e10vk
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
þ ANNUAL
REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2005
OR
o 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
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717 Texas, Suite 2100, Houston, Texas 77002
Telephone: (713) 624-9000
Securities registered pursuant to Section 12(b) of the Act:
Common Stock, par value $.01 per share
and 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 if the registrant is a well-known
seasoned issuer, as defined in Rule 405 of the Securities
Act. Yes þ No o
Indicate by check mark if the registrant is not required to file
reports pursuant to Section 13 or Section 15(d) of the
Act. Yes o No þ
Indicate by check mark whether the registrant (1) has filed
all reports required to be filed by Section 13 or 15(d) of
the Securities Exchange Act of 1934 during the preceding
12 months (or for such shorter period that the registrant
was required to file such reports), and (2) has been
subject to such filing requirements for the past
90 days. Yes þ No o
Indicate by check mark if disclosure of delinquent filers
pursuant to Item 405 of
Regulation S-K is
not contained herein, and will not be contained, to the best of
registrants knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this
Form 10-K or any
amendment to this
Form 10-K. þ
Indicate by check mark whether the registrant is a large
accelerated filer, an accelerated filer or a non-accelerated
filer. (See definition of accelerated filer and large
accelerated filer in
Rule 12b-2 of the
Exchange Act). (Check one):
Large accelerated
filer þ Accelerated
filer o Non-accelerated
filer o
Indicate by check mark whether the registrant is a shell company
(as defined in
Rule 12b-2 of the
Exchange
Act). Yes o No þ
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 31, 2006 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, 2006: $34,302,471,138 and as of June 30,
2005: $21,049,071,247.
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, 2006, Shares Outstanding: 375,876,300
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:
Information required by Part III will either be included in
Burlington Resources Inc. definitive proxy statement filed with
the Securities and Exchange Commission or filed as an amendment
to this Form 10-K
no later than 120 days after the end of the Companys
fiscal year, to the extent required by the Securities Exchange
Act of 1934, as amended.
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
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BCF
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Billion Cubic Feet
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BCFE
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Billion Cubic Feet of Gas Equivalent
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DD&A
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Depreciation, Depletion and
Amortization
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MBbls
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Thousands of Barrels
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MCF
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Thousand Cubic Feet
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MCFE
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Thousand Cubic Feet of Gas
Equivalent
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MMBbls
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Millions of Barrels
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MMBTU
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Million British Thermal Units
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MMCF
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Million Cubic Feet
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MMCFE
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Million Cubic Feet of Gas Equivalent
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NGLs
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Natural Gas Liquids
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TCF
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Trillion Cubic Feet
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TCFE
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Trillion Cubic Feet of Gas
Equivalent
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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 lease operating or well
operating expenses, 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.
Taxes other than income taxes include severance taxes, ad
valorem taxes, franchise and payroll taxes.
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.
ii
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 crude 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 the 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, the
United Kingdom, the Netherlands, North 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., Burlington Resources Canada
(Hunter) Ltd. (formerly known as Canadian Hunter Exploration
Ltd.) (Hunter), and their affiliated companies
(collectively, the Company).
On December 12, 2005, BR and ConocoPhillips entered into a
definitive agreement under which ConocoPhillips will acquire BR.
Under the terms of the agreement, BR shareholders will receive
$46.50 in cash and 0.7214 shares of ConocoPhillips common
stock for each BR share they own. The transaction is subject to
approval by BR shareholders of record on February 24, 2006
and other customary terms and conditions. A special meeting of
shareholders to vote on the proposed merger is March 30,
2006. Regulatory approvals have been granted and, upon approval
by shareholders, the transaction is expected to close by
March 31, 2006.
In December 2001, the Company consummated the acquisition of
Hunter valued at approximately U.S. $2.1 billion,
resulting in goodwill of approximately $793 million. The
Hunter acquisition added a portfolio of properties, primarily
located in the Western Canadian Sedimentary Basin, an area in
which the Company already operated. The most significant of the
assets is the Deep Basin, one of North Americas largest
natural gas fields.
The Companys reportable segments are the U.S., Canada and
International. For financial information related to the
Companys reportable segments, see Note 17 of Notes to
Consolidated Financial Statements. The Companys worldwide
major operating areas are discussed below.
North America
The Companys asset base is dominated by North American
natural gas properties. Its extensive North American lease
holdings extend from the U.S. Gulf Coast to Northeast
British Columbia and Northern Alberta in Canada. The
Companys North American operations include a mix of
production, development and exploration assets.
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U.S.s % of |
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Canadas % of |
Year Ended December 31, 2005 |
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Worldwide |
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U.S. |
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Worldwide |
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Canada |
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Worldwide |
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($ In Millions) |
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Oil and gas capital expenditures
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Development
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$ |
1,819 |
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$ |
795 |
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44 |
% |
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$ |
897 |
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49 |
% |
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Exploration
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467 |
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189 |
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40 |
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246 |
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53 |
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Acquisitionsproved
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328 |
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294 |
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90 |
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34 |
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10 |
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Total oil and gas capital
expenditures
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$ |
2,614 |
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$ |
1,278 |
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49 |
% |
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$ |
1,177 |
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45 |
% |
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Production
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Natural gas (MMCF per day)
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1,905 |
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950 |
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50 |
% |
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804 |
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42 |
% |
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NGLs (MBbls per day)
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66.7 |
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42.5 |
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64 |
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24.2 |
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36 |
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Crude oil (MBbls per day)
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93.0 |
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49.3 |
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53 |
% |
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6.0 |
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6 |
% |
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December 31,
2005
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Proved reserves (TCFE)
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12.5 |
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8.4 |
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67 |
% |
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3.0 |
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24 |
% |
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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 and mineral
acreage in this area with over 866,000 net acres under its
control. The Company operates over 7,700 well completions
in the San Juan Basin and holds interests in an additional
5,000 non-operated well completions.
In 2005, the Company invested $164 million in oil and gas
capital, excluding acquisitions, drilled or participated in
drilling 374 new wells and performed 134 workovers on existing
wells. The Companys net production from the San Juan
Basin averaged approximately 514 MMCF of natural gas per
day, 31.3 MBbls of NGLs per day and 1.1 MBbls of crude
oil per day during 2005.
1
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 the development of tight gas formations.
To mitigate Fruitland Coal production decline, the Company has
an ongoing program that consists of drilling new wells,
performing workovers on existing wells, adding compression, and
installing artificial lift, where appropriate.
The Company continues to pursue development opportunities in the
three conventional formations (Mesaverde, Pictured Cliffs and
Dakota) in the San Juan Basin. 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 2005, the Company continued its
ongoing infill drilling program in this formation. In 2005, the
Company drilled or participated in drilling 226 conventional
wells on 160-acre and
80-acre spacing. Net
production from the tight gas producing formations averaged
327 MMCF of natural gas per day, 30.3 MBbls of NGLs
per day and 1.1 MBbls of crude oil per day in 2005.
In the Fruitland Coal, the Company drilled or participated in
drilling 148 wells on
320-acre and
160-acre spacing during
2005. In 2005, net production from the Fruitland Coal averaged
187 MMCF of natural gas per day and 1.0 MBbls of NGLs
per day from over 2,100 completions.
On the Negro Canyon leasehold purchased in 2004, which is
located in the heart of the Companys Fruitland Coal
producing area, the Company drilled eight Fruitland Coal wells
and one Dakota well in 2005 and expects to fully develop the
remaining leases by the end of 2006. The Company owns a
100 percent working interest and an 87.5 percent net
revenue interest in the 1,242 acre tract.
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 127 MMCF of natural gas
per day in 2005 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
2005 totaled $48 million for 65 newly drilled wells and
workover projects. The Company owns an approximate
48 percent working interest in the Lost Cabin Gas Plant and
net revenue interests varying from 22 to 40 percent in the
producing reservoirs.
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 2005.
Total Williston Basin production averaged 34.0 MBbls of
crude oil per day and 11 MMCF of natural gas per day.
During 2005, the Company invested $152 million on projects
in the Williston Basin.
The Company continued its highly active waterflood development
program with 160-acre
infill drilling at both the Cedar Hills South and East Lookout
Butte Units. A total of 43 production 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, drilling
continued in the siltstone of the Bakken Shale formation where
34 wells were drilled in Richland County, Montana and two
wells in McKenzie County, North Dakota. The Company currently
controls over 98,000 net acres including areas in these two
counties.
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 ranging in depth
from 11,000 feet to over 21,000 feet. Net production for 2005
from the Anadarko Basin averaged 72 MMCF of natural gas per
day and 2.0 MBbls of NGLs per day. During 2005, the Company
invested $100 million in the Anadarko Basin. Operated
activity focused on the Red Fork and Atoka formations in Roger
Mills and Washita counties, Oklahoma, where the Company drilled
107 wells.
Permian Basin
Permian Basin operations, in west Texas, are focused on the
Waddell Ranch Field. Total Permian Basin net production in 2005
averaged 12 MMCF of natural gas per day, 3.8 MBbls of
crude oil per day and 2.6 MBbls of NGLs per day, with the
Waddell Ranch Field contributing 8 MMCF of natural gas per
day, 2.7 MBbls of crude oil per day and 2.5 MBbls of
NGLs per day. During 2005, the Company invested $7 million
in the Permian Basin operations.
Fort Worth Basin
In the Fort Worth Basin of north central Texas, the Company
continued to develop its Barnett Shale formation acreage in
Denton and Wise counties, Texas. Additional acreage was also
acquired during 2005 in mostly Johnson, Hood, Parker, and Palo
Pinto counties, Texas. The Company now controls 102,000 net
acres in the Fort Worth Basin. During 2005, the Company
invested $137 million in this area, excluding acquisitions,
and drilled 92 wells. Net production averaged 41 MMCF
of natural gas per day, 4.4 MBbls of NGLs per day and
1.0 MBbls of crude oil per day in 2005.
2
Onshore Gulf Coast
The Onshore Gulf Coast includes operations in a number of
drilling trends in east Texas, south Louisiana, the Onshore Gulf
of Mexico and the Florida panhandle where the Company invested
$344 million and drilled 70 wells. Net production in
2005 averaged 169 MMCF of natural gas per day,
9.0 MBbls of crude oil per day and 1.1 MBbls of NGLs
per day.
In south Louisiana, the Company owns 660,000 net acres of
fee lands with both surface and mineral rights. The Company
spent $156 million of capital in south Louisiana during
2005 and drilled 43 wells. Net production in south
Louisiana averaged 89 MMCF of natural gas per day,
6.6 MBbls of crude oil per day and 0.7 MBbls of NGLs
per day in 2005.
In the Bossier trend, the Company controlled over 177,000 net
acres at year end, and is expanding beyond its successful Savell
Field development with other exploration and development
activities along the trend. The Company spent $151 million
of capital, drilled 18 wells, and had five operated rigs
drilling at year end. In 2005, net production averaged
76 MMCF of natural gas per day in the Bossier.
Canada
Western Canadian Sedimentary Basin
In the Western Canadian Sedimentary Basin (Sedimentary
Basin), the Companys portfolio of opportunities
includes conventional exploration and development in Alberta,
British Columbia and Saskatchewan.
Canadian operations in 2005 were focused on expanding activity
into large-scale, repeatable drilling programs in conventional
and lower permeability reservoirs. Oil and gas capital
investments in Canada were $1,143 million, excluding
acquisitions, and 878 wells were drilled. Production in
Canada was 804 MMCF of natural gas per day, 24.2 MBbls
of NGLs per day and 6.0 MBbls of crude oil per day during
2005. The Company continued its resource assessment studies to
identify future drilling opportunities across the Sedimentary
Basin during 2005.
The Deep Basin area, in Alberta and British Columbia, consists
of the Elmworth, Wapiti, Noel and Brassey Fields. In 2005, a
$408 million oil and gas capital program was focused on
exploration and development in the Deep Basin area. As a result,
254 wells were drilled and 241 MMCF of natural gas per
day and 13.6 MBbls of NGLs per day were produced from this
area.
In the Foothills area, which borders on the west side of the
Deep Basin, $76 million of oil and gas capital spending was
focused on exploration and development and production was
52 MMCF of natural gas per day. In 2005, 16 wells were
drilled.
The OChiese area, in central Alberta, yielded production
of 150 MMCF of natural gas per day, 5.7 MBbls of NGLs
per day and 2.4 MBbls of crude oil per day in 2005. The
OChiese area was the focus of a $205 million
exploration and development program in 2005 that mostly targeted
the Lower Cretaceous and Jurassic sands, the principal
historical targets. In 2005, 144 wells were drilled.
In the Northern Plains, the Company continued exploration and
development activities in the northern Alberta and British
Columbia areas. Production in the Northern Plains during 2005
averaged 75 MMCF of natural gas per day and 2.2 MBbls
of NGLs per day. A $79 million capital program targeted the
Bluesky, Gething and Montney formations and 77 wells were
drilled during 2005.
In the Kaybob area, production for the year averaged
122 MMCF of natural gas per day, 1.9 MBbls of NGLs per
day and 0.9 MBbls of crude oil per day. The Company
invested $249 million and drilled 131 wells in this
area during 2005.
The Southern Plains area, which includes the Viking Kinsella
property, produced approximately 156 MMCF of natural gas
per day, 1.4 MBbls of crude oil per day and 0.8 MBbls
of NGLs per day in 2005. In 2005, the Company invested
$99 million and drilled 233 wells in the Southern
Plains area.
3
International
The Companys International activities include a
combination of exploration opportunities, large field
developments, and production operations. Key focus areas are
Northwest Europe, North Africa, China, and South America.
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% of |
Year Ended December 31, 2005 |
|
Worldwide |
|
International |
|
Worldwide |
|
|
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($ In Millions) |
|
|
Oil and gas capital expenditures
|
|
|
|
|
|
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|
|
|
|
|
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|
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Development
|
|
$ |
1,819 |
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|
$ |
127 |
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|
7 |
% |
|
|
Exploration
|
|
|
467 |
|
|
|
32 |
|
|
|
7 |
|
|
|
Acquisitionsproved
|
|
|
328 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Total oil and gas capital
expenditures
|
|
$ |
2,614 |
|
|
$ |
159 |
|
|
|
6 |
% |
|
|
Production
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (MMCF per day)
|
|
|
1,905 |
|
|
|
151 |
|
|
|
8 |
% |
|
|
NGLs (MBbls per day)
|
|
|
66.7 |
|
|
|
|
|
|
|
|
|
|
|
Crude oil (MBbls per day)
|
|
|
93.0 |
|
|
|
37.7 |
|
|
|
41 |
% |
|
December 31, 2005
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved reserves (TCFE)
|
|
|
12.5 |
|
|
|
1.1 |
|
|
|
9 |
% |
|
Northwest Europe
In the East Irish Sea, the Company has a 100 percent
working interest in seven operated gas fields, including Millom
and Dalton producing gas fields and the Rivers sour gas fields.
Net production from the East Irish Sea averaged 68 MMCF of
natural gas per day during 2005. The Company invested
$23 million of capital in this area during the year. At the
Rivers Fields, the Company continued the remedial work related
to the onshore terminal and production is expected to resume
during the first quarter of 2006. This facility is capable of
reaching a peak sales rate of approximately 100 MMCF of
natural gas per day.
During 2005, four wells were drilled in the East Irish Sea. One
well in the Dalton Field found sub-commercial quantities of gas
and was plugged and abandoned. Three other wells, on the Kelly,
Darwen East and Asland North prospects failed to encounter gas
in commercial quantities and were also plugged and abandoned.
The Companys Northwest European shelf investments also
consist of non-operated production from its wholly-owned
Netherlands affiliate in the Dutch sector of the North Sea. In
2005, the Netherlands affiliate CLAM was renamed
Burlington Resources Nederland Petroleum B.V. (BRN).
The BRN assets yielded an average production rate of
57 MMCF of natural gas per day during the year. BRN also
owns an interest in an exploration license in Denmark. License
01/04 in the Danish sector comprises 11 blocks or partial
blocks. The Company holds a 40 percent interest in the
blocks. In 2005, a total of 2,077 kilometers of 2D seismic was
acquired by DONG, the operator of the blocks.
North Africa
In North Africa, the Company continued progress in its
development programs in both Algeria and Egypt and approved
plans for future developments in both locations. The
Companys capital investments in North Africa during 2005
totaled $49 million.
In Algeria, at the Menzel Lejmat North (MLN) Field
on Block 405a, where the Company operates and has a
65 percent working interest, net production averaged
11.8 MBbls of crude oil per day. During 2005, the Company
approved the MLN Expansion Project which is expected to increase
field production and reserves through additional pressure
maintenance. One development well was drilled in the area in
2005.
The Ourhoud Field, where the Company has a 3.7 percent
working interest, produced at an average net rate of
4.8 MBbls of crude oil per day in 2005. Six development
wells, two injection wells and one water-source well were
drilled during 2005, and the waterflood development of this
large crude oil field was continued.
Development of oil reserves in the southern MLSE area of
Block 405a progressed with partners agreeing to form the
EMK oil field unit where the Company currently has a minority
interest in the unit. The partners have initiated engineering
studies and drilling activities with the expectation of
finalizing the development plan for the field in 2006. Capital
spending in 2005 was $4 million and two wells were drilled.
In Egypt, where the Company has a 50 percent non-operated
working interest in the Offshore North Sinai concession,
development of the Tao Gas Field was approved by the Company
during 2005. Detailed engineering studies are under way for the
facilities and pipelines, and plans are being developed to
commence drilling in 2006.
4
China
In the Far East, the Company continued its focus on selected
basins in China. The Company entered its second full year of
production at the Panyu Field in the South China Sea and
continued to pursue the first phase of its development plan for
its onshore gas development in the Sichuan Basin. The Company
made capital investments of $53 million in China in 2005.
The Panyu development involves two offshore oil fields, Bootes
and Ursa, located in Block 15/34 in the Pearl River Mouth
Basin. The Company holds a 24.5 percent working interest in
this asset. During 2005, the second phase of the development
drilling program was initiated. Government sanctioning was also
received and work commenced on a $5 million facilities
upgrade to handle the additional fluid volumes expected. In
addition, the plan of development was submitted to the
government for the
PY 11-6 discovery
which will be produced from the Bootes platform. In 2005,
average net production was 15.1 MBbls of crude oil per day.
Onshore, the Company holds a 100 percent working interest
in a natural gas project in the Chuanzhong Block in the Sichuan
Basin. The project represents an opportunity to apply the
Companys expertise in the development of tight gas sand
reservoirs. During 2005, the Company increased its net
production from 4 MMCF of natural gas per day to
8 MMCF of natural gas per day. Average annual net
production in 2005 was 6 MMCF of natural gas per day.
South America
The Companys efforts in South America during 2005 were
concentrated on expanding near-term production potential and
enhancing long-term exploration opportunities. Net production
from South America averaged 5.9 MBbls of crude oil per day
and 21 MMCF of natural gas per day. The Company invested
$38 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. Development of the Yuralpa Field in Block 21
continues where 11 wells were drilled during 2005. Net
production from Block 21 averaged 3.3 MBbls of crude
oil per day. In Block 7, six wells were successfully
drilled during the year. Net production from Block 7 was
2.5 MBbls of crude oil per day. The Companys capital
investments in 2005 totaled $26 million for projects in
Ecuador.
In Argentina, the Company holds a 25.7 percent working
interest in the Sierra Chata concession in the Neuquen Basin.
Three development wells were drilled during 2005. Net production
averaged 21 MMCF of natural gas per day in 2005 and capital
investments in Argentina totaled $2 million.
In Peru, the Company holds a 45 percent working interest in
Block 39 and operates Block 104 in the Marañon
Basin with a 100 percent working interest. The Company
participated in a discovery on Block 39 with the drilling
of the Buena Vista #1 well which tested a gross
2.5 MBbls of crude oil per day from two zones. Additional
drilling is expected to determine whether there are sufficient
reserves in the area to allow commercial development to proceed.
The Company also holds a 23.9 percent working interest in
Blocks 57 and 90 located in the Ucayali Basin. The
Companys capital investments in Peru totaled
$9 million during 2005.
In Colombia, the Company holds an exploration contract for a
100 percent working interest in the Orquídea area of
the Middle Magdalena Basin.
5
Productive Wells
Working interests in productive wells follow.
