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, 2001
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 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, 2001 206,892,247
PART I - FINANCIAL INFORMATION
ITEM 1. Financial Statements
BURLINGTON RESOURCES INC.
CONSOLIDATED STATEMENT OF INCOME
(UNAUDITED)
SECOND QUARTER SIX MONTHS
------------------------- -------------------------
2001 2000 2001 2000
-------- -------- -------- --------
(In Millions, Except per Share Amounts)
Revenues........................................................................ $ 917 $ 680 $ 2,060 $ 1,388
------- ------- --------- --------
Costs and Expenses
Production Taxes................................................................ 44 38 107 71
Transportation Expense.......................................................... 64 60 127 115
Production and Processing....................................................... 121 123 241 239
Depreciation, Depletion and Amortization........................................ 174 171 344 351
Exploration Costs............................................................... 52 48 122 146
Administrative.................................................................. 37 39 83 78
------- ------- --------- --------
Total Costs and Expenses........................................................ 492 479 1,024 1,000
------- ------- --------- --------
Operating Income................................................................ 425 201 1,036 388
Interest Expense................................................................ 46 53 91 103
Other Expense (Income) - Net.................................................... (1) 10 8 10
------- ------- --------- --------
Income Before Income Taxes...................................................... 380 138 937 275
Income Tax Expense.............................................................. 149 44 373 104
------- ------- --------- --------
Net Income Before Cumulative Effect of Change in Accounting Principle........... 231 94 564 171
Cumulative Effect of Change in Accounting Principle - Net....................... - - 3 -
------- ------- --------- --------
Net Income...................................................................... $ 231 $ 94 $ 567 $ 171
======= ======= ========= ========
Earnings per Common Share
Basic
Before Cumulative Effect of Change in Accounting Principle................. $ 1.10 $ .43 $ 2.66 $ .79
Cumulative Effect of Change in Accounting Principle - Net.................. - - .01 -
------- ------- --------- --------
Net Income................................................................. $ 1.10 $ .43 $ 2.67 $ .79
======= ======= ========= ========
Diluted
Before Cumulative Effect of Change in Accounting Principle................. $ 1.10 $ .43 $ 2.65 $ .78
Cumulative Effect of Change in Accounting Principle - Net.................. - - .01 -
-------- ------- --------- --------
Net Income................................................................. $ 1.10 $ 43 $ 2.66 $ .78
======== ======= ========= ========
See accompanying Notes to Consolidated Financial Statements.
2
BURLINGTON RESOURCES INC.
CONSOLIDATED BALANCE SHEET
(UNAUDITED)
June 30, December 31,
2001 2000
----------------- -----------------
(In Millions, Except Share Data)
ASSETS
Current Assets
Cash and Cash Equivalents..................................................... $ 586 $ 132
Accounts Receivable........................................................... 591 809
Commodity Hedging Contracts and Other Derivatives............................. 118 -
Inventories................................................................... 48 45
Other Current Assets.......................................................... 20 25
----------------- -----------------
1,363 1,011
----------------- -----------------
Oil & Gas Properties (Successful Efforts Method)................................ 13,547 13,118
Other Properties................................................................ 1,087 1,019
----------------- -----------------
14,634 14,137
Accumulated Depreciation, Depletion and Amortization.......................... 8,154 7,830
----------------- -----------------
Properties - Net............................................................ 6,480 6,307
----------------- -----------------
Commodity Hedging Contracts and Other Derivatives............................... 8 -
----------------- -----------------
Other Assets.................................................................... 199 188
----------------- -----------------
Total Assets.............................................................. $ 8,050 $ 7,506
================= =================
LIABILITIES
Current Liabilities
Accounts Payable.............................................................. $ 611 $ 619
Commodity Hedging Contracts and Other Derivatives............................. 30 -
Taxes Payable................................................................. 140 55
Accrued Interest.............................................................. 43 33
Dividends Payable............................................................. 29 30
Other Current Liabilities..................................................... 17 21
----------------- -----------------
870 758
----------------- -----------------
Long-term Debt.................................................................. 2,354 2,301
----------------- -----------------
Deferred Income Taxes........................................................... 523 266
----------------- -----------------
Commodity Hedging Contracts and Other Derivatives............................... 8 -
----------------- -----------------
Other Liabilities and Deferred Credits.......................................... 417 431
----------------- -----------------
Commitments and Contingent Liabilities
STOCKHOLDERS' EQUITY
Preferred Stock, Par Value $.01 per Share
(Authorized 75,000,000 Shares; One Share Issued)............................. - -
Common Stock, Par Value $.01 per Share
(Authorized 325,000,000 Shares; Issued 241,188,693 Shares)................... 2 2
Paid-in Capital................................................................. 3,944 3,944
Retained Earnings............................................................... 1,392 884
Deferred Compensation - Restricted Stock........................................ (14) (5)
Accumulated Other Comprehensive Loss............................................ (47) (70)
Cost of Treasury Stock
(34,296,446 and 25,619,893 Shares for 2001 and 2000, respectively)............. (1,399) (1,005)
----------------- -----------------
Stockholders' Equity............................................................ 3,878 3,750
----------------- -----------------
Total Liabilities and Stockholders' Equity................................ $ 8,050 $ 7,506
================= =================
See accompanying Notes to Consolidated Financial Statements.
