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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(X) QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended June 30, 2003
OR
( ) TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
Commission File Number 1-9971
BURLINGTON RESOURCES INC.
(Exact name of registrant as specified in its charter)
Delaware 91-1413284
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification Number)
5051 Westheimer, Suite 1400, Houston, Texas 77056
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code (713) 624-9500
Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the registrant was
required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days.
Yes X No
--------------- --------------
Indicate by check mark whether the registrant is an accelerated filer (as
defined in Rule 12b-2 of the Exchange Act).
Yes X No
--------------- --------------
Indicate the number of shares outstanding of each of the issuer's classes of
common stock, as of the latest practicable date.
Class Outstanding
----- -----------
Common Stock, par value $.01 per share,
as of June 30, 2003 200,710,143
PART I - FINANCIAL INFORMATION
ITEM 1. Financial Statements
BURLINGTON RESOURCES INC.
CONSOLIDATED STATEMENT OF INCOME
(UNAUDITED)
SECOND QUARTER SIX MONTHS
----------------- ---------------------
2003 2002 2003 2002
------ ----- ------- -------
(In Millions, Except per Share Amounts)
Revenues ........................................................... $1,059 $ 783 $ 2,187 $ 1,486
------ ----- ------- -------
Costs and Other Income - Net
Taxes Other than Income Taxes .................................... 46 30 94 63
Transportation Expense ........................................... 102 82 201 168
Production and Processing ........................................ 112 112 214 248
Depreciation, Depletion and Amortization ......................... 227 215 430 436
Exploration Costs ................................................ 52 104 120 161
Impairment of Oil and Gas Properties ............................. 30 -- 30 --
Administrative ................................................... 39 39 81 77
Interest Expense ................................................. 63 70 127 142
(Gain)/Loss on Disposal of Assets ................................ 1 (73) -- (73)
Other Expense (Income) - Net ..................................... 11 (3) 15 (4)
------ ----- ------- -------
Total Costs and Other Income - Net ................................. 683 576 1,312 1,218
------ ----- ------- -------
Income Before Income Taxes and Cumulative Effect of Change
in Accounting Principle .......................................... 376 207 875 268
Income Tax Expense ................................................. 98 37 269 50
------ ----- ------- -------
Income Before Cumulative Effect of Change in Accounting Principle... 278 170 606 218
Cumulative Effect of Change in Accounting Principle - Net .......... -- -- (59) --
------ ----- ------- -------
Net Income ......................................................... $ 278 $ 170 $ 547 $ 218
====== ===== ======= =======
Earnings per Common Share
Basic
Before Cumulative Effect of Change in Accounting Principle ....... $ 1.39 $0.84 $ 3.03 $ 1.08
Cumulative Effect of Change in Accounting Principle - Net ........ -- -- (0.30) --
------ ----- ------- -------
Net Income ....................................................... $ 1.39 $0.84 $ 2.73 $ 1.08
====== ===== ======= =======
Diluted
Before Cumulative Effect of Change in Accounting Principle ....... $ 1.38 $0.84 $ 3.00 $ 1.08
Cumulative Effect of Change in Accounting Principle - Net ........ -- -- (0.30) --
------ ----- ------- -------
Net Income ....................................................... $ 1.38 $0.84 $ 2.70 $ 1.08
====== ===== ======= =======
See accompanying Notes to Consolidated Financial Statements.
2
BURLINGTON RESOURCES INC.
CONSOLIDATED BALANCE SHEET
(UNAUDITED)
June 30, December 31,
2003 2002
-------- --------
(In Millions, Except Share Data)
ASSETS
Current Assets
Cash and Cash Equivalents ....................................... $ 615 $ 443
Accounts Receivable ............................................. 617 515
Inventories ..................................................... 54 48
Other Current Assets ............................................ 41 55
-------- --------
1,327 1,061
-------- --------
Oil & Gas Properties (Successful Efforts Method) .................. 15,103 12,716
Other Properties .................................................. 1,289 1,140
-------- --------
16,392 13,856
Accumulated Depreciation, Depletion and Amortization .............. 6,453 5,353
-------- --------
Properties - Net ................................................ 9,939 8,503
-------- --------
Goodwill .......................................................... 936 803
-------- --------
Other Assets ...................................................... 219 278
-------- --------
Total Assets .................................................... $ 12,421 $ 10,645
======== ========
LIABILITIES
Current Liabilities
Accounts Payable ................................................ $ 840 $ 809
Taxes Payable ................................................... 60 44
Accrued Interest ................................................ 61 61
Commodity Hedging Contracts and Other Derivatives ............... 72 38
Other Current Liabilities ....................................... 31 7
Current Maturities of Long-term Debt ............................ 74 63
-------- --------
1,138 1,022
-------- --------
Long-term Debt .................................................... 3,867 3,853
-------- --------
Deferred Income Taxes ............................................. 1,873 1,436
-------- --------
Commodity Hedging Contracts and Other Derivatives ................. 27 33
-------- --------
Other Liabilities and Deferred Credits ............................ 686 469
-------- --------
Commitments and Contingencies
STOCKHOLDERS' EQUITY
Preferred Stock, Par Value $.01 Per Share
(Authorized 75,000,000 Shares) .................................. -- --
Common Stock, Par Value $.01 Per Share
(Authorized 325,000,000 Shares; Issued 241,188,688 Shares) ..... 2 2
Paid-in Capital ................................................... 3,913 3,941
Retained Earnings ................................................. 2,167 1,675
Deferred Compensation - Restricted Stock .......................... (16) (9)
Accumulated Other Comprehensive Income (Loss) ..................... 410 (164)
Cost of Treasury Stock
(40,478,545 and 39,749,431 Shares for 2003 and 2002, respectively) (1,646) (1,613)
-------- --------
Stockholders' Equity .............................................. 4,830 3,832
-------- --------
Total Liabilities and Stockholders' Equity ...................... $ 12,421 $ 10,645
======== ========
See accompanying Notes to Consolidated Financial Statements.
3
BURLINGTON RESOURCES INC.
