UNITED
STATES
SECURITIES
AND EXCHANGE COMMISSION
Washington,
D.C. 20549
FORM
10-Q
|
þ
|
QUARTERLY
REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
ACT OF
1934
|
For
the quarterly period ended September 30, 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.
(Exact
name of registrant as specified in its charter)
|
Delaware
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91-1413284
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(State
or other jurisdiction of
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(I.R.S.
Employer
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incorporation
or organization)
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Identification
Number)
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717
Texas Ave., Suite 2100, Houston, Texas
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77002
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(Address
of principal executive offices)
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(Zip
Code)
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Registrant's
telephone number, including area code
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(713)
624-9000
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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.
Indicate
by check mark whether the registrant is an accelerated filer (as defined
in Rule
12b-2 of the Exchange Act).
Indicate
by check mark whether the registrant is a shell company (as defined in Rule
12b-2 of the Exchange Act).
Indicate
the number of shares outstanding of each of the issuer's classes of common
stock, as of the latest practicable date.
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Class
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Outstanding
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Common
Stock, par value $.01 per share,
|
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as
of September 30, 2005
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378,037,355
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PART
I — FINANCIAL INFORMATION
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PART
II — OTHER INFORMATION
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PART
I - FINANCIAL INFORMATION
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BURLINGTON
RESOURCES INC.
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CONSOLIDATED
STATEMENT OF INCOME
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(UNAUDITED)
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Third
Quarter
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Nine
Months
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2005
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2004
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2005
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2004
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(In
Millions, Except per Share Amounts)
|
|
|
|
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|
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Revenues
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$
|
1,953
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$
|
1,419
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$
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5,215
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|
$
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4,060
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|
|
|
|
|
|
|
|
|
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Costs
and Other Income - Net
|
|
|
|
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|
|
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Taxes
Other than Income Taxes
|
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94
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67
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250
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188
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Transportation
Expense
|
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127
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112
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364
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|
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329
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Operating
Costs
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176
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152
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490
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426
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Depreciation,
Depletion and Amortization
|
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325
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284
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975
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831
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Exploration
Costs
|
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65
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55
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183
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177
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Administrative
|
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76
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54
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176
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153
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Interest
Expense
|
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70
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71
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210
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211
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(Gain)/Loss
on Disposal of Assets
|
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(117
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)
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-
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(117
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)
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10
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Other
Expense (Income) - Net
|
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18
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|
|
(5
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)
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21
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|
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19
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Total
Costs and Other Income - Net
|
|
|
834
|
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|
790
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2,552
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2,344
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Income
Before Income Taxes
|
|
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1,119
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629
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2,663
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1,716
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Income
Tax Expense
|
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371
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|
|
235
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907
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589
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|
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Net
Income
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|
$
|
748
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$
|
394
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$
|
1,756
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|
$
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1,127
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|
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|
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Basic
Earnings per Common Share
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$
|
1.98
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$
|
1.00
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$
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4.60
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$
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2.87
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|
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|
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Diluted
Earnings per Common Share
|
|
$
|
1.96
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$
|
1.00
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$
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4.56
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$
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2.84
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|
|
|
|
|
|
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See
accompanying Notes to Consolidated Financial
Statements.
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BURLINGTON RESOURCES INC.
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CONSOLIDATED
BALANCE SHEET
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(UNAUDITED)
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September
30,
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December
31,
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2005
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2004
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(In
Millions, Except Share Data)
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ASSETS
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Current
Assets
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Cash
and Cash Equivalents
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$
|
2,816
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$
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2,179
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Accounts
Receivable
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1,292
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|
994
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Inventories
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159
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124
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Other
Current Assets
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309
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158
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4,576
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3,455
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Oil
& Gas Properties (Successful Efforts Method)
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19,939
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17,943
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Other
Properties
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1,616
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1,544
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21,555
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19,487
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Accumulated
Depreciation, Depletion and Amortization
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9,605
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8,454
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Properties
- Net
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11,950
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11,033
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Goodwill
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1,093
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1,054
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Other
Assets
|
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239
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|
|
202
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Total
Assets
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$
|
17,858
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$
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15,744
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LIABILITIES
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Current
Liabilities
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Accounts
Payable
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$
|
1,274
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$
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1,182
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Taxes
Payable
|
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|
303
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|
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216
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Accrued
Interest
|
|
|
56
|
|
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61
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Dividends
Payable
|
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38
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33
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Deferred
Income Taxes
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-
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48
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Commodity
Hedging Contracts and Other Derivatives
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433
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27
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Other
Current Liabilities
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12
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32
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2,116
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1,599
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Long-term
Debt
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3,893
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3,887
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Deferred
Income Taxes
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2,861
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2,396
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Other
Liabilities and Deferred Credits
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|
957
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851
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Commitments
and Contingencies (Note 5)
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STOCKHOLDERS'
EQUITY
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Preferred
Stock, Par Value $01 Per Share
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(Authorized
75,000,000 Shares; No Shares Issued)
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-
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-
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Common
Stock, Par Value $01 Per Share
|
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(Authorized
650,000,000 Shares; Issued 482,376,870 Shares)
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5
|
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5
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Paid-in
Capital
|
|
|
3,996
|
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|
3,973
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Retained
Earnings
|
|
|
5,816
|
|
|
4,163
|
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Deferred
Compensation - Restricted Stock
|
|
|
(19
|
)
|
|
(14
|
)
|
Accumulated
Other Comprehensive Income
|
|
|
1,057
|
|
|
1,092
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|
Cost
of Treasury Stock
|
|
|
|
|
|
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|
(104,339,515
and 94,435,401 Shares for 2005 and 2004, respectively)
|
|
|
(2,824
|
)
|
|
(2,208
|
)
|
Stockholders'
Equity
|
|
|
8,031
|
|
|
7,011
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Total
Liabilities and Stockholders' Equity
|
|
$
|
17,858
|
|
$
|
15,744
|
|
|
See
accompanying Notes to Consolidated Financial
Statements.
|
BURLINGTON
RESOURCES INC.
|
|
CONSOLIDATED
STATEMENT OF CASH FLOWS
|
|
(UNAUDITED)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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|
Nine
Months
|
|
|
|
2005
|
|
2004
|
|
|
|
(In
Millions)
|
|
|
|
|
|
|
|
CASH
FLOWS FROM OPERATING ACTIVITIES
|
|
|
|
|
|
Net
Income
|
|
$
|
1,756
|
|
$
|
1,127
|
|
Adjustments
to Reconcile Net Income to Net Cash
|
|
|
|
|
|
|
|
Provided
By Operating Activities
|
|
|
|
|
|
|
|
Depreciation,
Depletion and Amortization
|
|
|
975
|
|
|
831
|
|
Deferred
Income Taxes
|
|
|
342
|
|
|
353
|
|
Exploration
Costs
|
|
|
183
|
|
|
177
|
|
(Gain)/Loss
on Disposal of Assets
|
|
|
(117
|
)
|
|
10
|
|
Changes
in Derivative Fair Values
|
|
|
(4
|
)
|
|
(2
|
)
|
Working
Capital Changes
|
|
|
|
|
|
|
|
Accounts
Receivable
|
|
|
(282
|
)
|
|
(258
|
)
|
Inventories
|
|
|
(30
|
)
|
|
(30
|
)
|
Other
Current Assets
|
|
|
(27
|
)
|
|
(25
|
)
|
Accounts
Payable
|
|
|
69
|
|
|
168
|
|
Taxes
Payable
|
|
|
106
|
|
|
127
|
|
Accrued
Interest
|
|
|
(5
|
)
|
|
2
|
|
Other
Current Liabilities
|
|
|
(19
|
)
|
|
7
|
|
Changes
in Other Assets and Liabilities
|
|
|
16
|
|
|
(13
|
)
|
Net
Cash Provided By Operating Activities
|
|
|
2,963
|
|
|
2,474
|
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM INVESTING ACTIVITIES
|
|
|
|
|
|
|
|
Additions
to Properties
|
|
|
(1,833
|
)
|
|
(1,200
|
)
|
Proceeds
from Sales and Other
|
|
|
149
|
|
|
(25
|
)
|
Net
Cash Used In Investing Activities
|
|
|
(1,684
|
)
|
|
(1,225
|
)
|
|
|
|
|
|
|
|
|
CASH
FLOWS FROM FINANCING ACTIVITIES
|
|
|
|
|
|
|
|
Proceeds
from Long-term Debt
|
|
|
-
|
|
|
41
|
|
Reduction
in Long-term Debt
|
|
|
(1
|
)
|
|
(2
|
)
|
Dividends
Paid
|
|
|
(98
|
)
|
|
(89
|
)
|
Common
Stock Purchases
|
|
|
(691
|
)
|
|
(342
|
)
|
Common
Stock Issuances
|
|
|
58
|
|
|
139
|
|
Net
Cash Used In Financing Activities
|
|
|
(732
|
)
|
|
(253
|
)
|
|
|
|
|
|
|
|
|
Effect
of Exchange Rate Changes on Cash and Cash Equivalents
|
|
|
90
|
|
|
37
|
|
|
|
|
|
|
|
|
|
Increase
in Cash and Cash Equivalents
|
|
|
637
|
|
|
1,033
|
|
|
|
|
|
|
|
|
|
Cash
and Cash Equivalents
|
|
|
|
|
|
|
|
Beginning
of Year
|
|
|
2,179
|
|
|
757
|
|
End
of Period
|
|
$
|
2,816
|
|
$
|
1,790
|
|
|
See
accompanying Notes to Consolidated Financial
Statements.
|
BURLINGTON
RESOURCES INC.
NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
The
2004
Annual Report on Form 10-K (“Form 10-K”) of Burlington Resources Inc. (the
“Company”) includes certain definitions and a summary of significant accounting
policies and should be read in conjunction with this Quarterly Report on
Form
10-Q (“Quarterly Report”). The financial statements for the periods presented
herein are unaudited and do not contain all information required by generally
accepted accounting principles to be included in a full set of financial
statements. In the opinion of management, all material adjustments necessary
to
present fairly the results of operations have been included. All such
adjustments are of a normal, recurring nature. The results of operations
for any
interim period are not necessarily indicative of the results of operations
for
the entire year. The consolidated financial statements include certain
reclassifications that were made to conform to current period presentation.
Basic
earnings per common share (“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 378 million and 392 million for the third quarter
of
2005 and 2004, respectively, and 382 million and 393 million for the first
nine
months of 2005 and 2004, respectively. Diluted EPS reflects the potential
dilution that could occur if securities or other contracts to issue common
stock
were exercised or converted into common stock. The weighted average number
of
common shares outstanding for computing diluted EPS, including dilutive stock
options, was 381 million and 395 million for the third quarter of 2005 and
2004,
respectively, and 385 million and 396 million for the first nine months of
2005
and 2004, respectively.
For
the
quarter ended September 30, 2005 and 2004, all shares attributable to
outstanding options were dilutive. For the nine months ended September 30,
2005
and 2004, approximately 3 thousand and zero shares, respectively, attributable
to the potential exercise of outstanding options were excluded from the
calculation of diluted EPS because the effect was antidilutive. The Company
has
no convertible securities affecting EPS, therefore, no adjustments related
to
convertible securities were made to reported net income in the computation
of
EPS.
2.
|
STOCK-BASED
COMPENSATION
|
The
Company uses the intrinsic value based method of accounting for stock-based
compensation, as prescribed by Accounting Principles Board Opinion No. 25,
Accounting
for Stock Issued to Employees,
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 Company's Common Stock on the date
of the
grant.
The
following table illustrates the effect on net income and EPS if the Company
had
applied the fair value recognition provisions of Statement of Financial
Accounting Standards (“SFAS”) No. 123, Accounting
for Stock-Based Compensation,
as
amended by SFAS No. 148, to stock-based employee compensation. The fair value
of
stock options included in the pro forma amounts is not necessarily indicative
of
future effects on net income and EPS.
|
|
Third
Quarter
|
|
Nine
Months
|
|
|
|
2005
|
|
2004
|
|
2005
|
|
2004
|
|
|
|
(In
Millions, except per Share Amounts)
|
|
Net
income as reported
|
|
$
|
748
|
|
$
|
394
|
|
$
|
1,756
|
|
$
|
1,127
|
|
Less:
Pro forma stock-based employee compensation cost, after
tax
|
|
|
(1
|
)
|
|
(3
|
)
|
|
(4
|
)
|
|
(9
|
)
|
Net
income - pro forma
|
|
$
|
747
|
|
$
|
391
|
|
$
|
1,752
|
|
$
|
1,118
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
EPS - as reported
|
|
$
|
1.98
|
|
$
|
1.00
|
|
$
|
4.60
|
|
$
|
2.87
|
|
Basic
EPS - pro forma
|
|
|
1.98
|
|
|
1.00
|
|
|
4.59
|
|
|
2.84
|
|
Diluted
EPS - as reported
|
|
|
1.96
|
|
|
1.00
|
|
|
4.56
|
|
|
2.84
|
|
Diluted
EPS - pro forma
|
|
$
|
1.96
|
|
$
|
0.99
|
|
$
|
4.55
|
|
$
|
2.82
|
|
|
|
Nine
Months
|
|
|
|
2005
|
|
2004
|
|
|
|
(In
Millions)
|
|
Accumulated
other comprehensive income - beginning of period
|
|
|
|
$ 1,092
|
|
|
|
$ 655
|
|
|
|
|
|
|
|
|
|
|
|
Net
income
|
|
$
|
1,756
|
|
|
|
|
$
|
1,127
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
comprehensive income (loss) - net of tax
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Hedging
activities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current
period changes in fair value of settled contracts
|
|
|
(44
|
)
|
|
|
|
|
(1
|
)
|
|
|
|
Reclassification
adjustments for settled contracts
|
|
|
25
|
|
|
|
|
|
14
|
|
|
|
|
Changes
in fair value of outstanding hedging positions
|
|
|
(274
|
)
|
|
|
|
|
(44
|
)
|
|
|
|
Hedging
activities
|
|
|
(293
|
)
|
|
|
|
|
(31
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Foreign
currency translation
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Foreign
currency translation adjustments
|
|
|
258
|
|
|
|
|
|
134
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
other comprehensive income (loss)
|
|
|
(35
|
)
|
|
(35
|
)
|
|
103
|
|
|
103
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Comprehensive
income
|
|
$
|
1,721
|
|
|
|
|
$
|
1,230
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated
other comprehensive income - end of period
|
|
|
|
|
$
|
1,057
|
|
|
|
|
$
|
758
|
|
4.
|
DERIVATIVE
INSTRUMENTS AND HEDGING ACTIVITIES
|
The
Company uses derivative instruments to manage risks associated with natural
gas
and crude oil price volatility as well as interest rates. Derivative instruments
that meet the hedge criteria in SFAS No. 133, Accounting
for Derivative Instruments and Hedging Activities,
as
amended, are designated as either cash-flow hedges or fair-value 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. Derivative instruments
that do not meet the hedge criteria in SFAS No. 133 are not designated as
hedges.
As
of
September 30, 2005, the Company had the following derivative instruments
outstanding with average underlying prices that represent hedged prices of
commodities at various market locations.
|
|
|
|
|
|
Notional
Amount
|
|
Average
|
|
Fair
Value Asset
|
Settlement
Period
|
|
Derivative
Instrument
|
|
Hedge
Strategy
|
|
Gas
(MMBTU)
|
Oil
(Barrels)
|
|
Underlying
Prices
|
|
(Liability)
(In
Millions)
|
2005
|
|
Swap
|
|
Cash
flow
|
|
2,524,647
|
|
|
$
6.89
|
|
$
(9)
|
|
|
Swap
|
|
Not
designated
|
|
1,550,000
|
|
|
(0.11)
|
|
5
|
|
|
Purchased
put |
|
Cash
Flow |
|
41,643,802 |
|
|
6.10 |
|
- |
|
|
Written
call
|
|
Cash
flow
|
|
41,643,802
|
|
|
7.86
|
|
(182)
|
|
|
Purchased
put |
|
Cash
flow |
|
|
1,840,000 |
|
44.16 |
|
- |
|
|
Written
call
|
|
Cash
flow
|
|
|
1,840,000
|
|
56.63
|
|
(20)
|
|
|
Swap
|
|
Fair
value
|
|
303,800
|
|
|
7.15
|
|
1
|
|
|
N/A
|
|
Fair
value (obligation)
|
|
303,800
|
|
|
6.96
|
|
(1)
|
|
|
|
|
|
|
|
|
|
|
|
|
2006
|
|
Swap
|
|
Cash
flow
|
|
5,844,500
|
|
|
7.76
|
|
(21)
|
|
|
Swap
|
|
Fair
value
|
|
295,000
|
|
|
11.47
|
|
-
|
|
|
N/A
|
|
Fair
value (obligation)
|
|
295,000
|
|
|
11.09
|
|
(1)
|
|
|
Purchased
put
|
|
Cash
flow
|
|
60,796,657
|
|
|
7.72
|
|
20
|
|
|
Written
call
|
|
Cash
flow
|
|
60,796,657
|
|
|
9.83
|
|
(202)
|
|
|
Purchased
put
|
|
Cash
flow
|
|
|
3,795,000
|
|
51.81
|
|
7
|
|
|
Written
call
|
|
Cash
flow
|
|
|
3,795,000
|
|
66.41
|
|
(30)
|
|
|
|
|
|
|
|
|
|
|
|
|
2007
|
|
Swap
|
|
Cash
flow
|
|
1,013,000
|
|
|
$
3.83
|
|
(5)
|
|
|
|
|
|
|
|
|
|
|
|
$(438) |
As
of
September 30, 2005, the Company had the following derivative instruments
outstanding related to interest rate swaps.
Settlement
Period
|
|
Derivative
Instrument
|
|
Hedge
Strategy
|
|
|
|
Notional
Amount
(In
Millions)
|
|
|
Average
Underlying
Rate
|
Average
Floating
Rate
|
|
Fair
Value
Liability
(In
Millions)
|
|
2005
|
|
Interest
rate swap
|
|
Fair
value
|
|
|
|
$
50
|
|
|
5.6%
|
LIBOR+3.36%
|
|
$
-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006
|
|
Interest
rate swap
|
|
Fair
value
|
|
|
|
$
50
|
|
|
5.6%
|
LIBOR+3.36%
|
|
(1)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
(1)
|
|
Based on commodity prices as of September 30, 2005, the Company expects to
reclassify losses of $428 million ($265million after tax) to earnings from
the
balance in Accumulated Other Comprehensive Income during the next twelve
months.
At September 30, 2005, the Company had derivative assets of $7 million and
derivative liabilities of $446 million of which $7 million and $13 million
are
included in Other Current Assets and Other Liabilities and Deferred Credits,
respectively, on the Consolidated Balance Sheet.