3
BURLINGTON RESOURCES INC.
CONSOLIDATED STATEMENT OF CASH FLOWS
(UNAUDITED)
SIX MONTHS
---------------------------
2001 2000
----------- ----------
(In Millions)
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income.....................................................................$ 567 $ 171
Adjustments to Reconcile Net Income to Net Cash
Provided By Operating Activities
Depreciation, Depletion and Amortization..................................... 344 351
Deferred Income Taxes........................................................ 239 74
Exploration Costs............................................................ 122 146
Changes in Derivative Fair Values............................................ (36) -
Working Capital Changes
Accounts Receivable.......................................................... 217 (7)
Inventories.................................................................. (3) 2
Other Current Assets......................................................... 4 (6)
Accounts Payable............................................................. (33) (76)
Taxes Payable................................................................ 89 (36)
Accrued Interest............................................................. 10 (3)
Other Current Liabilities.................................................... (6) (3)
Other.......................................................................... (25) -
------------ -----------
Net Cash Provided By Operating Activities.................................. 1,489 613
------------ -----------
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to Properties........................................................ (657) (451)
Other.......................................................................... 9 (37)
------------ -----------
Net Cash Used In Investing Activities...................................... (648) (488)
------------ -----------
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from Borrowings....................................................... 400 370
Reduction in Borrowings........................................................ (341) (531)
Dividends Paid................................................................. (59) (30)
Common Stock Purchases......................................................... (418) (59)
Common Stock Issuances......................................................... 37 35
Other.......................................................................... (6) 12
------------ -----------
Net Cash Used In Financing Activities...................................... (387) (203)
------------ -----------
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS................................ 454 (78)
CASH AND CASH EQUIVALENTS
Beginning of Year.............................................................. 132 89
------------ -----------
End of Period..................................................................$ 586 $ 11
============ ===========
See accompanying Notes to Consolidated Financial Statements.
4
BURLINGTON RESOURCES INC.
Notes TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
1. BASIS OF PRESENTATION
The 2000 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 210 million and 216 million for the
second quarter of 2001 and 2000, respectively, and 212 million and 216 million
for the first six months of 2001 and 2000, 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 211 million and 216 million for the second quarter
of 2001 and 2000, respectively, and 213 million and 217 million for the first
six months of 2001 and 2000, respectively. No adjustments were made to reported
net income in the computation of EPS.
5
2. COMPREHENSIVE INCOME
The following table presents comprehensive income for the first six months
of 2001.
SIX MONTHS
2001
----------------------------
(In Millions)
Accumulated other comprehensive loss - December 31, 2000............................ $ (70)
Net income.......................................................................... $ 567
------------
Other comprehensive income - net of tax
Hedging activities
Cumulative effect of change in accounting principle - January 1, 2001..... (366)
Reclassification adjustments for settled contracts........................ 264
Current period changes in fair value of settled contracts................. 56
Changes in fair value of outstanding hedging positions.................... 75
------------
Hedging activities................................................... 29
Foreign currency translation
Foreign currency translation adjustments.................................. (6)
------------
Total other comprehensive income.................................................... 23 23
------------ ------------
Comprehensive income................................................................ $ 590
============
Accumulated other comprehensive loss - June 30, 2001................................ $ (47)
============
In the first six months of 2000, comprehensive income was $161 million
consisting of $171 million of net income and $10 million of losses from foreign
currency translation adjustments.
3. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES
The Company enters into derivative contracts, primarily options and swaps,
to hedge future crude oil and natural gas production in order to mitigate the
risk of market price fluctuations. The Company also enters into derivative
contracts to mitigate the risk of foreign currency exchange rate fluctuations.
On January 1, 2001, the Company adopted Financial Accounting Standards No. 133,
as amended, Accounting for Derivative Instruments and Hedging Activities ("SFAS
No. 133"). Effective with the adoption of SFAS No. 133, all derivatives are
recognized on the balance sheet and measured at fair value. If the derivative
does not qualify as a hedge or is not designated as a hedge, the gain or loss on
the derivative is recognized currently in earnings. If the derivative qualifies
6
for hedge accounting, the gain or loss on the derivative is either recognized in
income along with an offsetting adjustment to the basis of the item being hedged
or deferred in other comprehensive income to the extent the hedge is effective.
To qualify for hedge accounting, the derivative must qualify as either a
fair-value, cash-flow or foreign-currency hedge.
The hedging relationship between the hedging instruments and hedged items
must be highly effective in achieving the offset of changes in fair values or
cash flows attributable to the hedged risk both at the inception of the hedge
and on an ongoing basis. The Company measures hedge effectiveness on a quarterly
basis. Hedge accounting is discontinued prospectively when a hedging instrument
becomes ineffective. Gains and losses deferred in accumulated other
comprehensive income related to cash flow hedge derivatives that become
ineffective remain unchanged until the related production is delivered.
Adjustment to the carrying amounts of hedged production is discontinued in
instances where the related fair-value hedging instrument becomes ineffective.
The balance in the fair-value hedge adjustment account is recorded in income
when the related production is delivered. If the Company determines that it is
probable that a hedged forecasted transaction will not occur, deferred gains or
losses on the hedging instrument are recognized in earnings immediately.
Gains and losses on hedging instruments and adjustments of the carrying
amounts of hedged production are included in crude oil and natural gas revenues
and are included in realized prices in the period that the related production is
delivered. Gains and losses on hedging instruments which represent hedge
ineffectiveness and gains and losses on derivative instruments which do not
qualify for hedge accounting are included in other revenues in the period in
which they occur.
The Company enters into gas swap agreements to fix the prices of
anticipated future natural gas production and enters into gas swap agreements
that convert its production back to market sensitive positions when matched
against fixed-price gas sales. The Company enters into natural gas basis swap
agreements to fix the sales price differential between the Company's marketing
locations and NYMEX Henry Hub. The Company enters into natural gas option
agreements to establish floor and ceiling prices on anticipated future natural
gas production. The Company also enters into natural gas option agreements to
establish floor and ceiling prices on anticipated future natural gas production
while allowing the Company to participate in upward price movements above a
specified non-participation range. Generally, the Company does not receive net
premiums on its option hedging strategies.
The Company also enters into crude oil swap agreements to fix the price of
anticipated future crude oil production and purchases call options agreements
that allow the Company to participate in market price increases that exceed
hedge prices established when the Company enters into a swap.
7
As of June 30, 2001, the Company had the following natural gas volumes
hedged.
Natural Gas Fixed-Price Swaps
Average Fair Value
Production Volumes Strike Liability
Period (MMBTU) Price (In Millions)
--------------- ------------------ ---------------- --------------------
2001 16,864,880 $2.55 $(14)
2002 11,861,175 3.02 (6)
2003 to 2007 23,742,340 $3.39 $ (1)
Natural Gas Basis Swaps
Average Fair Value
Production Volumes Basis Asset
Period (MMBTU) Differential (In Millions)
--------------- ------------------ ---------------- --------------------
2001 5,049,880 $1.18 $ 6
2002 9,331,175 .17 4
2003 to 2007 23,742,340 $(.19) $ 3
Natural Gas Options
Average Fair Value
Production Volumes Strike Asset/(Liability)
Period Option Type (MMBTU) Price (In Millions)
- --------------- ------------------- ------------------- ---------------- ---------------------
2001 Puts purchased 74,520,000 $ 3.99 $ 72
2001 Calls sold 74,520,000 7.89 -
2001 Calls purchased 51,520,000 10.35 -
2002 Puts purchased 57,450,000 3.91 46
2002 Calls sold 57,450,000 7.85 (1)
2002 Calls purchased 30,250,000 $ 10.80 $ -
As of June 30, 2001, the fair value of the swap agreements the Company had
entered into in order to convert the Company's fixed-price gas sales contracts
to market sensitive positions was a $1 million asset offset by a $1 million
liability basis adjustment to the carrying value of the fixed-price gas sales
contracts. These arrangements are recorded as a revision to gas price in periods
the production is delivered. All firm commitments qualified as fair-value hedges
during the first six months of 2001.