CONSOLIDATED STATEMENT OF CASH FLOWS
(UNAUDITED)
SIX MONTHS
---------------------
2003 2002
------- -------
(In Millions)
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income .................................................. $ 547 $ 218
Adjustments to Reconcile Net Income to Net Cash
Provided By Operating Activities
Depreciation, Depletion and Amortization .................. 430 436
Deferred Income Taxes ..................................... 155 (28)
Exploration Costs ......................................... 120 161
(Gain)/Loss on Disposal of Assets ......................... -- (73)
Impairment of Oil and Gas Properties ...................... 30 --
Cumulative Effect of Change in Accounting Principle - Net.. 59 --
Changes in Derivative Fair Values ......................... (6) 26
Working Capital Changes
Accounts Receivable ....................................... (54) (10)
Inventories ............................................... (2) (8)
Other Current Assets ...................................... 16 (16)
Accounts Payable .......................................... 18 (7)
Taxes Payable ............................................. 18 99
Accrued Interest .......................................... -- 4
Other Current Liabilities ................................. (5) (7)
Changes in Other Assets and Liabilities ..................... (4) (19)
------- -------
Net Cash Provided By Operating Activities ................. 1,322 776
------- -------
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to Properties ..................................... (1,080) (1,034)
Proceeds from Sales and Other ............................... (10) 875
------- -------
Net Cash Used In Investing Activities ..................... (1,090) (159)
------- -------
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from Long-term Debt ................................ -- 454
Reduction in Long-term Debt ................................. -- (775)
Dividends Paid .............................................. (28) (56)
Common Stock Purchases ...................................... (173) --
Common Stock Issuances ...................................... 101 9
Other ....................................................... -- 14
------- -------
Net Cash Used In Financing Activities ..................... (100) (354)
------- -------
Effect of Exchange Rate Changes on Cash and Cash Equivalents... 40 13
------- -------
INCREASE IN CASH AND CASH EQUIVALENTS ......................... 172 276
CASH AND CASH EQUIVALENTS
Beginning of Year ........................................... 443 116
------- -------
End of Period ............................................... $ 615 $ 392
======= =======
See accompanying Notes to Consolidated Financial Statements.
4
BURLINGTON RESOURCES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
1. BASIS OF PRESENTATION
The 2002 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 200 million and 201 million for the
second quarter of 2003 and 2002, respectively, and 200 million and 201 million
for the first six months of 2003 and 2002, 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 202 million and 202 million for the second quarter
of 2003 and 2002, respectively, and 203 million and 202 million for the first
six months of 2003 and 2002, respectively. For the second quarter of 2003 and
2002 and six months ended June 30, 2003 and 2002, approximately 2 million, 4
million, 3 million and 4 million 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 preferred
dividends affecting EPS, therefore, no adjustments related to preferred
dividends were made to reported net income in the computation of EPS.
Recent Development
Statement of Financial Accounting Standards (SFAS) No. 141, Business
Combinations, and SFAS No. 142, Goodwill and Intangible Assets, were issued in
June 2001 and became effective July 1, 2001 and January 1, 2002, respectively.
It is our understanding that the Securities and Exchange Commission (SEC) has
questioned other SEC registrants as to whether they properly adopted the
provisions of SFAS No. 141 and SFAS No. 142, with respect to how the costs of
acquiring contractual mineral interests in oil and gas properties should be
classified on the balance sheet. It is also our understanding that the Financial
Accounting Standards Board (FASB), the SEC and others are engaged in
deliberations on the issue of whether SFAS No. 141 and SFAS No. 142 require that
interests held under oil, gas and mineral leases or other contractual
arrangements be classified as intangible assets or as oil and gas properties. If
such interests were deemed intangible assets, mineral interests for undeveloped
and developed leaseholds would be classified separately from oil and gas
properties on the balance sheet but would be aggregated with oil and gas
properties in the Notes to Consolidated Financial Statements in accordance with
SFAS No. 69, Disclosures about Oil and Gas Producing Activities.
5
Historically, the Company has included all oil and gas leasehold interests as
part of oil and gas properties. Because this issue is being deliberated and is
unresolved, the Company continues to include mineral interests as oil and gas
properties on its balance sheet. At June 30, 2003, the Company had undeveloped
and developed leaseholds of approximately $1.4 billion and $2.4 billion that
would have been classified on the balance sheet as intangible undeveloped
leaseholds and intangible developed leaseholds, respectively, if the
interpretation currently being deliberated had been applied. The
reclassification would have no impact on the Company's results of operations.
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 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.
Second Quarter Six Months
-------------------- --------------------
2003 2002 2003 2002
------- ------- ------- -------
(In Millions, Except per Share Amounts)
Net income - as reported ..................................... $ 278 $ 170 $ 547 $ 218
Pro forma stock based employee compensation cost, after tax... 3 2 6 5
------- ------- ------- -------
Net income - pro forma ....................................... $ 275 $ 168 $ 541 $ 213
======= ======= ======= =======
Basic EPS - as reported ...................................... $ 1.39 $ 0.84 $ 2.73 $ 1.08
Basic EPS - pro forma ........................................ 1.38 0.83 2.70 1.06
Diluted EPS - as reported .................................... 1.38 0.84 2.70 1.08
Diluted EPS - pro forma ...................................... $ 1.37 $ 0.83 $ 2.67 $ 1.06
6
3. COMPREHENSIVE INCOME (LOSS)
The following table presents comprehensive income (loss).
SIX MONTHS
-------------------------------------------------
(In Millions) 2003 2002
---------------------- --------------------
Accumulated other comprehensive loss - Beginning of Period....... $ (164) $ (106)
Net income....................................................... $ 547 $ 218
------- ------
Other comprehensive income (loss) - net of tax.................
Hedging activities
Current period changes in fair value of settled contracts...... (25) 19
Reclassification adjustments for settled contracts............. 32 (60)
Changes in fair value of outstanding hedging positions......... (26) (11)
------- ------
Hedging activities......................................... (19) (52)
Foreign currency translation
Foreign currency translation adjustments....................... 593 176
------- ------
Total other comprehensive income................................. 574 574 124 124
------- ------- ------ -------
Comprehensive income............................................. $ 1,121 $ 342
======= ======
Accumulated other comprehensive income - End of Period........... $ 410 $ 18
======= =======
4. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES
The Company uses derivative instruments to manage risks associated with
natural gas, crude oil and electricity price volatility as well as foreign
currency exchange rate fluctuations. Derivative instruments that meet the hedge
criteria in SFAS No. 133, Accounting for Derivative Instruments and Hedging
Activities, as amended, are designated as cash-flow hedges, fair-value hedges or
foreign-currency hedges. Derivative instruments designated as cash-flow hedges
are used by the Company to mitigate the risk of variability in cash flows from
crude oil and natural gas 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. In addition to hedges of commodity prices, the Company also uses
foreign-currency swaps to hedge its exposure to exchange rate fluctuations
related to its Canadian subsidiaries.
