
— | 989,719 | 247,465 | — | 1,237,184 | |||||||||||||||||
|
Less accumulated depreciation, depletion and amortization
|
— | (1,541,834 | ) | (86,022 | ) | — | (1,627,856 | ) | ||||||||||||||
|
Property, plant, equipment and mine development, net
|
— | 4,539,797 | 637,911 | — | 5,177,708 | |||||||||||||||||
|
Investments and other assets
|
4,971,500 | 311,512 | 63,432 | (4,977,383 | ) | 369,061 | ||||||||||||||||
|
Total assets
|
$ | 5,491,809 | $ | 5,421,003 | $ | 916,577 | $ | (4,977,383 | ) | $ | 6,852,006 | |||||||||||
| LIABILITIES AND STOCKHOLDERS’ EQUITY | ||||||||||||||||||||||
|
Current liabilities
|
||||||||||||||||||||||
|
Current maturities of long-term debt
|
$ | 10,625 | $ | 11,034 | $ | 926 | $ | — | $ | 22,585 | ||||||||||||
|
Payables and notes payable to affiliates, net
|
1,875,361 | (2,355,684 | ) | 480,323 | — | — | ||||||||||||||||
|
Liabilities from coal trading activities
|
— | 132,373 | — | — | 132,373 | |||||||||||||||||
|
Accounts payable and accrued expenses
|
24,560 | 732,319 | 111,086 | — | 867,965 | |||||||||||||||||
|
Total current liabilities
|
1,910,546 | (1,479,958 | ) | 592,335 | — | 1,022,923 | ||||||||||||||||
|
Long-term debt, less current maturities
|
1,312,521 | 69,014 | 1,386 | — | 1,382,921 | |||||||||||||||||
|
Deferred income taxes
|
12,903 | 304,740 | 20,845 | — | 338,488 | |||||||||||||||||
|
Other noncurrent liabilities
|
11,282 | 1,908,158 | 7,217 | — | 1,926,657 | |||||||||||||||||
|
Total liabilities
|
3,247,252 | 801,954 | 621,783 | — | 4,670,989 | |||||||||||||||||
|
Minority interests
|
— | — | 2,550 | — | 2,550 | |||||||||||||||||
|
Stockholders’ equity
|
2,244,557 | 4,619,049 | 292,244 | (4,977,383 | ) | 2,178,467 | ||||||||||||||||
|
Total liabilities and stockholders’ equity
|
$ | 5,491,809 | $ | 5,421,003 | $ | 916,577 | $ | (4,977,383 | ) | $ | 6,852,006 | |||||||||||
F-68
Table of Contents
PEABODY ENERGY CORPORATION
SUPPLEMENTAL CONSOLIDATED STATEMENTS OF CASH FLOWS
| Year Ended December 31, 2006 | ||||||||||||||||
| Parent | Guarantor | Non-Guarantor | ||||||||||||||
| Company | Subsidiaries | Subsidiaries | Consolidated | |||||||||||||
| (Dollars in thousands) | ||||||||||||||||
|
Cash Flows From Operating Activities
|
||||||||||||||||
|
Net cash provided by (used in) operating activities
|
$ | (166,841 | ) | $ | 447,114 | $ | 315,453 | $ | 595,726 | |||||||
|
Cash Flows From Investing Activities
|
||||||||||||||||
|
Acquisition of Excel Coal, net of cash acquired
|
— | — | (1,507,775 | ) | (1,507,775 | ) | ||||||||||
|
Additions to property, plant, equipment and mine development
|
— | (342,019 | ) | (135,702 | ) | (477,721 | ) | |||||||||
|
Federal coal lease expenditures
|
— | (118,364 | ) | (59,829 | ) | (178,193 | ) | |||||||||
|
Proceeds from disposal of assets, net of notes receivable
|
— | 66,494 | 11,085 | 77,579 | ||||||||||||
|
Other acquisitions, net
|
— | — | (44,538 | ) | (44,538 | ) | ||||||||||
|
Additions to advance mining royalties
|
— | (9,194 | ) | (1,827 | ) | (11,021 | ) | |||||||||
|
Investment in joint venture
|
— | (2,149 | ) | — | (2,149 | ) | ||||||||||
|
Net cash used in investing activities
|
— | (405,232 | ) | (1,738,586 | ) | (2,143,818 | ) | |||||||||
|
Cash Flows From Financing Activities
|
||||||||||||||||
|
Proceeds from long-term debt
|
2,579,383 | — | 912 | 2,580,295 | ||||||||||||
|
Payments of short-term and long-term debt
|
(853,180 | ) | (10,957 | ) | (181,836 | ) | (1,045,973 | ) | ||||||||
|
Common stock repurchase
|
(99,774 | ) | — | — | (99,774 | ) | ||||||||||
|
Dividends paid
|
(63,456 | ) | — | — | (63,456 | ) | ||||||||||
|
Payment of debt issuance costs
|
(40,611 | ) | — | — | (40,611 | ) | ||||||||||
|
Excess tax benefit related to stock options exercised
|
33,173 | — | — | 33,173 | ||||||||||||
|
Proceeds from stock options exercised
|
15,617 | — | — | 15,617 | ||||||||||||
|
Distributions to minority interests
|
— | — | (6,664 | ) | (6,664 | ) | ||||||||||
|
Decrease of securitized interests in accounts receivable
|
— | (5,800 | ) | — | (5,800 | ) | ||||||||||
|
Proceeds from employee stock purchases
|
4,518 | — | — | 4,518 | ||||||||||||
|
Transactions with affiliates, net
|
(1,630,835 | ) | (23,944 | ) | 1,654,779 | — | ||||||||||