The
derivative assets and liabilities related to commodities represent the
difference between hedged prices and market prices on hedged volumes of the
commodities as of September 30, 2005. Hedging activities related to cash
settlements on commodities decreased revenues $48 million and $9 million
in
the third quarter of 2005 and 2004, respectively. Hedging activities related
to
cash settlements on commodities decreased revenues $41 million and $23 million
in the first nine months of 2005 and 2004, respectively.
Gains
and
losses related to ineffectiveness and derivative instruments not designated
as
hedging instruments are included in revenues. Losses of $318 thousand
and
$3 million related to ineffectiveness of cash-flow and fair-value hedges
were
recorded during the third quarter and first nine months of 2005, respectively.
Gains of $1 million and $2 million related to ineffectiveness of
cash-flow
and fair-value hedges were recorded during the third quarter and first nine
months of 2004, respectively. Gains of $4 million and $3 million
related
to derivative instruments not designated as hedging instruments were recorded
during the third quarter and first nine months of 2005, respectively, compared
to de minimis amounts during the same periods of 2004.
5.
|
COMMITMENTS
AND CONTINGENCIES
|
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 producer's obligation to place
coal
seam gas in "marketable condition" at no cost to the government when calculating
federal royalty payments. Since some of the intervenor's claims relate to
the
Company's coal seam production in the San Juan Basin and the deductions utilized
by the Company in calculating royalty payments on such production, the Company
is currently analyzing the potential impact of the Amoco ruling on the
intervenor's claims and the Company's 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 Company’s 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 Company’s 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 management’s evaluation of this
matter.
The
Company has also been named as a defendant in the lawsuit styled UNOCAL
Netherlands B.V., et al v. Continental Netherlands Oil Company B.V., et al,
No.
98-854, filed in 1995 in the District Court in The Hague, the Netherlands
and
currently pending in the Supreme Court in The Hague. Plaintiffs, who are
working
interest owners in the Q-1 Block in the North Sea, have alleged that the
Company
and other former working interest owners in the adjacent Logger Field in
the
L16a Block unlawfully trespassed or were otherwise unjustly enriched by
producing part of the oil from the adjoining Q-1 Block. The plaintiffs claim
that the defendants infringed upon plaintiffs’ right to produce the minerals
present in its license area and acted in violation of generally accepted
standards by failing to inform plaintiffs of the overlap of the Logger Field
into the Q-1 Block. Plaintiffs seek damages of $97.8 million as of January
1,
1997, plus interest. For all relevant periods, the Company owned a 37.5 percent
working interest in the Logger Field. Following a trial, the District Court
in
The Hague rendered a judgment in favor of the defendants, including the Company,
dismissing all claims. Plaintiffs thereafter appealed. On October 19, 2000,
the
Court of Appeals in The Hague issued an interim judgment in favor of the
plaintiffs and ordered that additional evidence be presented to the court
relating to issues of both liability and damages. After receiving additional
evidence from the parties, the Court of Appeals subsequently issued a ruling
in
favor of defendants. In an interim judgment issued on December 18, 2003,
the
Court of Appeals found that defendants should not have assumed that they
were
extracting oil from the Q-1 Block, that Unocal was not entitled to compensation
for any production occurring prior to 1992 and that damages, if any, would
be
limited to the proceeds Unocal would have received for oil extracted from
the
Q-1 Block, less the costs Unocal would have incurred to produce the oil from
an
existing well in the L16a Block. The Court of Appeals ordered that further
evidence be presented to a court appointed expert to determine whether any
damages had been suffered by Unocal. Based on the information known to date,
the
Company believes that Unocal suffered no damages in excess of the costs of
production. On October 14, 2005, the Supreme Court in The Hague issued a
ruling
denying all appeals and affirming the ruling by the Court of Appeals. The
Company has also asserted claims of indemnity against two of the defendants
from
whom it had acquired a portion of its working interest share. If the Company
is
successful in enforcing the indemnities, its working interest share of any
adverse judgment could be reduced to 15 percent for some of the periods covered
by plaintiffs’ lawsuit. The Company has not established a reserve for this
matter since it currently does not believe that an unfavorable outcome is
probable.
The
Company and its former affiliate, El Paso Natural Gas Company, have also
been
named as defendants in two class action lawsuits styled Bank of America,
et al.
v. El Paso Natural Gas Company, et al., Case No. CJ-97-68, and Deane W. Moore,
et al. v. Burlington Northern, Inc., et. al., Case No. CJ-97-132, each filed
in
1997 in the District Court of Washita County, State of Oklahoma and subsequently
consolidated by the court. Plaintiffs contend that defendants underpaid
royalties from 1982 to the present on natural gas produced from specified
wells
in Oklahoma through the use of below-market prices, improper deductions and
transactions with affiliated companies and in other instances failed to pay
or
delayed in the payment of royalties on certain gas sold from these wells.
The
plaintiffs seek an accounting and damages for alleged royalty underpayments,
plus interest from the time such amounts were allegedly due. Plaintiffs
additionally seek the recovery of punitive damages. The plaintiffs have not
specified in their pleadings the amount of damages they seek from the Company.
However, through pre-trial discovery, plaintiffs have provided defendants
with
alternative theories of recovery claiming monetary damages of up to $42 million
in principal, plus $311 million in interest, and unspecified punitive damages
and attorney’s fees. The Company believes it has substantial defenses to these
claims and is vigorously asserting such defenses. The Company and El Paso
Natural Gas Company have asserted contractual claims for indemnity against
each
other. The court has certified the plaintiff classes of royalty and overriding
royalty interest owners. The trial of this matter commenced on October 10,
2005.
The Company has established a reserve to provide for this potential liability
based upon management’s evaluation of this matter.
The
Company received notice on October 19, 2004 from the United States Department
of
Justice that it may be one of many potentially responsible parties under
the
Comprehensive Environmental Response, Compensation and Liability Act, as
amended, with respect to the remediation of a site known as the Castex Systems,
Inc. Oil Field Waste Disposal Site in Jefferson Davis Parish near Jennings,
Louisiana. According to the Department of Justice, the remediation of the
site
has been completed under the supervision of the United States Environmental
Protection Agency for a total cost of approximately $3 million. The Company
has
been informed that it may have contributed up to two and one-half percent
(2.5%)
of the liquid oil field waste and twelve percent (12%) of the solid oil field
waste identified at the site. The Company 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 management’s 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
September 30, 2005, the Company’s Consolidated Balance Sheet included reserves
for legal proceedings of $118 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, we
believe that it is remote that future costs related to known contingent
liability exposures for legal proceedings and environmental matters will
exceed
current accruals by an amount that would have a material adverse effect on
the
consolidated financial position or results of operations of the Company,
although cash flow could be significantly impacted in the reporting periods
in
which such costs are incurred.
The
fair
value of the Company’s long-term debt at September 30, 2005 and December 31,
2004 was approximately $4,467 million and $4,528 million, respectively, based
on
quoted market prices.
7.
|
SEGMENT
AND GEOGRAPHIC INFORMATION
|
The
Company’s reportable segments are U.S., Canada and International (“Intl”). The
Company is engaged principally in the exploration for and the development,
production and marketing of natural gas, crude oil, and NGLs. The accounting
policies for the segments are the same as those disclosed in Note 1 of Notes
to
Consolidated Financial Statements included in the Company’s 2004 Form 10-K.
The
following tables present information about the Company’s reportable
segments.
|
|
Third
Quarter
|
|
|
|
2005
|
|
2004
|
|
|
|
U.S.
|
|
Canada
|
|
Intl
|
|
Total
|
|
U.S.
|
|
Canada
|
|
Intl
|
|
Total
|
|
|
|
(In
Millions)
|
|
Revenues
|
|
$
|
1,028
|
|
$
|
688
|
|
$
|
237
|
|
$
|
1,953
|
|
$
|
687
|
|
$
|
510
|
|
$
|
222
|
|
$
|
1,419
|
|
Depreciation,
depletion and amortization
|
|
|
108
|
|
|
166
|
|
|
45
|
|
|
319
|
|
|
92
|
|
|
134
|
|
|
52
|
|
|
278
|
|
Income
before income taxes
|
|
|
801
|
|
|
366
|
|
|
122
|
|
|
1,289
|
|
|
407
|
|
|
233
|
|
|
114
|
|
|
754
|
|
Capital
expenditures
|
|
$
|
472
|
|
$
|
207
|
|
$
|
51
|
|
$
|
730
|
|
$
|
169
|
|
$
|
135
|
|
$
|
55
|
|
$
|
359
|
|
|
|
Nine
Months
|
|
|
|
2005
|
|
2004
|
|
|
|
U.S.
|
|
Canada
|
|
Intl
|
|
Total
|
|
U.S.
|
|
Canada
|
|
Intl
|
|
Total
|
|
|
|
(In
Millions)
|
|
Revenues
|
|
$
|
2,644
|
|
$
|
1,846
|
|
$
|
725
|
|
$
|
5,215
|
|
$
|
1,941
|
|
$
|
1,523
|
|
$
|
596
|
|
$
|
4,060
|
|
Depreciation,
depletion and amortization
|
|
|
324
|
|
|
486
|
|
|
146
|
|
|
956
|
|
|
257
|
|
|
392
|
|
|
163
|
|
|
812
|
|
Income
before income taxes
|
|
|
1,790
|
|
|
917
|
|
|
386
|
|
|
3,093
|
|
|
1,139
|
|
|
710
|
|
|
268
|
|
|
2,117
|
|
Capital
expenditures
|
|
$
|
884
|
|
$
|
808
|
|
$
|
119
|
|
$
|
1,811
|
|
$
|
505
|
|
$
|
593
|
|
$
|
132
|
|
$
|
1,230
|
|
|
|
September
30, 2005
|
|
December
31, 2004
|
|
|
|
U.S.
