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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 March 31, 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 March 31, 2003 200,782,319
PART I - FINANCIAL INFORMATION
ITEM 1. Financial Statements
BURLINGTON RESOURCES INC.
CONSOLIDATED STATEMENT OF INCOME
(UNAUDITED)
FIRST QUARTER
------------------
2003 2002
------- -----
(In Millions, Except per Share Amounts)
Revenues ....................................................................... $ 1,128 $ 703
------- -----
Costs and Other Income - Net
Taxes Other than Income Taxes ............................................... 48 33
Transportation Expense ...................................................... 99 86
Production and Processing ................................................... 102 136
Depreciation, Depletion and Amortization .................................... 203 221
Exploration Costs ........................................................... 68 57
Administrative .............................................................. 42 38
Interest Expense ............................................................ 64 72
(Gain)/Loss on Disposal of Assets ........................................... (1) --
Other Expense (Income) - Net ................................................ 4 (1)
------- -----
Total Costs and Other Income - Net ............................................. 629 642
------- -----
Income Before Income Taxes and Cumulative Effect of Change
in Accounting Principle ..................................................... 499 61
Income Tax Expense ............................................................. 171 13
------- -----
Income Before Cumulative Effect of Change in Accounting Principle .............. 328 48
Cumulative Effect of Change in Accounting Principle - Net ...................... (59) --
------- -----
Net Income ..................................................................... $ 269 $ 48
======= =====
Earnings per Common Share
Basic
Before Cumulative Effect of Change in Accounting Principle ................ $ 1.63 $0.24
Cumulative Effect of Change in Accounting Principle - Net ................. (0.29) --
------- -----
Net Income ................................................................ $ 1.34 $0.24
======= =====
Diluted
Before Cumulative Effect of Change in Accounting Principle ................ $ 1.62 $0.24
Cumulative Effect of Change in Accounting Principle - Net ................. (0.29) --
------- -----
Net Income ................................................................ $ 1.33 $0.24
======= =====
See accompanying Notes to Consolidated Financial Statements.
2
BURLINGTON RESOURCES INC.
CONSOLIDATED BALANCE SHEET
(UNAUDITED)
March 31, December 31,
2003 2002
-------- --------
(In Millions, Except Share Data)
ASSETS
Current Assets
Cash and Cash Equivalents ......................................................... $ 428 $ 443
Accounts Receivable ............................................................... 731 515
Inventories ....................................................................... 62 48
Other Current Assets .............................................................. 43 55
-------- --------
1,264 1,061
-------- --------
Oil & Gas Properties (Successful Efforts Method) .................................... 13,744 12,716
Other Properties .................................................................... 1,198 1,140
-------- --------
14,942 13,856
Accumulated Depreciation, Depletion and Amortization .............................. 5,698 5,353
-------- --------
Properties - Net ................................................................ 9,244 8,503
-------- --------
Goodwill ............................................................................ 864 803
-------- --------
Other Assets ........................................................................ 295 278
-------- --------
Total Assets .................................................................. $ 11,667 $ 10,645
======== ========
LIABILITIES
Current Liabilities
Accounts Payable .................................................................. $ 958 $ 809
Taxes Payable ..................................................................... 68 44
Accrued Interest .................................................................. 64 61
Commodity Hedging Contracts and Other Derivatives ................................. 64 38
Other Current Liabilities ......................................................... 2 7
Current Maturities of Long-term Debt .............................................. 68 63
-------- --------
1,224 1,022
-------- --------
Long-term Debt ...................................................................... 3,859 3,853
-------- --------
Deferred Income Taxes ............................................................... 1,612 1,436
-------- --------
Commodity Hedging Contracts and Other Derivatives ................................... 26 33
-------- --------
Other Liabilities and Deferred Credits .............................................. 674 469
-------- --------
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 ..................................................................... 3,940 3,941
Retained Earnings ................................................................... 1,916 1,675
Deferred Compensation - Restricted Stock ............................................ (19) (9)
Accumulated Other Comprehensive Income (Loss) ....................................... 85 (164)
Cost of Treasury Stock
(40,406,369 and 39,749,431 Shares for 2003 and 2002, respectively) ................. (1,652) (1,613)
-------- --------
Stockholders' Equity ................................................................ 4,272 3,832
-------- --------
Total Liabilities and Stockholders' Equity .................................... $ 11,667 $ 10,645
======== ========
See accompanying Notes to Consolidated Financial Statements.