|
Net cash provided by (used in) financing activities
|
(55,165 | ) | (40,701 | ) | 1,467,191 | 1,371,325 | ||||||||||
|
Net increase (decrease) in cash and cash equivalents
|
(222,006 | ) | 1,181 | 44,058 | (176,767 | ) | ||||||||||
|
Cash and cash equivalents at beginning of year
|
494,232 | 2,471 | 6,575 | 503,278 | ||||||||||||
|
Cash and cash equivalents at end of year
|
$ | 272,226 | $ | 3,652 | $ | 50,633 | $ | 326,511 | ||||||||
F-69
Table of Contents
PEABODY ENERGY CORPORATION
SUPPLEMENTAL CONSOLIDATED STATEMENTS OF CASH FLOWS
| Year Ended December 31, 2005 | ||||||||||||||||
| Parent | Guarantor | Non-Guarantor | ||||||||||||||
| Company | Subsidiaries | Subsidiaries | Consolidated | |||||||||||||
| (Dollars in thousands) | ||||||||||||||||
|
Cash Flows From Operating Activities
|
||||||||||||||||
|
Net cash provided by (used in) operating activities
|
$ | (126,861 | ) | $ | 648,599 | $ | 181,021 | $ | 702,759 | |||||||
|
Cash Flows From Investing Activities
|
||||||||||||||||
|
Additions to property, plant, equipment and mine development
|
— | (297,040 | ) | (87,264 | ) | (384,304 | ) | |||||||||
|
Purchase of mining and related assets
|
— | (56,500 | ) | (84,695 | ) | (141,195 | ) | |||||||||
|
Federal coal lease expenditures
|
— | — | (118,364 | ) | (118,364 | ) | ||||||||||
|
Proceeds from disposal of assets
|
— | 74,103 | 2,124 | 76,227 | ||||||||||||
|
Additions to advance mining royalties
|
— | (14,566 | ) | — | (14,566 | ) | ||||||||||
|
Investment in joint venture
|
— | (2,000 | ) | — | (2,000 | ) | ||||||||||
|
Net cash used in investing activities
|
— | (296,003 | ) | (288,199 | ) | (584,202 | ) | |||||||||
|
Cash Flows From Financing Activities
|
||||||||||||||||
|
Proceeds from long-term debt
|
— | 11,734 | — | 11,734 | ||||||||||||
|
Payments of long-term debt
|
(6,250 | ) | (12,959 | ) | (989 | ) | (20,198 | ) | ||||||||
|
Dividends paid
|
(44,535 | ) | — | — | (44,535 | ) | ||||||||||
|
Proceeds from stock options exercised
|
22,573 | — | — | 22,573 | ||||||||||||
|
Distributions to minority interests
|
— | (2,498 | ) | — | (2,498 | ) | ||||||||||
|
Increase of securitized interests in accounts receivable
|
— | — | 25,000 | 25,000 | ||||||||||||
|
Proceeds from employee stock purchases
|
3,009 | — | — | 3,009 | ||||||||||||
|
Transactions with affiliates, net
|
273,230 | (349,869 | ) | 76,639 | — | |||||||||||
|
Net cash provided by (used in) financing activities
|
248,027 | (353,592 | ) | 100,650 | (4,915 | ) | ||||||||||
|
Net increase (decrease) in cash and cash equivalents
|
121,166 | (996 | ) | (6,528 | ) | 113,642 | ||||||||||
|
Cash and cash equivalents at beginning of year
|
373,066 | 3,496 | 13,074 | 389,636 | ||||||||||||
|
Cash and cash equivalents at end of year
|
$ | 494,232 | $ | 2,500 | $ | 6,546 | $ | 503,278 | ||||||||
F-70
Table of Contents
PEABODY ENERGY CORPORATION
SUPPLEMENTAL CONSOLIDATED STATEMENTS OF CASH FLOWS
| Year Ended December 31, 2004 | ||||||||||||||||
| Parent | Guarantor | Non-Guarantor | ||||||||||||||
| Company | Subsidiaries | Subsidiaries | Consolidated | |||||||||||||
| (Dollars in thousands) | ||||||||||||||||
|
Cash Flows From Operating Activities
|
||||||||||||||||
|
Net cash provided by (used in) operating activities
|
$ | (81,656 | ) | $ | 296,240 | $ | 69,176 | $ | 283,760 | |||||||
|
Cash Flows From Investing Activities
|
||||||||||||||||
|
Additions to property, plant, equipment and mine development
|
— | (129,511 | ) | (22,433 | ) | (151,944 | ) | |||||||||
|
Federal coal lease expenditures
|
— | — | (114,653 | ) | (114,653 | ) | ||||||||||
|
Proceeds from disposal of assets
|
— | 38,408 | 931 | 39,339 | ||||||||||||
|
Acquisitions, net
|
— | (193,736 | ) | (235,325 | ) | (429,061 | ) | |||||||||
|
Additions to advance mining royalties
|
— | (15,989 | ) | (250 | ) | (16,239 | ) | |||||||||
|
Investment in joint venture
|
— | — | (32,472 | ) | (32,472 | ) | ||||||||||
|
Net cash used in investing activities
|
— | (300,828 | ) | (404,202 | ) | (705,030 | ) | |||||||||
|
Cash Flows From Financing Activities
|
||||||||||||||||
|
Proceeds from long-term debt
|
700,000 | 13 | — | 700,013 | ||||||||||||
|
Payments of long-term debt
