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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
[X] ANNUAL REPORT PURSUANT TO
SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2004
OR
[ ] TRANSITION REPORT PURSUANT TO
SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
Commission file number 1-9971
BURLINGTON RESOURCES INC.
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Incorporated in the State of Delaware
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Employer Identification No. 91-1413284 |
717 Texas, Suite 2100, Houston, Texas 77002
Telephone: (713) 624-9500
Securities registered pursuant to Section 12(b) of the Act:
Common Stock, par value $.01 per share
Preferred Stock Purchase Rights
The above securities are registered on the New York Stock
Exchange.
Securities registered pursuant to Section 12(g) of the Act:
None
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 X No
Indicate by check mark if disclosure of delinquent filers
pursuant to Item 405 of Regulation S-K is not
contained herein, and will not be contained, to the best of
registrants knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this
Form 10-K or any amendment to this
Form 10-K. o
Indicate by check mark whether the registrant is an accelerated
filer (as defined in Rule 12b-2 of the Act).
Yes X No
State the aggregate market value of the voting and non-voting
common equity held by non-affiliates computed by reference to
the price at which the common equity was last sold, or the
average bid and asked price of such common equity, as of
January 30, 2005 and as of the last business day of the
registrants most recently completed second fiscal quarter.
Common Stock aggregate market value held by non-affiliates as of
January 31, 2005: $16,915,639,395 and as of June 30,
2004: $14,035,722,348.
Indicate the number of shares outstanding of each of the
registrants classes of common stock, as of the latest
practicable date. Class: Common Stock, par value $.01 per
share, on January 31, 2005, Shares Outstanding: 386,997,012
DOCUMENTS INCORPORATED BY REFERENCE
List hereunder the following documents if incorporated by
reference and the Part of the Form 10-K (e.g., Part I,
Part II, etc.) into which the document is incorporated:
Burlington Resources Inc. definitive proxy statement, to be
filed not later than 120 days after the end of the fiscal
year covered by this report, is incorporated by reference into
Part III.
Below are definitions of key certain technical industry terms
used in this Form 10-K.
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Bbls
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Barrels |
BCF
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Billion Cubic Feet |
BCFE
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Billion Cubic Feet of Gas Equivalent |
DD&A
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Depreciation, Depletion and Amortization |
MBbls
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Thousands of Barrels |
MCF
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Thousand Cubic Feet |
MCFE
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Thousand Cubic Feet of Gas Equivalent |
MMBbls
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Millions of Barrels |
MMBTU
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Million British Thermal Units |
MMCF
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Million Cubic Feet |
MMCFE
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Million Cubic Feet of Gas Equivalent |
NGLs
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Natural Gas Liquids |
TCF
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Trillion Cubic Feet |
TCFE
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Trillion Cubic Feet of Gas Equivalent |
Appraisal well is a well drilled in the vicinity of a
discovery or wildcat well in order to evaluate the extent and
importance of the discovery.
Basin is a synclinal structure in the subsurface that is
composed of sedimentary rock and regarded as a good prospect for
exploration.
Call options are contracts giving the holder
(purchaser) the right, but not the obligation, to buy
(call) a specified item at a fixed price (exercise or
strike price) during a specified period. The purchaser pays a
nonrefundable fee (the premium) to the seller (writer).
Cash-flow hedges are derivative instruments used to
mitigate the risk of variability in cash flows from crude oil
and natural gas sales due to changes in market prices. Examples
of such derivative instruments include fixed-price swaps,
fixed-price swaps combined with basis swaps, purchased put
options, costless collars (purchased put options and written
call options) and producer three-ways (purchased put spreads and
written call options). These derivative instruments either fix
the price a party receives for its production or, in the case of
option contracts, set a minimum price or a price within a fixed
range.
Compression is the process of squeezing a given volume of
gas into a smaller space.
Completion refers to the work performed and the
installation of permanent equipment for the production of
natural gas and crude oil from a recently drilled well.
Developed acreage is acreage that is allocated or
assignable to producing wells or wells capable of production.
Development well is a well drilled within the proved area
of an oil or natural gas field to the depth of a stratigraphic
horizon known to be productive.
Dry hole is an exploratory or development well that does
not produce oil or gas in commercial quantities.
Exploitation is drilling wells in areas proven to be
productive.
Exploratory well is a well drilled to find and produce
oil or gas in an unproved area, to find a new reservoir in a
field previously found to be productive of oil or gas in another
reservoir, or to extend a known reservoir. Generally, an
exploratory well is any well that is not a development well, a
service well or a stratigraphic test well.
Fair-value hedges are derivative instruments used to
hedge or offset the exposure to changes in the fair value of a
recognized asset or liability or an unrecognized firm
commitment. For example, a contract is entered into whereby a
commitment is made to deliver to a customer a specified quantity
of crude oil or natural gas at a fixed price over a specified
period of time. In order to hedge against changes in the fair
value of these commitments, a party enters into swap agreements
with financial counterparties that allow the party to receive
market prices for the committed specified quantities included in
the physical contract.
Field is an area consisting of a single reservoir or
multiple reservoirs all grouped on or related to the same
individual geological structural feature or stratigraphic
condition.
Formation is a stratum of rock that is recognizable from
adjacent strata consisting mainly of a certain type of rock or
combination of rock types with thickness that may range from
less than two feet to hundreds of feet.
Gross acres or gross wells are the total acres or wells
in which a working interest is owned.
Horizon is a zone of a particular formation or that part
of a formation of sufficient porosity and permeability to form a
petroleum reservoir.
Independent oil and gas company is a company that is
primarily engaged in the exploration and production sector of
the oil and gas business.
i
Infill drilling refers to drilling wells between
established producing wells on a lease; a drilling program to
reduce the spacing between wells in order to increase production
and/or recovery of in-place hydrocarbons from the lease.
Lease operating or well operating expenses are expenses
incurred to operate the wells and equipment on a producing lease.
Net acreage and net oil and gas wells are obtained by
multiplying gross acreage and gross oil and gas wells by the
Companys working interest percentage in the properties.
Oil and NGLs are converted into cubic feet of gas
equivalent based on 6 MCF of gas to one barrel of oil or
NGLs.
Operating costs include direct and indirect expenses,
including divisional office expenses, incurred to manage,
operate and maintain the Companys wells and related
equipment and facilities.
Permeability is a measure of ease with which fluids can
move through a reservoir.
Porosity is the ratio of the volume of empty space to the
volume of solid rock in a formation, indicating how much fluid a
rock can hold.
Production costs are costs incurred to operate and
maintain the Companys wells and related equipment and
facilities. These costs include well operating costs, severance
taxes and ad valorem taxes.
Productive well is a well that is found to be capable of
producing hydrocarbons in sufficient quantities such that
proceeds from the sale of such production exceed production
expenses and taxes.
Proved developed reserves are the portion of proved
reserves which can be expected to be recovered through existing
wells with existing equipment and operating methods. For
complete definitions of proved developed natural gas, NGLs and
crude oil reserves, refer to the Securities and Exchange
Commissions Regulation S-X, Rule 4-10(a)(2),
(3) and (4).
Proved reserves represent estimated quantities of natural
gas, NGLs and crude oil which geological and engineering data
demonstrate, with reasonable certainty, can be recovered in
future years from known reservoirs under existing economic and
operating conditions. Reservoirs are considered proved if shown
to be economically producible by either actual production or
conclusive formation tests. For complete definitions of proved
natural gas, NGLs and crude oil reserves, refer to the
Securities and Exchange Commissions Regulation S-X,
Rule 4-10(a)(2), (3) and (4).
Proved undeveloped reserves are the portion of proved
reserves which can be expected to be recovered from new wells on
undrilled proved acreage, or from existing wells where a
relatively major expenditure is required for completion. For
complete definitions of proved undeveloped natural gas, NGLs and
crude oil reserves, refer to the Securities and Exchange
Commissions Regulation S-X, Rule 4-10(a)(2),
(3) and (4).
Put options are contracts giving the holder
(purchaser) the right, but not the obligation, to sell
(put) a specified item at a fixed price (exercise or strike
price) during a specified period. The purchaser pays a
nonrefundable fee (the premium) to the seller (writer).
Reservoir is a porous and permeable underground formation
containing a natural accumulation of producible oil and/or gas
that is confined by impermeable rock and water barriers and/or
is individual and separate from other reservoirs.
Seismic is an exploration method of sending energy waves
or sound waves into the earth and recording the wave reflections
to indicate the type, size, shape and depth of subsurface rock
formation. (2-D seismic provides two-dimensional information and
3-D seismic provides three-dimensional pictures.)
Sour gas is natural gas containing chemical impurities,
notably hydrogen sulfide, other sulfur compounds and/or carbon
dioxide.
Spacing is the number of wells which conservation laws
allow to be drilled on a given area of land.
Step-out drilling is drilling a well adjacent to a proven
well but moving in the direction of an unproven area.
Swaps are contracts between two parties to exchange
streams of variable and fixed prices on specified notional
amounts. One party to the swap pays a fixed price while the
other pays a variable price.
Sweet gas is natural gas free of significant amounts of
hydrogen sulfide or carbon dioxide when produced.
ii
Tight gas is natural gas produced from a formation with
low permeability that will not give up its gas readily at high
flow rates.
Transportation expense primarily includes costs to
process, including payments made in-kind, and costs to transport
crude oil, NGLs and natural gas to a major facility, market hub,
sales point or plant.
Undeveloped acreage is lease acreage on which wells have
not been drilled or completed to a point that would permit the
production of commercial quantities of oil and natural gas.
Working interest is the operating interest that gives the
owner the right to drill, produce and conduct operating
activities on the property and a share of production.
Workover is operations on a producing well to restore or
increase production.
Writer refers to the seller of an option. The writer
earns the premium on the option but bears the risk of fulfilling
the obligations of the option.
Zone is a stratigraphic interval containing one or more
reservoirs.
iii
PART I
ITEMS ONE AND TWO
BUSINESS AND PROPERTIES
Burlington Resources Inc. (BR) is among the
worlds largest independent oil and gas companies and holds
one of the industrys leading positions in North American
natural gas reserves and production. BR conducts exploration,
production and development operations in the U.S., Canada,
United Kingdom, Africa, China and South America. BR is a holding
company and its principal subsidiaries include Burlington
Resources Oil & Gas Company LP, The Louisiana Land and
Exploration Company (LL&E), Burlington Resources
Canada Ltd. (formerly known as Poco Petroleums Ltd.), Burlington
Resources Canada (Hunter) Ltd. (formerly known as Canadian
Hunter Exploration Ltd.) (Hunter), and their
affiliated companies (collectively, the Company).
During 2002, after announcing in late 2001 its intent to sell
certain non-core, non-strategic properties, the Company sold
approximately 1 TCFE of reserves and a processing facility. As a
result of these property sales, the Company generated proceeds,
before post-closing adjustments, of approximately
$1.2 billion. The Company used a portion of the proceeds
generated from property sales to retire debt and for general
corporate purposes.
In December 2001, the Company consummated the acquisition of
Hunter valued at approximately U.S. $2.1 billion,
resulting in goodwill of approximately $793 million. The
Hunter acquisition added a portfolio of properties, primarily
located in the Western Canadian Sedimentary Basin, an area in
which the Company already operated. The most significant of the
assets is the Deep Basin, one of North Americas largest
natural gas fields.
The Companys reportable segments are U.S., Canada and
International. For financial information related to the
Companys reportable segments, see Note 17 of Notes to
Consolidated Financial Statements. The Companys worldwide
major operating areas are discussed below.
North America
The Companys asset base is dominated by North American
natural gas properties. Its extensive North American lease
holdings extend from the U.S. Gulf Coast to Northeast
British Columbia and Northern Alberta in Canada. The
Companys North American operations include a mix of
production, development and exploration assets.
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U.S.s % of | |
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Canadas % of | |
Year Ended December 31, 2004 |
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Worldwide | |
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U.S. | |
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Worldwide | |
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Canada | |
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Worldwide | |
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($ In Millions) | |
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Oil and gas capital expenditures Development
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$ |
1,273 |
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$ |
544 |
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43 |
% |
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$ |
639 |
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50 |
% |
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Exploration
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286 |
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87 |
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30 |
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159 |
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56 |
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Acquisitionsproved
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85 |
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81 |
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95 |
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4 |
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5 |
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Total oil and gas capital expenditures
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$ |
1,644 |
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$ |
712 |
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43 |
% |
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$ |
802 |
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49 |
% |
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Production
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Natural gas (MMCF per day)
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1,914 |
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908 |
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47 |
% |
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819 |
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43 |
% |
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NGLs (MBbls per day)
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65.3 |
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41.7 |
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64 |
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23.6 |
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36 |
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Crude oil (MBbls per day)
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85.2 |
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37.2 |
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44 |
% |
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5.5 |
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6 |
% |
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December 31, 2004
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Proved reserves (TCFE)
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12.0 |
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8.0 |
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67 |
% |
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2.7 |
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22 |
% |
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U.S.
San Juan Basin
The San Juan Basin, in northwest New Mexico and southwest
Colorado, is one of the Companys major operating areas in
terms of reserves and production. The San Juan Basin
encompasses nearly 7,500 square miles, or approximately
4.8 million acres, with the major portion located in New
Mexicos Rio Arriba and San Juan counties. The Company
is a significant holder of productive leasehold acreage in this
area with over 840,000 net acres under its control. The
Company operates almost 7,500 well completions in the
San Juan Basin and holds interests in an additional 4,700
non-operated well completions.
1
In 2004, the Company invested $154 million in oil and gas
capital, excluding acquisitions, drilled or participated in
drilling 361 new wells and performed 172 workovers on
existing wells. The Companys net production from the
San Juan Basin averaged approximately 550 MMCF of
natural gas per day, 31.3 MBbls of NGLs per day and
1.1 MBbls of crude oil per day during 2004. Production from
the San Juan Basin grew significantly during the 1990s,
first as a result of Fruitland Coal drilling and then as a
result of development of tight gas formations. By the end of the
decade, all formations were experiencing some decline; however,
the Company has been able to maintain flat production for the
last three years. To mitigate Fruitland Coal production decline,
the Company has an ongoing program that consists of performing
workovers on existing wells, adding compression, and installing
artificial lift, where appropriate. The Company drilled or
participated in drilling 200 wells on 320-acre and 160-acre
spacing during 2004. In 2004, net production from the Fruitland
Coal averaged 206 MMCF of natural gas per day from over
1,900 completions.
Also in 2004, the Company completed a $28 million purchase
of 1,242 undrilled acres in Negro Canyon, which is located in
the heart of the Companys Fruitland Coal producing area.
The purchase encompasses a 100 percent working interest and
87.5 percent net revenue interest in the tract. Production
has already been established and the Company expects to fully
develop these leases by the end of 2006.
The three conventional formations (Mesaverde, Pictured Cliffs
and Dakota) in the San Juan Basin continue to provide
attractive development opportunities for the Company. The
Mesaverde formation, which consists of the Lewis Shale,
Cliffhouse, Menefee and Point Lookout sands, is the largest
producing tight gas formation in the San Juan Basin. In
2004, the Company continued its ongoing infill-drilling program
in this formation. In 2004, the Company drilled or participated
in drilling 161 conventional wells on 160-acre and 80-acre
spacing. Net production from the tight gas producing formations
averaged 344 MMCF of natural gas per day, 31.3 MBbls
of NGLs per day and 1.1 MBbls of crude oil per day in 2004.
Wind River Basin
The Madden Field, located in the Wind River Basin, covers more
than 70,000 acres in Wyomings Fremont and Natrona
counties. Net production averaged 119 MMCF of natural gas
per day in 2004 from multiple horizons ranging in depth from
5,000 feet to over 25,000 feet, where the deep Madison
formation occurs. Investments in the Wind River Basin during
2004 totaled $24 million for 57 newly drilled wells and
workover projects. The Company owns an approximate
48 percent working interest in the Lost Cabin Gas Plant and
a 43 percent net revenue interest in the Madison reservoir.
Williston Basin
The Williston Basin operations, located in western North Dakota
and eastern Montana, were focused on activities on the Cedar
Creek Anticline and in the Bakken Shale formation during 2004.
Total Williston Basin production averaged 21.2 MBbls of
crude oil per day and 8 MMCF of natural gas per day. During
2004, the Company invested $113 million on projects in the
Williston Basin.
The Company continued its highly active waterflood development
program at both the Cedar Hills South and East Lookout Butte
Units, where the focus has moved to 160-acre infill drilling. A
total of 39 production and 8 injection wells were drilled in the
two units, along with the continued expansion of the injection
and gathering infrastructure. In addition to the development
drilling program on the Cedar Creek Anticline, a new development
area was initiated in Richland County, Montana, where the
Company drilled 8 horizontal wells in the siltstone of the
Bakken Shale formation and acquired additional acreage. The
Company currently controls over 60,000 acres including
areas in Richland County, Montana, and McKenzie County, North
Dakota.
Anadarko Basin
The Anadarko Basin, located principally in western Oklahoma,
encompasses over 30,000 square miles and contains some of
the deepest producing formations in the world. The Company
controls over 250,000 net acres and produces from multiple
horizons ranging in depth from 11,000 feet to over
21,000 feet. Net production for 2004 from the Anadarko
Basin averaged 70 MMCF of natural gas per day and
1.9 MBbls of NGLs per day. During 2004, the Company
invested $31 million in the Anadarko Basin. Operated
activity focused on the Red Fork formation in Roger Mills
County, Oklahoma, where the Company drilled 14 wells.
Permian Basin
Permian Basin operations, in west Texas, are focused on the
Waddell Ranch Field. Total Permian Basin production in 2004
averaged 14 MMCF of natural gas per day, 4.0 MBbls of
crude oil per day and 2.0 MBbls of NGLs per day, with the
Waddell Ranch Field contributing 10 MMCF of natural gas per
day, 2.7 MBbls of crude oil per day and 2.0 MBbls of
NGLs per day. During 2004, the Company invested $10 million
in Permian Basin operations.
2
Fort Worth Basin
In the Fort Worth Basin of north central Texas, the Company
is focused on the continued development of the Barnett Shale
formation acreage position in Denton and Wise Counties, Texas.
The Company employed up to five rigs during the year to drill or
participate in 93 wells in the Barnett Shale formation,
including an 11 well horizontal drilling program. The
Company invested $83 million in 2004 with production
averaging 33 MMCF of natural gas per day, 4.2 MBbls of
NGLs per day and 1.0 MBbls of crude oil per day.
Onshore Gulf Coast Area
The Onshore Gulf Coast Area includes operations in a number of
drilling trends in east Texas, south Louisiana, the Onshore Gulf
of Mexico and the Florida panhandle. In south Louisiana, the
Company owns 660,000 acres of fee lands with both surface
and mineral rights. In early 2004, the Company acquired
$70 million of properties in south Louisiana from
ChevronTexaco. The Company spent $29 million of capital on
these properties in 2004, and production increased to over
20 MMCF of natural gas per day. In the East Texas Bossier
trend, the Company commenced drilling seven wells in 2004, and
natural gas sales averaged 7 MMCF per day. Overall, the
Company invested $138 million on 128 drilling, workover and
facilities projects in the Gulf Coast Area. Net production for
2004 averaged 108 MMCF of natural gas per day,
9.2 MBbls of crude oil per day and 1.5 MBbls of NGLs
per day.
Canada
Western Canadian Sedimentary Basin
In the Western Canadian Sedimentary Basin, the Companys
portfolio of opportunities includes conventional exploration and
development in Alberta, British Columbia and Saskatchewan.
Canadian activity in 2004 was focused on expanding activity into
large-scale repeatable drilling programs in conventional and
lower permeability reservoirs. Oil and gas capital investment in
Canada was $798 million, excluding acquisitions, and
591 wells were drilled. Production in Canada was
819 MMCF of natural gas per day, 23.6 MBbls of NGLs
per day and 5.5 MBbls of crude oil per day during 2004.
The Deep Basin area, in Alberta and British Columbia, consists
of the Elmworth, Wapiti, Noel and Brassey Fields. In 2004, a
$262 million oil and gas capital program was focused on
exploration and development in the Deep Basin area. As a result,
106 wells were drilled and 231 MMCF of natural gas per
day and 12.3 MBbls of NGLs per day were produced from this
area.
In 2004, the Company completed resource assessment studies that
identified future drilling opportunities across 4 horizons
in the Deep Basin. The most prolific of these formations include
the Cadomin, Falher-A, Falher-B and Cadotte. The Company also
conducted down-spacing studies across the Cadomin, Chinook and
Belly River horizons. These studies were supplemented by
favorable regulatory approval to reduce well spacing from
640-acre to 320-acre over 55 sections of the Deep Basin.
In the Foothills area, which borders on the west side of the
Deep Basin, oil and gas capital spending focused on exploration
and development was $31 million and production was
53 MMCF of natural gas per day. Five wells were drilled in
2004.
The OChiese area in central Alberta yielded production of
161 MMCF of natural gas per day, 6.2 MBbls of NGLs per
day and 2.0 MBbls of crude oil per day in 2004. The
OChiese area was the focus of a $144 million
exploration and development program in 2004 that mostly targeted
the Lower Cretaceous and Jurassic sands, the principal
historical targets. In 2004, 111 wells were drilled.
In the Northern Plains, the Company continued exploration and
development activities in the northern Alberta and British
Columbia areas. Production in this area during 2004 averaged
83 MMCF of natural gas per day and 2.0 MBbls of NGLs
per day. A capital program in this area of $83 million
targeted the Bluesky, Gething and Montney formations and
58 wells were drilled during 2004.
In the Kaybob area, production for the year averaged
112 MMCF of natural gas per day, 1.8 MBbls of NGLs per
day and 0.8 MBbls of crude oil per day. The Company
invested $170 million and 82 wells were drilled during
2004.
The Southern Plains area, which includes the Viking Kinsella
property, produced approximately 166 MMCF of natural gas
per day, 1.4 MBbls of crude oil per day and 1.2 MBbls
of NGLs per day in 2004. In 2004, the Company invested
$81 million and 214 wells were drilled in the Southern
Plains area.
In 2004, the Company divested its acreage position in the
Mackenzie Delta area to focus efforts on Western Canadian
Sedimentary Basin opportunities.
3
International
The Companys International operations include a
combination of exploration opportunities, large field
development projects, and production operations. Key focus areas
are Northwest Europe, North Africa, China, and South America.
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% of | |
Year Ended December 31, 2004 |
|
Worldwide | |
|
International | |
|
Worldwide | |
| |
|
|
($ In Millions) | |
| |
|
Oil and gas capital expenditures
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Development
|
|
$ |
1,273 |
|
|
$ |
90 |
|
|
|
7 |
% |
|
|
Exploration
|
|
|
286 |
|
|
|
40 |
|
|
|
14 |
|
|
|
Acquisitionsproved
|
|
|
85 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Total oil and gas capital expenditures
|
|
$ |
1,644 |
|
|
$ |
130 |
|
|
|
8 |
% |
|
|
Production
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (MMCF per day)
|
|
|
1,914 |
|
|
|
187 |
|
|
|
10 |
% |
|
|
NGLs (MBbls per day)
|
|
|
65.3 |
|
|
|
|
|
|
|
|
|
|
|
Crude oil (MBbls per day)
|
|
|
85.2 |
|
|
|
42.5 |
|
|
|
50 |
% |
|
December 31, 2004
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved reserves (TCFE)
|
|
|
12.0 |
|
|
|
1.3 |
|
|
|
11 |
% |
|
Northwest Europe
The East Irish Sea assets consist of eight licenses covering
163,000 acres. The Company has a 100 percent working
interest in seven operated gas fields. First production from two
sweet gas fields, Millom and Dalton, commenced in 1999. Net
production from the East Irish Sea averaged 87 MMCF of
natural gas per day during 2004. The Company invested
$53 million of capital in this area during the year.
The development of the sour gas fields in the East Irish Sea
continued with first production from Calder in October 2004,
representing the first development in the Rivers Fields.
Operational issues identified during the startup phase of the
Rivers Fields onshore gas processing terminal resulted in the
shut down of production from mid-November through the remainder
of the year. Production at the Rivers Fields is expected to
resume by the second quarter of 2005 and is expected to peak at
a sales rate of approximately 100 MMCF of natural gas per
day during the year.
The Companys remaining Northwest European shelf operations
consist of non-operated production from the Companys
wholly-owned Netherlands affiliate (CLAM) in the
Dutch sector of the North Sea. The CLAM assets yielded an annual
production rate of 72 MMCF of natural gas per day in 2004.
North Africa
In North Africa, the Company continued with its exploration and
development programs in both Algeria and Egypt. The Company
benefited from a full years production from Algeria
Block 405a. Plans for future developments were advanced in
both Algeria and Egypt, and the Company completed its
exploration program on Algeria Block 402d. The
Companys capital investments in North Africa during 2004
totaled $33 million.
In Algeria, at the Menzel Lejmat North (MLN) Field on
Block 405a, where the Company has a 65 percent working
interest, activity was primarily focused on stabilizing
production from the Company-operated MLN central processing
facility. Annual average net oil production was 11.0 MBbls
of crude oil per day. One natural gas injection well was
successfully drilled and completed during 2004 for reservoir
pressure maintenance purposes. In the MLSE area, on the southern
portion of the block, development plans for crude oil and
natural gas discoveries are being discussed with Sonatrach, the
Algerian national oil company.
The Ourhoud Field, in which the Company has a 3.7 percent
working interest, produced at an average net rate of
5.5 MBbls of crude oil per day. Five development wells,
four injection wells and one water-source well were drilled
during 2004, and the waterflood development of this large crude
oil field was continued. The Company relinquished its
75 percent working interest in Block 402d in December
of 2004.
In Egypt, where the Company has a 50 percent non-operated
working interest in the Offshore North Sinai permit, development
of the Companys gas discoveries progressed. An agreement
was reached with the Egyptian authorities on a revision to the
existing gas sales contract to revise the start date of the
project and to bring the pricing structure in line with other
Egyptian contracts of this nature. Also, engineering design
studies were begun to determine the facilities required to
develop the Tao Field and potential satellites. These studies
should be completed in 2005.
4
China
In the Far East, the Company continued its focus on selected
basins in China. In 2004, an offshore oil development project
achieved the first full year of production and the first phase
of a development plan for an onshore gas development received
sanctioning and is working toward long-term expansion. The
Company invested $42 million in China in 2004.
During the year, the initial development drilling program was
completed for the Panyu offshore oil project in the Pearl River
Mouth Basin of the South China Sea. The Panyu development
involves two offshore oil fields, Bootes and Ursa, located in
Block 15/34, in which the Company holds a 24.5 percent
working interest. First production was achieved in October 2003,
and in 2004 the initial development drilling program was
successfully completed. In 2004, the average net production was
19.0 MBbls of crude oil per day.
The Company holds a 100 percent working interest in a
natural gas project in the onshore Chuanzhong Block in the
Sichuan Basin. In 2004, the Company received government
sanctioning of the first phase of development. The project
represents an opportunity to apply the Companys expertise
in the development of tight gas reservoirs in an area with
substantial reserve potential. During 2004, net production in
this area was 5 MMCF of natural gas per day.
South America
The Companys efforts in South America during 2004 focused
on expanding near-term production potential and enhancing
long-term exploration opportunities. Net production from South
America averaged 6.8 MBbls of crude oil per day and
23 MMCF of natural gas per day. The Company invested
$18 million of capital in South America during the year.
In Ecuador, the Company holds a 30 percent working interest
in Block 7 and a 37.5 percent working interest in
Block 21. Phase II development of the Yuralpa Field in
Block 21 is underway following startup in December 2003.
Production in this area averaged 4.0 MBbls of crude oil per
day during 2004. In Block 7, four wells were successfully
drilled during 2004. Net production in Block 7 for the year
was 2.6 MBbls of crude oil per day. In Ecuador, the
Companys capital investments in 2004 totaled
$12 million.
In Argentina, the Company holds a 25.7 percent working
interest in the Sierra Chata concession in the Neuquen Basin.
The Companys net production averaged 23 MMCF of
natural gas per day in 2004.
In Peru, the Company entered into an agreement to acquire a
23.9 percent working interest in Block 57, located in
the Ucayali Basin. The Company also holds a 23.9 percent
working interest in Block 90. In the Marañon Basin,
the Company entered into an agreement to farm-in a
45 percent working interest in Block 39 and signed a
preliminary agreement to explore and operate Block 104 with
a 100 percent working interest. During early 2004, the
Company relinquished its interests in Block 87.
In Colombia, the Company holds an exploration contract for a
100 percent working interest in the Orquídea area of
the Middle Magdalena Basin. A 3-D seismic acquisition program
was completed in November 2004.
5
Productive Wells
Working interests in productive wells follow.
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2004 |
|
Gross | |
|
Net | |
| |
North America
|
|
|
|
|
|
|
|
|
|
U.S.
|
|
|
|
|
|
|
|
|
|
|
Natural gas
|
|
|
11,533 |
|
|
|
6,609 |
|
|
|
Crude oil
|
|
|
2,722 |
|
|
|
1,313 |
|
|
Canada
|
|
|
|
|
|
|
|
|
|
|
Natural gas
|
|
|
5,768 |
|
|
|
4,458 |
|
|
|
Crude oil
|
|
|
1,147 |
|
|
|
581 |
|
International
|
|
|
|
|
|
|
|
|
|
|
Natural gas
|
|
|
198 |
|
|
|
62 |
|
|
|
Crude oil
|
|
|
166 |
|
|
|
46 |
|
|
Worldwide
|
|
|
|
|
|
|
|
|
|
|
Natural gas
|
|
|
17,499 |
|
|
|
11,129 |
|
|
|
Crude oil
|
|
|
4,035 |
|
|
|
1,940 |
|
|
|
|
|
Total Worldwide
|
|
|
21,534 |
|
|
|
13,069 |
|
|
Net Wells Drilled
The following table sets forth the Companys net productive
and dry wells.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
2004 | |
|
2003 | |
|
2002 | |
| |
North America
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Productive
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exploratory
|
|
|
3.9 |
|
|
|
0.9 |
|
|
|
4.5 |
|
|
|
|
Development
|
|
|
331.3 |
|
|
|
399.0 |
|
|
|
158.6 |
|
|
|
Dry
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exploratory
|
|
|
4.5 |
|
|
|
2.5 |
|
|
|
6.3 |
|
|
|
|
Development
|
|
|
4.0 |
|
|
|
5.3 |
|
|
|
2.1 |
|
|
|
|
|
|
Total U.S.
|
|
|
343.7 |
|
|
|
407.7 |
|
|
|
171.5 |
|
|
|
Canada
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Productive
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exploratory
|
|
|
32.6 |
|
|
|
102.5 |
|
|
|
73.3 |
|
|
|
|
Development
|
|
|
395.4 |
|
|
|
384.4 |
|
|
|
320.8 |
|
|
|
Dry
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exploratory
|
|
|
25.0 |
|
|
|
48.6 |
|
|
|
44.7 |
|
|
|
|
Development
|
|
|
27.2 |
|
|
|
57.6 |
|
|
|
46.2 |
|
|
|
|
|
|
Total Canada
|
|
|
480.2 |
|
|
|
593.1 |
|
|
|
485.0 |
|
|
International
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Productive
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exploratory
|
|
|
2.0 |
|
|
|
0.7 |
|
|
|
0.1 |
|
|
|
|
Development
|
|
|
8.5 |
|
|
|
10.9 |
|
|
|
1.5 |
|
|
|
Dry
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exploratory
|
|
|
3.1 |
|
|
|
1.8 |
|
|
|
2.0 |
|
|
|
|
Development
|
|
|
|
|
|
|
1.0 |
|
|
|
0.1 |
|
|
|
|
|
|
Total International
|
|
|
13.6 |
|
|
|
14.4 |
|
|
|
3.7 |
|
|
Worldwide
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Productive
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exploratory
|
|
|
38.5 |
|
|
|
104.1 |
|
|
|
77.9 |
|
|
|
|
Development
|
|
|
735.2 |
|
|
|
794.3 |
|
|
|
480.9 |
|
|
|
Dry
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exploratory
|
|
|
32.6 |
|
|
|
52.9 |
|
|
|
53.0 |
|
|
|
|
Development
|
|
|
31.2 |
|
|
|
63.9 |
|
|
|
48.4 |
|
|
|
|
|
|
Total Worldwide
|
|
|
837.5 |
|
|
|
1,015.2 |
|
|
|
660.2 |
|
|
As of December 31, 2004, 331 gross wells, representing
approximately 227 net wells, were being drilled or awaiting
completion with 71 percent and 29 percent of these
wells located in Canada and the U.S., respectively.
6
Acreage
Working interests in developed and undeveloped acreage follow.
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2004 |
|
Gross | |
|
Net | |
| |
North America
|
|
|
|
|
|
|
|
|
|
U.S.
|
|
|
|
|
|
|
|
|
|
|
Developed Acreage
|
|
|
4,576,365 |
|
|
|
2,591,740 |
|
|
|
Undeveloped Acreage
|
|
|
9,524,272 |
|
|
|
7,961,776 |
|
|
Canada
|
|
|
|
|
|
|
|
|
|
|
Developed Acreage
|
|
|
3,422,463 |
|
|
|
2,301,943 |
|
|
|
Undeveloped Acreage
|
|
|
5,124,634 |
|
|
|
3,410,447 |
|
International
|
|
|
|
|
|
|
|
|
|
|
Developed Acreage
|
|
|
690,813 |
|
|
|
209,650 |
|
|
|
Undeveloped Acreage
|
|
|
11,261,232 |
|
|
|
5,188,363 |
|
|
Worldwide
|
|
|
|
|
|
|
|
|
|
|
Developed Acreage
|
|
|
8,689,641 |
|
|
|
5,103,333 |
|
|
|
Undeveloped Acreage
|
|
|
25,910,138 |
|
|
|
16,560,586 |
|
|
|
|
|
Total Worldwide
|
|
|
34,599,779 |
|
|
|
21,663,919 |
|
|
Capital Expenditures
The Companys capital expenditures follow.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
2004 | |
|
2003 | |
|
2002 | |
| |
|
|
(In Millions) | |
| |
North America
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and Gas Activities
|
|
$ |
712 |
|
|
$ |
540 |
|
|
$ |
463 |
|
|
|
Plants and Pipelines
|
|
|
3 |
|
|
|
5 |
|
|
|
28 |
|
|
|
Administrative and Other
|
|
|
24 |
|
|
|
23 |
|
|
|
35 |
|
|
|
|
|
Total U.S.
|
|
|
739 |
|
|
|
568 |
|
|
|
526 |
|
|
|
Canada
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and Gas Activities
|
|
|
802 |
|
|
|
679 |
|
|
|
839 |
|
|
|
Plants and Pipelines
|
|
|
31 |
|
|
|
19 |
|
|
|
29 |
|
|
|
Administrative and Other
|
|
|
9 |
|
|
|
17 |
|
|
|
8 |
|
|
|
|
|
Total Canada
|
|
|
842 |
|
|
|
715 |
|
|
|
876 |
|
|
International
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and Gas Activities
|
|
|
130 |
|
|
|
366 |
|
|
|
299 |
|
|
|
Plants and Pipelines
|
|
|
32 |
|
|
|
139 |
|
|
|
136 |
|
|
|
Administrative and Other
|
|
|
4 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Total International
|
|
|
166 |
|
|
|
505 |
|
|
|
435 |
|
|
Worldwide
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and Gas Activities
|
|
|
1,644 |
|
|
|
1,585 |
|
|
|
1,601 |
|
|
|
Plants and Pipelines
|
|
|
66 |
|
|
|
163 |
|
|
|
193 |
|
|
|
Administrative and Other
|
|
|
37 |
|
|
|
40 |
|
|
|
43 |
|
|
|
|
|
Total Worldwide
|
|
$ |
1,747 |
|
|
$ |
1,788 |
|
|
$ |
1,837 |
|
|
In 2004, worldwide capital expenditures related to oil and gas
activities were $1,644 million and included 78 percent
associated with development, 17 percent for exploration and
5 percent for proved property acquisitions. Exploration
costs expensed under the successful efforts method of accounting
are included in capital expenditures for oil and gas activities.
7
Oil and Gas Production and Prices
The Companys average daily production represents its net
ownership and includes royalty interests and net profit
interests owned by the Company. The Companys average daily
production and average sales prices follow.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
2004 | |
|
2003 | |
|
2002 | |
| |
North America
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (MMCF per day)
|
|
|
908 |
|
|
|
865 |
|
|
|
949 |
|
|
|
|
NGLs (MBbls per day)
|
|
|
41.7 |
|
|
|
37.4 |
|
|
|
32.7 |
|
|
|
|
Crude oil (MBbls per day)
|
|
|
37.2 |
|
|
|
29.3 |
|
|
|
35.4 |
|
|
|
Average Sales Price
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas, including hedging (per MCF)
|
|
$ |
5.54 |
|
|
$ |
4.87 |
|
|
$ |
3.39 |
|
|
|
|
|
Natural gas, (gain) loss on hedging (per MCF)
|
|
|
(0.02 |
) |
|
|
0.10 |
|
|
|
(0.25 |
) |
|
|
|
|
Natural gas, excluding hedging (per MCF)
|
|
|
5.52 |
|
|
|
4.97 |
|
|
|
3.14 |
|
|
|
|
NGLs (per Bbl)
|
|
|
22.87 |
|
|
|
18.42 |
|
|
|
13.23 |
|
|
|
|
Crude oil, including hedging (per Bbl)
|
|
|
36.31 |
|
|
|
28.08 |
|
|
|
23.16 |
|
|
|
|
|
Crude oil, (gain) loss on hedging (per Bbl)
|
|
|
2.28 |
|
|
|
0.14 |
|
|
|
(0.24 |
) |
|
|
|
|
Crude oil, excluding hedging (per Bbl)
|
|
$ |
38.59 |
|
|
$ |
28.22 |
|
|
$ |
22.92 |
|
|
Canada
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (MMCF per day)
|
|
|
819 |
|
|
|
867 |
|
|
|
802 |
|
|
|
|
NGLs (MBbls per day)
|
|
|
23.6 |
|
|
|
27.4 |
|
|
|
27.4 |
|
|
|
|
Crude oil (MBbls per day)
|
|
|
5.5 |
|
|
|
5.1 |
|
|
|
7.8 |
|
|
|
Average Sales Price
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas, including hedging (per MCF)
|
|
$ |
5.85 |
|
|
$ |
5.12 |
|
|
$ |
3.17 |
|
|
|
|
|
Natural gas, (gain) loss on hedging (per MCF)
|
|
|
0.05 |
|
|
|
0.10 |
|
|
|
(0.06 |
) |
|
|
|
|
Natural gas, excluding hedging (per MCF)
|
|
|
5.90 |
|
|
|
5.22 |
|
|
|
3.11 |
|
|
|
|
NGLs (per Bbl)
|
|
|
29.79 |
|
|
|
23.08 |
|
|
|
15.92 |
|
|
|
|
Crude oil (per Bbl)
|
|
$ |
37.70 |
|
|
$ |
31.11 |
|
|
$ |
28.32 |
|
International
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (MMCF per day)
|
|
|
187 |
|
|
|
167 |
|
|
|
165 |
|
|
|
|
Crude oil (MBbls per day)
|
|
|
42.5 |
|
|
|
12.1 |
|
|
|
5.9 |
|
|
|
Average Sales Price
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas, including hedging (per MCF)
|
|
$ |
3.64 |
|
|
$ |
3.07 |
|
|
$ |
2.27 |
|
|
|
|
|
Natural gas, gain on hedging (per MCF)
|
|
|
|
|
|
|
|
|
|
|
(0.08 |
) |
|
|
|
|
Natural gas, excluding hedging (per MCF)
|
|
|
3.64 |
|
|
|
3.07 |
|
|
|
2.19 |
|
|
|
|
Crude oil (per Bbl)
|
|
$ |
35.94 |
|
|
$ |
23.49 |
|
|
$ |
24.30 |
|
|
Worldwide
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (MMCF per day)
|
|
|
1,914 |
|
|
|
1,899 |
|
|
|
1,916 |
|
|
|
|
NGLs (MBbls per day)
|
|
|
65.3 |
|
|
|
64.8 |
|
|
|
60.1 |
|
|
|
|
Crude oil (MBbls per day)
|
|
|
85.2 |
|
|
|
46.5 |
|
|
|
49.1 |
|
|
|
Average Sales Price
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas, including hedging (per MCF)
|
|
$ |
5.49 |
|
|
$ |
4.83 |
|
|
$ |
3.20 |
|
|
|
|
|
Natural gas, (gain) loss on hedging (per MCF)
|
|
|
0.01 |
|
|
|
0.09 |
|
|
|
(0.16 |
) |
|
|
|
|
Natural gas, excluding hedging (per MCF)
|
|
|
5.50 |
|
|
|
4.92 |
|
|
|
3.04 |
|
|
|
|
NGLs (per Bbl)
|
|
|
25.38 |
|
|
|
20.40 |
|
|
|
14.46 |
|
|
|
|
Crude oil, including hedging (per Bbl)
|
|
|
36.25 |
|
|
|
27.22 |
|
|
|
24.11 |
|
|
|
|
|
Crude oil, (gain) loss on hedging (per Bbl)
|
|
|
0.99 |
|
|
|
0.09 |
|
|
|
(0.18 |
) |
|
|
|
|
Crude oil, excluding hedging (per Bbl)
|
|
$ |
37.24 |
|
|
$ |
27.31 |
|
|
$ |
23.93 |
|
|
8
Production Unit Costs
The Companys production unit costs follow. Production
costs include production taxes and well operating costs.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
2004 | |
|
2003 | |
|
2002 | |
|
|
| |
|
|
(Per MCFE) | |
| |
North America
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Production Costs
|
|
$ |
0.80 |
|
|
$ |
0.68 |
|
|
$ |
0.62 |
|
|
|
DD&A Rates
|
|
|
0.68 |
|
|
|
0.62 |
|
|
|
0.66 |
|
|
Canada
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Production Costs
|
|
|
0.55 |
|
|
|
0.44 |
|
|
|
0.38 |
|
|
|
DD&A Rates
|
|
|
1.41 |
|
|
|
1.19 |
|
|
|
0.97 |
|
International
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Production Costs
|
|
|
0.60 |
|
|
|
0.53 |
|
|
|
0.32 |
|
|
|
DD&A Rates
|
|
|
1.32 |
|
|
|
1.14 |
|
|
|
1.02 |
|
|
Worldwide
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Production Costs
|
|
|
0.68 |
|
|
|
0.57 |
|
|
|
0.50 |
|
|
|
DD&A Rates
|
|
$ |
1.04 |
|
|
$ |
0.91 |
|
|
$ |
0.81 |
|
|
Reserves
The following table sets forth estimates by the Companys
petroleum engineers of proved natural gas, NGLs and crude oil
reserves at December 31, 2004. These reserves have been
prepared in accordance with the Securities and Exchange
Commissions Regulations. These reserves have been reduced
for royalty interests owned by others.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved | |
|
Proved | |
|
Total Proved | |
December 31, 2004 |
|
Developed | |
|
Undeveloped | |
|
Reserves | |
| |
North America
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (BCF)
|
|
|
3,745 |
|
|
|
1,331 |
|
|
|
5,076 |
|
|
|
NGLs (MMBbls)
|
|
|
193.1 |
|
|
|
85.3 |
|
|
|
278.4 |
|
|
|
Crude oil (MMBbls)
|
|
|
185.8 |
|
|
|
18.7 |
|
|
|
204.5 |
|
|
|
|
Total U.S. (BCFE)
|
|
|
6,019 |
|
|
|
1,954 |
|
|
|
7,973 |
|
|
Canada
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (BCF)
|
|
|
1,821 |
|
|
|
509 |
|
|
|
2,330 |
|
|
|
NGLs (MMBbls)
|
|
|
44.6 |
|
|
|
9.5 |
|
|
|
54.1 |
|
|
|
Crude oil (MMBbls)
|
|
|
13.6 |
|
|
|
4.3 |
|
|
|
17.9 |
|
|
|
|
Total Canada (BCFE)
|
|
|
2,170 |
|
|
|
592 |
|
|
|
2,762 |
|
International
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (BCF)
|
|
|
435 |
|
|
|
385 |
|
|
|
820 |
|
|
|
Crude oil (MMBbls)
|
|
|
48.5 |
|
|
|
26.8 |
|
|
|
75.3 |
|
|
|
|
Total International (BCFE)
|
|
|
726 |
|
|
|
546 |
|
|
|
1,272 |
|
|
Worldwide
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (BCF)
|
|
|
6,001 |
|
|
|
2,225 |
|
|
|
8,226 |
|
|
|
NGLs (MMBbls)
|
|
|
237.7 |
|
|
|
94.8 |
|
|
|
332.5 |
|
|
|
Crude oil (MMBbls)
|
|
|
247.9 |
|
|
|
49.8 |
|
|
|
297.7 |
|
|
|
|
Total Worldwide (BCFE)
|
|
|
8,915 |
|
|
|
3,092 |
|
|
|
12,007 |
|
|
Miller and Lents, Ltd. and Sproule Associates Limited,
independent oil and gas consultants, have reviewed the estimates
of proved reserves of natural gas, crude oil and NGLs that the
Company attributed to its net interests in oil and gas
properties as of December 31, 2004. Miller and Lents, Ltd.
reviewed the reserve estimates for the Companys U.S. and
International interests and Sproule Associates Limited reviewed
the Companys interests in Canada. Based on their review of
more than 80 percent of the Companys reserve
estimates, it is their judgment that the estimates are
reasonable in the aggregate. For more information, see
independent oil and gas consultants letters on pages 69-73.