As of June 30, 2001, the Company had the following crude oil volumes
hedged.
Crude Oil Swaps
Average Fair Value
Production Volumes Strike Liability
Period (Barrels) Price (In Millions)
--------------- ----------------- ---------------- --------------------
2001 8,280,000 $19.95 $(48)
2002 180,000 $21.91 $ (1)
8
Crude Oil Call Options
Average Fair Value
Production Volumes Strike Asset
Period (Barrels) Price (In Millions)
--------------- ------------------ ---------------- --------------------
2001 5,520,000 $19.69 $ 34
2002 180,000 $19.89 $ 1
The derivative assets and liabilities represent the difference between
hedged prices and market prices on hedged volumes of the commodities as of June
30, 2001. Hedging activities reduced natural gas and crude oil revenues by $405
million and $21 million, respectively, during the first six months of 2001. In
addition, during the first six months, gains of $30 million were recorded in
revenues associated with ineffectiveness of cash-flow and fair-value hedges and
gains on derivative instruments which do not qualify for hedge accounting. There
were no discontinued cash-flow hedges during the first six months of 2001.
In addition to hedges of commodity prices, the Company also has foreign
currency swaps to hedge its exposure to exchange rate fluctuations at one of its
Canadian subsidiaries. As of June 30, 2001, the Company had $7 million of
liabilities related to foreign currency exchange rate hedges.
In accordance with the transition provisions of SFAS No. 133, on January 1,
2001, the Company recorded a net-of-tax cumulative-effect-type loss adjustment
of $366 million in accumulated other comprehensive income to recognize at fair
value all derivatives that are designated as cash-flow hedging instruments. The
Company recorded cash-flow hedge derivatives liabilities of $582 million ($361
million after tax), fair value hedge derivative assets of $16 million ($10
million after tax), related liability adjustments to book value of fair-value
hedged items of $16 million ($10 million after tax) and a $3 million after tax
non-cash gain was recorded in current earnings as a cumulative effect of
accounting change.
During the first six months of 2001, losses of $426 million ($264 million
after tax) were transferred from accumulated other comprehensive income to
earnings related to settlements of oil and gas price hedging contracts, credit
adjustments of $90 million ($56 million after tax) were made to accumulated
other comprehensive income to reflect current period changes in fair value of
settled contracts, and the fair value of outstanding hedging position
liabilities decreased $121 million ($75 million after tax) resulting in an
ending balance of a $47 million credit ($29 million after tax) related to
hedging activities in accumulated other comprehensive income at June 30, 2001.
Based on commodity prices and foreign exchange rates as of June 30, 2001, the
Company expects to reclassify gains of $36 million ($22 million after tax) to
earnings from the balance in accumulated other comprehensive income during the
next twelve months. As of June 30, 2001, the Company had cash-flow hedge
derivative assets of $103 million and derivative liabilities of $31 million (a
net asset of $44 million after tax). The Company had liabilities and assets
related to fair-value hedges of $7 million and $8 million, respectively. The
Company also had commodity-related derivative instruments that do not qualify
for hedge accounting with related assets of $16 million and liabilities of $1
million.
4. COMMITMENTS AND CONTINGENT LIABILITIES
The Company and numerous other oil and gas companies have been named as
defendants in various lawsuits alleging violations of the civil False Claims
9
Act. These lawsuits have been consolidated by the United States Judicial Panel
on Multidistrict Litigation for pre-trial proceedings 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. 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.
Various administrative proceedings are also pending before the MMS of the
United States Department of the Interior with respect to the valuation of oil
and 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.