|
(458,350 | ) | (22,921 | ) | (1,653 | ) | (482,924 | ) | ||||||||
|
Dividends paid
|
(32,568 | ) | — | — | (32,568 | ) | ||||||||||
|
Payment of debt issuance costs
|
(12,875 | ) | — | — | (12,875 | ) | ||||||||||
|
Net proceeds from equity offering
|
383,125 | — | — | 383,125 | ||||||||||||
|
Proceeds from stock options exercised
|
27,266 | — | — | 27,266 | ||||||||||||
|
Distributions to minority interests
|
— | (1,007 | ) | — | (1,007 | ) | ||||||||||
|
Increase of securitized interests in accounts receivable
|
— | — | 110,000 | 110,000 | ||||||||||||
|
Proceeds from employee stock purchases
|
2,374 | — | — | 2,374 | ||||||||||||
|
Transactions with affiliates, net
|
(268,825 | ) | 30,607 | 238,218 | — | |||||||||||
|
Net cash provided by financing activities
|
340,147 | 6,692 | 346,565 | 693,404 | ||||||||||||
|
Net increase in cash and cash equivalents
|
258,491 | 2,104 | 11,539 | 272,134 | ||||||||||||
|
Cash and cash equivalents at beginning of year
|
114,575 | 1,392 | 1,535 | 117,502 | ||||||||||||
|
Cash and cash equivalents at end of year
|
$ | 373,066 | $ | 3,496 | $ | 13,074 | $ | 389,636 | ||||||||
F-71
Table of Contents
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Directors and Stockholders
Peabody Energy Corporation
We have audited the consolidated financial statements of Peabody
Energy Corporation as of December 31, 2006 and 2005, and
for each of the three years in the period ended
December 31, 2006, and have issued our report thereon dated
February 20, 2007. Our audits also included the financial
statement schedule listed in Item 15(a). This schedule is
the responsibility of the Company’s management. Our
responsibility is to express an opinion based on our audits. In
our opinion, the financial statement schedule referred to above,
when considered in relation to the basic financial statements
taken as a whole, presents fairly in all material respects the
information set forth therein.
| /s/ Ernst & Young LLP |
St. Louis, Missouri
February 20, 2007
F-72
Table of Contents
PEABODY ENERGY CORPORATION
SCHEDULE II — VALUATION AND QUALIFYING
ACCOUNTS
| Balance at | Charged to | Balance | ||||||||||||||||||||
| Beginning | Costs and | at End of | ||||||||||||||||||||
| Description | of Period | Expenses | Deductions(1) | Other | Period | |||||||||||||||||
| (Dollars in thousands) | ||||||||||||||||||||||
|
Year Ended December 31, 2006
|
||||||||||||||||||||||
|
Reserves deducted from asset accounts:
|
||||||||||||||||||||||
|
Advance royalty recoupment reserve
|
$ | 17,250 | $ | — | $ | — | $ | (576 | ) (2) | $ | 16,674 | |||||||||||
|
Reserve for materials and supplies
|
4,945 | 168 | — | (414 | ) (2) | 4,699 | ||||||||||||||||
|
Allowance for doubtful accounts
|
10,853 | 446 | — | (155 | ) (2)/(4) | 11,144 | ||||||||||||||||
|
Year Ended December 31, 2005
|
||||||||||||||||||||||
|
Reserves deducted from asset accounts:
|
||||||||||||||||||||||
|
Advance royalty recoupment reserve
|
$ | 18,224 | $ | 867 | $ | (2,551 | ) | $ | 710 | (2) | $ | 17,250 | ||||||||||
|
Reserve for materials and supplies
|
4,419 | 581 | (1,574 | ) | 1,519 | (2) | 4,945 | |||||||||||||||
|
Allowance for doubtful accounts
|
1,361 | 20,305 | (3) | (5,860 | ) | (4,953 | ) (4) | 10,853 | ||||||||||||||
|
Year Ended December 31, 2004
|
||||||||||||||||||||||
|
Reserves deducted from asset accounts:
|
||||||||||||||||||||||
|
Advance royalty recoupment reserve
|
$ | 14,465 | $ | — | $ | — | $ | 3,759 | (2) | $ | 18,224 | |||||||||||
|
Reserve for materials and supplies
|
7,563 | 234 | (4,180 | ) | 802 | (2) | 4,419 | |||||||||||||||
|
Allowance for doubtful accounts
|
1,361 | — | — | — | 1,361 | |||||||||||||||||
| (1) | Reserves utilized, unless otherwise indicated. |
| (2) | Balances transferred (to) from other accounts or reserves recorded as part of a property transaction or acquisition. |
| (3) | Includes $19.5 million for the establishment of a reserve for the collectibility of certain receivables billed prior to 2005. |
| (4) | Reflects subsequent recovery of amounts previously reserved. |
F-73
Table of Contents
EXHIBIT INDEX
The exhibits below are numbered in accordance with the
Exhibit Table of Item 601 of
Regulation S-K.