For further information on reserves, including information on
future net cash flows and the standardized measure of discounted
future net cash flows, see Supplementary Financial
Information Supplemental Oil and Gas Disclosures.
Other Matters
Competition The Company actively competes for
reserve acquisitions, exploration leases and sales of natural
gas and crude oil, frequently against companies with
substantially larger financial and other resources. In its
marketing activities,
9
the Company competes with numerous companies for the sale of
natural gas, NGLs and crude oil. Competitive factors in the
Companys business include price, contract terms, quality
of service, pipeline access, transportation discounts and
distribution efficiencies.
Regulation of Oil and Gas Production, Sales and
Transportation The oil and gas industry is subject to
regulation by numerous national, state and local governmental
agencies and departments throughout the world. Compliance with
these regulations is often difficult and costly and
noncompliance could result in substantial penalties and risks.
Most jurisdictions in which the Company operates also have
statutes, rules, regulations or guidelines governing the
conservation of natural resources, including the unitization or
pooling of oil and gas properties and the establishment of
maximum rates of production from oil and gas wells. Some
jurisdictions also require the filing of drilling and operating
permits, bonds and reports. The failure to comply with these
statutes, rules and regulations could result in the imposition
of fines and penalties and the suspension or cessation of
operations in affected areas.
The Company operates various gathering systems. The United
States Department of Transportation and certain governmental
agencies regulate the safety and operating aspects of the
transportation and storage activities of these facilities by
prescribing standards. However, based on current standards
concerning transportation and storage activities and any
proposed or contemplated standards, the Company believes that
the impact of such standards is not material to the
Companys operations, capital expenditures or financial
position. Compliance with such standards has been incorporated
by the Company in its operations over many years and no material
capital expenditures are allocated to such compliance.
All of the Companys sales of its domestic natural gas are
currently deregulated, although governmental agencies may elect
in the future to regulate certain sales.
Environmental Regulation Various federal, state and
local laws and regulations relating to the protection of the
environment, including the discharge of materials into the
environment, may affect the Companys domestic exploration,
development and production operations and the costs of those
operations. In addition, the Companys international
operations are subject to environmental regulations administered
by foreign governments, including political subdivisions
thereof, or by international organizations. These domestic and
international laws and regulations, among other things, govern
the amounts and types of substances that may be released into
the environment, the issuance of permits to conduct exploration,
drilling and production operations, the discharge and
disposition of generated waste materials and waste management,
the reclamation and abandonment of wells, sites and facilities,
financial assurance under the Oil Pollution Act of 1990 and the
remediation of contaminated sites. These laws and regulations
may impose substantial liabilities for noncompliance and for any
contamination resulting from the Companys operations and
may require the suspension or cessation of operations in
affected areas.
The environmental laws and regulations applicable to the Company
and its operations include, among others, the following United
States federal laws and regulations:
|
|
|
Clean Air Act, and its amendments, which governs air emissions; |
|
|
Clean Water Act, which governs discharges to waters of the
United States; |
|
|
Comprehensive Environmental Response, Compensation and Liability
Act, which imposes liability where hazardous releases have
occurred or are threatened to occur (commonly known as
Super Fund); |
|
|
Resource Conservation and Recovery Act, which governs the
management of solid waste; |
|
|
Oil Pollution Act of 1990, which imposes liabilities resulting
from discharges of oil into navigable waters of the United
States; |
|
|
Emergency Planning and Community Right-to-Know Act, which
requires reporting of toxic chemical inventories; |
|
|
Safe Drinking Water Act, which governs the underground injection
and disposal of wastewater; and |
|
|
U.S. Department of Interior regulations, which impose
liability for pollution cleanup and damages. |
In addition, many states and foreign countries where the Company
operates have similar environmental laws and regulations
covering the same types of matters. In Canada, environmental
compliance is governed by various statutes, regulations and
codes promulgated at different levels of government including
the federal Fisheries Act and Canadian Environmental
Protection Act; and provincially, the Environmental Protection
and Enhancement Act, the Oil and Gas Conservation Act and the
Pipeline Act in the province of Alberta; and the Waste
Management Act, the Environmental Assessment Act and the
Environment Management Act in the province of British Columbia.
The Kyoto Protocol to the United Nations Framework Convention on
Climate Change (Kyoto Protocol) became effective
February 16, 2005, and requires Annex I countries,
including Canada and the United Kingdom, to reduce their
emissions of carbon dioxide and other greenhouse gases. As a
result of the ratification of the Kyoto Protocol and the
adoption of legislation or other regulatory initiatives designed
to implement its objectives by the national and regional
governments, reductions in greenhouse gases from crude oil and
natural gas producers may be required which could result in,
among other things,
10
increased operating and capital expenditures for those
producers. Until such legislation or other regulatory
initiatives are finalized, the impact of the Kyoto Protocol and
any such legislation adopted as a result of its ratification
remains uncertain.
The Company routinely obtains permits for its facilities and
operations in accordance with these applicable laws and
regulations on an ongoing basis. There are no known issues that
have a significant adverse effect on the permitting process or
permit compliance status of any of the Companys facilities
or operations.
The ultimate financial impact of these environmental laws and
regulations is neither clearly known nor easily determined as
new standards are enacted and new interpretations of existing
standards are rendered. Environmental laws and regulations are
expected to have an increasing impact on the Companys
operations in the United States and in most countries in which
it operates. In addition, any non-compliance with such laws
could subject the Company to material administrative, civil or
criminal penalties, or other liabilities. Potential permitting
costs are variable and directly associated with the type of
facility and its geographic location. Costs, for example, may be
incurred for air emission permits, spill contingency
requirements, and discharge or injection permits. These costs
are considered a normal, recurring cost of the Companys
ongoing operations and not an extraordinary cost of compliance
with government regulations.
The Company is committed to the protection of the environment
throughout its operations and believes that it is in substantial
compliance with applicable environmental laws and regulations.
The Company believes that environmental stewardship is an
important part of its daily business and will continue to make
expenditures on a regular basis relating to environmental
compliance. The Company maintains insurance coverage for spills,
pollution and certain other environmental risks, although it is
not fully insured against all such risks. The insurance coverage
maintained by the Company provides for the reimbursement to the
Company of costs incurred for the containment and clean-up of
materials that may be suddenly and accidentally released in the
course of the Companys operations, but such insurance does
not fully insure pollution and similar environmental risks. The
Company does not anticipate that it will be required under
current environmental laws and regulations to expend amounts
that will have a material adverse effect on the consolidated
financial position or results of operations of the Company.
However, since environmental costs and liabilities are inherent
in the Companys operations and in the operations of
companies engaged in similar businesses and since regulatory
requirements frequently change and may become more stringent,
there can be no assurance that material costs and liabilities
will not be incurred in the future. Such costs may result in
increased costs of operations and acquisitions and decreased
production.
Filings of Reserve Estimates With Other Agencies
During 2004, the Company filed estimates of its oil and gas
reserves for the year 2003 with the Department of Energy. These
estimates differ by 5 percent or less from the reserve data
presented. For information concerning proved natural gas, NGLs
and crude oil reserves, see Supplementary Financial
Information Supplemental Oil and Gas Disclosures.
Employees
The Company had 2,214 and 2,111 employees at December 31,
2004 and 2003, respectively. At December 31, 2004, the
Company had no union employees.
Web Site Access to Reports
The Companys Web site address is
www.br-inc.com. The Company makes available, free
of charge on or through its Web site, its annual report on
Form 10-K, quarterly reports on Form 10-Q and current
reports on Form 8-K, and all amendments to these reports as
soon as reasonably practicable after such material is
electronically filed with, or furnished to, the United States
Securities and Exchange Commission. Such reports, which include
the Companys annual and quarterly financial statements,
are also filed in Canada on the System for Electronic Document
Analysis and Retrieval (SEDAR) and are also available to
the Companys stockholders, including those residing in
Ontario, Canada, from the Company upon request at no charge.
11
ITEM THREE
LEGAL PROCEEDINGS
See Note 14 of Notes to Consolidated Financial Statements.
ITEM FOUR
SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
No matters were submitted to a vote of Burlington Resources
Inc.s security holders during the fourth quarter of 2004.
EXECUTIVE OFFICERS OF THE REGISTRANT
Bobby S. Shackouls, 54 Chairman of the Board,
President and Chief Executive Officer, Burlington Resources
Inc., July 1997 to present.
Randy L. Limbacher, 46 Office of the Chairman,
Burlington Resources Inc., January 2004 to present. Executive
Vice President and Chief Operating Officer, Burlington Resources
Inc., December 2002 to present. Senior Vice President,
Production, Burlington Resources Inc., April 2001 to December
2002. President and Chief Executive Officer, BROG GP Inc.,
general partner of Burlington Resources Oil & Gas
Company LP, December 2000 to July 2001. President and Chief
Executive Officer, Burlington Resources Oil & Gas
Company, July 1998 to December 2000.
Steven J. Shapiro, 52 Office of the Chairman,
Burlington Resources Inc., January 2004 to present. Executive
Vice President and Chief Financial Officer, Burlington Resources
Inc., December 2002 to present. Senior Vice President and Chief
Financial Officer, Burlington Resources Inc., October 2000 to
December 2002. Senior Vice President, Chief Financial Officer
and Director, Vastar Resources, Inc., 1993 to September 2000.
Mark E. Ellis, 48 Senior Vice President, North
American Production, Burlington Resources Inc., September 2004
to present. President, Burlington Resources Canada Ltd., October
2000 to September 2004. Vice President, San Juan Division,
Burlington Resources Oil & Gas Company, January 1997 to
October 2000.
L. David Hanower, 45 Senior Vice President,
Law and Administration, Burlington Resources Inc., July 1998 to
present.
John A. Williams, 60 Senior Vice President,
Exploration, Burlington Resources Inc., April 2001 to present.
Senior Vice President, Exploration, BROG GP Inc., general
partner of Burlington Resources Oil & Gas Company LP,
December 2000 to present. Senior Vice President, Exploration,
Burlington Resources Oil & Gas Company, July 1998 to
December 2000.
12
PART II
ITEM FIVE
MARKET FOR REGISTRANTS COMMON EQUITY, RELATED
STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
The Companys common stock, par value $.01 per share
(Common Stock), is traded on the New York Stock
Exchange under the symbol BR. Effective at the close
of business on January 31, 2005, the Company discontinued
the listing of its Common Stock on the Toronto Stock Exchange.
At December 31, 2004, the number of record holders of
Common Stock was 11,801. Information on Common Stock prices and
quarterly dividends is shown on page 79 under the
subheading Quarterly Financial Data Unaudited.
See also Equity Compensation Plan Information under
Part III, Item 12 of this report.
Issuer Purchases of Equity Securities(1)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(c) | |
|
(d) | |
|
|
(a) | |
|
|
|
Total Number of | |
|
Approximate Dollar | |
|
|
Total | |
|
(b) | |
|
Shares Purchased | |
|
Value of Shares that | |
|
|
Number of | |
|
Average | |
|
as Part of Publicly | |
|
May Yet Be | |
|
|
Shares | |
|
Price Paid | |
|
Announced Plans | |
|
Purchased Under the | |
Period |
|
Purchased | |
|
per Share | |
|
or Programs | |
|
Plans or Programs | |
|
|
| |
|
|
(In Thousands, Except per Share Amounts) | |
| |
October 1, 2004 October 31, 2004
|
|
|
1,363 |
|
|
$ |
41.73 |
|
|
|
1,363 |
|
|
$ |
359,818 |
|
November 1, 2004 November 30, 2004
|
|
|
1,365 |
|
|
|
42.39 |
|
|
|
1,365 |
|
|
|
301,959 |
|
December 1, 2004 December 31, 2004
|
|
|
1,430 |
|
|
|
43.31 |
|
|
|
1,430 |
|
|
$ |
952,229 |
|
|
|
Total
|
|
|
4,158 |
|
|
$ |
42.49 |
|
|
|
4,158 |
|
|
|
|
|
|
|
|
(1) |
In December 2000, the Company announced that the Board of
Directors (Board) authorized the repurchase of up to
$1 billion of the Companys Common Stock. Through
April 30, 2003, the Company had repurchased
$816 million of its Common Stock under the program
authorized in December 2000. In April 2003, the Company
announced that the Board voted to restore the authorization
level to $1 billion effective May 1, 2003. Through
December 7, 2004, the Company had repurchased
$712 million of its Common Stock under the program
authorized in April 2003. In December 2004, the Company
announced that the Board again voted to restore the
authorization level to $1 billion. |
13
ITEM SIX
SELECTED FINANCIAL DATA
The selected financial data for the Company set forth below
should be read in conjunction with the consolidated financial
statements and accompanying notes thereto.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
2004 | |
|
2003 | |
|
2002 | |
|
2001 | |
|
2000 | |
|
|
| |
|
|
(In Millions, Except per Share Amounts) | |
| |
INCOME STATEMENT DATA
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues
|
|
$ |
5,618 |
|
|
$ |
4,311 |
|
|
$ |
2,968 |
|
|
$ |
3,419 |
|
|
$ |
3,218 |
|
|
Income Before Income Taxes and Cumulative Effect of Change in
Accounting Principle
|
|
|
2,304 |
|
|
|
1,570 |
|
|
|
569 |
|
|
|
907 |
|
|
|
967 |
|
|
Cumulative Effect of Change in Accounting Principle Net
|
|
|
|
|
|
|
(59 |
) |
|
|
|
|
|
|
3 |
|
|
|
|
|
|
Net Income(1)
|
|
|
1,527 |
|
|
|
1,201 |
|
|
|
454 |
|
|
|
561 |
|
|
|
675 |
|
|
Basic Earnings per Common Share(1)(2)(3)
|
|
|
3.90 |
|
|
|
3.02 |
|
|
|
1.13 |
|
|
|
1.35 |
|
|
|
1.57 |
|
|
Diluted Earnings per Common Share(1)(2)(3)
|
|
|
3.86 |
|
|
|
3.00 |
|
|
|
1.13 |
|
|
|
1.35 |
|
|
|
1.56 |
|
|
Cash Dividends Declared per Common Share(3)
|
|
$ |
0.32 |
|
|
$ |
0.29 |
|
|
$ |
0.28 |
|
|
$ |
0.28 |
|
|
$ |
0.28 |
|
|
December 31, |
|
BALANCE SHEET DATA
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Assets
|
|
$ |
15,744 |
|
|
$ |
12,995 |
|
|
$ |
10,645 |
|
|
$ |
10,582 |
|
|
$ |
7,506 |
|
|
Long-term Debt
|
|
|
3,887 |
|
|
|
3,873 |
|
|
|
3,853 |
|
|
|
4,337 |
|
|
|
2,301 |
|
|
Stockholders Equity
|
|
$ |
7,011 |
|
|
$ |
5,521 |
|
|
$ |
3,832 |
|
|
$ |
3,525 |
|
|
$ |
3,750 |
|
|
Common Shares Outstanding(3)
|
|
|
388 |
|
|
|
395 |
|
|
|
403 |
|
|
|
402 |
|
|
|
431 |
|
|
|
|
(1) |
Year 2004 includes an income tax benefit of $23 million or
$0.06 per share related to the reduction of the Canadian
federal income tax rate and $45 million or $0.11 per
share related to the reduction of the Alberta provincial income
tax rate. In 2004, the Company recorded a U.S. income tax
expense of $26 million or $0.07 per share related to
the planned repatriation of $500 million of eligible
foreign earnings to the U.S. under the one-time provisions of
the American Jobs Creation Act of 2004. Year 2004 also includes
a non-cash after tax charge of $59 million
($90 million pretax) or $0.15 per share related to the
impairment of undeveloped properties in Canada. Year 2003
includes an income tax benefit of $203 million or
$0.51 per share related to the reduction of the Canadian
federal income tax rate and $11 million or $0.02 per
share related to the reduction of the Alberta provincial income
tax rate. Year 2003 also includes a non-cash after tax charge of
$38 million ($63 million pretax) or $0.09 per
share related to the impairment of oil and gas properties in
Canada. |
|
(2) |
Year 2003 includes a cumulative effect of change in accounting
principle (Cumulative Effect) loss of $0.15 related
to the adoption of Statement of Financial Accounting Standards
(SFAS) No. 143, Asset Retirement
Obligations. Year 2001 includes a Cumulative Effect gain of
$0.01 related to the adoption of SFAS No. 133,
Accounting for Derivative Instruments and Hedging
Activities, as amended. |
|
(3) |
Share amounts related to years 2000 through 2003 have been
retroactively adjusted to reflect the 2-for-1 stock split of the
Companys Common Stock effective June 1, 2004. |
14
ITEMS SEVEN AND SEVEN A
MANAGEMENTS DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS AND QUANTITATIVE AND
QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Overview
The Company is one of the largest independent exploration and
production companies in North America. The Company explores for,
develops and produces natural gas, NGLs and crude oil, primarily
from its properties located in the Rocky Mountain natural gas
fairway of North America, complemented by international
operations. The Companys North American activities are
concentrated in areas with known hydrocarbon resources, which
are conducive to large, multi-well, repeatable drilling programs
and the Companys technical skills. Internationally, the
Company is focused on achieving operational efficiencies, while
advancing potential growth opportunities in existing positions.
Basin
ExcellenceSM
is the Companys concept of concentrating its operations
and expertise in core areas where it believes it holds
significant competitive advantages. These areas are typically in
high potential geologic basins with large natural gas and crude
oil resources that support multiple-year development programs.
These are also areas where the Company holds significant land or
mineral interest positions, has teams with years of relevant
geologic, geophysical, engineering and operational experience,
has access to production, processing and gathering
infrastructure and has long-term relationships with partners,
suppliers and land and mineral interest owners. The Company
believes that it has attained or will ultimately attain this
stature in several areas throughout the world that currently
represent the majority of its core assets. These assets
traditionally yield high returns on investment, and, therefore,
the Company has concentrated its activities in these areas and
exited other areas that did not meet these standards.
The Company has adopted a disciplined capital allocation
process, with the objective of achieving annual volumetric
growth (in the range of three to eight percent as a long-term
annual average) coupled with strong financial returns.
In managing its business, the Company must deal with numerous
risks and uncertainties. These risks and uncertainties can be
broadly categorized as: subsurface, which includes
the presence, size and recoverability of hydrocarbons;
regulatory, which includes access and permitting
necessary to conduct its operations; operational,
which includes logistical, timing and infrastructure issues,
especially internationally, which are often beyond the
Companys control; and commercial, which
includes commodity price volatility, local price differentials
in its various areas of operations and attention to operating
margins and the availability of markets for its production,
especially natural gas. Each of these factors is challenging and
highly variable.
To address subsurface risks, the Company utilizes many of the
latest technological tools available to assess and mitigate
these risks. These tools include, but are not limited to, modern
geophysical data and interpretation software, petrophysical
information, physical core data, production histories,
paleontology data and satellite imagery. In spite of these
technologies, the multitude of unknown variables that exist
below the surface of the earth make it difficult to consistently
and accurately predict drilling results. The Company has put
considerable emphasis in recent years on creating an asset
portfolio that improves the reliability of those predictions;
however, these types of operations tend to exploit or develop
smaller quantities of hydrocarbon reserves and, as a result, the
Company must develop more of these opportunities in order to
maintain production. Similarly, the Company has reduced its
focus on areas where there is far less analytical data available
and drilling outcomes are less predictable, such as wildcat
exploration operations in sparsely explored areas. The Company
is constantly assessing its drilling opportunities to achieve
balance in its drilling program for risk and financial returns.
In order to make this possible, the Company attempts to maintain
a large inventory of drillable projects from which its technical
and management teams can select a drilling program in any given
period.
On regulatory and operational matters, the Company actively
manages its exploration and production activities. The Company
values sound stewardship and strong relationships with all
stakeholders in conducting its business. The Company attempts to
stay abreast of emerging issues to effectively anticipate and
manage potential impacts to the Companys operations.
Managing the commercial risks is an ongoing priority at the
Company. Considerable analysis of historical price trends,
supply statistics, demand projections and infrastructure
constraints form the basis of the Companys outlook for the
commodity prices it may receive for its future production.
Because much of this data is dynamic, the Companys view
and the markets view of future commodity pricing can
change rapidly. Based on the Companys ongoing assessment
of the underlying data and the markets, the Company will from
time to time use various financial tools to hedge the price it
will receive for a particular commodity in the future. The
primary purpose of these activities is to enhance financial
returns on the significant investments that the Company makes
annually to replenish its productive base and grow its reserves
while leaving as much commodity price upside as possible for the
Companys stockholders. Margin enhancement is another
important element of the Companys business, including
attention to operating costs, administrative expenses and
marketing activities, such as securing transportation to
alternative market hubs to protect
15
against weak producing-area prices. The Company may also enter
into transportation agreements that allow the Company to sell a
portion of its production in alternative markets when local
prices are weak.
All of the risks and uncertainties described above create
opportunities in the exploration and production business to the
extent they drive the relative valuations of three distinct
asset classes in the business. The first asset class is the
commodities themselvesnatural gas, NGLs and crude oil. The
prices for this asset class are generally established by the
purchasers of these commodities, but closely track the prices
that are set through the public trading of futures contracts for
those same commodities. The second asset class consists of the
physical oil and gas properties that may contain proved,
probable and possible reserves, as well as exploratory
potential. The value of physical assets is usually established
in a private market created by a willing seller and a willing
buyer of a given property or group of properties. The third
asset class consists of the equities of the publicly traded
exploration and production companies that are valued in the
public market place daily. Because these three asset classes are
not always valued consistently with one another, opportunities
may exist from time to time to take advantage of these various
valuation differences. These valuation differences are key to
the Companys capital allocation philosophy.
There are three types of investment alternatives that constantly
compete for available capital at the Company. These include
drilling opportunities, acquisition opportunities and financial
alternatives such as share repurchases, dividends and debt
repayment. Depending on circumstances and the relative
valuations of the asset classes described above, the Company
allocates capital among its investment alternatives through an
allocation approach that is rate-of-return based. Its goal is to
ensure that capital is being invested in the highest return
opportunities available at any given time.
Much of what has been described above is conducted and handled
routinely. The ability of the Companys management and
staff to take into account all relevant factors, which fluctuate
constantly, will be a key determinant in the Companys
future performance.
Outlook
The Companys business model strives to achieve both
production growth and sector-leading financial returns when
compared to other independent oil and gas exploration and
production companies. This model requires the continuous
development of natural gas and crude oil reserves to fuel
growth, while maintaining a rigorous focus on cost structure and
capital efficiency.
Key to achieving the Companys financial goals is its
disciplined capital investment approach. The Company deploys the
net operating cash flows it generates among its core capital
programs, as well as for acquisitions and other financial uses,
such as share repurchases and dividend payments. Although
commodity prices are volatile, the Company generally does not
favor increasing or decreasing its capital program in response
to commodity prices. Instead, the Company seeks to exercise a
disciplined approach in order to keep its cost structure as low
as possible.
The Company expects to continue focusing on exploring for and
producing North American natural gas as its primary business.
The Company expects North America to represent 85 percent
of its total production in 2005. While the Companys
management recognizes that the North American natural gas
business has many characteristics of a mature, slow-growth
business, it believes that finding or acquiring and producing
North American natural gas will continue to be a profitable,
high-return business for the Company due to certain unique
advantages that position it to be successful. First, the Company
has long-lived asset positions in gas resource-prone basins and
focuses heavily on maintaining a competitive cost structure.
Secondly, the Company executes a consistent capital program by
employing a capital allocation approach that favors discipline
and balance.
The Companys International business segment is less
mature, but has undergone a significant growth phase after
several years of developing major projects. The International
segment is expected to represent 15 percent of the
Companys total production in 2005 and remain at about that
level for the foreseeable future.
Reserve Replacement
Finding and developing sufficient amounts of natural gas and
crude oil reserves at economical costs are critical to the
Companys long-term success. Given the inherent decline of
hydrocarbon reserves resulting from the production of those
reserves, it is important for an exploration and production
company to demonstrate a long-term trend of more than offsetting
produced volumes with new reserves that will provide for future
production. Management uses the reserve replacement ratio, as
defined below, as an indicator of the Companys ability to
replenish annual production volumes and grow its reserves,
thereby providing some information on the sources of future
production. The reserve replacement ratio is calculated by
dividing the sum of reserve additions from all sources
(revisions, extensions, discoveries, and other additions and
acquisitions) by the actual production for the corresponding
period. The values for these reserve additions are derived
directly from the proved reserves table on pages 76-77 in the
Supplementary Financial Information section of this report.
Accordingly, the Company does not use unproved reserve
quantities or proved reserve additions that include both proved
reserve additions attributable to consolidated entities and
investments accounted for using the equity method in calculating
its reserve replacement ratio. It should be noted that
16
the reserve replacement ratio is a statistical indicator that
has limitations. As an annual measure, the ratio is limited
because it typically varies widely based on the extent and
timing of new discoveries, project sanctioning and property
acquisitions. Its predictive and comparative value is also
limited for the same reasons. In addition, since the ratio does
not imbed the cost or timing of future production of new
reserves, it cannot be used as a measure of value creation.
It is also important for an exploration and production company
to demonstrate a long-term trend of adding reserves at a
reasonable cost. Given that the cost of adding reserves is
ultimately included in depreciation, depletion and amortization
(DD&A) expense, management believes that an
ability to add reserves in its core asset areas at a lower cost
than its competition should contribute to a sustainable
competitive advantage. The Company, in fact, has a goal to
achieve 10 to 15 percent lower replacement costs than its
competition in North America. Management therefore uses a per
unit reserve replacement costs metric, as defined below, as an
indicator of the Companys ability to replenish annual
production volumes and grow reserves on a cost-effective basis.
Analysts and investors use the measure widely and often cite the
measure on a single year basis. In 2004, the Companys
reserve replacement costs were $1.27 per MCFE including
acquisitions or $1.27 per MCFE excluding acquisitions. The
increase in costs was primarily due to industry service
inflation. The Company typically cites reserve replacement costs
in the context of a multi-year trend, in recognition of its
limitations as a single year measure, but also to demonstrate
consistency and stability, which are essential to the
Companys business model. For the three-year period ended
December 31, 2004, the Companys average reserve
replacement costs were $1.17 per MCFE including
acquisitions and $1.19 per MCFE excluding acquisitions. As
used herein, reserve replacement costs represent total oil and
gas capital costs, including acquisitions, incurred in order to
add reserves. Reserve replacement costs per unit are calculated
by dividing total oil and gas capital costs, including
acquisitions, by the sum of reserve revisions, extensions,
discoveries and other additions and acquisitions. The costs used
to calculate reserve replacement costs include the costs of
development, exploration and property acquisition activities as
presented in the Supplemental Oil and Gas Disclosures table on
page 74 of this report.
Set forth below are the Companys reserve replacement ratio
and reserve replacement costs per unit, along with the
Companys capital expenditures.
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
2004 | |
|
2003 | |
|
2002 | |
| |
|
|
($ per MCFE) | |
| |
Reserve replacement costs, including acquisitions
|
|
$ |
1.27 |
|
|
$ |
1.19 |
|
|
$ |
1.06 |
|
Reserve replacement costs, excluding acquisitions
|
|
$ |
1.27 |
|
|
$ |
1.23 |
|
|
$ |
1.03 |
|
|
|
|
(% of Production) |
|
Reserve replacement ratio, including acquisitions
|
|
|
125% |
|
|
|
142% |
|
|
|
161% |
|
Reserve replacement ratio, excluding acquisitions
|
|
|
119% |
|
|
|
118% |
|
|
|
103% |
|
|
Capital Expenditures
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
2004 | |
|
2003 | |
|
2002 | |
| |
|
|
(In Millions) | |
| |
Total capital expenditures
|
|
$ |
1,747 |
|
|
$ |
1,788 |
|
|
$ |
1,837 |
|
Less: acquisitions
|
|
|
85 |
|
|
|
228 |
|
|
|
604 |
|
|
Capital expenditures, excluding acquisitions
|
|
$ |
1,662 |
|
|
$ |
1,560 |
|
|
$ |
1,233 |
|
|
The Companys focus on Basin
Excellencesm
in established, long-lived core assets results in the majority
of its reserve additions coming from development drilling,
including extensions from both infill and step-out drilling.
Resource assessment studies in targeted areas also result in the
addition of proved undeveloped reserves at infill locations in
existing producing fields. Reserves added include both proved
developed and proved undeveloped components for all periods
presented. Over the past two years, the ratio of proved
undeveloped reserves to total proved reserves has been about
26 percent. Proved developed reserves will generally begin
producing within the year they are added. Proved undeveloped
reserves generally require a major future expenditure and it is
anticipated that approximately 75 percent of these reserves
will begin producing within five years from the date in which
the reserves are recorded. Due to the Companys extensive
inventory of potential capital projects, reserve additions are
expected to continue in the future, particularly in the
Companys core operating areas, although there are no
assurances as to the timing and magnitude of these additions.
17
In 2005, the Company expects to spend approximately
$2 billion of capital, excluding acquisitions. This level
of spending represents a 21 percent increase over 2004
capital. The Company currently believes that this level of
spending is needed in each of the next few years to achieve its
objective of three to eight percent average annual production
growth. Approximately 88 percent of the Companys 2005
capital program is allocated to its North American programs in
Canada and the U.S. This capital level in North America
represents an increase of approximately 12 percent from
prior years. In North America, the Company is allocating a
higher percentage of its capital investment to Canada primarily
due to an expected increase in drilling activities, higher
service costs and a stronger Canadian dollar in 2005.
Below is a discussion of the Companys production levels
and expected production growth.
Production
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
2004 | |
|
2003 | |
|
2002 | |
| |
|
|
(MMCFE per day) |
|
U.S.
|
|
|
1,381 |
|
|
|
1,265 |
|
|
|
1,358 |
|
Canada
|
|
|
994 |
|
|
|
1,062 |
|
|
|
1,013 |
|
International
|
|
|
442 |
|
|
|
240 |
|
|
|
200 |
|
|
|
Total production
|
|
|
2,817 |
|
|
|
2,567 |
|
|
|
2,571 |
|
|
The Company has a goal to achieve between three and eight
percent average annual production growth. In 2004, production
volumes were 2,817 MMCFE per day, representing a
10 percent increase over 2003. In 2005, the Company expects
production volumes to average between 2,800 and 3,001 MMCFE
per day. Production growth is expected to be driven by steady
production growth in the U.S. and increased production from
international operations.
In 2005, the Company expects production growth in the
U.S. as a result of increased production from Cedar Creek,
Bossier, south Louisiana and Bakken drilling programs.
Internationally, the Company expects increased production at the
sour gas fields in the East Irish Sea resulting from the
expected resumption of production from the Rivers Fields.
Production from the Rivers Fields commenced in October 2004;
however, in November 2004, problems were encountered related to
the acid plant. Repairs to the plant are progressing and
production is expected to resume by the second quarter of 2005.
The Company expects production in Canada to decline one to
seven percent from production levels in 2004.
While these activities are subject to the risks and delays
inherent to this business as discussed above, the Company
believes that these sources of production growth are currently
available and is now focused on identifying sources of
production growth for the future.
Financial Returns
In addition to the Companys production growth goal, it is
committed to generating sector-leading returns on capital
employed when compared to other independent oil and gas
exploration and production companies. While commodity prices
play a significant role in the Companys financial returns,
the Company focuses on controllable elements such as certain
operating costs. In 2005, the Company expects to keep its
operating and administrative costs about the same as 2004 on a
per unit-of-production basis. However, it expects DD&A
expense to increase about 14 to 23 percent in 2005 compared
to 2004, primarily as a result of higher rates related to
Canadian and International properties and unfavorable exchange
rate impacts. Other costs could also increase as a result of
unfavorable exchange rate impacts. Although subject to the
upward cost pressures generally experienced by the industry, the
Company believes it can differentiate its performance from that
of its peers as a result of several initiatives underway to
maintain its diligence on costs, specifically in the areas of
purchasing, continuous process improvement, and knowledge
transfer. The Company will continue to focus on capital
efficiency and cost control.
18
Below are estimated and actual costs and expenses for 2005 and
2004, respectively.
|
|
|
|
|
|
|
|
|
|
|
2005 | |
|
2004 | |
| |
|
|
(Per Mcfe) | |
| |
Transportation expense
|
|
$ |
0.46 to $0.49 |
|
|
$ |
0.44 |
|
Operating costs
|
|
|
0.58 to 0.62 |
|
|
|
0.57 |
|
DD&A
|
|
|
1.25 to 1.35 |
|
|
|
1.10 |
|
Administrative
|
|
$ |
0.16 to $0.19 |
|
|
$ |
0.21 |
|
|
|
|
(In Millions) |
|
Exploration costs
|
|
$ |
300 to $ 325 |
|
|
$ |
258 |
|
Interest expense
|
|
$ |
270 to $ 290 |
|
|
$ |
282 |
|
|
Transportation expense is expected to be higher in 2005 as a
result of resuming production at Rivers Fields in the
International operation. This operation is expected to add
approximately nine percent to the amount expended for
transportation in 2004. Transportation expense for the
Companys remaining operations is expected to increase
slightly over 2004. Exploration costs are primarily dependent
upon the size of the Companys drilling program and the
success it has in finding commercial hydrocarbons. The Company
cannot forecast its expected exploration success rate but it
expects exploration costs to exceed the costs incurred in 2004
primarily due to higher anticipated exploration capital spending.
Income Tax Expense
The ratio of current income tax expense to total income tax
expense is expected to increase from historical ratios in the
Canadian, International and U.S. jurisdictions as a result
of the reversal of book tax differences, initiation of
production in foreign locations and the exhaustion of
Alternative Minimum Tax credit carryforwards.
Commodity Prices
Commodity prices are impacted by many factors that are outside
of the Companys control. Historically, commodity prices
have been volatile and the Company expects them to remain that
way in the future. Commodity prices are affected by numerous
factors, including but not limited to, supply, market demands,
overall economic activity, weather, pipeline capacity
constraints, inventory storage levels, basis differentials and
other factors. As a result, the Company cannot accurately
predict future natural gas, NGLs and crude oil prices, and
therefore, it cannot determine what impact increases or
decreases in production volumes will have on future revenues or
net operating cash flows. However, based on average daily
natural gas production in 2004, the Company estimates that a
$0.10 per MCF change in natural gas prices would impact
annual natural gas revenues approximately $70 million.
Also, based on average daily crude oil production in 2004, the
Company estimates that a $1.00 per barrel change in crude
oil prices would impact annual crude oil revenues approximately
$31 million.
Potential Acquisitions
While it is difficult to predict future plans with respect to
acquisitions, the Company actively seeks acquisition
opportunities that build upon the Companys existing core
asset basins and conform to its Basin
Excellencesm
concept. Although the Company does not plan major acquisitions,
they play a large role in this industrys consolidation and
must be considered. Generally, acquisitions for the Company fall
into one of two categories: bolt-on transactions and other
acquisitions. Bolt-on transactions are usually relatively small
and involve acquiring properties and assets in areas where the
Company already controls a core position. Other acquisitions
tend to be transactions that involve the Company acquiring a
core position in an area where it either has no position or a
relatively small position. In either case, the purpose of
acquiring assets is to assist the Company in adding to its
existing inventory of future growth opportunities. Depending on
the commodity price environment at any given time, the property
acquisition market can be extremely competitive. Because of its
focus on sector-leading financial returns, the Company takes a
disciplined approach to property acquisitions, making it
difficult to predict the number and frequency of future
transactions.
Financial Condition and Liquidity
The Companys total debt to total capital (total capital is
defined as total debt and stockholders equity) ratio at
December 31, 2004 and December 31, 2003 was
36 percent and 41 percent, respectively. The
12 percent improvement in this ratio was attributable to
the Companys strong net income and the strength of the
Canadian currency partially offset by the repurchase of Common
Stock. Based on the current price environment, the Company
believes that it will generate sufficient cash from operating
activities to fund its 2005 capital expenditures, excluding any
potential major acquisition(s). At December 31, 2004, the
Company had $2,179 million of cash and cash equivalents on
hand, of which $1,200 million was located in Canada,
$696 million in the U.S. and $283 million in
19
International. The Company plans to repatriate $500 million
of eligible foreign earnings to the U.S. in 2005 under the
one-time provisions of the American Jobs Creation Act of 2004.
Burlington Resources Capital Trust I, Burlington Resources
Capital Trust II (collectively, the Trusts),
BR and Burlington Resources Finance Company
(BRFC) have a shelf registration statement of
$1,500 million on file with the Securities and Exchange
Commission (SEC). Pursuant to the registration
statement, BR may issue debt securities, shares of common
stock or preferred stock. In addition, BRFC may issue debt
securities and the Trusts may issue trust preferred securities.
Net proceeds, terms and pricing of offerings of securities
issued under the shelf registration statement will be determined
at the time of the offerings. BRFC and the Trusts are wholly
owned finance subsidiaries of BR and have no independent
assets or operations other than transferring funds to BRs
subsidiaries. Any debt issued by BRFC is fully and
unconditionally guaranteed by BR. Any trust preferred securities
issued by the Trusts are also fully and unconditionally
guaranteed by BR. In 2001, the Companys Board of Directors
authorized the Company to redeem, exchange or repurchase up to
an aggregate of $990 million principal amount of debt
securities.
The Company has a $1.5 billion revolving credit facility
(Credit Facility) that includes (i) a
US$500 million Canadian subfacility and (ii) a
US$750 million sublimit for the issuance of letters of
credit, including up to US$250 million in letters of credit
under the Canadian subfacility. The Credit Facility expires in
July 2009 unless extended. Under the covenants of the Credit
Facility, Company debt cannot exceed 60 percent of
capitalization (as defined in the agreements). The Credit
Facility is available to cover debt due within one year,
therefore commercial paper, credit facility notes and fixed-rate
debt due within one year are generally classified as long-term
debt. At December 31, 2004, there were no amounts
outstanding under the Credit Facility and no outstanding
commercial paper.
The Companys access to funds from its Credit Facility is
not restricted under any material adverse condition
clauses. These clauses typically remove the obligation of the
lenders to fund the credit line if any condition or event would
reasonably be expected to have a material and adverse effect on
the borrowers financial condition, operations or
properties considered as a whole, the borrowers ability to
make timely debt payments, or the enforceability of material
items of the credit agreement. While the Companys Credit
Facility includes a covenant that requires the Company to report
litigation or a proceeding that the Company has determined is
likely to have a material adverse effect on the consolidated
financial condition of the Company, the obligation of the
lenders to fund the Credit Facility is not conditioned on the
absence of such litigation or proceeding.
Net cash provided by operating activities in 2004 increased
$897 million and $1,887 million over 2003 and 2002,
respectively, primarily due to higher commodity prices and
higher production volumes partially offset by higher costs and
expenses, excluding non-cash expenses. Key drivers of net
operating cash flows are commodity prices, production volumes
and costs and expenses. Average natural gas prices increased
14 percent and 72 percent over 2003 and 2002,
respectively. Crude oil prices increased 33 percent and
50 percent over 2003 and 2002, respectively, while NGLs
prices increased 24 percent and 76 percent over the
same period. Production volumes increased 10 percent over
both 2003 and 2002. Although the Company believes that 2005
production volumes will exceed 2004 levels, it is unable to
predict future commodity prices, and as a result cannot provide
any assurance about future levels of net cash provided by
operating activities. Net cash provided by operating activities
in 2004 is not necessarily indicative of future cash flows from
operating activities. See page 19 for a discussion of
commodity prices.
The increase in net cash provided by operating activities
resulting from higher commodity prices and higher production
volumes were partially offset by higher costs and expenses. In
2004, costs and expenses that affect net operating cash provided
by operating activities primarily include operating costs, taxes
other than income taxes, transportation expense, and
administrative expenses. These costs and expenses increased
$281 million and $410 million over 2003 and 2002,
respectively. Operating costs and taxes other than income taxes
represented the largest increase in these costs. Operating costs
include well operating expenses, which are expenses incurred to
operate the Companys wells and equipment on producing
leases. The increase related to well operating expenses
accounted for 36 percent and 25 percent of the
increase in costs and expenses over 2003 and 2002, respectively.
Taxes other than income taxes include severance taxes, which are
directly correlated to crude oil and natural gas revenues. The
increase related to severance taxes accounted for
22 percent and 29 percent of the increase in costs and
expenses over 2003 and 2002, respectively. For revenue, price,
volume and costs and expense variances, see tables and
explanations on pages 27-29.