Based on the Company's present understanding of the various governmental
and False Claims Act proceedings described above, the Company believes that it
has substantial defenses to these claims and intends to vigorously assert such
defenses. However, in the event that the Company is found to have violated the
civil False Claims Act, the Company could be subject to monetary damages and a
variety of sanctions, including double damages, substantial monetary fines,
civil penalties and a temporary suspension from entering into future federal
mineral leases and other federal contracts for a defined period of time. 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 of the Company, although results of operations
and 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, in the Court of Appeal in The Hague in the Netherlands. Plaintiffs, who
are working interest owners in the Q1 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 Q1 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. For all relevant periods, the Company owned a 37.5%
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 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. 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.
10
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. While the
outcome of these other lawsuits and proceedings cannot be predicted with
certainty, management believes these other matters will not have a material
adverse effect on the consolidated financial position, results of operations or
cash flows of the Company.
5. LONG-TERM DEBT
On February 12, 2001, the Company issued $400 million of fixed-rate debt
with an interest rate of 6.68 percent due February 2011. During the first six
months of 2001, the Company retired $325 million of commercial paper and also
repaid $16 million of fixed-rate debt.
6. PROPERTY ACQUISITIONS
During the first quarter of 2001, the Company purchased from DIFCO Limited
an additional 10 percent interest in 7 fields in the East Irish Sea for $25
million. The Company is the operator of the properties and now owns 100 percent
of the assets. In January 2001, the Company's Canadian subsidiary, Burlington
Resources Canada Energy Ltd. ("BRCEL"), acquired approximately 46 billion cubic
feet of gas equivalent ("BCFE") of proved reserves from Petrobank Energy and
Resources Ltd. for $57 million. In January 2001, the Company also announced that
BRCEL entered into an agreement with ATCO Gas, a regulated gas utility, to
acquire properties in the Viking-Kinsella area of Alberta, Canada for
approximately $328 million. The properties have net proved reserves of
approximately 251 BCFE. During the second quarter, the Alberta Energy and
Utilities Board ( the "AEUB") denied an application by ATCO Gas for the proposed
sale of the properties. Reasons for the AEUB's decision have not yet been
released. The Company will evaluate its alternatives once these reasons are
known.
7. SEGMENT AND GEOGRAPHIC INFORMATION
The Company's reportable segments are North America and International. Both
segments are engaged principally in the exploration, development, production and
marketing of oil and gas. The North America segment is responsible for the
Company's operations in the USA and Canada and the International segment is
responsible for all operations outside that geographical region. 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 Form 10-K. There are
no significant intersegment sales or transfers.
11
The following tables present information about reported segment operations.
Second Quarter
----------------------------------------------------------------------------------------------
2001 2000
------------------------------------------- ------------------------------------------------
------------------- ----------------------
North America North America
------------------- ----------------------
USA Canada International Total USA Canada International Total
------- ------ ------------- --------- ------ ------ ------------- ----------
(In Millions) (In Millions)
Revenues $612 $263 $42 $ 917 $ 492 $ 148 $ 40 $ 680
Operating income (loss) $322 $146 $(1) $ 467 $ 187 $ 47 $ 9 $ 243
Six Months
----------------------------------------------------------------------------------------------
2001 2000
------------------------------------------- ------------------------------------------------
------------------ ------------------
North America North America
------------------ ------------------
USA Canada International Total USA Canada International Total
------- ------ ------------- --------- ------ ------ ------------- ---------
(In Millions) (In Millions)
Revenues $ 1,355 $608 $97 $ 2,060 $ 1,001 $ 292 $ 95 $1,388
Operating income $ 722 $384 $23 $ 1,129 $ 363 $ 78 $ 34 $ 475
The following is a reconciliation of segment operating income to
consolidated income before income taxes.
Second Quarter Six Months
-------------------------- --------------------------
2001 2000 2001 2000
------------ ------------ ------------ ------------
(In Millions) (In Millions)
Total operating income of reportable segments $ 467 $ 243 $1,129 $ 475
Corporate expenses 42 42 93 87
Interest expense 46 53 91 103
Other expense (income) - net (1) 10 8 10
-------------------------- --------------------------
Consolidated income before income taxes $ 380 $ 138 $ 937 $ 275
========================== ==========================
ITEM 2. Management's Discussion and Analysis of Financial Condition and Results
of Operations
Financial Condition and Liquidity
The Company's long-term debt to total capital ratio at June 30, 2001 and
December 31, 2000 was 38 percent. On February 12, 2001, the Company issued $400
million of fixed-rate debt with an interest rate of 6.68 percent due February
2011. During the first six months of 2001, the Company retired $325 million of
commercial paper and also repaid $16 million of fixed-rate debt. On July 10,
2001, the Company's board of directors authorized the Company to redeem or
repurchase up to $1 billion principal amount of debt securities of the Company.