7
As of June 30, 2003, the Company had the following derivative instruments
outstanding with average underlying prices that represent hedged prices at
various market locations.
Notional Amount
-----------------------------------
Electricity US$ Average Fair Value
Settlement Derivative Hedge Gas (Megawatt- (In Underlying Asset
Period Instrument Strategy (MMBTU) Hours) Millions) Prices (Liability)
- -----------------------------------------------------------------------------------------------------------------------
2003 Swap Cash Flow Hedge 9,227,847 $ 2.95 $ (14)
Purchased Put Cash Flow Hedge 112,829,084 3.34 4
Written Call Cash Flow Hedge 112,829,084 5.23 (43)
Written Put Cash Flow Hedge 110,069,084 2.49 --
Swap Foreign Currency Hedge $9 1.42 --
Swap Fair Value Hedge 1,290,700 3.04 3
N/A Fair Value Hedge (Obligation) 1,290,700 3.09 (3)
Purchased Call Cash Flow Hedge 88,320 47.23 1
Written Put Cash Flow Hedge 88,320 30.99 --
2004 Swap Cash Flow Hedge 15,610,390 3.12 (21)
Purchased Put Cash Flow Hedge 11,351,257 4.25 3
Written Put Cash Flow Hedge 11,351,257 3.15 (1)
Written Call Cash Flow Hedge 11,351,257 7.09 (3)
Swap Foreign Currency Hedge $8 1.43 --
Swap Fair Value Hedge 2,256,800 2.92 4
N/A Fair Value Hedge (Obligation) 2,256,800 2.95 (4)
2005 Swap Cash Flow Hedge 10,511,522 3.11 (12)
Swap Fair Value Hedge 1,579,200 2.82 2
N/A Fair Value Hedge (Obligation) 1,579,200 2.83 (2)
2006 to
2007 Swap Cash Flow Hedge 1,672,500 $ 3.06 (2)
-----------
$ (88)
===========
Based on commodity prices and foreign exchange rates as of June 30, 2003, the
Company expects to reclassify losses of $64 million ($40 million after tax) to
earnings from the balance in accumulated other comprehensive income during the
next twelve months. At June 30, 2003, the Company had derivative assets of $11
million and derivative liabilities of $99 million. Of the derivative assets of
$11 million, $6 million are included in Other Current Assets and $5 million are
included in Other Assets on the Consolidated Balance Sheet.
The derivative assets and liabilities represent the difference between hedged
prices and market prices on hedged volumes of the commodities as of June 30,
2003. Hedging activities related to cash settlements decreased revenues $11
million in the second quarter of 2003 and increased revenues $24 million in the
second quarter of 2002. Hedging activities decreased revenues $52 million in the
first six months of 2003 and increased revenues $96 million in the first six
months of 2002. In addition, non-cash losses of $2 million and $1 million were
recorded
8
in revenues associated with ineffectiveness of cash-flow and fair-value hedges
during the second quarter of 2003 and 2002, respectively. Non-cash losses of $3
million and $16 million were recorded in revenues associated with
ineffectiveness of cash-flow and fair-value hedges during the first six months
of 2003 and 2002, respectively. Also, a non-cash gain of $3 million and a
non-cash loss of $25 thousand were recorded in revenues associated with changes
in the fair value of derivative instruments that do not qualify for hedge
accounting during the second quarter of 2003 and 2002, respectively. A non-cash
gain of $9 million and a non-cash loss of $10 million were recorded in revenues
associated with changes in the fair value of derivative instruments that do not
qualify for hedge accounting during the first six months of 2003 and 2002,
respectively.
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.
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 $68 million. In the event that the Company is
found to have violated the civil False Claims Act, the Company could also 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.
The Company has established a reserve that management believes to be adequate to
provide for this potential liability based upon its evaluation of this matter.
While the ultimate outcome and impact on the Company cannot be predicted with
certainty, management believes that the resolution of these proceedings through
settlement or adverse judgment will not have a material adverse effect on the
consolidated financial position or results of operations of the Company,
9
although cash flow could be significantly impacted in the reporting periods in
which such matters are resolved.
The Company has also been named as a defendant in the lawsuit styled UNOCAL
Netherlands B.V., et al v. Continental Netherlands Oil Company B.V., et al, No.
98-854, filed in 1995 in the District Court in The Hague and currently pending
in the Court of Appeal in The Hague, the Netherlands. Plaintiffs, who are
working interest owners in the Q-1 Block in the North Sea, have alleged that the
Company and other former working interest owners in the adjacent Logger Field in
the L16a Block unlawfully trespassed or were otherwise unjustly enriched by
producing part of the oil from the adjoining Q-1 Block. The plaintiffs claim
that the defendants infringed upon plaintiffs' right to produce the minerals
present in its license area and acted in violation of generally accepted
standards by failing to inform plaintiffs of the overlap of the Logger Field
into the Q-1 Block. Plaintiffs seek damages of $97.5 million as of January 1,
1997, plus interest. For all relevant periods, the Company owned a 37.5 percent
working interest in the Logger Field. Following a trial, the District Court in
The Hague rendered a Judgment in favor of the defendants, including the Company,
dismissing all claims. Plaintiffs thereafter appealed. On October 19, 2000, the
Court of Appeal in The Hague issued an interim Judgment in favor of the
plaintiffs and ordered that additional evidence be presented to the court
relating to issues of both liability and damages. The Company and the other
defendants are continuing to present evidence to the Court and vigorously assert
defenses against these claims. The Company has also asserted claims of indemnity
against two of the defendants from whom it had acquired a portion of its working
interest share. If the Company is successful in enforcing the indemnities, its
working interest share of any adverse judgment could be reduced to 15 percent
for some of the periods covered by plaintiffs' lawsuit. The Company is unable at
this time to reasonably predict the outcome, or, in the event of an unfavorable
outcome, to reasonably estimate the possible loss or range of loss, if any, in
this lawsuit. Accordingly, there has been no reserve established for this
matter.
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 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. Two of the
governmental proceedings arise under the provincial laws of Alberta and British
Columbia, Canada, and relate to safety and environmental matters, respectively.
None of the other governmental proceedings involve foreign governments. While
the ultimate outcome of these other lawsuits and proceedings cannot be predicted
with certainty, management believes that the resolution of these other matters
will not have a material adverse effect on the consolidated financial position,
results of operations or cash flows of the Company.