Generally, producing natural gas and crude oil reservoirs have
declining production rates. Production rates are impacted by
numerous factors, including but not limited to, geological,
geophysical and engineering matters, production curtailments and
restrictions, weather, market demands and the Companys
ability to replace depleting reserves. The Companys
inability to adequately replace reserves could result in a
decline in production volumes, one of the key drivers of
generating net operating cash flows. The Companys reserve
replacement ratio for the year ended December 31, 2004 was
125 percent and has averaged 142 percent over the last
three years. Results for any year are a function of the success
of the Companys drilling program and acquisitions. While
program results are difficult to predict, the Companys
current drilling inventory provides the Company opportunities to
replace its production in 2005.
20
The Company has various contractual obligations primarily
related to leases for office space, other property and equipment
and demand charges on firm transportation agreements for its
production of natural gas and crude oil. The Company expects to
fund these contractual obligations with cash generated from
operations. The following table summarizes the Companys
contractual obligations at December 31, 2004.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Payments Due by Period | |
| |
|
|
Less than | |
|
|
|
After | |
Contractual Obligations |
|
Total | |
|
1 Year | |
|
1-3 Years | |
|
4-5 Years | |
|
5 Years | |
| |
|
|
(In Millions) | |
| |
Total debt(1)
|
|
$ |
3,930 |
|
|
$ |
2 |
|
|
$ |
978 |
|
|
$ |
150 |
|
|
$ |
2,800 |
|
Interest payments on long-term debt
|
|
|
3,754 |
|
|
|
272 |
|
|
|
721 |
|
|
|
424 |
|
|
|
2,337 |
|
Transportation demand charges(2)
|
|
|
946 |
|
|
|
165 |
|
|
|
325 |
|
|
|
134 |
|
|
|
322 |
|
Non-cancellable operating leases(2)
|
|
|
288 |
|
|
|
30 |
|
|
|
84 |
|
|
|
58 |
|
|
|
116 |
|
Postretirement benefits(3)
|
|
|
29 |
|
|
|
3 |
|
|
|
9 |
|
|
|
6 |
|
|
|
11 |
|
Pension funding(3)
|
|
|
12 |
|
|
|
12 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Drilling rig commitments(2)
|
|
|
11 |
|
|
|
7 |
|
|
|
4 |
|
|
|
|
|
|
|
|
|
|
|
Total Contractual Obligations
|
|
$ |
8,970 |
|
|
$ |
491 |
|
|
$ |
2,121 |
|
|
$ |
772 |
|
|
$ |
5,586 |
|
|
|
|
(1) |
See Note 9 of Notes to Consolidated Financial Statements
for details of long-term debt. |
(2) |
See Note 14 of Notes to Consolidated Financial Statements
for discussion of these commitments. |
(3) |
See Note 13 of Notes to Consolidated Financial Statements
for discussion of the Companys benefit plans. The Company
expects to contribute $12 million to its U.S. pension
plans in 2005. |
The Company also has liabilities of $468 million related to
asset retirement obligations on its Consolidated Balance Sheet
at December 31, 2004. Due to the nature of these obligations,
the Company cannot determine precisely when the payments will be
made to settle these obligations. See Note 10 of Notes to
Consolidated Financial Statements.
Certain of the Companys contracts require the posting of
collateral upon request in the event that the Companys
long-term debt is rated below investment grade or ceases to be
rated. Those contracts primarily consist of hedging agreements
and two long-term natural gas transportation agreements. A few
of the hedging agreements also require posting of collateral if
the market value of the transactions thereunder exceed a
specified dollar threshold that varies with the Companys
credit rating. As of December 31, 2004, the Company has a
BBB+ long-term debt rating from Standard & Poors and
Baa1 Moodys Investors Service (Moodys)
rating. Investment grade is designated as all ratings above BB+
for Standard & Poors and Ba1 for Moodys.
While the mark-to-market positions under the hedging agreements
will fluctuate with commodity prices, as a producer, the
Companys liquidity exposure due to its outstanding
derivative instruments tends to increase when commodity prices
increase. Consequently, the Company is most likely to have its
largest unfavorable mark-to-market position in a high commodity
price environment when it is least likely that a credit support
requirement due to an adverse rating action would occur. At
December 31, 2004, the aggregate unfavorable mark-to-market
position under the aforementioned hedging agreements was
approximately $11 million. In the case of the Canadian
transportation agreements, the collateral required would be an
amount equal to 12 months of estimated demand charges. That
amount totaled approximately $34 million as of
December 31, 2004.
In the normal course of business, the Company has performance
obligations which are supported by surety bonds or letters of
credit. These obligations are primarily for site restoration and
dismantlement, royalty payment appeals and excise tax exemption
certifications where governmental organizations require such
support.
Changes in credit rating also impact the cost of borrowing under
the Companys Credit Facility, but have no impact on
availability of credit under the agreements.
In December 2000, the Companys Board of Directors
(Board) authorized the repurchase of up to
$1 billion of the Companys Common Stock. Through
April 30, 2003, the Company had repurchased
$816 million of its Common Stock under the program
authorized in December 2000. In April 2003, the Companys
Board voted to restore the authorization level to
$1 billion effective May 1, 2003. Through
December 7, 2004, the Company had repurchased
$712 million of its Common Stock under the program
authorized in April 2003. In December 2004, the Companys
Board again voted to restore the authorization level to
$1 billion.
During 2004, the Company repurchased approximately
14 million shares of its Common Stock for approximately
$522 million and, as of December 31, 2004, had
authority to repurchase an additional $952 million of its
Common Stock under the current authorization. As of
December 31, 2004, $8 million of the share repurchases
were not cash settled; however, $4 million related to 2003
repurchases were settled during the current year. Since December
2000, the
21
Company has repurchased approximately 61.8 million shares
of its Common Stock for $1.6 billion. Share amounts have
been adjusted to reflect the 2-for-1 stock split
(split) of the Companys Common Stock effective
June 1, 2004.
The Company has certain other commitments and uncertainties
related to its normal operations. Management believes that there
are no other commitments or uncertainties that will have a
material adverse effect on the consolidated financial position,
results of operations or cash flows of the Company.
Off-Balance Sheet Arrangements
The Company has off-balance sheet arrangements that it believes
have not and are not reasonably likely to have a material
current or future effect on the Companys results of
operations, financial condition, liquidity, capital expenditures
or capital resources. These off-balance sheet arrangements
consist of equity investments in two entities that the Company
accounts for under the equity method. The book values of the
Companys interests in Lost Creek Gathering Company, L.L.C.
(Lost Creek) and Evangeline Gas Pipeline Company
(Evangeline) are $19 million and
$2 million, respectively. As of December 31, 2004,
Lost Creek had outstanding debt totaling $42 million and
Evangeline had outstanding debt totaling $33 million. Lost
Creek and Evangelines debts are non-recourse to the
Company, and as a result, the Company has no legal
responsibility or obligation for these debts. Management
believes that Lost Creek and Evangeline are financially stable
and therefore will be in a position to repay their outstanding
debts.
Capital Expenditures and Resources
Capital expenditures were as follow.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2004 vs. 2003 | |
|
2004 vs. 2002 | |
|
|
|
|
|
|
|
|
| |
|
| |
|
|
|
|
|
|
|
|
|
|
(%) | |
|
|
|
(%) | |
|
|
|
|
|
|
|
|
Increase | |
|
Increase | |
|
Increase | |
|
Increase | |
Year Ended December 31, |
|
2004 | |
|
2003 | |
|
2002 | |
|
(Decrease) | |
|
(Decrease) | |
|
(Decrease) | |
|
(Decrease) | |
| |
|
|
($ In Millions) | |
| |
Oil and gas
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Development
|
|
$ |
1,273 |
|
|
$ |
1,056 |
|
|
$ |
779 |
|
|
$ |
217 |
|
|
|
21 |
% |
|
$ |
494 |
|
|
|
63 |
% |
|
Exploration
|
|
|
286 |
|
|
|
301 |
|
|
|
218 |
|
|
|
(15 |
) |
|
|
(5 |
) |
|
|
68 |
|
|
|
31 |
|
|
Acquisitions
|
|
|
85 |
|
|
|
228 |
|
|
|
604 |
|
|
|
(143 |
) |
|
|
(63 |
) |
|
|
(519 |
) |
|
|
(86 |
) |
|
|
|
Total oil and gas
|
|
|
1,644 |
|
|
|
1,585 |
|
|
|
1,601 |
|
|
|
59 |
|
|
|
4 |
|
|
|
43 |
|
|
|
3 |
|
|
Plants and pipelines
|
|
|
66 |
|
|
|
163 |
|
|
|
193 |
|
|
|
(97 |
) |
|
|
(60 |
) |
|
|
(127 |
) |
|
|
(66 |
) |
Administrative and other
|
|
|
37 |
|
|
|
40 |
|
|
|
43 |
|
|
|
(3 |
) |
|
|
(8 |
) |
|
|
(6 |
) |
|
|
(14 |
) |
|
|
|
Total capital expenditures
|
|
$ |
1,747 |
|
|
$ |
1,788 |
|
|
$ |
1,837 |
|
|
$ |
(41 |
) |
|
|
(2 |
)% |
|
$ |
(90 |
) |
|
|
(5 |
)% |
|
The Companys consolidated capital expenditures were down
2 percent and 5 percent compared to 2003 and 2002,
respectively. Excluding acquisitions, the Companys capital
spending related to internal development and exploration was up
15 and 56 percent compared to 2003 and 2002, respectively.
Capital expenditures in 2005, excluding proved property
acquisitions, are expected to be approximately $2 billion,
up 21 percent over 2004, primarily due to anticipated
higher project counts in major operating areas, increased
service costs, and higher foreign currency exchange rates,
particularly in Canada. The Company believes that 2005 estimated
spending is sufficient to add adequate reserves and achieve the
target of three to eight percent average annual production
growth. Capital expenditures in 2005 are expected to be
primarily for internal development and exploration of oil and
gas properties. Capital spending in 2005 related to internal
development and exploration is expected to be about
22 percent higher than 2004 and is expected to be funded
from internally generated cash flows.
During 2002, the Company sold a processing facility and other
non-core, non-strategic properties that consisted of high cost
structure, high production volume decline rates and limited
growth opportunities. As a result of these property sales, the
Company generated proceeds, before post closing adjustments, of
approximately $1.2 billion and recognized a net pretax gain
of $68 million. The producing properties that were sold
contributed approximately 230 MMCFE per day during 2002.
The Company used a portion of the proceeds generated from
property sales to retire debt and for general corporate purposes.
22
Marketing
North America (U.S. and Canada)
The Companys marketing strategy is to maximize the value
of its production by developing marketing flexibility from the
wellhead to its ultimate sale. The Companys natural gas
production is gathered, processed, exchanged and transported
utilizing various firm and interruptible contracts and routes to
access higher value market hubs. The Companys customers
include local distribution companies, electric utilities,
industrial users and marketers. The Company maintains the
capacity to ensure its production can be marketed either at the
wellhead or downstream at market sensitive prices.
All of the Companys crude oil production is sold to third
parties at the wellhead or transported to market hubs where it
is sold or exchanged. NGLs are typically sold at field plants or
transported to market hubs and sold to third parties. Downgrades
or the inability of the Companys customers to maintain
their credit rating or credit worthiness could result in an
increase in the allowance for unrecoverable receivables from
natural gas, NGLs or crude oil revenues or it could result in a
change in the Companys assumption process of evaluating
collectibility based on situations regarding specific customers
and applicable economic conditions.
International
The Companys International production is marketed to third
parties either directly by the Company or by the operators of
the properties. Production is sold at the platforms or various
sales points based on spot or contract prices.
Qualitative and Quantitative Disclosure About Market Risk
Commodity Risk
Substantially all of the Companys natural gas, NGLs and
crude oil production is sold on the spot market or under
short-term contracts at market sensitive prices. Spot market
prices for domestic natural gas and crude oil are subject to
volatile trading patterns in the commodity futures market,
including among others, the New York Mercantile Exchange
(NYMEX). Quality differentials, worldwide political
developments and the actions of the Organization of Petroleum
Exporting Countries also affect crude oil prices.
There is also a difference between the NYMEX futures contract
price for a particular month and the actual cash price received
for that month in a North America producing basin or at a North
America market hub, which is referred to as basis
differentials. Basis differentials can vary widely
depending on various factors, including but not limited to,
local supply and demand.
The Company utilizes over-the-counter price and basis swaps as
well as options to hedge its production in order to decrease its
price risk exposure. The gains and losses realized as a result
of these price and basis derivative transactions are
substantially offset when the hedged commodity is delivered. In
order to accommodate the needs of its customers, the Company
also uses price swaps to convert natural gas sold under
fixed-price contracts to market sensitive prices.
The Company recognizes all derivatives as either assets or
liabilities on the balance sheet and measures those instruments
at fair value. The requisite accounting for changes in the fair
value of a derivative depends on the intended use of the
derivative and the resulting designation.
The Company uses a sensitivity analysis technique to evaluate
the hypothetical effect that changes in the market value of
natural gas and crude oil may have on the fair value of the
Companys derivative instruments. For example, at
December 31, 2004, the potential decrease in fair value of
derivative instruments assuming a 10 percent adverse
movement (an increase in the underlying commodities prices)
would result in a $50 million decrease in the net
unrealized gain. The derivative instruments in place at
December 31, 2004 hedged approximately 15 percent of
the Companys expected natural gas production volumes
through 2005.
For purposes of calculating the hypothetical change in fair
value, the relevant variables include the type of commodity, the
commodity futures prices, the volatility of commodity prices and
the basis and quality differentials. The hypothetical change in
fair value is calculated by multiplying the difference between
the hypothetical price (adjusted for any basis or quality
differentials) and the contractual price by the contractual
volumes. As more fully described in Note 1 of Notes to
Consolidated Financial Statements, the Company periodically
assesses the effectiveness of its derivative instruments in
achieving offsetting cash flows attributable to the risks being
hedged. Changes in basis differentials or notional amounts of
the hedged transactions could cause the derivative instruments
to fail the effectiveness test and result in mark-to-market
accounting for the affected derivative transactions which would
be reflected in the Companys current period earnings.
23
Credit and Market Risks
The Company manages and controls market and counterparty credit
risk through a system of established internal controls and
procedures which are reviewed on a periodic basis. The Company
attempts to minimize credit risk exposure to counterparties
through formal credit policies and monitoring procedures as well
as the use of netting arrangements and requiring letters of
credit or parent guarantees, when necessary. Accounts receivable
are stated at historical value which approximates fair market
value on the Companys Consolidated Balance Sheet and no
single customer of the Company constitutes more than
11 percent of the Companys accounts receivable
balance at December 31, 2004. In the normal course of
business, collateral is not required for financial instruments
with credit risk. The fair value of the Companys
fixed-rate debt is subject to change based on changes in
interest rates. From time to time, the Company enters into
financial derivatives to manage this exposure. Based on
financial derivative transactions in place as of year-end 2004,
a 10 percent adverse move in interest rates (an increase in
the underlying interest rates) would result in less than a
$1 million increase in interest expense. Additionally, the
Company has cash investments that it manages based on internal
investment guidelines that emphasize liquidity and preservation
of capital, and such cash investments are stated at historical
cost which approximates fair market value on the Companys
Consolidated Balance Sheet.
Foreign Currency Risk
The Company has exposure to currency risk in certain of its
foreign subsidiaries where the functional currency is the U.S.
dollar and where some of the transactions are denominated in the
local currency. The Company monitors and manages its exposure to
foreign currency risk in these subsidiaries primarily by
balancing local currency monetary assets and liabilities. The
Company does not actively manage foreign currency risk in its
other foreign subsidiaries where the U.S. dollar is not the
functional currency, primarily Canada, since the majority of
transactions are denominated in the local currency. A
substantial amount of the Companys cash is located in
Canada, in Canadian dollars, which provides a natural hedge
against foreign currency risk. As of December 31, 2004, the
Company had no foreign currency financial derivatives.
Dividends
On January 26, 2005, the Board declared a Common Stock
quarterly cash dividend of $0.085 per share, payable
April 8, 2005 to shareholders of record on March 9,
2005. During the third quarter of 2004, the Company increased
its quarterly cash dividend from $0.075 to $0.085 per
share, representing a 13 percent increase. Dividend levels
are determined by the Board based on profitability, capital
expenditures, financing and other factors. The Company declared
and paid cash dividends on Common Stock totaling approximately
$125 million and $122 million, respectively, during
2004.
On January 21, 2004, the Companys Board approved a
2-for-1 split of the Companys Common Stock in the form of
a share distribution, subject to shareholder approval of an
amendment to the Companys Certificate of Incorporation to
increase the number of authorized shares from 325 million
to 650 million. On April 21, 2004, the Companys
shareholders approved the amendment. As a result, the split was
paid in the form of a share distribution on June 1, 2004 to
shareholders of record on May 5, 2004.
Application of Critical Accounting Policies
Oil and Gas Reserves
The Companys estimate of proved reserves reflects
quantities of natural gas, NGLs and crude oil which geological
and engineering data demonstrate, with reasonable certainty, to
be recoverable in future years from known reservoirs under
existing economic conditions. The process of estimating
quantities of natural gas, NGLs and crude oil reserves requires
judgment in the evaluation of all available geological,
geophysical, engineering and economic data, including production
data, reservoir pressure data and data collected as a result of
development or exploration drilling. Economic and operating
conditions, such as product prices, the availability of
additional development capital, operating costs, development
costs, production tax rates, the installation of additional
infrastructure, regulatory approval and actions of domestic or
foreign governments influence the estimation of reserves. Any
significant variance in these assumptions could materially
affect the estimated quantity and value of the Companys
reserves.
The Company has policies and procedures through which the
required engineering, geological, and economic data is gathered
and proved reserves are estimated. Experienced and qualified
Company engineers prepare the reserve estimates. These estimates
are subjected to a series of internal reviews to ensure that
they are technically and legally justified and therefore
reasonable, prepared using generally accepted principles and
practices, and comply with SEC Regulations. A corporate staff of
engineers conducts oversight and audit of the reserve estimates.
Furthermore, the reserve maintenance process requires review and
approval of every change to the proved reserve ledger, the most
significant requiring approval by the Companys Chief
Engineer.
24
The Company also engages independent oil and gas engineering
consulting firms to review its proved reserves base. The firms
determine both the specific properties reviewed and the
aggregate magnitude they require for review. Typically, at least
80 percent of the estimated proved reserves receive
external review. The Companys reserve estimates during
2002, 2003, and 2004 were subjected to this external review by
the independent oil and gas consultants, who in their judgment
determined the estimates to be reasonable in the aggregate. At
the conclusion of their external review, the audit firms issue a
written opinion and present their findings to the members of the
Board of Directors Audit Committee. For more information,
see the independent oil and gas consultants letters on
pages 69-73.
Despite the inherent imprecision in these engineering estimates,
the Companys reserves are used throughout its financial
statements. As described in Note 1 of Notes to Consolidated
Financial Statements, the Company uses the unit-of-production
method to amortize its oil and gas properties. Changes in
reserve quantities as described above will cause corresponding
changes in depletion expense in periods subsequent to the
quantity revision or, in some cases, an impairment charge in the
period of the revision. Although revisions to reserve estimates
in previous years have averaged less than one percent, a five
percent negative or adverse revision to the Companys
consolidated proved reserves would result in an increase in
annual DD&A expense of approximately $66 million. See
the Supplementary Financial Information for reserve data.
Successful Efforts Method of Accounting
The Company accounts for its oil and gas properties using the
successful efforts method of accounting. Acquisition and
development costs are capitalized and amortized using the
unit-of-production method based on total proved and proved
developed reserves, respectively, estimated by the
Companys reserve engineers. Changes in reserve quantities
as described above will cause corresponding changes in depletion
expense in periods subsequent to the quantity revision.
Unsuccessful exploration or dry hole wells are expensed in the
period in which the wells are determined to be dry and could
have a significant effect on results of operations.
Carrying Value of Long-lived Assets
As more fully described in Note 1 of Notes to Consolidated
Financial Statements, the Company performs an impairment
analysis on its proved properties whenever events or changes in
circumstances indicate an assets carrying amount may not
be recoverable and annually for the Companys unproved
reserves. Cash flows used in the impairment analysis are
determined based upon managements estimates of proved
natural gas, NGLs and crude oil reserves, future natural gas,
NGLs and crude oil prices and costs to extract these reserves.
Downward revisions in estimated reserve quantities, increases in
future cost estimates or depressed natural gas, NGLs and crude
oil prices could cause the Company to reduce the carrying
amounts of its properties. The estimated prices used in the cash
flow analysis are determined by management based on forward
price curves for the related commodities, adjusted for average
historical location and quality differentials. Because natural
gas, NGLs and crude oil prices are volatile, these estimates are
inherently imprecise. A five percent negative or adverse
revision to the Companys proved reserves combined with a
10 percent decline in the natural gas price used to
identify fields that are potentially impaired would have
resulted in a pretax impairment charge of approximately
$105 million ($70 million after tax) for the year
ended December 31, 2004. See Note 16 of Notes to
Consolidated Financial Statements for impairment of oil and gas
properties.
The Companys lease acquisition costs are not subject to
the impairment analysis described above, however, a portion of
the costs associated with such properties is subject to
amortization on a composite basis based on past experience and
average property lives. On an annual basis, the Company monitors
the estimated success rate used to determine the amount of lease
acquisition costs that are not subject to amortization and makes
an adjustment, if needed. Typically, these adjustments do not
have a significant impact on future amortization. As these
properties are developed and reserves are proven, the remaining
capitalized costs are subject to depletion. If the development
of these properties is deemed unsuccessful, the capitalized
costs related to the unsuccessful activity are expensed in the
period the determination is made. The rate at which the unproved
properties are written off depends on the timing and success of
the Companys future exploration program.
Asset Retirement Obligations (ARO)
The Company has significant obligations to plug and abandon
natural gas and crude oil wells and related equipment as well as
to dismantle and abandon plants at the end of oil and gas
production operations. The Company records the fair value of a
liability for ARO in the period in which it is incurred and a
corresponding increase in the carrying amount of the related
asset. Subsequently, the asset retirement costs included in the
carrying amount of the related asset are allocated to expense
using a systematic and rational method. In addition, increases
in the discounted ARO liability resulting from the passage of
time are reflected as additional depreciation, depletion and
amortization expense in the Consolidated Statement of Income.
Estimating the future ARO requires management to make estimates
and judgments regarding timing, existence of a liability, as
well as what constitutes adequate restoration. The Company uses
the present value of estimated cash flows related to its ARO to
determine the fair value. The present value calculation includes
numerous assumptions and
25
judgments including the ultimate costs, inflation factors,
credit adjusted discount rates, timing of settlement, and
changes in the legal, regulatory, environmental and political
environments. Abandonment cost estimates are determined by the
Companys reserve engineers based on actual costs incurred
to abandon similar wells, and their knowledge of the respective
wells. The Company has been unable to determine the accuracy of
these estimates due to the limited amount of abandonment
activity since the adoption of SFAS No. 143. The
Company uses an inflation factor determined by analyzing an
industry specific price index that it updates annually. Timing
of settlement is based on reserve estimates and is subject to
the same inherent imprecision described above for oil and gas
reserves. To the extent future revisions to these assumptions
impact the present value of the existing ARO liability, a
corresponding adjustment is made to the related asset. A five
percent increase in the Company consolidated ARO would result in
a $23 million increase in the Companys obligation and
a $1.5 million increase in annual accretion expense.
Goodwill
As required, the Company performs an annual impairment
assessment in lieu of periodic amortization of goodwill. The
impairment assessment requires management to make estimates
regarding the fair value of the reporting unit to which goodwill
has been assigned. The Company determined the fair value of its
Canadian reporting unit using a combination of the income
approach and the market approach. Under the income approach, the
Company estimated the fair value of the reporting unit based on
the present value of expected future cash flows. Under the
market approach, the Company estimated the fair value based on
market multiples of reserves and production for comparable
companies.
The income approach is dependent on a number of factors
including estimates of forecasted revenue and costs, proved
reserves, as well as the success of future exploration for and
development of unproved reserves, appropriate discount rates and
other variables. Downward revisions of estimated reserve
quantities, increases in future cost estimates, divestiture of a
significant component of the reporting unit, continued weakening
of the U.S. dollar or depressed natural gas, NGLs and crude
oil prices could lead to an impairment of all or a portion of
goodwill in future periods. In the market approach, the Company
makes certain judgments about the selection of comparable
companies, comparable recent company and asset transactions and
transaction premiums. Although the Company based its fair value
estimate on assumptions it believes to be reasonable, those
assumptions are inherently unpredictable and uncertain. In 2004,
the Company used a professional valuation services firm to
assist in preparing its annual valuation of goodwill. At
December 31, 2004, the fair value of the Canadian reporting
unit exceeded its carrying amount and the use of other
reasonable assumptions would not have changed the outcome of the
impairment test.
Revenue Recognition
Natural gas, NGLs and crude oil revenues are recorded using the
entitlement method. Under the entitlement method, revenue is
recorded when title passes based on the Companys net
interest. The Company records its entitled share of revenues
based on entitled volumes and contracted sales prices. The sales
prices for natural gas, NGLs and crude oil are adjusted for
transportation costs and other related deductions. The
transportation costs and other deductions are based on
contractual or historical data and do not require significant
judgment. Subsequently, these deductions and transportation
costs are adjusted to reflect actual charges based on
third-party documents. Historically, these adjustments have been
insignificant. Since there is a ready market for natural gas,
crude oil and NGLs, the Company sells the majority of its
products soon after production at various locations at which
time title and risk of loss pass to the buyer.
Legal, Environmental and Other Contingencies
A provision for legal, environmental and other contingencies is
charged to expense when the loss is probable and the cost can be
reasonably estimated. Determining when expenses should be
recorded for these contingencies and the appropriate amounts for
accrual is an estimation process that includes the subjective
judgment of management. In many cases, managements
judgment is based on the advice and opinions of legal counsel
and other advisers, the interpretation of laws and regulations,
which can be interpreted differently by regulators and/or courts
of law, the experience of the Company and other companies in
dealing with similar matters, and the decision of management on
how it intends to respond to a particular contingency (for
example, a decision to contest a matter vigorously or a decision
to seek a negotiated settlement). The Companys management
closely monitors known and potential legal, environmental and
other contingencies and periodically determines when the Company
should record losses for these items based on information
available to the Company.
Results of Operations
Year Ended December 31, 2004 Compared With Year Ended
December 31, 2003
The Companys consolidated net income increased
$326 million or $0.86 diluted earnings per common share
(per share) in 2004 primarily due to higher
commodity prices and higher production volumes. Net income in
2004 and 2003 included charges, net of taxes, of
$59 million or $0.15 per share and $38 million or
$0.09 per share, respectively,
26
related to the impairment of oil and gas properties primarily in
Canada. Net income in 2004 and 2003 included income tax benefits
of $23 million or $0.06 per share and $203 million or
$0.51 per share, respectively, related to the reduction of the
Canadian federal income tax rate. Net income in 2004 and 2003
also included income tax benefits of $45 million or $0.11
per share and $11 million or $0.02 per share, respectively,
related to the reduction of the Alberta provincial corporate
income tax rate. In 2004, the Company recorded a
U.S. income tax expense of $26 million or
$0.07 per share related to the planned repatriation of
$500 million of eligible foreign earnings to the U.S. under
the one-time provisions of the American Jobs Creation Act of
2004. Net income in 2003 also included a net-of-tax cumulative
effect of change in accounting principle charge of
$59 million or $0.15 per share related to the adoption of
SFAS No. 143, Asset Retirement Obligations. See
Note 10 of Notes to Consolidated Financial Statements for
more information. Per share amounts for 2003 have been
retroactively adjusted to reflect the 2-for-1 split of the
Companys Common Stock effective June 1, 2004.
Below is a discussion of prices, volumes and revenue variances.
Price and Volume Variances
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2004 vs. 2003 | |
|
|
|
|
|
|
| |
|
|
|
|
|
|
|
|
(%) | |
|
|
Year Ended December 31, |
|
2004 | |
|
2003 | |
|
Increase | |
|
Increase | |
|
Increase | |
| |
|
|
(In Millions) | |
| |
Price Variance
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas sales prices (per MCF)
|
|
$ |
5.49 |
|
|
$ |
4.83 |
|
|
$ |
0.66 |
|
|
|
14 |
% |
|
$ |
462 |
|
|
NGLs sales prices (per Bbl)
|
|
|
25.38 |
|
|
|
20.40 |
|
|
|
4.98 |
|
|
|
24 |
|
|
|
119 |
|
|
Crude oil sales prices (per Bbl)
|
|
$ |
36.25 |
|
|
$ |
27.22 |
|
|
$ |
9.03 |
|
|
|
33 |
% |
|
|
282 |
|
|
|
|
Total price variance
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
863 |
|
|
Volume Variance
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas sales volumes (MMCF per day)
|
|
|
1,914 |
|
|
|
1,899 |
|
|
|
15 |
|
|
|
1 |
% |
|
$ |
35 |
|
|
NGLs sales volumes (MBbls per day)
|
|
|
65.3 |
|
|
|
64.8 |
|
|
|
0.5 |
|
|
|
1 |
|
|
|
5 |
|
|
Crude oil sales volumes (MBbls per day)
|
|
|
85.2 |
|
|
|
46.5 |
|
|
|
38.7 |
|
|
|
83 |
% |
|
|
387 |
|
|
|
|
Total volume variance
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
427 |
|
|
Revenue Variances
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2004 vs. 2003 | |
|
|
|
|
|
|
| |
|
|
|
|
|
|
|
|
% | |
|
|
|
|
|
|
Increase | |
|
Increase | |
Year Ended December 31, |
|
2004 | |
|
2003 | |
|
(Decrease) | |
|
(Decrease) | |
| |
|
|
($ In Millions) | |
| |
Natural gas
|
|
$ |
3,847 |
|
|
$ |
3,331 |
|
|
$ |
516 |
|
|
|
15 |
% |
NGLs
|
|
|
606 |
|
|
|
482 |
|
|
|
124 |
|
|
|
26 |
|
Crude oil
|
|
|
1,131 |
|
|
|
462 |
|
|
|
669 |
|
|
|
145 |
|
Processing and other
|
|
|
34 |
|
|
|
36 |
|
|
|
(2 |
) |
|
|
(6 |
) |
|
|
Total revenues
|
|
$ |
5,618 |
|
|
$ |
4,311 |
|
|
$ |
1,307 |
|
|
|
30 |
% |
|
Revenues
The Companys consolidated revenues increased
$1,307 million in 2004. Higher revenues were primarily due
to higher commodity prices and higher production volumes,
resulting in increased revenues of $863 million and
$427 million, respectively. Revenue variances related to
commodity prices and sales volumes are described below.
Price Variances
Commodity prices are one of the key drivers of earnings
generation and net operating cash flow for the Company. Higher
commodity prices contributed $863 million to the increase
in revenues in 2004. Average natural gas prices, including a
$0.01 realized loss per MCF related to hedging activities,
increased $0.66 per MCF during 2004, resulting in increased
revenues of $462 million. Average crude oil prices,
including a $0.99 realized loss per barrel related to hedging
activities, increased $9.03 per barrel in 2004, resulting
in increased revenues of $282 million. Average NGLs
27
prices increased $4.98 per barrel in 2004, resulting in
higher revenues of $119 million. As discussed on
page 19, commodity prices are affected by many factors that
are outside of the Companys control. Therefore, commodity
prices received by the Company during 2004 are not necessarily
indicative of prices it may receive in the future. Depressed
commodity prices over a significant period of time would result
in reduced cash from operating activities potentially causing
the Company to expend less on its capital program. Lower
spending on the capital program could result in a reduction of
the amount of production volumes the Company is able to produce.
The Company cannot accurately predict future commodity prices,
and cannot be certain whether these events will occur.
Volume Variances
Sales volumes are another key driver that impact the
Companys earnings and net operating cash flow. Higher
sales volumes in 2004 resulted in increased revenues of
$427 million. Average crude oil sales volumes increased
38.7 MBbls per day in 2004, resulting in increased revenues
of $387 million. The increase in crude oil sales volumes
was primarily due to higher production from Internationals
new project start-ups in late 2003 from fields in offshore
China, Algeria and Ecuador, which contributed increased
production of 17.9 MBbls per day, 8.6 MBbls per day
and 3.9 MBbls per day, respectively, in 2004. Production
from the U.S. Cedar Creek Anticline increased
6.6 MBbls per day and the Bakken Shale increased
1.5 MBbls per day in 2004.
Average natural gas sales volumes increased 15 MMCF per day
in 2004, resulting in increased revenues of $35 million.
Average natural gas sales volumes increased primarily due to
higher production from the Madden Field, CLAM in the Dutch
sector of the North Sea, and south Louisiana, which contributed
increased production of 31 MMCF per day, 29 MMCF per
day and 6 MMCF per day, respectively, in 2004. These
increases were partially offset by lower production volumes in
Canada of 48 MMCF per day. Production volumes in Canada
were down primarily due to higher service costs and the Canadian
dollar strengthening against the U.S. dollar that led to
fewer net wells drilled in 2004 versus 2003, unfavorable weather
conditions that impacted program execution during 2004 and lower
than expected new well productivity in certain areas. Average
NGLs sales volumes increased 0.5 MBbls per day in 2004,
resulting in higher revenues of $5 million over 2003.
The Company has a goal to achieve between three and eight
percent average annual production growth; therefore, future
production volumes are expected to increase over the current
period. See discussion under Outlook on page 18
for guidance on production volumes. As mentioned above,
depressed prices over an extended period of time or other
unforeseen events could occur that would result in the Company
being unable to sustain a capital program that allows it to meet
its production growth goals. However, the Company cannot predict
whether such events will occur.
Below is a discussion of total costs and other incomenet.
Total Costs and Other Income Net
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2004 vs. | |
|
|
|
|
|
|
|
|
2003 | |
|
|
|
|
|
|
|
|
| |
|
|
|
|
|
|
|
|
% | |
|
|
|
|
|
|
Increase | |
|
Increase | |
Year Ended December 31, |
|
2004 | |
|
2003 | |
|
(Decrease) | |
|
(Decrease) | |
| |
|
|
($ In Millions) | |
| |
Costs and other income net
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Taxes other than income taxes
|
|
$ |
260 |
|
|
$ |
187 |
|
|
$ |
73 |
|
|
|
39 |
% |
|
Transportation expense
|
|
|
453 |
|
|
|
408 |
|
|
|
45 |
|
|
|
11 |
|
|
Operating costs
|
|
|
587 |
|
|
|
475 |
|
|
|
112 |
|
|
|
24 |
|
|
Depreciation, depletion and amortization
|
|
|
1,137 |
|
|
|
927 |
|
|
|
210 |
|
|
|
23 |
|
|
Exploration costs
|
|
|
258 |
|
|
|
252 |
|
|
|
6 |
|
|
|
2 |
|
|
Impairment of oil and gas properties
|
|
|
90 |
|
|
|
63 |
|
|
|
27 |
|
|
|
43 |
|
|
Administrative
|
|
|
215 |
|
|
|
164 |
|
|
|
51 |
|
|
|
31 |
|
|
Interest expense
|
|
|
282 |
|
|
|
260 |
|
|
|
22 |
|
|
|
8 |
|
|
(Gain)/loss on disposal of assets
|
|
|
13 |
|
|
|
(8 |
) |
|
|
(21 |
) |
|
|
(263 |
) |
|
Other expense (income) net
|
|
|
19 |
|
|
|
13 |
|
|
|
6 |
|
|
|
46 |
|
|
|
|
Total costs and other income net
|
|
$ |
3,314 |
|
|
$ |
2,741 |
|
|
$ |
573 |
|
|
|
21 |
% |
|
Total costs and other incomenet increased
$573 million in 2004. This increase in total costs and
other incomenet was primarily due to the items discussed
below. The increase in the exchange rate in Canada during 2004
impacted certain costs and expenses for the Company. Changes in
the value of the Canadian dollar versus the U.S. dollar
could impact costs and expenses in future years. However, at
this time, the Company cannot predict what impact the
28
Canadian exchange rate will have on costs and expenses in the
future. See discussion under Outlook on page 18
for guidance on costs and expenses in 2005.
DD&A expense increased $210 million primarily due to
higher production and higher unit-of-production rates on
International properties and higher unit-of-production rates on
Canadian properties. Operating costs increased $112 million
compared to 2003. This increase is primarily due to higher well
operating expenses, which include direct expenses incurred to
operate the Companys wells and equipment on producing
leases. Well operating expenses were higher primarily due to
increased repair and maintenance expenses, higher workover
activity and changes in exchange rates.
Taxes other than income taxes increased $73 million
primarily due to higher production taxes resulting from higher
crude oil and natural gas revenues. Taxes other than income
taxes include severance taxes which are directly correlated to
natural gas and crude oil revenues. Administrative expense
increased $51 million primarily due to higher stock-based
compensation expense, excluding stock options, related to a
higher stock price for the Company and higher legal expenses.
Transportation expense increased $45 million primarily due
to operations related to new start-up projects in late 2003 in
International operations and higher rates in Canada. Interest
expense increased $22 million primarily due to no
capitalized interest incurred on capital projects in 2004.
The Company performs an impairment analysis annually for
unproved reserves or whenever events or changes in circumstances
indicate an assets carrying amount may not be recoverable.
Cash flows used in the impairment analysis are determined based
upon managements estimates of natural gas, NGLs and crude
oil reserves, future natural gas, NGLs and crude oil prices and
costs to extract these reserves. In 2004 and 2003, the Company
recorded non-cash charges of $90 million and
$63 million, respectively, related to the impairment of oil
and gas properties. The impairments in 2004 and 2003 were
related to undeveloped properties in Canada and
performance-related downward reserve adjustments, also primarily
in Canada, respectively.
Exploration costs increased $6 million due to higher
geological and geophysical (G&G) and other
expenses of $20 million partially offset by lower
amortization of undeveloped lease costs of $10 million and
lower exploratory dry hole costs of $4 million. Exploration
expense fluctuates from period to period primarily due to the
amount the Company expends on its exploration capital program
and its success rate; however, the success rate is difficult to
predict. Of the exploratory wells drilled by the Company in
2004, 2003 and 2002, the Company experienced a success rate in
the range of approximately 50 to 66 percent during that
period of time. These success rates are not necessarily
indicative of future rates. The Company capitalizes costs
incurred to drill exploratory wells pending determination of
whether the wells have found an adequate amount of economically
recoverable reserves to be classified as proved. When a
determination cannot be made at the time drilling is completed,
the costs are deferred until a determination can be made. At
December 31, 2004, $23 million of deferred exploration
costs were included in oil and gas properties on the
Companys Consolidated Balance Sheet. Some or all of these
costs could be included in exploration expense in future
periods. In 2004 and 2003, $14 million and $7 million,
respectively, were reclassified from oil and gas properties to
exploration expense.
Income Tax Expense
Income tax expense increased $467 million in 2004,
primarily due to an increase in pretax income of
$734 million. In 2004, the Company recorded
$26 million of U.S. income tax expense related to its
plan to repatriate $500 million of eligible foreign
earnings under the one-time provisions of the American Job
Creation Act of 2004. In addition, income taxes on foreign
earnings in excess of the U.S. tax rate resulted in an
increase in tax expense of $19 million in 2004. The
reduction of the Canadian federal income tax rate resulted in an
income tax benefit of $45 million in 2004 compared to a
benefit of $203 million in 2003. The reduction of the
Alberta provincial corporate income tax rate resulted in an
income tax benefit of $23 million in 2004 compared to a
benefit of $11 million in 2003. The Company also recorded a
net tax benefit of $10 million in 2004 related to the
settlement of the 1999-2000 audits of its Section 29 Tax
Credits, and recorded a net tax benefit of $27 million in
2003 related to the settlements of the 1996-1998 audits of its
Section 29 Tax Credits. As a result of the increase in
exchange rates, the Company recorded higher tax benefits of
$7 million related to interest deductions allowed in both
the U.S. and Canada on transactions associated with cross-border
financing. The deduction for interest on the cross-border
financing is allowable in both the U.S. and Canada because the
issuer of the debt is a wholly-owned finance subsidiary of the
Company and the activities of the finance subsidiary are taxable
in both the U.S. and Canada. Substantially all of the increase
in the tax benefit of the cross-border financing deduction from
2003 to 2004 was due to the strengthening of the Canadian
dollar. This benefit is not expected to fluctuate in the future
for reasons other than changes in exchange rate and debt levels.
Year Ended December 31, 2003 Compared With Year Ended
December 31, 2002
The Companys consolidated net income increased
$747 million or $1.87 per share in 2003 primarily due to
higher commodity prices. Net income in 2003 included tax
benefits of $203 million or $0.51 per share and
$11 million or $0.02 per share related to the
reduction of the Canadian federal income tax and the Alberta
provincial corporate income tax rates, respectively. Net income
in 2002 included a tax benefit of $26 million or $0.06 per
share related to the reduction of the Alberta provincial
corporate income tax rate in Canada and the reversal of a tax
valuation reserve of
29
$27 million or $0.07 per share related to the sale of
assets in the United Kingdom (U.K.) sector of the
North Sea. Per share amounts for 2003 and 2002 have been
retroactively adjusted to reflect the 2-for-1 split of the
Companys Common Stock effective June 1, 2004.
Below is a discussion of prices, volumes and revenue variances.
Price and Volume Variances
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2003 vs. 2002 | |
|
|
|
|
|
|
|
|
| |
|
|
|
|
|
|
|
|
(%) | |
|
|
|
|
|
|
|
|
Increase | |
|
Increase | |
|
Increase | |
Year Ended December 31, |
|
2003 | |
|
2002 | |
|
(Decrease) | |
|
(Decrease) | |
|
(Decrease) | |
| |
|
|
(In Millions) | |
| |
Price Variance
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas sales prices (per MCF)
|
|
$ |
4.83 |
|
|
$ |
3.20 |
|
|
$ |
1.63 |
|
|
|
51 |
% |
|
$ |
1,129 |
|
|
NGLs sales prices (per Bbl)
|
|
|
20.40 |
|
|
|
14.46 |
|
|
|
5.94 |
|
|
|
41 |
|
|
|
140 |
|
|
Crude oil sales prices (per Bbl)
|
|
$ |
27.22 |
|
|
$ |
24.11 |
|
|
$ |
3.11 |
|
|
|
13 |
% |
|
|
53 |
|
|
|
|
Total price variance
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
1,322 |
|
|
Volume Variance
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas sales volumes (MMCF per day)
|
|
|
1,899 |
|
|
|
1,916 |
|
|
|
(17 |
) |
|
|
(1 |
)% |
|
$ |
(20 |
) |
|
NGLs sales volumes (MBbls per day)
|
|
|
64.8 |
|
|
|
60.1 |
|
|
|
4.7 |
|
|
|
8 |
|
|
|
25 |
|
|
Crude oil sales volumes (MBbls per day)
|
|
|
46.5 |
|
|
|
49.1 |
|
|
|
(2.6 |
) |
|
|
(5 |
)% |
|
|
(23 |
) |
|
|
|
Total volume variance
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
(18 |
) |
|
Revenue Variances
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2003 vs. 2002 | |
|
|
|
|
|
|
| |
|
|
|
|
|
|
|
|
% | |
Year Ended December 31, |
|
2003 | |
|
2002 | |
|
Increase | |
|
Increase | |
| |
|
|
($ In Millions) | |
| |
Natural gas
|
|
$ |
3,331 |
|
|
$ |
2,209 |
|
|
$ |
1,122 |
|
|
|
51 |
% |
NGLs
|
|
|
482 |
|
|
|
317 |
|
|
|
165 |
|
|
|
52 |
|
Crude oil
|
|
|
462 |
|
|
|
432 |
|
|
|
30 |
|
|
|
7 |
|
Processing and other
|
|
|
36 |
|
|
|
10 |
|
|
|
26 |
|
|
|
260 |
|
|
|
Total revenues
|
|
$ |
4,311 |
|
|
$ |
2,968 |
|
|
$ |
1,343 |
|
|
|
45 |
% |
|
Revenues
The Companys consolidated revenues increased
$1,343 million in 2003. Higher revenues were primarily due
to higher commodity prices, resulting in increased revenues of
$1,322 million. Revenues also increased $26 million
due to higher processing and other revenues. Processing and
other revenues increased $20 million and $19 million,
respectively, due to ineffectiveness of cash-flow and fair-value
hedges and changes in fair value instruments that do not qualify
for hedge accounting. The amounts were partially offset by a
decrease of $18 million related to lower sales volumes and
$19 million related to the sale of a processing facility in
June 2002. The revenue variances related to commodity prices and
sales volumes are described below.