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2005 |
|
Gross |
|
Net |
|
North America
|
|
|
|
|
|
|
|
|
|
U.S.
|
|
|
|
|
|
|
|
|
|
|
Natural gas
|
|
|
12,326 |
|
|
|
7,042 |
|
|
|
Crude oil
|
|
|
2,712 |
|
|
|
1,293 |
|
|
Canada
|
|
|
|
|
|
|
|
|
|
|
Natural gas
|
|
|
6,308 |
|
|
|
4,897 |
|
|
|
Crude oil
|
|
|
1,078 |
|
|
|
547 |
|
International
|
|
|
|
|
|
|
|
|
|
|
Natural gas
|
|
|
207 |
|
|
|
67 |
|
|
|
Crude oil
|
|
|
205 |
|
|
|
57 |
|
|
Worldwide
|
|
|
|
|
|
|
|
|
|
|
Natural gas
|
|
|
18,841 |
|
|
|
12,006 |
|
|
|
Crude oil
|
|
|
3,995 |
|
|
|
1,897 |
|
|
|
|
|
Total Worldwide
|
|
|
22,836 |
|
|
|
13,903 |
|
|
Net Wells Drilled
The following table sets forth the Companys net productive
and dry wells.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
2005 |
|
2004 |
|
2003 |
|
North America
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Productive
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exploratory
|
|
|
13.5 |
|
|
|
3.9 |
|
|
|
0.9 |
|
|
|
|
Development
|
|
|
393.2 |
|
|
|
331.3 |
|
|
|
399.0 |
|
|
|
Dry
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exploratory
|
|
|
5.1 |
|
|
|
4.5 |
|
|
|
2.5 |
|
|
|
|
Development
|
|
|
11.7 |
|
|
|
4.0 |
|
|
|
5.3 |
|
|
|
|
|
|
Total U.S.
|
|
|
423.5 |
|
|
|
343.7 |
|
|
|
407.7 |
|
|
|
Canada
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Productive
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exploratory
|
|
|
85.0 |
|
|
|
32.6 |
|
|
|
102.5 |
|
|
|
|
Development
|
|
|
506.5 |
|
|
|
395.4 |
|
|
|
384.4 |
|
|
|
Dry
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exploratory
|
|
|
29.7 |
|
|
|
25.0 |
|
|
|
48.6 |
|
|
|
|
Development
|
|
|
51.7 |
|
|
|
27.2 |
|
|
|
57.6 |
|
|
|
|
|
|
Total Canada
|
|
|
672.9 |
|
|
|
480.2 |
|
|
|
593.1 |
|
|
International
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Productive
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exploratory
|
|
|
0.5 |
|
|
|
2.0 |
|
|
|
0.7 |
|
|
|
|
Development
|
|
|
13.0 |
|
|
|
8.5 |
|
|
|
10.9 |
|
|
|
Dry
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exploratory
|
|
|
5.0 |
|
|
|
3.1 |
|
|
|
1.8 |
|
|
|
|
Development
|
|
|
1.0 |
|
|
|
|
|
|
|
1.0 |
|
|
|
|
|
|
Total International
|
|
|
19.5 |
|
|
|
13.6 |
|
|
|
14.4 |
|
|
Worldwide
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Productive
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exploratory
|
|
|
99.0 |
|
|
|
38.5 |
|
|
|
104.1 |
|
|
|
|
Development
|
|
|
912.7 |
|
|
|
735.2 |
|
|
|
794.3 |
|
|
|
Dry
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exploratory
|
|
|
39.8 |
|
|
|
32.6 |
|
|
|
52.9 |
|
|
|
|
Development
|
|
|
64.4 |
|
|
|
31.2 |
|
|
|
63.9 |
|
|
|
|
|
|
Total Worldwide
|
|
|
1,115.9 |
|
|
|
837.5 |
|
|
|
1,015.2 |
|
|
As of December 31, 2005, 380 gross wells, representing
approximately 281 net wells, were being drilled or awaiting
completion with 67 percent and 31 percent of these
wells located in Canada and the U.S., respectively.
6
Acreage
Working interests in developed and undeveloped acreage follow.
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2005 |
|
Gross |
|
Net |
|
North America
|
|
|
|
|
|
|
|
|
|
U.S.
|
|
|
|
|
|
|
|
|
|
|
Developed Acreage
|
|
|
4,658,680 |
|
|
|
2,661,973 |
|
|
|
Undeveloped Acreage
|
|
|
9,586,087 |
|
|
|
8,106,349 |
|
|
Canada
|
|
|
|
|
|
|
|
|
|
|
Developed Acreage
|
|
|
3,670,010 |
|
|
|
2,463,999 |
|
|
|
Undeveloped Acreage
|
|
|
4,638,729 |
|
|
|
3,133,984 |
|
International
|
|
|
|
|
|
|
|
|
|
|
Developed Acreage
|
|
|
719,389 |
|
|
|
235,092 |
|
|
|
Undeveloped Acreage
|
|
|
12,978,084 |
|
|
|
6,829,801 |
|
|
Worldwide
|
|
|
|
|
|
|
|
|
|
|
Developed Acreage
|
|
|
9,048,079 |
|
|
|
5,361,064 |
|
|
|
Undeveloped Acreage
|
|
|
27,202,900 |
|
|
|
18,070,134 |
|
|
|
|
|
Total Worldwide
|
|
|
36,250,979 |
|
|
|
23,431,198 |
|
|
Capital Expenditures
The Companys capital expenditures follow.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
2005 |
|
2004 |
|
2003 |
|
|
|
(In Millions) |
|
North America
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and Gas Activities
|
|
$ |
1,278 |
|
|
$ |
712 |
|
|
$ |
540 |
|
|
|
Plants and Pipelines
|
|
|
3 |
|
|
|
3 |
|
|
|
5 |
|
|
|
Administrative and Other
|
|
|
14 |
|
|
|
24 |
|
|
|
23 |
|
|
|
|
|
Total U.S.
|
|
|
1,295 |
|
|
|
739 |
|
|
|
568 |
|
|
|
Canada
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and Gas Activities
|
|
|
1,177 |
|
|
|
802 |
|
|
|
679 |
|
|
|
Plants and Pipelines
|
|
|
27 |
|
|
|
31 |
|
|
|
19 |
|
|
|
Administrative and Other
|
|
|
13 |
|
|
|
9 |
|
|
|
17 |
|
|
|
|
|
Total Canada
|
|
|
1,217 |
|
|
|
842 |
|
|
|
715 |
|
|
International
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and Gas Activities
|
|
|
159 |
|
|
|
130 |
|
|
|
366 |
|
|
|
Plants and Pipelines
|
|
|
14 |
|
|
|
32 |
|
|
|
139 |
|
|
|
Administrative and Other
|
|
|
2 |
|
|
|
4 |
|
|
|
|
|
|
|
|
|
Total International
|
|
|
175 |
|
|
|
166 |
|
|
|
505 |
|
|
Worldwide
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and Gas Activities
|
|
|
2,614 |
|
|
|
1,644 |
|
|
|
1,585 |
|
|
|
Plants and Pipelines
|
|
|
44 |
|
|
|
66 |
|
|
|
163 |
|
|
|
Administrative and Other
|
|
|
29 |
|
|
|
37 |
|
|
|
40 |
|
|
|
|
|
Total Worldwide
|
|
$ |
2,687 |
|
|
$ |
1,747 |
|
|
$ |
1,788 |
|
|
In 2005, worldwide capital expenditures related to oil and gas
activities were $2,614 million and included 70 percent
associated with development, 18 percent for exploration and
12 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, |
|
2005 |
|
2004 |
|
2003 |
|
North America
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (MMCF per day)
|
|
|
950 |
|
|
|
908 |
|
|
|
865 |
|
|
|
|
NGLs (MBbls per day)
|
|
|
42.5 |
|
|
|
41.7 |
|
|
|
37.4 |
|
|
|
|
Crude oil (MBbls per day)
|
|
|
49.3 |
|
|
|
37.2 |
|
|
|
29.3 |
|
|
|
Average Sales Price
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas, including hedging (per
MCF)
|
|
$ |
7.27 |
|
|
$ |
5.54 |
|
|
$ |
4.87 |
|
|
|
|
|
Natural gas, (gain) loss on
hedging (per MCF)
|
|
|
0.26 |
|
|
|
(0.02 |
) |
|
|
0.10 |
|
|
|
|
|
Natural gas, excluding hedging (per
MCF)
|
|
|
7.53 |
|
|
|
5.52 |
|
|
|
4.97 |
|
|
|
|
|
NGLs (per Bbl)
|
|
|
28.45 |
|
|
|
22.87 |
|
|
|
18.42 |
|
|
|
|
|
Crude oil, including hedging (per
Bbl)
|
|
|
50.39 |
|
|
|
36.31 |
|
|
|
28.08 |
|
|
|
|
|
Crude oil, loss on hedging (per Bbl)
|
|
|
1.50 |
|
|
|
2.28 |
|
|
|
0.14 |
|
|
|
|
|
Crude oil, excluding hedging (per
Bbl)
|
|
$ |
51.89 |
|
|
$ |
38.59 |
|
|
$ |
28.22 |
|
|
Canada
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (MMCF per day)
|
|
|
804 |
|
|
|
819 |
|
|
|
867 |
|
|
|
|
NGLs (MBbls per day)
|
|
|
24.2 |
|
|
|
23.6 |
|
|
|
27.4 |
|
|
|
|
Crude oil (MBbls per day)
|
|
|
6.0 |
|
|
|
5.5 |
|
|
|
5.1 |
|
|
|
Average Sales Price
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas, including hedging (per
MCF)
|
|
$ |
7.54 |
|
|
$ |
5.85 |
|
|
$ |
5.12 |
|
|
|
|
|
Natural gas, loss on hedging (per
MCF)
|
|
|
0.23 |
|
|
|
0.05 |
|
|
|
0.10 |
|
|
|
|
|
Natural gas, excluding hedging (per
MCF)
|
|
|
7.77 |
|
|
|
5.90 |
|
|
|
5.22 |
|
|
|
|
|
NGLs (per Bbl)
|
|
|
40.68 |
|
|
|
29.79 |
|
|
|
23.08 |
|
|
|
|
|
Crude oil (per Bbl)
|
|
$ |
52.20 |
|
|
$ |
37.70 |
|
|
$ |
31.11 |
|
International
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (MMCF per day)
|
|
|
151 |
|
|
|
187 |
|
|
|
167 |
|
|
|
|
Crude oil (MBbls per day)
|
|
|
37.7 |
|
|
|
42.5 |
|
|
|
12.1 |
|
|
|
Average Sales Price
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas, including hedging (per
MCF)
|
|
$ |
5.16 |
|
|
$ |
3.64 |
|
|
$ |
3.07 |
|
|
|
|
|
Natural gas, loss on hedging (per
MCF)
|
|
|
0.07 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas, excluding hedging (per
MCF)
|
|
|
5.23 |
|
|
|
3.64 |
|
|
|
3.07 |
|
|
|
|
|
Crude oil (per Bbl)
|
|
$ |
51.10 |
|
|
$ |
35.94 |
|
|
$ |
23.49 |
|
|
Worldwide
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (MMCF per day)
|
|
|
1,905 |
|
|
|
1,914 |
|
|
|
1,899 |
|
|
|
|
NGLs (MBbls per day)
|
|
|
66.7 |
|
|
|
65.3 |
|
|
|
64.8 |
|
|
|
|
Crude oil (MBbls per day)
|
|
|
93.0 |
|
|
|
85.2 |
|
|
|
46.5 |
|
|
|
Average Sales Price
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas, including hedging (per
MCF)
|
|
$ |
7.22 |
|
|
$ |
5.49 |
|
|
$ |
4.83 |
|
|
|
|
|
Natural gas, loss on hedging (per
MCF)
|
|
|
0.23 |
|
|
|
0.01 |
|
|
|
0.09 |
|
|
|
|
|
Natural gas, excluding hedging (per
MCF)
|
|
|
7.45 |
|
|
|
5.50 |
|
|
|
4.92 |
|
|
|
|
|
NGLs (per Bbl)
|
|
|
32.88 |
|
|
|
25.38 |
|
|
|
20.40 |
|
|
|
|
|
Crude oil, including hedging (per
Bbl)
|
|
|
50.77 |
|
|
|
36.25 |
|
|
|
27.22 |
|
|
|
|
|
Crude oil, loss on hedging (per Bbl)
|
|
|
0.80 |
|
|
|
0.99 |
|
|
|
0.09 |
|
|
|
|
|
Crude oil, excluding hedging (per
Bbl)
|
|
$ |
51.57 |
|
|
$ |
37.24 |
|
|
$ |
27.31 |
|
|
8
Production Unit Costs
The Companys production unit costs follow. Production
costs include production taxes and well operating costs.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
2005 |
|
2004 |
|
2003 |
|
|
|
|
(Per MCFE) |
|
North America
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Production Costs
|
|
$ |
0.98 |
|
|
$ |
0.80 |
|
|
$ |
0.68 |
|
|
|
Average Production Taxes
|
|
|
0.55 |
|
|
|
0.42 |
|
|
|
0.34 |
|
|
|
DD&A Rates
|
|
|
0.76 |
|
|
|
0.68 |
|
|
|
0.62 |
|
|
Canada
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Production Costs
|
|
|
0.60 |
|
|
|
0.55 |
|
|
|
0.44 |
|
|
|
Average Production Taxes
|
|
|
0.05 |
|
|
|
0.04 |
|
|
|
0.03 |
|
|
|
DD&A Rates
|
|
|
1.73 |
|
|
|
1.41 |
|
|
|
1.19 |
|
International
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Production Costs
|
|
|
0.83 |
|
|
|
0.60 |
|
|
|
0.53 |
|
|
|
Average Production Taxes
|
|
|
0.11 |
|
|
|
0.09 |
|
|
|
0.01 |
|
|
|
DD&A Rates
|
|
|
1.45 |
|
|
|
1.32 |
|
|
|
1.14 |
|
|
Worldwide
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Production Costs
|
|
|
0.83 |
|
|
|
0.68 |
|
|
|
0.57 |
|
|
|
Average Production Taxes
|
|
|
0.32 |
|
|
|
0.23 |
|
|
|
0.18 |
|
|
|
DD&A Rates
|
|
$ |
1.18 |
|
|
$ |
1.04 |
|
|
$ |
0.91 |
|
|
Reserves
The following table sets forth estimates by the Companys
petroleum engineers of proved natural gas, NGLs and crude oil
reserves at December 31, 2005. 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, 2005 |
|
Developed |
|
Undeveloped |
|
Reserves |
|
North America
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (BCF)
|
|
|
3,752 |
|
|
|
1,523 |
|
|
|
5,275 |
|
|
|
NGLs (MMBbls)
|
|
|
221.4 |
|
|
|
109.4 |
|
|
|
330.8 |
|
|
|
Crude oil (MMBbls)
|
|
|
172.0 |
|
|
|
13.8 |
|
|
|
185.8 |
|
|
|
|
Total U.S. (BCFE)
|
|
|
6,113 |
|
|
|
2,262 |
|
|
|
8,375 |
|
|
Canada
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (BCF)
|
|
|
1,956 |
|
|
|
583 |
|
|
|
2,539 |
|
|
|
NGLs (MMBbls)
|
|
|
45.1 |
|
|
|
12.6 |
|
|
|
57.7 |
|
|
|
Crude oil (MMBbls)
|
|
|
13.3 |
|
|
|
2.9 |
|
|
|
16.2 |
|
|
|
|
Total Canada (BCFE)
|
|
|
2,306 |
|
|
|
676 |
|
|
|
2,982 |
|
International
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (BCF)
|
|
|
398 |
|
|
|
296 |
|
|
|
694 |
|
|
|
Crude oil (MMBbls)
|
|
|
42.5 |
|
|
|
29.7 |
|
|
|
72.2 |
|
|
|
|
Total International (BCFE)
|
|
|
653 |
|
|
|
474 |
|
|
|
1,127 |
|
|
Worldwide
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (BCF)
|
|
|
6,106 |
|
|
|
2,402 |
|
|
|
8,508 |
|
|
|
NGLs (MMBbls)
|
|
|
266.5 |
|
|
|
122.0 |
|
|
|
388.5 |
|
|
|
Crude oil (MMBbls)
|
|
|
227.8 |
|
|
|
46.4 |
|
|
|
274.2 |
|
|
|
|
Total Worldwide (BCFE)
|
|
|
9,072 |
|
|
|
3,412 |
|
|
|
12,484 |
|
|
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, 2005. 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 68-72.
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.
9
Other Matters
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
Superfund); |
|
|
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, 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.
10
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 2005, the Company filed estimates of its oil and gas
reserves for the year 2004 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 2,416 and 2,214 employees at December 31,
2005 and 2004, respectively. At December 31, 2005, 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 ONE A
RISK FACTORS
Business Uncertainties and Contractual Restrictions While
Merger is Pending Uncertainty about the effect of the
merger on employees, suppliers, partners, regulators and
customers may have an adverse effect on BR. These uncertainties
may impair BRs ability to attract, retain and motivate key
personnel until the merger is consummated, and could cause
suppliers, customers and others that deal with BR to defer
purchases or other decisions concerning BR, or seek to change
existing business relationships with BR. Employee retention may
be particularly challenging while the merger is pending, as
employees may experience uncertainty about their future roles
with ConocoPhillips. In addition, the merger agreement restricts
BR from making certain acquisitions and taking other specified
actions without ConocoPhillips approval. These
restrictions could prevent BR from pursuing attractive business
opportunities that may arise prior to the completion of the
merger.
Failure to Complete Merger Could Negatively Impact Stock
Price, Future Business and Financial Results Although
BR has agreed that its board of directors will, subject to
fiduciary exceptions, recommend that its stockholders approve
and adopt the merger agreement, there is no assurance that the
merger agreement and the merger will be approved, and there is
no assurance that the other conditions to the completion of the
merger will be satisfied. If the merger is not completed, BR
will be subject to several risks, including the following:
|
|
|
BR may be required to pay ConocoPhillips a termination fee of
$1 billion in the aggregate if the merger agreement is
terminated under certain circumstances and BR enters into or
completes an alternative transaction; |
|
|
The current market price of BR common stock may reflect a market
assumption that the merger will occur, and a failure to complete
the merger could result in a negative perception by the stock
market of BR generally and a resulting decline in the market
price of BR common stock; |
|
|
Certain costs relating to the merger (such as legal, accounting
and financial advisory fees) are payable by BR whether or not
the merger is completed; |
|
|
There may be substantial disruption to the business of BR and a
distraction of its management and employees from
day-to-day operations,
because matters related to the merger (including integration
planning) may require substantial commitments of time and
resources, which could otherwise have been devoted to other
opportunities that could have been beneficial to BR; |
|
|
BRs business could be adversely affected if it is unable
to retain key employees or attract qualified
replacements; and |
|
|
BR would continue to face the risks that it currently faces as
an independent company. |
Changes in Commodity Prices Could Have a Significant Adverse
Effect on Financial Results, Impact the Companys
Determination of Proved Reserves and Result in the Company
Recognizing an Impairment 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.
Risks and Uncertainties Normally Associated with the
Exploration for and Development and Production of Natural Gas
Could Significantly Impact the Companys Operations and
Financial Results 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
12
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 proved 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 prices, market demand
and the political, economic and regulatory climate. In addition,
Organization of Petroleum Exporting 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.
Concentration Risk for Natural Gas Transportation
Because the Company transports a significant amount of its
natural gas production through a limited number of pipeline
systems, mechanical failure or regulatory action at certain
points on these pipeline systems could result in a substantial
interruption of the transportation of the Companys natural
gas production for a limited period of time pending the Company
securing alternate transportation arrangements.
Assumptions Used in Valuing Goodwill Are Inherently
Unpredictable and Uncertain and Revisions to Estimates Could
Lead to an Impairment in Future Periods The Company
accounts for goodwill in accordance with Statement of Financial
Accounting Standards 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.
Numerous Factors Affecting the Timing and Outcome of Projects
Could Have a Significant Adverse Impact on the Companys
Development Plan 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.
The Companys International Operations Are Subject to
Risks Which May Adversely Affect the Companys
Operations 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
13
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 in the Crude Oil and Natural Gas Industry is
Intense; the Company Competes with Companies with Substantially
Larger Financial and Other Resources 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.
Foreign, National, State and Local Laws and Regulations Could
Negatively Impact the Companys Operations or Financial
Results 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 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 Could Have a Significant Adverse
Effect on the Companys Operations or Financial
Results 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. Terrorist attacks and the threat of
terrorist attacks, whether domestic or foreign, as well as the
military or other actions taken in response, cause instability
in the global financial and energy markets. Terrorism and other
geopolitical hostilities could adversely affect production or
the market prices in unpredictable ways, including through the
disruption of fuel supplies and markets, increased volatility in
crude oil and natural gas prices, or the possibility that the
infrastructure on which the Company or operators developing the
underlying properties rely could be a direct target or an
indirect casualty of an act of terror.
Various Regulations Relating to the Protection of the
Environment May Significantly Affect the Companys
Exploration, Development and Production, Including the Cost of
Operations, and Could Result in Substantial Liabilities for
Noncompliance or Suspension of Operations in Affected
Areas 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.
14
ITEM ONE B
UNRESOLVED STAFF COMMENTS
None
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 2005.
EXECUTIVE OFFICERS OF THE REGISTRANT
Bobby S. Shackouls, 55 Chairman of the Board,
President and Chief Executive Officer, Burlington Resources
Inc., July 1997 to present.
Randy L. Limbacher, 47 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.
Steven J. Shapiro, 53 Office of the Chairman,
Burlington Resources Inc., January 2004 to present. Executive
Vice President, Finance and Corporate Development, Burlington
Resources Inc., April 2005 to present. Executive Vice President
and Chief Financial Officer, Burlington Resources Inc., December
2002 to April 2005. Senior Vice President and Chief Financial
Officer, Burlington Resources Inc., October 2000 to December
2002.
Mark E. Ellis, 49 Senior Vice President, North
American Production, Burlington Resources Inc., September 2004
to present. President, Burlington Resources Canada Ltd., October
2000 to September 2004.
L. David Hanower, 46 Senior Vice President,
Law and Administration, Burlington Resources Inc., July 1998 to
present.
Joseph P. McCoy, 54 Senior Vice President and Chief
Financial Officer, Burlington Resources Inc., April 2005 to
present. Vice President and Controller, Burlington Resources
Inc., May 2001 to April 2005. Vice President and Controller,
Vastar Resources, Inc., May 1994 to March 2001.
John A. Williams, 61 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.
15
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, 2005, the number of record holders of
Common Stock was 10,522. 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, 2005
October 31, 2005
|
|
|
1,143 |
|
|
$ |
71.03 |
|
|
|
1,143 |
|
|
$ |
984,533 |
|
November 1, 2005
November 30, 2005
|
|
|
1,584 |
|
|
|
70.47 |
|
|
|
1,584 |
|
|
|
872,904 |
|
December 1, 2005
December 31, 2005
|
|
|
220 |
|
|
|
74.26 |
|
|
|
220 |
|
|
$ |
856,596 |
|
|
|
Total
|
|
|
2,947 |
|
|
$ |
70.97 |
|
|
|
2,947 |
|
|
|
|
|
|
|
|
(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 Companys
Board voted to restore the authorization level to
$1 billion. Through October 25, 2005, the Company had
the authority to purchase $193 million of its Common Stock
under the program authorized in December 2004. On
October 26, 2005, the Company announced that the Board
voted to restore the authorization level to $1 billion.