3
BURLINGTON RESOURCES INC.
CONSOLIDATED STATEMENT OF CASH FLOWS
(UNAUDITED)
FIRST QUARTER
---------------
2003 2002
----- -----
(In Millions)
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income ...................................................................... $ 269 $ 48
Adjustments to Reconcile Net Income to Net Cash
Provided By Operating Activities
Depreciation, Depletion and Amortization ...................................... 203 221
Deferred Income Taxes ......................................................... 136 (1)
Exploration Costs ............................................................. 68 57
Cumulative Effect of Change in Accounting Principle - Net ..................... 59 --
Changes in Derivative Fair Values ............................................. (5) 25
Working Capital Changes
Accounts Receivable ........................................................... (207) --
Inventories ................................................................... (12) (6)
Other Current Assets .......................................................... 13 (10)
Accounts Payable .............................................................. 62 (25)
Taxes Payable ................................................................. 26 50
Accrued Interest .............................................................. 3 19
Other Current Liabilities ..................................................... (7) (4)
Changes in Other Assets and Liabilities ......................................... (19) (13)
----- -----
Net Cash Provided By Operating Activities ................................... 589 361
----- -----
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to Properties ......................................................... (537) (762)
Other ........................................................................... (8) 5
----- -----
Net Cash Used In Investing Activities ....................................... (545) (757)
----- -----
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from Borrowings ........................................................ -- 355
Dividends Paid .................................................................. (28) (28)
Common Stock Purchases .......................................................... (72) --
Common Stock Issuances .......................................................... 23 4
Other ........................................................................... 1 5
----- -----
Net Cash Provided by (Used In) Financing Activities ......................... (76) 336
----- -----
Effect of Exchange Rate Changes on Cash and Cash Equivalents ...................... 17 --
----- -----
DECREASE IN CASH AND CASH EQUIVALENTS ............................................. (15) (60)
CASH AND CASH EQUIVALENTS
Beginning of Year ............................................................... 443 116
----- -----
End of Period ................................................................... $ 428 $ 56
===== =====
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 201 million for the first quarter of
2003 and 2002. 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 for the
first quarter of 2003 and 2002. For the periods ended March 31, 2003 and 2002,
approximately 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 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.
5
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.
Three Months Ended March 31,
----------------------------
2003 2002
------- ------
(In Millions, Except
per Share Amounts)
Net income - as reported ................................. $ 269 $ 48
Pro forma stock based employee compensation cost, after tax 3 3
------- ------
Net income - pro forma ................................... $ 266 $ 45
======= ======
Basic EPS - as reported .................................. $ 1.34 $ 0.24
Basic EPS - pro forma .................................... 1.32 0.23
Diluted EPS - as reported ................................ 1.33 0.24
Diluted EPS - pro forma .................................. $ 1.32 $ 0.23
3. COMPREHENSIVE INCOME (LOSS)
The following table presents comprehensive income (loss).