Price Variances
Commodity prices are one of the key drivers of earnings and net
operating cash flow generation. Higher commodity prices
contributed $1,322 million to the increase in revenues in
2003. Average natural gas prices, including a $0.09 realized
loss per MCF related to hedging activities, increased
$1.63 per MCF in 2003 resulting in increased revenues of
$1,129 million. Average NGLs prices increased
$5.94 per barrel in 2003, resulting in higher revenues of
$140 million. Average crude oil prices, including a $0.09
realized loss per barrel related to hedging activities,
increased $3.11 per barrel in 2003, resulting in increased
revenues of $53 million. See page 19 for a discussion
of commodity prices.
Volume Variances
Sales volumes are another key driver that impact the
Companys earnings and net operating cash flow generation.
Lower sales volumes in 2003 resulted in a decline in revenues of
$18 million. Average crude oil sales volumes
30
decreased 2.6 MBbls per day in 2003, reducing revenues
$23 million. Average crude oil sales volumes decreased
13.8 MBbls per day primarily due to asset sales in 2002 in
the Gulf of Mexico, Canada, the U.K. sector of the North Sea and
the Williston Basin. This decrease in crude oil sales volumes
was partially offset by an increase of 10.8 MBbls per day
resulting from higher production at Ourhoud Field and the
Company-operated MLN Field in Algeria, south Louisiana and Cedar
Creek. Average natural gas sales volumes decreased 17 MMCF
per day in 2003, resulting in decreased revenues of
$20 million. Average natural gas sales volumes decreased
108 MMCF per day primarily due to asset sales in 2002 in
the Gulf of Mexico, the U.K. sector of the North Sea and Sonora.
This decrease in natural gas sales volumes was partially offset
by an increase of 93 MMCF per day primarily as a result of
the drilling programs in Canada and the Fort Worth Basin.
Average NGLs sales volumes increased 4.7 MBbls per day in
2003, resulting in higher revenues of $25 million year over
year. Average NGLs sales volumes increased 4.8 MBbls per
day in the San Juan Basin and the Fort Worth Basin.
Below is a discussion of total costs and other income net.
Total Costs and Other Income Net
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2003 vs. 2002 | |
|
|
|
|
|
|
| |
|
|
|
|
|
|
|
|
% | |
|
|
|
|
|
|
Increase | |
|
Increase | |
Year Ended December 31, |
|
2003 | |
|
2002 | |
|
(Decrease) | |
|
(Decrease) | |
|
|
|
($ In Millions) |
|
Costs and other incomenet
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Taxes other than income taxes
|
|
$ |
187 |
|
|
$ |
123 |
|
|
$ |
64 |
|
|
|
52 |
% |
|
Transportation expense
|
|
|
408 |
|
|
|
354 |
|
|
|
54 |
|
|
|
15 |
|
|
Operating costs
|
|
|
475 |
|
|
|
467 |
|
|
|
8 |
|
|
|
2 |
|
|
Depreciation, depletion and amortization
|
|
|
927 |
|
|
|
833 |
|
|
|
94 |
|
|
|
11 |
|
|
Exploration costs
|
|
|
252 |
|
|
|
286 |
|
|
|
(34 |
) |
|
|
(12 |
) |
|
Impairment of oil and gas properties
|
|
|
63 |
|
|
|
|
|
|
|
63 |
|
|
|
|
|
|
Administrative
|
|
|
164 |
|
|
|
161 |
|
|
|
3 |
|
|
|
2 |
|
|
Interest expense
|
|
|
260 |
|
|
|
274 |
|
|
|
(14 |
) |
|
|
(5 |
) |
|
Gain on disposal of assets
|
|
|
(8 |
) |
|
|
(68 |
) |
|
|
(60 |
) |
|
|
(88 |
) |
|
Other expense (income)net
|
|
|
13 |
|
|
|
(31 |
) |
|
|
(44 |
) |
|
|
(142 |
) |
|
|
|
Total costs and other incomenet
|
|
$ |
2,741 |
|
|
$ |
2,399 |
|
|
$ |
342 |
|
|
|
14 |
% |
|
Total costs and other incomenet increased
$342 million in 2003. This increase in total costs and
other income net was primarily due to items discussed
below. The increase in the exchange rate in Canada during 2003
impacted certain costs and expenses for the Company. Changes in
the value of the Canadian dollar versus the U.S. dollar
could impact costs and expenses in future years. However, at
this time, the Company cannot predict what impact the Canadian
exchange rate will have on costs and expenses in the future.
DD&A expense increased $94 million primarily due to
higher unit-of-production rates on the Canadian properties which
have higher rates than average unit-of-production rates for the
Company partially offset by the divestiture of higher cost
properties in 2002 and lower crude oil and natural gas
production volumes. Taxes other than income taxes increased
$64 million primarily due to higher production taxes
resulting from higher crude oil and natural gas revenues.
The Company performs an impairment analysis annually for
unproved reserves or whenever events or changes in circumstances
indicate an assets carrying amount may not be recoverable.
Cash flows used in the impairment analysis are determined based
upon managements estimates of natural gas, NGLs and crude
oil reserves, future natural gas, NGLs and crude oil prices and
costs to extract these reserves. In 2003, the Company recorded
charges of $63 million related to the impairment of oil and
gas properties due to performance-related downward reserve
adjustments associated with certain properties primarily in
Canada.
Gain on disposal of assets decreased $60 million primarily
due to the divestiture program that was announced by the Company
in late 2001 and completed in late 2002. Transportation expense
increased $54 million primarily due to higher contract
rates primarily resulting from the sale of a processing facility
in 2002. Other expense(income) net increased
$44 million primarily due to lower interest income and
higher expenses related to foreign currency transactions.
Exploration costs decreased $34 million primarily due to
lower drilling rig expenses of $32 million attributable to
a loss incurred by the Company in 2002 related to the remaining
terms of a sublease of a deepwater drilling rig, and
$19 million due to lower G&G and other expenses. These
decreases were partially offset by higher exploratory dry hole
costs of $15 million and higher amortization of undeveloped
lease costs of $2 million.
31
Income Tax Expense
Income tax expense increased $195 million in 2003. The
increase in tax expense was primarily due to higher pretax
income of $1,001 million. In November 2003, the Government
of Canada passed Bill C-48, which reduced the Canadian federal
income tax rate for companies in the natural resource sector
from 28 percent to 21 percent over a 5-year period
beginning in 2003. As a result, in 2003, the Company recorded a
benefit of $203 million related to the reduction in the
Canadian federal income tax rate. The Company also recorded a
net tax benefit of $27 million in 2003 related to the
successful appeal of the 1996-1998 IRS tax audit. Additionally,
the Company recorded higher tax benefits of $11 million in
2003 related to interest deductions allowed in both the U.S. and
Canada on transactions associated with cross-border financing.
The deduction for interest on the cross-border financing is
allowable in both the U.S. and Canada because the issuer of the
debt is a wholly owned finance subsidiary of the Company and the
activities of the finance subsidiary are taxable in both the
U.S. and Canada. Substantially all of the increase in the tax
benefit of the cross-border financing deduction from 2002 to
2003 was due to the strengthening of the Canadian dollar. This
benefit is not expected to fluctuate in the future for reasons
other than changes in exchange rate and debt levels. In 2003,
the Company resolved all disputes under tax sharing agreements
with certain former affiliates. As a result, during 2003, the
Company recorded a $3 million decrease in income tax
expense. The Company recorded lower tax benefits of
$15 million related to the reduction in the Alberta
provincial corporate income tax rate in Canada. Year 2002
included a tax benefit associated with the reversal of a tax
valuation allowance of $27 million related to the sale of
assets in the U.K. sector of the North Sea.
Legal Proceedings
The Company and numerous other oil and gas companies have been
named as defendants in various lawsuits alleging violations of
the civil False Claims Act. These lawsuits were consolidated
during 1999 and 2000 for pre-trial proceedings by the United
States Judicial Panel on Multidistrict Litigation in the matter
of In re Natural Gas Royalties Qui Tam Litigation,
MDL-1293, United States District Court for the District of
Wyoming (MDL-1293). The plaintiffs contend that
defendants underpaid royalties on natural gas and NGLs produced
on federal and Indian lands through the use of below-market
prices, improper deductions, improper measurement techniques and
transactions with affiliated companies during the period of 1985
to the present. Plaintiffs allege that the royalties paid by
defendants were lower than the royalties required to be paid
under federal regulations and that the forms filed by defendants
with the Minerals Management Service (MMS) reporting
these royalty payments were false, thereby violating the civil
False Claims Act. The United States has intervened in certain of
the MDL-1293 cases as to some of the defendants, including the
Company. The plaintiffs and the intervenor have not specified in
their pleadings the amount of damages they seek from the
Company. On December 5, 2003, the United States
Judicial Panel on Multidistrict Litigation entered an order
transferring the cases alleging claims of below-market prices,
improper deductions, and transactions with affiliated companies
for further pre-trial proceedings and trial in Wright v.
AGIP, 5:03CV264, United States District Court for the
Eastern District of Texas, Texarkana Division. All parties are
proceeding with pre-trial discovery, and the trial of these
cases is scheduled to begin in February 2007. The cases
alleging improper measurement techniques remain pending in
MDL-1293, and motions to dismiss have been filed by the Company
and other defendants and are pending before the Court.
Various administrative proceedings are also pending before the
MMS of the United States Department of the Interior with respect
to the valuation of natural gas produced by the Company on
federal and Indian lands. In general, these proceedings stem
from regular MMS audits of the Companys royalty payments
over various periods of time and involve the interpretation of
the relevant federal regulations. Most of these proceedings
involve production volumes and royalties that are the subject of
Natural Gas Royalties Qui Tam Litigation.
Based on the Companys present understanding of the various
governmental and civil False Claims Act proceedings described
above, the Company believes that it has substantial defenses to
these claims and intends to vigorously assert such defenses. The
Company is also exploring the possibility of a settlement of
these claims. Although there has been no formal demand for
damages, the Company currently estimates, based on its
communications with the intervenor, that the amount of underpaid
royalties on onshore production claimed by the intervenor in
these proceedings is approximately $76 million. In the
event that the Company is found to have violated the civil False
Claims Act, the Company could be subject to double damages,
civil monetary penalties and other sanctions, including a
temporary suspension from bidding on and entering into future
federal mineral leases and other federal contracts for a defined
period of time. As an alternative to monetary penalties under
the False Claims Act, the intervenor has informed the Company
that it may seek the recovery of interest payments of
approximately $95 million. The Company has established a
reserve that management believes to be adequate to provide for
this potential liability based upon its evaluation of this
matter.
The Company has also been named as a defendant in the lawsuit
styled UNOCAL Netherlands B.V., et al v.
Continental Netherlands Oil Company B.V., et al, No.
98-854, filed in 1995 in the District Court in The Hague and
currently pending in the Court of Appeal in The Hague, the
Netherlands. Plaintiffs, who are working interest owners in the
Q-1 Block in the North Sea, have alleged that the Company and
other former working interest owners in the adjacent Logger
Field in the
32
L16a Block unlawfully trespassed or were otherwise unjustly
enriched by producing part of the oil from the adjoining Q-1
Block. The plaintiffs claim that the defendants infringed upon
plaintiffs right to produce the minerals present in its
license area and acted in violation of generally accepted
standards by failing to inform plaintiffs of the overlap of the
Logger Field into the Q-1 Block. Plaintiffs seek damages of
$97.5 million as of January 1, 1997, plus interest.
For all relevant periods, the Company owned a 37.5 percent
working interest in the Logger Field. Following a trial, the
District Court in The Hague rendered a Judgment in favor of the
defendants, including the Company, dismissing all claims.
Plaintiffs thereafter appealed. On October 19, 2000, the
Court of Appeal in The Hague issued an interim Judgment in favor
of the plaintiffs and ordered that additional evidence be
presented to the court relating to issues of both liability and
damages. After receiving additional evidence from the parties,
the Court of Appeals subsequently issued a ruling in favor of
defendants. In an interim Judgment issued on December 18,
2003, the Court of Appeals found that defendants should not have
assumed that they were extracting oil from the Q-1 Block, that
Unocal was not entitled to compensation for any production
occurring prior to 1992 and that damages, if any, would be
limited to the proceeds Unocal would have received for oil
extracted from the Q-1 Block, less the costs Unocal would have
incurred to produce the oil from an existing well in the L16a
Block. The Court of Appeals ordered that further evidence be
presented to a court appointed expert to determine whether any
damages had been suffered by Unocal. The Company and the other
defendants are continuing to present evidence to the Court and
vigorously assert defenses against these claims. The Company has
also asserted claims of indemnity against two of the defendants
from whom it had acquired a portion of its working interest
share. If the Company is successful in enforcing the
indemnities, its working interest share of any adverse judgment
could be reduced to 15 percent for some of the periods
covered by plaintiffs lawsuit. Based on the information
known to date, the Company believes that Unocal suffered no
damages in excess of the costs of production and that the
Company will incur no liability in this matter other than the
costs of litigation. The Company has not established a reserve
for this matter since it currently does not believe that an
unfavorable outcome is probable.
The Company and its former affiliate, El Paso Natural Gas
Company, have also been named as defendants in two class action
lawsuits styled Bank of America, et al. v.
El Paso Natural Gas Company, et al., Case
No. CJ-97-68, and Deane W. Moore, et al. v.
Burlington Northern, Inc., et. al., Case
No. CJ-97-132, each filed in 1997 in the District Court of
Washita County, State of Oklahoma and subsequently consolidated
by the court. Plaintiffs contend that defendants underpaid
royalties from 1982 to the present on natural gas produced from
specified wells in Oklahoma through the use of below-market
prices, improper deductions and transactions with affiliated
companies and in other instances failed to pay or delayed in the
payment of royalties on certain gas sold from these wells. The
plaintiffs seek an accounting and damages for alleged royalty
underpayments, plus interest from the time such amounts were
allegedly due. Plaintiffs additionally seek the recovery of
punitive damages. The plaintiffs have not specified in their
pleadings the amount of damages they seek from the Company.
However, through pre-trial discovery, plaintiffs have provided
defendants with alternative theories of recovery claiming
monetary damages of up to $221 million in principal, plus
$996 million in interest and unspecified punitive damages
and attorneys fees. The Company believes it has
substantial defenses to these claims and is vigorously asserting
such defenses. The Company and El Paso Natural Gas Company
have asserted contractual claims for indemnity against each
other. The court has certified the plaintiff classes of royalty
and overriding royalty interest owners, and the parties are
proceeding with pre-trial discovery. It is anticipated that the
trial of this matter will be scheduled during 2005. The Company
has established a reserve that management believes to be
adequate to provide for this potential liability based upon its
evaluation of this matter.
The Company received notice on October 19, 2004 from the
United States Department of Justice that it may be one of many
potentially responsible parties under the Comprehensive
Environmental Response, Compensation and Liability Act, as
amended, with respect to the remediation of a site known as the
Castex Systems, Inc. Oil Field Waste Disposal Site in Jefferson
Davis Parish near Jennings, Louisiana. According to the
Department of Justice, the remediation of the site has been
completed under the supervision of the United States
Environmental Protection Agency for a total cost of
approximately $3 million. The Company has been informed
that it may have contributed up to two and one-half percent
(2.5%) of the liquid oil field waste and twelve percent (12%) of
the solid oil field waste identified at the site. The Company
has signed an agreement tolling the statute of limitations for a
period of approximately three months and is currently
investigating this matter to determine if it is liable for any
portion of the remediation costs.
In addition to the foregoing, the Company and its subsidiaries
are named defendants in numerous other lawsuits and named
parties in numerous governmental and other proceedings arising
in the ordinary course of business, including: claims for
personal injury and property damage, claims challenging oil and
gas royalty, ad valorem and severance tax payments, claims
related to joint interest billings under oil and gas operating
agreements, claims alleging mismeasurement of volumes and
wrongful analysis of heating content of natural gas and other
claims in the nature of contract, regulatory or employment
disputes. None of the governmental proceedings involve foreign
governments.
While the ultimate outcome and impact on the Company cannot be
predicted with certainty, management believes that the
resolution of these legal proceedings and environmental matters
through settlement or adverse judgment will not have a material
adverse effect on the consolidated financial position or results
of operations of the Company, although cash flow could be
significantly impacted in the reporting periods in which such
matters are resolved.
33
At December 31, 2004, the Companys Consolidated
Balance Sheet included reserves for legal proceedings of
$84 million and environmental matters of $15 million.
The accrual of reserves for legal and environmental matters is
included in Other Liabilities and Deferred Credits on the
Consolidated Balance Sheet. The establishment of a reserve
involves an estimation process that includes the advice of legal
counsel and subjective judgment of management. While management
believes these reserves to be adequate, it is reasonably
possible that the Company could incur additional loss, the
amount of which is not currently estimable, in excess of the
amounts currently accrued with respect to those matters in which
reserves have been established. Future changes in the facts and
circumstances could result in actual liability exceeding the
estimated ranges of loss and the amounts accrued. Based on
currently available information, we believe that it is remote
that future costs related to known contingent liability
exposures for legal proceedings and environmental matters will
exceed current accruals by an amount that would have a material
adverse effect on the consolidated financial position or results
of operations of the Company, although cash flow could be
significantly impacted in the reporting periods in which such
costs are incurred.
Other Matters
Recent Accounting Pronouncements
In January 2005, the Financial Accounting Standards Board
(FASB) issued SFAS No. 153, Exchanges
of Nonmonetary Assets an amendment of APB Opinion
No. 29. This statement, which addresses the measurement
of exchanges of nonmonetary assets, is effective prospectively
for nonmonetary asset exchanges occurring in fiscal periods
beginning after June 15, 2005. The adoption of this
statement is not expected to impact the Companys
consolidated financial position or results of operations.
In January 2005, the FASB issued SFAS No. 151,
Inventory Costs, which is effective prospectively for
inventory costs incurred during fiscal years beginning after
June 15, 2005. SFAS No. 151 amends Accounting
Research Bulletin No. 43, Chapter 4, to clarify that
abnormal amounts of idle facility expense, freight, handling
costs, and wasted materials should be recognized as current
period charges. The adoption of this statement is not expected
to impact the Companys consolidated financial position or
results of operations.
In December 2004, the FASB issued SFAS No. 123
(revised 2004) or SFAS No. 123(R), Share-Based
Payment. This statement requires the cost resulting from all
share-based payment transactions be recognized in the financial
statements at their fair value on the grant date.
SFAS No. 123(R) is effective as of the beginning of
the first interim or annual reporting period that begins after
June 15, 2005. The Company will adopt this statement on
July 1, 2005 using the modified prospective application
method described in the statement. Under the modified
prospective application method, the Company will apply the
standard to new awards and to awards modified, repurchased, or
cancelled after the required effective date. Additionally,
compensation cost for the unvested portion of awards outstanding
as of the required effective date will be recognized as
compensation expense as the requisite service is rendered after
the required effective date. The adoption of this statement is
not expected to have a material impact on the Companys
consolidated financial position or results of operations.
In January 2003, the FASB issued Interpretation No. 46,
(FIN 46), Consolidation of Variable Interest
Entities. FIN 46, as amended by FIN 46(R),
provides guidance on how to identify a variable interest entity
(VIE), and determine when the assets, liabilities,
and results of operations of a VIE need to be included in a
companys consolidated financial statements. FIN 46
also requires additional disclosures by primary beneficiaries
and other significant variable interest holders in a VIE. The
provisions of FIN 46 were effective immediately for all
VIEs created after January 31, 2003. For VIEs created
before February 1, 2003, the provisions of FIN 46, as
amended, were effective on January 1, 2004. After
evaluating this accounting pronouncement, the Company determined
that it did not have any interests in any VIEs. Therefore, the
adoption of FIN 46 did not have any impact on the
Companys consolidated financial position, results of
operations or cash flows.
Other Information
The Companys independent auditor, PricewaterhouseCoopers
LLP (PwC), has recently notified the SEC, the Public
Company Accounting Oversight Board and the Audit Committee of
the Companys Board of Directors that certain non-audit
work it previously performed in China for the Company and other
companies has raised questions regarding PwCs independence
with respect to its performance of audit services.
With respect to the Company, during fiscal years 2002, 2003 and
2004, PwCs affiliated firm in China performed tax
calculation and return preparation services for a small number
of employees of the Companys subsidiary in China.
PwCs China affiliate received from the Company and
remitted to the appropriate authorities on behalf of the
Companys employees payments of the relevant taxes owed by
the employees, which involved the handling of Company funds in
the amount of approximately $232,000 in 2002, $340,000 in 2003
and $44,000 in 2004. The fees paid by the Company to PwCs
China affiliate for the performance of all expatriate tax
services were approximately $6,000 in 2002, $15,000 in 2003 and
$8,000 in 2004. These expatriate tax services were discontinued
during 2004.
34
PwC has informed the Companys Audit Committee that it does
not believe its independence was impaired by the performance of
tax payment services. The Company, in consultation with legal
counsel, and the Companys Audit Committee independently
reviewed the facts surrounding these services provided by
PwCs China affiliate and do not believe that PwCs
independence was impaired by the performance of tax calculations
and return preparation services in light of the nature of the
services, the size of the fees associated with the services and
the fact that none of PwCs personnel who were involved in
providing these tax services performed any audit or
audit-related services for the Company.
Safe Harbor Cautionary Disclosure on Forward-Looking
Statements
The Company, in discussions of its future plans, expectations,
objectives and anticipated performance in periodic reports filed
by the Company with the SEC (or documents incorporated by
reference therein) may include projections or other
forward-looking statements within the meaning of the safe
harbor provisions of the Private Securities Litigation
Reform Act of 1995 and Section 27A of the Securities Act of
1933 and Section 21E of the Securities Exchange Act of
1934, as amended. Forward-looking statements can be identified
by the words expects, anticipates,
intends, plans, believes,
should and similar expressions. Projections and
forward-looking statements are based on assumptions which the
Company believes are reasonable, but are by their nature
inherently uncertain. In all cases, there can be no assurance
that such assumptions will prove correct or that projected
events will occur, and actual results could differ materially
from those projected. Some of the important factors that could
cause actual results to differ from any such projections or
other forward-looking statements follow.
Commodity Prices Changes in natural gas, NGLs and
crude oil prices (including basis differentials) from those
assumed in preparing projections and forward-looking statements
could cause the Companys actual financial results to
differ materially from projected financial results and could
also impact the Companys determination of proved reserves
and the standardized measure of discounted future net cash flows
relative to natural gas, NGLs and crude oil reserves. In
addition, periods of sharply lower commodity prices could affect
the Companys production levels could cause it to curtail
capital spending projects and delay or defer exploration,
exploitation or development projects, could render productive
wells non-commercial earlier than in a higher price environment
and could result in the Company recognizing for Generally
Accepted Accounting Principles purposes an impairment of
unamortized capital costs.
Projections relating to the price received by the Company for
natural gas and NGLs also rely on assumptions regarding the
availability and pricing of transportation to the Companys
key markets. In particular, the Company has contractual
arrangements for the transportation of natural gas from the
San Juan Basin eastward to Eastern and Midwestern markets
or to market hubs in Texas, Oklahoma and Louisiana. The natural
gas price received by the Company could be adversely affected by
any constraints in pipeline capacity to serve these markets.
These and other commodity price risks that could cause actual
results to differ from projections and forward-looking
statements are further described in Part II,
Qualitative and Quantitative Disclosure About Market
Risk-Commodity Risk.
Exploration and Production Risk The Companys
business is subject to all of the risks and uncertainties
normally associated with the exploration for and development and
production of natural gas, NGLs and crude oil, including
uncertainties as to the presence, size and recoverability of
hydrocarbons. The exploration for natural gas and crude oil is a
high-risk business in which significant numbers of dry holes,
completion and production difficulties and high associated costs
can be incurred in the process of seeking commercial discoveries
and placing them on production.
The process of estimating quantities of proved reserves is
inherently uncertain and requires making subjective engineering,
geological, geophysical and economic assumptions. In this
regard, changes in the economic conditions (including commodity
prices) or operating conditions (including, without limitation,
exploration, development and production costs and expenses and
drilling and production results from exploration and development
activity) could cause the Companys estimated proved
reserves or production to differ from those included in any such
forward-looking statements or projections. Reserves which
require the use of improved recovery techniques for production
are included in proved reserves if supported by a suitable
analogy, a successful pilot project or the operation of an
installed program. There are many risks inherent in developing
and implementing improved recovery techniques which can cause a
pilot project to be unsuccessful.
In addition, the Company has significant obligations to plug and
abandon natural gas and crude oil wells and related equipment as
well as to dismantle and abandon plants at the end of oil and
gas production operations. Estimating the costs of these
obligations requires management to make estimates and judgments
regarding timing, existence of a liability as well as what
constitutes adequate restoration. Increases in the estimated
costs of decommissioning and abandoning a developed property or
production facilities above previously forecasted levels could
cause the Companys estimated proved reserves to decrease
from those included in forward-looking statements.
Projecting future natural gas, NGLs and crude oil production is
imprecise. Producing oil and gas reservoirs eventually have
declining production rates. Projections of production rates rely
on certain assumptions regarding historical production patterns
in the area or formation tests for a particular producing
horizon. Actual production rates could differ materially from
such projections. Production rates depend on a number of
additional factors, including commodity
35
prices, market demand and the political, economic and regulatory
climate. In addition, OPEC countries in which the Company has
producing properties, such as Algeria, could subject the Company
to periods of curtailed production due to governmental mandated
cutbacks when world oil market demand is weak.
Another major factor affecting the Companys production is
its ability to replace depleting reservoirs with new reserves
through acquisition, exploration or development programs.
Exploration success is extremely difficult to predict with
certainty, particularly over the short term where the timing and
extent of successful results vary widely. Over the long term,
the ability to replace reserves depends not only on the
Companys ability to locate crude oil, NGLs and natural gas
reserves, but on the cost of finding and developing such
reserves. Moreover, development of any particular exploration or
development project may not be justified because of the
commodity price environment at the time or because of the
Companys finding and development costs for such project.
No assurances can be given as to the level or timing of success
that the Company will be able to achieve in acquiring or finding
and developing additional reserves.
Projections relating to the Companys production and
financial results rely on certain assumptions about the
Companys continued success in its acquisition and asset
rationalization programs and in its cost management efforts.
The Companys drilling operations are subject to various
hazards common to the oil and gas industry, including weather
conditions, explosions, fires, and blowouts, which could result
in damage to or destruction of oil and gas wells or formations,
production facilities and other property and injury to people.
They are also subject to the additional hazards of marine
operations, such as capsizing, collision and damage or loss from
severe weather conditions.
Goodwill The Company accounts for goodwill in
accordance with SFAS No. 142, Goodwill and other
Intangible Assets, and is required to make an annual impairment
assessment in lieu of periodic amortization. The impairment
assessment requires the Company to make estimates regarding the
fair value of the reporting unit to which goodwill has been
assigned. Although the Company bases its fair value estimate on
assumptions it believes to be reasonable, those assumptions are
inherently unpredictable and uncertain. Downward revisions of
estimated reserve quantities, increases in future cost
estimates, divestiture of a significant component of the
reporting unit, continued weakening of the U.S. dollar or
depressed natural gas, NGLs and crude oil prices could lead to
an impairment of goodwill in future periods.
Development Risk A significant portion of the
Companys development plans involve large projects in
Canada, Algeria, the East Irish Sea, China, Ecuador, Wyoming,
North Dakota and other areas. A variety of factors affect the
timing and outcome of such projects including, without
limitation, approval by the other parties owning working
interests in the project, receipt of necessary permits and
approvals by applicable governmental agencies, access to surface
locations and facilities, opposition by non-government
organizations and local indigenous communities, the
availability, costs and performance of the necessary drilling
equipment and infrastructure, drilling risks, operating hazards,
unexpected cost increases and technical difficulties in
constructing, modifying and operating equipment, plants and
facilities, manufacturing and delivery schedules for critical
equipment and arrangements for the gathering and transportation
of the produced hydrocarbons.
Foreign Operations Risk The Companys
operations outside of the U.S. are subject to risks
inherent in foreign operations, including, without limitation,
the loss of revenue, property and equipment from hazards such as
expropriation, nationalization, war, insurrection, acts of
terrorism and other political risks, increases in taxes and
governmental royalties, renegotiation or abrogation of contracts
with governmental entities, changes in laws and policies
governing operations of foreign-based companies, currency
restrictions and exchange rate fluctuations, world economic
cycles, restrictions or quotas on production and commodity
sales, limited market access and other uncertainties arising out
of foreign government sovereignty over the Companys
international operations. Laws and policies of the
U.S. affecting foreign trade and taxation may also
adversely affect the Companys international operations.
The Companys ability to market natural gas, NGLs and crude
oil discovered or produced in its foreign operations, and the
price the Company could obtain for such production, depends on
many factors beyond the Companys control, including ready
markets for natural gas, NGLs and crude oil, the proximity and
capacity of pipelines and other transportation facilities,
fluctuating demand for crude oil and natural gas, the
availability and cost of competing fuels, and the effects of
foreign governmental regulation of oil and gas production and
sales. Pipeline and processing facilities do not exist in
certain areas of exploration and, therefore, any actual sales of
the Companys production could be delayed for extended
periods of time until such facilities are constructed.
Competition The Company actively competes for
property acquisitions, exploration leases and sales of natural
gas, NGLs and crude oil, frequently against companies with
substantially larger financial and other resources. In its
marketing activities, the Company competes with numerous
companies for gas purchasing and processing contracts and for
natural gas and NGLs at several stages in the distribution
chain. Competitive factors in the Companys business
include price, contract terms, quality of service, pipeline
access, transportation discounts and distribution efficiencies.
Legal and Regulatory Risk The Companys
operations are affected by foreign, national, state and local
laws and regulations. Compliance with these regulations is often
difficult and costly and non-compliance could subject the
36
Company to material administrative, civil or criminal penalties,
or other liabilities. Restrictions on production, price or
gathering rate controls, changes in taxes, royalties and other
amounts payable to governments or governmental agencies and
other changes in or litigation arising under laws and
regulations, or interpretations thereof, could have a
significant effect on the Companys operations or financial
results. The Companys operations in some geographic areas
may be negatively impacted by legal proceedings, the actions of
national, state and local governments, and the actions of
non-governmental organizations that delay, restrict or prevent
the Companys access to surface locations for natural gas
and crude oil exploration and production activities. The
Companys operations also may be negatively impacted by
laws, regulations and legal proceedings pertaining to the
valuation and measurement of natural gas, crude oil and NGLs and
payment of royalties from such sales. Existing litigation
involving the valuation and measurement of natural gas, crude
oil and NGLs and payment of royalties from such sales is
described in Note 14 of the Notes to Consolidated Financial
Statements. Other legal and regulatory risks that could cause
actual results to differ from projections and other
forward-looking statements are described in Part I,
Other Matters.
Political and Security Risk Domestic and
international political and security risks, including changes in
government, seizure of property, civil unrest, armed hostilities
and acts of terrorism, could have a significant effect on the
Companys operations or financial results.
Environmental Regulations and Liabilities The
Companys operations are subject to various foreign,
national, state and local laws and regulations covering the
discharge of material into, and protection of, the environment.
Such regulations and liability for remedial actions under
environmental regulations affect the costs of planning,
designing, operating and abandoning facilities. The Company
expends considerable resources, both financial and managerial,
to comply with environmental regulations and permitting
requirements. Although the Company believes that its operations
and facilities are in substantial compliance with applicable
environmental laws and regulations, risks of substantial costs
and liabilities are inherent in crude oil and natural gas
operations. Moreover, it is possible that other developments,
such as increasingly strict environmental laws, regulations and
enforcement, and claims for damage to property or persons
resulting from the Companys current or discontinued
operations, could result in substantial costs and liabilities in
the future.
While the Company maintains insurance coverage for spills,
pollutions and certain other environmental risks, it is not
fully insured against all such risks. Because regulatory
requirements frequently change and may become more stringent,
and environmental costs and liabilities are inherent in the
Companys operations, there can be no assurance that
material costs and liabilities will not be incurred in the
future or that the Companys insurance will be sufficient
to cover any such costs or liabilities. Such costs may result in
increased costs of operations and acquisitions and decrease
production.
37
MANAGEMENT REPORT ON INTERNAL CONTROL OVER FINANCIAL
REPORTING
The management of the Company is responsible for establishing
and maintaining adequate internal control over financial
reporting. Internal control over financial reporting is a
process designed by, or under the supervision of, the
Companys principal executive and principal financial
officers and effected by the Companys board of directors,
management and other personnel, 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 and
includes those policies and procedures that:
|
|
|
Pertain to the maintenance of records that, in reasonable
detail, accurately and fairly reflect the transactions and
dispositions of the assets of the Company; |
|
|
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 |
|
|
Provide reasonable assurance regarding prevention or timely
detection of unauthorized acquisition, use or disposition of the
Companys assets that could have a material effect on the
financial statements. |
Because of its inherent limitations, internal control over
financial reporting may not prevent or detect misstatements.
Also, projections of any evaluation of effectiveness to future
periods are subject to the risk that controls may become
inadequate because of changes in conditions, or that the degree
of compliance with the policies or procedures may deteriorate.
The Companys management assessed the effectiveness of the
Companys internal control over financial reporting as of
December 31, 2004. In making this assessment, the
Companys management used the criteria set forth by the
Committee of Sponsoring Organizations of the Treadway Commission
(COSO) in Internal Control-Integrated Framework.
Based on our assessment, management has concluded that, as of
December 31, 2004, the Companys internal control over
financial reporting was effective based on those criteria. The
Companys independent registered public accounting firm,
PricewaterhouseCoopers LLP, has audited our assessment of the
effectiveness of the Companys internal control over
financial reporting as of December 31, 2004, as stated in
their report which appears on page 39.
|
|
|
|
|
![-s- STEVEN J. SHAPIRO](h22407h2240701.gif) |
|
|
|
|
|
|
|
Bobby S. Shackouls
Chairman of the Board, President and
Chief Executive Officer |
|
Steven J. Shapiro
Executive Vice President and Chief
Financial Officer |
38
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholders
of Burlington Resources Inc.:
We have completed an integrated audit of Burlington Resources
Inc.s 2004 consolidated financial statements and of its
internal control over financial reporting as of
December 31, 2004 and audits of its 2003 and 2002
consolidated financial statements in accordance with the
standards of the Public Company Accounting Oversight Board
(United States). Our opinions, based on our audits, are
presented below.
Consolidated financial statements
In our opinion, the accompanying consolidated balance sheets and
the related consolidated statements of income, cash flows and
stockholders equity present fairly, in all material
respects, the financial position of Burlington Resources Inc.
and its subsidiaries at December 31, 2004 and 2003, and the
results of their operations and their cash flows for each of the
three years in the period ended December 31, 2004 in
conformity with accounting principles generally accepted in the
United States of America. These financial statements are the
responsibility of the Companys management. Our
responsibility is to express an opinion on these financial
statements based on our audits. We conducted our audits of these
statements 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 of financial statements
includes examining, on a test basis, evidence supporting the
amounts and disclosures in the financial statements, assessing
the accounting principles used and significant estimates made by
management, and evaluating the overall financial statement
presentation. We believe that our audits provide a reasonable
basis for our opinion.
As discussed in Note 10 to the consolidated financial
statements, on January 1, 2003, the Company changed its
method of accounting for its asset retirement obligations in
connection with its adoption of Statement of Financial
Accounting Standards No. 143, Accounting for Asset
Retirement Obligations.
Internal control over financial reporting
Also, in our opinion, managements assessment, included in
the Management Report on Internal Control Over Financial
Reporting appearing under Item 7, that the Company
maintained effective internal control over financial reporting
as of December 31, 2004 based on criteria established in
Internal Control Integrated Framework issued
by the Committee of Sponsoring Organizations of the Treadway
Commission (COSO), is fairly stated, in all material
respects, based on those criteria. Furthermore, in our opinion,
the Company maintained, in all material respects, effective
internal control over financial reporting as of
December 31, 2004, based on criteria established in
Internal Control Integrated Framework issued
by the COSO. The Companys 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
opinions on managements assessment and on the
effectiveness of the Companys internal control over
financial reporting based on our audit. We conducted our audit
of internal control over financial reporting 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. An audit of internal
control over financial reporting includes obtaining an
understanding of internal control over financial reporting,
evaluating managements assessment, testing and evaluating
the design and operating effectiveness of internal control, and
performing such other procedures as we consider necessary in the
circumstances. We believe that our audit provides a reasonable
basis for our opinions.
A companys internal control over financial reporting is a
process designed to provide reasonable assurance regarding the
reliability of financial reporting and the preparation of
financial statements for external purposes in accordance with
generally accepted accounting principles. A companys
internal control over financial reporting includes those
policies and procedures that (i) pertain to the maintenance
of records that, in reasonable detail, accurately and fairly
reflect the transactions and dispositions of the assets of the
company; (ii) 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 (iii) provide
reasonable assurance regarding prevention or timely detection of
unauthorized acquisition, use, or disposition of the
companys assets that could have a material effect on the
financial statements.
Because of its inherent limitations, internal control over
financial reporting may not prevent or detect misstatements.
Also, projections of any evaluation of effectiveness to future
periods are subject to the risk that controls may become
inadequate because of changes in conditions, or that the degree
of compliance with the policies or procedures may deteriorate.
Houston, Texas
February 28, 2005
39
ITEM EIGHT
FINANCIAL STATEMENTS AND SUPPLEMENTARY FINANCIAL INFORMATION
BURLINGTON RESOURCES INC.
CONSOLIDATED STATEMENT OF INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
2004 | |
|
2003 | |
|
2002 | |
| |
(In Millions, Except per Share Amounts) | |
| |
REVENUES
|
|
$ |
5,618 |
|
|
$ |
4,311 |
|
|
$ |
2,968 |
|
|
COSTS AND OTHER INCOMENET
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Taxes Other than Income Taxes
|
|
|
260 |
|
|
|
187 |
|
|
|
123 |
|
|
Transportation Expense
|
|
|
453 |
|
|
|
408 |
|
|
|
354 |
|
|
Operating Costs
|
|
|
587 |
|
|
|
475 |
|
|
|
467 |
|
|
Depreciation, Depletion and Amortization
|
|
|
1,137 |
|
|
|
927 |
|
|
|
833 |
|
|
Exploration Costs
|
|
|
258 |
|
|
|
252 |
|
|
|
286 |
|
|
Impairment of Oil and Gas Properties
|
|
|
90 |
|
|
|
63 |
|
|
|
|
|
|
Administrative
|
|
|
215 |
|
|
|
164 |
|
|
|
161 |
|
|
Interest Expense
|
|
|
282 |
|
|
|
260 |
|
|
|
274 |
|
|
(Gain)/ Loss on Disposal of Assets
|
|
|
13 |
|
|
|
(8 |
) |
|
|
(68 |
) |
|
Other Expense (Income)Net
|
|
|
19 |
|
|
|
13 |
|
|
|
(31 |
) |
|
Total Costs and Other IncomeNet
|
|
|
3,314 |
|
|
|
2,741 |
|
|
|
2,399 |
|
|
Income Before Income Taxes and Cumulative Effect of Change in
Accounting Principle
|
|
|
2,304 |
|
|
|
1,570 |
|
|
|
569 |
|
Income Tax Expense
|
|
|
777 |
|
|
|
310 |
|
|
|
115 |
|
|
Income Before Cumulative Effect of Change in Accounting Principle
|
|
|
1,527 |
|
|
|
1,260 |
|
|
|
454 |
|
Cumulative Effect of Change in Accounting PrincipleNet
|
|
|
|
|
|
|
(59 |
) |
|
|
|
|
|
Net Income
|
|
$ |
1,527 |
|
|
$ |
1,201 |
|
|
$ |
454 |
|
|
EARNINGS PER COMMON SHARE
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Before Cumulative Effect of Change in Accounting Principle
|
|
$ |
3.90 |
|
|
$ |
3.17 |
|
|
$ |
1.13 |
|
|
|
Cumulative Effect of Change in Accounting PrincipleNet
|
|
|
|
|
|
|
(0.15 |
) |
|
|
|
|
|
|
|
Net Income
|
|
$ |
3.90 |
|
|
$ |
3.02 |
|
|
$ |
1.13 |
|
|
|
Diluted
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Before Cumulative Effect of Change in Accounting Principle
|
|
$ |
3.86 |
|
|
$ |
3.15 |
|
|
$ |
1.13 |
|
|
|
Cumulative Effect of Change in Accounting PrincipleNet
|
|
|
|
|
|
|
(0.15 |
) |
|
|
|
|
|
|
|
Net Income
|
|
$ |
3.86 |
|
|
$ |
3.00 |
|
|
$ |
1.13 |
|
|
See accompanying Notes to Consolidated Financial Statements.
40
BURLINGTON RESOURCES INC.