|
|
Canada
|
|
Intl
|
|
Total
|
|
U.S.
|
|
Canada
|
|
Intl
|
|
Total
|
|
|
|
(In
Millions)
|
|
Properties-net
|
|
$
|
4,520
|
|
$
|
5,982
|
|
$
|
1,371
|
|
$
|
11,873
|
|
$
|
3,984
|
|
$
|
5,541
|
|
$
|
1,417
|
|
$
|
10,942
|
|
Goodwill
|
|
$
|
-
|
|
$
|
1,093
|
|
$
|
-
|
|
$
|
1,093
|
|
$
|
-
|
|
$
|
1,054
|
|
$
|
-
|
|
$
|
1,054
|
|
The
following is a reconciliation of income before income taxes for reportable
segments to consolidated income before income taxes.
|
|
Third
Quarter
|
|
Nine
Months
|
|
|
|
2005
|
|
2004
|
|
2005
|
|
2004
|
|
|
|
(In
Millions)
|
|
Income
before income taxes for reportable segments
|
|
$
|
1,289
|
|
$
|
754
|
|
$
|
3,093
|
|
$
|
2,117
|
|
Corporate
expenses
|
|
|
82
|
|
|
59
|
|
|
199
|
|
|
171
|
|
Interest
expense
|
|
|
70
|
|
|
71
|
|
|
210
|
|
|
211
|
|
Other
expense (income) - net
|
|
|
18
|
|
|
(5
|
)
|
|
21
|
|
|
19
|
|
Consolidated
income before income taxes
|
|
$
|
1,119
|
|
$
|
629
|
|
$
|
2,663
|
|
$
|
1,716
|
|
The
following is a reconciliation of capital expenditures for reportable segments
to
consolidated capital expenditures.
|
|
Third
Quarter
|
|
Nine
Months
|
|
|
|
2005
|
|
2004
|
|
2005
|
|
2004
|
|
|
|
(In
Millions)
|
|
Total
capital expenditures for reportable segments
|
|
$
|
730
|
|
$
|
359
|
|
$
|
1,811
|
|
$
|
1,230
|
|
Corporate
capital expenditures
|
|
|
1
|
|
|
2
|
|
|
5
|
|
|
14
|
|
Total
capital expenditures
|
|
$
|
731
|
|
$
|
361
|
|
$
|
1,816
|
|
$
|
1,244
|
|
The
following is a reconciliation of segment net properties to consolidated
amounts.
|
|
September
30,
|
|
December
31,
|
|
|
|
2005
|
|
2004
|
|
|
|
(In
Millions)
|
|
Properties
-
net
for reportable segments
|
|
$
|
11,873
|
|
$
|
10,942
|
|
Corporate
properties -
net
|
|
|
77
|
|
|
91
|
|
Consolidated
properties -
net
|
|
$
|
11,950
|
|
$
|
11,033
|
|
8.
|
ASSET
RETIREMENT OBLIGATIONS
|
The
Company’s asset retirement obligations of $490 million at September 30, 2005 are
included on the Consolidated Balance Sheet in Other Liabilities and Deferred
Credits. Accretion expense is included in Depreciation, Depletion and
Amortization expense on the Company’s Consolidated Statement of
Income.
The
following table reflects the changes in the Company’s asset retirement
obligations during the first nine months of 2005.
|
|
(In
Millions)
|
|
Carrying
amount of asset retirement obligations as of December 31,
2004
|
|
$
|
468
|
|
Liabilities
settled during the period
|
|
|
(11
|
)
|
Current
period accretion expense
|
|
|
22
|
|
Changes
in foreign exchange rates during the period
|
|
|
11
|
|
Carrying
amount of asset retirement obligations as of September 30,
2005
|
|
$
|
490
|
|
9.
|
OIL
AND GAS PROPERTIES
|
During
the quarter ended June 30, 2005, the Company adopted the requirements of
the
Financial Accounting Standards Board (“FASB”) Staff Position No. FAS 19-1,
Accounting
for Suspended Well Costs
(“FSP
19-1”). Upon the adoption of FSP 19-1, the Company evaluated all existing
capitalized well costs under the provisions of FSP 19-1 and determined there
was
no impact to the Company’s consolidated financial statements. The following
table reflects the net changes in capitalized exploratory well costs for
the
nine-month period ended September 30, 2005.
|
|
(In
Millions)
|
|
Balance
at January 1, 2005
|
|
$
|
23
|
|
Additions
|
|
|
48
|
|
Reclassifications
to proved properties
|
|
|
(25
|
)
|
Charged
to expense
|
|
|
(5
|
)
|
Balance
at September 30, 2005
|
|
$
|
41
|
|
|
|
|
|
|
Capitalized
less than one year since completion of drilling
|
|
$
|
41
|
|
At
September 30, 2005, the Company had no deferred costs related to wells that
have
been completed for more than one year.
10.
PROPERTY ACQUISITIONS AND DIVESTITURES
In
August
and September of 2005, the Company acquired certain oil and gas properties
located in the Fort Worth Basin in Texas for approximately $140 million.
During the first nine months of 2005, the Company also made acquisitions
for
other oil and gas properties totaling approximately $97 million in the
aggregate.
In
August
and September of 2005, the Company sold 8,350,000 units of beneficial interest
in the Permian Basin Royalty Trust (“Units”) held by the Company, generating
proceeds, after underwriting fees, of approximately $123 million. The Company
recorded a pretax gain of $117 million on this sale. Net proceeds generated
from
the sale of Units were used for the acquisitions of oil and gas
properties.
All
of
the Company’s goodwill is assigned to the Canadian reporting unit which consists
of all of the Company’s Canadian subsidiaries. The following table reflects the
changes in the carrying amount of goodwill during the first nine months of
2005
as it relates to the Canadian reporting unit.
|
|
(In
Millions)
|
|
Balance-December
31, 2004
|
|
$
|
1,054
|
|
Changes
in foreign exchange rates during the period
|
|
|
39
|
|
Balance-September
30, 2005
|
|
$
|
1,093
|
|
The
Company’s effective income tax rate for the nine months ended September 30, 2005
is unchanged from the 34 percent rate for the year ended December 31, 2004.
The
nine months ended September 30, 2005 and the year ended December 31, 2004
included income tax benefits of $19 million or 1 percent and $68 million
or 3
percent, respectively, related to reductions in the Company’s Canadian tax
rates. The income tax benefits for the year ended December 31, 2004 were
partially offset by an income tax expense of $26 million or 1 percent related
to
the planned repatriation of $500 million of eligible foreign earnings from
Canada to the U.S. during 2005 under the one-time provisions of the American
Jobs Creation Act of 2004. On October 27, 2005, the Company repatriated the
$500
million of eligible foreign earnings from Canada to the U.S.
At
September 30, 2005, $176 million of deferred income tax is classified as
current
and is included in Other Current Assets on the Consolidated Balance
Sheet.
The
Company's 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. Burlington Resources Canada (Hunter) Ltd. 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’s net periodic benefit cost for its plans is comprised of the following
components.
|
|
Third
Quarter
|
|
|
|
Pension
Benefits
|
|
Postretirement
Benefits
|
|
|
|
2005
|
|
2004
|
|
2005
|
|
2004
|
|
|
|
(In
Millions)
|
|
Benefit
cost for the plans includes the following components
|
|
|
|
|
|
|
|
|
|
Service
cost
|
|
$
|
3
|
|
$
|
2
|
|
$
|
-
|
|
$
|
-
|
|
Interest
cost
|
|
|
4
|
|
|
3
|
|
|
1
|
|
|
-
|
|
Expected
return on plan asset
|
|
|
(4
|
)
|
|
(3
|
)
|
|
-
|
|
|
-
|
|
Recognized
net actuarial loss
|
|
|
2
|
|
|
2
|
|
|
-
|
|
|
-
|
|
Net
benefit cost
|
|
$
|
5
|
|
$
|
4
|
|
$
|
1
|
|
$
|
-
|
|
|
|
Nine
Months
|
|
|
|
Pension
Benefits
|
|
Postretirement
Benefits
|
|
|
|
2005
|
|
2004
|
|
2005
|
|
2004
|
|
|
|
(In
Millions)
|
|
Benefit
cost for the plans includes the following components
|
|
|
|
|
|
|
|
|
|
Service
cost
|
|
$
|
9
|
|
$
|
8
|
|
$
|
-
|
|
$
|
-
|
|
Interest
cost
|
|
|
10
|
|
|
9
|
|
|
2
|
|
|
2
|
|
Expected
return on plan asset
|
|
|
(10
|
)
|
|
(9
|
)
|
|
-
|
|
|
-
|
|
Recognized
net actuarial loss
|
|
|
4
|
|
|
4
|
|
|
-
|
|
|
-
|
|
Net
benefit cost
|
|
$
|
13
|
|
$
|
12
|
|
$
|
2
|
|
$
|
2
|
|
During
the third quarter of 2005, the Company contributed $15 million to its pension
plans. The Company expects to contribute a total of $46 million to its pension
plans during 2005, of which $24 million remains unfunded as of September
30,
2005. The assumptions used in the valuation of the Company’s retirement plans
and the target investment allocations have not changed since December 31,
2004.