FIRST QUARTER FIRST QUARTER
----------------------------------
(In Millions) 2003 2002
------------- ------------- -------------
Accumulated other comprehensive loss - Beginning of Period ..................... $(164) $(106)
Net income...................................................................... $ 269 $ 48
----- -----
Other comprehensive loss - net of tax
Hedging activities
Current period changes in fair value of settled contracts ................. (19) 14
Reclassification adjustments for settled contracts ........................ 25 (43)
Changes in fair value of outstanding hedging positions .................... (19) (31)
----- -----
Hedging activities ................................................... (13) (60)
Foreign currency translation
Foreign currency translation adjustments .................................. 262 5
----- -----
Total other comprehensive income (loss) ........................................ 249 249 (55) (55)
----- ----- ----- -----
Comprehensive income (loss) .................................................... $ 518 $ (7)
===== =====
Accumulated other comprehensive income (loss) - End of Period .................. $ 85 $(161)
===== =====
6
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 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.
As of March 31, 2003, the Company had the following derivative instruments
outstanding. The average underlying prices included in the table below represent
hedged prices at various market locations.
Notional Amount
------------------------------------------
Average Fair Value
Settlement Derivative Hedge Gas Electricity US $ Underlying Asset
Period Instrument Strategy (MMBTU) (Megawatts) (in millions) Prices (Liability)
- ------------------------------------------------------------------------------------------------------------------------------------
2003 Swap Cash Flow Hedge 14,474,119 $ 2.82 $ (18)
Purchased Put Cash Flow Hedge 166,375,000 3.31 9
Written Call Cash Flow Hedge 166,375,000 5.17 (44)
Written Put Cash Flow Hedge 162,250,000 2.47 (1)
Swap Fair Value Hedge 2,070,000 3.12 3
N/A Fair Value Hedge (Obligation) 2,070,000 3.19 (3)
Purchased Call Cash Flow Hedge 132,000 43.25 1
Written Put Cash Flow Hedge 132,000 28.38 -
Swap Foreign Currency Hedge $ 13 1.42 -
2004 Swap Cash Flow Hedge 15,610,390 3.01 (15)
Purchased Put Cash Flow Hedge 9,100,000 3.96 3
Written Put Cash Flow Hedge 9,100,000 2.96 (1)
Written Call Cash Flow Hedge 9,100,000 6.82 (2)
Swap Fair Value Hedge 2,166,800 2.83 3
N/A Fair Value Hedge (Obligation) 2,166,800 2.85 (3)
Swap Foreign Currency Hedge 8 1.43 -
2005 Swap Cash Flow Hedge 10,511,522 2.96 (8)
Swap Fair Value Hedge 1,459,200 2.65 2
N/A Fair Value Hedge (Obligation) 1,459,200 2.65 (2)
Swap Not Designated as a Hedge $ 99 1.50 (3)
2006 to
2007 Swap Cash Flow Hedge 1,672,500 $ 3.06 (1)
-----
$ (80)
=====
7
The derivative assets and liabilities represent the difference between
hedged prices and market prices on hedged volumes of the commodities as of March
31, 2003. Hedging activities related to cash settlements decreased revenues $41
million in the first quarter of 2003 and increased revenues $72 million in the
first quarter of 2002. In addition, a non-cash gain of $6 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 quarter of 2003 and 2002, respectively. Also, non-cash losses
of $1 million and $15 million were recorded in revenues associated with
ineffectiveness of cash-flow and fair-value hedges during the first quarter of
2003 and 2002, respectively.
Based on commodity prices and foreign exchange rates as of March 31, 2003,
the Company expects to reclassify losses of $59 million ($36 million after tax)
to earnings from the balance in accumulated other comprehensive loss during the
next twelve months. At March 31, 2003, the Company had derivative assets of $10
million and derivative liabilities of $90 million. Of the derivative assets of
$10 million, $6 million and $4 million are included in Other Current Assets and
Other Assets, respectively, on the Consolidated Balance Sheet.
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
8
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, 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. None of the
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.
9
6. LONG-TERM DEBT
The fair value of the Company's long-term debt at March 31, 2003 and
December 31, 2002 was approximately $4,512 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.
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 first quarter of 2003 compared to $14 million
during the first quarter of 2002.
The following tables present information about the Company's reportable
segments.