Through December 31, 2005, the Company had the authority to
purchase $857 million of its Common Stock under the current
authorization. |
16
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, |
|
2005 |
|
2004 |
|
2003 |
|
2002 |
|
2001 |
|
|
|
|
|
(In Millions, Except per Share Amounts) |
|
INCOME STATEMENT DATA
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues
|
|
$ |
7,587 |
|
|
$ |
5,618 |
|
|
$ |
4,311 |
|
|
$ |
2,968 |
|
|
$ |
3,419 |
|
|
Income Before Income Taxes and
Cumulative Effect of Change in Accounting Principle
|
|
|
4,048 |
|
|
|
2,304 |
|
|
|
1,570 |
|
|
|
569 |
|
|
|
907 |
|
|
Cumulative Effect of Change in
Accounting Principle Net(2)
|
|
|
|
|
|
|
|
|
|
|
(59 |
) |
|
|
|
|
|
|
3 |
|
|
Net Income(1)
|
|
|
2,710 |
|
|
|
1,527 |
|
|
|
1,201 |
|
|
|
454 |
|
|
|
561 |
|
|
Basic Earnings per Common
Share(1)(2)
|
|
|
7.13 |
|
|
|
3.90 |
|
|
|
3.02 |
|
|
|
1.13 |
|
|
|
1.35 |
|
|
Diluted Earnings per Common
Share(1)(2)
|
|
|
7.07 |
|
|
|
3.86 |
|
|
|
3.00 |
|
|
|
1.13 |
|
|
|
1.35 |
|
|
Cash Dividends Declared per Common
Share
|
|
$ |
0.37 |
|
|
$ |
0.32 |
|
|
$ |
0.29 |
|
|
$ |
0.28 |
|
|
$ |
0.28 |
|
|
December 31, |
|
BALANCE SHEET DATA
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Assets
|
|
$ |
19,225 |
|
|
$ |
15,744 |
|
|
$ |
12,995 |
|
|
$ |
10,645 |
|
|
$ |
10,582 |
|
|
Long-term Debt
|
|
|
3,893 |
|
|
|
3,887 |
|
|
|
3,873 |
|
|
|
3,853 |
|
|
|
4,337 |
|
|
Stockholders Equity
|
|
$ |
8,935 |
|
|
$ |
7,011 |
|
|
$ |
5,521 |
|
|
$ |
3,832 |
|
|
$ |
3,525 |
|
|
Common Shares Outstanding
|
|
|
375 |
|
|
|
388 |
|
|
|
395 |
|
|
|
403 |
|
|
|
402 |
|
|
|
|
(1) |
Year 2005 includes an after tax gain of $149 million
($240 million pretax) or $0.39 per share related to
the sale of 16,950,000 units of beneficial interest in the
Permian Basin Royalty Trust held by the Company. Year 2005 also
includes a non-cash after tax charge of $34 million
($50 million pretax) or $0.09 per share primarily
related to the impairment of properties in onshore China. |
|
|
Year 2005 and 2004 include income tax benefits of
$51 million or $0.13 per share and $23 million or
$0.06 per share, respectively, related to the reduction of
the Canadian federal statutory income tax rate. Year 2004 also
includes an income tax benefit of $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 in 2005
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) after tax loss of
$59 million ($95 million pretax) or $0.15 per
share related to the adoption of Statement of Financial
Accounting Standards (SFAS) No. 143, Asset
Retirement Obligations. Year 2001 includes a Cumulative
Effect after tax gain of $3 million ($4 million
pretax) or $0.01 per share related to the adoption of
SFAS No. 133, Accounting for Derivative Instruments
and Hedging Activities, as amended. |
17
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, from its
properties primarily located in the onshore U.S. and western
Canada, 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 various areas of its 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. In recent years, the
Company has put considerable emphasis 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
sustain its production growth goals. 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 on 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. Margin
enhancement is another important element of the Companys
business, including focus on operating costs, administrative
expenses and marketing activities, such as securing
transportation to alternative market hubs to protect 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 themselves natural 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
18
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
On December 12, 2005, BR and ConocoPhillips entered into a
definitive agreement under which ConocoPhillips will acquire BR.
Under the terms of the agreement, BR shareholders will receive
$46.50 in cash and 0.7214 shares of ConocoPhillips common
stock for each BR share they own. The transaction is subject to
approval by BR shareholders of record on February 24, 2006
and other customary terms and conditions. A special meeting of
shareholders to vote on the proposed merger is March 30,
2006. Regulatory approvals have been granted and, upon approval
by shareholders, the transaction is expected to close by
March 31, 2006.
The merger agreement (Agreement) provides that until
the effective time of the merger, BR will conduct its business
in the ordinary course in all material respects, in
substantially the same manner as conducted prior to the date of
the Agreement, subject to certain conditions and restrictions as
set forth in the Agreement. In addition, BR has agreed not to,
except with prior written consent of ConocoPhillips, incur or
commit to any capital expenditures, other than in the ordinary
course of business or as contemplated by the 2006 capital
budget. BR has agreed to pay ConocoPhillips a $1 billion
termination fee in cash if BR terminates the Agreement prior to
the approval by BRs shareholders of the Agreement, if
BRs board of directors has determined that it has received
a superior proposal and BR has complied with its obligation with
respect to non-solicitation of other acquisition proposals and
conditions.
In the ordinary course of business, 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 its North America business to represent
approximately 88 percent of its total production in 2006.
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 approximately 12 percent
of the Companys total production in 2006.
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
19
proved reserve additions attributable to investments accounted
for using the equity method in calculating its reserve
replacement ratio. It should be noted that 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 the
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 2005, the Companys
reserve replacement costs were $1.68 per MCFE including
acquisitions or $1.61 per MCFE excluding acquisitions. The
increase in costs in 2005 compared to 2004 was primarily due to
industry service cost 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, 2005, the
Companys average reserve replacement costs were
$1.40 per MCFE including acquisitions and $1.39 per
MCFE excluding acquisitions. As used herein, reserve replacement
costs represent total oil and gas capital costs, including
acquisitions, incurred in order to add reserves. Reserve
replacement costs per unit are calculated by dividing total oil
and gas capital costs, including acquisitions, by the sum of
reserve revisions, extensions, discoveries and other additions
and acquisitions. The costs used to calculate reserve
replacement costs include the costs of development, exploration,
and property acquisition activities as presented in the
Supplemental Oil and Gas Disclosures table on page 73 of
this report.
Set forth below are the Companys reserve replacement ratio
and reserve replacement costs per unit, along with the
Companys capital expenditures.
Reserve Replacement
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
2005 |
|
2004 |
|
2003 |
|
|
|
($ per MCFE) |
|
Reserve replacement costs,
including acquisitions
|
|
$ |
1.68 |
|
|
$ |
1.27 |
|
|
$ |
1.19 |
|
Reserve replacement costs,
excluding acquisitions
|
|
$ |
1.61 |
|
|
$ |
1.27 |
|
|
$ |
1.23 |
|
|
|
|
(% of Production)
|
|
Reserve replacement ratio,
including acquisitions
|
|
|
149% |
|
|
|
125% |
|
|
|
142% |
|
Reserve replacement ratio,
excluding acquisitions
|
|
|
136% |
|
|
|
119% |
|
|
|
118% |
|
|
Capital Expenditures
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
2005 |
|
2004 |
|
2003 |
|
|
|
(In Millions) |
|
Total capital expenditures
|
|
$ |
2,687 |
|
|
$ |
1,747 |
|
|
$ |
1,788 |
|
Less: acquisitions
|
|
|
328 |
|
|
|
85 |
|
|
|
228 |
|
|
Capital expenditures, excluding
acquisitions
|
|
$ |
2,359 |
|
|
$ |
1,662 |
|
|
$ |
1,560 |
|
|
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 and
immediately adjacent 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 27 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
80 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.
20
In 2006, the Company expects to spend approximately
$3.1 billion of capital, plus approved acquisitions. This
level of spending represents a 33 percent increase over
2005 capital. The Company currently believes that this level of
spending is needed to achieve its objective of three to eight
percent average annual production growth. Approximately
88 percent of the Companys 2006 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 26 percent from prior year.
Below is a discussion of the Companys production levels
and expected production growth.
Production
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
2005 |
|
2004 |
|
2003 |
|
|
|
(MMCFE per day)
|
|
U.S.
|
|
|
1,501 |
|
|
|
1,381 |
|
|
|
1,265 |
|
Canada
|
|
|
985 |
|
|
|
994 |
|
|
|
1,062 |
|
International
|
|
|
377 |
|
|
|
442 |
|
|
|
240 |
|
|
|
Total production
|
|
|
2,863 |
|
|
|
2,817 |
|
|
|
2,567 |
|
|
The Company has a goal to achieve between three and eight
percent average annual production growth. In 2005, production
volumes were 2,863 MMCFE per day, representing a
2 percent increase over 2004. In 2006, the Company expects
production volumes to average between 2,940 and 3,100 MMCFE
per day.
The Company expects production growth in the U.S. during
2006 to be driven by increased production from Bossier, Cedar
Creek, and Barnett Shale drilling programs. Production from the
Rivers Fields commenced in October 2004; however, in November
2004, problems were encountered related to the acid plant.
Production is expected to resume during the first quarter of
2006. The Company expects production from its international
operations to range from a decline of 8 percent to an
increase of 7 percent compared to production levels in
2005. In 2006, the Company expects production in Canada to
decline from 1 to 4 percent compared to production levels
in 2005.
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 in the
U.S. are currently available and therefore continues to
focus 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 the first quarter of 2006, the Company
expects its operating costs to increase 7 to 13 percent and
administrative expense to decrease 17 to 33 percent
compared to the full year of 2005 on a per
unit-of-production
basis. The Company expects its operating costs to increase
primarily due to industry service cost pressures. The Company
expects administrative expense, which includes expenses related
to compensation plans that are correlated to the Company stock,
to decrease in the first quarter of 2006 compared to the full
year of 2005. The Company expects DD&A expense to increase
11 to 19 percent on a unit-of-production basis in the first
quarter of 2006 compared to the full year of 2005, 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.
Below are estimated and actual costs and expenses for the first
quarter of 2006 and the full year of 2005, respectively.
|
|
|
|
|
|
|
|
|
|
|
First Quarter |
|
Full Year |
|
|
2006 |
|
2005 |
|
|
|
($ per MCFE) |
|
Transportation expense
|
|
$ |
0.46 to $0.50 |
|
|
$ |
0.47 |
|
Operating costs
|
|
|
0.72 to 0.76 |
|
|
|
0.67 |
|
DD&A
|
|
|
1.40 to 1.50 |
|
|
|
1.26 |
|
Administrative
|
|
$ |
0.16 to $0.20 |
|
|
$ |
0.24 |
|
|
|
|
(In Millions)
|
|
Exploration costs
|
|
$ |
60 to $ 80 |
|
|
$ |
293 |
|
Interest expense
|
|
$ |
68 to $ 72 |
|
|
$ |
281 |
|
|
21
Transportation expense in 2006 compared to 2005 is expected to
range from a decrease of 2 percent to an increase of
6 percent, on a
unit-of-production
basis. The expected increase in transportation expense primarily
results from the anticipated increase in production volumes in
the U.S. 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
accurately forecast its exploration success rate but it expects
exploration costs to exceed the costs incurred in 2005 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 2005, 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 2005, the
Company estimates that a $1.00 per barrel change in crude
oil prices would impact annual crude oil revenues approximately
$34 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. In accordance with the terms of the Agreement
between BR and ConocoPhillips, individual acquisitions by the
Company in excess of $50 million are subject to approval by
ConocoPhillips.
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, 2005 and December 31, 2004 was
30 percent and 36 percent, respectively. The
17 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 2006 capital expenditures, excluding any
potential major acquisition(s). At December 31, 2005, the
Company had $3,528 million of cash and cash equivalents on
hand, of which $1,948 million was located in Canada,
$1,285 million in the U.S. and $295 million in
International. On October 27, 2005, the Company repatriated
$500 million of eligible foreign earnings to the
U.S. 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.
On April 14, 2005, the Company filed as co-registrant with
the Permian Basin Royalty Trust (Royalty Trust) a
registration statement on
Form S-3 with the
SEC registering the sale from time to time, in one or more
offerings, of up to 27,577,741 units of beneficial interest
in the Royalty Trust (Units) held by the Company.
During the second half of 2005, the Company sold
22
16,950,000 Units, generating proceeds, after underwriting fees,
of approximately $252 million. Net proceeds generated from
the sale of Units were used primarily for the acquisitions of
oil and gas properties. At December 31, 2005,
$64 million of the net proceeds generated from the sale of
Units were on deposit with a third-party intermediary to be used
to purchase oil and gas properties during 2006.
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 sub-limit for the issuance of letters of
credit, including up to US$250 million in letters of credit
under the Canadian subfacility. On August 17, 2005, the
Company amended the Credit Facility to extend the expiration
date from July 2009 to August 2010. 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 repay 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, 2005, 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 2005 increased
$1,100 million and $1,997 million over 2004 and 2003,
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
32 percent and 49 percent over 2004 and 2003,
respectively. Crude oil prices increased 40 percent and
87 percent over 2004 and 2003, respectively, while NGLs
prices increased 30 percent and 61 percent over the
same period. Crude oil volumes increased 9 percent and
100 percent over 2004 and 2003, respectively. NGLs volumes
increased 2 percent and 3 percent over 2004 and 2003,
respectively. Natural gas volumes in 2005 were essentially the
same as 2004 and 2003. Although the Company believes that 2006
production volumes will exceed 2005 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 2005 is not necessarily indicative of future cash flows from
operating activities. See page 22 for a discussion of
commodity prices.
The increase in net cash provided by operating activities
resulting from higher commodity prices and higher production
volumes was partially offset by higher costs and expenses. In
2005, costs and expenses that affect net operating cash provided
by operating activities primarily include operating costs, taxes
other than income taxes, transportation expenses, and
administrative expenses. These costs and expenses increased
$289 million and $570 million over 2004 and 2003,
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. Well operating expenses accounted for 24 percent
and 30 percent of the increase in costs and expenses over
2004 and 2003, respectively. Taxes other than income taxes
include severance taxes, which are directly correlated to crude
oil and natural gas revenues. Severance taxes accounted for
25 percent and 24 percent of the increase in costs and
expenses over 2004 and 2003, respectively. For revenue, price,
volume and costs and expense variances, see tables and
explanations on pages 29-34.
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, 2005 was
149 percent and has averaged 139 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 2006.
23
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, 2005.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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)
|
|
$ |
3,933 |
|
|
$ |
502 |
|
|
$ |
481 |
|
|
$ |
1,228 |
|
|
$ |
1,722 |
|
Interest payments on long-term debt
|
|
|
3,421 |
|
|
|
270 |
|
|
|
656 |
|
|
|
378 |
|
|
|
2,117 |
|
Transportation demand charges(2)
|
|
|
797 |
|
|
|
152 |
|
|
|
288 |
|
|
|
119 |
|
|
|
238 |
|
Non-cancellable operating leases(2)
|
|
|
307 |
|
|
|
36 |
|
|
|
100 |
|
|
|
71 |
|
|
|
100 |
|
Postretirement benefits(3)
|
|
|
29 |
|
|
|
3 |
|
|
|
9 |
|
|
|
6 |
|
|
|
11 |
|
Pension funding(3)
|
|
|
12 |
|
|
|
12 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Drilling rig commitments(2)
|
|
|
139 |
|
|
|
65 |
|
|
|
69 |
|
|
|
5 |
|
|
|
|
|
|
|
Total Contractual
Obligations
|
|
$ |
8,638 |
|
|
$ |
1,040 |
|
|
$ |
1,603 |
|
|
$ |
1,807 |
|
|
$ |
4,188 |
|
|
|
|
(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 also has liabilities of $604 million related to
asset retirement obligations on its Consolidated Balance Sheet
at December 31, 2005. 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, 2005, the Company has a
BBB+ long-term debt rating from Standard & Poors and A3
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, 2005, the aggregate
unfavorable
mark-to-market position
under the aforementioned hedging agreements was approximately
$72 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 $33 million as of December 31, 2005.
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 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 Companys
Board voted to restore the authorization level to
$1 billion. Through October 25, 2005, the Company had
the authority to purchase $193 million of its Common Stock
under the program authorized in December 2004. On
October 26, 2005, the Company announced that the Board
voted to restore the authorization level to $1 billion.
Through December 31, 2005, the Company had the authority to
purchase $857 million of its Common Stock under the current
authorization.
During 2005, the Company repurchased approximately
16 million shares of its Common Stock for approximately
$902 million and, as of December 31, 2005, had
authority to repurchase an additional $857 million of its
Common Stock under the current authorization. Share repurchases
of $8 million related to 2004 transactions were cash
settled during 2005. Since December 2000, the Company has
repurchased approximately 77 million shares of its Common
Stock for $2.5 billion.
24
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
$23 million and $2 million, respectively. As of
December 31, 2005, Lost Creek had outstanding debt totaling
$37 million and Evangeline had outstanding debt totaling
$28 million. Lost Creek and Evangelines debts are
non-recourse to the Company, and as a result, the Company has no
legal responsibility or obligation for these debts. Management
believes that Lost Creek and Evangeline are financially stable
and therefore will be in a position to repay their outstanding
debts.
Capital Expenditures and Resources
Capital expenditures were as follow.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2005 vs. 2004 |
|
2005 vs. 2003 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
% |
|
|
|
% |
|
|
|
|
|
|
|
|
Increase |
|
Increase |
|
Increase |
|
Increase |
Year Ended December 31, |
|
2005 |
|
2004 |
|
2003 |
|
(Decrease) |
|
(Decrease) |
|
(Decrease) |
|
(Decrease) |
|
|
|
($ in millions) |
|
Oil and gas
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Development
|
|
$ |
1,819 |
|
|
$ |
1,273 |
|
|
$ |
1,056 |
|
|
$ |
546 |
|
|
|
43 |
% |
|
$ |
763 |
|
|
|
72 |
% |
|
Exploration
|
|
|
467 |
|
|
|
286 |
|
|
|
301 |
|
|
|
181 |
|
|
|
63 |
|
|
|
166 |
|
|
|
55 |
|
|
Acquisitions
|
|
|
328 |
|
|
|
85 |
|
|
|
228 |
|
|
|
243 |
|
|
|
286 |
|
|
|
100 |
|
|
|
44 |
|
|
|
|
Total oil and gas
|
|
|
2,614 |
|
|
|
1,644 |
|
|
|
1,585 |
|
|
|
970 |
|
|
|
59 |
|
|
|
1,029 |
|
|
|
65 |
|
|
Plants and pipelines
|
|
|
44 |
|
|
|
66 |
|
|
|
163 |
|
|
|
(22 |
) |
|
|
(33 |
) |
|
|
(119 |
) |
|
|
(73 |
) |
Administrative and other
|
|
|
29 |
|
|
|
37 |
|
|
|
40 |
|
|
|
(8 |
) |
|
|
(22 |
) |
|
|
(11 |
) |
|
|
(28 |
) |
|
|
|
Total capital
expenditures
|
|
$ |
2,687 |
|
|
$ |
1,747 |
|
|
$ |
1,788 |
|
|
$ |
940 |
|
|
|
54 |
% |
|
$ |
899 |
|
|
|
50 |
% |
|
The Companys consolidated capital expenditures were up
54 percent and 50 percent compared to 2004 and 2003,
respectively. Excluding acquisitions, the Companys capital
spending related to internal development and exploration was up
47 and 68 percent compared to 2004 and 2003, respectively.
Capital expenditures in 2006, excluding proved property
acquisitions, are expected to be approximately
$3.1 billion, up 33 percent over 2005, 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 2006
estimated spending is sufficient to add adequate reserves and
achieve the target of three to eight percent average annual
production growth. Capital expenditures in 2006 are expected to
be primarily for internal development and exploration of oil and
gas properties. Capital spending in 2006 related to internal
development and exploration is expected to be about
29 percent higher than 2005 and is expected to be funded
from internally generated cash flows.
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.
25
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, 2005, 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 $77 million decrease in the net
unrealized gain. The derivative instruments in place at
December 31, 2005 hedged approximately 10 percent and
11 percent of the Companys expected natural gas and
crude oil production volumes, respectively, through 2006.
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.
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 six percent
of the Companys accounts receivable balance at
December 31, 2005. 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 2005, 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
26
located in Canada, in Canadian dollars, which provides a natural
hedge against foreign currency risk. As of December 31,
2005, the Company had no foreign currency financial derivatives.
Dividends
On January 25, 2006, the Board declared a Common Stock
quarterly cash dividend of $0.10 per share, payable
April 10, 2006 to shareholders of record on March 9,
2006. During the third quarter of 2005, the Company increased
its quarterly cash dividend from $0.085 to $0.10 per share,
representing an 18 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
$141 million and $136 million, respectively, during
2005.
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.
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
2005, 2004, and 2003 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 68-72.
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 the costs of 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
$62 million. See the Supplementary Financial Information in
this report 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 as exploration cost 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
27
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 not have resulted in an
additional impairment charge for the year ended
December 31, 2005. See Note 16 of Notes to
Consolidated Financial Statements for a discussion of 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 and
additionally 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 DD&A
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 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 $30 million increase in
the Companys obligation and a $2 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. Under 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 2005, the Company used a professional valuation
services firm to assist in preparing its annual valuation of the
Canadian reporting unit. At December 31, 2005, 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
28
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, 2005 Compared With Year Ended
December 31, 2004
The Companys consolidated net income increased to
$2,710 million or $7.07 diluted earnings per common share
(per share) in 2005 primarily due to higher
commodity prices and higher production volumes. Net income in
2005 includes a gain of $240 million or $0.39 per
share related to the sale of 16,950,000 units of beneficial
interest in the Permian Basin Royalty Trust held by the Company.
Net income in 2005 and 2004 included charges, net of taxes, of
$34 million or $0.09 per share and $59 million or
$0.15 per share, respectively, related to the impairment of
oil and gas properties. Net income in 2005 and 2004 included
income tax benefits of $51 million or $0.13 per share
and $23 million or $0.06 per share, respectively,
related to the reduction of the Canadian federal income tax
rate. Net income in 2004 also included income tax benefits of
$45 million or $0.11 per share 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. in 2005 under the one-time provisions of the
American Jobs Creation Act of 2004.