| Exhibit | ||
| No. | Description of Exhibit | |
|
2.1
|
Merger Implementation Agreement, dated as of July 6, 2006, between the Registrant and Excel Coal Limited (Incorporated by reference to Exhibit 2.1 of the Registrant’s Current Report on Form 8-K, filed on July 7, 2006). | |
|
2.2
|
Deed of Variation — Merger Implementation Agreement, dated as of September 18, 2006, between the Registrant and Excel Coal Limited (Incorporated by reference to Exhibit 2.2 of the Registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2006, filed on November 7, 2006). | |
|
3.1
|
Third Amended and Restated Certificate of Incorporation of the Registrant, as amended (Incorporated by reference to Exhibit 3.1 of the Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2006, filed on August 7, 2006). | |
|
3.2
|
Amended and Restated By-Laws of the Registrant (Incorporated by reference to Exhibit 3.2 of the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2004, filed on March 16, 2005). | |
|
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 on July 24, 2002). | |
|
4.2
|
Certificate of Designations of Series A Junior Participating Preferred Stock of the Registrant, filed with the Secretary of State of the State of Delaware on July 24, 2002 (Incorporated herein by reference to Exhibit 3.1 to the Registrant’s Registration Statement on Form 8-A, filed on July 24, 2002). | |
|
4.3
|
Certificate of Adjustment delivered by the Registrant to Equiserve Trust Company, NA., as Rights Agent, on March 29, 2005 (Incorporated by reference to Exhibit 4.2 to Amendment No. 1 to the Registrant’s Registration Statement on Form 8-A, filed on March 29, 2005). | |
|
4.4
|
Certificate of Adjustment delivered by the Registrant to American Stock Transfer & Trust Company, as Rights Agent, on February 22, 2006 (Incorporated by reference to Exhibit 4.2 to Amendment No. 1 to the Registrant’s Registration Statement on Form 8-A, filed on 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 of the Registrant’s Form S-1 Registration Statement No. 333-55412). | |
|
4.6
|
67/8% Senior Notes Due 2013 Indenture, dated as of March 21, 2003, between the Registrant and US Bank National Association, as trustee (Incorporated by reference to Exhibit 4.27 of the Registrant’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2003, filed on May 13, 2003). | |
|
4.7
|
67/8% Senior Notes Due 2013 First Supplemental Indenture, dated as of May 7, 2003, among the Registrant, the Guaranteeing Subsidiaries (as defined therein), and US Bank National Association, as trustee (Incorporated by reference to Exhibit 4.3 of the Registrant’s Form S-4 Registration Statement No. 333-106208). | |
|
4.8
|
67/8% Senior Notes Due 2013 Second Supplemental Indenture, dated as of September 30, 2003, among the Registrant, the Guaranteeing Subsidiaries (as defined therein), and US Bank National Association, as trustee (Incorporated by reference to Exhibit 4.198 of the Registrant’s Form S-3 Registration Statement No. 333-109906, filed on October 22, 2003). | |
|
4.9
|
67/8% Senior Notes Due 2013 Third Supplemental Indenture, dated as of February 24, 2004, among the Registrant, the Guaranteeing Subsidiaries (as defined therein), and US Bank National Association, as trustee (Incorporated by reference to Exhibit 4.211 of the Registrant’s Form S-3/ A Registration Statement No. 333-109906, filed on March 4, 2004). | |
|
4.10
|
67/8% Senior Notes Due 2013 Fourth Supplemental Indenture, dated as of April 22, 2004, among the Registrant, the Guaranteeing Subsidiaries (as defined therein), and US Bank National Association, as trustee (Incorporated by reference to Exhibit 10.57 of the Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2004, filed on August 6, 2004). |
Table of Contents
| Exhibit | ||
| No. | Description of Exhibit | |
|
4.11
|
67/8% Senior Notes Due 2013 Fifth Supplemental Indenture, dated as of October 18, 2004, among the Registrant, the Guaranteeing Subsidiaries (as defined therein), and US Bank National Association, as trustee (Incorporated by reference to Exhibit 4.9 of the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2004, filed on March 16, 2005). | |
|
4.12
|
67/8% Senior Notes Due 2013 Sixth Supplemental Indenture, dated as of January 20, 2005, among the Registrant, the Guaranteeing Subsidiaries (as defined therein), and US Bank National Association, as trustee (Incorporated by reference to Exhibit 4.1 of the Registrant’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2005, filed on May 6, 2005). | |
|
4.13
|
67/8% Senior Notes Due 2013 Seventh Supplemental Indenture, dated as of September 30, 2005, among the Registrant, the Guaranteeing Subsidiaries (as defined therein), and US Bank National Association, as trustee (as defined therein), and US Bank National Association, as trustee (Incorporated by reference to Exhibit 4.1 of the Registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2005, filed on November 8, 2005). | |
|
4.14
|
67/8% Senior Notes Due 2013 Eighth Supplemental Indenture, dated as of January 20, 2006, among the Registrant, the Guaranteeing Subsidiaries (as defined therein), and US Bank National Association, as trustee (Incorporated by reference to Exhibit 4.14 of the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2005, filed on March 6, 2006). | |