First Quarter 2003
------------------------------------------
Other
U.S. Canada International Total
---- ------ ------------- -----
(In Millions)
Revenues ....................................... $555 $526 $47 $1,128
Income before income taxes and cumulative effect
of change in accounting principle........... 309 296 10 615
Capital expenditures ........................... $213 $284 $97 $ 594
First Quarter 2002
-------------------------------------------
Other
U.S. Canada International Total
---- ------ ------------- -----
(In Millions)
Revenues ....................................... $397 $252 $ 54 $703
Income before income taxes and cumulative effect
of change in accounting principle........... 137 34 4 175
Capital expenditures ........................... $ 72 $524 $118 $714
10
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.
First Quarter
--------------------
2003 2002
---- ----
(In Millions)
Income before income taxes and cumulative effect of change in $ 615 $ 175
accounting principle for reportable segments...........................
Corporate expenses......................................................... 48 43
Interest expense.......................................................... 64 72
Other expense (income) - net............................................... 4 (1)
------ -----
Consolidated income before income taxes and cumulative effect of
change in accounting principle........................................ $ 499 $ 61
====== =====
The following is a reconciliation of capital expenditures for reportable
segments to consolidated capital expenditures.
First Quarter
--------------------
2003 2002
---- ----
(In Millions)
Capital expenditures for reportable segments............................... $ 594 $ 714
Administrative capital expenditures........................................ 3 22
----- -----
Consolidated capital expenditures.......................................... $ 597 $ 736
===== =====
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 $314
million at March 31, 2003.
11
For the period ended March 31, 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.
As Pro
Reported Forma
-------- -----
(In Millions, Except Per
Share Data)
Net Income............................................ $ 48 $ 46
Earnings per share:
Basic............................................. 0.24 0.23
Diluted........................................... $0.24 $0.23
9. 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
quarter 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.................. 61
------
Balance-March 31, 2003............................................... $864
======
10. INCOME TAXES
The Company's effective income tax rate increased to 34 percent at March
31, 2003 from 20 percent for the year ended December 31, 2002 primarily due to
higher pretax income. Also, 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.
11. SUBSEQUENT EVENT
In April 2003, the Company's Board of Directors voted to restore the
current Common Stock repurchase authorization level to $1 billion effective May
1, 2003.
ITEM 2. Management's Discussion and Analysis of Financial Condition and Results
of Operations
Outlook
The Company expects second quarter 2003 production volumes to average
between 2,460 and 2,604 MMCFE per day. The key to second quarter 2003
performance will be the impact on production volumes associated with annual
plant maintenance scheduled in the San Juan Basin, Canada, the East Irish Sea
and at the Lost Cabin plant. The pace of new well connections in
12
Canada, south Louisiana and the Ft. Worth Basin and the timing of start-up in
the Algeria MLN Field, which is scheduled for later in second quarter 2003, will
also influence the results. The Company expects full year 2003 production
volumes to average between 2,575 and 2,705 MMCFE per day. The Company targets
the delivery of 3-8 percent long-term production volume growth and expects to
achieve near the bottom of the range in 2003 and near the top of the range in
2004. Accomplishing all of the above referenced goals require successful
execution on the Company's base program, achieving expectations on planned
maintenance downtime and successfully delivering 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 $1.4 billion
on development, exploration and plants and pipeline capital.
Financial Condition and Liquidity
The Company's total debt to total capital (total capital is defined as
total debt and stockholders' equity) ratio at March 31, 2003 and December 31,
2002 was 48 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 March 31,
2003, the Company had $428 million of cash and cash equivalents on hand.
The Company had credit commitments in the form of revolving credit
facilities (revolvers) as of March 31, 2003. The revolvers are comprised of
agreements for $600 million, $400 million and Canadian $468 million (U.S. $318
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 March 31, 2003,
there were no amounts outstanding under the revolvers and no outstanding
commercial paper.