Below is a discussion of prices, volumes and revenue variances.
Price and Volume Variances
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2005 vs. 2004 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Increase |
|
% |
|
Increase |
Year Ended December 31, |
|
2005 |
|
2004 |
|
2003 |
|
(Decrease) |
|
Increase |
|
(Decrease) |
|
(In Millions) | |
|
Price Variance
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas sales prices (per MCF)
|
|
$ |
7.22 |
|
|
$ |
5.49 |
|
|
$ |
4.83 |
|
|
$ |
1.73 |
|
|
|
32 |
% |
|
$ |
1,200 |
|
|
NGLs sales prices (per Bbl)
|
|
|
32.88 |
|
|
|
25.38 |
|
|
|
20.40 |
|
|
|
7.50 |
|
|
|
30 |
|
|
|
184 |
|
|
Crude oil sales prices (per Bbl)
|
|
$ |
50.77 |
|
|
$ |
36.25 |
|
|
$ |
27.22 |
|
|
$ |
14.52 |
|
|
|
40 |
% |
|
|
493 |
|
|
|
|
Total price variance
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
1,877 |
|
|
Volume Variance
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas sales volumes (MMCF per
day)
|
|
|
1,905 |
|
|
|
1,914 |
|
|
|
1,899 |
|
|
|
(9 |
) |
|
|
|
% |
|
$ |
(29 |
) |
|
NGLs sales volumes (MBbls per day)
|
|
|
66.7 |
|
|
|
65.3 |
|
|
|
64.8 |
|
|
|
1.4 |
|
|
|
2 |
|
|
|
11 |
|
|
Crude oil sales volumes (MBbls per
day)
|
|
|
93.0 |
|
|
|
85.2 |
|
|
|
46.5 |
|
|
|
7.8 |
|
|
|
9 |
% |
|
|
100 |
|
|
|
|
Total volume variance
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
82 |
|
|
29
Revenue Variances
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2005 vs. 2004 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
% |
Year Ended December 31, |
|
2005 |
|
2004 |
|
2003 |
|
Increase |
|
Increase |
|
|
|
($ In Millions) |
|
|
|
Natural gas
|
|
$ |
5,018 |
|
|
$ |
3,847 |
|
|
$ |
3,331 |
|
|
$ |
1,171 |
|
|
|
30 |
% |
NGLs
|
|
|
801 |
|
|
|
606 |
|
|
|
482 |
|
|
|
195 |
|
|
|
32 |
|
Crude oil
|
|
|
1,724 |
|
|
|
1,131 |
|
|
|
462 |
|
|
|
593 |
|
|
|
52 |
|
Processing and other
|
|
|
44 |
|
|
|
34 |
|
|
|
36 |
|
|
|
10 |
|
|
|
29 |
|
|
|
Total revenues
|
|
$ |
7,587 |
|
|
$ |
5,618 |
|
|
$ |
4,311 |
|
|
$ |
1,969 |
|
|
|
35 |
% |
|
Revenues
The Companys consolidated revenues increased
$1,969 million in 2005 compared to 2004. Higher revenues
were primarily due to higher commodity prices and higher crude
oil and NGLs production volumes, resulting in increased revenues
of $1,877 million and $111 million, respectively.
Increased revenues related to higher commodity prices and higher
oil and NGLs sales volumes were partially offset by lower
natural gas sales volumes, resulting in reduced revenues of
$29 million. 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 $1,877 million to the increase
in revenues in 2005. Average natural gas prices, including a
$0.23 realized loss per MCF related to hedging activities,
increased $1.73 per MCF during 2005, resulting in increased
revenues of $1,200 million. Average crude oil prices,
including an $0.80 realized loss per barrel related to hedging
activities, increased $14.52 per barrel in 2005, resulting
in increased revenues of $493 million. Average NGLs prices
increased $7.50 per barrel in 2005, resulting in higher
revenues of $184 million. As discussed on page 12,
commodity prices are affected by many factors that are outside
of the Companys control. Therefore, commodity prices
received by the Company during 2005 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 2005 resulted in increased revenues of
$82 million. Average crude oil sales volumes increased
7.8 MBbls per day in 2005, resulting in increased revenues
of $100 million. The increase in crude oil sales volumes in
2005 was primarily due to higher production from the Cedar Creek
Anticline which increased 9.4 MBbls per day and the Bakken
Shale which increased 4.2 MBbls per day partially offset by
decreased production of 3.9 MBbls per day in China.
Average NGLs sales volumes increased 1.4 MBbls per day in
2005, resulting in higher revenues of $11 million. Average
NGLs sales volumes increased primarily due to higher production
of 0.6 MBbls per day from Canada and 0.5 MBbls per day
from the Waddell Ranch Field.
Average natural gas sales volumes decreased 9 MMCF per day
in 2005, resulting in decreased revenues of $29 million.
Average natural gas sales volumes decreased primarily due to
lower production of 35 MMCF per day from the San Juan
Basin, 19 MMCF per day from Millom and Dalton in the East
Irish Sea, 15 MMCF per day from Canada and 12 MMCF per
day from south Louisiana. These decreases were partially offset
by higher production volumes in the Bossier trend of
69 MMCF per day.
The Company has a goal to achieve between three and eight
percent average annual production growth; therefore, future
production volumes are expected to increase over the current
period. See discussion under Outlook on page 19
for guidance on production volumes. As mentioned above,
depressed prices over an extended period of time or other
unforeseen events could occur that would result in the Company
being unable to sustain a capital program that allows it to meet
its production growth goals. However, the Company cannot predict
whether such events will occur.
30
Below is a discussion of total costs and other incomenet.
Total Costs and Other IncomeNet
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2005 vs. 2004 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
% |
|
|
|
|
|
|
|
|
Increase |
|
Increase |
Year Ended December 31, |
|
2005 |
|
2004 |
|
2003 |
|
(Decrease) |
|
(Decrease) |
|
|
|
($ In Millions) |
|
|
|
Costs and other
incomenet
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Taxes other than income taxes
|
|
$ |
355 |
|
|
$ |
260 |
|
|
$ |
187 |
|
|
$ |
95 |
|
|
|
37 |
% |
|
Transportation expense
|
|
|
496 |
|
|
|
453 |
|
|
|
408 |
|
|
|
43 |
|
|
|
9 |
|
|
Operating costs
|
|
|
697 |
|
|
|
587 |
|
|
|
475 |
|
|
|
110 |
|
|
|
19 |
|
|
Depreciation, depletion and
amortization
|
|
|
1,313 |
|
|
|
1,137 |
|
|
|
927 |
|
|
|
176 |
|
|
|
15 |
|
|
Exploration costs
|
|
|
293 |
|
|
|
258 |
|
|
|
252 |
|
|
|
35 |
|
|
|
14 |
|
|
Impairment of oil and gas properties
|
|
|
50 |
|
|
|
90 |
|
|
|
63 |
|
|
|
(40 |
) |
|
|
(44 |
) |
|
Administrative
|
|
|
256 |
|
|
|
215 |
|
|
|
164 |
|
|
|
41 |
|
|
|
19 |
|
|
Interest expense
|
|
|
281 |
|
|
|
282 |
|
|
|
260 |
|
|
|
(1 |
) |
|
|
|
|
|
(Gain)/loss on disposal of assets
|
|
|
(240 |
) |
|
|
13 |
|
|
|
(8 |
) |
|
|
253 |
|
|
|
N/A |
|
|
Other expensenet
|
|
|
38 |
|
|
|
19 |
|
|
|
13 |
|
|
|
19 |
|
|
|
100 |
|
|
|
|
Total costs and other
incomenet
|
|
$ |
3,539 |
|
|
$ |
3,314 |
|
|
$ |
2,741 |
|
|
$ |
225 |
|
|
|
7 |
% |
|
Total costs and other incomenet increased
$225 million in 2005. 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 2005
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, the
Company cannot predict what impact the Canadian exchange rate
will have on costs and expenses in the future. See discussion
under Outlook on page 21 for guidance on costs
and expenses for the first quarter of 2006.
DD&A expense increased $176 million primarily due to
asset additions with higher
unit-of-production
rates, and higher foreign currency exchange rates. Operating
costs increased $110 million in 2005 compared to 2004. This
increase is primarily due to higher divisional office expenses
related to various compensation programs and 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 fuel and electricity expenses, higher repair and
maintenance expenses, higher workover activity and higher
foreign currency exchange rates.
Taxes other than income taxes increased $95 million
primarily due to higher production taxes resulting from higher
crude oil and natural gas revenues. Production taxes include
severance taxes which are directly correlated to natural gas and
crude oil revenues. Transportation expense increased
$43 million primarily due to the U.S. and International
operations. Administrative expense increased $41 million
primarily due to various compensation programs primarily related
to the increase in the Companys stock price as well as
other performance measures, and merger costs related to the
proposed merger between BR and ConocoPhillips.
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 2005 and 2004, the Company
recorded non-cash charges of $50 million and
$90 million, respectively, related to the impairment of oil
and gas properties. The impairment of oil and gas properties in
2005 was related to a downward reserve adjustment primarily
related to the Companys onshore China properties. The
impairment in 2004 was related to undeveloped properties in
Canada.
Exploration costs increased $35 million due to higher
geological and geophysical (G&G) and other
expenses of $25 million, higher amortization of undeveloped
lease costs of $10 million and higher exploratory dry hole
costs of $8 million partially offset by lower deepwater rig
impairment of $8 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 2005, 2004 and 2003,
the Company experienced a success rate in the range of
approximately 50 to 71 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,
2005, $25 million of deferred exploration drilling 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 2005 and
2004, deferred exploration drilling costs of $16 million
and $14 million, respectively, were reclassified from oil
and gas properties to exploration expense.
31
In 2005, gain on disposal of assets increased $253 million
primarily due to a $240 million pretax gain related to the
sale of 16,950,000 units of beneficial interest in the
Permian Basin Royalty Trust held by the Company. Other
expense net increased $19 million
primarily due to higher legal cost accruals of $42 million
and higher foreign currency transaction losses of
$36 million, partially offset by higher interest income of
$41 million resulting from higher cash balances, lower
write-offs of inventory of $7 million and lower interest
expense related to tax and other matters of $6 million.
Income Tax Expense
Income tax expense increased $561 million in 2005 compared
to 2004, primarily due to an increase in pretax income of
$1,744 million. During 2005, the Company recorded higher
income tax benefits of $52 million related to return as
filed adjustments and higher income tax benefits of
$8 million related to interest deductions allowed in both
the U.S. and Canada on transactions associated with cross-border
financing. The increase in the tax benefit related to
cross-border financing is the result of changes in the exchange
rate. 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. This benefit is not expected to fluctuate in
the future for reasons other than changes in exchange rate and
debt levels. The Company recorded a higher income tax expense of
$35 million related to taxes on foreign income in excess of
U.S. rates. In 2005, the Company also recorded lower income
tax benefits of $17 million related to the Canadian federal
statutory income tax rate reductions. In 2004, the Company
recorded $26 million of U.S. income tax expense
related to its planned repatriation in 2005 of $500 million
of eligible foreign earnings under the one-time provisions of
the American Job Creation Act of 2004.
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 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, 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 statutory 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.
Below is a discussion of prices, volumes and revenue variances.
Price and Volume Variances
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2004 vs. 2003 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
% |
|
|
Year Ended December 31, |
|
2004 |
|
2003 |
|
2002 |
|
Increase |
|
Increase |
|
Increase |
|
|
|
(In Millions) |
|
Price Variance
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas sales prices (per MCF)
|
|
$ |
5.49 |
|
|
$ |
4.83 |
|
|
$ |
3.20 |
|
|
$ |
0.66 |
|
|
|
14 |
% |
|
$ |
462 |
|
|
NGLs sales prices (per Bbl)
|
|
|
25.38 |
|
|
|
20.40 |
|
|
|
14.46 |
|
|
|
4.98 |
|
|
|
24 |
|
|
|
119 |
|
|
Crude oil sales prices (per Bbl)
|
|
$ |
36.25 |
|
|
$ |
27.22 |
|
|
$ |
24.11 |
|
|
$ |
9.03 |
|
|
|
33 |
% |
|
|
282 |
|
|
|
|
Total price variance
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
863 |
|
|
Volume Variance
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas sales volumes (MMCF per
day)
|
|
|
1,914 |
|
|
|
1,899 |
|
|
|
1,916 |
|
|
|
15 |
|
|
|
1 |
% |
|
$ |
35 |
|
|
NGLs sales volumes (MBbls per day)
|
|
|
65.3 |
|
|
|
64.8 |
|
|
|
60.1 |
|
|
|
0.5 |
|
|
|
1 |
|
|
|
5 |
|
|
Crude oil sales volumes (MBbls per
day)
|
|
|
85.2 |
|
|
|
46.5 |
|
|
|
49.1 |
|
|
|
38.7 |
|
|
|
83 |
% |
|
|
387 |
|
|
|
|
Total volume variance
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
427 |
|
|
32
Revenue Variances
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2004 vs. 2003 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
% |
|
|
|
|
|
|
|
|
Increase |
|
Increase |
Year Ended December 31, |
|
2004 |
|
2003 |
|
2002 |
|
(Decrease) |
|
(Decrease) |
|
|
|
($ In Millions) |
|
|
|
Natural gas
|
|
$ |
3,847 |
|
|
$ |
3,331 |
|
|
$ |
2,209 |
|
|
$ |
516 |
|
|
|
15 |
% |
NGLs
|
|
|
606 |
|
|
|
482 |
|
|
|
317 |
|
|
|
124 |
|
|
|
26 |
|
Crude oil
|
|
|
1,131 |
|
|
|
462 |
|
|
|
432 |
|
|
|
669 |
|
|
|
145 |
|
Processing and other
|
|
|
34 |
|
|
|
36 |
|
|
|
10 |
|
|
|
(2 |
) |
|
|
(6 |
) |
|
|
Total revenues
|
|
$ |
5,618 |
|
|
$ |
4,311 |
|
|
$ |
2,968 |
|
|
$ |
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 prices
increased $4.98 per barrel in 2004, resulting in higher
revenues of $119 million. See page 22 for a discussion
of commodity prices.
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 $5 million over 2003.
33
Below is a discussion of total costs and other incomenet.
Total Costs and Other IncomeNet
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2004 vs. 2003 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
% |
|
|
|
|
|
|
|
|
Increase |
|
Increase |
Year Ended December 31, |
|
2004 |
|
2003 |
|
2002 |
|
(Decrease) |
|
(Decrease) |
|
|
|
($ In Millions) |
|
|
|
Costs and other
incomenet
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Taxes other than income taxes
|
|
$ |
260 |
|
|
$ |
187 |
|
|
$ |
123 |
|
|
$ |
73 |
|
|
|
39 |
% |
|
Transportation expense
|
|
|
453 |
|
|
|
408 |
|
|
|
354 |
|
|
|
45 |
|
|
|
11 |
|
|
Operating costs
|
|
|
587 |
|
|
|
475 |
|
|
|
467 |
|
|
|
112 |
|
|
|
24 |
|
|
Depreciation, depletion and
amortization
|
|
|
1,137 |
|
|
|
927 |
|
|
|
833 |
|
|
|
210 |
|
|
|
23 |
|
|
Exploration costs
|
|
|
258 |
|
|
|
252 |
|
|
|
286 |
|
|
|
6 |
|
|
|
2 |
|
|
Impairment of oil and gas properties
|
|
|
90 |
|
|
|
63 |
|
|
|
|
|
|
|
27 |
|
|
|
43 |
|
|
Administrative
|
|
|
215 |
|
|
|
164 |
|
|
|
161 |
|
|
|
51 |
|
|
|
31 |
|
|
Interest expense
|
|
|
282 |
|
|
|
260 |
|
|
|
274 |
|
|
|
22 |
|
|
|
8 |
|
|
(Gain)/loss on disposal of assets
|
|
|
13 |
|
|
|
(8 |
) |
|
|
(68 |
) |
|
|
(21 |
) |
|
|
(263 |
) |
|
Other expense (income)net
|
|
|
19 |
|
|
|
13 |
|
|
|
(31 |
) |
|
|
6 |
|
|
|
46 |
|
|
|
|
Total costs and other
incomenet
|
|
$ |
3,314 |
|
|
$ |
2,741 |
|
|
$ |
2,399 |
|
|
$ |
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 Canadian
exchange rate will have on costs and expenses in the future.
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 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.
34
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 in 2005 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 statutory income tax rate
resulted in lower income tax benefits of $158 million in
2004 compared to 2003. The reduction of the Alberta provincial
corporate income tax rate resulted in higher income tax benefits
of $12 million in 2004 compared to 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.
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 June 10, 2005, in the case of Amoco v.
Watson, the United States Court of Appeals for the District of
Columbia issued an opinion in favor of the MMS regarding a
producers obligation to place coal seam gas in
marketable condition at no cost to the government
when calculating federal royalty payments. Since some of the
intervenors claims relate to the Companys coal seam
production in the San Juan Basin and the deductions
utilized by the Company in calculating royalty payments on such
production, the Company analyzed the potential impact of the
Amoco ruling and determined that, if upheld, the decision will
have a negative impact on the Companys defenses in these
proceedings.
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 to provide for this potential liability based upon
managements evaluation of this matter.
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 court certified the plaintiff classes of
royalty and overriding royalty interest owners, and trial by
jury commenced on October 10, 2005, during which plaintiffs
sought monetary damages of up to $42 million in principal,
plus $311 million in interest, and unspecified punitive
damages and
35
attorneys fees. The Company presented substantial defenses
to these claims. In a separate action, the Company and
El Paso Natural Gas Company asserted contractual claims for
indemnity against each other. On November 9, 2005, the
parties counsel entered into a preliminary agreement to
settle this lawsuit for $66 million, plus interest on this
amount commencing January 20, 2006, as provided in the
settlement agreement. On January 20, 2006, the Court
preliminarily approved the settlement and scheduled a fairness
hearing to determine the fairness to class members of the
proposed settlement, which is scheduled to commence in May 2006.
The Company and El Paso Natural Gas Company have reached a
preliminary agreement to settle the contractual indemnity claims
against each other. The settlement of the indemnity claims is
subject to final court approval of the class action settlement.
Upon final court approval of the class action settlement, the
Companys contribution to the settlement will be
approximately $36 million, plus interest from
January 20, 2006, as provided in the settlement agreement.
The Company has established a reserve to provide for this
potential liability based upon managements evaluation of
this matter.
The Company and its directors have been named defendants in a
lawsuit styled Jeffrey Halpern, Derivatively on Behalf of
Burlington Resources Inc., Plaintiff, vs. Bobby S. Shackouls,
et al., and Burlington Resources Inc. a Delaware
Corporation, Nominal Defendant, Cause No. 2005-79250,
filed on December 15, 2005, in the 215th Judicial
District Court of Harris County, Texas (Halpern
case) and also named as defendants in a lawsuit styled
Charles Conrardy, On Behalf of Himself and All Others
Similarly Situated, Plaintiff, vs. Burlington Resources Inc.,
et al., Cause No. 2005-79267, filed on
December 16, 2005, in the 165th Judicial District
Court of Harris County, Texas (Conrardy case). Both
lawsuits allege that Companys board of directors breached
its fiduciary duties in approving the proposed merger announced
on December 12, 2005, between the Company and
ConocoPhillips. The Halpern case is a stockholder derivative
action purportedly filed on behalf of the Company against the
Companys board of directors, and contains claims for abuse
of control, breach of the duty of candor, gross mismanagement,
waste and unjust enrichment, and breach of fiduciary duty. The
Conrardy case is a purported stockholder class action lawsuit
against the Company and the Companys board of directors,
and contains a claim for breach of fiduciary duty. Both
petitions allege, among other things, that the Companys
board of directors engaged in self dealing by approving a
proposed merger that allegedly advances the Companys board
of directors personal interests at the expense of the
Companys stockholders, thus causing the Companys
stockholders to receive an unfair price for their shares of the
Companys common stock. Both petitions seek, among other
things, an injunction preventing the completion of the merger,
rescission if the merger is consummated, attorneys fees
and expenses associated with the lawsuit, and any other further
equitable relief as the courts may deem just and proper. The
Company believes these actions are without merit and intends to
defend them vigorously. The Company has not established a
reserve for these matters.
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 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 and could prove to be greater than
managements current assessments, 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.
At December 31, 2005, the Companys Consolidated
Balance Sheet included reserves for legal proceedings of
$137 million and environmental matters of $20 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, the Company believes 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.
36
Other Matters
Recent Accounting Pronouncements
In May 2005, the FASB issued SFAS No. 154,
Accounting Changes and Error Corrections, a replacement of
APB Opinion No. 20 and FASB Statement No. 3.
SFAS No. 154 requires retrospective application to
prior period financial statements for changes in accounting
principle, unless it is impracticable to determine either the
period-specific effects or the cumulative effect of the change.
SFAS No. 154 also requires that retrospective
application of a change in accounting principle be limited to
the direct effects of the change. Indirect effects of a change
in accounting principle should be recognized in the period of
the accounting change. The Company adopted
SFAS No. 154 on January 1, 2006. The impact of
SFAS No. 154 will depend on the nature and extent of
any voluntary accounting changes and correction of errors after
the effective date, but management does not currently expect
SFAS No. 154 to have a material impact on the
Companys consolidated financial position, results of
operations or cash flows.