|
4.15
|
67/8% Senior Notes Due 2013 Ninth Supplemental Indenture, dated as of June 13, 2006, among the Registrant, the Guaranteeing Subsidiaries (as defined therein), and US Bank National Association, as trustee (Incorporated by reference to Exhibit 4.1 of the Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2006, filed on August 7, 2006). | |
|
4.16
|
67/8% Senior Notes Due 2013 Tenth Supplemental Indenture, dated as of June 30, 2006, among the Registrant, the Guaranteeing Subsidiaries (as defined therein), and US Bank National Association, as trustee (Incorporated by reference to Exhibit 4.2 of the Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2006, filed on August 7, 2006). | |
|
4.17
|
67/8% Senior Notes Due 2013 Eleventh Supplemental Indenture, dated as of September 29, 2006, among the Registrant, the Guaranteeing Subsidiaries (as defined therein), and US Bank National Association, as trustee (Incorporated by reference to Exhibit 4.2 of the Registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2006, filed on November 7, 2006). | |
|
4.18
|
† 67/8% Senior Notes Due 2013 Twelfth Supplemental Indenture, dated as of November 10, 2006, among the Registrant, the Guaranteeing Subsidiaries (as defined therein), and US Bank National Association, as trustee. | |
|
4.19
|
† 67/8% Senior Notes Due 2013 Thirteenth Supplemental Indenture, dated as of January 31, 2007, among the Registrant, the Guaranteeing Subsidiaries (as defined therein), and US Bank National Association, as trustee. | |
|
4.20
|
57/8% Senior Notes Due 2016 Indenture, dated as of March 19, 2004, between the Registrant and US Bank National Association, as trustee (Incorporated by reference to Exhibit 4.12 of the Registrant’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2004, filed on May 10, 2004). | |
|
4.21
|
57/8% Senior Notes Due 2016 First Supplemental Indenture, dated as of March 23, 2004, between the Registrant and US Bank National Association, as trustee (Incorporated by reference to Exhibit 4.1 of the Registrant’s Current Report on Form 8-K dated March 23, 2004). | |
|
4.22
|
57/8% Senior Notes Due 2016 Second Supplemental Indenture, dated as of April 22, 2004, among the Registrant, the Guaranteeing Subsidiaries (as defined therein), and US Bank National Association, as trustee (Incorporated by reference to Exhibit 10.58 of the Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2004, filed on August 6, 2004). | |
|
4.23
|
57/8% Senior Notes Due 2016 Third Supplemental Indenture, dated as of October 18, 2004, among the Registrant, the Guaranteeing Subsidiaries (as defined therein), and US Bank National Association, as trustee (Incorporated by reference to Exhibit 4.13 of the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2004, filed on March 16, 2005). |
Table of Contents
| Exhibit | ||
| No. | Description of Exhibit | |
|
4.24
|
57/8% Senior Notes Due 2016 Fourth Supplemental Indenture, dated as of January 20, 2005, among the Registrant, the Guaranteeing Subsidiaries (as defined therein), and US Bank National Association, as trustee (Incorporated by reference to Exhibit 4.2 of the Registrant’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2005, filed on May 6, 2005). | |
|
4.25
|
57/8% Senior Notes Due 2016 Fifth Supplemental Indenture, dated as of September 30, 2005, among the Registrant, the Guaranteeing Subsidiaries (as defined therein), and US Bank National Association, as trustee (Incorporated by reference to Exhibit 4.2 of the Registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2005, filed on November 8, 2005). | |
|
4.26
|
57/8% Senior Notes Due 2016 Sixth Supplemental Indenture, dated as of January 20, 2006, among the Registrant, the Guaranteeing Subsidiaries (as defined therein), and US Bank National Association, as trustee (Incorporated by reference to Exhibit 4.21 of the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2005, filed on March 6, 2006). | |
|
4.27
|
57/8% Senior Notes Due 2016 Seventh Supplemental Indenture, dated as of June 13, 2006, among the Registrant, the Guaranteeing Subsidiaries (as defined therein), and US Bank National Association, as trustee (Incorporated by reference to Exhibit 4.3 of the Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2006, filed on August 7, 2006). | |
|
4.28
|
57/8% Senior Notes Due 2016 Eighth Supplemental Indenture, dated as of June 30, 2006, among the Registrant, the Guaranteeing Subsidiaries (as defined therein), and US Bank National Association, as trustee (Incorporated by reference to Exhibit 4.4 of the Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2006, filed on August 7, 2006). | |
|
4.29
|
57/8% Senior Notes Due 2016 Ninth Supplemental Indenture, dated as of September 29, 2006, among the Registrant, the Guaranteeing Subsidiaries (as defined therein), and US Bank National Association, as trustee (Incorporated by reference to Exhibit 4.1 of the Registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2006, filed on November 7, 2006). | |
|
4.30†
|