CONSOLIDATED BALANCE SHEET
|
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
2004 | |
|
2003 | |
| |
(In Millions, Except Share Data) | |
| |
ASSETS |
|
|
Current Assets
|
|
|
|
|
|
|
|
|
|
|
Cash and Cash Equivalents
|
|
$ |
2,179 |
|
|
$ |
757 |
|
|
|
Accounts Receivable
|
|
|
994 |
|
|
|
605 |
|
|
|
Inventories
|
|
|
124 |
|
|
|
81 |
|
|
|
Other Current Assets
|
|
|
158 |
|
|
|
74 |
|
|
|
|
|
3,455 |
|
|
|
1,517 |
|
|
|
Oil and Gas Properties (Successful Efforts Method)
|
|
|
17,943 |
|
|
|
15,962 |
|
|
Other Properties
|
|
|
1,544 |
|
|
|
1,381 |
|
|
|
|
|
19,487 |
|
|
|
17,343 |
|
|
Less: Accumulated Depreciation, Depletion and Amortization
|
|
|
8,454 |
|
|
|
7,032 |
|
|
|
|
PropertiesNet
|
|
|
11,033 |
|
|
|
10,311 |
|
|
|
Goodwill
|
|
|
1,054 |
|
|
|
982 |
|
|
|
Other Assets
|
|
|
202 |
|
|
|
185 |
|
|
|
|
|
Total Assets
|
|
$ |
15,744 |
|
|
$ |
12,995 |
|
|
LIABILITIES |
|
|
Current Liabilities
|
|
|
|
|
|
|
|
|
|
|
Accounts Payable
|
|
$ |
1,182 |
|
|
$ |
714 |
|
|
|
Taxes Payable
|
|
|
264 |
|
|
|
43 |
|
|
|
Accrued Interest
|
|
|
61 |
|
|
|
61 |
|
|
|
Dividends Payable
|
|
|
33 |
|
|
|
30 |
|
|
|
Current Maturities of Long-term Debt
|
|
|
2 |
|
|
|
|
|
|
|
Other Current Liabilities
|
|
|
57 |
|
|
|
43 |
|
|
|
|
|
1,599 |
|
|
|
891 |
|
|
|
Long-term Debt
|
|
|
3,887 |
|
|
|
3,873 |
|
|
|
Deferred Income Taxes
|
|
|
2,396 |
|
|
|
1,948 |
|
|
|
Other Liabilities and Deferred Credits
|
|
|
851 |
|
|
|
762 |
|
|
|
Commitments and Contingent Liabilities (Note 14)
|
|
|
|
|
|
|
|
|
|
STOCKHOLDERS EQUITY |
|
|
Preferred Stock, Par Value $.01 per Share (Authorized
75,000,000 Shares; No Shares Issued)
|
|
|
|
|
|
|
|
|
|
Common Stock, Par Value $.01 per Share (Authorized
650,000,000 Shares; Issued 482,376,870 and
482,377,376 Shares for 2004 and 2003, respectively)
|
|
|
5 |
|
|
|
5 |
|
|
Paid-in Capital
|
|
|
3,973 |
|
|
|
3,943 |
|
|
Retained Earnings
|
|
|
4,163 |
|
|
|
2,761 |
|
|
Deferred CompensationRestricted Stock
|
|
|
(14 |
) |
|
|
(10 |
) |
|
Accumulated Other Comprehensive Income
|
|
|
1,092 |
|
|
|
655 |
|
|
Cost of Treasury Stock (94,435,401 and 87,079,770 Shares
for 2004 and 2003, respectively)
|
|
|
(2,208 |
) |
|
|
(1,833 |
) |
|
|
Stockholders Equity
|
|
|
7,011 |
|
|
|
5,521 |
|
|
|
|
|
Total Liabilities and Stockholders Equity
|
|
$ |
15,744 |
|
|
$ |
12,995 |
|
|
See accompanying Notes to Consolidated Financial Statements.
41
BURLINGTON RESOURCES INC.
CONSOLIDATED STATEMENT OF CASH FLOWS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
2004 | |
|
2003 | |
|
2002 | |
| |
|
|
(In Millions) | |
| |
CASH FLOWS FROM OPERATING ACTIVITIES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income
|
|
$ |
1,527 |
|
|
$ |
1,201 |
|
|
$ |
454 |
|
|
Adjustments to Reconcile Net Income to Net Cash Provided by
Operating Activities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation, Depletion and Amortization
|
|
|
1,137 |
|
|
|
927 |
|
|
|
833 |
|
|
|
Deferred Income Taxes
|
|
|
371 |
|
|
|
150 |
|
|
|
39 |
|
|
|
Exploration Costs
|
|
|
258 |
|
|
|
252 |
|
|
|
286 |
|
|
|
Impairment of Oil and Gas Properties
|
|
|
90 |
|
|
|
63 |
|
|
|
|
|
|
|
(Gain)/Loss on Disposal of Assets
|
|
|
13 |
|
|
|
(8 |
) |
|
|
(68 |
) |
|
|
Changes in Derivative Fair Values
|
|
|
(5 |
) |
|
|
(5 |
) |
|
|
32 |
|
|
|
Cumulative Effect of Change in Accounting Principle Net
|
|
|
|
|
|
|
59 |
|
|
|
|
|
|
Working Capital Changes
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts Receivable
|
|
|
(365 |
) |
|
|
(28 |
) |
|
|
(117 |
) |
|
|
Inventories
|
|
|
(40 |
) |
|
|
(26 |
) |
|
|
2 |
|
|
|
Other Current Assets
|
|
|
(25 |
) |
|
|
(15 |
) |
|
|
(17 |
) |
|
|
Accounts Payable
|
|
|
278 |
|
|
|
(4 |
) |
|
|
138 |
|
|
|
Taxes Payable
|
|
|
188 |
|
|
|
(9 |
) |
|
|
43 |
|
|
|
Accrued Interest
|
|
|
|
|
|
|
(1 |
) |
|
|
4 |
|
|
|
Other Current Liabilities
|
|
|
18 |
|
|
|
|
|
|
|
(8 |
) |
|
Changes in Other Assets and Liabilities
|
|
|
(9 |
) |
|
|
(17 |
) |
|
|
(72 |
) |
|
|
|
|
Net Cash Provided by Operating Activities
|
|
|
3,436 |
|
|
|
2,539 |
|
|
|
1,549 |
|
|
CASH FLOWS FROM INVESTING ACTIVITIES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Additions to Properties
|
|
|
(1,582 |
) |
|
|
(1,899 |
) |
|
|
(1,851 |
) |
|
Proceeds from Sales and Other
|
|
|
(25 |
) |
|
|
4 |
|
|
|
1,180 |
|
|
|
|
|
Net Cash Used in Investing Activities
|
|
|
(1,607 |
) |
|
|
(1,895 |
) |
|
|
(671 |
) |
|
CASH FLOWS FROM FINANCING ACTIVITIES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proceeds from Long-term Debt
|
|
|
41 |
|
|
|
|
|
|
|
454 |
|
|
Reduction in Long-term Debt
|
|
|
(41 |
) |
|
|
(75 |
) |
|
|
(879 |
) |
|
Dividends Paid
|
|
|
(122 |
) |
|
|
(85 |
) |
|
|
(139 |
) |
|
Common Stock Purchases
|
|
|
(518 |
) |
|
|
(356 |
) |
|
|
|
|
|
Common Stock Issuances
|
|
|
153 |
|
|
|
128 |
|
|
|
13 |
|
|
Other
|
|
|
(1 |
) |
|
|
(3 |
) |
|
|
2 |
|
|
|
|
|
Net Cash Used in Financing Activities
|
|
|
(488 |
) |
|
|
(391 |
) |
|
|
(549 |
) |
|
Effect of Exchange Rate Changes on Cash and Cash Equivalents
|
|
|
81 |
|
|
|
61 |
|
|
|
(2 |
) |
|
Increase in Cash and Cash Equivalents
|
|
|
1,422 |
|
|
|
314 |
|
|
|
327 |
|
Cash and Cash Equivalents
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Beginning of Year
|
|
|
757 |
|
|
|
443 |
|
|
|
116 |
|
|
|
End of Year
|
|
$ |
2,179 |
|
|
$ |
757 |
|
|
$ |
443 |
|
|
See accompanying Notes to Consolidated Financial Statements.
42
BURLINGTON RESOURCES INC.
CONSOLIDATED STATEMENT OF STOCKHOLDERS EQUITY
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated | |
|
|
|
|
|
|
|
|
|
|
|
|
Deferred | |
|
Other | |
|
Cost of | |
|
|
|
|
Common | |
|
Paid-in | |
|
Retained | |
|
Compensation | |
|
Comprehensive | |
|
Treasury | |
|
Stockholders | |
|
|
Stock | |
|
Capital | |
|
Earnings | |
|
Restricted Stock | |
|
Income (Loss) | |
|
Stock | |
|
Equity | |
|
|
| |
|
|
(In Millions, Except Share Data) | |
| |
December 31, 2001
|
|
|
$5 |
|
|
|
$3,941 |
|
|
|
$1,332 |
|
|
$ |
(9 |
) |
|
$ |
(106 |
) |
|
|
$(1,638 |
) |
|
|
$3,525 |
|
|
Comprehensive Income (Loss)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income
|
|
|
|
|
|
|
|
|
|
|
454 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
454 |
|
|
Foreign Currency Translation
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
34 |
|
|
|
|
|
|
|
34 |
|
|
Hedging Activities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(86 |
) |
|
|
|
|
|
|
(86 |
) |
|
Minimum Pension Liability
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(6 |
) |
|
|
|
|
|
|
(6 |
) |
|
|
|
Comprehensive Income (Loss)
|
|
|
|
|
|
|
|
|
|
|
454 |
|
|
|
|
|
|
|
(58 |
) |
|
|
|
|
|
|
396 |
|
|
Cash Dividends Declared ($0.28 per Share)
|
|
|
|
|
|
|
|
|
|
|
(111 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(111 |
) |
Stock Option Activity
|
|
|
|
|
|
|
(3 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
16 |
|
|
|
13 |
|
Issuance of Restricted Stock
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(9 |
) |
|
|
|
|
|
|
9 |
|
|
|
|
|
Amortization of Restricted Stock
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
9 |
|
|
|
|
|
|
|
|
|
|
|
9 |
|
|
December 31, 2002
|
|
|
5 |
|
|
|
3,938 |
|
|
|
1,675 |
|
|
|
(9 |
) |
|
|
(164 |
) |
|
|
(1,613 |
) |
|
|
3,832 |
|
|
Comprehensive Income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income
|
|
|
|
|
|
|
|
|
|
|
1,201 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,201 |
|
|
Foreign Currency Translation
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
802 |
|
|
|
|
|
|
|
802 |
|
|
Hedging Activities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
11 |
|
|
|
|
|
|
|
11 |
|
|
Minimum Pension Liability
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
6 |
|
|
|
|
|
|
|
6 |
|
|
|
|
Comprehensive Income
|
|
|
|
|
|
|
|
|
|
|
1,201 |
|
|
|
|
|
|
|
819 |
|
|
|
|
|
|
|
2,020 |
|
|
Cash Dividends Declared ($0.29 per Share)
|
|
|
|
|
|
|
|
|
|
|
(115 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(115 |
) |
Common Stock Purchases (14,829,980 Shares)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(361 |
) |
|
|
(361 |
) |
Stock Option Activity
|
|
|
|
|
|
|
5 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
129 |
|
|
|
134 |
|
Issuance of Restricted Stock
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(12 |
) |
|
|
|
|
|
|
12 |
|
|
|
|
|
Amortization of Restricted Stock
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
11 |
|
|
|
|
|
|
|
|
|
|
|
11 |
|
|
December 31, 2003
|
|
|
5 |
|
|
|
3,943 |
|
|
|
2,761 |
|
|
|
(10 |
) |
|
|
655 |
|
|
|
(1,833 |
) |
|
|
5,521 |
|
|
Comprehensive Income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income
|
|
|
|
|
|
|
|
|
|
|
1,527 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,527 |
|
|
Foreign Currency Translation
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
396 |
|
|
|
|
|
|
|
396 |
|
|
Hedging Activities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
41 |
|
|
|
|
|
|
|
41 |
|
|
|
|
Comprehensive Income
|
|
|
|
|
|
|
|
|
|
|
1,527 |
|
|
|
|
|
|
|
437 |
|
|
|
|
|
|
|
1,964 |
|
|
Cash Dividends Declared ($0.32 per Share)
|
|
|
|
|
|
|
|
|
|
|
(125 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(125 |
) |
Common Stock Purchases (14,358,000 Shares)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(522 |
) |
|
|
(522 |
) |
Stock Option Activity
|
|
|
|
|
|
|
30 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
132 |
|
|
|
162 |
|
Issuance of Restricted Stock
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(15 |
) |
|
|
|
|
|
|
15 |
|
|
|
|
|
Amortization of Restricted Stock
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
11 |
|
|
|
|
|
|
|
|
|
|
|
11 |
|
|
December 31, 2004
|
|
|
$5 |
|
|
|
$3,973 |
|
|
|
$4,163 |
|
|
$ |
(14 |
) |
|
$ |
1,092 |
|
|
|
$(2,208 |
) |
|
|
$7,011 |
|
|
See accompanying Notes to Consolidated Financial Statements.
43
BURLINGTON RESOURCES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. Accounting Policies
Nature of Business
Burlington Resources Inc. (BR) is among the
worlds largest independent oil and gas companies and holds
one of the industrys leading positions in North American
natural gas reserves and production. BR conducts exploration,
production and development operations in the U.S., Canada, the
United Kingdom, Africa, China and South America. Its extensive
North American lease holdings extend from the U.S. Gulf
Coast to Northeast British Columbia and Northern Alberta in
Canada. BR is a holding company and its principal subsidiaries
include Burlington Resources Oil & Gas Company LP, The
Louisiana Land and Exploration Company (LL&E),
Burlington Resources Canada Ltd. (formerly known as Poco
Petroleums Ltd.), Burlington Resources Canada (Hunter) Ltd.
(formerly known as Canadian Hunter Exploration Ltd.)
(Hunter), and their affiliated companies
(collectively, the Company).
Principles of Consolidation and Reporting
The consolidated financial statements of the Company include the
accounts of BR and its majority-owned subsidiaries. All
significant intercompany transactions have been eliminated in
consolidation. Investments in entities in which the Company has
a significant ownership interest, generally 20 to
50 percent, or otherwise does not exercise control, are
accounted for using the equity method. Under the equity method,
the investments are stated at cost plus the Companys
equity in undistributed earnings and losses. The consolidated
financial statements for previous periods include certain
reclassifications that were made to conform to current
presentation. Such reclassifications have no impact on
previously reported net income or stockholders equity.
Stock Split (split)
All prior period common stock and applicable share and per share
amounts have been retroactively adjusted to reflect a 2-for-1
split of the Companys Common Stock effective June 1,
2004.
Cash and Cash Equivalents
All short-term investments purchased with a maturity of three
months or less are considered cash equivalents. Cash equivalents
are stated at cost, which approximates market value.
Inventories
Inventories of materials, supplies and products are valued at
the lower of average cost or market. Inventories consisted of
the following.
|
|
|
|
|
|
|
|
|
|
December 31, |
|
2004 | |
|
2003 | |
| |
|
|
(In Millions) | |
| |
Materials and supplies
|
|
$ |
99 |
|
|
|
$70 |
|
Product inventory
|
|
|
25 |
|
|
|
11 |
|
|
|
Inventories
|
|
$ |
124 |
|
|
|
$81 |
|
|
Properties
Proved
Oil and gas properties are accounted for using the successful
efforts method. Under this method, all development costs and
acquisition costs of proved properties are capitalized and
amortized on a unit-of-production basis over the remaining life
of proved developed reserves and proved reserves, respectively.
Costs of drilling exploratory wells are initially capitalized,
but charged to expense if and when a well is determined to be
unsuccessful.
The Company evaluates the impairment of its proved oil and gas
properties on a field-by-field basis whenever events or changes
in circumstances indicate an assets carrying amount may
not be recoverable. Unamortized capital costs are reduced to
fair value if the expected undiscounted future cash flows are
less than the assets net book value. Cash flows are
determined based upon reserves using prices and costs consistent
with those used for internal decision making. The underlying
commodity prices embedded in the Companys estimated cash
flows are the product of a process that begins with the New York
Mercantile Exchange pricing and adjusted for estimated location
and quality differentials, as well as other factors that
management believes will impact realizable prices. Although
prices used are
44
BURLINGTON RESOURCES INC.
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
likely to approximate market, they do not necessarily represent
current market prices. Given that spot hydrocarbon market prices
are subject to volatile changes, it is the Companys
opinion that a long-term look at market prices will lead to a
more appropriate valuation of long-term assets.
Costs of retired, sold or abandoned properties that constitute a
part of an amortization base are charged or credited, net of
proceeds, to accumulated depreciation, depletion and
amortization unless doing so significantly affects the
unit-of-production amortization rate, in which case a gain or
loss is recognized currently. Gains or losses from the disposal
of other properties are recognized currently. Expenditures for
maintenance, repairs and minor renewals necessary to maintain
properties in operating condition are expensed as incurred.
Major replacements and renewals are capitalized. Estimated
dismantlement and abandonment costs for oil and gas properties
are capitalized, net of salvage, at their estimated net present
value and amortized on a unit-of-production basis over the
remaining life of the related proved developed reserves. See
Note 10 of Notes to Consolidated Financial Statements.
Unproved
Unproved properties consist of costs incurred to acquire
unproved leases (lease acquisition costs) as well as
costs incurred to acquire unproved reserves. Unproved lease
acquisition costs are capitalized and amortized on a composite
basis, based on past success, experience and average lease-term
lives. Unamortized lease acquisition costs related to successful
exploratory drilling are reclassified to proved properties and
depleted on a unit-of-production basis. The book value of the
Companys unproved reserves, which were acquired in
connection with business acquisitions, was determined using the
same methods, after adjusting for risks, that were used to value
the proved reserves acquired in the same acquisition. Because
these reserves did not meet the strict definition of proved
reserves, the related costs were not classified as proved
properties. As the unproved reserves are developed and proven,
the associated costs are reclassified to proved properties and
depleted on a unit-of-production basis. The Company assesses
unproved reserves for impairment annually by comparing book
value to fair value, which is determined using discounted
estimates of future cash flows. See Note 16 of Notes to
Consolidated Financial Statements.
Exploration
Costs of drilling exploratory wells are initially capitalized,
but charged to expense if and when a well is determined to be
unsuccessful. Determination is usually made on or shortly after
completing or drilling the well, however, in certain situations
determination cannot be made when drilling is completed. The
Company defers capitalized exploratory costs for wells that have
found a sufficient quantity of producible hydrocarbons but
cannot be classified as proved because they are located in areas
that require major capital expenditures or governmental or other
regulatory approvals before production can begin. These costs
continue to be deferred as wells in progress as long as
development is underway, is firmly planned for the near future
or the necessary approvals are actively being sought. For all
other exploratory wells, determination is made within one year
from the date drilling and other necessary activities have been
completed. If a determination cannot be made after one year, all
costs associated with the well are expensed.
Other
Other properties include gas plants, pipelines, buildings, data
processing and telecommunications equipment, office furniture
and equipment and other fixed assets. These items are recorded
at cost and are depreciated using the straight-line method based
on expected lives of the individual assets or group of assets.
Goodwill
Goodwill represents the excess of the cost of an acquired entity
over the net of the amounts assigned to assets acquired and
liabilities assumed. The Company accounts for its goodwill in
accordance with Statement of Financial Accounting Standards
(SFAS) No. 142, Goodwill and Other
Intangible Assets, which requires the Company to test
goodwill for impairment annually or whenever events or changes
in circumstances indicate that the carrying value of an asset
may not be recoverable, rather than amortize.
Revenue Recognition
Natural gas, NGLs and crude oil revenues are recorded using the
entitlement method. Under the entitlement method, revenue is
recorded when title passes based on the Companys net
interest. The Company records its entitled share of revenues
based on entitled volumes and contracted sales prices. The sales
price for natural gas, NGLs and crude oil are adjusted for
transportation cost and other related deductions. The
transportation costs and other deductions are based on
contractual or historical data and do not require significant
judgment. Subsequently, these deductions and
45
BURLINGTON RESOURCES INC.
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
transportation costs are adjusted to reflect actual charges
based on third party documents. Historically, these adjustments
have been insignificant. Since there is a ready market for
natural gas, crude oil and NGLs, the Company sells the majority
of its products soon after production at various locations at
which time title and risk of loss pass to the buyer. As a
result, the Company maintains a minimum amount of product
inventory in storage. Gas imbalances occur when the Company
sells more or less than its entitled ownership percentage of
total gas production. Any amount received in excess of the
Companys share is treated as a liability. If the Company
receives less than it is entitled, the underproduction is
recorded as a receivable. At December 31, 2004 and 2003,
the Company had a net gas imbalance payable of $11 million
and a net gas imbalance receivable of $19 million,
respectively, of which $58 million and $69 million is
recorded in Accounts Receivable and Accounts Payable,
respectively, on the Companys Consolidated Balance Sheet
at December 31, 2004.
The Company utilizes buy/sell or exchange contracts to transport
its crude oil from producing areas to a market center, typically
Cushing, Oklahoma. The Company accounts for these transactions
on a net basis in its Consolidated Statement of Income.
Royalty Payable
It is the Companys policy to calculate and pay royalties
on natural gas, crude oil and NGLs in accordance with the
particular contractual provisions of the lease, license or
concession agreements and the laws and regulations applicable to
those agreements. Royalty liabilities are recorded in the period
in which the natural gas, crude oil or NGLs are produced and are
included in Accounts Payable on the Companys Consolidated
Balance Sheet.
Foreign Currency Translation
The assets, liabilities and operations of BRs Canadian
operating subsidiaries are measured using the Canadian dollar as
the functional currency. These assets and liabilities are
translated into United States (U.S.) dollars at
end-of-period exchange rates. Gains and losses related to
translating these assets and liabilities are recorded in
Accumulated Other Comprehensive Income. At December 31,
2004 and 2003, the balances in Accumulated Other Comprehensive
Income related to foreign currency translation were gains of
$1,072 million and $676 million, respectively. Revenue
and expenses are translated into U.S. dollars at the
average exchange rates in effect during the period. The assets,
liabilities and results of operations of BRs International
operating subsidiaries are measured using the U.S. dollar
as the functional currency. For International subsidiaries where
the U.S. dollar is the functional currency, all foreign
currency denominated assets and liabilities are remeasured into
U.S. dollars at end-of-period exchange rates. Inventories,
prepaid expenses and properties are exceptions to this policy
and are remeasured at historical rates. Foreign currency
revenues and expenses are remeasured at average exchange rates
in effect during the year. Exceptions to this policy include all
expenses related to balance sheet amounts that are remeasured at
historical exchange rates. Exchange gains and losses arising
from remeasured foreign currency denominated monetary assets and
liabilities are included in Other Expense (Income)
Net in the Consolidated Statement of Income. Included in net
income for the years ended December 31, 2004, 2003 and 2002
are exchange gains of $5 million and exchange losses of
$7 million and $1 million, respectively.
Commodity Hedging Contracts and Other Derivatives
The Company enters into derivative contracts, primarily options
and swaps, to hedge future natural gas and crude oil production
in order to mitigate the risk of market price fluctuations. The
Company also enters into derivative contracts to mitigate the
risk of foreign currency exchange and interest rate
fluctuations. All derivatives are recognized on the balance
sheet and measured at fair value. If the derivative does not
qualify as a hedge or is not designated as a hedge, changes in
the fair value of the derivative are recognized currently in
earnings. If the derivative qualifies for hedge accounting,
changes in the fair value of the derivative are either
recognized in income along with the corresponding change in fair
value of the item being hedged for fair-value hedges or deferred
in other comprehensive income to the extent the hedge is
effective for cash-flow hedges. To qualify for hedge accounting,
the derivative must qualify as either a fair-value, cash-flow or
foreign-currency hedge.
The hedging relationship between the hedging instruments and
hedged items must be highly effective in achieving the offset of
changes in fair values or cash flows attributable to the hedged
risk, both at the inception of the hedge and on an ongoing
basis. The Company measures hedge effectiveness on a quarterly
basis. Hedge accounting is discontinued prospectively if and
when a hedging instrument becomes ineffective. The Company
assesses hedge effectiveness based on total changes in the fair
value of its derivative instruments. Gains and losses deferred
in Accumulated Other Comprehensive Income related to cash-flow
hedge derivatives that become ineffective remain unchanged until
the related production is delivered. Adjustment to the carrying
amounts of hedged items is discontinued in instances where the
related fair-value hedging instrument becomes ineffective. The
balance in the fair-value hedge adjustment account
46
BURLINGTON RESOURCES INC.
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
is recognized in income when the hedged item is sold. If the
Company determines that it is probable that a hedged forecasted
transaction will not occur, deferred gains or losses on the
related hedging instrument are recognized in earnings
immediately.
Gains and losses on hedging instruments and adjustments of the
carrying amounts of hedged items are included in revenues and
are included in realized prices in the period that the hedged
item is sold. Gains and losses on hedging instruments which
represent hedge ineffectiveness and gains and losses on
derivative instruments which do not qualify for hedge accounting
are included in revenues in the period in which they occur. The
resulting cash flows are reported as cash flows from operating
activities.
Credit and Market Risks
The Company manages and controls market and counterparty credit
risk through established formal internal control procedures
which are reviewed on an ongoing basis. In the normal course of
business, collateral is not required for financial instruments
with credit risk. The Company uses the specific identification
method of providing allowances for doubtful accounts.
Income Taxes
Income taxes are provided based on earnings reported for tax
return purposes in addition to a provision for deferred income
taxes. Deferred income taxes are provided to reflect the tax
consequences in future years of differences between the
financial statement and tax basis of assets and liabilities. Tax
credits are accounted for under the flow-through method, which
reduces the provision for income taxes in the year the tax
credits are earned. A valuation allowance is established to
reduce deferred tax assets if it is more likely than not that
the related tax benefits will not be realized.
Treasury Stock
The Company follows the weighted-average-cost method of
accounting for treasury stock transactions.
Stock-based Compensation
At December 31, 2004, the Company has three stock-based
employee compensation plans, which are described in Note 12
of Notes to Consolidated Financial Statements. The Company uses
the intrinsic value based method of accounting for stock-based
compensation, as prescribed by Accounting Principles Board
Opinion No. 25 and related interpretations. Under this
method, the Company records no compensation expense for stock
options granted when the exercise price for options granted is
equal to the fair market value of the Companys Common
Stock on the date of the grant.
The weighted average fair values of options granted during the
years 2004, 2003 and 2002 were $5.50, $5.43 and $5.42,
respectively. The fair values of employee stock options were
calculated using the Black-Scholes stock option valuation model
that has been modified to include dividends since the Company
has historically paid dividends. Additionally, the Company uses
an expected term for stock options rather than the contractual
term since they are non-transferable and are typically exercised
prior to expiration. The following weighted average assumptions
were used for grants in 2004, 2003 and 2002: stock price
volatility of 26 percent, 32 percent and
31 percent, respectively; risk free rate of return ranging
from 2 percent to 4 percent; dividend yields of
0.89 percent, 1.18 percent and 1.43 percent,
respectively; and an expected term of 3 to 5 years.
47
BURLINGTON RESOURCES INC.
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The following table illustrates the effect on net income and
earnings per share had the Company applied the fair value
recognition provisions of SFAS No. 123, Accounting
for Stock-Based Compensation, to its stock-based employee
compensation.
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
2004 | |
|
2003 | |
|
2002 | |
| |
(In Millions, Except per Share Amounts) | |
| |
Net income as reported
|
|
$ |
1,527 |
|
|
$ |
1,201 |
|
|
$ |
454 |
|
Less: pro forma stock based employee compensation cost, after
tax (unaudited)
|
|
|
10 |
|
|
|
10 |
|
|
|
11 |
|
|
Net income pro forma (unaudited)
|
|
$ |
1,517 |
|
|
$ |
1,191 |
|
|
$ |
443 |
|
|
|
Basic EPS as reported
|
|
$ |
3.90 |
|
|
$ |
3.02 |
|
|
$ |
1.13 |
|
Basic EPS pro forma (unaudited)
|
|
|
3.87 |
|
|
|
2.99 |
|
|
|
1.11 |
|
Diluted EPS as reported
|
|
|
3.86 |
|
|
|
3.00 |
|
|
|
1.13 |
|
Diluted EPS pro forma (unaudited)
|
|
$ |
3.84 |
|
|
$ |
2.98 |
|
|
$ |
1.10 |
|
|
Environmental Costs
Environmental expenditures are expensed or capitalized, as
appropriate, depending on their future economic benefit.
Expenditures that relate to an existing condition caused by past
operations, and that do not have future economic benefit, are
expensed. Liabilities related to future costs are recorded on an
undiscounted basis when environmental assessments and/or
remediation activities are probable and the costs can be
reasonably estimated.
Earnings Per Common Share (EPS)
Basic EPS is computed by dividing income available to common
stockholders by the weighted-average number of common shares
outstanding for the period. The weighted average number of
common shares outstanding for computing basic EPS was
392 million, 398 million and 402 million for the
years ended December 31, 2004, 2003 and 2002, respectively.
Diluted EPS reflects the potential dilution that could occur if
contracts to issue common stock and related stock options were
exercised. The weighted average number of common shares
outstanding for computing diluted EPS, including dilutive stock
options, was 395 million, 400 million and
404 million for the years ended December 31, 2004,
2003 and 2002, respectively. All shares attributable to
outstanding options were dilutive for the year ended
December 31, 2004. For the years ended December 31,
2003 and 2002, approximately 2 million and 8 million
shares, respectively, attributable to the assumed exercise of
outstanding options were excluded from the calculation of
diluted EPS because the effect was antidilutive. The Company has
no preferred stock affecting EPS, and therefore, no adjustments
related to preferred stock were made to reported net income in
the computation of EPS.
Use of Estimates
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 the
reported amounts of revenues and expenses during the reporting
period. The most significant estimates pertain to proved natural
gas, NGLs and crude oil reserves and related cash flow estimates
used in impairment tests of goodwill and other long-lived
assets, estimates of future development, income taxes,
dismantlement and abandonment costs, estimates relating to
certain natural gas, NGLs and crude oil revenues and expenses as
well as estimates of expenses related to legal, environmental
and other contingencies. Actual results could differ from those
estimates.
2. Property Acquisitions and Divestitures
Property Acquisitions
In May 2003, the Company purchased an additional 50 percent
interest in CLAM Petroleum B.V. (CLAM) for
approximately $100 million, including cash acquired at
closing of $25 million, resulting in a total purchase price
for the common equity of approximately $75 million. The
Company owned 50 percent of CLAM prior to the acquisition
and had accounted for its interest under the equity method of
accounting. Effective on the date of acquisition, the Company
began consolidating CLAMs financial results.
48
BURLINGTON RESOURCES INC.
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Divestitures
During 2002, after announcing in late 2001 its intent to sell
properties, the Company completed the sale of a processing
facility and other non-core, non-strategic properties that
consisted of high cost structure, high production volume decline
rates and limited growth opportunities. As a result of this
divestiture program, the Company generated proceeds, before
post-closing adjustments, of approximately $1.2 billion and
recognized a net pretax gain of $68 million in 2002. The
Company used a portion of the proceeds generated from property
sales to retire debt and for general corporate purposes.
3. Accounts Receivable
Accounts receivable consisted of the following.
|
|
|
|
|
|
|
|
|
|
December 31, |
|
2004 | |
|
2003 | |
| |
|
|
(In Millions) | |
| |
Natural gas, NGLs and crude oil revenue sales
|
|
$ |
848 |
|
|
$ |
508 |
|
Joint interest billings
|
|
|
99 |
|
|
|
93 |
|
Income tax receivable
|
|
|
35 |
|
|
|
|
|
Other
|
|
|
25 |
|
|
|
17 |
|
|
|
|
|
1,007 |
|
|
|
618 |
|
Less: allowance for doubtful accounts
|
|
|
13 |
|
|
|
13 |
|
|
|
Accounts receivable
|
|
$ |
994 |
|
|
$ |
605 |
|
|
4. Goodwill
The entire goodwill balance of $1,054 million at
December 31, 2004, which is not deductible for tax
purposes, is related to the Companys acquisition of Hunter
in December 2001. With the acquisition of Hunter, the Company
gained Hunters significant interest in Canadas Deep
Basin, North Americas third-largest natural gas field,
increased its critical mass and enhanced its position as a
leading North American natural gas producer. The Company also
obtained the exploration expertise of Hunters workforce,
gained additional cost optimization, increased purchasing power
and gained greater marketing flexibility in optimizing sales and
accessing key market information. The goodwill was assigned to
the Companys Canadian reporting unit which includes all of
the Companys Canadian subsidiaries.
The provisions of SFAS No. 142 require that a two-step
impairment test be performed annually or whenever events or
changes in circumstances indicate that the carrying value of an
asset may not be recoverable. The first step of the test for
impairment compares the book value of the Companys
reporting unit to its estimated fair value. The second step of
the goodwill impairment test, which is only required when the
net book value of the reporting unit exceeds the fair value,
compares the implied fair value of goodwill to its book value to
determine if an impairment is required.
The Company performed step one of its annual goodwill impairment
test in the fourth quarter of 2004 and determined that the fair
value of the Companys Canadian reporting unit exceeded its
net book value as of September 30, 2004. Therefore, step
two was not required.
The fair value of the Companys Canadian reporting unit was
determined using a combination of the income approach and the
market approach. Under the income approach, the Company
estimated the fair value of the reporting unit based on the
present value of expected future cash flows. Under the market
approach, the Company estimated the fair value based on market
multiples of reserves and production for comparable companies as
well as recent comparable transactions.
The income approach is dependent on a number of factors
including estimates of forecasted revenue and costs, proved
reserves, as well as the success of future exploration for and
development of unproved reserves, appropriate discount rates and
other variables. Downward revisions of estimated reserve
quantities, increases in future cost estimates, divestiture of a
significant component of the reporting unit, continued weakening
of the U.S. dollar, or depressed natural gas, NGLs and
crude oil prices could lead to an impairment of all or a portion
of goodwill in future periods. In the market approach, the
Company makes certain judgments about the selection of
comparable companies, comparable recent company and asset
transactions and transaction premiums. Although the Company
based its fair value estimate on
49
BURLINGTON RESOURCES INC.
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
assumptions it believes to be reasonable, those assumptions are
inherently unpredictable and uncertain. In 2004, the Company
used a professional valuation services firm to assist in
preparing its annual valuation of goodwill.
The following table reflects the changes in the carrying amount
of goodwill during the year as it relates to the Canadian
reporting unit.
|
|
|
|
|
|
|
(In Millions) | |
| |
December 31, 2003
|
|
$ |
982 |
|
Changes in foreign exchange rates during the period
|
|
|
72 |
|
|
December 31, 2004
|
|
$ |
1,054 |
|
|
5. Oil and Gas and Other Properties
Oil and gas properties consisted of the following.
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
2004 | |
|
2003 | |
| |
|
|
(In Millions) | |
| |
Proved properties
|
|
$ |
16,662 |
|
|
$ |
14,588 |
|
|
Less: Accumulated depreciation, depletion and amortization
|
|
|
7,882 |
|
|
|
6,573 |
|
|
Proved propertiesnet
|
|
|
8,780 |
|
|
|
8,015 |
|
|
Unproved properties
|
|
|
|
|
|
|
|
|
|
Leasehold acquisition costs
|
|
|
536 |
|
|
|
495 |
|
|
Unproved reserves
|
|
|
745 |
|
|
|
879 |
|
|
Less: Accumulated amortization
|
|
|
152 |
|
|
|
97 |
|
|
Unproved propertiesnet
|
|
|
1,129 |
|
|
|
1,277 |
|
|
|
|
Oil and gas propertiesnet
|
|
$ |
9,909 |
|
|
$ |
9,292 |
|
|
The following table reflects the net changes in capitalized
exploratory well costs pending proved reserve determination.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2004 | |
|
2003 | |
|
2002 | |
| |
|
|
(In Millions) | |
| |
Balance at January 1,
|
|
$ |
29 |
|
|
$ |
30 |
|
|
$ |
19 |
|
|
Additions
|
|
|
18 |
|
|
|
8 |
|
|
|
19 |
|
|
Reclassifications to proved properties
|
|
|
(10 |
) |
|
|
(2 |
) |
|
|
(7 |
) |
|
Charged to expense
|
|
|
(14 |
) |
|
|
(7 |
) |
|
|
(1 |
) |
|
Balance at December 31,
|
|
$ |
23 |
|
|
$ |
29 |
|
|
$ |
30 |
|
|
Capitalized less than one year since completion of drilling
|
|
$ |
22 |
|
|
|
|
|
|
|
|
|
Capitalized more than one year since completion of drilling(1)
|
|
$ |
1 |
|
|
|
|
|
|
|
|
|
|
|
(1) |
At December 31, 2004, the Company had deferred costs
related to one well that has been completed for more than a year
while the Company has actively been pursuing the necessary
permits and pipeline connection. |
Other properties consisted of the following.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciable | |
|
|
|
|
December 31, |
|
Life-Years | |
|
2004 | |
|
2003 | |
| |
|
|
(In Millions) | |
| |
Plants and pipeline systems
|
|
|
10-20 |
|
|
$ |
1,139 |
|
|
$ |
1,018 |
|
Land, buildings, improvements and furniture and fixtures
|
|
|
0-40 |
|
|
|
139 |
|
|
|
128 |
|
Data processing and telecommunications equipment
|
|
|
3-7 |
|
|
|
184 |
|
|
|
159 |
|
Other
|
|
|
3-15 |
|
|
|
82 |
|
|
|
76 |
|
|
|
|
|
|
|
|
|
1,544 |
|
|
|
1,381 |
|
Less: Accumulated depreciation
|
|
|
|
|
|
|
420 |
|
|
|
362 |
|
|
|
Other properties net
|
|
|
|
|
|
$ |
1,124 |
|
|
$ |
1,019 |
|
|
50
BURLINGTON RESOURCES INC.
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
6. Accounts Payable
Accounts payable consisted of the following.
|
|
|
|
|
|
|
|
|
|
December 31, |
|
2004 | |
|
2003 | |
| |
|
|
(In Millions) | |
| |
Trade payables
|
|
$ |
89 |
|
|
$ |
67 |
|
Accrued expenses
|
|
|
828 |
|
|
|
478 |
|
Revenues and royalties payable to others
|
|
|
192 |
|
|
|
98 |
|
Accrued payroll
|
|
|
56 |
|
|
|
44 |
|
Other
|
|
|
17 |
|
|
|
27 |
|
|
|
Accounts payable
|
|
$ |
1,182 |
|
|
$ |
714 |
|
|
7. Income Taxes
The jurisdictional components of income before income taxes and
cumulative effect of change in accounting principle follow.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
2004 | |
|
2003 | |
|
2002 | |
| |
|
|
(In Millions) | |
| |
Domestic
|
|
$ |
1,357 |
|
|
$ |
983 |
|
|
$ |
548 |
|
Foreign
|
|
|
947 |
|
|
|
587 |
|
|
|
21 |
|
|
|
Total
|
|
$ |
2,304 |
|
|
$ |
1,570 |
|
|
$ |
569 |
|
|
The provision for income taxes follows.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
2004 | |
|
2003 | |
|
2002 | |
| |
|
|
(In Millions) | |
| |
Current
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Federal
|
|
$ |
171 |
|
|
$ |
84 |
|
|
$ |
37 |
|
|
State
|
|
|
43 |
|
|
|
9 |
|
|
|
11 |
|
|
Foreign
|
|
|
192 |
|
|
|
67 |
|
|
|
28 |
|
|
|
|
|
406 |
|
|
|
160 |
|
|
|
76 |
|
|
Deferred
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Federal
|
|
|
175 |
|
|
|
85 |
|
|
|
63 |
|
|
State
|
|
|
(4 |
) |
|
|
6 |
|
|
|
4 |
|
|
Foreign
|
|
|
200 |
|
|
|
59 |
|
|
|
(28 |
) |
|
|
|
|
371 |
|
|
|
150 |
|
|
|
39 |
|
|
|
|
Total
|
|
$ |
777 |
|
|
$ |
310 |
|
|
$ |
115 |
|
|
Reconciliation of the federal statutory income tax rate to the
effective income tax rate follows.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
2004 | |
|
2003 | |
|
2002 | |
| |
U.S. statutory rate
|
|
|
35.0 |
% |
|
|
35.0 |
% |
|
|
35.0 |
% |
State income taxes (net of federal benefit)
|
|
|
1.0 |
|
|
|
0.6 |
|
|
|
1.7 |
|
Taxes on foreign income in excess of U.S. statutory rate
|
|
|
3.6 |
|
|
|
3.9 |
|
|
|
9.4 |
|
Effect of change in foreign income tax rate(1)
|
|
|
(2.9 |
) |
|
|
(13.6 |
) |
|
|
(2.3 |
) |
Section 29 tax credits(2)
|
|
|
(0.4 |
) |
|
|
(1.7 |
) |
|
|
(0.2 |
) |
Cross-border financing benefit(3)
|
|
|
(4.5 |
) |
|
|
(6.2 |
) |
|
|
(15.1 |
) |
Other(4)
|
|
|
1.9 |
|
|
|
1.7 |
|
|
|
(8.4 |
) |
|
|
Effective rate
|
|
|
33.7 |
% |
|
|
19.7 |
% |
|
|
20.1 |
% |
|
51
BURLINGTON RESOURCES INC.
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
(1) In 2003, the government of Canada passed Bill C-48
that reduced the Canadian federal income tax rate for companies
in the natural resource sector. The rate reduction takes effect
over a five-year period from 2003 to 2007 and resulted in
benefits to the Company of $23 million (-1.0%) and
$203 million (-12.9%) in 2004 and 2003, respectively. The
Company also recorded a benefit of $45 million (-1.9%),
$11 million (-0.7%) and $26 million (-4.5%) in 2004,
2003 and 2002, respectively, due to reductions in the Alberta
provincial corporate income tax rate in Canada. In 2002, the
Company recorded an expense of $12 million (2.2%) related
to an increase in the U.K.s income tax rate.
(2) In 2004, a tax benefit associated with Section 29
Tax Credits was provided in the amount of $10 million
(-0.4%) as a result of the finalization of the 1999-2000 federal
income tax audits. In 2003, a tax benefit associated with
Section 29 Tax Credits was provided in the amount of
$27 million (-1.7%) as a result of an appeal proceeding
related to the 1996-1998 income tax audits. In 2002, the tax
benefit associated with Section 29 Tax Credits was reduced
by $16 million (2.9%) as a result of the 1996-1998 federal
income tax audits.
(3) The Company recorded benefits of $104 million,
$97 million and $86 million in 2004, 2003 and 2002,
respectively, related to interest deductions allowed in both the
U.S. and Canada. The deduction for interest on the cross-border
financing is allowable in both the U.S. and Canada because the
issuer of the debt is a wholly owned finance subsidiary of the
Company and the activities of the finance subsidiary are taxable
in both the U.S. and Canada.
(4) In 2004, the Company recorded a U.S. tax liability of
$26 million (1.1%) related to the planned repatriation of
$500 million of eligible foreign earnings to the U.S. in
2005 under the one-time provisions of the American Jobs Creation
Act of 2004. In 2002, this rate primarily consisted of the
reversal of a $27 million (-4.8%) tax valuation reserve
related to the sale of assets in the U.K. Sector of the North
Sea.
Deferred income tax liabilities (assets) follow.