14.
|
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. SFAS No. 154 will become effective for the Company’s fiscal
year beginning 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 Company’s consolidated financial position,
results of operations or cash flows.
In
December 2004, the FASB issued SFAS No. 123 (revised 2004) or SFAS No. 123(R),
Share-Based
Payment.
This
statement requires the cost resulting from all share-based payment transactions
be recognized in the financial statements at their fair value on the grant
date.
SFAS No. 123(R) is effective as of the beginning of the first interim or
annual
reporting period that begins after June 15, 2005. In April 2005, the Securities
and Exchange Commission issued a rule that amends the date for compliance
with
SFAS No. 123(R). As a result, the Company will adopt 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 is not
expected to have a material impact on the Company’s consolidated financial
position, results of operations or cash flows.
ITEM
2. Management's
Discussion and Analysis of Financial Condition and Results of
Operations
Outlook
The
Company strives to achieve both production growth and sector-leading financial
returns when compared to other independent oil and gas exploration and
production companies. This 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.
The
Company has a goal to achieve between three and eight percent average annual
production growth. Production growth in 2005 is expected to be driven by
steady
production growth in North America.
Some
of
the Company’s oil and gas facilities in south Louisiana and adjacent areas
sustained minor damages as a result of Hurricanes Katrina and Rita.
During
the quarter, storm-related production curtailments temporarily peaked at
180
MMCFE per day but the curtailments had declined to approximately 30 MMCFE
per
day by late-October. Full restoration of the Company’s shut-in production
will depend on the pace of the industry’s restoration of its services and
facilities.
Future
International production volumes will be impacted by the timing of the
resumption of operations at the Rivers Field natural gas processing plant
in the
United Kingdom (“Rivers Field Plant”). The Company continues to conduct repairs
and audit the design of certain components of the Rivers Field Plant. These
activities are intended to address various construction and operational issues
that occurred during commissioning and start-up of the plant.
The
Company’s current estimate for full year 2005 production volumes is expected to
average between 2,840 and 2,890 MMCFE per day. This estimate does not include
any production volumes from the Rivers Field Plant. The Company expects fourth
quarter production volumes to average between 2,830 and 2,950 MMCFE per day.
Below
are
estimated and actual costs and expenses for full year 2005 and 2004,
respectively.
|
|
2005
|
|
2004
|
|
|
|
(Per
Mcfe)
|
|
Transportation
expense
|
|
$
|
0.46
to $0.50
|
|
$
|
0.44
|
|
Operating
costs
|
|
|
0.62
to 0.66
|
|
|
0.57
|
|
Depreciation,
depletion and amortization (“DD&A”)
|
|
|
1.20
to 1.30
|
|
|
1.10
|
|
Administrative
|
|
$
|
0.19
to $0.22
|
|
$
|
0.21
|
|
|
|
(In
Millions)
|
|
Exploration
costs
|
|
$
|
265
to $ 285
|
|
$
|
258
|
|
Interest
expense
|
|
$
|
270
to $ 290
|
|
$
|
282
|
|
In
2005,
the Company’s operating costs are expected to increase about 9 to 16 percent
over 2004 on a per unit-of-production basis as a result of higher industry
service costs. DD&A expense is expected to increase about 9 to 18 percent in
2005 compared to 2004, primarily as a result of asset additions with higher
unit-of-production rates and unfavorable exchange rate impacts. Transportation
expense is expected to increase 5 to 14 percent over 2004 on a
unit-of-production basis due primarily to International operations. The Company
expects administrative expenses to range from a decrease of 10 percent to
an
increase of 5 percent from 2004 on a per unit-of-production basis. This range
is
primarily related to stock-based compensation, excluding stock options, and
is
expected to vary based on the performance of the Company’s stock price.
Exploration costs are expected to increase in 2005 compared to 2004 as a
result
of increased exploration activity. These costs are primarily dependent upon
the
size of the Company’s drilling program, timing, and the success it has in
finding commercial hydrocarbons, which cannot be precisely forecasted.
Therefore, it is difficult to accurately estimate these costs.
Commodity
prices are impacted by many factors that are outside of the Company's control.
Historically, commodity prices have been volatile and the Company expects
them
to remain that way in the future. Commodity prices are affected by 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 the estimated range of average daily natural
gas
production in 2005, the Company estimates that a $0.10 per MCF change in
natural
gas prices would have an impact on full year 2005 natural gas revenues of
approximately $69 to $70 million. Also, based on the estimated range of average
daily crude oil production in 2005, the Company estimates that a $1.00 per
barrel change in crude oil prices would have an impact on full year 2005
crude
oil revenues of approximately $33 to $34 million.
Finding
and developing sufficient amounts of natural gas and crude oil reserves at
economical costs are critical to the Company's long-term success. In July
2005,
the Company’s Board of Directors (“Board”) approved an increase in the Company’s
capital expenditures for 2005 to $2.4 billion, excluding acquisitions. During
the first nine months of 2005, acquisition transactions totaled approximately
$237 million. For more information on the Company’s 2005 capital program, see
the capital expenditures discussion on page 21 of this report.
Financial
Condition and Liquidity
The
Company’s total debt to total capital (total capital is defined as total debt
and stockholders’ equity) ratio at September 30, 2005 and December 31, 2004 was
33 percent and 36 percent, respectively. The improvement in this ratio was
primarily attributable to higher net income partially offset by the repurchase
of Common Stock. Based on the current price environment, the Company believes
that it will generate sufficient cash from operating activities to fund its
2005
capital expenditures, excluding any potential major acquisition(s). At September
30, 2005, the Company had $2,816 million of cash and cash equivalents on
hand,
of which $2,040 million was located in Canada, $513 million in the U.S. and
$263
million in International. On October 27, 2005, the Company repatriated $500
million of eligible foreign earnings from Canada 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 $1.5 billion 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 BR’s 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 December 2001, the Company’s Board authorized the Company
to redeem, exchange or repurchase up to an aggregate of $990 million principal
amount of debt securities. As of September 30, 2005, no debt securities had
been
redeemed, exchanged or repurchased under this authorization.
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, up to
27,577,741 units of beneficial interest in the Royalty Trust (“Units”) held by
the Company. In August and September of 2005, the Company sold 8,350,000
Units,
generated proceeds, after underwriting fees, of approximately $123 million.
Net
proceeds generated from the sale of Units were used for the acquisitions
of oil
and gas properties.
The
Company has a $1.5 billion revolving credit facility (“Credit Facility”) that
includes (i) a US$500 million Canadian sub-facility 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 September 30, 2005, there were
no
amounts outstanding under the Credit Facility and no outstanding commercial
paper.
Net
cash
provided by operating activities during the first nine months of 2005 was
$2,963
million, representing an increase of $489 million over the same period in
2004.
Commodity prices, production volumes and costs and expenses are key drivers
of
net operating cash flow generation for the Company. Net cash provided by
operating activities increased primarily due to higher net income resulting
from
higher commodity prices and higher crude oil and NGLs production volumes.
These
increases were partially offset by lower natural gas production volumes,
higher
costs and expenses, excluding non-cash expenses, and higher working capital
needs. Commodity prices increased over the comparable period last year,
resulting in higher revenues of $1,086 million. Crude oil and NGLs production
volumes increased resulting in higher revenues of $98 million. Lower natural
gas
production volumes resulted in reduced revenues of $41 million. Working capital
needs increased $179 million during the first nine months of 2005 compared
to
the first nine months of 2004.
Costs
and
expenses referred to in this discussion include operating costs, taxes other
than income taxes, transportation expense, and administrative expense. These
costs and expenses in the first nine months of 2005 increased $184 million
over
the first nine months of 2004. Taxes other than income taxes and operating
costs
represented the largest increase in these costs. Taxes other than income
taxes
include severance and ad valorem taxes, and severance taxes are directly
correlated to crude oil and natural gas revenues. Severance and ad valorem
taxes
accounted for 32 percent of the increase in costs and expenses compared to
the
first nine months of 2004. Operating costs include well operating expenses,
which are expenses incurred to operate the Company’s wells and equipment on
producing leases. Well operating expenses accounted for 24 percent of the
increase in costs and expenses compared to the first nine months of 2004.
Transportation expense and administrative expense represented increases of
19
percent and 13 percent, respectively, in costs and expenses during the period
compared to 2004.
Although
the Company believes that 2005 production volumes will exceed 2004 levels,
it is
unable to predict future commodity prices, and as a result cannot provide
any
assurance about future levels of net cash provided by operating activities.
Net
cash provided by operating activities during the first nine months of 2005
is
not necessarily indicative of future cash flows from operating
activities.
In
December 2000, the Company’s Board authorized the repurchase of up to $1 billion
of the Company’s 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’s Board voted to restore the
authorization level to $1 billion effective May 1, 2003. Through December
7,
2004, the Company had repurchased $712 million of its Common Stock under
the
program authorized in April 2003. In December 2004, the Company’s Board voted to
restore the authorization level to $1 billion.
During
the first nine months of 2005, the Company repurchased approximately 13 million
shares of its Common Stock for approximately $693 million and, as of September
30, 2005, had the authority to repurchase an additional $259 million of its
Common Stock under the current authorization. On October 26, 2005, the Company
announced that its Board voted to restore the current authorization level
to $1
billion.
The
Company and its subsidiaries are named defendants in numerous lawsuits and
named
parties in numerous governmental and other proceedings arising in the ordinary
course of business. While the outcome of these lawsuits and other proceedings
cannot be predicted with certainty, management believes these matters will
not
have a material adverse effect on the consolidated financial position of
the
Company, although results of operations and cash flows could be significantly
impacted in the reporting periods in which such matters are
resolved.