Net cash provided by operating activities during the first quarter of 2003
was $589 million compared to $361 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 production 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. During the first
quarter of 2003, the Company repurchased 1,733,000 shares of its Common Stock
for approximately $79 million. As of March
13
31, 2003, $7 million of the share repurchases were not cash settled. Through
March 31, 2003, the Company has repurchased approximately 18 million shares or
$772 million of its Common Stock under this $1 billion authorization. In April
2003, the Company's Board of Directors voted to restore the current
authorization level to $1 billion effective May 1, 2003.
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 quarter of 2003 totaled $597 million
compared to $736 million in 2002. The Company invested $445 million on internal
development and exploration of oil and gas properties during the first quarter
of 2003 compared to $285 million in 2002. The Company invested $103 million for
property acquisitions in first quarter 2003 compared to $405 million in 2002.
Property acquisitions during the first quarter 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 April 23, 2003, the Board of Directors declared a quarterly common stock
cash dividend of $0.1375 per share, with record and payment dates of June 13,
2003 and July 10, 2003, respectively.
Results of Operations - First Quarter 2003 Compared to First Quarter 2002
The Company reported net income of $269 million or $1.33 diluted earnings
per common share in first quarter 2003 compared to net income of $48 million or
$0.24 diluted earnings per common share in 2002. Net income in 2003 included a
net-of-tax cumulative effect of change in accounting principle charge of $59
million or $0.29 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.
14
Revenues
Revenues increased $425 million to $1,128 million in first quarter 2003
compared to $703 million in first quarter 2002. The $425 million increase in
revenues primarily consists of $480 million related to higher commodity prices
and NGLs volumes, $16 million related to changes in the fair value of derivative
instruments that do not qualify for hedge accounting and $14 million related to
ineffectiveness on cash-flow and fair-value hedges, partially offset by $80
million related to lower gas and oil production volumes and $9 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 $0.23 realized loss per MCF related to
hedging activities, increased $2.30 per MCF in first quarter 2003 to $5.29 per
MCF from $2.99 per MCF, including a $0.38 realized gain per MCF related to
hedging activities, in first quarter 2002. Higher average natural gas prices
increased revenues $388 million during first quarter 2003. Average NGLs prices
increased $9.62 per barrel in first quarter 2003 to $22.07 per barrel from
$12.45 per barrel in first quarter 2002, resulting in higher revenues of $56
million during first quarter 2003. Average oil prices, including a $0.44
realized loss per barrel related hedging activities, increased $8.06 per barrel
in first quarter 2003 to $29.74 per barrel from $21.68 per barrel, including a
$0.58 realized gain per barrel related to hedging activities, in first quarter
2002. Higher average oil prices resulted in increased revenues of $28 million
during first quarter 2003.
Volume variances
Average gas sales volumes decreased 147 MMCF per day in first quarter 2003
to 1,872 MMCF per day from 2,019 MMCF per day in first quarter 2002, resulting
in decreased revenues of $40 million during first quarter 2003. Average oil
sales volumes decreased 20.6 MBbls per day in first quarter 2003 to 39.3 MBbls
per day from 59.9 MBbls per day in first quarter 2002, reducing revenues $40
million during first quarter 2003. Average NGLs sales volumes increased 7.4
MBbls per day in first quarter 2003 to 63.7 MBbls per day from 56.3 MBbls per
day in first quarter 2002, resulting in higher revenues of $8 million from
quarter to quarter. Average gas sales volumes in San Juan, Gulf Coast and Other
International decreased 214 MMCF per day primarily due to asset sales in 2002
and natural declines, partially offset by an increase of 61 MMCF per day
primarily as a result of the aggressive winter drilling program in Canada.
Average oil sales volumes decreased 19.5 MBbls per day primarily due to asset
sales in 2002 and natural declines in the Mid-Continent and Canada. Average NGLs
sales volumes in San Juan increased 9.0 MBbls per day primarily due to higher
liquid recoveries.