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
2004 | |
|
2003 | |
|
|
| |
|
|
(In Millions) | |
| |
Deferred income tax liabilities
|
|
|
|
|
|
|
|
|
|
Property, plant and equipment
|
|
$ |
2,175 |
|
|
$ |
1,972 |
|
|
Financial accruals and other
|
|
|
590 |
|
|
|
391 |
|
|
|
|
|
2,765 |
|
|
|
2,363 |
|
|
Deferred income tax assets
|
|
|
|
|
|
|
|
|
|
Alternative minimum tax (AMT) credit
carryforward
|
|
|
(161 |
) |
|
|
(277 |
) |
|
Foreign net operating loss carryforward
|
|
|
(171 |
) |
|
|
(150 |
) |
|
Commodity hedging contracts and other derivatives
|
|
|
13 |
|
|
|
(13 |
) |
|
|
|
|
(319 |
) |
|
|
(440 |
) |
|
Less: valuation allowance
|
|
|
15 |
|
|
|
25 |
|
|
|
|
Deferred income taxes
|
|
$ |
2,461 |
|
|
$ |
1,948 |
|
|
At December 31, 2004, $48 million of the deferred
income tax liability is classified as current and is included in
Taxes Payable on the Companys Consolidated Balance Sheet.
Also, $17 million of the deferred income tax liability
related to income tax reserves is included in Other Liabilities
and Deferred Credits. The net deferred income tax liabilities at
December 31, 2004 and 2003 include deferred state income
tax liabilities of approximately $51 million and
$56 million, respectively. The net deferred income tax
liabilities also include foreign tax liabilities of
approximately $1,872 million and $1,564 million at
December 31, 2004 and 2003, respectively.
No deferred U.S. income tax liability has been recognized
on undistributed earnings of certain foreign subsidiaries as
they have been deemed permanently invested outside the U.S., and
it is not practicable to estimate the deferred tax liability
related to such undistributed earnings. At December 31,
2004, undistributed earnings for which a U.S. deferred
income tax liability has not been recognized total
$1,079 million. The Company plans to repatriate
$500 million of eligible foreign earnings to the
U.S. Company in 2005 under the one-time provisions of the
American Jobs Creation Act of 2004. Included in Taxes Payable at
December 31, 2004 are accrued U.S. taxes of
$26 million related to this planned repatriation. Not
included in undistributed earnings at December 31, 2004 are
permanent differences of $875 million that would result in
taxable income in the U.S. if an amount greater than the
retained earnings of the Companys Canadian subsidiaries
was distributed to the U.S.
52
BURLINGTON RESOURCES INC.
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The AMT credit carryforward, related primarily to
Section 29 Tax Credits, is available to offset future
federal income tax liabilities. The AMT credit carryforward has
no expiration date. Of the $171 million tax benefit for
operating loss carryforwards, all of which relates to foreign
jurisdictions, $106 million has no expiration date and
$65 million will expire in 2010.
|
|
8. |
Commodity Hedging Contracts and Other Derivatives |
The Company uses derivative instruments to manage risks
associated with natural gas and crude oil price volatility as
well as interest rate fluctuations. Derivative instruments that
meet the hedge criteria in SFAS No. 133 are designated
as cash-flow hedges or fair-value hedges. Derivative instruments
that do not meet the hedge criteria in SFAS No. 133
are not designated as hedges. Derivative instruments designated
as cash-flow hedges are used by the Company to mitigate the risk
of variability in cash flows from natural gas and crude oil
sales due to changes in market prices. Fair-value hedges are
used by the Company to hedge or offset the exposure to changes
in the fair value of a recognized asset or liability or an
unrecognized firm commitment.
Cash-Flow Hedges
At December 31, 2004, the Companys cash-flow hedges
consisted of fixed-price swaps and producer collars (purchased
put options and written call options). The fixed-price swap
agreements are used to fix the prices of anticipated future
natural gas production. The producer collars are used to
establish floor and ceiling prices on anticipated future natural
gas and crude oil production. There were no net premiums
received when the Company entered into these option agreements.
Fair-Value Hedges
At December 31, 2004, the Companys fair-value hedges
consisted of commodity price swaps and interest rate swaps. The
Companys commodity price swaps are used to hedge against
changes in the fair value of unrecognized firm commitments
representing physical contracts that require the delivery of a
specified quantity of natural gas or crude oil at a fixed price
over a specified period of time. The swap agreements allow the
Company to receive market prices for the committed specified
quantities included in the physical contracts.
At December 31, 2004, the Company has interest rate swap
agreements with an aggregate notional amount of $50 million
related to principal amounts of $50 million,
5.6% Notes due December 1, 2006. The objective of
these transactions is to protect the designated debt against
changes in fair value due to changes in the benchmark interest
rate, which was designated as six-month LIBOR. Under the
interest rate swap agreements, the Company receives a fixed rate
equal to 5.6% per annum and pays the benchmark interest
rate plus 3.36 percent. Interest expense on the debt is
adjusted to reflect payments made or received under the hedge
agreements.
As of December 31, 2004, the Company had the following
commodity related derivative instruments outstanding with
average underlying prices that represent hedged prices of
commodities at various market locations.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Notional Amount |
|
|
|
Fair Value | |
|
|
|
|
|
|
|
|
Average | |
|
Asset | |
Settlement | |
|
Derivative |
|
Hedge |
|
Gas |
|
Oil |
|
Underlying | |
|
(Liability) | |
Period | |
|
Instrument |
|
Strategy |
|
(MMBTU) |
|
(Barrels) |
|
Prices | |
|
(In Millions) | |
| |
|
2005 |
|
|
Swap |
|
Cash flow |
|
11,411,522 |
|
|
|
$ |
4.06 |
|
|
$ |
(16 |
) |
|
|
|
|
Purchased put |
|
Cash flow |
|
95,472,358 |
|
|
|
|
5.82 |
|
|
|
56 |
|
|
|
|
|
Written call |
|
Cash flow |
|
95,472,358 |
|
|
|
|
7.82 |
|
|
|
(16 |
) |
|
|
|
|
Purchased put |
|
Cash flow |
|
|
|
3,795,000 |
|
|
41.81 |
|
|
|
16 |
|
|
|
|
|
Written call |
|
Cash flow |
|
|
|
3,795,000 |
|
|
53.79 |
|
|
|
(5 |
) |
|
|
|
|
Swap |
|
Fair value |
|
2,324,200 |
|
|
|
|
3.92 |
|
|
|
4 |
|
|
|
|
|
N/A |
|
Fair value (obligation) |
|
2,324,200 |
|
|
|
|
3.92 |
|
|
|
(4 |
) |
|
|
|
|
Swap |
|
Not designated |
|
5,350,000 |
|
|
|
|
(0.09 |
) |
|
|
|
|
|
|
2006 |
|
|
Swap |
|
Cash flow |
|
912,500 |
|
|
|
|
3.06 |
|
|
|
(2 |
) |
|
|
2007 |
|
|
Swap |
|
Cash flow |
|
760,000 |
|
|
|
$ |
3.06 |
|
|
|
(2 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
31 |
|
|
53
BURLINGTON RESOURCES INC.
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
As of December 31, 2004, the Company had the following
derivative instruments outstanding related to interest rate
swaps.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Notional | |
|
Average | |
|
Average |
|
Fair Value | |
Settlement | |
|
Derivative |
|
Hedge |
|
Amount | |
|
Underlying | |
|
Floating |
|
Liability | |
Period | |
|
Instrument |
|
Strategy |
|
(In Millions) | |
|
Rate | |
|
Rate |
|
(In Millions) | |
| |
|
2005 |
|
|
Interest rate swap |
|
Fair value |
|
$ |
50 |
|
|
|
5.6% |
|
|
LIBOR + 3.36% |
|
$ |
|
|
|
|
2006 |
|
|
Interest rate swap |
|
Fair value |
|
$ |
50 |
|
|
|
5.6% |
|
|
LIBOR + 3.36% |
|
|
(1 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
(1 |
) |
|
The derivative assets and liabilities represent the market
values of the Companys derivative instruments as of
December 31, 2004. During the years ended 2004, 2003 and
2002, hedging activities related to cash settlements decreased
revenues $40 million, $63 million and increased
revenues $114 million, respectively. In addition, during
2004, 2003 and 2002, gains of $2 million, and losses of
$200 thousand and $22 million, respectively, were recorded
in revenues associated with ineffectiveness of cash-flow and
fair-value hedges. During 2004, 2003 and 2002, gains of
$1 million, $9 million and losses of $10 million,
respectively, were recorded in revenues related to changes in
fair value of derivative instruments which do not qualify for
hedge accounting.
Changes in other comprehensive income for the three years ended
December 31, 2004 follow.
|
|
|
|
|
|
|
|
(In Millions) | |
| |
Accumulated other comprehensive income on hedging
activitiesDecember 31, 2001
|
|
$ |
54 |
|
|
Reclassification adjustments for settled contracts
|
|
|
(68 |
) |
|
Current period changes in fair value of settled contracts
|
|
|
20 |
|
|
Changes in fair value of outstanding hedging positions
|
|
|
(38 |
) |
|
Accumulated other comprehensive loss on hedging
activitiesDecember 31, 2002
|
|
|
(32 |
) |
|
Reclassification adjustments for settled contracts
|
|
|
39 |
|
|
Current period changes in fair value of settled contracts
|
|
|
(18 |
) |
|
Changes in fair value of outstanding hedging positions
|
|
|
(10 |
) |
|
Accumulated other comprehensive loss on hedging
activitiesDecember 31, 2003
|
|
|
(21 |
) |
|
Reclassification adjustments for settled contracts
|
|
|
24 |
|
|
Current period changes in fair value of settled contracts
|
|
|
(8 |
) |
|
Changes in fair value of outstanding hedging positions
|
|
|
25 |
|
|
Accumulated other comprehensive income on hedging
activitiesDecember 31, 2004
|
|
$ |
20 |
|
|
Based on commodity prices and foreign exchange rates as of
December 31, 2004, the Company expects to reclassify gains
of $33 million ($20 million after tax) to earnings
from the balance in Accumulated Other Comprehensive Income
during the next twelve months. At December 31, 2004, the
Company had derivative assets of $62 million and derivative
liabilities of $32 million of which $62 million,
$27 million and $5 million is included in Other
Current Assets, Other Current Liabilities and Other Liabilities
and Deferred Credits, respectively, on the Consolidated Balance
Sheet.
54
BURLINGTON RESOURCES INC.
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Long-term debt follows.
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
2004 | |
|
2003 | |
| |
|
|
(In Millions) | |
| |
Notes, 5.60%, due 2006
|
|
$ |
500 |
|
|
$ |
500 |
|
Notes, 6.60%, due 2007(1)
|
|
|
124 |
|
|
|
116 |
|
Notes, 5.70%, due 2007
|
|
|
350 |
|
|
|
350 |
|
Debentures,
97/8%,
due 2010
|
|
|
150 |
|
|
|
150 |
|
Notes, 6.50%, due 2011
|
|
|
500 |
|
|
|
500 |
|
Notes, 6.68%, due 2011
|
|
|
400 |
|
|
|
400 |
|
Notes, 6.40%, due 2011
|
|
|
178 |
|
|
|
178 |
|
Debentures,
75/8%,
due 2013
|
|
|
100 |
|
|
|
100 |
|
Debentures,
91/8%,
due 2021
|
|
|
150 |
|
|
|
150 |
|
Debentures, 7.65%, due 2023
|
|
|
88 |
|
|
|
88 |
|
Debentures, 8.20%, due 2025
|
|
|
150 |
|
|
|
150 |
|
Debentures,
67/8%,
due 2026
|
|
|
67 |
|
|
|
67 |
|
Debentures,
73/8%,
due 2029
|
|
|
92 |
|
|
|
92 |
|
Notes, 7.20%, due 2031
|
|
|
575 |
|
|
|
575 |
|
Notes, 7.40%, due 2031
|
|
|
500 |
|
|
|
500 |
|
Capital lease
|
|
|
6 |
|
|
|
|
|
Discounts and other
|
|
|
(41 |
) |
|
|
(43 |
) |
|
|
Total debt
|
|
|
3,889 |
|
|
|
3,873 |
|
|
|
Less current maturities
|
|
|
2 |
|
|
|
|
|
|
|
Total long-term debt
|
|
$ |
3,887 |
|
|
$ |
3,873 |
|
|
|
|
(1) |
Notes are denominated in Canadian dollars and reported in
U.S. dollars. |
The Company has debt maturities of $2 million due in 2005,
$502 million due in 2006, $475 million due in 2007,
$1 million due in 2008 and $2,950 million due in 2010
and thereafter. The fair value of debt outstanding as of
December 31, 2004 and 2003 was $4,528 million and
$4,483 million, respectively.
Burlington Resources Capital Trust I, Burlington Resources
Capital Trust II (collectively, the Trusts), BR
and Burlington Resources Finance Company (BRFC) have
a shelf registration of $1,500 million on file with the
Securities and Exchange Commission (SEC). Pursuant
to the registration statement, BR may issue debt securities,
shares of common stock or preferred stock. In addition, BRFC may
issue debt securities and the Trusts may issue trust preferred
securities. Net proceeds, terms and pricing of offerings of
securities issued under the shelf registration statement will be
determined at the time of the offerings. BRFC and the Trusts are
wholly owned finance subsidiaries of BR and have no independent
assets or operations other than transferring funds to BRs
subsidiaries. Any debt issued by BRFC is fully and
unconditionally guaranteed by BR. Any trust preferred securities
issued by the Trusts are also fully and unconditionally
guaranteed by BR.
The Company has a $1.5 billion revolving credit facility
(Credit Facility) that includes (i) a
US$500 million Canadian subfacility and (ii) a
US$750 million sublimit for the issuance of letters of
credit, including up to US$250 million in letters of credit
under the Canadian subfacility. The Credit Facility expires in
July 2009 unless extended. Under the covenants of the Credit
Facility, Company debt cannot exceed 60 percent of
capitalization (as defined in the agreements). The Credit
Facility is available to cover debt due within one year,
therefore commercial paper, credit facility notes and fixed-rate
debt due within one year are generally classified as long-term
debt. At December 31, 2004, there were no amounts
outstanding under the Credit Facility and no outstanding
commercial paper.
At the Companys option, interest on borrowings under the
Credit Facility is based on the prime rate, Eurodollar rates or
absolute rates. The Canadian subfacility bears interest at rates
based on prime, Eurodollar or absolute rates also at the
Companys option. The Company also has the option under the
Canadian subfacility to request borrowings by way of
bankers acceptances.
The Companys access to funds from its Credit Facility is
not restricted under any material adverse condition
clauses. These clauses typically remove the obligation of the
lenders to fund the credit line if any condition or event would
reasonably be expected to have a material and adverse effect on
the borrowers financial condition, operations or
properties considered as a whole, the borrowers ability to
make timely debt payments, or the enforceability of material
55
BURLINGTON RESOURCES INC.
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
items of the credit agreement. While the Companys Credit
Facility includes a covenant that requires the Company to report
litigation or a proceeding that the Company has determined is
likely to have a material adverse effect on the consolidated
financial condition of the Company, the obligation of the
lenders to fund the Credit Facility is not conditioned on the
absence of such litigation or proceeding.
The Company has a closed deferred compensation plan funded by
Company-owned life insurance policies that were entered into by
LL&E prior to being acquired by BR. Outstanding borrowings
of $160 million and $148 million as of
December 31, 2004 and 2003, respectively, on these life
insurance policies were reported as a reduction to the cash
surrender value and are included as a component of Other Assets
on the Companys Consolidated Balance Sheet.
|
|
10. |
Asset Retirement Obligations |
On January 1, 2003, the Company adopted
SFAS No. 143, Asset Retirement Obligations.
SFAS No. 143 requires entities to record the fair
value of a liability for an asset retirement obligation in the
period in which it is incurred and a corresponding increase in
the carrying amount of the related long-lived asset.
Subsequently, the asset retirement costs included in the
carrying amount of the related asset is allocated to expense
through depreciation or depletion of the asset. The majority of
the Companys asset retirement obligations relate to
plugging and abandoning oil and gas wells and related equipment
as well as dismantling plants. During the first quarter of 2003,
the Company recorded a net-of-tax cumulative effect of change in
accounting principle charge of $59 million
($95 million before tax), increased long-term liabilities
$191 million, net properties $96 million and deferred
tax assets $36 million in accordance with the transition
provisions of SFAS No. 143. There was no impact on the
Companys cash flows as a result of adopting
SFAS No. 143. The asset retirement obligations, which
are included on the Companys Consolidated Balance Sheet in
Other Liabilities and Deferred Credits, were $468 million
and $442 million at December 31, 2004 and 2003,
respectively. Accretion expense for 2004 was $27 million
and is included in Depreciation, Depletion and Amortization
expense on the Companys Consolidated Statement of Income.
The following table reflects the changes in the Companys
asset retirement obligations during the current year.
|
|
|
|
|
|
|
|
(In Millions) | |
| |
Carrying amount of asset retirement obligations as of
December 31, 2003
|
|
$ |
442 |
|
|
Liabilities incurred during the period
|
|
|
56 |
|
|
Liabilities settled during the period
|
|
|
(20 |
) |
|
Current year accretion expense
|
|
|
27 |
|
|
Revisions in estimated cash flows
|
|
|
(62 |
) |
|
Changes in foreign exchange rates during the period
|
|
|
25 |
|
|
Carrying amount of asset retirement obligations as of
December 31, 2004
|
|
$ |
468 |
|
|
The following table shows the pro forma effect on the
Companys net income and earnings per share, had
SFAS No. 143 been applied during the year ended
December 31, 2002.
|
|
|
|
|
|
|
(In Millions, | |
|
|
Except per | |
|
|
Share | |
|
|
Amounts) | |
| |
Net income as reported
|
|
$ |
454 |
|
Less: pro forma amounts assuming SFAS No. 143 was
applied retroactively (unaudited)
|
|
|
9 |
|
|
Net income pro forma (unaudited)
|
|
$ |
445 |
|
|
Basic earnings per share as reported
|
|
$ |
1.13 |
|
Basic earnings per share pro forma (unaudited)
|
|
|
1.11 |
|
Diluted earnings per share as reported
|
|
|
1.13 |
|
Diluted earnings per share pro forma (unaudited)
|
|
$ |
1.10 |
|
|
|
|
11. |
Significant Concentrations |
In 2004, 2003 and 2002, approximately 48 percent,
49 percent and 43 percent, respectively, of the
Companys natural gas production was transported through
pipeline systems owned by El Paso Natural Gas Company
(EPNG) and TransCanada Pipelines Limited
(TCPL). Mechanical failure and regulatory action at
certain points on the EPNG pipeline system could result in a
substantial interruption of the transportation of the
Companys natural gas production
56
BURLINGTON RESOURCES INC.
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
for a limited period of time in the San Juan Basin. TCPL,
through its subsidiary, Nova Gas Transmission Ltd., gathers and
transports a majority of the Companys Canadian gas
production from multiple receipt points to multiple delivery
points on their pipeline system. The interruption of gathering
or transportation at any individual receipt point or delivery
point would not have a material impact on the overall
transportation of the Companys Canadian production. The
Company takes steps to mitigate these risks through commercial
insurance and identification of alternative pipeline
transportation. The Company expects to continue to transport a
substantial portion of its future natural gas production through
these pipeline systems. See Note 14 of Notes to
Consolidated Financial Statements for demand charges paid under
firm and interruptible transportation capacity rights on
pipeline systems.
During the year ended December 31, 2004, sales to BP and
ConocoPhillips accounted for approximately 12 percent and
10 percent, respectively, of the Companys total
revenues. Management believes that the loss of either of these
customers would not have a material adverse effect on its
results of operations or its financial position since the market
for the Companys production is highly liquid with other
willing buyers, including potential additional sales to existing
customers, other than the two named above. During the years
ended December 31, 2003 and 2002, no customer accounted for
more than 10 percent of total revenues.
Substantially all of the Companys accounts receivable at
December 31, 2004 and 2003 result from sales of natural
gas, NGLs and crude oil as well as joint interest billings to
third party companies also in the oil and gas industry. This
concentration of customers and joint interest owners may impact
the Companys overall credit risk, either positively or
negatively, in that these entities may be similarly affected by
changes in economic or other conditions. At December 31,
2004, 11 percent of the Companys accounts receivable
balance was due from BP.
On January 21, 2004, the Companys Board of Directors
approved a 2-for-1 split on the Companys Common Stock in
the form of a share distribution, subject to shareholder
approval of an amendment to the Companys Certificate of
Incorporation to increase the number of authorized shares of the
Companys Common Stock from 325 million to
650 million. On April 21, 2004, the Companys
shareholders approved the amendment. As a result, the split was
paid in the form of a share distribution on June 1, 2004 to
shareholders of record on May 5, 2004. The effect on the
December 31, 2003 balance sheet was to reduce Paid-in
Capital by $2.4 million and increase Common Stock by
$2.4 million. All prior period Common Stock and applicable
share and per share amounts have been retroactively adjusted to
reflect the split.
The Companys Common Stock activity follows.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Number of Shares | |
|
|
| |
|
|
Issued | |
|
Treasury | |
|
Outstanding | |
| |
December 31, 2001
|
|
|
482,377,376 |
|
|
|
(80,791,390 |
) |
|
|
401,585,986 |
|
|
Shares issued under compensation plans, net of forfeitures
|
|
|
|
|
|
|
484,432 |
|
|
|
484,432 |
|
|
Option exercises
|
|
|
|
|
|
|
808,096 |
|
|
|
808,096 |
|
|
December 31, 2002
|
|
|
482,377,376 |
|
|
|
(79,498,862 |
) |
|
|
402,878,514 |
|
|
Treasury shares purchased
|
|
|
|
|
|
|
(14,829,980 |
) |
|
|
(14,829,980 |
) |
|
Shares issued under compensation plans, net of forfeitures
|
|
|
|
|
|
|
476,168 |
|
|
|
476,168 |
|
|
Option exercises
|
|
|
|
|
|
|
6,772,904 |
|
|
|
6,772,904 |
|
|
December 31, 2003
|
|
|
482,377,376 |
|
|
|
(87,079,770 |
) |
|
|
395,297,606 |
|
|
Treasury shares purchased
|
|
|
|
|
|
|
(14,358,000 |
) |
|
|
(14,358,000 |
) |
|
Treasury shares cancelled
|
|
|
(506 |
) |
|
|
506 |
|
|
|
|
|
|
Shares issued under compensation plans, net of forfeitures
|
|
|
|
|
|
|
418,731 |
|
|
|
418,731 |
|
|
Option exercises
|
|
|
|
|
|
|
6,583,132 |
|
|
|
6,583,132 |
|
|
December 31, 2004
|
|
|
482,376,870 |
|
|
|
(94,435,401 |
) |
|
|
387,941,469 |
|
|
Stock Compensation Plans
The Companys 2002 Stock Incentive Plan (2002
Plan) succeeds its 1993 Stock Incentive Plan (1993
Plan) which expired by its terms in April 2002 but remains
in effect for options granted prior to April 2002. The 2002 Plan
provides for the grant of stock options, restricted stock and
stock appreciation rights (collectively, 2002
Awards).
57
BURLINGTON RESOURCES INC.
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Under the 2002 Plan, options may be granted to officers and key
employees at fair market value on the date of grant, are
exercisable in whole or part by the optionee after completion of
at least one year of continuous employment from the grant date
and have a term of ten years. The total number of shares of the
Companys Common Stock for which 2002 Awards under the 2002
Plan may be granted is 15,000,000. At December 31, 2004,
10,323,845 shares were available for grant under the 2002
Plan.
In 1997, the Company adopted the 1997 Employee Stock Incentive
Plan (1997 Plan) from which stock options and
restricted stock (collectively, 1997 Awards) may be
granted to employees who are not eligible to participate in the
plans adopted for officers and key employees. The options are
granted at fair market value on the grant date, generally vest
ratably over a period of three years from the date of the grant
and have a term of ten years. The 1997 Plan was amended during
2002 to limit the maximum number of shares of the Companys
Common Stock for which 1997 Awards under the 1997 Plan may be
granted after April 2002 to 10,000,000 shares. At
December 31, 2004, 8,087,224 shares were available for
grant under the 1997 Plan, of which up to 300,000 shares
annually may be restricted stock.
The Company issued 519,105, 578,850 and 514,050 shares of
restricted stock in 2004, 2003 and 2002, respectively, from the
2002 and 1997 Plans. The restrictions on this stock generally
lapse on the third anniversary of the date of grant. The
weighted average grant-date fair value of restricted stock
granted in the years ended December 31, 2004, 2003, and
2002 was approximately $29.44, $21.04 and $17.87, respectively.
Related compensation expense of approximately $11 million,
$11 million and $9 million was recognized for the
years ended December 31, 2004, 2003 and 2002, respectively.
The Companys 2000 Stock Option Plan (2000
Plan) for Non-Employee Directors provides for the annual
grant of a nonqualified option for 4,000 shares of the
Companys Common Stock immediately following the Annual
Meeting of Stockholders to each Director who is not a salaried
officer of the Company. In addition, an option for
10,000 shares is granted upon a Directors initial
election or appointment to the Board of Directors. The options
vest immediately and have a term of 10 years. The exercise
price per share with respect to each option is the fair market
value, as defined in the 2000 Plan, of the Companys Common
Stock on the date the option is granted. The total number of
shares of the Companys Common Stock for which options may
be granted under the 2000 Plan is 500,000. At December 31,
2004, 262,000 shares were available for grant under the
2000 Plan.
The Companys stock option activity follows.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted | |
|
|
|
|
Average | |
|
|
Options | |
|
Exercise Price | |
| |
December 31, 2001
|
|
|
13,728,516 |
|
|
$ |
21.47 |
|
|
Granted
|
|
|
2,017,700 |
|
|
|
17.82 |
|
|
Exercised
|
|
|
(808,096 |
) |
|
|
15.90 |
|
|
Cancelled
|
|
|
(609,692 |
) |
|
|
22.56 |
|
|
December 31, 2002
|
|
|
14,328,428 |
|
|
|
21.22 |
|
|
Granted
|
|
|
3,955,780 |
|
|
|
21.06 |
|
|
Exercised
|
|
|
(6,772,904 |
) |
|
|
19.44 |
|
|
Cancelled
|
|
|
(562,224 |
) |
|
|
23.55 |
|
|
December 31, 2003
|
|
|
10,949,080 |
|
|
|
22.14 |
|
|
Granted
|
|
|
1,910,600 |
|
|
|
29.48 |
|
|
Exercised
|
|
|
(6,583,132 |
) |
|
|
22.74 |
|
|
Cancelled
|
|
|
(183,314 |
) |
|
|
24.00 |
|
|
December 31, 2004
|
|
|
6,093,234 |
|
|
$ |
23.75 |
|
|
58
BURLINGTON RESOURCES INC.
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The following table summarizes information related to stock
options outstanding and exercisable at December 31, 2004.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted | |
|
|
|
|
|
|
|
|
|
|
Average | |
|
|
|
|
|
|
Range of | |
|
Weighted | |
|
Remaining | |
|
|
|
Weighted | |
Options | |
|
Exercise | |
|
Average | |
|
Contractual | |
|
Options | |
|
Average | |
Outstanding | |
|
Prices | |
|
Exercise Price | |
|
Life | |
|
Exercisable | |
|
Exercise Price | |
| |
|
266,772 |
|
|
$ |
11.66$17.42 |
|
|
$ |
16.21 |
|
|
|
2.6 |
|
|
|
266,772 |
|
|
$ |
16.21 |
|
|
3,976,862 |
|
|
|
17.69 26.02 |
|
|
|
21.59 |
|
|
|
6.9 |
|
|
|
2,820,707 |
|
|
|
21.83 |
|
|
1,849,600 |
|
|
|
29.36 40.65 |
|
|
|
29.48 |
|
|
|
9.1 |
|
|
|
68,000 |
|
|
|
31.92 |
|
|
|
6,093,234 |
|
|
$ |
11.66$40.65 |
|
|
$ |
23.75 |
|
|
|
7.4 |
|
|
|
3,155,479 |
|
|
$ |
21.57 |
|
|
Exercisable stock options and weighted average exercise prices
at December 31, 2003 and 2002 follow.
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted | |
|
|
Options | |
|
Average | |
|
|
Exercisable | |
|
Exercise Price | |
| |
December 31, 2003
|
|
|
6,797,856 |
|
|
$ |
22.54 |
|
December 31, 2002
|
|
|
11,060,298 |
|
|
$ |
21.61 |
|
|
Preferred Stock and Preferred Stock Purchase Rights
The Company is authorized to issue 75,000,000 shares of
preferred stock, par value $.01 per share. On
December 9, 1998, the Companys Board of Directors
designated 3,250,000 of the authorized preferred shares as
Series A Junior Participating Preferred Stock. Upon
issuance, each two-hundredth of a share of Series A Junior
Participating Preferred Stock will have dividend and voting
rights approximately equal to those of one share of Common Stock
of the Company. In addition, on December 9, 1998, the Board
of Directors declared a dividend distribution of one Right for
each outstanding share of Common Stock of the Company to
shareholders of record on December 16, 1998. The Rights
become exercisable if, without the Companys prior consent,
a person or group acquires securities having 15 percent or
more of the voting power of all of the Companys voting
securities (an Acquiring Person) or ten days following the
announcement of a tender offer which would result in such
ownership. Each Right, when exercisable, entitles the registered
holder to purchase from the Company two-hundredth of a share of
Series A Junior Participating Preferred Stock at a price of
$200 per two-hundredth of a share, subject to adjustment.
If, after the Rights become exercisable, the Company were to be
involved in a merger or other business combination in which its
Common Stock was exchanged or changed or 50 percent or more
of the Companys assets or earning power were sold, each
Right would permit the holder to purchase, for the exercise
price, stock of the acquiring company having a value of twice
the exercise price. In addition, except for certain permitted
offers, if any person or group becomes an Acquiring Person, each
Right would permit the purchase, for the exercise price, of
Common Stock of the Company having a value of twice the exercise
price. Rights owned by an Acquiring Person are void. The Rights
may be redeemed by the Company under certain circumstances until
their expiration date for $.01 per Right.
The Companys U.S. pension plans are non-contributory
defined benefit plans covering all eligible U.S. employees.
The benefits are based on years of credited service and final
average compensation. Effective January 1, 2003, the
Company amended its U.S. pension plan to provide cash
balance benefits to new employees. U.S. employees hired
before January 1, 2003, were given the choice to remain in
the prior plan or accrue future benefits under the cash balance
formula. Contributions to the tax qualified plans are limited to
amounts that are currently deductible for tax purposes.
Contributions are intended to provide not only for benefits
attributed to service-to-date but also for those expected to be
earned in the future. Hunter also provides a pension plan and
postretirement benefits to a closed group of employees and
retirees.
The Company provides postretirement medical, dental and life
insurance benefits for a closed group of retirees and their
dependents. The Company also provides limited retiree life
insurance benefits to employees who retire under the pension
plan. The postretirement benefit plans are unfunded, therefore,
the Company funds claims on a cash basis.
The Company has discretionary defined contribution savings plans
(401(k) Plan in the U.S.). Under the 401(k) Plan, an
employee may elect to contribute from 1 to 13 percent of
his/her eligible compensation subject to an Internal
59
BURLINGTON RESOURCES INC.
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Revenue Service limit of $13,000 in 2004. The Company matches
with cash, up to 6 or 8 percent of the employees
eligible contributions based upon years of service. The Company
contributed approximately $10 million, $9 million and
$9 million to these plans for the years ended
December 31, 2004, 2003 and 2002, respectively, to match
eligible contributions by employees.
The Company provides a charitable award benefit to Directors who
were elected to serve on the Board of Directors prior to
February 2003 and served for at least two years. Upon the death
of a Director who qualifies for this benefit, the Company will
donate $1 million to one or more educational institutions
of higher learning or other charitable organizations, which may
include private foundations, nominated by the Director. At
December 31, 2004, a $9 million liability has been
accrued for these benefits and is included in Other Liabilities
and Deferred Credits on the Companys Consolidated Balance
Sheet.
The following tables set forth the pension and postretirement
amounts recognized in the Consolidated Balance Sheet.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pension | |
|
Postretirement | |
|
|
Benefits | |
|
Benefits | |
| |
Year Ended December 31, |
|
2004 | |
|
2003 | |
|
2004 | |
|
2003 | |
| |
|
|
(In Millions) | |
| |
Change in benefit obligation
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Benefit obligation at beginning of year
|
|
$ |
222 |
|
|
$ |
187 |
|
|
$ |
46 |
|
|
$ |
42 |
|
|
Service cost
|
|
|
11 |
|
|
|
9 |
|
|
|
|
|
|
|
|
|
|
Interest cost
|
|
|
13 |
|
|
|
13 |
|
|
|
2 |
|
|
|
3 |
|
|
Plan amendment
|
|
|
1 |
|
|
|
|
|
|
|
(3 |
) |
|
|
|
|
|
Actuarial loss
|
|
|
15 |
|
|
|
24 |
|
|
|
(6 |
) |
|
|
7 |
|
|
Currency exchange
|
|
|
2 |
|
|
|
4 |
|
|
|
|
|
|
|
|
|
|
Participant contributions
|
|
|
|
|
|
|
|
|
|
|
2 |
|
|
|
1 |
|
|
Benefits paid
|
|
|
(14 |
) |
|
|
(15 |
) |
|
|
(5 |
) |
|
|
(7 |
) |
|
|
Benefit obligation at end of year
|
|
|
250 |
|
|
|
222 |
|
|
|
36 |
|
|
|
46 |
|
|
Change in plan assets
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair value of plan assets at beginning of year
|
|
|
180 |
|
|
|
138 |
|
|
|
|
|
|
|
|
|
|
Actual return on plan assets
|
|
|
23 |
|
|
|
31 |
|
|
|
|
|
|
|
|
|
|
Currency exchange
|
|
|
2 |
|
|
|
4 |
|
|
|
|
|
|
|
|
|
|
Employer contribution
|
|
|
23 |
|
|
|
22 |
|
|
|
3 |
|
|
|
6 |
|
|
Participant contributions
|
|
|
|
|
|
|
|
|
|
|
2 |
|
|
|
1 |
|
|
Benefits paid
|
|
|
(14 |
) |
|
|
(15 |
) |
|
|
(5 |
) |
|
|
(7 |
) |
|
|
Fair value of plan assets at end of year
|
|
|
214 |
|
|
|
180 |
|
|
|
|
|
|
|
|
|
|
Funded status
|
|
|
(36 |
) |
|
|
(42 |
) |
|
|
(36 |
) |
|
|
(46 |
) |
Unrecognized net actuarial loss
|
|
|
51 |
|
|
|
51 |
|
|
|
17 |
|
|
|
23 |
|
Unrecognized prior service cost (benefit)
|
|
|
3 |
|
|
|
2 |
|
|
|
(8 |
) |
|
|
(5 |
) |
|
Net prepaid (accrued) benefit cost
|
|
$ |
18 |
|
|
$ |
11 |
|
|
$ |
(27 |
) |
|
$ |
(28 |
) |
|
The following table summarizes the projected benefit obligation,
accumulated benefit obligation, fair value of plan assets and
related consolidated balance sheet amounts for the
Companys pension plans as of the measurement date.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. | |
|
Canada | |
| |
December 31, |
|
2004 | |
|
2003 | |
|
2004 | |
|
2003 | |
| |
|
|
(In Millions) | |
| |
Benefit obligation
|
|
$ |
225 |
|
|
$ |
200 |
|
|
$ |
25 |
|
|
$ |
22 |
|
Accumulated benefit obligation
|
|
|
179 |
|
|
|
159 |
|
|
|
23 |
|
|
|
20 |
|
Fair value of plan assets
|
|
|
187 |
|
|
|
157 |
|
|
|
27 |
|
|
|
23 |
|
Accrued benefit liability
|
|
|
|
|
|
|
4 |
|
|
|
1 |
|
|
|
1 |
|
Prepaid benefit cost
|
|
$ |
15 |
|
|
$ |
12 |
|
|
$ |
4 |
|
|
$ |
4 |
|
|
The Company expects to contribute $12 million to its
pension plans in 2005.
60
BURLINGTON RESOURCES INC.
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The following table summarizes pension and postretirement
benefit expense for the three years ended December 31, 2004.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Postretirement | |
|
|
Pension Benefits | |
|
Benefits | |
| |
Year Ended December 31, |
|
2004 | |
|
2003 | |
|
2002 | |
|
2004 | |
|
2003 | |
|
2002 | |
| |
|
|
(In Millions) | |
| |
Benefit cost for the plans includes the following components
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Service cost
|
|
$ |
11 |
|
|
$ |
9 |
|
|
$ |
9 |
|
|
$ |
|
|
|
$ |
|
|
|
|
$ |
|
|
Interest cost
|
|
|
13 |
|
|
|
13 |
|
|
|
12 |
|
|
|
2 |
|
|
|
3 |
|
|
|
3 |
|
|
Expected return on plan assets
|
|
|
(13 |
) |
|
|
(13 |
) |
|
|
(14 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Recognized net actuarial loss
|
|
|
5 |
|
|
|
4 |
|
|
|
1 |
|
|
|
1 |
|
|
|
|
|
|
|
|
|
|
|
|
Net benefit cost
|
|
$ |
16 |
|
|
$ |
13 |
|
|
$ |
8 |
|
|
$ |
3 |
|
|
$ |
3 |
|
|
|
$ 3 |
|
|
Assumptions used to determine net benefit obligations follow.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Postretirement | |
|
|
Pension Benefits | |
|
Benefits | |
| |
December 31, |
|
2004 | |
|
2003 | |
|
2002 | |
|
2004 | |
|
2003 | |
|
2002 | |
| |
Weighted average assumptions
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Discount rate
|
|
|
5.75 |
% |
|
|
6.00 |
% |
|
|
6.75 |
% |
|
|
5.75 |
% |
|
|
6.00 |
% |
|
|
6.75% |
|
|
Rate of compensation increase
|
|
|
4.50 |
% |
|
|
4.50 |
% |
|
|
4.50 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
Assumptions used to determine net benefit cost follow.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Postretirement | |
|
|
Pension Benefits | |
|
Benefits | |
| |
Year Ended December 31, |
|
2004 | |
|
2003 | |
|
2002 | |
|
2004 | |
|
2003 | |
|
2002 | |
| |
Weighted average assumptions
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Discount rate
|
|
|
6.00 |
% |
|
|
6.75 |
% |
|
|
7.25 |
% |
|
|
6.00 |
% |
|
|
6.75 |
% |
|
|
7.25% |
|
|
Expected return on plan assets
|
|
|
7.50 |
|
|
|
8.00 |
|
|
|
8.50 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Rate of compensation increase
|
|
|
4.50 |
% |
|
|
4.50 |
% |
|
|
5.00 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
The following table summarizes the future expected benefit
payments to be paid from the pension and postretirement plans.
|
|
|
|
|
|
|
|
|
|
|
Pension | |
|
Postretirement | |
Year Ended |
|
Payments | |
|
Payments | |
| |
|
|
(In Millions) | |
| |
2005
|
|
$ |
16 |
|
|
$ |
3 |
|
2006
|
|
|
18 |
|
|
|
3 |
|
2007
|
|
|
18 |
|
|
|
3 |
|
2008
|
|
|
20 |
|
|
|
3 |
|
2009
|
|
|
21 |
|
|
|
3 |
|
2010-2014
|
|
$ |
140 |
|
|
$ |
14 |
|
|
The following table provides the target and actual asset
allocations for the Companys pension plans as of
December 31.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. | |
|
Canada | |
| |
Asset Category |
|
Target | |
|
2004 | |
|
2003 | |
|
Target | |
|
2004 | |
|
2003 | |
| |
Equity
|
|
|
65 |
% |
|
|
67 |
% |
|
|
68 |
% |
|
|
58 |
% |
|
|
62 |
% |
|
|
60% |
|
Fixed income
|
|
|
35 |
|
|
|
33 |
|
|
|
30 |
|
|
|
31 |
|
|
|
27 |
|
|
|
40 |
|
Other
|
|
|
|
|
|
|
|
|
|
|
2 |
|
|
|
11 |
|
|
|
11 |
|
|
|
|
|
|
|
Total
|
|
|
100 |
% |
|
|
100 |
% |
|
|
100 |
% |
|
|
100 |
% |
|
|
100 |
% |
|
|
100% |
|
|
61
BURLINGTON RESOURCES INC.
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The primary investment objective is to ensure, over the
long-term life of the pension plans, an adequate pool of
sufficiently liquid assets to support the benefit obligations to
participants, retirees and beneficiaries. In meeting this
objective, the pension plans seek to achieve a high level of
investment return consistent with a prudent level of portfolio
risk while maintaining asset allocations within 5 percent
of the target allocation shown above.
To develop the expected long-term rate of return on assets
assumption, the Company considered the current level of expected
returns on risk-free investments (primarily government bonds),
the historical level of the risk premium associated with the
other asset classes in which the portfolio is invested and the
expectations for future returns of each asset class. Since the
Companys investment policy is to actively manage certain
asset classes where the potential exists to outperform the
broader market, the expected returns for those asset classes
were adjusted to reflect the expected additional returns. The
expected return for each asset class was then weighted based on
the target asset allocation to develop the expected long-term
rate of return on assets assumption for the portfolio. This
process resulted in the selection of the 7.5 percent
assumption.
A 9 percent annual rate of increase in the per capita cost
of pre-age 65 covered health care benefits was assumed for
2005. The rate is assumed to decrease gradually to
5 percent for 2009 and remain at that level thereafter. An
11 percent annual rate of increase in the per capita cost
of post-age 65 covered health care benefits was assumed to
gradually decrease to 5 percent for 2011 and remain at that
level thereafter. Assumed health care cost trends have a
significant effect on the amounts reported for the
postretirement medical and dental care plans. A one-percentage
point change in assumed health care cost trend rates would have
the following effects.
|
|
|
|
|
|
|
|
|
|
|
1-Percentage | |
|
1-Percentage | |
|
|
Point Increase | |
|
Point Decrease | |
| |
|
|
(In Thousands) | |
| |
Effect on total service and interest cost
|
|
$ |
179 |
|
|
$ |
(156 |
) |
Effect on postretirement benefit obligation
|
|
$ |
2,977 |
|
|
$ |
(2,595 |
) |
|
14. Commitments and Contingent Liabilities
Transportation Demand Charges
The Company has entered into contracts which provide firm
transportation capacity rights on pipeline systems. The
remaining terms on these contracts range from 1 to 19 years
and require the Company to pay transportation demand charges
regardless of the amount of pipeline capacity utilized by the
Company. The Company paid $193 million, $179 million
and $156 million of demand charges for the years ended
December 31, 2004, 2003 and 2002, respectively. All
transportation costs including demand charges are included in
transportation expense in the Consolidated Statement of Income.
Future transportation demand charge commitments at
December 31, 2004 follow.
|
|
|
|
|
|
|
|
(In Millions) | |
| |
2005
|
|
$ |
165 |
|
2006
|
|
|
130 |
|
2007
|
|
|
107 |
|
2008
|
|
|
88 |
|
2009
|
|
|
74 |
|
Thereafter
|
|
|
382 |
|
|
|
Total
|
|
$ |
946 |
|
|
Lease Obligations and Other Commitments
The Company has operating leases for office space and other
property and equipment. The Company incurred lease rental
expense of $35 million, $38 million and
$29 million for the years ended December 31, 2004,
2003 and 2002, respectively.