In March 2005, the FASB issued Interpretation No. 47,
Accounting for Conditional Asset Retirement
Obligationsan interpretation of FASB Statement
No. 143 (Interpretation). This
Interpretation clarifies that the term conditional asset
retirement obligation as used in FASB Statement
No. 143, Accounting for Asset Retirement
Obligations, refers to a legal obligation to perform an
asset retirement activity in which the timing and
(or) method of settlement are conditional on a future event
that may or may not be within the control of the entity. The
obligation to perform the asset retirement activity is
unconditional even though uncertainty exists about the timing
and (or) method of settlement. Thus, the timing and
(or) method of settlement may be conditional on a future
event. Accordingly, an entity is required to recognize a
liability for the fair value of a conditional asset retirement
obligation if the fair value of the liability can be reasonably
estimated. This Interpretation also clarifies when an entity
would have sufficient information to reasonably estimate the
fair value of an asset retirement obligation. This
Interpretation is effective for the Companys year ended
December 31, 2005. The adoption of this Interpretation did
not 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
December 15, 2005. The Company adopted this statement on
January 1, 2006, 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 will
result in the Company recording an expense of approximately
$10 million in 2006.
In September 2005, the FASB issued EITF Issue No. 04-13,
Accounting for Purchases and Sales of Inventory with the Same
Counterparty (Issue). This Issue addresses the
accounting for purchase and sales arrangements with the same
party and is effective for new arrangements entered into, and
modifications or renewals of existing arrangements, beginning in
the first interim or annual reporting period beginning after
March 15, 2006. The adoption of this Issue is not expected
to have a material impact on the Companys consolidated
financial position or results of operations.
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. See Risk Factors on pages 12-14 for
some of the important factors that could cause actual results to
differ from any such projections.
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, 2005. 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, 2005, 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, 2005, as stated in
their report which appears on page 39.
|
|
|
Bobby S.
Shackouls
Chairman of the Board, President and
Chief Executive Officer
|
|
Joseph P.
McCoy
Senior 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 integrated audits of Burlington Resources
Inc.s 2005 and 2004 consolidated financial statements and
of its internal control over financial reporting as of
December 31, 2005, and an audit of its 2003 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 consolidated financial statements listed in
the index appearing under Item Fifteen present fairly, in all
material respects, the financial position of Burlington
Resources Inc. and its subsidiaries at December 31, 2005
and 2004, and the results of their operations and their cash
flows for each of the three years in the period ended
December 31, 2005 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 Seven, that the Company
maintained effective internal control over financial reporting
as of December 31, 2005 based on criteria established in
Internal ControlIntegrated 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, 2005,
based on criteria established in Internal
ControlIntegrated 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, 2006
39
ITEM EIGHT
FINANCIAL STATEMENTS AND SUPPLEMENTARY FINANCIAL INFORMATION
BURLINGTON RESOURCES INC.
CONSOLIDATED STATEMENT OF INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
2005 |
|
2004 |
|
2003 |
|
(In Millions, Except per Share Amounts) | |
|
REVENUES
|
|
$ |
7,587 |
|
|
$ |
5,618 |
|
|
$ |
4,311 |
|
|
COSTS AND OTHER
INCOMENET
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Taxes Other than Income Taxes
|
|
|
355 |
|
|
|
260 |
|
|
|
187 |
|
|
Transportation Expense
|
|
|
496 |
|
|
|
453 |
|
|
|
408 |
|
|
Operating Costs
|
|
|
697 |
|
|
|
587 |
|
|
|
475 |
|
|
Depreciation, Depletion and
Amortization
|
|
|
1,313 |
|
|
|
1,137 |
|
|
|
927 |
|
|
Exploration Costs
|
|
|
293 |
|
|
|
258 |
|
|
|
252 |
|
|
Impairment of Oil and Gas Properties
|
|
|
50 |
|
|
|
90 |
|
|
|
63 |
|
|
Administrative
|
|
|
256 |
|
|
|
215 |
|
|
|
164 |
|
|
Interest Expense
|
|
|
281 |
|
|
|
282 |
|
|
|
260 |
|
|
(Gain)/Loss on Disposal of Assets
|
|
|
(240 |
) |
|
|
13 |
|
|
|
(8 |
) |
|
Other ExpenseNet
|
|
|
38 |
|
|
|
19 |
|
|
|
13 |
|
|
Total Costs and Other
IncomeNet
|
|
|
3,539 |
|
|
|
3,314 |
|
|
|
2,741 |
|
|
Income Before Income Taxes and
Cumulative Effect of Change in Accounting Principle
|
|
|
4,048 |
|
|
|
2,304 |
|
|
|
1,570 |
|
Income Tax Expense
|
|
|
1,338 |
|
|
|
777 |
|
|
|
310 |
|
|
Income Before Cumulative Effect of
Change in Accounting Principle
|
|
|
2,710 |
|
|
|
1,527 |
|
|
|
1,260 |
|
Cumulative Effect of Change in
Accounting PrincipleNet
|
|
|
|
|
|
|
|
|
|
|
(59 |
) |
|
Net Income
|
|
$ |
2,710 |
|
|
$ |
1,527 |
|
|
$ |
1,201 |
|
|
EARNINGS PER COMMON
SHARE
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Before Cumulative Effect of Change
in Accounting Principle
|
|
$ |
7.13 |
|
|
$ |
3.90 |
|
|
$ |
3.17 |
|
|
|
Cumulative Effect of Change in
Accounting PrincipleNet
|
|
|
|
|
|
|
|
|
|
|
(0.15 |
) |
|
|
|
Net Income
|
|
$ |
7.13 |
|
|
$ |
3.90 |
|
|
$ |
3.02 |
|
|
|
Diluted
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Before Cumulative Effect of Change
in Accounting Principle
|
|
$ |
7.07 |
|
|
$ |
3.86 |
|
|
$ |
3.15 |
|
|
|
Cumulative Effect of Change in
Accounting PrincipleNet
|
|
|
|
|
|
|
|
|
|
|
(0.15 |
) |
|
|
|
Net Income
|
|
$ |
7.07 |
|
|
$ |
3.86 |
|
|
$ |
3.00 |
|
|
See accompanying Notes to Consolidated Financial Statements.
40
BURLINGTON RESOURCES INC.
CONSOLIDATED BALANCE SHEET
|
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
2005 |
|
2004 |
|
(In Millions, Except Share Data) | |
|
ASSETS |
|
|
Current Assets
|
|
|
|
|
|
|
|
|
|
|
Cash and Cash Equivalents
|
|
$ |
3,528 |
|
|
$ |
2,179 |
|
|
|
Accounts Receivable
|
|
|
1,444 |
|
|
|
947 |
|
|
|
Inventories
|
|
|
140 |
|
|
|
124 |
|
|
|
Other Current Assets
|
|
|
258 |
|
|
|
158 |
|
|
|
|
|
5,370 |
|
|
|
3,408 |
|
|
|
Oil and Gas Properties (Successful
Efforts Method)
|
|
|
20,669 |
|
|
|
17,943 |
|
|
Other Properties
|
|
|
1,669 |
|
|
|
1,544 |
|
|
|
|
|
22,338 |
|
|
|
19,487 |
|
|
Less: Accumulated Depreciation,
Depletion and Amortization
|
|
|
9,900 |
|
|
|
8,454 |
|
|
|
|
PropertiesNet
|
|
|
12,438 |
|
|
|
11,033 |
|
|
|
Goodwill
|
|
|
1,089 |
|
|
|
1,054 |
|
|
|
Other Assets
|
|
|
328 |
|
|
|
249 |
|
|
|
|
|
Total Assets
|
|
$ |
19,225 |
|
|
$ |
15,744 |
|
|
LIABILITIES |
|
|
Current Liabilities
|
|
|
|
|
|
|
|
|
|
|
Accounts Payable
|
|
$ |
1,730 |
|
|
$ |
1,125 |
|
|
|
Taxes Payable
|
|
|
271 |
|
|
|
264 |
|
|
|
Accrued Interest
|
|
|
61 |
|
|
|
61 |
|
|
|
Dividends Payable
|
|
|
38 |
|
|
|
33 |
|
|
|
Other Current Liabilities
|
|
|
116 |
|
|
|
59 |
|
|
|
|
|
2,216 |
|
|
|
1,542 |
|
|
|
Long-term Debt
|
|
|
3,893 |
|
|
|
3,887 |
|
|
|
Deferred Income Taxes
|
|
|
3,038 |
|
|
|
2,396 |
|
|
|
Other Liabilities and Deferred
Credits
|
|
|
1,143 |
|
|
|
908 |
|
|
|
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 Shares for 2005 and 2004)
|
|
|
5 |
|
|
|
5 |
|
|
Paid-in Capital
|
|
|
3,998 |
|
|
|
3,973 |
|
|
Retained Earnings
|
|
|
6,732 |
|
|
|
4,163 |
|
|
Deferred
CompensationRestricted Stock
|
|
|
(16 |
) |
|
|
(14 |
) |
|
Accumulated Other Comprehensive
Income
|
|
|
1,244 |
|
|
|
1,092 |
|
|
Cost of Treasury Stock (107,074,368
and 94,435,401 Shares for 2005 and 2004, respectively)
|
|
|
(3,028 |
) |
|
|
(2,208 |
) |
|
|
Stockholders Equity
|
|
|
8,935 |
|
|
|
7,011 |
|
|
|
|
|
Total Liabilities and
Stockholders Equity
|
|
$ |
19,225 |
|
|
$ |
15,744 |
|
|
See accompanying Notes to Consolidated Financial Statements.
41
BURLINGTON RESOURCES INC.
CONSOLIDATED STATEMENT OF CASH FLOWS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
2005 |
|
2004 |
|
2003 |
|
|
|
(In Millions) |
|
CASH FLOWS FROM OPERATING
ACTIVITIES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income
|
|
$ |
2,710 |
|
|
$ |
1,527 |
|
|
$ |
1,201 |
|
|
Adjustments to Reconcile Net Income
to Net Cash Provided by Operating Activities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation, Depletion and
Amortization
|
|
|
1,313 |
|
|
|
1,137 |
|
|
|
927 |
|
|
|
Deferred Income Taxes
|
|
|
503 |
|
|
|
371 |
|
|
|
150 |
|
|
|
Exploration Costs
|
|
|
293 |
|
|
|
258 |
|
|
|
252 |
|
|
|
Impairment of Oil and Gas Properties
|
|
|
50 |
|
|
|
90 |
|
|
|
63 |
|
|
|
(Gain)/Loss on Disposal of Assets
|
|
|
(240 |
) |
|
|
13 |
|
|
|
(8 |
) |
|
|
Changes in Derivative Fair Values
|
|
|
(1 |
) |
|
|
(5 |
) |
|
|
(5 |
) |
|
|
Cumulative Effect of Change in
Accounting PrincipleNet
|
|
|
|
|
|
|
|
|
|
|
59 |
|
|
Working Capital Changes
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts Receivable
|
|
|
(481 |
) |
|
|
(365 |
) |
|
|
(28 |
) |
|
|
Inventories
|
|
|
(29 |
) |
|
|
(40 |
) |
|
|
(26 |
) |
|
|
Other Current Assets
|
|
|
(24 |
) |
|
|
(25 |
) |
|
|
(15 |
) |
|
|
Accounts Payable
|
|
|
384 |
|
|
|
278 |
|
|
|
(4 |
) |
|
|
Taxes Payable
|
|
|
77 |
|
|
|
188 |
|
|
|
(9 |
) |
|
|
Accrued Interest
|
|
|
|
|
|
|
|
|
|
|
(1 |
) |
|
|
Other Current Liabilities
|
|
|
(10 |
) |
|
|
18 |
|
|
|
|
|
|
Changes in Other Assets and
Liabilities
|
|
|
(9 |
) |
|
|
(9 |
) |
|
|
(17 |
) |
|
|
|
|
Net Cash Provided by Operating
Activities
|
|
|
4,536 |
|
|
|
3,436 |
|
|
|
2,539 |
|
|
CASH FLOWS FROM INVESTING
ACTIVITIES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Additions to Properties
|
|
|
(2,469 |
) |
|
|
(1,582 |
) |
|
|
(1,899 |
) |
|
Proceeds from Sales and Other
|
|
|
183 |
|
|
|
(25 |
) |
|
|
4 |
|
|
|
|
|
Net Cash Used in Investing
Activities
|
|
|
(2,286 |
) |
|
|
(1,607 |
) |
|
|
(1,895 |
) |
|
CASH FLOWS FROM FINANCING
ACTIVITIES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proceeds from Long-term Debt
|
|
|
|
|
|
|
41 |
|
|
|
|
|
|
Reduction in Long-term Debt
|
|
|
(2 |
) |
|
|
(41 |
) |
|
|
(75 |
) |
|
Dividends Paid
|
|
|
(136 |
) |
|
|
(122 |
) |
|
|
(85 |
) |
|
Common Stock Purchases
|
|
|
(911 |
) |
|
|
(518 |
) |
|
|
(356 |
) |
|
Common Stock Issuances
|
|
|
64 |
|
|
|
153 |
|
|
|
128 |
|
|
Other
|
|
|
|
|
|
|
(1 |
) |
|
|
(3 |
) |
|
|
|
|
Net Cash Used in Financing
Activities
|
|
|
(985 |
) |
|
|
(488 |
) |
|
|
(391 |
) |
|
Effect of Exchange Rate Changes on
Cash and Cash Equivalents
|
|
|
84 |
|
|
|
81 |
|
|
|
61 |
|
|
Increase in Cash and Cash
Equivalents
|
|
|
1,349 |
|
|
|
1,422 |
|
|
|
314 |
|
Cash and Cash Equivalents
|
|
|
|
|
|
|
|
|
|
|
|
|
Beginning of Year
|
|
|
2,179 |
|
|
|
757 |
|
|
|
443 |
|
|
|
End of Year
|
|
$ |
3,528 |
|
|
$ |
2,179 |
|
|
$ |
757 |
|
|
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, 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 |
|
|
Comprehensive Income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income
|
|
|
|
|
|
|
|
|
|
|
2,710 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,710 |
|
|
Foreign Currency Translation
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
232 |
|
|
|
|
|
|
|
232 |
|
|
Hedging Activities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(79 |
) |
|
|
|
|
|
|
(79 |
) |
|
Minimum Pension Liability
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1 |
) |
|
|
|
|
|
|
(1 |
) |
|
|
|
Comprehensive Income
|
|
|
|
|
|
|
|
|
|
|
2,710 |
|
|
|
|
|
|
|
152 |
|
|
|
|
|
|
|
2,862 |
|
|
Cash Dividends Declared
($0.37 per Share)
|
|
|
|
|
|
|
|
|
|
|
(141 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(141 |
) |
Common Stock Purchases
(15,734,600 Shares)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(902 |
) |
|
|
(902 |
) |
Stock Option Activity
|
|
|
|
|
|
|
25 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
66 |
|
|
|
91 |
|
Issuance of Restricted Stock
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(16 |
) |
|
|
|
|
|
|
16 |
|
|
|
|
|
Amortization of Restricted Stock
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
14 |
|
|
|
|
|
|
|
|
|
|
|
14 |
|
|
December 31, 2005
|
|
|
$5 |
|
|
|
$3,998 |
|
|
|
$6,732 |
|
|
$ |
(16 |
) |
|
$ |
1,244 |
|
|
|
$(3,028 |
) |
|
|
$8,935 |
|
|
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, the Netherlands, North 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., Burlington Resources Canada (Hunter) Ltd. (formerly
known as Canadian Hunter Exploration Ltd.) (Hunter),
and their affiliated companies (collectively, the
Company).
Pending Merger
On December 12, 2005, BR and ConocoPhillips entered into a
definitive agreement under which ConocoPhillips will acquire BR.
Upon completion of the merger, the Company will be merged into a
wholly owned subsidiary of ConocoPhillips and its separate
corporate existence will cease. Under the terms of the
agreement, BR shareholders will receive $46.50 in cash and
0.7214 shares of ConocoPhillips common stock for each BR
share they own. The transaction is subject to BR shareholder and
regulatory approval and other customary terms and conditions.
All options to purchase BR common stock granted under BRs
equity compensation plans that are outstanding at
December 31, 2005 will vest and become fully exercisable
upon the completion of the merger and will be converted into
options to purchase ConocoPhillips common stock. In
addition, the restrictions on all shares of restricted BR common
stock granted under BRs equity compensation plans that are
outstanding at December 31, 2005 will lapse upon completion
of the merger, and the shares will be converted into rights to
receive the per share merger consideration.
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.
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, |
|
2005 |
|
2004 |
|
|
|
(In Millions) |
|
Materials and supplies
|
|
$ |
113 |
|
|
$ |
99 |
|
Product inventory
|
|
|
27 |
|
|
|
25 |
|
|
|
Inventories
|
|
$ |
140 |
|
|
$ |
124 |
|
|
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
44
BURLINGTON RESOURCES INC.
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
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 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 do not meet the
strict definition of proved reserves, the related costs are 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 drilling 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. See Note 5 of
Notes to Consolidated Financial Statements.
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 either the straight-line
method based on expected lives of the individual assets or group
of assets or the
unit-of-production
method over the remaining life of related proved reserves.
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.
45
BURLINGTON RESOURCES INC.
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
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 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 (overproduction) 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, 2005 and 2004,
the Company had imbalance receivables of $64 million and
$58 million, respectively and imbalance payables of
$64 million and $69 million, respectively. The current
portion of the imbalance receivables and payables is included in
Accounts Receivable and Accounts Payable, respectively, on the
Companys Consolidated Balance Sheet. The long-term portion
of imbalance receivables and payables is included in Other
Assets and Other Liabilities and Deferred Credits, respectively.
At December 31, 2005 and 2004, the long-term portion of
imbalance receivables and payables was $52 million and
$53 million, and $47 million and $57 million,
respectively.
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, 2005 and 2004, the balances in
Accumulated Other Comprehensive Income related to foreign
currency translation were gains of $1,304 million and
$1,072 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, 2005, 2004 and 2003 are exchange losses of
$31 million, exchange gains of $5 million and exchange
losses of $7 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 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
46
BURLINGTON RESOURCES INC.
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
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 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, 2005, 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 2005, 2004 and 2003 were $8.39, $5.50 and $5.43,
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 2005, 2004 and 2003: stock price
volatility of 22 percent, 26 percent and
32 percent, respectively; risk free rate of return percent
of 3.4 percent, 2.1 percent and 2.4 percent,
respectively; dividend yields of 0.61 percent,
0.89 percent and 1.18 percent, respectively; and an
expected term of 3 years, 3 years and 4 years,
respectively.
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, |
|
2005 |
|
2004 |
|
2003 |
|
(In Millions, Except per Share Amounts) | |
|
Net income as reported
|
|
$ |
2,710 |
|
|
$ |
1,527 |
|
|
$ |
1,201 |
|
Less: pro forma stock based
employee compensation cost, after tax (unaudited)
|
|
|
5 |
|
|
|
10 |
|
|
|
10 |
|
|
Net income pro forma
(unaudited)
|
|
$ |
2,705 |
|
|
$ |
1,517 |
|
|
$ |
1,191 |
|
|
Basic EPS as reported
|
|
$ |
7.13 |
|
|
$ |
3.90 |
|
|
$ |
3.02 |
|
Basic EPS pro forma
(unaudited)
|
|
|
7.12 |
|
|
|
3.87 |
|
|
|
2.99 |
|
Diluted EPS as reported
|
|
|
7.07 |
|
|
|
3.86 |
|
|
|
3.00 |
|
Diluted EPS pro forma
(unaudited)
|
|
$ |
7.05 |
|
|
$ |
3.84 |
|
|
$ |
2.98 |
|
|
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 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
380 million, 392 million and 398 million for the
years ended December 31, 2005, 2004 and 2003, 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 383 million, 395 million and
400 million for the years ended December 31, 2005,
2004 and 2003, respectively. For the years ended
December 31, 2005 and 2003, approximately 5 thousand
and 2 million shares, respectively, attributable to the
assumed exercise of outstanding options were excluded from the
calculation of diluted EPS because the effect was antidilutive.
All shares attributable to outstanding options were dilutive for
the year ended December 31, 2004. 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 the third quarter of 2005, the Company acquired certain oil
and gas properties located in the Fort Worth Basin in Texas
for approximately $136 million. During 2005, the Company
also made acquisitions for other oil and gas properties totaling
approximately $192 million in the aggregate.
Sale of Trust Units
During the second half of 2005, the Company sold
16,950,000 units of beneficial interest in the Permian
Basin Royalty Trust (Units) held by the Company,
generating proceeds, after underwriting fees, of approximately
$252 million. The Company recorded a pretax gain of
$240 million on these sales. Net proceeds generated from
the sale of Units were used primarily for the acquisition of oil
and gas properties. At December 31, 2005, $64 million
of the net proceeds generated from the sale of Units were on
deposit with a third-party intermediary to be used to purchase
oil and gas properties during 2006.
48
BURLINGTON RESOURCES INC.
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
3. Accounts Receivable
Accounts receivable consisted of the following.
|
|
|
|
|
|
|
|
|
|
December 31, |
|
2005 |
|
2004 |
|
|
|
(In Millions) |
|
Natural gas, NGLs and crude oil
sales
|
|
$ |
1,248 |
|
|
$ |
790 |
|
Joint interest billings
|
|
|
142 |
|
|
|
99 |
|
Income tax receivable
|
|
|
36 |
|
|
|
35 |
|
Gas imbalance
|
|
|
12 |
|
|
|
11 |
|
Other
|
|
|
13 |
|
|
|
25 |
|
|
|
|
|
1,451 |
|
|
|
960 |
|
Less: allowance for doubtful
accounts
|
|
|
7 |
|
|
|
13 |
|
|
|
Accounts receivable
|
|
$ |
1,444 |
|
|
$ |
947 |
|
|
4. Goodwill
The entire goodwill balance of $1,089 million at
December 31, 2005, 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 2005 and determined that the fair
value of the Companys Canadian reporting unit exceeded its
net book value as of September 30, 2005. 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. Under 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 2005, the Company used a professional valuation
services firm to assist in preparing its annual valuation of the
Canadian reporting unit.
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, 2004
|
|
$ |
1,054 |
|
Changes in foreign exchange rates
during the period
|
|
|
35 |
|
|
December 31, 2005
|
|
$ |
1,089 |
|
|
49
BURLINGTON RESOURCES INC.
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
5. Oil and Gas and Other Properties
Oil and gas properties consisted of the following.