The Company has established reserves for legal proceedings which are included
in Other Liabilities and Deferred Credits on the Consolidated Balance Sheet. The
establishment of a reserve involves a complex 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 of up to approximately $25 million
to $30 million in excess of the amounts currently accrued. Future changes in the
facts and circumstances could result in actual liability exceeding the estimated
ranges of loss and the amounts accrued.
10
6. LONG-TERM DEBT
The fair value of the Company's long-term debt at June 30, 2003 and December
31, 2002 was approximately $4,741 million and $4,443 million, respectively,
based on quoted market prices.
7. SEGMENT AND GEOGRAPHIC INFORMATION
The Company's reportable segments are U.S., Canada and Other International
(Intl). The segments are engaged principally in the exploration for and the
development, production and marketing of oil and gas. 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 2002 Form 10-K.
There were no intersegment sales during the second quarter and first six months
of 2003. Intersegment sales were $1 million and $15 million during the second
quarter and first six months of 2002, respectively.
The following tables present information about the Company's reportable
segments.
Second Quarter
-----------------------------------------------------------------------
2003 2002
---------------------------------- ----------------------------------
U.S. Canada Intl Total U.S. Canada Intl Total
------ ------ ------ ------ ------ ------ ------ ------
(In Millions)
Revenues ................................................. $ 525 $ 491 $ 43 $1,059 $ 429 $ 313 $ 41 $ 783
Income (loss) before income taxes and cumulative
effect of change in accounting principle ............... 287 213 (4) 496 341 59 (83) 317
Capital expenditures ..................................... $ 122 $ 120 $ 232 $ 474 $ 53 $ 101 $ 88 $ 242
Six Months
----------------------------------------------------------------------
2003 2002
--------------------------------- ----------------------------------
U.S. Canada Intl Total U.S. Canada Intl Total
------ ------ ------ ------ ------ ------ ------ ------
(In Millions)
Revenues .................................................. $1,080 $1,017 $ 90 $2,187 $ 826 $ 565 $ 95 $1,486
Income (loss) before income taxes and cumulative
effect of change in accounting principle ................ 596 509 6 1,111 478 93 (79) 492
Capital expenditures ...................................... $ 335 $ 404 $ 329 $1,068 $ 126 $ 625 $ 206 $ 957
The following is a reconciliation of income before income taxes and
cumulative effect of change in accounting principle for reportable segments to
consolidated income before income taxes and cumulative effect of change in
accounting principle.
Second Quarter Six Months
------------------- -------------------
2003 2002 2003 2002
------ ------ ------ ------
(In Millions)
Income before income taxes and cumulative
effect of change in accounting principle ........... $ 496 $ 317 $1,111 $ 492
Corporate expense .................................... 46 43 94 86
Interest expense ..................................... 63 70 127 142
Other expense (income) - net ......................... 11 (3) 15 (4)
------ ------ ------ ------
Consolidated income before income taxes and cumulative
effect of change in accounting principle ........... $ 376 $ 207 $ 875 $ 268
====== ====== ====== ======
11
The following is a reconciliation of capital expenditures for reportable
segments to consolidated capital expenditures.
Second Quarter Six Months
------------------- -------------------
2003 2002 2003 2002
------ ------ ------ ------
(In Millions)
Capital expenditures for reportable segments................ $ 474 $ 242 $1,068 $ 957
Administrative capital expenditures ........................ 2 4 5 25
------ ------ ------ ------
Consolidated capital expenditures .......................... $ 476 $ 246 $1,073 $ 982
====== ====== ====== ======
8. ASSET RETIREMENT OBLIGATIONS
On January 1, 2003, the Company adopted SFAS No. 143, Asset Retirement
Obligations. SFAS No. 143 requires entities to record the fair value of a
liability for an asset retirement obligation in the period in which it is
incurred and a corresponding increase in the carrying amount of the related
long-lived asset. Subsequently, the asset retirement cost should be allocated to
expense using a systematic and rational method. During the first quarter of
2003, the Company recorded a net-of-tax cumulative effect of change in
accounting principle charge of $59 million ($95 million before tax), increased
long-term liabilities $191 million, net properties $96 million and deferred tax
assets $36 million in accordance with the provisions of SFAS No. 143. There was
no impact on the Company's cash flows as a result of adopting SFAS No. 143. The
pro forma asset retirement obligation would have been $376 million at January 1,
2002 and $298 million at December 31, 2002 had the Company adopted SFAS No. 143
on January 1, 2002. The asset retirement obligation, which is included on the
Consolidated Balance Sheet in Other Liabilities and Deferred Credits, was $360
million at June 30, 2003.
For the period ended June 30, 2002, the pro forma effect on net income and
earnings per share, had SFAS No. 143 been adopted by the Company on January 1,
2002, would have been as follows.
Second Quarter Six Months
--------------------------- ---------------------------
As Reported Pro Forma As Reported Pro Forma
----------- ---------- ----------- ----------
(In Millions, Except per Share Amounts)
Net income ................................... $ 170 $ 169 $ 218 $ 215
Earnings per share:
Basic ...................................... 0.84 0.84 1.08 1.07
Diluted .................................... $ 0.84 $ 0.83 $ 1.08 $ 1.06
9. ACQUISITION
In May 2003, the Company purchased an additional 50 percent interest in CLAM
Petroleum B.V. (CLAM) for approximately $100 million, including cash acquired of
$25 million, resulting in a total purchase price for the common equity of
approximately $75 million. The Company, prior to the acquisition in May 2003,
owned 50 percent of CLAM which had been accounted for under the equity method of
accounting. Effective on the date of acquisition, the Company began
consolidating CLAM's financial results.
12
10. GOODWILL
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
six months of 2003 as it relates to the Canadian reporting unit.
(In Millions)
Balance - December 31, 2002 ................................... $803
Changes in foreign exchange rates during the period ........... 133
----
Balance - June 30, 2003 ....................................... $936
====
11. INCOME TAXES
The Company's effective income tax rate increased to 31 percent for the
period ended June 30, 2003 from 20 percent for the year ended December 31, 2002
primarily due to higher pretax income. The period ended June 30, 2003 includes
amounts related to the closing of the 1996 - 1998 IRS tax audit cycle, the
reversal of tax reserves no longer required due to the audit closure, normal tax
return true-up and adjustments of tax credits. The tax rate for the year ended
December 31, 2002 included the reversal of a foreign tax valuation reserve
related to the sale of assets in the U.K. sector of the North Sea.