The
Company has certain other commitments and uncertainties related to its normal
operations. Management believes that there are no other commitments or
uncertainties that will have a material adverse effect on the consolidated
financial position, results of operations or cash flows of the
Company.
Capital
Expenditures
|
|
Nine
Months
|
|
Increase
|
|
%
Increase
|
|
|
|
2005
|
|
2004
|
|
(Decrease)
|
|
(Decrease)
|
|
|
|
($
In Millions)
|
|
Oil
and gas
|
|
|
|
|
|
|
|
|
|
Development
|
|
$
|
1,242
|
|
$
|
883
|
|
$
|
359
|
|
|
41
|
%
|
Exploration
|
|
|
297
|
|
|
194
|
|
|
103
|
|
|
53
|
|
Acquisitions
|
|
|
237
|
|
|
85
|
|
|
152
|
|
|
179
|
|
Total
oil and gas
|
|
|
1,776
|
|
|
1,162
|
|
|
614
|
|
|
53
|
|
Plants
and pipelines
|
|
|
25
|
|
|
58
|
|
|
(33
|
)
|
|
(57
|
)
|
Administrative
and other
|
|
|
15
|
|
|
24
|
|
|
(9
|
)
|
|
(38
|
)
|
Total
capital expenditures
|
|
$
|
1,816
|
|
$
|
1,244
|
|
$
|
572
|
|
|
46
|
%
|
The
Company’s total capital expenditures during the first nine months of 2005
increased 46 percent compared to the first nine months of 2004. The Company
utilizes a disciplined approach to capital spending. Property acquisitions
during the first nine months of 2005 total approximately $237 million compared
to $85 million during the first nine months of 2004. In August and September
of
2005, the Company acquired certain oil and gas properties located in the
Fort
Worth Basin in Texas for approximately $140 million. During the first nine
months of 2005, the Company also made acquisitions for other oil and gas
properties totaling approximately $97 million in the aggregate. Excluding
acquisitions, the Company’s capital spending related to internal development and
exploration increased 43 percent compared to the first nine months of 2004.
In
order to fund additional exploration and development drilling, increase lease
purchases in North America and meet rising industry service costs, the Company
expects its capital expenditures in 2005, excluding property acquisitions,
to
approximate $2.4 billion, representing a 20 percent increase over expectations
announced in late 2004. This capital spending includes the costs associated
with
the initiation of projects in Egypt and Algeria, and represents an increase
of
44 percent over 2004. Capital expenditures in 2005 are expected to be primarily
for internal development and exploration of oil and gas properties and are
expected to be funded from internally generated cash flows.
Dividends
On
October 26, 2005, the Company’s Board declared a quarterly common stock cash
dividend of $0.10 per share. The record and payment dates for the quarterly
dividend are December 9, 2005 and January 10, 2006,
respectively.
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. SFAS No. 154 will become effective for the Company’s fiscal
year beginning 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 Company’s consolidated financial position,
results of operations or cash flows.
In
December 2004, the FASB issued SFAS No. 123 (revised 2004) or SFAS No. 123(R),
Share-Based
Payment.
This
statement requires the cost resulting from all share-based payment transactions
be recognized in the financial statements at their fair value on the grant
date.
SFAS No. 123(R) is effective as of the beginning of the first interim or
annual
reporting period that begins after June 15, 2005. In April 2005, the SEC
issued
a rule that amends the date for compliance with SFAS No. 123(R). As a result,
the Company will adopt 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 is not expected to have a
material impact on the Company’s consolidated financial position, results of
operations or cash flows.
Results
of Operations -Third Quarter of 2005 Compared to Third Quarter of
2004
The
Company reported net income of $748 million or $1.96 diluted earnings per
common
share in the third quarter of 2005 compared to net income of $394 million
or
$1.00 diluted earnings per common share in the third quarter of 2004. Net
income
in the third quarter of 2005 includes a pretax gain of $117 million ($73
million
after tax or $0.19 per diluted share) related to the sale of 8,350,000 units
of
beneficial interest in the Permian Basin Royalty Trust held by the
Company.
Below
is
a discussion of revenues, price, and volume variances.
Revenue
Variances
|
|
Third
Quarter
|
|
|
|
%
|
|
|
|
2005
|
|
2004
|
|
Increase
|
|
Increase
|
|
|
|
($
In Millions)
|
|
Revenues
|
|
|
|
|
|
|
|
|
|
Natural
gas
|
|
$
|
1,249
|
|
$
|
927
|
|
$
|
322
|
|
|
35
|
%
|
NGLs
|
|
|
211
|
|
|
161
|
|
|
50
|
|
|
31
|
|
Crude
oil
|
|
|
478
|
|
|
322
|
|
|
156
|
|
|
48
|
|
Processing
and other
|
|
|
15
|
|
|
9
|
|
|
6
|
|
|
67
|
|
Total
revenues
|
|
$
|
1,953
|
|
$
|
1,419
|
|
$
|
534
|
|
|
38
|
%
|
Price
and Volume Variances
|
|
Third
Quarter
|
|
|
|
%
|
|
Increase
|
|
|
|
2005
|
|
2004
|
|
Increase
|
|
Increase
|
|
(In
Millions)
|
|
Price
variance
|
|
|
|
|
|
|
|
|
|
|
|
Natural
gas sales prices (per MCF)
|
|
$
|
7.19
|
|
$
|
5.29
|
|
$
|
1.90
|
|
|
36
|
%
|
$
|
330
|
|
NGLs
sales prices (per Bbl)
|
|
|
34.69
|
|
|
26.26
|
|
|
8.43
|
|
|
32
|
|
|
51
|
|
Crude
oil sales prices (per Bbl)
|
|
$
|
55.86
|
|
$
|
41.06
|
|
$
|
14.80
|
|
|
36
|
%
|
|
126
|
|
Total
price variance
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
507
|
|
|
|
|
|
|
|
%
|
|
Increase
|
|
|
|
Third
Quarter
|
|
Increase
|
|
Increase
|
|
(Decrease)
|
|
|
|
2005
|
|
2004
|
|
(Decrease)
|
|
(Decrease)
|
|
(In
Millions)
|
|
Volume
variance
|
|
|
|
|
|
|
|
|
|
|
|
Natural
gas sales volumes (MMCF per day)
|
|
|
1,888
|
|
|
1,906
|
|
|
(18
|
)
|
|
(1
|
)%
|
$
|
(8
|
)
|
NGLs
sales volumes (MBbls per day)
|
|
|
66.1
|
|
|
66.5
|
|
|
(0.4
|
)
|
|
(1
|
)
|
|
(1
|
)
|
Crude
oil sales volumes (MBbls per day)
|
|
|
93.0
|
|
|
85.1
|
|
|
7.9
|
|
|
9
|
%
|
|
30
|
|
Total
volume variance
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
21
|
|
Revenues
The
Company's consolidated revenues increased $534 million in the third quarter
of
2005 compared to the third quarter of 2004. Higher revenues were due primarily
to higher commodity prices and higher crude oil sales volumes, resulting
in
increased revenues of $507 million and $30 million, respectively. Higher
revenues related to higher commodity prices and higher crude oil sales volumes
were partially offset by lower natural gas and NGLs sales volumes, resulting
in
reduced revenues of $9 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 and net operating cash flow
generation. Higher commodity prices contributed $507 million to increased
revenues in the third quarter of 2005 compared to the third quarter of 2004.
Average natural gas prices, including a $0.19 realized loss per MCF related
to
hedging activities, increased $1.90 per MCF during the third quarter of 2005
resulting in increased revenues of $330 million. Average crude oil prices,
including a $1.79 realized loss per barrel related to hedging activities,
increased $14.80 per barrel in the third quarter of 2005, resulting in increased
revenues of $126 million. Average NGLs prices increased $8.43 per barrel
in the
third quarter of 2005, resulting in higher revenues of $51 million.
Volume
Variances
Sales
volumes are another key driver that impact the Company's earnings and net
operating cash flow generation. Higher average crude oil sales volumes,
which increased 7.9 MBbls in the third quarter of 2005, resulted in increased
revenues of $30 million compared to the third quarter of 2004. Crude
oil
sales volumes increased primarily due to higher production of 10.4 MBbls
per day
in the Cedar Creek Anticline and 4.4 MBbls per day in the Bakken Shale partially
offset by lower production of 5.3 MBbls per day in China. Average
natural
gas sales volumes decreased 18 MMCF per day in the third quarter of 2005,
resulting in lower revenues of $8 million. Average natural gas sales volumes
decreased primarily due to lower production of 46 MMCF per day in the San
Juan
Basin, 31 MMCF per day in south Louisiana, 19 MMCF per day at Millom and
Dalton
in the East Irish Sea, and 17 MMCF per day from the Dutch sector of the North
Sea. These decreases were partially offset by higher production volumes
of
83 MMCF per day at Savell (Bossier) Field and 9 MMCF per day in the Fort
Worth
Basin. Average NGLs sales volumes decreased 0.4 MBbls per day in
the third
quarter of 2005, resulting in lower revenues of $1 million compared to the
same
quarter last year. NGLs sales volumes decreased primarily due to
lower
production of 1.1 MBbls per day in south Louisiana partially offset by higher
production of 0.6 MBbls per day in the Fort Worth Basin.
Below
is
a discussion of total costs and other income - net.