62
BURLINGTON RESOURCES INC.
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Future minimum annual rental commitments under non-cancelable
leases at December 31, 2004 follow.
|
|
|
|
|
|
|
|
(In Millions) | |
| |
2005
|
|
$ |
30 |
|
2006
|
|
|
28 |
|
2007
|
|
|
27 |
|
2008
|
|
|
29 |
|
2009
|
|
|
29 |
|
Thereafter
|
|
|
145 |
|
|
|
Total
|
|
$ |
288 |
|
|
The Company has drilling rig commitments of $7 million and
$4 million for 2005 and 2006, respectively.
Legal Proceedings
The Company and numerous other oil and gas companies have been
named as defendants in various lawsuits alleging violations of
the civil False Claims Act. These lawsuits were consolidated
during 1999 and 2000 for pre-trial proceedings by the United
States Judicial Panel on Multidistrict Litigation in the matter
of In re Natural Gas Royalties Qui Tam Litigation,
MDL-1293, United States District Court for the District of
Wyoming (MDL-1293). The plaintiffs contend that
defendants underpaid royalties on natural gas and NGLs produced
on federal and Indian lands through the use of below-market
prices, improper deductions, improper measurement techniques and
transactions with affiliated companies during the period of 1985
to the present. Plaintiffs allege that the royalties paid by
defendants were lower than the royalties required to be paid
under federal regulations and that the forms filed by defendants
with the Minerals Management Service (MMS) reporting
these royalty payments were false, thereby violating the civil
False Claims Act. The United States has intervened in certain of
the MDL-1293 cases as to some of the defendants, including the
Company. The plaintiffs and the intervenor have not specified in
their pleadings the amount of damages they seek from the
Company. On December 5, 2003, the United States
Judicial Panel on Multidistrict Litigation entered an order
transferring the cases alleging claims of below-market prices,
improper deductions, and transactions with affiliated companies
for further pre-trial proceedings and trial in Wright v.
AGIP, 5:03CV264, United States District Court for the
Eastern District of Texas, Texarkana Division. All parties are
proceeding with pre-trial discovery, and the trial of these
cases is scheduled to begin in February 2007. The cases alleging
improper measurement techniques remain pending in MDL-1293, and
motions to dismiss have been filed by the Company and other
defendants and are pending before the Court.
Various administrative proceedings are also pending before the
MMS of the United States Department of the Interior with respect
to the valuation of natural gas produced by the Company on
federal and Indian lands. In general, these proceedings stem
from regular MMS audits of the Companys royalty payments
over various periods of time and involve the interpretation of
the relevant federal regulations. Most of these proceedings
involve production volumes and royalties that are the subject of
Natural Gas Royalties Qui Tam Litigation.
Based on the Companys present understanding of the various
governmental and civil False Claims Act proceedings described
above, the Company believes that it has substantial defenses to
these claims and intends to vigorously assert such defenses. The
Company is also exploring the possibility of a settlement of
these claims. Although there has been no formal demand for
damages, the Company currently estimates, based on its
communications with the intervenor, that the amount of underpaid
royalties on onshore production claimed by the intervenor in
these proceedings is approximately $76 million. In the
event that the Company is found to have violated the civil False
Claims Act, the Company could be subject to double damages,
civil monetary penalties and other sanctions, including a
temporary suspension from bidding on and entering into future
federal mineral leases and other federal contracts for a defined
period of time. As an alternative to monetary penalties under
the False Claims Act, the intervenor has informed the Company
that it may seek the recovery of interest payments of
approximately $95 million. The Company has established a
reserve that management believes to be adequate to provide for
this potential liability based upon its evaluation of this
matter.
The Company has also been named as a defendant in the lawsuit
styled UNOCAL Netherlands B.V., et al v.
Continental Netherlands Oil Company B.V., et al,
No. 98-854, filed in 1995 in the District Court in The
Hague and currently pending in the Court of Appeal in The Hague,
the Netherlands. Plaintiffs, who are working interest owners in
the Q-1 Block in the North Sea, have alleged that the Company
and other former working interest owners in the adjacent Logger
Field in the L16a Block unlawfully trespassed or were otherwise
unjustly enriched by producing part of the oil from the
adjoining Q-1 Block. The plaintiffs claim that the defendants
infringed upon plaintiffs right to produce the minerals
present in its
63
BURLINGTON RESOURCES INC.
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
license area and acted in violation of generally accepted
standards by failing to inform plaintiffs of the overlap of the
Logger Field into the Q-1 Block. Plaintiffs seek damages of
$97.5 million as of January 1, 1997, plus interest.
For all relevant periods, the Company owned a 37.5 percent
working interest in the Logger Field. Following a trial, the
District Court in The Hague rendered a Judgment in favor of the
defendants, including the Company, dismissing all claims.
Plaintiffs thereafter appealed. On October 19, 2000, the
Court of Appeal in The Hague issued an interim Judgment in favor
of the plaintiffs and ordered that additional evidence be
presented to the court relating to issues of both liability and
damages. After receiving additional evidence from the parties,
the Court of Appeals subsequently issued a ruling in favor of
defendants. In an interim Judgment issued on December 18,
2003, the Court of Appeals found that defendants should not have
assumed that they were extracting oil from the Q-1 Block, that
Unocal was not entitled to compensation for any production
occurring prior to 1992 and that damages, if any, would be
limited to the proceeds Unocal would have received for oil
extracted from the Q-1 Block, less the costs Unocal would have
incurred to produce the oil from an existing well in the L16a
Block. The Court of Appeals ordered that further evidence be
presented to a court appointed expert to determine whether any
damages had been suffered by Unocal. The Company and the other
defendants are continuing to present evidence to the Court and
vigorously assert defenses against these claims. The Company has
also asserted claims of indemnity against two of the defendants
from whom it had acquired a portion of its working interest
share. If the Company is successful in enforcing the
indemnities, its working interest share of any adverse judgment
could be reduced to 15 percent for some of the periods
covered by plaintiffs lawsuit. Based on the information
known to date, the Company believes that Unocal suffered no
damages in excess of the costs of production and that the
Company will incur no liability in this matter other than the
costs of litigation. The Company has not established a reserve
for this matter since it currently does not believe that an
unfavorable outcome is probable.
The Company and its former affiliate, El Paso Natural Gas
Company, have also been named as defendants in two class action
lawsuits styled Bank of America, et al. v.
El Paso Natural Gas Company, et al., Case
No. CJ-97-68, and Deane W. Moore, et al. v.
Burlington Northern, Inc., et. al., Case No. CJ-97-132,
each filed in 1997 in the District Court of Washita County,
State of Oklahoma and subsequently consolidated by the court.
Plaintiffs contend that defendants underpaid royalties from 1982
to the present on natural gas produced from specified wells in
Oklahoma through the use of below-market prices, improper
deductions and transactions with affiliated companies and in
other instances failed to pay or delayed in the payment of
royalties on certain gas sold from these wells. The plaintiffs
seek an accounting and damages for alleged royalty
underpayments, plus interest from the time such amounts were
allegedly due. Plaintiffs additionally seek the recovery of
punitive damages. The plaintiffs have not specified in their
pleadings the amount of damages they seek from the Company.
However, through pre-trial discovery, plaintiffs have provided
defendants with alternative theories of recovery claiming
monetary damages of up to $221 million in principal, plus
$996 million in interest, and unspecified punitive damages
and attorneys fees. The Company believes it has
substantial defenses to these claims and is vigorously asserting
such defenses. The Company and El Paso Natural Gas Company
have asserted contractual claims for indemnity against each
other. The court has certified the plaintiff classes of royalty
and overriding royalty interest owners, and the parties are
proceeding with pre-trial discovery. It is anticipated that the
trial of this matter will be scheduled during 2005. The Company
has established a reserve that management believes to be
adequate to provide for this potential liability based upon its
evaluation of this matter.
The Company received notice on October 19, 2004 from the
United States Department of Justice that it may be one of many
potentially responsible parties under the Comprehensive
Environmental Response, Compensation and Liability Act, as
amended, with respect to the remediation of a site known as the
Castex Systems, Inc. Oil Field Waste Disposal Site in Jefferson
Davis Parish near Jennings, Louisiana. According to the
Department of Justice, the remediation of the site has been
completed under the supervision of the United States
Environmental Protection Agency for a total cost of
approximately $3 million. The Company has been informed
that it may have contributed up to two and one-half percent (2.5
%) of the liquid oil field waste and twelve percent (12%) of the
solid oil field waste identified at the site. The Company has
signed an agreement tolling the statute of limitations for a
period of approximately three months and is currently
investigating this matter to determine if it is liable for any
portion of the remediation costs.
In addition to the foregoing, the Company and its subsidiaries
are named defendants in numerous other lawsuits and named
parties in numerous governmental and other proceedings arising
in the ordinary course of business, including: claims for
personal injury and property damage, claims challenging oil and
gas royalty, ad valorem and severance tax payments, claims
related to joint interest billings under oil and gas operating
agreements, claims alleging mismeasurement of volumes and
wrongful analysis of heating content of natural gas and other
claims in the nature of contract, regulatory or employment
disputes. None of the governmental proceedings involve foreign
governments.
While the ultimate outcome and impact on the Company cannot be
predicted with certainty, management believes that the
resolution of these legal proceedings and environmental matters
through settlement or adverse judgment will not have a material
adverse effect on the consolidated financial position or results
of operations of the Company, although cash flow could be
significantly impacted in the reporting periods in which such
matters are resolved.
64
BURLINGTON RESOURCES INC.
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
At December 31, 2004, the Companys Consolidated
Balance Sheet included reserves for legal proceedings of
$84 million and environmental matters of $15 million.
The accrual of reserves for legal and environmental matters is
included in Other Liabilities and Deferred Credits on the
Consolidated Balance Sheet. The establishment of a reserve
involves an estimation process that includes the advice of legal
counsel and subjective judgment of management. While management
believes these reserves to be adequate, it is reasonably
possible that the Company could incur additional loss, the
amount of which is not currently estimable, in excess of the
amounts currently accrued with respect to those matters in which
reserves have been established. Future changes in the facts and
circumstances could result in actual liability exceeding the
estimated ranges of loss and the amounts accrued. Based on
currently available information, we believe that it is remote
that future costs related to known contingent liability
exposures for legal proceedings and environmental matters will
exceed current accruals by an amount that would have a material
adverse effect on the consolidated financial position or results
of operations of the Company, although cash flow could be
significantly impacted in the reporting periods in which such
costs are incurred.
15. Supplemental Cash Flow Information
The following is additional information concerning supplemental
disclosures of cash payments.
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
2004 | |
|
2003 | |
|
2002 | |
| |
|
|
(In Millions) | |
| |
Interest paidnet of capitalized interest(1)
|
|
$ |
275 |
|
|
$ |
251 |
|
|
$ |
260 |
|
Income taxes paidnet
|
|
$ |
274 |
|
|
$ |
171 |
|
|
$ |
40 |
|
|
|
|
(1) |
The Company had no capitalized interest in 2004. Capitalized
interest was $25 million and $22 million for the years
ended December 31, 2003 and 2002, respectively. |
At December 31, 2004 and 2003, capital expenditures
included in the Accounts Payable balance on the Companys
Consolidated Balance Sheet were $333 million and
$171 million, respectively. During the year ended
December 31, 2004, the Company acquired $6 million of
assets through a capital lease.
16. Impairment of Oil and Gas Properties
The Company performs an impairment analysis annually for
unproved reserves or whenever events or changes in circumstances
indicate an assets carrying amount may not be recoverable.
Cash flows used in the impairment analysis are determined based
upon managements estimates of natural gas, NGLs and crude
oil reserves, future natural gas, NGLs and crude oil prices and
costs to extract these reserves.
In connection with the preparation of its financial statements,
the Company recorded an impairment charge of $90 million
for the year ended December 31, 2004 related to unproved
properties in Canada. During the year ended December 31,
2003, the Company recorded charges of $63 million related
to the impairment of oil and gas properties due to performance
related downward reserve adjustments associated with certain
properties primarily in Canada.
17. Segment and Geographic Information
The Companys reportable segments are U.S., Canada and
International. The Company is engaged principally in the
exploration, development, production and marketing of natural
gas, crude oil and NGLs. The Companys reportable segments
are managed separately based on their geographic location. The
accounting policies for the segments are the same as those
described in Note 1 of Notes to Consolidated Financial
Statements. There were no intersegment sales in 2004 and 2003.
Intersegment sales were $17 million in 2002.
65
BURLINGTON RESOURCES INC.
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The following tables present information about reported segment
operations.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
North America | |
|
|
|
|
|
|
| |
|
|
|
|
Year Ended December 31, 2004 |
|
U.S. | |
|
Canada | |
|
International | |
|
Total | |
| |
|
|
(In Millions) | |
| |
Revenues
|
|
$ |
2,710 |
|
|
$ |
2,100 |
|
|
$ |
808 |
|
|
$ |
5,618 |
|
Depreciation, depletion and amortization
|
|
|
363 |
|
|
|
535 |
|
|
|
214 |
|
|
|
1,112 |
|
Impairment of oil and gas properties
|
|
|
|
|
|
|
90 |
|
|
|
|
|
|
|
90 |
|
Income before income taxes
|
|
|
1,612 |
|
|
|
891 |
|
|
|
341 |
|
|
|
2,844 |
|
Propertiesnet
|
|
|
3,984 |
|
|
|
5,541 |
|
|
|
1,417 |
|
|
|
10,942 |
|
Goodwill
|
|
|
|
|
|
|
1,054 |
|
|
|
|
|
|
|
1,054 |
|
Capital expenditures
|
|
$ |
719 |
|
|
$ |
842 |
|
|
$ |
166 |
|
|
$ |
1,727 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
North America | |
|
|
|
|
|
|
| |
|
|
|
|
Year Ended December 31, 2003 |
|
U.S. | |
|
Canada | |
|
International | |
|
Total | |
| |
|
|
(In Millions) | |
| |
Revenues
|
|
$ |
2,111 |
|
|
$ |
1,925 |
|
|
$ |
275 |
|
|
$ |
4,311 |
|
Depreciation, depletion and amortization
|
|
|
307 |
|
|
|
493 |
|
|
|
102 |
|
|
|
902 |
|
Impairment of oil and gas properties
|
|
|
5 |
|
|
|
58 |
|
|
|
|
|
|
|
63 |
|
Income before income taxes and cumulative effect of change in
accounting principle
|
|
|
1,124 |
|
|
|
869 |
|
|
|
39 |
|
|
|
2,032 |
|
Propertiesnet
|
|
|
3,608 |
|
|
|
5,102 |
|
|
|
1,505 |
|
|
|
10,215 |
|
Goodwill
|
|
|
|
|
|
|
982 |
|
|
|
|
|
|
|
982 |
|
Capital expenditures
|
|
$ |
545 |
|
|
$ |
715 |
|
|
$ |
505 |
|
|
$ |
1,765 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
North America | |
|
|
|
|
|
|
| |
|
|
|
|
Year Ended December 31, 2002 |
|
U.S. | |
|
Canada | |
|
International | |
|
Total | |
| |
|
|
(In Millions) | |
| |
Revenues
|
|
$ |
1,642 |
|
|
$ |
1,165 |
|
|
$ |
161 |
|
|
$ |
2,968 |
|
Depreciation, depletion and amortization
|
|
|
350 |
|
|
|
382 |
|
|
|
78 |
|
|
|
810 |
|
Income (loss) before income taxes
|
|
|
817 |
|
|
|
278 |
|
|
|
(99 |
) |
|
|
996 |
|
Propertiesnet
|
|
|
3,433 |
|
|
|
4,008 |
|
|
|
961 |
|
|
|
8,402 |
|
Goodwill
|
|
|
|
|
|
|
803 |
|
|
|
|
|
|
|
803 |
|
Capital expenditures
|
|
$ |
491 |
|
|
$ |
876 |
|
|
$ |
435 |
|
|
$ |
1,802 |
|
|
66
BURLINGTON RESOURCES INC.
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The following is a reconciliation of segment income before
income taxes and cumulative effect of change in accounting
principle to consolidated income before income taxes and
cumulative effect of change in accounting principle. For segment
reporting purposes, corporate expenses, total interest expense
and other expense (income)net have been excluded from
segment operations.
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
2004 | |
|
2003 | |
|
2002 | |
| |
|
|
(In Millions) | |
| |
Income before income taxes and cumulative effect of change in
accounting principle for reportable segments
|
|
$ |
2,844 |
|
|
$ |
2,032 |
|
|
$ |
996 |
|
Corporate expenses
|
|
|
239 |
|
|
|
189 |
|
|
|
184 |
|
Interest expense
|
|
|
282 |
|
|
|
260 |
|
|
|
274 |
|
Other expense (income)net
|
|
|
19 |
|
|
|
13 |
|
|
|
(31 |
) |
|
Consolidated income before income taxes and cumulative effect of
change in accounting principle
|
|
$ |
2,304 |
|
|
$ |
1,570 |
|
|
$ |
569 |
|
|
The following is a reconciliation of segment additions to
properties to consolidated amounts.
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
2004 | |
|
2003 | |
|
2002 | |
| |
|
|
(In Millions) | |
| |
Total capital expenditures for reportable segments
|
|
$ |
1,727 |
|
|
$ |
1,765 |
|
|
$ |
1,802 |
|
Corporate administrative capital expenditures
|
|
|
20 |
|
|
|
23 |
|
|
|
35 |
|
|
Consolidated capital expenditures
|
|
$ |
1,747 |
|
|
$ |
1,788 |
|
|
$ |
1,837 |
|
|
The following is a reconciliation of segment net properties to
consolidated amounts.
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
2004 | |
|
2003 | |
|
2002 | |
| |
|
|
(In Millions) | |
| |
Propertiesnet for reportable segments
|
|
$ |
10,942 |
|
|
$ |
10,215 |
|
|
$ |
8,402 |
|
Corporate propertiesnet
|
|
|
91 |
|
|
|
96 |
|
|
|
101 |
|
|
Consolidated propertiesnet
|
|
$ |
11,033 |
|
|
$ |
10,311 |
|
|
$ |
8,503 |
|
|
18. Taxes Other Than Income Taxes
Taxes other than income taxes are as follow.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
2004 | |
|
2003 | |
|
2002 | |
| |
|
|
(In Millions) | |
| |
Severance taxes
|
|
$ |
204 |
|
|
$ |
141 |
|
|
$ |
85 |
|
Ad valorem taxes
|
|
|
36 |
|
|
|
30 |
|
|
|
25 |
|
Payroll taxes and other
|
|
|
20 |
|
|
|
16 |
|
|
|
13 |
|
|
|
Taxes other than income taxes
|
|
$ |
260 |
|
|
$ |
187 |
|
|
$ |
123 |
|
|
19. Other Matters
Recent Accounting Pronouncements
In January 2005, the Financial Accounting Standards Board
(FASB) issued SFAS No. 153, Exchanges
of Nonmonetary Assets an amendment of APB Opinion
No. 29. This statement, which addresses the measurement
of exchanges of nonmonetary assets, is effective prospectively
for nonmonetary asset exchanges occurring in fiscal periods
beginning after June 15, 2005. The adoption of this
statement is not expected to impact the Companys
consolidated financial position or results of operations.
In January 2005, the FASB issued SFAS No. 151,
Inventory Costs, which is effective prospectively for
inventory costs incurred during fiscal years beginning after
June 15, 2005. SFAS No. 151 amends Accounting
Research Bulletin No. 43, Chapter 4, to clarify that
abnormal amounts of idle facility expense, freight, handling
costs, and wasted materials should
67
BURLINGTON RESOURCES INC.
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
be recognized as current period charges. The adoption of this
statement is not expected to impact the Companys
consolidated financial position or results of operations.
In December 2004, the FASB issued SFAS No. 123
(revised 2004) or SFAS No. 123(R), Share-Based
Payment. This statement requires the cost resulting from all
share-based payment transactions be recognized in the financial
statements at their fair value on the grant date.
SFAS No. 123(R) is effective as of the beginning of
the first interim or annual reporting period that begins after
June 15, 2005. The Company will adopt this statement on
July 1, 2005 using the modified prospective application
method described in the statement. Under the modified
prospective application method, the Company will apply the
standard to new awards and to awards modified, repurchased, or
cancelled after the required effective date. Additionally,
compensation cost for the unvested portion of awards outstanding
as of the required effective date will be recognized as
compensation expense as the requisite service is rendered after
the required effective date. The adoption of this statement is
not expected to have a material impact on the Companys
consolidated financial position or results of operations.
In January 2003, the FASB issued Interpretation No. 46,
(FIN 46), Consolidation of Variable Interest
Entities. FIN 46, as amended by FIN 46(R),
provides guidance on how to identify a variable interest entity
(VIE), and determine when the assets, liabilities,
and results of operations of a VIE need to be included in a
companys consolidated financial statements. FIN 46
also requires additional disclosures by primary beneficiaries
and other significant variable interest holders in a VIE. The
provisions of FIN 46 were effective immediately for all
VIEs created after January 31, 2003. For VIEs created
before February 1, 2003, the provisions of FIN 46, as
amended, were effective on January 1, 2004. After
evaluating this accounting pronouncement, the Company determined
that it did not have any interests in any VIEs. Therefore, the
adoption of FIN 46 did not have any impact on the
Companys consolidated financial position, results of
operations or cash flows.
68
January 17, 2005
Burlington Resources Inc.
717 Texas Avenue, Suite 2100
Houston, TX 77002
Re: Proved Reserves as of December 31, 2004
Gentlemen:
At your request, we reviewed the estimates of domestic and
international proved reserves of oil, condensate, natural gas,
and natural gas liquids (NGLs) that Burlington Resources Inc.
(BR) attributes to its net interests in oil and gas
properties as of December 31, 2004. BRs estimates of
proved reserves shown below are in accordance with the
definitions contained in Securities and Exchange Commission
Regulation S-X, Rule 4-10(a).
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved Reserves | |
|
|
| |
|
|
Developed | |
|
Undeveloped | |
|
Total | |
| |
Oil, Condensate, and NGLs, Million Barrels
|
|
|
427.3 |
|
|
|
130.9 |
|
|
|
558.2 |
|
Gas, Billions of Cubic Feet
|
|
|
4,180.8 |
|
|
|
1,715.5 |
|
|
|
5,896.3 |
|
|
Based on our investigations and subject to the limitations
described hereinafter, it is our judgment that (1) BR has
an effective system for gathering data and documenting
information required to estimate its proved reserves;
(2) in making its estimates, BR uses appropriate
engineering, geologic, and evaluation principles and techniques
that are in accordance with practices generally accepted in the
petroleum industry; and (3) the results of the estimates
prepared by BR that we reviewed are, in the aggregate,
reasonable.
Gas volumes were estimated at the appropriate pressure base and
temperature base established for each well or field by the
applicable sales contract or regulatory body. Total gas reserves
were obtained by summing the reserves for all the individual
properties and are therefore stated at a mixed pressure base.
In conducting our audit, we reviewed BRs estimates of wet
gas volumes prior to adjustment for impurities, shrinkage, and
NGL recovery. We reviewed these wet gas volumes, along with the
methods employed by BR, to convert these volumes to sales gas
volumes and NGLs. In our judgment, the conversion methods used
by BR to adjust the wet volumes to account for impurities, fuel
use, shrinkage, and NGL recovery are appropriate and reasonable.
We reviewed approximately 84 percent of BRs estimated
proved reserves forecasts and either accepted their forecast or
revised it as needed. We selected the sampling of properties for
independent estimates and review. In general, those properties
with the largest reserves were selected for review. We
investigated the pertinent available engineering, geological,
and accounting information to satisfy ourselves that BRs
reserve estimates are, in the aggregate, reasonable. In making
our reserve estimates and comparing them with BRs
estimates, we used product prices and expenses provided by BR.
The prices used were represented by BR as the actual prices
received for oil, condensate, natural gas, and NGLs on
December 31, 2004, and are in accordance with Securities
and Exchange Commission guidelines.
69
|
|
Burlington Resources Inc. |
January 17, 2005 |
Page 2
These reserve estimates are based primarily on decline curve
analysis, material balance calculations, volumetric
calculations, analogies, or combinations of these methods.
Reserve estimates from volumetric calculations and from
analogies are often less certain than reserve estimates based on
well performance obtained over a period during which a
substantial portion of the reserves were produced.
In conducting these evaluations, we relied upon production
histories, accounting data, and other financial, operating,
engineering, geological and geophysical data supplied by BR. To
a lesser extent, data existing in the files of Miller and Lents,
Ltd. and data obtained from commercial services were used. We
also relied, without independent verification, upon BRs
representation of its ownership interests for each property.
Miller and Lents, Ltd. is an independent oil and gas consulting
firm. No director, officer, or key employee of Miller and Lents,
Ltd. has any financial ownership in Burlington Resources Inc. or
any affiliated company. Our compensation for the required
investigations and preparation of this report is not contingent
on the results obtained and reported, and we have not performed
other work that would affect our objectivity. Production of this
report was supervised by an officer of the firm who is a
professionally qualified and licensed Professional Engineer in
the State of Texas with more than 20 years of relevant
experience in the estimation, assessment, and evaluation of oil
and gas reserves.
The evaluations presented in this report, with the exceptions of
those parameters specified by others, reflect our informed
judgments based on accepted standards of professional
investigation but are subject to those generally recognized
uncertainties associated with interpretation of geological,
geophysical, and engineering information. Government policies
and market conditions different from those employed in this
study may cause the total quantity of oil or gas to be
recovered, actual production rates, prices received, or
operating and capital costs to vary from those reviewed for this
report.
|
|
|
Very truly yours, |
|
|
MILLER AND LENTS, LTD.
|
|
![-s- CHRISTOPHER A. BUTTA](h22407h2240706.gif) |
|
|
|
Christopher A. Butta |
|
Senior Vice President |
CAB/psh
70
January 11, 2005
Burlington Resources Inc.
Ste. 2100, 717 Texas Avenue
Houston, TX 77002-2712
|
|
Re: |
Unqualified Audit Opinion of Burlington Resources
Incorporated Canadian Proved Reserves, as of December 31,
2004 |
Gentlemen:
At your request, we have examined the proved oil, natural gas
liquids, and natural gas reserves estimates of Burlington
Resources Incorporated (Burlington) Canadian
properties, as of December 31, 2004. Our examination
included such tests and procedures as we considered necessary
under the circumstances to render the opinion set forth herein.
Table 1 presents Burlingtons estimates of proved oil,
natural gas liquids and natural gas reserves, which are in
accordance with the definitions contained in Securities and
Exchange Commission Regulation S-X, Rule 4-10(a).
Table 1
Summary of Burlington Resources Incorporated Canadian Proved
Reserves Estimates
Using Net Marketable Gas Volumes
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved Reserves | |
|
|
| |
|
|
Developed | |
|
Undeveloped | |
|
Total | |
| |
Oil, MMbbl
|
|
|
13.6 |
|
|
|
4.3 |
|
|
|
17.9 |
|
Natural Gas, Bcf
|
|
|
1,821 |
|
|
|
509 |
|
|
|
2,330 |
|
Natural Gas Liquids, MMbbl
|
|
|
44.7 |
|
|
|
9.4 |
|
|
|
54.1 |
|
|
The volumes of natural gas liquids are comprised of ethane,
propane, butanes, condensate and pentanes plus. All volumes are
reported net, after royalties.
71
We are independent with respect to Burlington, as provided in
the Standard Pertaining to the Estimating and Auditing of Oil
and Gas Reserves Information promulgated by the Society of
Petroleum Engineers.
Our audit does not constitute a complete reserves study of the
oil and gas properties of Burlington. In the conduct of our
audit, we did not independently verify the accuracy and
completeness of information and data furnished by Burlington
with respect to ownership interests, oil and gas production,
historical costs of operation and development, product prices,
agreements relating to current and future operations and sales
of production, etc. Burlingtons Canadian reserves
assignments were audited directly by a citrix link into the PEEP
reserves database, and by reviewing available public data to
determine if those assignments were reasonable. If in the course
of our examination something came to our attention that brought
into question the validity or sufficiency of any such
information or data, we did not rely on such information or data
until we had satisfactorily resolved our questions relating
thereto or independently verified such information or data.
The proved developed producing reserves and production forecasts
were estimated by production decline extrapolations, water-oil
ratio trends, material balance, or by volumetric calculations.
For some properties with insufficient performance history to
establish trends, we estimated future production by analogy with
other properties with similar characteristics. The past
performance trends of many properties were influenced by
production curtailments, workovers, waterfloods, and/or infill
drilling. Actual future production may require that our
estimated trends be significantly altered.
The estimated proved undeveloped reserves require significant
capital expenditures for items such as the drilling, completion
and tie-in of wells. The proved undeveloped reserves estimates
for infill wells are based on analogies to similar infill wells
in the same field and/or the production histories of offset
wells in the same field.
Reserve estimates from volumetric calculations and from
analogies are often less certain than reserves estimates based
on well performance obtained over a period during which a
substantial portion of the reserves was produced.
The reserves estimates presented in this report, with the
exceptions of those parameters specified by others, reflect our
informed judgements based on accepted standards of professional
investigation, but are subject to those generally recognized
uncertainties associated with interpretation of geological,
geophysical and engineering information. Government policies and
market conditions different from those employed in this review
may cause the total quantity of oil or gas to be recovered,
actual production rates, prices received, or operating and
capital costs to vary from those estimated in this audit.
In our opinion, the estimates of Burlingtons proved
reserves are, in the aggregate, reasonable and have been
prepared in accordance with generally accepted petroleum
engineering and evaluation principles as set forth in the
Standards Pertaining to the Estimating and Auditing of Oil and
Gas Reserves Information promulgated by the Society of Petroleum
Engineers.
This letter is solely for the information of Burlington
Resources Inc. and for the information and assistance of its
independent public accountants in connection with their review
of, and report upon, the financial statements of Burlington
Resources Inc. This letter should not be used, circulated or
quoted for any other purpose without the express written consent
of the undersigned or except as required by law.
72
Our working papers are available for review upon request. If you
have any questions regarding the above, or if we may be of
further assistance, please call us.
|
|
|
Sincerely, |
|
![(-s- Robert N. Johnson)](h22407h2240710.gif) |
|
|
|
|
|
Robert N. Johnson, P.Eng. |
|
Manager, Engineering and Corporate Secretary |
|
![(-s- Kenneth H. Crowther)](h22407h2240711.gif) |
|
|
|
|
|
Kenneth H. Crowther, P.Eng |
|
President |
|
|
PERMIT TO PRACTICE
SPROULE ASSOCIATES LIMITED |
|
![(-s- Robert N. Johnson)](h22407h2240710.gif) |
|
Signature |
|
|
|
![(January 11. 2005)](h22407h2240712.gif) |
|
Date |
|
|
|
PERMIT NUMBER: P 417 |
|
The Association of Professional Engineers, |
|
Geologists and Geophysicists of Alberta |
|
73
BURLINGTON RESOURCES INC.
SUPPLEMENTARY FINANCIAL INFORMATION
Supplemental Oil and Gas DisclosuresUnaudited
The supplemental data presented herein reflects information for
all of the Companys oil and gas producing activities.
Costs incurred for oil and gas property acquisition, exploration
and development activities follow.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
North America | |
|
|
|
|
|
|
| |
|
|
|
|
Year Ended December 31, 2004 |
|
U.S. | |
|
Canada | |
|
International | |
|
Total | |
| |
|
|
(In Millions) | |
| |
Property acquisition
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved
|
|
$ |
81 |
|
|
$ |
4 |
|
|
$ |
|
|
|
$ |
85 |
|
|
Unproved
|
|
|
32 |
|
|
|
33 |
|
|
|
2 |
|
|
|
67 |
|
Exploration
|
|
|
55 |
|
|
|
126 |
|
|
|
38 |
|
|
|
219 |
|
Development
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved developed
|
|
|
473 |
|
|
|
526 |
|
|
|
36 |
|
|
|
1,035 |
|
|
Proved undeveloped
|
|
|
71 |
|
|
|
113 |
|
|
|
54 |
|
|
|
238 |
|
|
Costs incurred before estimated asset retirement
obligations
|
|
|
712 |
|
|
|
802 |
|
|
|
130 |
|
|
|
1,644 |
|
Estimated asset retirement obligations incurred(1)
|
|
|
18 |
|
|
|
(5 |
) |
|
|
(2 |
) |
|
|
11 |
|
|
|
|
Total costs incurred
|
|
$ |
730 |
|
|
$ |
797 |
|
|
$ |
128 |
|
|
$ |
1,655 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
North America | |
|
|
|
|
|
|
| |
|
|
|
|
Year Ended December 31, 2003 |
|
U.S. | |
|
Canada | |
|
International | |
|
Total | |
| |
|
|
(In Millions) | |
| |
Property acquisition
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved
|
|
$ |
110 |
|
|
$ |
19 |
|
|
$ |
99 |
|
|
$ |
228 |
|
|
Unproved
|
|
|
9 |
|
|
|
79 |
|
|
|
2 |
|
|
|
90 |
|
Exploration
|
|
|
43 |
|
|
|
135 |
|
|
|
33 |
|
|
|
211 |
|
Development
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved developed
|
|
|
246 |
|
|
|
375 |
|
|
|
36 |
|
|
|
657 |
|
|
Proved undeveloped
|
|
|
132 |
|
|
|
71 |
|
|
|
196 |
|
|
|
399 |
|
|
Costs incurred before estimated asset retirement
obligations
|
|
|
540 |
|
|
|
679 |
|
|
|
366 |
|
|
|
1,585 |
|
Estimated asset retirement obligations incurred(1)
|
|
|
6 |
|
|
|
26 |
|
|
|
52 |
|
|
|
84 |
|
|
|
|
Total costs incurred
|
|
$ |
546 |
|
|
$ |
705 |
|
|
$ |
418 |
|
|
$ |
1,669 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
North America | |
|
|
|
|
|
|
| |
|
|
|
|
Year Ended December 31, 2002 |
|
U.S. | |
|
Canada | |
|
International | |
|
Total | |
| |
|
|
(In Millions) | |
| |
Property acquisition
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved
|
|
$ |
178 |
|
|
$ |
352 |
|
|
$ |
74 |
|
|
$ |
604 |
|
|
Unproved
|
|
|
4 |
|
|
|
13 |
|
|
|
|
|
|
|
17 |
|
Exploration
|
|
|
35 |
|
|
|
126 |
|
|
|
40 |
|
|
|
201 |
|
Development
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved developed
|
|
|
165 |
|
|
|
279 |
|
|
|
32 |
|
|
|
476 |
|
|
Proved undeveloped
|
|
|
81 |
|
|
|
69 |
|
|
|
153 |
|
|
|
303 |
|
|
|
|
Total costs incurred
|
|
$ |
463 |
|
|
$ |
839 |
|
|
$ |
299 |
|
|
$ |
1,601 |
|
|
|
|
(1) |
Amounts are shown net of current year estimated cash flow
revisions. |
The Company estimates that it will spend capital of
approximately $503 million, $635 million and
$405 million in 2005, 2006 and 2007, respectively, for the
development of its proved undeveloped reserves.
74
BURLINGTON RESOURCES INC.
SUPPLEMENTARY FINANCIAL INFORMATION
Results of operations for natural gas, NGLs and crude oil
producing activities, which exclude processing and other
activities, corporate general and administrative expenses and
straight-line depreciation expense, were as follow. There were
no intersegment sales in 2004 and 2003. Intersegment sales were
$17 million in 2002.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
North America | |
|
|
|
|
|
|
| |
|
|
|
|
Year Ended December 31, 2004 |
|
U.S. | |
|
Canada | |
|
International | |
|
Total | |
| |
|
|
(In Millions) | |
| |
Revenues
|
|
$ |
2,690 |
|
|
$ |
2,087 |
|
|
$ |
807 |
|
|
$ |
5,584 |
|
|
Production costs
|
|
|
407 |
|
|
|
200 |
|
|
|
97 |
|
|
|
704 |
|
Exploration costs
|
|
|
37 |
|
|
|
154 |
|
|
|
67 |
|
|
|
258 |
|
Operating expenses
|
|
|
284 |
|
|
|
221 |
|
|
|
90 |
|
|
|
595 |
|
Depreciation, depletion and amortization
|
|
|
346 |
|
|
|
512 |
|
|
|
212 |
|
|
|
1,070 |
|
Impairment of oil and gas properties
|
|
|
|
|
|
|
90 |
|
|
|
|
|
|
|
90 |
|
Income tax provision
|
|
|
554 |
|
|
|
315 |
|
|
|
201 |
|
|
|
1,070 |
|
|
Results of operations for oil and gas producing activities
|
|
$ |
1,062 |
|
|
$ |
595 |
|
|
$ |
140 |
|
|
$ |
1,797 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
North America | |
|
|
|
|
|
|
| |
|
|
|
|
Year Ended December 31, 2003 |
|
U.S. | |
|
Canada | |
|
International | |
|
Total | |
| |
|
|
(In Millions) | |
| |
Revenues
|
|
$ |
2,089 |
|
|
$ |
1,911 |
|
|
$ |
275 |
|
|
$ |
4,275 |
|
|
Production costs
|
|
|
317 |
|
|
|
173 |
|
|
|
46 |
|
|
|
536 |
|
Exploration costs
|
|
|
100 |
|
|
|
121 |
|
|
|
31 |
|
|
|
252 |
|
Operating expenses
|
|
|
270 |
|
|
|
206 |
|
|
|
58 |
|
|
|
534 |
|
Depreciation, depletion and amortization
|
|
|
288 |
|
|
|
461 |
|
|
|
100 |
|
|
|
849 |
|
Impairment of oil and gas properties
|
|
|
5 |
|
|
|
58 |
|
|
|
|
|
|
|
63 |
|
Income tax provision
|
|
|
345 |
|
|
|
201 |
|
|
|
10 |
|
|
|
556 |
|
|
Results of operations for oil and gas producing activities
|
|
$ |
764 |
|
|
$ |
691 |
|
|
$ |
30 |
|
|
$ |
1,485 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
North America | |
|
|
|
|
|
|
| |
|
|
|
|
Year Ended December 31, 2002 |
|
U.S. | |
|
Canada | |
|
International | |
|
Total | |
| |
|
|
(In Millions) | |
| |
Revenues
|
|
$ |
1,631 |
|
|
$ |
1,166 |
|
|
$ |
161 |
|
|
$ |
2,958 |
|
|
Production costs
|
|
|
307 |
|
|
|
141 |
|
|
|
23 |
|
|
|
471 |
|
Exploration costs
|
|
|
116 |
|
|
|
121 |
|
|
|
49 |
|
|
|
286 |
|
Operating expenses
|
|
|
233 |
|
|
|
191 |
|
|
|
43 |
|
|
|
467 |
|
Depreciation, depletion and amortization
|
|
|
330 |
|
|
|
358 |
|
|
|
75 |
|
|
|
763 |
|
Income tax provision
|
|
|
224 |
|
|
|
151 |
|
|
|
10 |
|
|
|
385 |
|
|
Results of operations for oil and gas producing activities
|
|
$ |
421 |
|
|
$ |
204 |
|
|
$ |
(39 |
) |
|
$ |
586 |
|
|
75
BURLINGTON RESOURCES INC.
SUPPLEMENTARY FINANCIAL INFORMATION
The following table reflects estimated quantities of proved
natural gas, NGLs and crude oil reserves. These reserves have
been estimated by the Companys petroleum engineers in
accordance with the Securities and Exchange Commissions
Regulations. The Company considers such estimates to be
reasonable, however, due to inherent uncertainties, estimates of
underground reserves are imprecise and subject to change over
time as additional information becomes available.
Miller and Lents, Ltd. and Sproule Associates Limited,
independent oil and gas consultants, have reviewed the estimates
of proved reserves of natural gas, NGLs and crude oil that BR
attributed to its net interests in oil and gas properties as of
December 31, 2004. Miller and Lents, Ltd. reviewed the
reserve estimates for the Companys U.S. and International
interests and Sproule Associates Limited reviewed the
Companys interests in Canada. Based on their review of
more than 80 percent of the Companys reserve
estimates, it is their judgment that the estimates are
reasonable in the aggregate.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude Oil (MMBbls) | |
| |
|
|
North America | |
|
|
|
|
| |
|
|
|
|
U.S. | |
|
Canada | |
|
International | |
|
Worldwide | |
| |
Proved Developed and Undeveloped Reserves
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2001
|
|
|
244.3 |
|
|
|
56.6 |
|
|
|
71.0 |
|
|
|
371.9 |
|
|
Revisions of previous estimates
|
|
|
(2.0 |
) |
|
|
(1.4 |
) |
|
|
(1.6 |
) |
|
|
(5.0 |
) |
|
Extensions, discoveries and other additions
|
|
|
2.8 |
|
|
|
5.3 |
|
|
|
6.3 |
|
|
|
14.4 |
|
|
Production
|
|
|
(13.0 |
) |
|
|
(2.8 |
) |
|
|
(2.1 |
) |
|
|
(17.9 |
) |
|
Purchase of reserves in place
|
|
|
1.2 |
|
|
|
|
|
|
|
19.9 |
|
|
|
21.1 |
|
|
Sales of reserves in place
|
|
|
(46.1 |
) |
|
|
(43.3 |
) |
|
|
(7.2 |
) |
|
|
(96.6 |
) |
|
December 31, 2002
|
|
|
187.2 |
|
|
|
14.4 |
|
|
|
86.3 |
|
|
|
287.9 |
|
|
Revisions of previous estimates
|
|
|
(4.9 |
) |
|
|
0.4 |
|
|
|
1.7 |
|
|
|
(2.8 |
) |
|
Extensions, discoveries and other additions
|
|
|
11.0 |
|
|
|
2.8 |
|
|
|
|
|
|
|
13.8 |
|
|
Production
|
|
|
(10.7 |
) |
|
|
(1.9 |
) |
|
|
(4.4 |
) |
|
|
(17.0 |
) |
|
Purchase of reserves in place
|
|
|
0.5 |
|
|
|
0.1 |
|
|
|
|
|
|
|
0.6 |
|
|
Sales of reserves in place
|
|
|
(0.3 |
) |
|
|
(0.1 |
) |
|
|
|
|
|
|
(0.4 |
) |
|
December 31, 2003
|
|
|
182.8 |
|
|
|
15.7 |
|
|
|
83.6 |
|
|
|
282.1 |
|
|
Revisions of previous estimates
|
|
|
13.7 |
|
|
|
(0.7 |
) |
|
|
6.0 |
|
|
|
19.0 |
|
|
Extensions, discoveries and other additions
|
|
|
18.9 |
|
|
|
4.9 |
|
|
|
1.2 |
|
|
|
25.0 |
|
|
Production
|
|
|
(13.7 |
) |
|
|
(2.0 |
) |
|
|
(15.5 |
) |
|
|
(31.2 |
) |
|
Purchase of reserves in place
|
|
|
2.8 |
|
|
|
|
|
|
|
|
|
|
|
2.8 |
|
|
Sales of reserves in place
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2004
|
|
|
204.5 |
|
|
|
17.9 |
|
|
|
75.3 |
|
|
|
297.7 |
|
|
Proved Developed Reserves
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2001
|
|
|
163.7 |
|
|
|
38.4 |
|
|
|
8.8 |
|
|
|
210.9 |
|
|
December 31, 2002
|
|
|
155.2 |
|
|
|
12.9 |
|
|
|
12.9 |
|
|
|
181.0 |
|
|
December 31, 2003
|
|
|
176.5 |
|
|
|
13.1 |
|
|
|
50.8 |
|
|
|
240.4 |
|
|
December 31, 2004
|
|
|
185.8 |
|
|
|
13.6 |
|
|
|
48.5 |
|
|
|
247.9 |
|
|
76
BURLINGTON RESOURCES INC.