12. RECENT ACCOUNTING PRONOUNCEMENTS
In May 2003, the FASB issued SFAS No. 150, Accounting for Certain Financial
Instruments with Characteristics of both Liabilities and Equity (SFAS No. 150).
SFAS No. 150 establishes standards for how an issuer classifies and measures
certain financial instruments with characteristics of both liabilities and
equity. It requires that an issuer classify a financial instrument that is
within its scope as a liability (or an asset in some circumstances). Many of
those instruments were previously classified as equity. SFAS No. 150 is
effective for financial instruments entered into or modified after May 31, 2003,
and otherwise is effective at the beginning of the first interim period
beginning after June 15, 2003. It is to be implemented by reporting the
cumulative effect of a change in an accounting principle for financial
instruments created before the issuance date of SFAS No. 150 and still existing
at the beginning of the interim period of adoption. Restatement is not
permitted. The Company does not expect the requirements of SFAS No. 150 to have
a material impact on its consolidated financial position or results of
operations.
In April 2003, the FASB issued SFAS No. 149, Amendment of Statement No. 133
on Derivative Instruments and Hedging Activities (SFAS No. 149). SFAS No. 149
improves financial reporting by requiring that contracts with comparable
characteristics be accounted for similarly. In particular, SFAS No. 149
clarifies under what circumstances a contract with an initial net investment
meets the characteristic of a derivative, clarifies when a derivative contains a
financing component, amends the definition of an "underlying" to conform it to
language used in FIN No. 45 and amends certain other existing pronouncements.
SFAS No. 149 is effective for contracts entered into or modified after June 30,
2003, and for hedging relationships designated after June 30, 2003. In addition,
with some exceptions, all provisions of SFAS No. 149 should be applied
prospectively. The Company does not expect the requirements of SFAS No. 149 to
have a material impact on its consolidated financial position or results of
operations.
13
ITEM 2. Management's Discussion and Analysis of Financial Condition and Results
of Operations
Outlook
The Company expects third quarter 2003 production volumes to average between
2,410 and 2,610 MMCFE per day. The key to third quarter 2003 performance will be
the impact on production volumes associated with annual plant maintenance, the
base capital program and the restoration of production from the Deep Madison
Formation at Madden Field (Madden) in Wyoming. In late June 2003, the production
at Madden was curtailed due to deformations in the gas gathering lines.
Currently, repairs to the gathering lines are underway. The Company expects full
year 2003 production volumes to average between 2,500 and 2,640 MMCFE per day
and expects full year 2004 production volumes to average between 2,650 and 2,850
MMCFE per day. Accomplishing the production goals depend upon the performance of
the base assets, results of the capital program, restoration of production at
Madden and delivery of production from major projects in Algeria, China and the
East Irish Sea.
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 volatile. Commodity prices are affected by
changes in 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, cannot accurately predict revenues.
In addition to production volumes and commodity prices, finding and
developing sufficient amounts of crude oil and natural gas reserves at
economical costs are critical to the Company's long-term success. In 2003,
excluding acquisitions, the Company expects to spend approximately $1.5 billion
on development, exploration and plants and pipeline capital. During the first
six months of 2003, the Company spent $211 million on acquisitions.
Financial Condition and Liquidity
The Company's total debt to total capital (total capital is defined as total
debt and stockholders' equity) ratio at June 30, 2003 and December 31, 2002 was
45 percent and 51 percent, respectively. Based on the current price environment,
management believes that the Company will generate sufficient cash from
operations to fund its 2003 capital expenditures, excluding any major
acquisition(s), dividend payments and Common Stock repurchases. At June 30,
2003, the Company had $615 million of cash and cash equivalents on hand.
The Company had credit commitments in the form of revolving credit facilities
(Revolvers) as of June 30, 2003. The Revolvers are comprised of agreements for
$600 million, $400 million and Canadian $468 million (U.S. $345 million). The
$600 million Revolver expires in December 2006 and the $400 million and Canadian
$468 million Revolvers expire in December 2004 unless renewed by mutual consent.
The Company has the option to convert the outstanding balances on the $400
million and Canadian $468 million Revolvers to one-year and five-year plus one
day term notes, respectively. Under the covenants of the Revolvers, Company debt
cannot exceed 60 percent of capitalization (as defined in the agreements). The
Revolvers are available to cover debt due within one year, therefore, commercial
paper, credit facility notes and fixed-rate debt due within one year are
generally classified as long-term debt. At June 30, 2003, there were no amounts
outstanding under the Revolvers and no outstanding commercial paper.
14
Net cash provided by operating activities during the first six months of 2003
was $1,322 million compared to $776 million in 2002. The increase was primarily
due to higher net income partially offset by higher working capital needs.
Higher net income is principally the result of higher commodity prices partially
offset by lower natural gas and crude oil sales volumes.
In December 2000, the Company's Board of Directors 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 of Directors
voted to restore the authorization level to $1 billion effective May 1, 2003.
During the first six months of 2003, the Company repurchased approximately 3.7
million shares of its Common Stock for approximately $176 million and, as of
June 30, 2003, has authority to repurchase an additional $947 million of its
Common Stock under the current authorization. As of June 30, 2003, $3 million of
the share repurchases were not cash settled during the period. Since December
2000, the Company has repurchased approximately 20 million shares or $870
million of its Common Stock. In 2001, the Company's Board of Directors
authorized the Company to redeem, exchange or repurchase up to an aggregate of
$990 million principal amount of debt securities.
The Company 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
Capital expenditures for the first six months of 2003 totaled $1,073 million
compared to $982 million in 2002. The Company invested $742 million on internal
development and exploration of oil and gas properties during the first six
months of 2003 compared to $484 million in 2002. The Company invested $211
million for property acquisitions in the first six months of 2003 compared to
$417 million in 2002. Property acquisitions during the first six months of 2003
included the acquisition of an additional 50 percent interest in CLAM Petroleum
B.V. for approximately $100 million. For more information on this acquisition,
see Note 9 of Notes to Consolidated Financial Statements. Property acquisitions
during the first six months of 2002 included the purchase of certain assets from
ATCO Gas and Pipelines Ltd., a Canadian regulated gas utility, for approximately
$344 million.