Total
Costs and Other Income - Net
|
|
|
|
|
|
|
|
%
|
|
|
|
Third
Quarter
|
|
Increase
|
|
Increase
|
|
|
|
2005
|
|
2004
|
|
(Decrease)
|
|
(Decrease)
|
|
|
|
($
In Millions)
|
|
Costs
and other income -
net
|
|
|
|
|
|
|
|
|
|
Taxes
other than income taxes
|
|
$
|
94
|
|
$
|
67
|
|
$
|
27
|
|
|
40
|
%
|
Transportation
expense
|
|
|
127
|
|
|
112
|
|
|
15
|
|
|
13
|
|
Operating
costs
|
|
|
176
|
|
|
152
|
|
|
24
|
|
|
16
|
|
Depreciation,
depletion and amortization
|
|
|
325
|
|
|
284
|
|
|
41
|
|
|
14
|
|
Exploration
costs
|
|
|
65
|
|
|
55
|
|
|
10
|
|
|
18
|
|
Administrative
|
|
|
76
|
|
|
54
|
|
|
22
|
|
|
41
|
|
Interest
expense
|
|
|
70
|
|
|
71
|
|
|
(1
|
)
|
|
(1
|
)
|
Gain
on disposal of assets
|
|
|
(117
|
)
|
|
-
|
|
|
117
|
|
|
-
|
|
Other
expense (income) -
net
|
|
|
18
|
|
|
(5
|
)
|
|
23
|
|
|
460
|
|
Total
costs and other income -
net
|
|
$
|
834
|
|
$
|
790
|
|
$
|
44
|
|
|
6
|
%
|
Total
costs and other income - net increased $44 million in the third quarter of
2005
compared to the third quarter of 2004. The increase in total costs and other
income - net was primarily due to the items discussed below. Changes in foreign
currencies versus the U.S. dollar could impact costs and expenses in future
periods. However, the Company cannot predict what impact the exchange rates
will
have on future costs and expenses.
DD&A
expense increased $41 million primarily due to asset additions with higher
unit-of-production rates and higher foreign exchange rates. Taxes other than
income taxes increased $27 million primarily due to higher severance taxes
resulting from higher crude oil and natural gas revenues.
In
general, operating costs are higher due to industry service cost pressures.
Operating costs increased $24 million primarily due to higher well operating
expenses related to well activity levels, foreign currency rates, maintenance
and repairs, fuel, and electricity expenses. Administrative expense increased
$22 million primarily due to stock-based compensation, excluding stock options,
related to a higher stock price for the Company. Transportation expense
increased $15 million primarily in the U.S. and International operations.
Exploration
costs increased $10 million primarily due to higher dry hole costs. Exploration
costs fluctuate from period to period primarily due to the amount the Company
expends on its exploration capital program, timing, and its success rate.
The
current period exploration costs are not necessarily indicative of future
costs.
Gain
on
disposal of assets increased $117 million due to the sale of 8,350,000 units
of
beneficial interest in the Permian Basin Royalty Trust held by the Company.
Other expense - net increased primarily due to higher legal cost accruals
partially offset by higher interest income. The Company recorded legal cost
accruals of $29 million and $200 thousand during the third quarter of 2005
and
2004, respectively. The Company recorded interest income of $16 million and
$6
million during the third quarter of 2005 and 2004, respectively.
Income
Tax Expense
Income
tax expense increased $136 million in the third quarter of 2005 compared
to the
third quarter of 2004. The increase in income tax expense was primarily due
to
higher pretax income of $490 million. During the third quarter of 2005 and
2004,
the Company recorded income tax benefits of $40 million and income tax expense
of $12 million, respectively, related to return as filed adjustments. The
Company recorded income tax benefits of $10 million related to the Canadian
rate
reductions in the third quarter of 2005 compared to none in the third quarter
of
2004. The Company also recorded income tax expense of $28 million and $4
million
in the third quarter of 2005 and 2004, respectively, related to taxes on
foreign
income in excess of U.S. rates.
Results
of Operations - Nine Months of 2005 Compared to Nine Months of
2004
The
Company reported net income of $1,756 million or $4.56 diluted earnings per
common share in the first nine months of 2005 compared to net income of $1,127
million or $2.84 diluted earnings per common share in the first nine months
of
2004. Net income in the first nine months of 2005 includes a pretax gain
of $117
million ($73 million after tax or $0.19 per diluted share) related to the
sale
of 8,350,000 units of beneficial interest in the Permian Basin Royalty Trust
held by the Company.
Below
is
a discussion of revenues, price, and volume variances.
Revenue
Variances
|
|
Nine
Months
|
|
|
|
%
|
|
|
|
2005
|
|
2004
|
|
Increase
|
|
Increase
|
|
|
|
($
In Millions)
|
|
Revenues
|
|
|
|
|
|
|
|
|
|
Natural
gas
|
|
$
|
3,346
|
|
$
|
2,803
|
|
$
|
543
|
|
|
19
|
%
|
NGLs
|
|
|
565
|
|
|
423
|
|
|
142
|
|
|
34
|
|
Crude
oil
|
|
|
1,267
|
|
|
809
|
|
|
458
|
|
|
57
|
|
Processing
and other
|
|
|
37
|
|
|
25
|
|
|
12
|
|
|
48
|
|
Total
revenues
|
|
$
|
5,215
|
|
$
|
4,060
|
|
$
|
1,155
|
|
|
28
|
%
|
Price
and Volume Variances
|
|
Nine
Months
|
|
|
|
%
|
|
Increase
|
|
|
|
2005
|
|
2004
|
|
Increase
|
|
Increase
|
|
(In
Millions)
|
|
Price
variance
|
|
|
|
|
|
|
|
|
|
|
|
Natural
gas sales prices (per MCF)
|
|
$
|
6.46
|
|
$
|
5.33
|
|
$
|
1.13
|
|
|
21
|
%
|
$
|
584
|
|
NGLs
sales prices (per Bbl)
|
|
|
30.90
|
|
|
24.06
|
|
|
6.84
|
|
|
28
|
|
|
125
|
|
Crude
oil sales prices (per Bbl)
|
|
$
|
50.08
|
|
$
|
35.17
|
|
$
|
14.91
|
|
|
42
|
%
|
|
377
|
|
Total
price variance
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
1,086
|
|
|
|
Nine
Months
|
|
Increase
|
|
%
Increase
|
|
Increase
(Decrease)
|
|
|
|
2005
|
|
2004
|
|
(Decrease)
|
|
(Decrease)
|
|
(In
Millions)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume
variance
|
|
|
|
|
|
|
|
|
|
|
|
Natural
gas sales volumes (MMCF per day)
|
|
|
1,898
|
|
|
1,919
|
|
|
(21
|
)
|
|
(1
|
)%
|
$
|
(41
|
)
|
NGLs
sales volumes (MBbls per day)
|
|
|
67.0
|
|
|
64.2
|
|
|
2.8
|
|
|
4
|
|
|
17
|
|
Crude
oil sales volumes (MBbls per day)
|
|
|
92.7
|
|
|
83.9
|
|
|
8.8
|
|
|
10
|
%
|
|
81
|
|
Total
volume variance
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
57
|
|
Revenues
The
Company's consolidated revenues increased $1,155 million in the first nine
months of 2005 compared to the first nine months of 2004. Higher revenues
were
due primarily to higher commodity prices and higher crude oil and NGLs sales
volumes, resulting in increased revenues of $1,086 million and $98 million,
respectively. Higher revenues related to higher commodity prices and higher
crude oil and NGLs sales volumes were partially offset by lower natural gas
sales volumes, resulting in reduced revenues of $41 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 and net operating cash flow
generation. Higher commodity prices contributed $1,086 million to increased
revenues in the first nine months of 2005 compared to the first nine months
of
2004. Average natural gas prices, including a $0.05 realized loss per MCF
related to hedging activities, increased $1.13 per MCF during the first nine
months of 2005 resulting in increased revenues of $584 million. Average crude
oil prices, including a $0.75 realized loss per barrel related to hedging
activities, increased $14.91 per barrel in the first nine months of 2005,
resulting in increased revenues of $377 million. Average NGLs prices increased
$6.84 per barrel in the first nine months of 2005, resulting in higher revenues
of $125 million.
Volume
Variances
Sales
volumes are another key driver that impact the Company's earnings and net
operating cash flow generation. Higher crude oil and NGLs sales volumes
in
the first nine months of 2005 resulted in increased revenues of $98 million
compared to the first nine months of 2004. Average crude oil sales
volumes
increased 8.8 MBbls per day in the first nine months of 2005, resulting in
increased revenues of $81 million. Crude oil sales volumes increased
primarily due to higher production of 9.3 MBbls per day in the Cedar Creek
Anticline and 3.9 MBbls per day in the Bakken Shale partially offset by lower
production of 2.5 MBbls per day in China and 1.8 MBbls per day in Ecuador.
Average NGLs sales volumes increased 2.8 MBbls per day in the first nine
months
of 2005, resulting in higher revenues of $17 million compared to the same
period
last year. NGLs sales volumes increased primarily due to higher production
of 1.1 MBbls per day in Canada and 1.0 MBbls per day at the Waddell Ranch
Field. Average natural gas sales volumes decreased 21 MMCF per day
in the
first nine months of 2005, resulting in lower revenues of $41 million. Average
natural gas sales volumes decreased primarily due to lower production of
33 MMCF
per day in the San Juan Basin, 22 MMCF per day at Millom and Dalton in the
East
Irish Sea, 16 MMCF per day in the Dutch sector of the North Sea, 13 MMCF
per day
in Canada and 11 MMCF per day in south Louisiana. These decreases
were
partially offset by higher production volumes of 61 MMCF per day from the
drilling programs at Savell (Bossier) Field and 11 MMCF per day at Madden
Field.