57/8% Senior Notes Due 2016 Twelfth Supplemental Indenture, dated as of November 10, 2006, among the Registrant, the Guaranteeing Subsidiaries (as defined therein), and US Bank National Association, as trustee. | |
|
4.31†
|
57/8% Senior Notes Due 2016 Fifteenth Supplemental Indenture, dated as of January 31, 2007, among the Registrant, the Guaranteeing Subsidiaries (as defined therein), and US Bank National Association, as trustee. | |
|
4.32
|
73/8% Senior Notes due 2016 Tenth Supplemental Indenture, dated as of October 12, 2006 among the Registrant, the Guaranteeing Subsidiaries (as defined therein), and U.S. Bank National Association, as trustee (Incorporated by reference to Exhibit 4.1 of the Registrant’s Current Report on Form 8-K dated October 13, 2006). | |
|
4.33†
|
73/8% Senior Notes due 2016 Thirteenth Supplemental Indenture, dated as of November 10, 2006 among the Registrant, the Guaranteeing Subsidiaries (as defined therein), and U.S. Bank National Association, as trustee. | |
|
4.34†
|
73/8% Senior Notes due 2016 Sixteenth Supplemental Indenture, dated as of January 31, 2007 among the Registrant, the Guaranteeing Subsidiaries (as defined therein), and U.S. Bank National Association, as trustee. | |
|
4.35
|
77/8% Senior Notes due 2026 Eleventh Supplemental Indenture, dated as of October 12, 2006, among the Registrant, the Guaranteeing Subsidiaries (as defined therein), and U.S. Bank National Association, as trustee (Incorporated by reference to Exhibit 4.2 of the Registrant’s Current Report on Form 8-K dated October 13, 2006). | |
|
4.36†
|
77/8% Senior Notes due 2026 Fourteenth Supplemental Indenture, dated as of November 10, 2006, among the Registrant, the Guaranteeing Subsidiaries (as defined therein), and U.S. Bank National Association, as trustee. | |
|
4.37†
|
77/8% Senior Notes due 2026 Seventeenth Supplemental Indenture, dated as of January 31, 2007, among the Registrant, the Guaranteeing Subsidiaries (as defined therein), and U.S. Bank National Association, as trustee. | |
|
4.38
|
Subordinated Indenture, dated as of December 20, 2006, between the Registrant and US 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). |
Table of Contents
| Exhibit | ||
| No. | Description of Exhibit | |
|
4.39
|
4.75% Convertible Junior Subordinated Debentures Due 2066 First Supplemental Indenture, dated as December 20, 2006, among the Registrant and US 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). | |
|
4.40
|
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). | |
|
10.1
|
Third Amended and Restated Credit Agreement, dated as of September 15, 2006, among the Registrant, Bank of America, N.A., as administrative agent, Citibank, N.A., as syndication agent, and the lenders named therein (Incorporated by reference to Exhibit 10.1 of the Registrant’s Current Report on Form 8-K, filed September 18, 2006). | |
|
10.2
|
Amendment No. 1 to Third Amended and Restated Credit Agreement, dated as of September 27, 2006, among the Registrant, the Lenders named therein, and Bank of America, N.A., as Administrative Agent (Incorporated by reference to Exhibit 10.3 of the Registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2006, filed on November 7, 2006). | |
|
10.3
|
Amended and Restated Guarantee, dated as of September 15, 2006, among the Registrant and the Guarantors (as defined therein) in favor of Bank of America, N.A., as administrative agent under the Third Amended and Restated Credit Agreement dated as of September 15, 2006 (Incorporated by reference to Exhibit 10.2 of the Registrant’s Current Report on Form 8-K, filed September 18, 2006). | |
|
10.4
|
Federal Coal Lease WYW0321779: North Antelope/ Rochelle Mine (Incorporated by reference to Exhibit 10.3 of the Registrant’s Form S-4 Registration Statement No. 333-59073). | |
|
10.5
|
Federal Coal Lease WYW119554: North Antelope/ Rochelle Mine (Incorporated by reference to Exhibit 10.4 of the Registrant’s Form S-4 Registration Statement No. 333-59073). | |
|
10.6
|
Federal Coal Lease WYW5036: Rawhide Mine (Incorporated by reference to Exhibit 10.5 of the Registrant’s Form S-4 Registration Statement No. 333-59073). | |
|
10.7
|
Federal Coal Lease WYW3397: Caballo Mine (Incorporated by reference to Exhibit 10.6 of the Registrant’s Form S-4 Registration Statement No. 333-59073). | |
|
10.8
|
Federal Coal Lease WYW83394: Caballo Mine (Incorporated by reference to Exhibit 10.7 of the Registrant’s Form S-4 Registration Statement No. 333-59073). | |
|
10.9
|
Federal Coal Lease WYW136142 (Incorporated by reference to Exhibit 10.8 of Amendment No. 1 of the Registrant’s Form S-4 Registration Statement No. 333-59073). | |
|
10.10
|
Royalty Prepayment Agreement by and among Peabody Natural Resources Company, Gallo Finance Company and Chaco Energy Company, dated September 30, 1998 (Incorporated by reference to Exhibit 10.9 of the Registrant’s Quarterly Report on Form 10-Q for the second quarter ended September 30, 1998, filed on November 13, 1998). | |
|
10.11
|
Federal Coal Lease WYW154001: North Antelope Rochelle South (Incorporated by reference to Exhibit 10.68 of the Registrant’s Quarterly Report on Form 10-Q for the third quarter ended September 30, 2004, filed on December 10, 2004). | |
|
10.12
|