Dividends
On July 23, 2003, the Board of Directors declared a quarterly common stock
cash dividend of $0.15 per share which represents a 9 percent increase over the
previous quarterly dividend of $0.1375 per share. The record and payment dates
for the quarterly dividend are September 10, 2003 and October 10, 2003,
respectively.
15
Application of Critical Accounting Policies
Statement of Financial Accounting Standards (SFAS) No. 141, Business
Combinations, and SFAS No. 142, Goodwill and Intangible Assets, were issued in
June 2001 and became effective July 1, 2001 and January 1, 2002, respectively.
It is our understanding that the Securities and Exchange Commission (SEC) has
questioned other SEC registrants as to whether they properly adopted the
provisions of SFAS No. 141 and SFAS No. 142, with respect to how the costs of
acquiring contractual mineral interests in oil and gas properties should be
classified on the balance sheet. It is also our understanding that the Financial
Accounting Standards Board (FASB), the SEC and others are engaged in
deliberations on the issue of whether SFAS No. 141 and SFAS No. 142 require that
interests held under oil, gas and mineral leases or other contractual
arrangements be classified as intangible assets or as oil and gas properties. If
such interests were deemed intangible assets, mineral interests for undeveloped
and developed leaseholds would be classified separately from oil and gas
properties on the balance sheet but would be aggregated with oil and gas
properties in the Notes to Consolidated Financial Statements in accordance with
SFAS No. 69, Disclosures about Oil and Gas Producing Activities.
Historically, the Company has included all oil and gas leasehold interests as
part of the oil and gas properties. Because this issue is unresolved, the
Company continues to include mineral interests as oil and gas properties on its
balance sheet. At June 30, 2003, the Company had undeveloped and developed
leaseholds of approximately $1.4 billion and $2.4 billion that would have been
classified on the balance sheet as intangible undeveloped leaseholds and
intangible developed leaseholds, respectively, if the interpretation currently
being deliberated had been applied. The reclassification would have no impact on
the Company's results of operations.
Results of Operations - Second Quarter 2003 Compared to Second Quarter 2002
The Company reported net income of $278 million or $1.38 diluted earnings per
common share in the second quarter of 2003 compared to net income of $170
million or $0.84 diluted earnings per common share in 2002. Net income in the
second quarter of 2003 included a net after tax charge of $18 million or $0.09
per diluted share related to the impairment of oil and gas properties. Net
income in the second quarter of 2002 included a net after tax gain of $45
million or $0.23 per diluted share related to the disposal of assets.
Revenues
Revenues increased $276 million to $1,059 million in the second quarter of
2003 compared to $783 million in the second quarter of 2002. As described below,
the $276 million increase in revenues primarily consists of $335 million related
to higher commodity prices, partially offset by $48 million related to lower
sales volumes and $10 million due to the sale of the Val Verde Plant in the
second quarter of 2002. Details of commodity prices AND sales volumes variances
are described below.
Price Variances
Average gas prices, including a $0.07 realized loss per MCF related to
hedging activities, increased $1.74 per MCF in the second quarter of 2003 to
$4.96 per MCF from $3.22 per MCF, including a $0.14 realized gain per MCF
related to hedging activities in the second quarter of 2002. Higher average
natural gas prices resulted in increased revenues of $297 million during the
second quarter of 2003. Average NGLs prices increased $4.67 per barrel in the
second quarter of
16
2003 to $18.53 per barrel from $13.86 per barrel in the second quarter of 2002,
resulting in higher revenues of $27 million during the second quarter of 2003.
Average oil prices, which included no gains or losses related to hedging
activities, increased $2.89 per barrel in the second quarter of 2003 to $27.53
per barrel from $24.64 per barrel in the second quarter of 2002. Higher average
oil prices resulted in increased revenues of $11 million during the second
quarter of 2003.
Volume Variances
Average gas sales volumes decreased 48 MMCF per day in the second quarter of
2003 to 1,879 MMCF per day from 1,927 MMCF per day in the second quarter of
2002, resulting in decreased revenues of $14 million during the second quarter
of 2003. Average oil sales volumes decreased 14.1 MBbls per day in the second
quarter of 2003 to 40.7 MBbls per day from 54.8 MBbls per day in the second
quarter of 2002, reducing revenues $32 million during the second quarter of
2003. Average NGLs sales volumes decreased 1.9 MBbls per day in the second
quarter of 2003 to 63.1 MBbls per day from 65.0 MBbls per day in the second
quarter of 2002, resulting in lower revenues of $2 million from quarter to
quarter. Average gas sales volumes, primarily in the Gulf of Mexico, the Permian
Basin and the U.K. Sector of the North Sea, decreased 170 MMCF per day due to
asset sales in 2002 partially offset by an increase of 122 MMCF per day
primarily as a result of the winter drilling program in Canada, the drilling
program in the Ft. Worth Basin and the plant expansion at Madden in Wyoming.
Average oil sales volumes decreased 20.0 MBbls per day due to asset sales in
2002 primarily in the Gulf of Mexico, the U.K. Sector of the North Sea, Canada
and the Williston Basin partially offset by an increase of 4.0 MBbls per day
resulting from higher production at the Ourhoud Field in Algeria.
Total Costs and Other Income - Net
Total costs and other income - net were $683 million in the second quarter of
2003 compared to $576 million in the second quarter of 2002. The $107 million
increase in total costs and other income - net was primarily due to a $74
million decrease in gain on disposal of assets, a $30 million increase in the
impairment of oil and gas properties, a $20 million increase in transportation
expenses, a $16 million increase in taxes other than income taxes, a $14 million
increase in other expense-net, a $12 million increase in depreciation, depletion
and amortization (DD&A), partially offset by a $52 million decrease in
exploration costs and a $7 million decrease in interest expense.
Gain on disposal of assets decreased primarily due to the divestiture program
initiated by the Company in the second quarter of 2002 and completed in late
2002. The impairment of oil and gas properties increased due to performance
related downward reserve adjustments associated with certain properties
primarily in Canada. Transportation expenses increased primarily due to higher
contract rates primarily resulting from the sale of the Val Verde Plant in 2002.
Taxes other than income taxes increased primarily due to higher production taxes
resulting from higher oil and gas revenues. Other expense-net increased
primarily due to foreign currency transactions, lower interest income and higher
environmental costs. DD&A increased primarily due to higher unit-of-production
rates on the Canadian properties which have higher rates than average
unit-of-production rates for the Company partially offset by the divestiture of
higher cost properties in 2002 and lower gas and oil production volumes.