Below
is
a discussion of total costs and other income - net.
Total
Costs and Other Income - Net
|
|
Nine
Months
|
|
Increase
|
|
%
Increase
|
|
|
|
2005
|
|
2004
|
|
(Decrease)
|
|
(Decrease)
|
|
|
|
($
In Millions)
|
|
|
|
Costs
and other income -
net
|
|
|
|
|
|
|
|
|
|
Taxes
other than income taxes
|
|
$
|
250
|
|
$
|
188
|
|
$
|
62
|
|
|
33
|
%
|
Transportation
expense
|
|
|
364
|
|
|
329
|
|
|
35
|
|
|
11
|
|
Operating
costs
|
|
|
490
|
|
|
426
|
|
|
64
|
|
|
15
|
|
Depreciation,
depletion and amortization
|
|
|
975
|
|
|
831
|
|
|
144
|
|
|
17
|
|
Exploration
costs
|
|
|
183
|
|
|
177
|
|
|
6
|
|
|
3
|
|
Administrative
|
|
|
176
|
|
|
153
|
|
|
23
|
|
|
15
|
|
Interest
expense
|
|
|
210
|
|
|
211
|
|
|
(1
|
)
|
|
-
|
|
(Gain)/loss
on disposal of assets
|
|
|
(117
|
)
|
|
10
|
|
|
127
|
|
|
1,270
|
|
Other
expense -
net
|
|
|
21
|
|
|
19
|
|
|
2
|
|
|
11
|
|
Total
costs and other income -
net
|
|
$
|
2,552
|
|
$
|
2,344
|
|
$
|
208
|
|
|
9
|
%
|
Total
costs and other income - net increased $208 million in the first nine months
of
2005 compared to the first nine months of 2004. The increase in total costs
and
other income - net was primarily due to the items discussed below. Changes
in
foreign currencies versus the U.S. dollar could impact costs and expenses
in
future periods. However, the Company cannot predict what impact the exchange
rates will have on future costs and expenses.
DD&A
expense increased $144 million primarily due to asset additions with higher
unit-of-production rates and higher foreign exchange rates. In general,
operating costs are higher due to industry service cost pressures. Operating
costs increased $64 million primarily due to higher well operating expenses
related to workovers, well activity levels, foreign currency rates, maintenance
and repairs, fuel, and electricity expenses.
Taxes
other than income taxes increased $62 million primarily due to higher severance
taxes resulting from higher crude oil and natural gas revenues. Administrative
expense increased $23 million primarily due to stock-based compensation,
excluding stock options, related to a higher stock price for the Company.
Transportation expense increased $35 million primarily in the U.S. and
International operations.
Exploration
costs increased due to higher geological and geophysical costs, delay rentals
and other expenses of $12 million, higher amortization of undeveloped lease
costs of $8 million partially offset by lower dry hole costs of $5 million
and
lower drilling rig expenses of $9 million. Exploration costs fluctuate from
period to period primarily due to the amount the Company expends on its
exploration capital program, timing, and its success rate. The current period
exploration costs are not necessarily indicative of future costs.
Gain
on
disposal of assets of $117 million in 2005 is due to the sale of 8,350,000
units
of beneficial interest in the Permian Basin Royalty Trust held by the Company.
Other expense - net increased primarily due to higher legal cost accruals
and
higher environmental cost accruals partially offset by higher interest income.
The Company recorded legal cost accruals of $39 million and $17 million during
the first nine months of 2005 and 2004, respectively. The Company recorded
environmental cost accruals of $7 million during the first nine months of
2005
compared to none in the first nine months of 2004. The Company recorded interest
income of $42 million and $14 million during the first nine months of 2005
and
2004, respectively.
Income
Tax Expense
Income
tax expense increased $318 million in the first nine months of 2005 compared
to
the first nine months of 2004. The increase in income tax expense was primarily
due to higher pretax income of $947 million. During the first nine months
of
2005 and 2004, the Company recorded income tax benefits of $68 million and
$53
million, respectively, related to cross-border financing. During the first
nine
months of 2005 and 2004, the Company recorded income tax benefits of $40
million
and income tax expense of $12 million, respectively, related to return as
filed
adjustments. The Company recorded income tax benefits of $19 million and
$27
million related to the Canadian rate reductions in the first nine months
of 2005
and 2004, respectively. The Company also recorded income tax expense of $80
million and $36 million in the first nine months of 2005 and 2004, respectively,
related to taxes on foreign income in excess of U.S. rates.
ITEM
3. Quantitative
and Qualitative Disclosures about Commodity Risk
Substantially
all of the Company's crude oil and natural gas production is sold on the
spot
market or under short-term contracts at market sensitive prices. Spot market
prices for domestic crude oil and natural gas 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
the
"basis differential." 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. Under certain
circumstances, 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 Company's derivative instruments. For example, at
September 30, 2005, the potential increase in fair value of derivative
instruments assuming a 10 percent adverse movement (an increase in the
underlying commodity prices) would result in an $160 million decrease in
the net
unrealized gain.
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.
Based
on
commodity prices as of September 30, 2005, the Company expects to reclassify
losses of $428 million ($265 million after tax) to earnings from the balance
in
Accumulated Other Comprehensive Income during the next twelve months. At
September 30, 2005, the Company had derivative assets of $7 million and
derivative liabilities of $446 million, of which $7 million and $13 million
are
included in Other Current Assets and Other Liabilities and Deferred Credits,
respectively, on the Consolidated Balance Sheet.
ITEM
4. Controls
and Procedures
Under
the
supervision and with the participation of certain members of the Company's
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 Company's 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
Company's 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 Company's
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 Company's 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 Company's internal control over financial reporting during
the
Company's last fiscal quarter that has materially affected, or is reasonably
likely to materially affect, the Company's internal control over financial
reporting.
Forward-looking
Statements
This
Quarterly Report contains projections and other forward-looking statements
within the meaning of Section 21E of the Securities Exchange Act of 1934.
These
projections and statements reflect the Company’s current views with respect to
future events and financial performance. No assurances can be given, however,
that these events will occur or that these projections will be achieved and
actual results could differ materially from those projected as a result of
certain factors. A discussion of these factors is included in the Company’s 2004
Annual Report on Form 10-K.
PART
II -
OTHER INFORMATION
ITEM
1. Legal
Proceedings
See
Note
5 of Notes to Consolidated Financial Statements.
ITEM
2. Unregistered
Sales of Equity Securities and Use of Proceeds
Issuer
Purchases of Equity Securities
(1)
Period
|
|
(a)
Total
Number of Shares Purchased
|
|
(b)
Average
Price Paid per Share
|
|
(c)
Total
Number of Shares Purchased as Part of Publicly Announced Plans
or
Programs
|
|
(d)
Approximate
Dollar Value of Shares that May Yet Be Purchased Under the Plans
or
Programs
|
|
|
|
(In
Thousands, Except per Share Amounts)
|
|
|
|
July
1, 2005 -
July
31, 2005
|
|
|
1,400
|
|
$
|
60.16
|
|
|
1,400
|
|
$
|
423,890
|
|
August
1, 2005 -
August
31, 2005
|
|
|
1,351
|
|
|
66.77
|
|
|
1,351
|
|
|
333,688
|
|
September
1, 2005 -
September
30, 2005
|
|
|
972
|
|
|
76.94
|
|
|
972
|
|
$
|
258,898
|
|
Total
|
|
|
3,723
|
|
$
|
66.94
|
|
|
3,723
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
In
December 2000, the Company announced that its Board of Directors
(“Board”)
authorized the repurchase of up to $1 billion of the Company’s 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 its Board voted to restore the
authorization level to $1 billion effective May 1, 2003. Through
December
7, 2004, the Company had repurchased $712 million of its Common
Stock
under the program authorized in April 2003. In December 2004, the
Company
announced that the Board voted to restore the authorization level
to $1
billion. Through September 30, 2005, the Company had the authority
to
purchase $259 million of its Common Stock under the current authorization.
On October 26, 2005, the Company announced that its Board voted
to restore
the authorization level to $1
billion.
|
The
following exhibits are filed as part of this report.
Exhibit
|
|
Nature
of Exhibit
|
|
|
|
4.1*
|
|
The
Company and its subsidiaries either have filed with the Securities
and
Exchange Commission or upon request will furnish a copy of any
instrument
with respect to long-term debt of the Company
|
|
|
|
10.1*
|
|
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)
|
|
|
|
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 by reference.
|
Items
3,
4 and 5 of Part II are not applicable and have been omitted.
Pursuant
to the requirements of the Securities Exchange Act of 1934, the registrant
has
duly caused this report to be signed on its behalf by the undersigned thereunto
duly authorized.
|
BURLINGTON
RESOURCES INC.
|
|
(Registrant)
|
|
|
|
|
|
|
|
By
|
/S/
JOSEPH P. McCOY
|
|
|
Joseph
P. McCoy
|
|
|
Senior
Vice President and
|
|
|
Chief
Financial Officer
|
|
|
|
|
|
|
|
By
|
/S/
DANE E. WHITEHEAD
|
|
|
Dane
E. Whitehead
|
|
|
Vice
President, Controller and
|
|
|
Chief
Accounting Officer
|
Date:
November 2, 2005