Total Costs and Other Income - Net
Total costs and other income - net were $629 million in first quarter 2003
compared to $642 million in first quarter 2002. The $13 million decrease was
primarily due to a $34 million decrease in production and processing expenses,
an $18 million decrease in depreciation, depletion and amortization (DD&A), an
$8 million decrease in interest expense and a $1 million increase in gain on
disposal of assets, partially offset by a $15 million increase in taxes other
than income taxes, a $13 million increase in transportation expenses, an $11
million increase in exploration costs, a $5 million increase in other expense,
and a $4 million increase in administrative (G&A) expenses.
15
Production and processing expenses decreased primarily due to lower well
operating costs related to the Shelf and other asset sales in 2002. DD&A
decreased primarily due to the divestiture of higher cost properties in 2002 and
lower gas and oil production volumes. Interest expense decreased primarily due
to lower debt balances during the first quarter of 2003. Taxes other than income
taxes increased primarily due to higher production taxes resulting from higher
oil and gas revenues. Transportation expenses increased primarily due to higher
contract rates primarily resulting from the sale of the Val Verde Plant.
Exploration costs increased primarily due to higher exploratory dry hole costs
of $16 million and higher drilling rig expenses of $3 million, partially offset
by lower geological and geophysical and other expenses of $4 million and lower
amortization of undeveloped lease costs of $4 million. Other expenses increased
primarily due to foreign currency transactions and lower interest income. G&A
expenses increased primarily due to higher insurance expense and other
miscellaneous expenses.
Income Tax Expense
Income taxes were an expense of $171 million in first quarter 2003 compared
to an expense of $13 million in first quarter 2002. The increase in tax expense
was primarily due to higher pretax income. The Company recorded tax benefits of
$26 million in first quarter 2003 compared to $13 million in first quarter 2002
related to interest deductions allowed in both the U.S. and Canada on
transactions associated with cross-border financing. The Company recorded no
Section 29 Tax Credits in 2003 compared to $3 million in 2002.
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 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 March 31, 2003, an assumed 10 percent adverse movement in commodity
prices (an increase in the underlying commodities prices) would result in a $127
million increase in the fair value of the net liabilities related to commodity
hedging activities.
16
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 March 31, 2003,
the Company expects to reclassify losses of $59 million ($36 million after tax)
to earnings from the balance in accumulated other comprehensive loss during the
next twelve months. At March 31, 2003, the Company had derivative assets of $10
million and derivative liabilities of $90 million. Of the derivative assets of
$10 million, $6 million and $4 million are included in Other Current Assets and
Other Assets, respectively, on the Consolidated Balance Sheet.
ITEM 4. Controls and Procedures
Within 90 days prior to the date of this report, 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-14(c) and 15d-14(c) to the
Securities Exchange Act of 1934, as amended). Based on this evaluation, the
Company's Chief Executive Officer and Chief Financial Officer believe that the
disclosure controls and procedures are effective 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 were no significant changes in the Company's internal controls or
other factors that could significantly affect internal controls subsequent to
the date of the most recently completed evaluation.
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.
17
PART II - OTHER INFORMATION
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
3.1* By-Laws of Burlington Resources Inc. amended
as of March 1, 2003 (Exhibit 3.2 to Form
10-K, filed March 12, 2003)
4.1* 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.
99.1 Certification accompanying Quarterly Report
pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002 executed by Bobby
S. Shackouls, Chairman of the Board,
President and Chief Executive Officer of the
Company
99.2 Certification accompanying Quarterly Report
pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002 executed by
Steven J. Shapiro, Executive Vice President
and Chief Financial Officer of the Company
* Exhibit incorporated by reference.
B. Reports on Form 8-K
On March 13, 2003, the Company filed Form 8-K/A amending the
Current Report on Form 8-K filed by the Company on August 22, 2001.