Exploration costs decreased primarily due to lower drilling rig expenses of $41
million, lower amortization of undeveloped lease costs of $6 million and lower
geological and geophysical and other expenses of $5 million. Interest expense
decreased primarily due to lower debt balances and higher capitalized interest
during the second quarter of 2003.
17
Income Tax Expense
Income taxes were an expense of $98 million in the second quarter of 2003
compared to an expense of $37 million in the second quarter of 2002. The
increase in tax expense was primarily due to higher pretax income. The Company
recorded tax benefits of $11 million in the second quarter of 2003 compared to
$42 million in the second quarter of 2002 related to interest deductions allowed
in both the U.S. and Canada on transactions associated with cross-border
financing. The Company also recorded a net tax benefit of $31 million in second
quarter 2003 related to the closing of the 1996 - 1998 IRS tax audit cycle, the
reversal of tax reserves no longer required due to the audit closure, normal tax
return true-up and adjustments of tax credits. Additionally, in the second
quarter of 2003, the Company resolved all disputes under tax sharing agreements
with certain former affiliates. As a result, during the second quarter of 2003,
the Company recorded a $3 million decrease in income tax expense.
Results of Operations - First Six Months of 2003 Compared to First Six Months of
2002
The Company reported net income of $547 million or $2.70 diluted earnings
per common share in the first six months of 2003 compared to net income of $218
million or $1.08 diluted earnings per common share in the first six months of
2002. Net income in the first six months of 2002 included a net-of-tax
cumulative effect of change in accounting principle charge of $59 million or
$0.30 per diluted earnings per common share related to the adoption of Statement
of Financial Accounting Standards No. 143, Asset Retirement Obligations. See
Note 8 of Notes to Consolidated Financial Statements for more information. Net
income in the first six months of 2003 also included a net after tax charge of
$18 million or $0.09 per diluted share related to the impairment of oil and gas
properties. Net income in the first six months of 2002 included a net after tax
gain of $45 million or $0.23 per diluted share related to the disposal of
assets.
Revenues
Revenues increased $701 million to $2,187 million in the first six months
of 2003 compared to $1,486 million in the first six months of 2002. As described
below, the $701 million increase in revenues primarily consists of $810 million
related to higher commodity prices, $19 million due to higher revenues related
to changes in fair value instruments that do not qualify for hedge accounting,
$13 million due to higher revenues related to ineffectiveness on hedging
activities and $6 million related to higher NGLs sales volumes, partially offset
by $127 million related to lower natural gas and oil sales volumes and $19
million related to the sale of the Val Verde Plant in June 2002.
Price Variances
Average gas prices, including a $0.15 realized loss per MCF related to
hedging activities, increased $2.03 per MCF in the first six months of 2003 to
$5.13 per MCF from $3.10 per MCF, including a $0.26 realized gain per MCF
related to hedging activities in the first six months of 2002. Higher average
natural gas prices resulted in increased revenues of $689 million during the
first six months of 2003. Average NGLs prices increased $7.09 per barrel in the
first six months of 2003 to $20.30 per barrel from $13.21 per barrel in the
first six months of 2002, resulting in higher revenues of $81 million during
first six months of 2003. Average oil prices, including a $0.21 realized loss
per barrel related hedging activities, increased $5.51 per barrel in first six
months of 2003 to $28.61 per barrel from $23.10 per barrel. Higher average oil
prices resulted in increased revenues of $40 million during the first six months
of 2003.
18
Volume Variances
Average gas sales volumes decreased 97 MMCF per day in the first six months
of 2003 to 1,875 MMCF per day from 1,972 MMCF per day in the first six months of
2002, resulting in decreased revenues of $55 million during the first six months
of 2003. Average oil sales volumes decreased 17.3 MBbls per day in the first six
months of 2003 to 40.0 MBbls per day from 57.3 MBbls per day in the first six
months of 2002, reducing revenues $72 million during the first six months of
2003. Average NGLs sales volumes increased 2.7 MBbls per day in the first six
months of 2003 to 63.4 MBbls per day from 60.7 MBbls per day in the first six
months of 2002, resulting in higher revenues of $6 million from period to
period. Average gas sales volumes, primarily in the Gulf of Mexico, the U.K.
Sector of the North Sea and the Permian Basin, decreased 183 MMCF per day due to
asset sales in 2002 partially offset by an increase of 111 MMCF per day
primarily as a result of the winter drilling program in Canada and plant
expansion at Madden in Wyoming. Average oil sales volumes decreased 22.6 MBbls
per day due to asset sales in 2002 primarily in the Gulf of Mexico, Canada, the
U.K. Sector of the North Sea and the Williston Basin partially offset by an
increase of 3.9 MBbls per day resulting from higher production at the Ourhoud
Field in Algeria.
Total Costs and Other Income - Net
Total costs and other income - net were $1,312 million in the first six
months of 2003 compared to $1,218 million in first six months of 2002. The $94
million increase in total costs and other income - net was primarily due to a
$73 million decrease in gain on disposal of assets, a $30 million increase in
the impairment of oil and gas properties, a $33 million increase in
transportation expenses, a $31 million increase in taxes other than income
taxes, a $19 million increase in other expense-net, partially offset by a $41
million decrease in exploration costs, a $34 million decrease in production and
processing expenses, a $15 million decrease in interest expense and a $6 million
decrease in DD&A.
Gain on disposal of assets decreased primarily due to the divestiture program
that was initiated by the Company in the second quarter of 2002 and completed in
late 2002. The impairment of oil and gas properties increased due to performance
related downward reserve adjustments associated with certain properties
primarily in Canada. Transportation expenses increased primarily due to higher
contract rates primarily resulting from the sale of the Val Verde Plant in 2002.
Taxes other than income taxes increased primarily due to higher production taxes
resulting from higher oil and gas revenues. Other expense-net increased
primarily due to foreign currency transactions, lower interest income and higher
environmental costs. Exploration costs decreased primarily due to lower drilling
rig expenses of $38 million, lower amortization of undeveloped lease costs of
$10 million and lower geological and geophysical and other expenses of $9
million partially offset by higher exploratory dry hole costs of $16 million.
Production and processing expenses decreased primarily due to lower well
operating costs related to the Shelf and other asset sales in 2002. Interest
expense decreased primarily due to lower debt balances and higher capitalized
interest during the first six months of 2003. DD&A decreased primarily due to
the divestiture of higher cost properties in 2002 and lower gas and oil
production volumes partially offset by higher unit-of-production rates on the
Canadian properties which have higher rates than average unit-of-production
rates for the Company.