SUPPLEMENTARY FINANCIAL INFORMATION
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NGLs (MMBbls) | |
|
Natural Gas (BCF) | |
|
|
|
|
| |
|
|
North America | |
|
|
|
North America | |
|
|
|
Total | |
|
|
| |
|
|
|
| |
|
|
|
Equivalent | |
|
|
U.S. | |
|
Canada | |
|
Worldwide | |
|
U.S. | |
|
Canada | |
|
International | |
|
Worldwide | |
|
(BCFE) | |
| |
|
|
|
227.7 |
|
|
|
47.7 |
|
|
|
275.4 |
|
|
|
4,892 |
|
|
|
2,136 |
|
|
|
897 |
|
|
|
7,925 |
|
|
|
11,808 |
|
|
|
|
9.8 |
|
|
|
14.7 |
|
|
|
24.5 |
|
|
|
(14 |
) |
|
|
(140 |
) |
|
|
(11 |
) |
|
|
(165 |
) |
|
|
(48 |
) |
|
|
|
15.7 |
|
|
|
9.2 |
|
|
|
24.9 |
|
|
|
350 |
|
|
|
341 |
|
|
|
85 |
|
|
|
776 |
|
|
|
1,012 |
|
|
|
|
(11.9 |
) |
|
|
(10.0 |
) |
|
|
(21.9 |
) |
|
|
(346 |
) |
|
|
(293 |
) |
|
|
(60 |
) |
|
|
(699 |
) |
|
|
(938 |
) |
|
|
|
|
|
|
|
0.2 |
|
|
|
0.2 |
|
|
|
153 |
|
|
|
268 |
|
|
|
|
|
|
|
421 |
|
|
|
549 |
|
|
|
|
(0.9 |
) |
|
|
(2.0 |
) |
|
|
(2.9 |
) |
|
|
(282 |
) |
|
|
(16 |
) |
|
|
(70 |
) |
|
|
(368 |
) |
|
|
(965 |
) |
|
|
|
|
|
|
240.4 |
|
|
|
59.8 |
|
|
|
300.2 |
|
|
|
4,753 |
|
|
|
2,296 |
|
|
|
841 |
|
|
|
7,890 |
|
|
|
11,418 |
|
|
|
|
19.8 |
|
|
|
(0.7 |
) |
|
|
19.1 |
|
|
|
(88 |
) |
|
|
(57 |
) |
|
|
(45 |
) |
|
|
(190 |
) |
|
|
(91 |
) |
|
|
|
22.9 |
|
|
|
12.0 |
|
|
|
34.9 |
|
|
|
425 |
|
|
|
427 |
|
|
|
54 |
|
|
|
906 |
|
|
|
1,198 |
|
|
|
|
(13.6 |
) |
|
|
(10.0 |
) |
|
|
(23.6 |
) |
|
|
(315 |
) |
|
|
(317 |
) |
|
|
(61 |
) |
|
|
(693 |
) |
|
|
(937 |
) |
|
|
|
0.6 |
|
|
|
0.3 |
|
|
|
0.9 |
|
|
|
131 |
|
|
|
9 |
|
|
|
79 |
|
|
|
219 |
|
|
|
228 |
|
|
|
|
(0.5 |
) |
|
|
(0.1 |
) |
|
|
(0.6 |
) |
|
|
(54 |
) |
|
|
(4 |
) |
|
|
|
|
|
|
(58 |
) |
|
|
(64 |
) |
|
|
|
|
|
|
269.6 |
|
|
|
61.3 |
|
|
|
330.9 |
|
|
|
4,852 |
|
|
|
2,354 |
|
|
|
868 |
|
|
|
8,074 |
|
|
|
11,752 |
|
|
|
|
4.0 |
|
|
|
(8.5 |
) |
|
|
(4.5 |
) |
|
|
40 |
|
|
|
(77 |
) |
|
|
2 |
|
|
|
(35 |
) |
|
|
52 |
|
|
|
|
19.7 |
|
|
|
9.8 |
|
|
|
29.5 |
|
|
|
475 |
|
|
|
352 |
|
|
|
18 |
|
|
|
845 |
|
|
|
1,172 |
|
|
|
|
(15.3 |
) |
|
|
(8.6 |
) |
|
|
(23.9 |
) |
|
|
(333 |
) |
|
|
(300 |
) |
|
|
(68 |
) |
|
|
(701 |
) |
|
|
(1,031 |
) |
|
|
|
0.5 |
|
|
|
0.1 |
|
|
|
0.6 |
|
|
|
43 |
|
|
|
4 |
|
|
|
|
|
|
|
47 |
|
|
|
67 |
|
|
|
|
(0.1 |
) |
|
|
|
|
|
|
(0.1 |
) |
|
|
(1 |
) |
|
|
(3 |
) |
|
|
|
|
|
|
(4 |
) |
|
|
(5 |
) |
|
|
|
|
278.4 |
|
|
|
54.1 |
|
|
|
332.5 |
|
|
|
5,076 |
|
|
|
2,330 |
|
|
|
820 |
|
|
|
8,226 |
|
|
|
12,007 |
|
|
|
|
|
|
|
175.5 |
|
|
|
39.3 |
|
|
|
214.8 |
|
|
|
3,771 |
|
|
|
1,758 |
|
|
|
384 |
|
|
|
5,913 |
|
|
|
8,467 |
|
|
|
|
179.2 |
|
|
|
53.1 |
|
|
|
232.3 |
|
|
|
3,617 |
|
|
|
1,836 |
|
|
|
263 |
|
|
|
5,716 |
|
|
|
8,196 |
|
|
|
|
188.6 |
|
|
|
50.8 |
|
|
|
239.4 |
|
|
|
3,715 |
|
|
|
1,837 |
|
|
|
322 |
|
|
|
5,874 |
|
|
|
8,753 |
|
|
|
|
193.1 |
|
|
|
44.6 |
|
|
|
237.7 |
|
|
|
3,745 |
|
|
|
1,821 |
|
|
|
435 |
|
|
|
6,001 |
|
|
|
8,915 |
|
|
|
|
77
BURLINGTON RESOURCES INC.
SUPPLEMENTARY FINANCIAL INFORMATION
A summary of the standardized measure of discounted future net
cash flows relating to proved natural gas, NGLs and crude oil
reserves is shown below. Future net cash flows are computed
using year end commodity prices, costs and statutory tax rates
(adjusted for tax credits and other items) that relate to the
Companys existing proved natural gas, NGLs and crude oil
reserves.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
North America | |
|
|
|
|
|
|
| |
|
|
|
|
2004 |
|
U.S. | |
|
Canada | |
|
International | |
|
Total | |
| |
|
|
(In Millions) | |
| |
Future cash inflows |
|
$ |
38,750 |
|
|
$ |
14,787 |
|
|
$ |
5,544 |
|
|
$ |
59,081 |
|
|
Less related future
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production costs
|
|
|
8,070 |
|
|
|
2,705 |
|
|
|
1,063 |
|
|
|
11,838 |
|
|
|
Development costs
|
|
|
1,658 |
|
|
|
1,047 |
|
|
|
429 |
|
|
|
3,134 |
|
|
|
Income taxes
|
|
|
9,927 |
|
|
|
3,208 |
|
|
|
1,445 |
|
|
|
14,580 |
|
|
Future net cash flows |
|
|
19,095 |
|
|
|
7,827 |
|
|
|
2,607 |
|
|
|
29,529 |
|
10% annual discount for estimated timing of cash flows |
|
|
10,575 |
|
|
|
2,948 |
|
|
|
788 |
|
|
|
14,311 |
|
|
Standardized measure of discounted future net cash flows |
|
$ |
8,520 |
|
|
$ |
4,879 |
|
|
$ |
1,819 |
|
|
$ |
15,218 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
North America | |
|
|
|
|
|
|
| |
|
|
|
|
2003 |
|
U.S. | |
|
Canada | |
|
International | |
|
Total | |
| |
|
|
(In Millions) | |
| |
Future cash inflows
|
|
$ |
34,868 |
|
|
$ |
14,689 |
|
|
$ |
5,357 |
|
|
$ |
54,914 |
|
|
Less related future
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production costs
|
|
|
6,551 |
|
|
|
2,219 |
|
|
|
1,342 |
|
|
|
10,112 |
|
|
|
Development costs
|
|
|
888 |
|
|
|
717 |
|
|
|
424 |
|
|
|
2,029 |
|
|
|
Income taxes
|
|
|
9,351 |
|
|
|
3,416 |
|
|
|
1,102 |
|
|
|
13,869 |
|
|
Future net cash flows
|
|
|
18,078 |
|
|
|
8,337 |
|
|
|
2,489 |
|
|
|
28,904 |
|
10% annual discount for estimated timing of cash flows
|
|
|
9,937 |
|
|
|
3,028 |
|
|
|
762 |
|
|
|
13,727 |
|
|
Standardized measure of discounted future net cash flows
|
|
$ |
8,141 |
|
|
$ |
5,309 |
|
|
$ |
1,727 |
|
|
$ |
15,177 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
North America | |
|
|
|
|
|
|
| |
|
|
|
|
2002 |
|
U.S. | |
|
Canada | |
|
International | |
|
Total | |
| |
|
|
(In Millions) | |
| |
Future cash inflows
|
|
$ |
24,879 |
|
|
$ |
10,563 |
|
|
$ |
3,861 |
|
|
$ |
39,303 |
|
|
Less related future
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production costs
|
|
|
5,543 |
|
|
|
1,634 |
|
|
|
1,072 |
|
|
|
8,249 |
|
|
|
Development costs
|
|
|
750 |
|
|
|
327 |
|
|
|
614 |
|
|
|
1,691 |
|
|
|
Income taxes
|
|
|
6,018 |
|
|
|
2,940 |
|
|
|
475 |
|
|
|
9,433 |
|
|
Future net cash flows
|
|
|
12,568 |
|
|
|
5,662 |
|
|
|
1,700 |
|
|
|
19,930 |
|
10% annual discount for estimated timing of cash flows
|
|
|
6,976 |
|
|
|
1,894 |
|
|
|
646 |
|
|
|
9,516 |
|
|
Standardized measure of discounted future net cash flows
|
|
$ |
5,592 |
|
|
$ |
3,768 |
|
|
$ |
1,054 |
|
|
$ |
10,414 |
|
|
78
BURLINGTON RESOURCES INC.
SUPPLEMENTARY FINANCIAL INFORMATION
A summary of the changes in the standardized measure of
discounted future net cash flows applicable to proved natural
gas, NGLs and crude oil reserves follows.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2004 | |
|
2003 | |
|
2002 | |
|
|
|
(In Millions) | |
| |
January 1,
|
|
$ |
15,177 |
|
|
$ |
10,414 |
|
|
$ |
6,000 |
|
|
Revisions of previous estimates
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Changes in prices and costs
|
|
|
606 |
|
|
|
6,050 |
|
|
|
6,744 |
|
|
Changes in quantities
|
|
|
173 |
|
|
|
(111 |
) |
|
|
(26 |
) |
Additions to proved reserves resulting from extensions,
discoveries and improved recovery, less related costs
|
|
|
1,978 |
|
|
|
2,119 |
|
|
|
1,235 |
|
Purchases of reserves in place
|
|
|
126 |
|
|
|
416 |
|
|
|
656 |
|
Sales of reserves in place
|
|
|
(10 |
) |
|
|
(86 |
) |
|
|
(1,215 |
) |
Accretion of discount
|
|
|
2,165 |
|
|
|
1,472 |
|
|
|
815 |
|
Sales, net of production costs
|
|
|
(4,880 |
) |
|
|
(3,739 |
) |
|
|
(2,483 |
) |
Net change in income taxes
|
|
|
(401 |
) |
|
|
(2,163 |
) |
|
|
(2,158 |
) |
Changes in rate of production and other
|
|
|
284 |
|
|
|
805 |
|
|
|
846 |
|
|
Net change
|
|
|
41 |
|
|
|
4,763 |
|
|
|
4,414 |
|
|
December 31,
|
|
$ |
15,218 |
|
|
$ |
15,177 |
|
|
$ |
10,414 |
|
|
Quarterly Financial DataUnaudited
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2004 | |
|
2003 | |
| |
|
|
4th | |
|
3rd | |
|
2nd | |
|
1st | |
|
4th | |
|
3rd | |
|
2nd | |
|
1st | |
| |
|
|
(In Millions, Except per Share Amounts) | |
| |
Revenues
|
|
$ |
1,558 |
|
|
$ |
1,419 |
|
|
$ |
1,333 |
|
|
$ |
1,308 |
|
|
$ |
1,065 |
|
|
$ |
1,059 |
|
|
$ |
1,059 |
|
|
$ |
1,128 |
|
Income before income taxes and cumulative effect of change in
accounting principle(a)
|
|
|
588 |
|
|
|
629 |
|
|
|
540 |
|
|
|
547 |
|
|
|
299 |
|
|
|
396 |
|
|
|
376 |
|
|
|
499 |
|
Income before cumulative effect of change in accounting
principle(d)
|
|
|
400 |
|
|
|
394 |
|
|
|
379 |
|
|
|
354 |
|
|
|
387 |
|
|
|
267 |
|
|
|
278 |
|
|
|
328 |
|
Net income(b)
|
|
|
400 |
|
|
|
394 |
|
|
|
379 |
|
|
|
354 |
|
|
|
387 |
|
|
|
267 |
|
|
|
278 |
|
|
|
269 |
|
Basic earnings per common share before cumulative effect of
change in accounting principle(c)
|
|
|
1.03 |
|
|
|
1.00 |
|
|
|
0.96 |
|
|
|
0.90 |
|
|
|
0.98 |
|
|
|
0.67 |
|
|
|
0.70 |
|
|
|
0.82 |
|
Net income(c)
|
|
|
1.03 |
|
|
|
1.00 |
|
|
|
0.96 |
|
|
|
0.90 |
|
|
|
0.98 |
|
|
|
0.67 |
|
|
|
0.70 |
|
|
|
0.67 |
|
Diluted earnings per common share before cumulative effect of
change in accounting principle(c)(d)
|
|
|
1.02 |
|
|
|
1.00 |
|
|
|
0.96 |
|
|
|
0.89 |
|
|
|
0.98 |
|
|
|
0.67 |
|
|
|
0.69 |
|
|
|
0.81 |
|
Net income(b)(c)
|
|
|
1.02 |
|
|
|
1.00 |
|
|
|
0.96 |
|
|
|
0.89 |
|
|
|
0.98 |
|
|
|
0.67 |
|
|
|
0.69 |
|
|
|
0.67 |
|
Cash dividends declared per common share(c)
|
|
|
0.08 |
|
|
|
0.09 |
|
|
|
0.07 |
|
|
|
0.08 |
|
|
|
0.08 |
|
|
|
0.07 |
|
|
|
0.07 |
|
|
|
0.07 |
|
Common stock price range(c)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
High
|
|
|
46.41 |
|
|
|
41.24 |
|
|
|
37.49 |
|
|
|
31.98 |
|
|
|
28.73 |
|
|
|
27.04 |
|
|
|
27.98 |
|
|
|
24.04 |
|
|
Low
|
|
$ |
39.19 |
|
|
$ |
34.92 |
|
|
$ |
31.23 |
|
|
$ |
26.33 |
|
|
$ |
23.48 |
|
|
$ |
22.52 |
|
|
$ |
22.92 |
|
|
$ |
20.38 |
|
|
|
|
|
(a) |
|
During the fourth quarter of 2004 and the second and fourth
quarters of 2003, the Company recognized non-cash, pretax
charges of $90 million, $30 million and
$33 million, respectively, related to the impairment of oil
and gas properties. |
(b) |
|
Fourth quarter 2004 includes a tax benefit of $28 million
($0.07 per diluted share) related to the Canadian federal
income tax reduction as well as a U.S. expense of
$26 million ($0.07 per diluted share) related to the
planned repatriation of $500 million under the one-time
provisions of the American Jobs Creation Act of 2004. Fourth
quarter 2003 includes a tax benefit of $203 million or
$0.51 per diluted share related to the Canadian federal
income tax reduction. |
(c) |
|
Share amounts and per share amounts for periods prior to
June 30, 2004 have been retroactively adjusted to reflect
the stock split of the Companys Common Stock effective
June 1, 2004. |
(d) |
|
During the first quarter of 2003, the Company recorded a pre-tax
charge of $95 million ($59 million after tax or $0.15
per diluted share) resulting from the adoption of
SFAS No. 143. |
79
ITEM NINE
CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING
AND FINANCIAL DISCLOSURE
None
ITEM NINE A
CONTROLS AND PROCEDURES
Under the supervision and with the participation of certain
members of the Companys management, including the Chief
Executive Officer and Chief Financial Officer, the Company
completed an evaluation of the effectiveness of the design and
operation of its disclosure controls and procedures (as defined
in Rules 13a-15(e) and 15d-15(e) to the Securities Exchange
Act of 1934, as amended (the Exchange Act)). Based
on this evaluation, the Companys Chief Executive Officer
and Chief Financial Officer believe that the disclosure controls
and procedures were effective as of the end of the period
covered by this report with respect to timely communicating to
them and other members of management responsible for preparing
periodic reports all material information required to be
disclosed in this report as it relates to the Company and its
consolidated subsidiaries.
The Companys management does not expect that its
disclosure controls and procedures or its internal control over
financial reporting will prevent all errors and all fraud. A
control system, no matter how well conceived and operated, can
provide only reasonable, not absolute, assurance that the
objectives of the control system are met. Further, the design of
a control system must reflect the fact that there are resource
constraints, and the benefits of controls must be considered
relative to their costs. Because of the inherent limitations in
all control systems, no evaluation of controls can provide
absolute assurance that all control issues and instances of
fraud, if any, within the Company have been detected. These
inherent limitations include the realities that judgments in
decision-making can be faulty, and breakdowns can occur because
of simple errors or mistakes. Additionally, controls can be
circumvented by the individual acts of some person or by
collusion of two or more people. The design of any system of
controls also is based in part upon certain assumptions about
the likelihood of future events, and there can be no assurance
that any design will succeed in achieving its stated goals under
all potential future conditions; over time, controls may become
inadequate because of changes in conditions, or the degree of
compliance with the policies or procedures may deteriorate.
Because of the inherent limitations in a cost-effective control
system, misstatements due to error or fraud may occur and not be
detected. Accordingly, the Companys disclosure controls
and procedures are designed to provide reasonable, not absolute,
assurance that the objectives of our disclosure control system
are met and, as set forth above, the Companys management
has concluded, based on their evaluation as of the end of the
period, that our disclosure controls and procedures were
sufficiently effective to provide reasonable assurance that the
objectives of our disclosure control system were met.
There was no change in the Companys internal control over
financial reporting during the Companys last fiscal
quarter that has materially affected, or is reasonably likely to
materially affect, the Companys internal control over
financial reporting. See page 38 for Management Report on
Internal Control over Financial Reporting.
ITEM NINE B
OTHER INFORMATION
None
PART III
ITEMS TEN AND ELEVEN
DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT AND
EXECUTIVE COMPENSATION
A definitive proxy statement for the 2004 Annual Meeting of
Stockholders (the Proxy Statement) of the Company will be filed
no later than 120 days after the end of the fiscal year
with the Securities and Exchange Commission. The information set
forth therein under Election of Directors,
Executive Compensation and Section 16(a)
Beneficial Ownership Reporting Compliance is incorporated
herein by reference. Certain information with respect to the
executive officers of the Company is set forth under the caption
Executive Officers of the Registrant in Part I
of this report. Certain information with respect to the Audit
Committee and Audit Committee financial experts is set forth
under the caption Corporate Governance in the Proxy
Statement and is incorporated herein by reference.
80
The Company has adopted a Code of Business Conduct and Ethics
(Code of Conduct) that applies to directors, officers and
employees, including the principal executive officer, principal
financial officer and principal accounting officer or controller
and has posted such code on its Web site at www.br-inc.com.
Changes to and waivers granted with respect to the
Companys Code of Conduct related to the above named
officers, other executive officers and Directors required to be
disclosed pursuant to the applicable rules and regulations will
also be posted on the Companys Web site. The
Companys Code of Conduct, as well as its Corporate
Governance Guidelines and its Audit, Compensation and Governance
and Nominating Committee charters are available on its Web site
and in print to any shareholder who requests them.
ITEM TWELVE
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
MANAGEMENT
Certain information required by this item is set forth under the
caption Stock Ownership of Management and Certain Other
Holders in the Proxy Statement and is incorporated herein
by reference.
EQUITY COMPENSATION PLAN INFORMATION
At December 31, 2004
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Number of Securities | |
|
|
|
|
|
|
Remaining Available for | |
|
|
Number of Securities | |
|
|
|
Future Issuance Under | |
|
|
to be Issued | |
|
Weighted-Average | |
|
Equity Compensation Plans | |
|
|
Upon Exercise of | |
|
Exercise Price of | |
|
(Excluding Securities | |
|
|
Outstanding Options, | |
|
Outstanding Options, | |
|
Reflected in | |
|
|
Warrants and Rights(2) | |
|
Warrants and Rights(2) | |
|
Column(a))(2) | |
Plan Category |
|
(a) | |
|
(b) | |
|
(c) | |
| |
Equity compensation plans approved by security holders
|
|
|
4,506,902 |
|
|
$ |
24.55 |
|
|
|
10,585,845 |
|
Equity compensation plan not approved by security holders(1)
|
|
|
1,586,332 |
|
|
|
21.49 |
|
|
|
8,087,224 |
|
|
|
Total
|
|
|
6,093,234 |
|
|
$ |
23.75 |
|
|
|
18,673,069 |
|
|
|
|
(1) |
See Note 12 of Notes to Consolidated Financial Statements
for a description of the Companys 1997 Employee Stock
Incentive Plan, which is the only compensation plan in effect
that was adopted without the approval of the Companys
stockholders. |
|
(2) |
The number of equity securities have been adjusted for the
Companys 2-for-1 stock split paid in the form of a share
distribution on June 1, 2004. |
ITEM THIRTEEN
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
The information required by this item is set forth under the
caption Certain Relationships and Related
Transactions in the Proxy Statement and is incorporated
herein by reference.
ITEM FOURTEEN
PRINCIPAL ACCOUNTANT FEES AND SERVICES
The information required by this item is set forth under the
caption Independent Auditor Fees and Services in the
Proxy Statement and is incorporated herein by reference.
81
PART IV
ITEM FIFTEEN
EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
82
SIGNATURES REQUIRED FOR FORM 10-K
Pursuant to the requirements of Section 13 or 15(d) of the
Securities Exchange Act of 1934, Burlington Resources Inc. has
duly caused this report to be signed on its behalf by the
undersigned, thereunto duly authorized.
|
|
|
BURLINGTON RESOURCES INC. |
|
|
|
|
By |
/s/ BOBBY S. SHACKOULS
|
|
|
|
|
|
Bobby S. Shackouls |
|
Chairman of the Board, President and |
|
Chief Executive Officer |
Pursuant to the requirements of the Securities Exchange Act of
1934, this report has been signed below by the following persons
on behalf of Burlington Resources Inc. and in the capacities and
on the dates indicated.
|
|
|
|
|
By: /s/ BOBBY S.
SHACKOULS
Bobby
S. Shackouls |
|
Chairman of the Board, President and Chief Executive Officer |
|
February 28, 2005 |
|
/s/ STEVEN J. SHAPIRO
Steven
J. Shapiro |
|
Director, Executive Vice President and Chief Financial Officer |
|
February 28, 2005 |
|
/s/ JOSEPH P. McCOY
Joseph
P. McCoy |
|
Vice President, Controller and
Chief Accounting Officer |
|
February 28, 2005 |
|
/s/ BARBARA T.
ALEXANDER
Barbara
T. Alexander |
|
Director |
|
February 28, 2005 |
|
/s/ REUBEN V. ANDERSON
Reuben
V. Anderson |
|
Director |
|
February 28, 2005 |
|
/s/ LAIRD I. GRANT
Laird
I. Grant |
|
Director |
|
February 28, 2005 |
|
/s/ ROBERT J. HARDING
Robert
J. Harding |
|
Director |
|
February 28, 2005 |
|
/s/ JOHN T. LaMACCHIA
John
T. LaMacchia |
|
Director |
|
February 28, 2005 |
|
/s/ RANDY L. LIMBACHER
Randy
L. Limbacher |
|
Director |
|
February 28, 2005 |
|
/s/ JAMES F. McDONALD
James
F. McDonald |
|
Director |
|
February 28, 2005 |
|
/s/ KENNETH W. ORCE
Kenneth
W. Orce |
|
Director |
|
February 28, 2005 |
|
/s/ DONALD M. ROBERTS
Donald
M. Roberts |
|
Director |
|
February 28, 2005 |
|
/s/ JAMES A. RUNDE
James
A. Runde |
|
Director |
|
February 28, 2005 |
|
/s/ JOHN F. SCHWARZ
John
F. Schwarz |
|
Director |
|
February 28, 2005 |
|
/s/ WALTER SCOTT, JR.
Walter
Scott, Jr. |
|
Director |
|
February 28, 2005 |
|
/s/ WILLIAM E. WADE,
JR.
William
E. Wade, Jr. |
|
Director |
|
February 28, 2005 |
83
BURLINGTON RESOURCES INC.
AMENDED EXHIBIT INDEX
The following exhibits are filed as part of this report.
|
|
|
|
|
|
|
|
|
Exhibit | |
|
|
|
|
Number | |
|
Description |
|
|
| |
|
|
3.1 |
|
|
Certificate of Incorporation of Burlington Resources Inc. as
amended April 21,2004 (Exhibit 3.1 to Form 10-Q, filed
May 7, 2004) |
|
|
* |
|
|
3.2 |
|
|
By-Laws of Burlington Resources Inc. amended as of March 1,
2003 (Exhibit 3.2 to Form 10-K, filed March 12, 2003) |
|
|
* |
|
|
4.1 |
|
|
Form of Shareholder Rights Agreement dated as of
December 16, 1998, between Burlington Resources Inc. and
EquiServe Trust Company, N.A. (the current Rights Agent) which
includes, as Exhibit A thereto, the form of Certificate of
Designation specifying terms of the Series A Junior
Participating Preferred Stock and, as Exhibit B thereto,
the form of Rights Certificate (Exhibit 1 to Form 8-A,
filed December 1998) |
|
|
* |
|
|
4.2 |
|
|
Indenture, dated as of June 15, 1990, between Burlington
Resources Inc. and Citibank, N.A. (as Trustee), including Form
of Debt Securities (Exhibit 4.2 to Form 8, filed
February 1992) |
|
|
* |
|
|
4.3 |
|
|
Indenture, dated as of October 1, 1991, between Burlington
Resources Inc. and Citibank, N.A. (as Trustee), including Form
of Debt Securities (Exhibit 4.3 to Form 8, filed
February 1992) |
|
|
* |
|
|
4.4 |
|
|
Indenture, dated as of April 1, 1992, between Burlington
Resources Inc. and Citibank, N.A. (as Trustee), including Form
of Debt Securities (Exhibit 4.4 to Form 8, filed March
1993) |
|
|
* |
|
|
4.5 |
|
|
Indenture, dated as of June 15, 1992, between The Louisiana
Land and Exploration Company (LL&E) and Texas
Commerce Bank National Association (as Trustee)
(Exhibit 4.1 to LL&Es Form S-3, as amended,
filed November 1993) |
|
|
* |
|
|
4.6 |
|
|
Indenture, dated as of February 12, 2001, between
Burlington Resources Finance Company and Citibank, N.A. (as
Trustee), including form of Debt Securities (Exhibit 4.2 to
Form S-4, filed April 2002) |
|
|
* |
|
|
4.7 |
|
|
Guarantee Agreement, dated as of February 12, 2001, of
Burlington Resources Inc. with Respect to Senior Debt Securities
of Burlington Resources Finance Company (Exhibit 4.5 to
Form S-4, filed April 2002) |
|
|
* |
|
|
4.8 |
|
|
The Company and its subsidiaries either have filed with the
Securities and Exchange Commission or upon request will furnish
a copy of any instruments with respect to long-term debt of the
Company |
|
|
* |
|
|
10.1 |
|
|
Burlington Resources Inc. Incentive Compensation Plan as amended
and restated (Exhibit 10.29 to Form 10-Q, filed November
2000) |
|
|
* |
|
|
|
|
|
Amendment to Burlington Resources Inc. Incentive Compensation
Plan dated December 2000 (Exhibit 10.2 to Form 10-K,
filed February 2001) |
|
|
* |
|
|
|
|
|
Amendment No. 1, dated January 9, 2002, to Burlington
Resources Inc. Incentive Compensation Plan (Exhibit 10.1 to
Form 10-Q, filed April 2002) |
|
|
* |
|
|
|
|
|
Amendment No. 2, dated July 21, 2004, to Burlington
Resources Inc. Incentive Compensation Plan (Exhibit 10.4 to
Form 10-Q filed August 3, 2004) |
|
|
* |
|
|
|
|
|
Amendment, dated December 23, 2004, to Burlington Resources
Inc. Incentive Compensation Plan |
|
|
|
|
|
10.2 |
|
|
Burlington Resources Inc. Senior Executive Survivor Benefit Plan
dated as of January 1, 1989 (Exhibit 10.11 to
Form 8, filed February 1989) |
|
|
* |
|
|
10.3 |
|
|
Burlington Resources Inc. Deferred Compensation Plan as amended
and restated (Exhibit 10.4 to Form 10-K, filed February
1997) |
|
|
* |
|
|
|
|
|
Amendment No. 1, dated July 21, 2004, to Burlington
Resources Inc. Deferred Compensation Plan (Exhibit 10.3 to
Form 10-Q filed August 3, 2004) |
|
|
* |
|
|
|
|
|
Amendment, dated December 23, 2004, to Burlington Resources
Inc. Deferred Compensation Plan (Filed as Exhibit 10.1
hereto) |
|
|
|
|
84
|
|
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|
|
|
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|
|
Exhibit | |
|
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|
|
Number | |
|
Description |
|
|
| |
|
10.4 |
|
|
Burlington Resources Inc. Supplemental Benefits Plan as amended
and restated (Exhibit 10.5 to Form 10-K, filed February
1997) |
|
|
* |
|
|
|
|
|
Amendment No. 4, dated January 1, 1997, to Burlington
Resources Inc. Supplemental Benefits Plan (Exhibit 10.5 to
Form 10-Q filed August 3, 2004) |
|
|
* |
|
|
|
|
|
Amendment No. 5, dated July 21, 2004, to Burlington
Resources Inc. Supplemental Benefits Plan (Exhibit 10.6 to
Form 10-Q filed August 3, 2004) |
|
|
* |
|
|
|
|
|
Amendment, dated December 23, 2004, to Burlington Resources
Inc. Supplemental Benefits Plan (Filed as Exhibit 10.1
hereto) |
|
|
|
|
|
10.5 |
|
|
Amended and Restated Employment Contract between the Company and
Bobby S. Shackouls (Exhibit 10.29 to Form 10-Q, filed
August 1999) |
|
|
* |
|
|
10.6 |
|
|
Burlington Resources Inc. Compensation Plan for Non-Employee
Directors as amended and restated (Exhibit 10.8 to
Form 10-K, filed February 1997) |
|
|
* |
|
|
|
|
|
Amendment, dated December 23, 2004, to Burlington Resources
Inc. Compensation Plan for Non-Employee Directors (Filed as
Exhibit 10.1 hereto) |
|
|
|
|
|
10.7 |
|
|
Amended and Restated Burlington Resources Inc. Executive Change
in Control Severance Plan (Exhibit 10.8 to Form 10-K, filed
February 2001) |
|
|
* |
|
|
10.8 |
|
|
Burlington Resources Inc. Retirement Income Plan for Directors
(Exhibit 10.21 to Form 8, filed February 1991) |
|
|
* |
|
|
10.9 |
|
|
Burlington Resources Inc. 1991 Director Charitable Award
Plan, dated as of January 16, 1991 (Exhibit 10.21 to
Form 8, filed February 1991) |
|
|
* |
|
|
|
|
|
Amendment No. 1 dated April 9, 1997 to Burlington
Resources Inc. 1991 Director Charitable Award Plan
(Exhibit 10.10 to Form 10-K, filed March 12, 2003) |
|
|
* |
|
|
|
|
|
Amendment No. 2 dated January 22, 2003 to Burlington
Resources Inc. 1991 Director Charitable Award Plan
(Exhibit 10.10 to Form 10-K, filed March 12, 2003) |
|
|
* |
|
|
|
|
|
Amendment No. 3 dated December 2003 to Burlington Resources
Inc. 1991 Director Charitable Award Plan (Exhibit 10.9
to Form 10-K, filed February 26, 2004) |
|
|
* |
|
|
10.10 |
|
|
Master Separation Agreement and documents related thereto dated
January 15, 1992 by and among Burlington Resources Inc.,
El Paso Natural Gas Company and Meridian Oil Holding Inc.,
including exhibits (Exhibit 10.24 to Form 8,
filed February 1992) |
|
|
* |
|
|
10.11 |
|
|
Burlington Resources Inc. 1992 Stock Option Plan for
Non-employee Directors (Exhibit 28.1 of Form S-8,
No. 33-46518, filed March 1992) |
|
|
* |
|
|
10.12 |
|
|
Burlington Resources Inc. Key Executive Retention Plan and
Amendments No. 1 and 2 (Exhibit 10.20 to Form 8,
filed March 1993) |
|
|
* |
|
|
|
|
|
Amendments No. 3 and 4 to the Burlington Resources Inc. Key
Executive Retention Plan (Exhibit 10.17 to Form 10-K, filed
February 1994) |
|
|
* |
|
|
10.13 |
|
|
Burlington Resources Inc. 1992 Performance Share Unit Plan as
amended and restated (Exhibit 10.17 to Form 10-K, filed
February 1997) |
|
|
* |
|
|
10.14 |
|
|
Burlington Resources Inc. 1993 Stock Incentive Plan
(Exhibit 10.22 to Form 10-K, filed February 1994) |
|
|
* |
|
|
|
|
|
Amendment to Burlington Resources Inc. 1993 Stock Incentive Plan
dated April 2000 (Exhibit 10.15 to Form 10-K, filed
February 2001) |
|
|
* |
|
|
|
|
|
Amendment to Burlington Resources 1993 Stock Incentive Plan
dated December 2000 (Exhibit 10.2 to Form 10-K, filed
February 2001) |
|
|
* |
|
|
|
|
|
Amendment to Burlington Resources Inc. 1993 Stock Incentive Plan
dated December 2003 (Exhibit 10.14 to Form 10-K, filed
February 26, 2004) |
|
|
* |
|
|
10.15 |
|
|
Burlington Resources Inc. 1994 Restricted Stock Exchange Plan
(Exhibit 10.23 to Form 10-K, filed February 1995) |
|
|
* |
|
|
|
|
|
Amendment to Burlington Resources Inc. 1994 Restricted Stock
Exchange Plan dated December 2000 (Exhibit 10.16 to
Form 10-K, filed February 2001) |
|
|
* |
|
|
10.16 |
|
|
Burlington Resources Inc. 1997 Performance Share Unit Plan
(Exhibit 10.21 to Form 10-K, filed February 1997) |
|
|
* |
|
85
|
|
|
|
|
|
|
|
|
Exhibit | |
|
|
|
|
Number | |
|
Description |
|
|
| |
|
10.17 |
|
|
$1.5 billion Credit Agreement, dated July 29, 2004,
between Burlington Resources Inc., Burlington Resources Canada
Ltd. and Burlington Resources Canada (Hunter) Ltd., as
Borrowers, and JPMorgan Chase Bank, as administrative agent
(Exhibit 10.1 to Form 10-Q filed August 3, 2004) |
|
|
* |
|
|
10.18 |
|
|
Form of The Louisiana Land and Exploration Company Deferred
Compensation Arrangement for Selected Key Employees
(Exhibit 10(g) to LL&Es Form 10-K, filed March
1991) |
|
|
* |
|
|
|
|
|
Amendment to the LL&E Deferred Compensation Arrangement for
Selected Key Employees dated December 21, 1998
(Exhibit 10.26 to Form 10-K, filed February 1999) |
|
|
* |
|
|
10.19 |
|
|
The LL&E Supplemental Excess Plan (Exhibit 10(j) to
LL&Es Form 10-K, filed March 1993) |
|
|
* |
|
|
10.20 |
|
|
Form of agreement on pension related benefits with certain
former Seattle holding company office employees, including L.
David Hanower (Exhibit 10.26 to Form 10-K, filed
March 17, 2000) |
|
|
* |
|
|
10.21 |
|
|
Poco Petroleums Ltd. Incentive Stock Option Plan (Form S-8
No. 333-91247, filed November 18, 1999) |
|
|
* |
|
|
10.22 |
|
|
Employee Savings Plan for Eligible Employees of Poco Petroleums
Ltd. (Exhibit 4.4 to Form S-8 No. 333-95071,
filed January 20, 2000) |
|
|
* |
|
|
10.23 |
|
|
Burlington Resources Inc. Phantom Stock Plan for Non-Employee
Directors (Exhibit 10.12 to Form 10-K, filed February 1996) |
|
|
* |
|
|
|
|
|
First Amendment to the Burlington Resources Inc. Phantom Stock
Plan for Non-Employee Directors (Exhibit 10.29 to
Form 10-Q, filed May 2000) |
|
|
* |
|
|
|
|
|
Amendment, dated December 23, 2004, to Burlington Resources
Inc. Phantom Stock Plan for Non-Employee Directors (filed as
Exhibit 10.1 hereto) |
|
|
|
|
|
10.24 |
|
|
Burlington Resources Inc. 2000 Stock Option Plan for
Non-Employee Directors (Exhibit 10.30 to Form 10-Q, filed
August 2000) |
|
|
* |
|
|
10.25 |
|
|
Letter agreement regarding Steven J. Shapiro dated
October 18, 2000 related to supplemental pension benefits
in connection with employment (Exhibit 10.29 to Form 10-K,
filed February 2001) |
|
|
* |
|
|
10.26 |
|
|
Burlington Resources Inc. 2001 Performance Share Unit Plan
(Exhibit 10.30 to Form 10-K, filed February 2001) |
|
|
* |
|
|
|
|
|
Amendment No. 1, dated January 9, 2002, to Burlington
Resources Inc. 2001 Performance Share Unit Plan
(Exhibit 10.2 to Form 10-Q, filed April 2002) |
|
|
* |
|
|
|
|
|
Amendment No. 2, dated July 21, 2004, to Burlington
Resources Inc. 2001 Performance Share Unit Plan
(Exhibit 10.2 to Form 10-Q filed August 3, 2004) |
|
|
* |
|
|
|
|
|
Amendment, dated December 23, 2004, to Burlington Resources
Inc. 2001 Performance Share Unit Plan (filed as
Exhibit 10.1 hereto) |
|
|
|
|
|
10.27 |
|
|
Burlington Resources Inc. 2002 Stock Incentive Plan
(Exhibit A to Schedule 14A, filed March 15, 2002) |
|
|
* |
|
|
|
|
|
Amendment No. 1 dated December 2003 to Burlington Resources
Inc. 2002 Stock Incentive Plan (Exhibit 10.29 to
Form 10-K filed February 26, 2004) |
|
|
* |
|
|
|
|
|
Amendment No. 2 dated December 2003 to Burlington Resources
Inc. 2002 Stock Incentive Plan (Exhibit 10.29 to
Form 10-K filed February 26, 2004) |
|
|
* |
|
|
|
|
|
Amendment, dated December 23, 2004, to Burlington Resources
Inc. 2002 Stock Incentive Plan (filed as Exhibit 10.1
hereto) |
|
|
|
|
|
10.28 |
|
|
Burlington Resources Inc. 1997 Employee Stock Incentive Plan
Amendment dated December 2003 to Burlington Resources Inc. 1997
Employee Stock Incentive Plan (Exhibit 10.30 to
Form 10-K, filed February 26, 2004) |
|
|
* |
|
|
10.29 |
|
|
Form of stock option grant letter under the Burlington Resources
Inc. 2002 Stock Incentive Plan |
|
|
|
|
|
10.30 |
|
|
Form of restricted stock grant letter under the Burlington
Resources Inc. 2002 Stock Incentive Plan (Exhibit 10.8 to
Form 10-Q filed August 3, 2004) |
|
|
* |
|
|
10.31 |
|
|
Burlington Resources Inc. 2005 Performance Share Unit Plan
(Exhibit 10.2 to Form 8-K filed January 31, 2005) |
|
|
* |
|
86
|
|
|
|
|
|
|
|
|
Exhibit | |
|
|
|
|
Number | |
|
Description |
|
|
| |
|
10.32 |
|
|
Form of performance share unit grant letter under the Burlington
Resources Inc. 2005 Performance Share Unit Plan
(Exhibit 10.3 to Form 8-K filed January 31, 2005) |
|
|
* |
|
|
10.33 |
|
|
Summary of Performance Measures for the Burlington Resources
Inc. Incentive Compensation Plan |
|
|
|
|
|
10.34 |
|
|
Summary of the Compensation of Non-Employee Directors of
Burlington Resources Inc. |
|
|
|
|
|
21.1 |
|
|
Subsidiaries of the Registrant |
|
|
|
|
|
23.1 |
|
|
Consent of Independent Auditors
PricewaterhouseCoopers LLP |
|
|
|
|
|
23.2 |
|
|
Consent of Independent Oil and Gas Consultant Miller
and Lents, Ltd. |
|
|
|
|
|
23.3 |
|
|
Consent of Independent Oil and Gas Consultant
Sproule Associates Limited |
|
|
|
|
|
31.1 |
|
|
Rule 13a-14(a)/15d-14(a) Certification executed by Bobby S.
Shackouls, Chairman of the Board, President and Chief Executive
Officer of the Company |
|
|
|
|
|
31.2 |
|
|
Rule 13a-14(a)/15d-14(a) Certification executed by Steven J.
Shapiro, Executive Vice President and Chief Financial Officer of
the Company |
|
|
|
|
|
32.1 |
|
|
Section 1350 Certification |
|
|
|
|
|
32.2 |
|
|
Section 1350 Certification |
|
|
|
|
|
|
* |
Exhibit incorporated herein by reference as indicated or
otherwise not filed. |
|
|
|
Exhibit constitutes a management contract or compensatory plan
or arrangement required to be filed as an exhibit to this report
pursuant to Item 14(c) of Form 10-K. |
87