Federal Coal Lease WYW150210: North Antelope Rochelle Mine (Incorporated by reference to Exhibit 10.8 of the Registrant’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2005, filed on May 6, 2005). | |
|
10.13
|
Federal Coal Lease WYW151134 effective May 1, 2005: West Roundup (Incorporated by reference to Exhibit 10.1 of the Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2005, filed on August 8, 2005). | |
|
10.14*
|
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 on May 21, 2003). | |
|
10.15*
|
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, filed on March 4, 2004). | |
|
10.16*
|
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, filed on March 4, 2004). |
Table of Contents
| Exhibit | ||
| No. | Description of Exhibit | |
|
10.17*
|
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, filed on August 6, 2004). | |
|
10.18*
|
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, filed on March 4, 2004). | |
|
10.19*
|
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 on May 22, 2001). | |
|
10.20*
|
Peabody Energy Corporation 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 on April 2, 2004). | |
|
10.21*
|
Amendment No. 1 to the Peabody Energy Corporation 2004 Long Term Incentive Plan (Incorporated by reference to Exhibit 10.67 of the Registrant’s Quarterly Report on Form 10-Q for the third quarter ended September 30, 2004, filed on December 10, 2004). | |
|
10.22*
|
Form of Non-Qualified Stock Option Agreement under the Peabody Energy Corporation 2004 Long-Term Equity Incentive Plan (Incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K, filed on January 7, 2005). | |
|
10.23*
|
Form of Performance Units Agreement under the Peabody Energy Corporation 2004 Long-Term Equity Incentive Plan (Incorporated by reference to Exhibit 10.2 of the Registrant’s Current Report on Form 8-K, dated January 3, 2005). | |
|
10.24*
|
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 on May 22, 2001). | |
|
10.25*
|
Form of Non-Qualified Stock Option Agreement for Outside Directors under the Peabody Energy Corporation Long-Term Equity Incentive Plan (Incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K, filed on December 14, 2005). | |
|
10.26*
|
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, filed on March 4, 2004). | |
|
10.27*
|
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, filed on March 4, 2004). | |
|
10.28*
|
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, filed on March 4, 2004). | |
|
10.29*
|
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, filed on March 4, 2004). | |
|
10.30*
|
Form of Restricted Stock Award Agreement for Outside Directors under the Peabody Energy Corporation Long-Term Equity Incentive Plan (Incorporated by reference to Exhibit 10.2 to the Registrant’s Current Report on Form 8-K, filed on December 14, 2005). | |
|
10.31*
|
Employee Stock Purchase Plan of the Registrant (Incorporated by reference to Exhibit 99.1 of the Registrant’s Form S-8 Registration Statement No. 333-61406, filed on May 22, 2001). | |
|
10.32*
|
First Amendment to Registrant’s Employee Stock Purchase Plan, dated as of February 7, 2002 (Incorporated by reference to Exhibit 10.23 of the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2003, filed on March 4, 2004). | |
|
10.33*
|
Letter Agreement, dated as of March 1, 2005, by and between the Registrant and Irl F. Engelhardt (Incorporated by reference to Exhibit 10.2 of the Registrant’s Current Report on Form 8-K, filed March 4, 2005). | |
|
10.34*
|
Amended and Restated Employment Agreement, dated as of January 1, 2006, by and between the Registrant and Irl F. Engelhardt (Incorporated by reference to Exhibit 10.4 of the Registrant’s Current Report on Form 8-K, filed March 4, 2005). | |
|
10.35*
|
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). |
Table of Contents
| Exhibit | ||
| No. | Description of Exhibit | |
|
10.36*
|
Amended and Restated Employment Agreement, dated as of January 1, 2006, by and between the Registrant and Gregory H. Boyce (Incorporated by reference to Exhibit 10.3 of the Registrant’s Current Report on Form 8-K, filed March 4, 2005). | |
|
10.37*
|
Employment Agreement between Richard M. Whiting and the Registrant dated May 19, 1998 (Incorporated by reference to Exhibit 10.12 of the Registrant’s Form S-1 Registration Statement No. 333-55412). | |
|
10.38*
|
First Amendment to the Employment Agreement between Richard M. Whiting and the Registrant dated as of May 10, 2001 (Incorporated by reference to Exhibit 10.22 of the Registrant’s Form S-1 Registration Statement No. 333-55412). | |
|
10.39*
|
Second Amendment to the Employment Agreement between Richard M. Whiting and the Registrant dated as of June 15, 2004 (Incorporated by reference to Exhibit 10.60 of the Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2004, filed on August 6, 2004). | |
|
10.40*
|
Employment Agreement between Richard A. Navarre and the Registrant dated May 19, 1998 (Incorporated by reference to Exhibit 10.13 of the Registrant’s Form S-1 Registration Statement No. 333-55412). | |
|
10.41*
|