19
Income Tax Expense
Income taxes were an expense of $269 million in the first six months of 2003
compared to $50 million in the first six months of 2002. The increase in tax
expense was primarily due to higher pretax income. The Company also recorded
benefits of $37 million in the first six months of 2003 compared to $55 million
in 2002 related to interest deductions allowed in both the U.S. and Canada on
transactions associated with debt financing entered into in the second half of
2001 and the first quarter of 2002. The Company also recorded a net tax benefit
of $31 million in the first six months of 2003 related to the closing of the
1996 - 1998 IRS tax audit cycle, the reversal of tax reserves no longer required
due to the audit closure, normal tax return true-up and adjustments of tax
credits. Additionally, in the first six months of 2003, the Company resolved all
disputes under tax sharing agreements with certain former affiliates. As a
result, during the first six months of 2003, the Company recorded a $3 million
decrease in income tax expense.
Recent Accounting Pronouncements
In May 2003, the FASB issued SFAS No. 150, Accounting for Certain Financial
Instruments with Characteristics of both Liabilities and Equity (SFAS No. 150).
SFAS No. 150 establishes standards for how an issuer classifies and measures
certain financial instruments with characteristics of both liabilities and
equity. It requires that an issuer classify a financial instrument that is
within its scope as a liability (or an asset in some circumstances). Many of
those instruments were previously classified as equity. SFAS No. 150 is
effective for financial instruments entered into or modified after May 31, 2003,
and otherwise is effective at the beginning of the first interim period
beginning after June 15, 2003. It is to be implemented by reporting the
cumulative effect of a change in an accounting principle for financial
instruments created before the issuance date of SFAS No. 150 and still existing
at the beginning of the interim period of adoption. Restatement is not
permitted. The Company does not expect the requirements of SFAS No. 150 to have
a material impact on its consolidated financial position or results of
operations.
In April 2003, the FASB issued SFAS No. 149, Amendment of Statement No. 133
on Derivative Instruments and Hedging Activities (SFAS No. 149). SFAS No. 149
improves financial reporting by requiring that contracts with comparable
characteristics be accounted for similarly. In particular, SFAS No. 149
clarifies under what circumstances a contract with an initial net investment
meets the characteristic of a derivative, clarifies when a derivative contains a
financing component, amends the definition of an "underlying" to conform it to
language used in FIN No. 45 and amends certain other existing pronouncements.
SFAS No. 149 is effective for contracts entered into or modified after June 30,
2003, and for hedging relationships designated after June 30, 2003. In addition,
with some exceptions, all provisions of SFAS No. 149 should be applied
prospectively. The Company does not expect the requirements of SFAS No. 149 to
have a material impact on its consolidated financial position or results of
operations.
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.
20
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 uses a sensitivity analysis technique to evaluate the
hypothetical effect that changes in the market value of crude oil and natural
gas may have on the fair value of the Company's derivative instruments. For
example, at June 30, 2003, an assumed 10 percent adverse movement in commodity
prices (an increase in the underlying commodities prices) would result in a $136
million increase in the fair value of the net liabilities related to commodity
hedging activities.
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 and foreign exchange rates as of June 30, 2003,
the Company expects to reclassify losses of $64 million ($40 million after tax)
to earnings from the balance in accumulated other comprehensive loss during the
next twelve months. At June 30, 2003, the Company had derivative assets of $11
million and derivative liabilities of $99 million. Of the derivative assets of
$11 million, $6 million are included in Other Current Assets and $5 million are
included in Other Assets 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.
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.
21
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 2002
Form 10-K.
PART II - OTHER INFORMATION
ITEM 1. Legal Proceedings
See Note 5 of Notes to Consolidated Financial Statements.
ITEM 4. Submission of Matters to a Vote of Security Holders
The annual meeting of stockholders was held on April 23, 2003. The following
were nominated and elected to serve as Directors of Burlington Resources Inc.
for a term of one year or until their successors shall have been duly elected
and qualified:
Nominee For Withheld
--------------- ----------- -----------
R. V. Anderson 178,748,109 2,445,238
L. I. Grant 179,262,282 1,931,065
R. J. Harding 178,877,789 2,315,558
J. T. LaMacchia 178,852,879 2,340,468
J. F. McDonald 179,386,731 1,806,616
K. W. Orce 148,295,919 32,897,428
D. M. Roberts 179,254,219 1,939,128
J. F. Schwarz 179,435,034 1,758,313
W. Scott, Jr 178,645,702 2,547,645
B. S. Shackouls 178,655,934 2,537,413
W. E. Wade, Jr 179,462,378 1,730,969
22
ITEM 6. Exhibits and Reports on Form 8-K
A. Exhibits
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.
31.1 Rule 13a-14(a)/15d-14(a) Certification executed by Bobby S.
Shackouls, Chairman of the Board, President and Chief
Executive Officer of the Company
31.2 Rule 13a-14(a)/15d-14(a) Certification executed by Steven J.
Shapiro, Executive Vice President and Chief Financial
Officer of the Company
32.1 Section 1350 Certification
32.2 Section 1350 Certification
* Exhibit incorporated by reference.
B. Reports on Form 8-K
On April 24, 2003, the Company furnished Form 8-K, pursuant to Item
12, Results of Operations, under Item 9, Regulation FD Disclosure (in accordance
with the interim filing guidance for these items), a press release announcing
its earnings results for the first quarter of fiscal year 2003.
Items 2, 3 and 5 of Part II are not applicable and have been omitted.
23
SIGNATURES
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/ STEVEN J. SHAPIRO
---------------------------------
Steven J. Shapiro
Executive Vice President and
Chief Financial Officer
By /S/ JOSEPH P. McCOY
---------------------------------
Joseph P. McCoy
Vice President, Controller and
Chief Accounting Officer
Date: August 7, 2003
24
Exhibit Index
Exhibit No. Description
- ----------- -----------
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.
31.1 Rule 13a-14(a)/15d-14(a) Certification executed by Bobby S.
Shackouls, Chairman of the Board, President and Chief Executive
Officer of the Company
31.2 Rule 13a-14(a)/15d-14(a) Certification executed by Steven J.
Shapiro, Executive Vice President and Chief Financial Officer of
the Company
32.1 Section 1350 Certification
32.2 Section 1350 Certification