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
2005 |
|
2004 |
|
|
|
(In Millions) |
|
Proved properties
|
|
$ |
19,608 |
|
|
$ |
16,662 |
|
|
Less: Accumulated depreciation,
depletion and amortization
|
|
|
9,274 |
|
|
|
7,882 |
|
|
Proved propertiesnet
|
|
|
10,334 |
|
|
|
8,780 |
|
|
Unproved properties
|
|
|
|
|
|
|
|
|
|
Leasehold acquisition costs
|
|
|
471 |
|
|
|
536 |
|
|
Unproved reserves
|
|
|
590 |
|
|
|
745 |
|
|
Less: Accumulated amortization
|
|
|
123 |
|
|
|
152 |
|
|
Unproved propertiesnet
|
|
|
938 |
|
|
|
1,129 |
|
|
|
|
Oil and gas propertiesnet
|
|
$ |
11,272 |
|
|
$ |
9,909 |
|
|
Other properties consisted of the following.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciable |
|
|
|
|
December 31, |
|
Life-Years |
|
2005 |
|
2004 |
|
|
|
(In Millions) |
|
Plants and pipeline
systemsstraight-line
|
|
|
10-20 |
|
|
$ |
857 |
|
|
$ |
801 |
|
Plantsunit-of-production
|
|
|
|
|
|
|
401 |
|
|
|
338 |
|
Land, buildings, improvements and
furniture and fixtures
|
|
|
0-40 |
|
|
|
126 |
|
|
|
139 |
|
Data processing and
telecommunications equipment
|
|
|
3-7 |
|
|
|
200 |
|
|
|
184 |
|
Other
|
|
|
3-15 |
|
|
|
85 |
|
|
|
82 |
|
|
|
|
|
|
|
|
|
1,669 |
|
|
|
1,544 |
|
Less: Accumulated depreciation
|
|
|
|
|
|
|
503 |
|
|
|
420 |
|
|
|
Other propertiesnet
|
|
|
|
|
|
$ |
1,166 |
|
|
$ |
1,124 |
|
|
The following table reflects the net changes in capitalized
exploratory well costs pending proved reserve determination.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2005 |
|
2004 |
|
2003 |
|
|
|
(In Millions) |
|
Balance at January 1,
|
|
$ |
23 |
|
|
$ |
29 |
|
|
$ |
30 |
|
|
Additions
|
|
|
22 |
|
|
|
18 |
|
|
|
8 |
|
|
Reclassifications to proved
properties
|
|
|
(4 |
) |
|
|
(10 |
) |
|
|
(2 |
) |
|
Charged to expense
|
|
|
(16 |
) |
|
|
(14 |
) |
|
|
(7 |
) |
|
Balance at December 31,
|
|
$ |
25 |
|
|
$ |
23 |
|
|
$ |
29 |
|
|
Capitalized more than one year
since completion of drilling
|
|
$ |
|
|
|
$ |
1 |
|
|
$ |
|
|
50
BURLINGTON RESOURCES INC.
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
6. Accounts Payable
Accounts payable consisted of the following.
|
|
|
|
|
|
|
|
|
|
December 31, |
|
2005 |
|
2004 |
|
|
|
(In Millions) |
|
Trade payables
|
|
$ |
144 |
|
|
$ |
89 |
|
Accrued expenses
|
|
|
1,207 |
|
|
|
828 |
|
Revenues and royalties payable to
others
|
|
|
286 |
|
|
|
123 |
|
Accrued payroll
|
|
|
79 |
|
|
|
56 |
|
Gas imbalance
|
|
|
11 |
|
|
|
12 |
|
Other
|
|
|
3 |
|
|
|
17 |
|
|
|
Accounts payable
|
|
$ |
1,730 |
|
|
$ |
1,125 |
|
|
7. Income Taxes
The jurisdictional components of income before income taxes and
cumulative effect of change in accounting principle follow.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
2005 |
|
2004 |
|
2003 |
|
|
|
(In Millions) |
|
Domestic
|
|
$ |
2,483 |
|
|
$ |
1,357 |
|
|
$ |
983 |
|
Foreign
|
|
|
1,565 |
|
|
|
947 |
|
|
|
587 |
|
|
|
Total
|
|
$ |
4,048 |
|
|
$ |
2,304 |
|
|
$ |
1,570 |
|
|
The provision for income taxes follows.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
2005 |
|
2004 |
|
2003 |
|
|
|
(In Millions) |
|
Current
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Federal
|
|
$ |
498 |
|
|
$ |
171 |
|
|
$ |
84 |
|
|
State
|
|
|
25 |
|
|
|
43 |
|
|
|
9 |
|
|
Foreign
|
|
|
312 |
|
|
|
192 |
|
|
|
67 |
|
|
|
|
|
835 |
|
|
|
406 |
|
|
|
160 |
|
|
Deferred
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Federal
|
|
|
261 |
|
|
|
175 |
|
|
|
85 |
|
|
State
|
|
|
1 |
|
|
|
(4 |
) |
|
|
6 |
|
|
Foreign
|
|
|
241 |
|
|
|
200 |
|
|
|
59 |
|
|
|
|
|
503 |
|
|
|
371 |
|
|
|
150 |
|
|
|
|
Total
|
|
$ |
1,338 |
|
|
$ |
777 |
|
|
$ |
310 |
|
|
Reconciliation of the federal statutory income tax rate to the
effective income tax rate follows.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
2005 |
|
2004 |
|
2003 |
|
U.S. statutory rate
|
|
|
35.0 |
% |
|
|
35.0 |
% |
|
|
35.0 |
% |
State income taxes (net of federal
benefit)
|
|
|
0.4 |
|
|
|
1.0 |
|
|
|
0.6 |
|
Taxes on foreign income in excess
of U.S. statutory rate
|
|
|
2.9 |
|
|
|
3.6 |
|
|
|
3.9 |
|
Effect of change in foreign income
tax rate(1)
|
|
|
(1.3 |
) |
|
|
(2.9 |
) |
|
|
(13.6 |
) |
Section 29 tax credits(2)
|
|
|
|
|
|
|
(0.4 |
) |
|
|
(1.7 |
) |
Cross-border financing benefit(3)
|
|
|
(2.8 |
) |
|
|
(4.5 |
) |
|
|
(6.2 |
) |
Other(4)
|
|
|
(1.1 |
) |
|
|
1.9 |
|
|
|
1.7 |
|
|
|
Effective rate
|
|
|
33.1 |
% |
|
|
33.7 |
% |
|
|
19.7 |
% |
|
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 statutory 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 $51 million
( 1.3%), $23 million ( 1.0%) and
$203 million ( 12.9%) in 2005, 2004 and 2003,
respectively. The Company also recorded a benefit of
$45 million ( 1.9%) and $11 million
( 0.7%) in 2004 and 2003, respectively, due to
reductions in the Alberta provincial corporate income tax rate
in Canada. |
|
(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. |
|
(3) |
The Company recorded benefits of $112 million (
2.8%), $104 million ( 4.5%) and
$97 million ( 6.2%) in 2005, 2004 and 2003,
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 2005 and 2004, the Company recorded a tax benefit of
$40 million ( 0.98%) and an income tax expense
of $12 million (0.53%), respectively, related to return as
filed adjustments. 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. |
Deferred income tax liabilities (assets) follow.
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
2005 |
|
2004 |
|
|
|
(In Millions) |
|
Deferred income tax liabilities
|
|
|
|
|
|
|
|
|
|
Property, plant and equipment
|
|
$ |
2,310 |
|
|
$ |
2,175 |
|
|
Financial accruals and other
|
|
|
793 |
|
|
|
573 |
|
|
|
|
|
3,103 |
|
|
|
2,748 |
|
|
Deferred income tax assets
|
|
|
|
|
|
|
|
|
|
Alternative minimum tax
(AMT) credit carryforward
|
|
|
|
|
|
|
(161 |
) |
|
Foreign net operating loss
carryforward
|
|
|
(133 |
) |
|
|
(171 |
) |
|
Commodity hedging contracts and
other derivatives
|
|
|
(36 |
) |
|
|
13 |
|
|
|
|
|
(169 |
) |
|
|
(319 |
) |
|
Less: valuation allowance
|
|
|
35 |
|
|
|
15 |
|
|
|
|
|
|
|
2,969 |
|
|
|
2,444 |
|
Less: current portion
(asset) liability
|
|
|
(69 |
) |
|
|
48 |
|
|
|
|
Deferred income taxes
|
|
$ |
3,038 |
|
|
$ |
2,396 |
|
|
At December 31, 2005 and 2004, $69 million and
$48 million, respectively, of the net deferred income tax
(asset) liability is classified as current and is included in
Other Current Assets and Taxes Payable, respectively, on the
Companys Consolidated Balance Sheet. The net deferred
income tax liabilities at December 31, 2005 and 2004
include deferred state income tax liabilities of approximately
$51 million for both years. The net deferred income tax
liabilities also include foreign tax liabilities of
approximately $2,192 million and $1,872 million at
December 31, 2005 and 2004, 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,
2005, undistributed earnings for which a U.S. deferred
income tax liability has not been recognized total
$2,049 million. On October 27, 2005, the Company
repatriated $500 million of eligible foreign earnings to
the U.S. Company under the one-time provisions of the
American Jobs Creation Act of 2004. Excluded from undistributed
earnings at December 31, 2005 are permanent differences of
$1,195 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.
Of the tax benefits for operating loss carryforwards, all of
which relate to foreign jurisdictions, $109 million has no
expiration date, $17 million will expire in the next four
to five years, and $7 million will expire in 2015.
|
|
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
52
BURLINGTON RESOURCES INC.
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
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, 2005, the Companys cash-flow hedges
consist 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, 2005, the Companys fair-value hedges
consist 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, 2005, 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, 2005, 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) |
|
|
2006 |
|
|
Swap
|
|
Cash flow
|
|
5,844,500
|
|
|
|
$ |
7.59 |
|
|
$ |
(28 |
) |
|
|
|
|
Purchased put
|
|
Cash flow
|
|
64,006,657
|
|
|
|
|
7.83 |
|
|
|
27 |
|
|
|
|
|
Written call
|
|
Cash flow
|
|
64,006,657
|
|
|
|
|
9.94 |
|
|
|
(80 |
) |
|
|
|
|
Purchased put
|
|
Cash flow
|
|
|
|
3,795,000
|
|
|
51.81 |
|
|
|
5 |
|
|
|
|
|
Written call
|
|
Cash flow
|
|
|
|
3,795,000
|
|
|
66.41 |
|
|
|
(15 |
) |
|
|
|
|
Swap
|
|
Fair value
|
|
457,000
|
|
|
|
|
10.96 |
|
|
|
(1 |
) |
|
|
|
|
N/A
|
|
Fair value (obligation)
|
|
457,000
|
|
|
|
|
11.02 |
|
|
|
1 |
|
|
|
2007 |
|
|
Swap
|
|
Cash flow
|
|
1,013,000
|
|
|
|
|
3.83 |
|
|
|
(5 |
) |
|
|
|
|
Swap
|
|
Fair value
|
|
136,000
|
|
|
|
|
10.01 |
|
|
|
|
|
|
|
|
|
N/A
|
|
Fair value (obligation)
|
|
136,000
|
|
|
|
$ |
10.90 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
(96 |
) |
|
As of December 31, 2005, 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) |
|
|
2006 |
|
|
Interest rate swap
|
|
Fair value
|
|
$ |
50 |
|
|
|
5.6% |
|
|
LIBOR + 3.36%
|
|
$ |
(1 |
) |
|
The derivative assets and liabilities represent the market
values of the Companys derivative instruments as of
December 31, 2005. During the years ended 2005, 2004 and
2003, hedging activities related to cash settlements decreased
revenues $189 million, $40 million and
$63 million, respectively. In addition, during 2005, 2004
and 2003, losses of $2 million, gains of $2 million,
and losses of $200 thousand, respectively, were recorded in
revenues associated with ineffectiveness of cash-flow and
fair-value
53
BURLINGTON RESOURCES INC.
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
hedges. During 2005, 2004 and 2003, losses of $1 million,
gains of $1 million and $9 million, respectively, were
recorded in revenues related to changes in fair value of
derivative instruments not designated as hedging instruments.
Changes in other comprehensive income (loss) for the three years
ended December 31, 2005 follow.
|
|
|
|
|
|
|
|
(In Millions) |
|
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 |
|
|
Reclassification adjustments for
settled contracts
|
|
|
114 |
|
|
Current period changes in fair
value of settled contracts
|
|
|
(135 |
) |
|
Changes in fair value of
outstanding hedging positions
|
|
|
(58 |
) |
|
Accumulated other comprehensive
loss on hedging activitiesDecember 31, 2005
|
|
$ |
(59 |
) |
|
Based on commodity prices and foreign exchange rates as of
December 31, 2005, the Company expects to reclassify losses
of $90 million ($56 million after tax) to earnings
from the balance in Accumulated Other Comprehensive Income
during the next twelve months. At December 31, 2005, the
Company had derivative assets of $2 million and derivative
liabilities of $99 million of which $2 million,
$94 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.
Long-term debt follows.
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
2005 |
|
2004 |
|
|
|
(In Millions) |
|
Notes, 5.60%, due 2006
|
|
$ |
500 |
|
|
$ |
500 |
|
Notes, 6.60%, due 2007(1)
|
|
|
129 |
|
|
|
124 |
|
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
|
|
|
4 |
|
|
|
6 |
|
Discounts and other
|
|
|
(38 |
) |
|
|
(41 |
) |
|
|
Total debt
|
|
|
3,895 |
|
|
|
3,889 |
|
|
|
Less current maturities
|
|
|
2 |
|
|
|
2 |
|
|
|
Total long-term debt
|
|
$ |
3,893 |
|
|
$ |
3,887 |
|
|
|
|
(1) |
Notes are denominated in Canadian dollars and reported in
U.S. dollars. |
54
BURLINGTON RESOURCES INC.
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The Company has debt maturities of $502 million due in
2006, $480 million due in 2007, $1 million due in
2008, $150 million due in 2010, and $2,800 million due
in 2011 and thereafter. The fair value of debt outstanding as of
December 31, 2005 and 2004 was $4,489 million and
$4,528 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 sub-limit for the issuance of letters of
credit, including up to US$250 million in letters of credit
under the Canadian subfacility. On August 17, 2005, the
Company amended the Credit Facility to extend the expiration
date from July 2009 to August 2010. 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 repay 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, 2005, 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
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 notice of 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 $173 million and $160 million as of
December 31, 2005 and 2004, 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 $604 million
and $468 million at December 31, 2005 and 2004,
respectively. Accretion expense for 2005 was $31 million
and is included in Depreciation, Depletion and Amortization
expense on the Companys Consolidated Statement of Income.
55
BURLINGTON RESOURCES INC.
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
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, 2004
|
|
$ |
468 |
|
|
Liabilities incurred during the
period
|
|
|
50 |
|
|
Liabilities settled during the
period
|
|
|
(15 |
) |
|
Current year accretion expense
|
|
|
31 |
|
|
Revisions in estimated cash flows
|
|
|
73 |
|
|
Changes in foreign exchange rates
during the period
|
|
|
(3 |
) |
|
Carrying amount of asset retirement
obligations as of December 31, 2005
|
|
$ |
604 |
|
|
|
|
11. |
Significant Concentrations |
In 2005, 2004 and 2003, approximately 46 percent,
48 percent and 49 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 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 years ended December 31, 2005 and 2004, sales to
BP and ConocoPhillips accounted for approximately 11 and
10 percent and 12 and 10 percent, respectively, of the
Companys total revenues. During the year ended
December 31, 2003, no customer accounted for more than
10 percent of 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.
Substantially all of the Companys accounts receivable at
December 31, 2005 and 2004 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,
2005, 25 percent of the Companys accounts receivable
balance was due from five customers.
56
BURLINGTON RESOURCES INC.
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The Companys Common Stock activity follows.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Number of Shares |
|
|
|
|
|
Issued |
|
Treasury |
|
Outstanding |
|
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 |
|
|
Treasury shares purchased
|
|
|
|
|
|
|
(15,734,600 |
) |
|
|
(15,734,600 |
) |
|
Shares issued under compensation
plans, net of forfeitures
|
|
|
|
|
|
|
313,702 |
|
|
|
313,702 |
|
|
Option exercises
|
|
|
|
|
|
|
2,781,931 |
|
|
|
2,781,931 |
|
|
December 31, 2005
|
|
|
482,376,870 |
|
|
|
(107,074,368 |
) |
|
|
375,302,502 |
|
|
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).
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 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, 2005,
9,049,370 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, 2005, 8,120,843 shares were available for
grant under the 1997 Plan, of which up to 300,000 shares
annually may be restricted stock.
The Company issued 363,425 shares, 519,105 shares and
578,850 shares of restricted stock in 2005, 2004 and 2003,
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,
2005, 2004, and 2003 was approximately $44.77, $29.44 and
$21.04, respectively. Related compensation expense of
approximately $14 million, $11 million and
$11 million was recognized for the years ended
December 31, 2005, 2004 and 2003, respectively.
The Companys 2000 Stock Option Plan (2000
Plan) for Non-Employee Directors provides for the annual
grant of a nonqualified option of 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,
2005, 214,000 shares were available for grant under the
2000 Plan.
57
BURLINGTON RESOURCES INC.
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The Companys stock option activity follows.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted |
|
|
|
|
Average |
|
|
Options |
|
Exercise Price |
|
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 |
|
|
Granted
|
|
|
1,042,250 |
|
|
|
44.80 |
|
|
Exercised
|
|
|
(2,781,931 |
) |
|
|
23.63 |
|
|
Cancelled
|
|
|
(98,285 |
) |
|
|
28.94 |
|
|
December 31, 2005
|
|
|
4,255,268 |
|
|
$ |
28.87 |
|
|
The following table summarizes information related to stock
options outstanding and exercisable at December 31, 2005.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted |
|
|
|
|
|
|
|
|
|
|
Average |
|
|
|
|
|
|
Range of |
|
Weighted |
|
Remaining |
|
|
|
Weighted |
Options |
|
Exercise |
|
Average |
|
Contractual |
|
Options |
|
Average |
Outstanding |
|
Prices |
|
Exercise Price |
|
Life |
|
Exercisable |
|
Exercise Price |
|
|
472,652 |
|
|
$ |
13.69$20.31 |
|
|
$ |
17.90 |
|
|
|
4.3 |
|
|
|
472,652 |
|
|
$ |
17.90 |
|
|
2,724,366 |
|
|
|
20.83 29.36 |
|
|
|
24.77 |
|
|
|
6.8 |
|
|
|
2,192,947 |
|
|
|
25.69 |
|
|
992,500 |
|
|
|
32.98 44.22 |
|
|
|
43.70 |
|
|
|
9.0 |
|
|
|
48,400 |
|
|
|
33.63 |
|
|
65,750 |
|
|
|
49.55 72.58 |
|
|
|
53.30 |
|
|
|
9.4 |
|
|
|
48,000 |
|
|
|
49.55 |
|
|
|
4,255,268 |
|
|
$ |
13.69$72.58 |
|
|
$ |
28.87 |
|
|
|
7.1 |
|
|
|
2,761,999 |
|
|
$ |
24.91 |
|
|
Exercisable stock options and weighted average exercise prices
at December 31, 2004 and 2003 follow.
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted |
|
|
Options |
|
Average |
|
|
Exercisable |
|
Exercise Price |
|
December 31, 2004
|
|
|
3,155,479 |
|
|
$ |
21.57 |
|
December 31, 2003
|
|
|
6,797,856 |
|
|
$ |
22.54 |
|
|
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
58
BURLINGTON RESOURCES INC.
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
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 Revenue
Service limit of $14,000 in 2005. 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 $11 million, $10 million and
$9 million to these plans for the years ended
December 31, 2005, 2004 and 2003, 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, 2005, a $10 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, |
|
2005 |
|
2004 |
|
2005 |
|
2004 |
|
|
|
(In Millions) |
|
Change in benefit obligation
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Benefit obligation at beginning of
year
|
|
$ |
250 |
|
|
$ |
222 |
|
|
$ |
36 |
|
|
$ |
46 |
|
|
Service cost
|
|
|
12 |
|
|
|
11 |
|
|
|
|
|
|
|
|
|
|
Interest cost
|
|
|
14 |
|
|
|
13 |
|
|
|
2 |
|
|
|
2 |
|
|
Plan amendment
|
|
|
|
|
|
|
1 |
|
|
|
|
|
|
|
(3 |
) |
|
Actuarial loss
|
|
|
40 |
|
|
|
15 |
|
|
|
2 |
|
|
|
(6 |
) |
|
Currency exchange
|
|
|
1 |
|
|
|
2 |
|
|
|
|
|
|
|
|
|
|
Participant contributions
|
|
|
|
|
|
|
|
|
|
|
2 |
|
|
|
2 |
|
|
Benefits paid
|
|
|
(21 |
) |
|
|
(14 |
) |
|
|
(5 |
) |
|
|
(5 |
) |
|
|
Benefit obligation at end of year
|
|
|
296 |
|
|
|
250 |
|
|
|
37 |
|
|
|
36 |
|
|
Change in plan assets
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair value of plan assets at
beginning of year
|
|
|
214 |
|
|
|
180 |
|
|
|
|
|
|
|
|
|
|
Actual return on plan assets
|
|
|
13 |
|
|
|
23 |
|
|
|
|
|
|
|
|
|
|
Currency exchange
|
|
|
1 |
|
|
|
2 |
|
|
|
|
|
|
|
|
|
|
Employer contribution
|
|
|
46 |
|
|
|
23 |
|
|
|
3 |
|
|
|
3 |
|
|
Participant contributions
|
|
|
|
|
|
|
|
|
|
|
2 |
|
|
|
2 |
|
|
Benefits paid
|
|
|
(21 |
) |
|
|
(14 |
) |
|
|
(5 |
) |
|
|
(5 |
) |
|
|
Fair value of plan assets at end of
year
|
|
|
253 |
|
|
|
214 |
|
|
|
|
|
|
|
|
|
|
Funded status
|
|
|
(43 |
) |
|
|
(36 |
) |
|
|
(37 |
) |
|
|
(36 |
) |
Unrecognized net actuarial loss
|
|
|
87 |
|
|
|
51 |
|
|
|
17 |
|
|
|
17 |
|
Unrecognized prior service cost
(benefit)
|
|
|
3 |
|
|
|
3 |
|
|
|
(7 |
) |
|
|
(8 |
) |
|
Net prepaid (accrued) benefit
cost
|
|
$ |
47 |
|
|
$ |
18 |
|
|
$ |
(27 |
) |
|
$ |
(27 |
) |
|
59
BURLINGTON RESOURCES INC.