On March 13, 2003, the Company filed Form 8-K/A amending the
Current Report on Form 8-K filed by the Company on February 21, 2002.
Items 1, 2, 3, 4 and 5 of Part II are not applicable and have been omitted.
18
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: May 7, 2003
CERTIFICATIONS
I, Bobby S. Shackouls, certify that:
1. I have reviewed this quarterly report on Form 10-Q of Burlington Resources
Inc.;
2. Based on my knowledge, this quarterly report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to make
the statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this quarterly
report;
3. Based on my knowledge, the financial statements, and other financial
information included in this quarterly report, fairly present in all material
respects the financial condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this quarterly report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:
a) designed such disclosure controls and procedures to ensure that material
information relating to the registrant, including its consolidated subsidiaries,
is made known to us by others within those entities, particularly during the
period in which this quarterly report is being prepared;
19
b) evaluated the effectiveness of the registrant's disclosure controls and
procedures as of a date within 90 days prior to the filing date of this
quarterly report (the "Evaluation Date"); and
c) presented in this quarterly report our conclusions about the effectiveness of
the disclosure controls and procedures based on our evaluation as of the
Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based on our
most recent evaluation, to the registrant's auditors and the audit committee of
registrant's board of directors (or persons performing the equivalent function):
a) all significant deficiencies in the design or operation of internal controls
which could adversely affect the registrant's ability to record, process,
summarize and report financial data and have identified for the registrant's
auditors any material weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal controls; and
6. The registrant's other certifying officers and I have indicated in this
quarterly report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal controls
subsequent to the date of our most recent evaluation, including any corrective
actions with regard to significant deficiencies and material weaknesses.
Date: May 7, 2003 /s/ BOBBY S. SHACKOULS
-------------------------------------------
Bobby S. Shackouls
Chairman of the Board, President and Chief
Executive Officer
CERTIFICATIONS
I, Steven J. Shapiro, certify that:
1. I have reviewed this quarterly report on Form 10-Q of Burlington Resources
Inc.;
2. Based on my knowledge, this quarterly report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to make
the statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this quarterly
report;
3. Based on my knowledge, the financial statements, and other financial
information included in this quarterly report, fairly present in all material
respects the financial condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this quarterly report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:
20
a) designed such disclosure controls and procedures to ensure that material
information relating to the registrant, including its consolidated subsidiaries,
is made known to us by others within those entities, particularly during the
period in which this quarterly report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls and
procedures as of a date within 90 days prior to the filing date of this
quarterly report (the "Evaluation Date"); and
c) presented in this quarterly report our conclusions about the effectiveness of
the disclosure controls and procedures based on our evaluation as of the
Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based on our
most recent evaluation, to the registrant's auditors and the audit committee of
registrant's board of directors (or persons performing the equivalent function):
a) all significant deficiencies in the design or operation of internal controls
which could adversely affect the registrant's ability to record, process,
summarize and report financial data and have identified for the registrant's
auditors any material weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal controls; and
6. The registrant's other certifying officers and I have indicated in this
quarterly report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal controls
subsequent to the date of our most recent evaluation, including any corrective
actions with regard to significant deficiencies and material weaknesses.
Date: May 7, 2003 /s/ STEVEN J. SHAPIRO
--------------------------------------
Steven J. Shapiro
Executive Vice President and
Chief Financial Officer
21
EXHIBIT INDEX
Exhibit Nature of Exhibit
3.1* By-Laws of Burlington Resources Inc. amended
as of March 1, 2003 (Exhibit 3.2 to Form
10-K, filed March 12, 2003)
4.1* 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.
99.1 Certification accompanying Quarterly Report
pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002 executed by Bobby
S. Shackouls, Chairman of the Board,
President and Chief Executive Officer of the
Company
99.2 Certification accompanying Quarterly Report
pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002 executed by
Steven J. Shapiro, Executive Vice President
and Chief Financial Officer of the Company
* Exhibit incorporated by reference.
22