First Amendment to the Employment Agreement between Richard A. Navarre and the Registrant dated as of May 10, 2001 (Incorporated by reference to Exhibit 10.23 of the Registrant’s Form S-1 Registration Statement No. 333-55412). | |
|
10.42*
|
Second Amendment to the Employment Agreement between Richard A. Navarre and the Registrant dated as of June 15, 2004 (Incorporated by reference to Exhibit 10.61 of the Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2004, filed on August 6, 2004). | |
|
10.43*
|
Employment Agreement between Roger B. Walcott, Jr. and the Registrant dated May 19, 1998 (Incorporated by reference to Exhibit 10.14 of the Registrant’s Form S-1 Registration Statement No. 333-55412). | |
|
10.44*
|
First Amendment to the Employment Agreement between Roger B. Walcott, Jr. and the Registrant dated as of May 10, 2001 (Incorporated by reference to Exhibit 10.24 of the Registrant’s Form S-1 Registration Statement No. 333-55412). | |
|
10.45*
|
Second Amendment to the Employment Agreement between Roger B. Walcott and the Registrant dated as of June 15, 2004 (Incorporated by reference to Exhibit 10.62 of the Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2004, filed on August 6, 2004). | |
|
10.46*
|
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). | |
|
10.47*
|
Employment Agreement, dated as of December 22, 2006, by and between the Company and Eric Ford (Incorporated by reference to Exhibit 10.2 of the Registrant’s Current Report on Form 8-K, filed December 29, 2006). | |
|
10.47A*
|
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). | |
|
10.47B*
|
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). | |
|
10.48*
|
Peabody Energy Corporation 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, filed on October 30, 2001). | |
|
10.49*
|
First Amendment to the Peabody Energy Corporation 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, filed on March 16, 2005). | |
|
10.50*
|
Performance Units Agreement, dated as of August 1, 2004, by and between Registrant and Irl F. Engelhardt (Incorporated by reference to Exhibit 10.72 of the Registrant’s Quarterly Report on Form 10-Q/ A for the third quarter ended September 30, 2004, filed on December 10, 2004). | |
|
10.51*
|
Indemnification Agreement, dated as of December 5, 2002, by and between Registrant and Irl F. Engelhardt (Incorporated by reference to Exhibit 10.31 of the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2002, filed on March 7, 2003). |
Table of Contents
| Exhibit | ||
| No. | Description of Exhibit | |
|
10.52*
|
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, filed on March 7, 2003). | |
|
10.53*
|
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, filed on March 7, 2003). | |
|
10.54*
|
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, filed on March 7, 2003). | |
|
10.55*
|
Indemnification Agreement, dated as of December 5, 2002, by and between Registrant and Dr. James R. Schlesinger (Incorporated by reference to Exhibit 10.37 of the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2002, filed on March 7, 2003). | |
|
10.56*
|
Indemnification Agreement, dated as of December 5, 2002, by and between Registrant and Dr. Blanche M. Touhill (Incorporated by reference to Exhibit 10.38 of the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2002, filed on March 7, 2003). | |
|
10.57*
|
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, filed on March 7, 2003). | |
|
10.58*
|
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, filed on March 7, 2003). | |
|
10.59*
|
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, filed on March 7, 2003). | |
|
10.60*
|
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, filed on March 7, 2003). | |
|
10.61*
|
Indemnification Agreement, dated as of December 9, 2003, by and between Registrant and B. R. Brown (Incorporated by reference to Exhibit 10.48 of the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2003, filed on March 4, 2004). | |
|
10.62*
|
Indemnification Agreement, dated as of March 22, 2004, by and between Registrant and Henry Givens, Jr. (Incorporated by reference to Exhibit 10.52 of the Registrant’s Quarterly Report on Form 10-Q for the quarter Ended March 31, 2004, filed on May 10, 2004). | |
|
10.63*
|
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, filed on May 10, 2004). | |
|
10.64*
|
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). | |
|
10.65*
|
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 on August 5, 2005). | |
|
10.66
|
Amended and Restated Receivables Purchase Agreement, dated as of September 30, 2005, by and among Seller, the Registrant, the Sub-Servicers named therein, Market Street Funding Corporation, as Issuer, and PNC Bank, National Association, as Administrator (Incorporated by reference to Exhibit 10.2 of the Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2005, filed on August 8, 2005). | |
|
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. |
Table of Contents
| Exhibit | ||
| No. | Description of Exhibit | |
|
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. |
| * | These exhibits constitute all management contracts, compensatory plans and arrangements required to be filed as an exhibit to this form pursuant to Item 15(c) of this report. |
| † | Filed herewith. |