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The following table summarizes the projected benefit obligation,
accumulated benefit obligation, fair value of plan assets,
minimum pension liability and related consolidated balance sheet
amounts for the Companys pension plans as of the
measurement date.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. |
|
Canada |
|
December 31, |
|
2005 |
|
2004 |
|
2005 |
|
2004 |
|
|
|
(In Millions) |
|
Benefit obligation
|
|
$ |
267 |
|
|
$ |
225 |
|
|
$ |
29 |
|
|
$ |
25 |
|
Accumulated benefit obligation
|
|
|
207 |
|
|
|
179 |
|
|
|
26 |
|
|
|
23 |
|
Fair value of plan assets
|
|
|
222 |
|
|
|
187 |
|
|
|
31 |
|
|
|
27 |
|
Accrued benefit liability
|
|
|
4 |
|
|
|
|
|
|
|
1 |
|
|
|
1 |
|
Prepaid benefit cost
|
|
$ |
46 |
|
|
$ |
15 |
|
|
$ |
4 |
|
|
$ |
4 |
|
|
Minimum pension liability
|
|
$ |
2 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
Accumulated other comprehensive loss
|
|
$ |
2 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
The Company expects to contribute $12 million to its
pension plans in 2006.
The following table summarizes pension and postretirement
benefit expense for the three years ended December 31, 2005.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Postretirement |
|
|
Pension Benefits |
|
Benefits |
|
Year Ended December 31, |
|
2005 |
|
2004 |
|
2003 |
|
2005 |
|
2004 |
|
2003 |
|
|
|
(In Millions) |
|
Benefit cost for the plans includes
the following components
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Service cost
|
|
$ |
12 |
|
|
$ |
11 |
|
|
$ |
9 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
Interest cost
|
|
|
14 |
|
|
|
13 |
|
|
|
13 |
|
|
|
2 |
|
|
|
2 |
|
|
|
3 |
|
|
Expected return on plan assets
|
|
|
(14 |
) |
|
|
(13 |
) |
|
|
(13 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Recognized net actuarial loss
|
|
|
5 |
|
|
|
5 |
|
|
|
4 |
|
|
|
1 |
|
|
|
1 |
|
|
|
|
|
|
|
|
Net benefit cost
|
|
$ |
17 |
|
|
$ |
16 |
|
|
$ |
13 |
|
|
$ |
3 |
|
|
$ |
3 |
|
|
$ |
3 |
|
|
Assumptions used to determine net benefit obligations follow.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Postretirement |
|
|
Pension Benefits |
|
Benefits |
|
December 31, |
|
2005 |
|
2004 |
|
2003 |
|
2005 |
|
2004 |
|
2003 |
|
Weighted average assumptions
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Discount rate
|
|
|
5.50 |
% |
|
|
5.75 |
% |
|
|
6.00 |
% |
|
|
5.50 |
% |
|
|
5.75 |
% |
|
|
6.00% |
|
|
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, |
|
2005 |
|
2004 |
|
2003 |
|
2005 |
|
2004 |
|
2003 |
|
Weighted average assumptions
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Discount rate
|
|
|
5.75 |
% |
|
|
6.00 |
% |
|
|
6.75 |
% |
|
|
5.75 |
% |
|
|
6.00 |
% |
|
|
6.75% |
|
|
Expected return on plan assets
|
|
|
7.50 |
|
|
|
7.50 |
|
|
|
8.00 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Rate of compensation increase
|
|
|
4.50 |
% |
|
|
4.50 |
% |
|
|
4.50 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
60
BURLINGTON RESOURCES INC.
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The following table summarizes the future expected benefit
payments to be paid from the pension and postretirement plans.
|
|
|
|
|
|
|
|
|
|
|
Pension |
|
Postretirement |
Year Ended |
|
Payments |
|
Payments(1) |
|
|
|
(In Millions) |
|
2006
|
|
$ |
19 |
|
|
$ |
3 |
|
2007
|
|
|
21 |
|
|
|
3 |
|
2008
|
|
|
23 |
|
|
|
3 |
|
2009
|
|
|
23 |
|
|
|
3 |
|
2010
|
|
|
26 |
|
|
|
3 |
|
2011-2015
|
|
$ |
166 |
|
|
$ |
14 |
|
|
|
|
(1) |
Includes a reduction each year after 2006 for an expected
subsidy related to the Medicare Prescription Drug Improvement
and Modernization Act of 2003. |
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 |
|
2005 |
|
2004 |
|
Target |
|
2005 |
|
2004 |
|
Equity
|
|
|
65 |
% |
|
|
64 |
% |
|
|
67 |
% |
|
|
58 |
% |
|
|
63 |
% |
|
|
62 |
% |
Fixed income
|
|
|
35 |
|
|
|
35 |
|
|
|
33 |
|
|
|
31 |
|
|
|
27 |
|
|
|
27 |
|
Other
|
|
|
|
|
|
|
1 |
|
|
|
|
|
|
|
11 |
|
|
|
10 |
|
|
|
11 |
|
|
|
Total
|
|
|
100 |
% |
|
|
100 |
% |
|
|
100 |
% |
|
|
100 |
% |
|
|
100 |
% |
|
|
100 |
% |
|
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.
The Company bases its assumed discount rate on the annualized
Moodys Aa bond rating as an approximation of the
yield curve of a portfolio of high-quality zero coupon bonds.
Since this index does not vary by duration, the Company compares
it to an alternate discount rate calculated by discounting plan
cash flows using a yield curve derived from over 300 noncallable
bonds rated Aa or better. For the year ended December 31,
2005, the discount rates calculated using each methodology were
not significantly different.
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
2006. The rate is assumed to decrease gradually to
5 percent for 2010 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 for
2006 to gradually decrease to 5 percent for 2012 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
|
|
$ |
144 |
|
|
$ |
(126 |
) |
Effect on postretirement benefit
obligation
|
|
$ |
2,845 |
|
|
$ |
(2,493 |
) |
|
61
BURLINGTON RESOURCES INC.
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
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 18 years
and require the Company to pay transportation demand charges
regardless of the amount of pipeline capacity utilized by the
Company. The Company paid $181 million, $193 million
and $179 million of demand charges for the years ended
December 31, 2005, 2004 and 2003, 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, 2005 follow.
|
|
|
|
|
|
|
|
(In Millions) |
|
2006
|
|
$ |
152 |
|
2007
|
|
|
118 |
|
2008
|
|
|
95 |
|
2009
|
|
|
75 |
|
2010
|
|
|
58 |
|
Thereafter
|
|
|
299 |
|
|
|
Total
|
|
$ |
797 |
|
|
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 $32 million, $35 million and
$38 million for the years ended December 31, 2005,
2004 and 2003, respectively.
Future minimum annual rental commitments under non-cancelable
leases at December 31, 2005 follow.
|
|
|
|
|
|
|
|
(In Millions) |
|
2006
|
|
$ |
36 |
|
2007
|
|
|
33 |
|
2008
|
|
|
34 |
|
2009
|
|
|
33 |
|
2010
|
|
|
35 |
|
Thereafter
|
|
|
136 |
|
|
|
Total
|
|
$ |
307 |
|
|
The Companys drilling rig commitments at December 31,
2005 follow.
|
|
|
|
|
|
|
|
(In Millions) |
|
2006
|
|
$ |
65 |
|
2007
|
|
|
36 |
|
2008
|
|
|
20 |
|
2009
|
|
|
13 |
|
2010
|
|
|
5 |
|
Thereafter
|
|
|
|
|
|
|
Total
|
|
$ |
139 |
|
|
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
62
BURLINGTON RESOURCES INC.
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Company. On June 10, 2005, in the case of Amoco v.
Watson, the United States Court of Appeals for the District of
Columbia issued an opinion in favor of the MMS regarding a
producers obligation to place coal seam gas in
marketable condition at no cost to the government
when calculating federal royalty payments. Since some of the
intervenors claims relate to the Companys coal seam
production in the San Juan Basin and the deductions
utilized by the Company in calculating royalty payments on such
production, the Company analyzed the potential impact of the
Amoco ruling and determined that, if upheld, the decision will
have a negative impact on the Companys defenses in these
proceedings.
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 to provide for this potential liability based upon
managements evaluation of this matter.
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 court certified the plaintiff classes of
royalty and overriding royalty interest owners, and trial by
jury commenced on October 10, 2005, during which plaintiffs
sought monetary damages of up to $42 million in principal,
plus $311 million in interest, and unspecified punitive
damages and attorneys fees. The Company presented
substantial defenses to these claims. In a separate action, the
Company and El Paso Natural Gas Company asserted
contractual claims for indemnity against each other. On
November 9, 2005, the parties counsel entered into a
preliminary agreement to settle this lawsuit for
$66 million, plus interest on this amount commencing
January 20, 2006, as provided in the settlement agreement.
On January 20, 2006, the Court preliminarily approved the
settlement and scheduled a fairness hearing to determine the
fairness to class members of the proposed settlement, which is
scheduled to commence in May 2006. The Company and El Paso
Natural Gas Company have reached a preliminary agreement to
settle the contractual indemnity claims against each other. The
settlement of the indemnity claims is subject to final court
approval of the class action settlement. Upon final court
approval of the class action settlement, the Companys
contribution to the settlement will be approximately
$36 million, plus interest from January 20, 2006, as
provided in the settlement agreement. The Company has
established a reserve to provide for this potential liability
based upon managements evaluation of this matter.
The Company and its directors have been named defendants in a
lawsuit styled Jeffrey Halpern, Derivatively on Behalf of
Burlington Resources Inc., Plaintiff, vs. Bobby S. Shackouls,
et al., and Burlington Resources Inc. a Delaware
Corporation, Nominal Defendant, Cause No. 2005-79250,
filed on December 15, 2005, in the 215th Judicial
District Court of Harris County, Texas (Halpern
case) and also named as defendants in a lawsuit styled
Charles Conrardy, On Behalf of Himself and All Others
Similarly Situated, Plaintiff, vs. Burlington Resources Inc.,
et al., Cause No. 2005-79267, filed on
December 16, 2005, in the 165th Judicial District
Court of Harris County, Texas (Conrardy case). Both
lawsuits allege that Companys board of directors breached
its fiduciary duties in approving the proposed merger announced
on December 12, 2005, between the Company and
ConocoPhillips. The Halpern case is a stockholder derivative
action purportedly filed on behalf of the Company against the
Companys board of directors, and contains claims for abuse
of control, breach of the duty of candor, gross mismanagement,
waste and unjust enrichment, and breach of fiduciary duty. The
Conrardy case is a purported stockholder class action lawsuit
against the Company and the Companys board of directors,
and contains a claim for breach of fiduciary duty. Both
petitions allege, among other things, that the Companys
board of directors engaged in self dealing by approving a
proposed merger that allegedly advances the Companys board
of directors personal interests at the expense of the
Companys stockholders, thus causing the Companys
stockholders to receive an unfair price for their shares of the
Companys common stock. Both petitions seek, among other
things, an injunction preventing the completion of the merger,
rescission if the merger is consummated, attorneys fees
and expenses associated with the lawsuit, and
63
BURLINGTON RESOURCES INC.
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
any other further equitable relief as the courts may deem just
and proper. The Company believes these actions are without merit
and intends to defend them vigorously. The Company has not
established a reserve for these matters.
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 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 and could prove to be greater than
managements current assessments, 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.
At December 31, 2005, the Companys Consolidated
Balance Sheet included reserves for legal proceedings of
$137 million and environmental matters of $20 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, the Company believes 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, |
|
2005 |
|
2004 |
|
2003 |
|
|
|
(In Millions) |
|
Interest paidnet of
capitalized interest(1)
|
|
$ |
273 |
|
|
$ |
275 |
|
|
$ |
251 |
|
Income taxes paidnet
|
|
$ |
794 |
|
|
$ |
274 |
|
|
$ |
171 |
|
|
|
|
(1) |
The Company recorded capitalized interest of $1 million and
$25 million for the years ended December 31, 2005 and
2003, respectively. The Company had no capitalized interest for
the year ended December 31, 2004. |
At December 31, 2005 and 2004, capital expenditures
included in the Accounts Payable balance on the Companys
Consolidated Balance Sheet were $555 million and
$333 million, respectively.
16. Impairment of Oil and Gas Properties
During the year ended December 31, 2005, the Company
recorded an impairment charge of $50 million for a downward
reserve adjustment primarily related to its onshore China
properties. During the year ended December 31, 2004, the
Company recorded an impairment charge of $90 million
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.
64
BURLINGTON RESOURCES INC.
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
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 2005, 2004 or
2003.
The following tables present information about reported segment
operations.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
North America |
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2005 |
|
U.S. |
|
Canada |
|
International |
|
Total |
|
|
|
(In Millions) |
|
Revenues
|
|
$ |
3,891 |
|
|
$ |
2,707 |
|
|
$ |
989 |
|
|
$ |
7,587 |
|
Depreciation, depletion and
amortization
|
|
|
434 |
|
|
|
651 |
|
|
|
202 |
|
|
|
1,287 |
|
Impairment of oil and gas properties
|
|
|
|
|
|
|
|
|
|
|
50 |
|
|
|
50 |
|
Income before income taxes
|
|
|
2,766 |
|
|
|
1,412 |
|
|
|
471 |
|
|
|
4,649 |
|
Propertiesnet
|
|
|
4,845 |
|
|
|
6,188 |
|
|
|
1,326 |
|
|
|
12,359 |
|
Goodwill
|
|
|
|
|
|
|
1,089 |
|
|
|
|
|
|
|
1,089 |
|
Capital expenditures
|
|
$ |
1,281 |
|
|
$ |
1,217 |
|
|
$ |
175 |
|
|
$ |
2,673 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 |
|
|
65
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, |
|
2005 |
|
2004 |
|
2003 |
|
|
|
(In Millions) |
|
Income before income taxes and
cumulative effect of change in accounting principle for
reportable segments
|
|
$ |
4,649 |
|
|
$ |
2,844 |
|
|
$ |
2,032 |
|
Corporate expenses
|
|
|
282 |
|
|
|
239 |
|
|
|
189 |
|
Interest expense
|
|
|
281 |
|
|
|
282 |
|
|
|
260 |
|
Other expensenet
|
|
|
38 |
|
|
|
19 |
|
|
|
13 |
|
|
Consolidated income before income
taxes and cumulative effect
of change in accounting principle
|
|
$ |
4,048 |
|
|
$ |
2,304 |
|
|
$ |
1,570 |
|
|
The following is a reconciliation of segment additions to
properties to consolidated amounts.
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
2005 |
|
2004 |
|
2003 |
|
|
|
(In Millions) |
|
Total capital expenditures for
reportable segments
|
|
$ |
2,673 |
|
|
$ |
1,727 |
|
|
$ |
1,765 |
|
Corporate administrative capital
expenditures
|
|
|
14 |
|
|
|
20 |
|
|
|
23 |
|
|
Consolidated capital expenditures
|
|
$ |
2,687 |
|
|
$ |
1,747 |
|
|
$ |
1,788 |
|
|
The following is a reconciliation of segment net properties to
consolidated amounts.
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
2005 |
|
2004 |
|
2003 |
|
|
|
(In Millions) |
|
Propertiesnet for reportable
segments
|
|
$ |
12,359 |
|
|
$ |
10,942 |
|
|
$ |
10,215 |
|
Corporate propertiesnet
|
|
|
79 |
|
|
|
91 |
|
|
|
96 |
|
|
Consolidated propertiesnet
|
|
$ |
12,438 |
|
|
$ |
11,033 |
|
|
$ |
10,311 |
|
|
18. Taxes Other Than Income Taxes
Taxes other than income taxes are as follow.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
2005 |
|
2004 |
|
2003 |
|
|
|
(In Millions) |
|
Severance taxes
|
|
$ |
278 |
|
|
$ |
204 |
|
|
$ |
141 |
|
Ad valorem taxes
|
|
|
56 |
|
|
|
36 |
|
|
|
30 |
|
Payroll taxes and other
|
|
|
21 |
|
|
|
20 |
|
|
|
16 |
|
|
|
Taxes other than income taxes
|
|
$ |
355 |
|
|
$ |
260 |
|
|
$ |
187 |
|
|
19. Other Matters
Recent Accounting Pronouncements
In May 2005, the FASB issued SFAS No. 154,
Accounting Changes and Error Corrections, a replacement of
APB Opinion No. 20 and FASB Statement No. 3.
SFAS No. 154 requires retrospective application to
prior period financial statements for changes in accounting
principle, unless it is impracticable to determine either the
period-specific effects or the cumulative effect of the change.
SFAS No. 154 also requires that retrospective
application of a change in accounting principle be limited to
the direct effects of the change. Indirect effects of a change
in accounting principle should be recognized in the period of
the accounting change. The Company adopted
SFAS No. 154 on January 1, 2006. The impact of
SFAS No. 154 will depend on the nature and extent of
any voluntary accounting changes and correction of errors after
the effective date, but management does not currently expect
SFAS No. 154 to have a material impact on the
Companys consolidated financial position, results of
operations or cash flows.
In March 2005, the FASB issued Interpretation No. 47,
Accounting for Conditional Asset Retirement Obligations
an interpretation of FASB Statement No. 143
(Interpretation). This Interpretation clarifies
that the term conditional asset retirement obligation as
66
BURLINGTON RESOURCES INC.
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
used in FASB Statement No. 143, Accounting for Asset
Retirement Obligations, refers to a legal obligation to
perform an asset retirement activity in which the timing and
(or) method of settlement are conditional on a future event
that may or may not be within the control of the entity. The
obligation to perform the asset retirement activity is
unconditional even though uncertainty exists about the timing
and (or) method of settlement. Thus, the timing and
(or) method of settlement may be conditional on a future
event. Accordingly, an entity is required to recognize a
liability for the fair value of a conditional asset retirement
obligation if the fair value of the liability can be reasonably
estimated. This Interpretation also clarifies when an entity
would have sufficient information to reasonably estimate the
fair value of an asset retirement obligation. This
Interpretation is effective for the Companys year ended
December 31, 2005. The adoption of this Interpretation did
not 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
December 15, 2005. The Company adopted this statement on
January 1, 2006, 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 will
result in the Company recording an expense of approximately
$10 million in 2006.
In September 2005, the FASB issued EITF Issue No. 04-13,
Accounting for Purchases and Sales of Inventory with the Same
Counterparty (Issue). This Issue addresses the
accounting for purchase and sales arrangements with the same
party and is effective for new arrangements entered into, and
modifications or renewals of existing arrangements, beginning in
the first interim or annual reporting period beginning after
March 15, 2006. The adoption of this Issue is not expected
to have a material impact on the Companys consolidated
financial position or results of operations.
Subsequent Event
In January 2006, the Company acquired oil and gas properties in
the Bossier trend of east Texas for approximately
$381 million, net of purchase price adjustments. The
acquisition was funded in part with the remaining proceeds of
$64 million from the Units sale.
67
January 16, 2006
Burlington Resources Inc.
717 Texas Avenue, Suite 2100
Houston, TX 77002
Re: Proved Reserves as of December 31, 2005
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, 2005. 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
|
|
|
435.9 |
|
|
|
152.9 |
|
|
|
588.8 |
|
Gas, Billions of Cubic Feet
|
|
|
4,150.2 |
|
|
|
1,818.6 |
|
|
|
5,968.8 |
|
|
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 82 percent of BRs estimated
proved reserves forecasts and either accepted its forecast or
revised them 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, 2005, and are in accordance with Securities
and Exchange Commission guidelines.
68
|
|
Burlington Resources Inc. |
January 16, 2006 |
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.
|
|
|
|
|
|
|
Robert J. Oberst
|
|
Senior Vice President |
|
|
|
|
|
|
R.W. Frazier |
|
Senior Vice President |
RJO/sg
69
Ref.: 1408.15626
January 11, 2006
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,
2005 |
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, 2005. 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
|
|
|
13.3 |
|
|
|
2.9 |
|
|
|
16.2 |
|
Natural Gas, Bcf
|
|
|
1,956 |
|
|
|
583 |
|
|
|
2,539 |
|
Natural Gas Liquids, MMbbl
|
|
|
45.1 |
|
|
|
12.6 |
|
|
|
57.7 |
|
|
70
The volumes of natural gas liquids are comprised of ethane,
propane, butanes, condensate and pentanes plus. All volumes are
reported net, after royalties.
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 of 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.
71
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, |
|
|
|
|
Robert N. Johnson, P.Eng. |
|
Manager, Engineering and |
|
Corporate Secretary |
|
|
|
|
Ken H. Crowther, P.Eng |
|
President |
72
BURLINGTON RESOURCES INC.
SUPPLEMENTARY FINANCIAL INFORMATION
Supplemental Oil and Gas Disclosures Unaudited
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, 2005 |
|
U.S. |
|
Canada |
|
International |
|
Total |
|
|
|
(In Millions) |
|
Property acquisition
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved
|
|
$ |
294 |
|
|
$ |
34 |
|
|
$ |
|
|
|
$ |
328 |
|
|
Unproved
|
|
|
56 |
|
|
|
47 |
|
|
|
|
|
|
|
103 |
|
Exploration
|
|
|
133 |
|
|
|
199 |
|
|
|
32 |
|
|
|
364 |
|
Development
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved developed
|
|
|
570 |
|
|
|
722 |
|
|
|
60 |
|
|
|
1,352 |
|
|
Proved undeveloped
|
|
|
225 |
|
|
|
175 |
|
|
|
67 |
|
|
|
467 |
|
|
Costs incurred before estimated
asset retirement obligations
|
|
|
1,278 |
|
|
|
1,177 |
|
|
|
159 |
|
|
|
2,614 |
|
Estimated asset retirement
obligations incurred(1)
|
|
|
50 |
|
|
|
53 |
|
|
|
20 |
|
|
|
123 |
|
|
|
|
Total costs incurred
|
|
$ |
1,328 |
|
|
$ |
1,230 |
|
|
$ |
179 |
|
|
$ |
2,737 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 |
|
|
|
|
(1) |
Amounts are shown net of current year estimated cash flow
revisions. |
The Company estimates that it will spend capital of
approximately $1,015 million, $870 million and
$621 million in 2006, 2007 and 2008, respectively, for the
development of its proved undeveloped reserves.
73
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 2005, 2004 and 2003.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
North America |
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2005 |
|
U.S. |
|
Canada |
|
International |
|
Total |
|
|
|
(In Millions) |
|
Revenues
|
|
$ |
3,870 |
|
|
$ |
2,686 |
|
|
$ |
987 |
|
|
$ |
7,543 |
|
|
Production costs
|
|
|
539 |
|
|
|
215 |
|
|
|
114 |
|
|
|
868 |
|
Exploration costs
|
|
|
75 |
|
|
|
186 |
|
|
|
32 |
|
|
|
293 |
|
Operating expenses
|
|
|
316 |
|
|
|
243 |
|
|
|
120 |
|
|
|
679 |
|
Depreciation, depletion and
amortization
|
|
|
417 |
|
|
|
621 |
|
|
|
199 |
|
|
|
1,237 |
|
Impairment of oil and gas properties
|
|
|
|
|
|
|
|
|
|
|
50 |
|
|
|
50 |
|
Income tax provision
|
|
|
936 |
|
|
|
544 |
|
|
|
155 |
|
|
|
1,635 |
|
|
Results of operations for oil and
gas producing activities
|
|
$ |
1,587 |
|
|
$ |
877 |
|
|
$ |
317 |
|
|
$ |
2,781 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 |
|
|
74
(This page intentionally left blank)
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, 2005. 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, 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 |
|
|
Revisions of previous estimates
|
|
|
(7.2 |
) |
|
|
(1.5 |
) |
|
|
(3.5 |
) |
|
|
(12.2 |
) |
|
Extensions, discoveries and other
additions
|
|
|
8.7 |
|
|
|
2.0 |
|
|
|
14.2 |
|
|
|
24.9 |
|
|
Production
|
|
|
(18.0 |
) |
|
|
(2.2 |
) |
|
|
(13.8 |
) |
|
|
(34.0 |
) |
|
Purchase of reserves in place
|
|
|
0.7 |
|
|
|
|
|
|
|
|
|
|
|
0.7 |
|
|
Sales of reserves in place
|
|
|
(2.9 |
) |
|
|
|
|
|
|
|
|
|
|
(2.9 |
) |
|
December 31, 2005
|
|
|
185.8 |
|
|
|
16.2 |
|
|
|
72.2 |
|
|
|
274.2 |
|
|
Proved Developed Reserves
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 |
|
|
December 31, 2005
|
|
|
172.0 |
|
|
|
13.3 |
|
|
|
42.5 |
|
|
|
227.8 |
|
|
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) |
|
|
|
|
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 |
|
|
|
|
39.4 |
|
|
|
1.0 |
|
|
|
40.4 |
|
|
|
(88 |
) |
|
|
34 |
|
|
|
(74 |
) |
|
|
(128 |
) |
|
|
42 |
|
|
|
|
27.8 |
|
|
|
11.3 |
|
|
|
39.1 |
|
|
|
522 |
|
|
|
465 |
|
|
|
3 |
|
|
|
990 |
|
|
|
1,374 |
|
|
|
|
(15.5 |
) |
|
|
(8.8 |
) |
|
|
(24.3 |
) |
|
|
(347 |
) |
|
|
(293 |
) |
|
|
(55 |
) |
|
|
(695 |
) |
|
|
(1,045 |
) |
|
|
|
1.8 |
|
|
|
0.2 |
|
|
|
2.0 |
|
|
|
120 |
|
|
|
6 |
|
|
|
|
|
|
|
126 |
|
|
|
142 |
|
|
|
|
(1.1 |
) |
|
|
(0.1 |
) |
|
|
(1.2 |
) |
|
|
(8 |
) |
|
|
(3 |
) |
|
|
|
|
|
|
(11 |
) |
|
|
(36 |
) |
|
|
|
|
|
|
330.8 |
|
|
|
57.7 |
|
|
|
388.5 |
|
|
|
5,275 |
|
|
|
2,539 |
|
|
|
694 |
|
|
|
8,508 |
|
|
|
12,484 |
|
|
|
|
|
|
|
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 |
|
|
|
|
221.4 |
|
|
|
45.1 |
|
|
|
266.5 |
|
|
|
3,752 |
|
|
|
1,956 |
|
|
|
398 |
|
|
|
6,106 |
|
|
|
9,072 |
|
|
|
|
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 |
|
|
|
|
|
|
|
|
|
|
|
2005 |
|
U.S. |
|
Canada |
|
International |
|
Total |
|
|
|
(In Millions) |
|
Future cash inflows
|
|
$ |
56,061 |
|
|
$ |
25,560 |
|
|
$ |
8,741 |
|
|
$ |
90,362 |
|
|
Less related future
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production costs(1)
|
|
|
11,590 |
|
|
|
4,156 |
|
|
|
1,099 |
|
|
|
16,845 |
|
|
|
Development costs
|
|
|
2,367 |
|
|
|
1,710 |
|
|
|
502 |
|
|
|
4,579 |
|
|
|
Income taxes
|
|
|
14,703 |
|
|
|
6,016 |
|
|
|
2,881 |
|
|
|
23,600 |
|
|
Future net cash flows
|
|
|
27,401 |
|
|
|
13,678 |
|
|
|
4,259 |
|
|
|
45,338 |
|
10% annual discount for estimated
timing of cash flows
|
|
|
14,849 |
|
|
|
5,542 |
|
|
|
1,390 |
|
|
|
21,781 |
|
|
Standardized measure of discounted
future net cash flows
|
|
$ |
12,552 |
|
|
$ |
8,136 |
|
|
$ |
2,869 |
|
|
$ |
23,557 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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(1)
|
|
|
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(1)
|
|
|
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 |
|
|
|
|
(1) |
Include lease operating expenses, severance taxes, ad valorem
taxes and estimated asset retirement costs, net of estimated
salvage recoveries. |
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.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2005 |
|
2004 |
|
2003 |
|
|
|
(In Millions) |
|
January 1,
|
|
$ |
15,218 |
|
|
$ |
15,177 |
|
|
$ |
10,414 |
|
|
Revisions of previous estimates
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Changes in prices and costs
|
|
|
11,505 |
|
|
|
606 |
|
|
|
6,050 |
|
|
Changes in quantities
|
|
|
168 |
|
|
|
173 |
|
|
|
(111 |
) |
Additions to proved reserves
resulting from extensions, discoveries and improved recovery,
less related costs
|
|
|
3,555 |
|
|
|
1,978 |
|
|
|
2,119 |
|
Purchases of reserves in place
|
|
|
375 |
|
|
|
126 |
|
|
|
416 |
|
Sales of reserves in place
|
|
|
(70 |
) |
|
|
(10 |
) |
|
|
(86 |
) |
Accretion of discount
|
|
|
2,209 |
|
|
|
2,165 |
|
|
|
1,472 |
|
Sales, net of production costs
|
|
|
(6,675 |
) |
|
|
(4,880 |
) |
|
|
(3,739 |
) |
Net change in income taxes
|
|
|
(4,617 |
) |
|
|
(401 |
) |
|
|
(2,163 |
) |
Changes in rate of production and
other
|
|
|
1,889 |
|
|
|
284 |
|
|
|
805 |
|
|
Net change
|
|
|
8,339 |
|
|
|
41 |
|
|
|
4,763 |
|
|
December 31,
|
|
$ |
23,557 |
|
|
$ |
15,218 |
|
|
$ |
15,177 |
|
|
Quarterly Financial DataUnaudited
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2005 |
|
2004 |
|
|
|
4th |
|
3rd |
|
2nd |
|
1st |
|
4th |
|
3rd |
|
2nd |
|
1st |
|
|
|
(In Millions, Except per Share Amounts) |
|
Revenues
|
|
$ |
2,372 |
|
|
$ |
1,953 |
|
|
$ |
1,686 |
|
|
$ |
1,576 |
|
|
$ |
1,558 |
|
|
$ |
1,419 |
|
|
$ |
1,333 |
|
|
$ |
1,308 |
|
Income before income taxes(a)
|
|
|
1,385 |
|
|
|
1,119 |
|
|
|
805 |
|
|
|
739 |
|
|
|
588 |
|
|
|
629 |
|
|
|
540 |
|
|
|
547 |
|
Net income(b)
|
|
|
954 |
|
|
|
748 |
|
|
|
537 |
|
|
|
471 |
|
|
|
400 |
|
|
|
394 |
|
|
|
379 |
|
|
|
354 |
|
Basic earnings per common
share(a)(b)
|
|
|
2.54 |
|
|
|
1.98 |
|
|
|
1.41 |
|
|
|
1.22 |
|
|
|
1.03 |
|
|
|
1.00 |
|
|
|
0.96 |
|
|
|
0.90 |
|
Diluted earnings per common(a)(b)
|
|
|
2.52 |
|
|
|
1.96 |
|
|
|
1.40 |
|
|
|
1.21 |
|
|
|
1.02 |
|
|
|
1.00 |
|
|
|
0.96 |
|
|
|
0.89 |
|
Cash dividends declared per common
share
|
|
|
0.10 |
|
|
|
0.10 |
|
|
|
0.09 |
|
|
|
0.08 |
|
|
|
0.08 |
|
|
|
0.09 |
|
|
|
0.07 |
|
|
|
0.08 |
|
Common stock price range
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
High
|
|
|
87.03 |
|
|
|
81.98 |
|
|
|
57.18 |
|
|
|
53.32 |
|
|
|
46.41 |
|
|
|
41.24 |
|
|
|
37.49 |
|
|
|
31.98 |
|
|
Low
|
|
$ |
64.02 |
|
|
$ |
55.57 |
|
|
$ |
44.72 |
|
|
$ |
40.40 |
|
|
$ |
39.19 |
|
|
$ |
34.92 |
|
|
$ |
31.23 |
|
|
$ |
26.33 |
|
|
|
|
|
(a) |
|
During the third quarter of 2005, the Company recorded a pretax
gain of $117 million ($73 million after tax or
$0.19 per diluted share) related to the sale of
8,350,000 units of beneficial interest in the Permian Basin
Royalty Trust (Units) held by the Company. During
the fourth quarter of 2005, the Company also recorded a pretax
gain of $123 million ($76 million after tax or
$0.20 per diluted share) related to the sale of 8,600,000
Units held by the Company. During the fourth quarters of 2005
and 2004, the Company recognized non-cash, pretax charges of
$50 million ($34 million after tax or $0.09 per
diluted share) and $90 million ($59 million after tax
or $0.15 per diluted share), respectively, related to the
impairment of oil and gas properties. |
|
(b) |
|
The fourth quarter of 2004 includes a U.S. income tax
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. |
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
Information required by Part III, items ten and eleven,
will either be included in the Companys definitive proxy
statement (the Proxy Statement) filed with the
Securities and Exchange Commission or filed as an amendment to
this Form 10-K no
later than 120 days after the end of the Companys
fiscal year, to the extent required by the Securities Exchange
Act of 1934, as amended. 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.
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
80
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
Information required by Part III, item twelve, will either
be included in the Proxy Statement filed with the Securities and
Exchange Commission or filed as an amendment to this
Form 10-K no later
than 120 days after the end of the Companys fiscal
year, to the extent required by the Securities Exchange Act of
1934, as amended.
EQUITY COMPENSATION PLAN INFORMATION
At December 31, 2005
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Number of Securities |
|
|
Number of Securities |
|
|
|
Remaining Available for |
|
|
to be Issued |
|
Weighted-Average |
|
Future Issuance Under |
|
|
Upon Exercise of |
|
Exercise Price of |
|
Equity Compensation Plans |
|
|
Outstanding Options, |
|
Outstanding Options, |
|
(Excluding Securities |
|
|
Warrants and Rights(2) |
|
Warrants and Rights(2) |
|
Reflected in Column(a)) |
Plan Category |
|
(a) |
|
(b) |
|
(c) |
|
Equity compensation plans approved
by security holders
|
|
|
3,428,730 |
|
|
$ |
30.68 |
|
|
|
9,263,370 |
|
Equity compensation plan not
approved by security holders(1)
|
|
|
826,538 |
|
|
|
21.34 |
|
|
|
8,120,843 |
|
|
|
Total
|
|
|
4,255,268 |
|
|
$ |
28.87 |
|
|
|
17,384,213 |
|
|
|
|
(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. |
ITEM THIRTEEN
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Information required by Part III, item thirteen, will
either be included in the Proxy Statement filed with the
Securities and Exchange Commission or filed as an amendment to
this Form 10-K no
later than 120 days after the end of the Companys
fiscal year, to the extent required by the Securities Exchange
Act of 1934, as amended.
ITEM FOURTEEN
PRINCIPAL ACCOUNTANT FEES AND SERVICES
Information required by Part III, item fourteen, will
either be included in the Proxy Statement filed with the
Securities and Exchange Commission or filed as an amendment to
this Form 10-K no
later than 120 days after the end of the Companys
fiscal year, to the extent required by the Securities Exchange
Act of 1934, as amended.
81
PART IV
ITEM FIFTEEN
EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
|
|
|
|
|
|
|
|
Page |
|
Financial Statements and
Supplementary Financial Information
|
|
|
|
|
|
Consolidated Statement of Income
|
|
|
40 |
|
|
Consolidated Balance Sheet
|
|
|
41 |
|
|
Consolidated Statement of Cash Flows
|
|
|
42 |
|
|
Consolidated Statement of
Stockholders Equity
|
|
|
43 |
|
|
Notes to Consolidated Financial
Statements
|
|
|
44 |
|
|
Reports of Independent Oil and Gas
Consultants
|
|
|
68 |
|
|
Supplemental Oil and Gas
DisclosuresUnaudited
|
|
|
73 |
|
|
Quarterly Financial
DataUnaudited
|
|
|
79 |
|
Amended
Exhibit Index
|
|
|
84 |
|
|
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, 2006
|
|
/s/
STEVEN J. SHAPIRO
Steven
J. Shapiro
|
|
Director, Executive Vice President
Finance
and Corporate Development
|
|
February 28, 2006
|
|
/s/
JOSEPH P. MCCOY
Joseph
P. McCoy
|
|
Senior Vice President
and Chief Financial Officer
|
|
February 28, 2006
|
|
/s/
DANE E. WHITEHEAD
Dane
E. Whitehead
|
|
Vice President, Controller
and Chief Accounting Officer
|
|
February 28, 2006
|
|
/s/
BARBARA T. ALEXANDER
Barbara
T. Alexander
|
|
Director
|
|
February 28, 2006
|
|
/s/
REUBEN V. ANDERSON
Reuben
V. Anderson
|
|
Director
|
|
February 28, 2006
|
|
/s/
LAIRD I. GRANT
Laird
I. Grant
|
|
Director
|
|
February 28, 2006
|
|
/s/
ROBERT J. HARDING
Robert
J. Harding
|
|
Director
|
|
February 28, 2006
|
|
/s/
JOHN T. LAMACCHIA
John
T. LaMacchia
|
|
Director
|
|
February 28, 2006
|
|
/s/
RANDY L. LIMBACHER
Randy
L. Limbacher
|
|
Director
|
|
February 28, 2006
|
|
/s/
JAMES F. MCDONALD
James
F. McDonald
|
|
Director
|
|
February 28, 2006
|
|
/s/
KENNETH W. ORCE
Kenneth
W. Orce
|
|
Director
|
|
February 28, 2006
|
|
/s/
DONALD M. ROBERTS
Donald
M. Roberts
|
|
Director
|
|
February 28, 2006
|
|
/s/
JAMES A. RUNDE
James
A. Runde
|
|
Director
|
|
February 28, 2006
|
|
/s/
JOHN F. SCHWARZ
John
F. Schwarz
|
|
Director
|
|
February 28, 2006
|
|
/s/
WALTER SCOTT, JR.
Walter
Scott, Jr.
|
|
Director
|
|
February 28, 2006
|
|
/s/
WILLIAM E.
WADE, JR.
William
E. Wade, Jr.
|
|
Director
|
|
February 28, 2006
|
83
BURLINGTON RESOURCES INC.
AMENDED EXHIBIT INDEX
The following exhibits are filed as part of this report.
|
|
|
|
|
|
|
|
|
Exhibit |
|
|
|
|
Number |
|
Description |
|
|
|
|
2.1 |
|
|
Agreement and Plan of Merger, dated
as of December 12, 2005, by and among ConocoPhillips, Cello
Acquisition Corp. and Burlington Resources Inc.
(Exhibit 2.1 to Form 8-K filed December 14, 2005)
|
|
|
* |
|
|
|
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 10.2 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
(Exhibit 10.1 to Form 10-K filed February 28,
2005)
|
|
|
* |
|
|
|
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
(Exhibit 10.1 to Form 10-K filed February 28,
2005)
|
|
|
* |
|
84
|
|
|
|
|
|
|
|
|
Exhibit |
|
|
|
|
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
(Exhibit 10.1 to Form 10-K filed February 28,
2005)
|
|
|
* |
|
|
|
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 (Exhibit 10.1 to Form 10-K
filed February 28, 2005)
|
|
|
* |
|
|
|
|
|
|
Amendment No. 1, dated
December 19, 2005, to Burlington Resources Inc.
Compensation Plan for Non-Employee Directors
|
|
|
|
|
|
|
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)
|
|
|
* |
|
|
|
|
|
|
First Amendment, effective
August 17, 2005, to the $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 8-K filed
August 22, 2005)
|
|
|
* |
|
|
|
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 (Exhibit 10.1 to Form 10-K
filed February 28, 2005)
|
|
|
* |
|
|
|
|
|
|
Amendment No. 2, dated
December 19, 2005, to Burlington Resources Inc. Phantom
Stock Plan for Non-Employee Directors
|
|
|
|
|
|
|
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 10.3 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 (Exhibit 10.1 to Form 10-K filed
February 28, 2005)
|
|
|
* |
|
|
|
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
(Exhibit 10.1 to Form 10-K Filed February 28,
2005)
|
|
|
* |
|
|
|
|
|
|
Amendment No. 3, dated
December 19, 2005, to Burlington Resources Inc. 2002 Stock
Incentive Plan
|
|
|
|
|
|
|
|
|
|
Amendment No. 4, dated
January 25, 2006, to Burlington Resources Inc. 2002 Stock
Incentive Plan
|
|
|
|
|
86
|
|
|
|
|
|
|
|
|
Exhibit |
|
|
|
|
Number |
|
Description |
|
|
|
|
10.28 |
|
|
Burlington Resources Inc. 1997
Employee Stock Incentive Plan (Exhibit 10.33 to
Form 10-K filed March 12, 2003)
|
|
|
* |
|
|
|
|
|
|
Amendment, dated December 2003, to
Burlington Resources Inc. 1997 Employee Stock Incentive Plan
(Exhibit 10.30 to Form 10-K, filed February 26,
2004)
|
|
|
* |
|
|
|
|
|
|
Amendment No. 4, effective
July 28, 2005 to Burlington Resources Inc. 1997 Employee
Stock Incentive Plan (Exhibit 10.1 to Form 10-Q, filed
August 3, 2005)
|
|
|
* |
|
|
|
|
|
|
Amendment No. 5, dated
December 19, 2005, to Burlington Resources Inc. 1997
Employee Stock Incentive Plan
|
|
|
|
|
|
|
|
|
|
Amendment No. 6, dated
January 25, 2006, to Burlington Resources Inc. 1997
Employee Stock Incentive Plan
|
|
|
|
|
|
|
10.29 |
|
|
Form of stock option grant letter
under the Burlington Resources Inc. 2002 Stock Incentive Plan
(Exhibit 10.1 to Form 8-K filed January 31, 2006)
|
|
|
* |
|
|
|
10.30 |
|
|
Form of restricted stock grant
letter under the Burlington Resources Inc. 2002 Stock Incentive
Plan (Exhibit 10.2 to Form 8-K filed January 31,
2006)
|
|
|
* |
|
|
|
10.31 |
|
|
Burlington Resources Inc. 2005
Performance Share Unit Plan (Exhibit 10.2 to Form 8-K
filed January 31, 2005)
|
|
|
* |
|
|
|
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
(Exhibit 10.33 to Form 10-K filed February 28,
2005)
|
|
|
* |
|
|
|
10.34 |
|
|
Summary of the Compensation of
Non-Employee Directors of Burlington Resources Inc.
(Exhibit 10.34 to Form 10-K filed February 28,
2005)
|
|
|
* |
|
|
|
10.35 |
|
|
Letter Agreement, dated as of
December 12, 2005 among Burlington Resources Inc.,
ConocoPhillips, and Bobby S. Shackouls (Exhibit 10.33 to
ConocoPhillips Form S-4 filed January 11, 2006)
|
|
|
* |
|
|
|
21.1 |
|
|
Subsidiaries of the Registrant
|
|
|
|
|
|
|
23.1 |
|
|
Consent of Independent Registered
Public Accounting FirmPricewaterhouseCoopers LLP
|
|
|
|
|
|
|
23.2 |
|
|
Consent of Independent Oil and Gas
ConsultantMiller and Lents, Ltd.
|
|
|
|
|
|
|
23.3 |
|
|
Consent of Independent Oil and Gas
ConsultantSproule 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 Joseph P. McCoy, Senior 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