The Company had unused credit commitments in the form of revolving credit
facilities ("revolvers") as of June 30, 2001. These 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 classified as long-term debt.
The revolvers are comprised of agreements for $600 million, $400 million and
12
$328 million. The $600 million revolver expires in February 2003 and the $400
million and $328 million revolvers expire in March 2002 unless renewed by mutual
consent. The Company has the option to convert the outstanding balances on the
$400 million and $328 million revolvers to one year term notes at expiration of
the agreements. The Company has a $1.5 billion shelf registration statement on
file with the Securities and Exchange Commission.
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
six months of 2001, the Company repurchased approximately 10 million shares of
its Common Stock for approximately $447 million. As of June 30, 2001, $29
million of the share repurchases were not cash settled.
Net cash provided by operating activities during the first six months of
2001 was $1,489 million compared to $613 million in 2000. The increase was
primarily due to higher operating income and lower working capital needs.
Operating income was higher principally as a result of higher commodity prices.
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 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 2001 totaled $655 million
compared to $465 million in 2000. The Company invested $489 million on internal
development and exploration of oil and gas properties during the first six
months of 2001 compared to $419 million in 2000. The Company invested $92
million for property acquisitions in the first six months of 2001 compared to
$11 million in 2000. The Company also invested $65 million in plants and
pipelines during the first six months compared to $23 million in 2000.
During the first quarter of 2001, the Company purchased from DIFCO Limited
an additional 10 percent interest in 7 fields in the East Irish Sea for $25
million. The Company is the operator of the properties and now owns 100 percent
of the assets. In January 2001, the Company's Canadian subsidiary, Burlington
Resources Canada Energy Ltd. ("BRCEL"), acquired approximately 46 billion cubic
feet of gas equivalent ("BCFE") of proved reserves from Petrobank Energy and
Resources Ltd. for $57 million. In January 2001, the Company also announced that
BRCEL entered into an agreement with ATCO Gas, a regulated gas utility, to
acquire properties in the Viking-Kinsella area of Alberta, Canada for
approximately $328 million. The properties have net proved reserves of
approximately 251 BCFE. During the second quarter, the Alberta Energy and
Utilities Board ( the "AEUB") denied an application by ATCO Gas for the proposed
sale of the properties. Reasons for the AEUB's decision have not yet been
released. The Company will evaluate its alternatives once these reasons are
known.
13
Dividends
On July 18, 2001, the Board of Directors declared a quarterly common stock
cash dividend of $.1375 per share, payable October 1, 2001.
Results of Operations - Second Quarter 2001 Compared to Second Quarter 2000
The Company reported net income of $231 million or $1.10 diluted earnings
per common share in second quarter 2001 compared to net income of $94 million or
$.43 diluted earnings per common share in 2000. Net income in the second quarter
included an after tax gain of $14 million or $.07 per diluted share consisting
of ineffectiveness of cash-flow and fair-value hedges and gains on derivative
instruments which do not qualify for hedge accounting under Statement of
Financial Accounting Standards No. 133, as amended, Accounting for Derivative
Instruments and Hedging Activities ("SFAS No. 133"). For more discussion of SFAS
No. 133, see ITEM 3.
Revenues were $917 million in second quarter 2001 compared to $680 million
in 2000. Average gas prices, including a $.66 loss per MCF related to hedging
activities, increased 49 percent to $4.10 per MCF in second quarter 2001
resulting in increased revenues of $239 million. Average oil prices, including a
$1.62 loss per barrel related to hedging activities, were $24.92 per barrel in
second quarter 2001 which was essentially the same as second quarter 2000. Oil
sales volumes decreased 12 percent in second quarter 2001 to 69.6 MBbls per day
and gas sales volumes decreased 1 percent to 1,945 MMCF per day which decreased
revenues $22 million and $5 million, respectively. Oil sales volumes decreased
primarily due to natural production declines and reduced capital spending in the
Gulf Coast and Mid-Continent areas and property sales in 2000. Revenues also
included a $23 million gain related to ineffectiveness of cash-flow and
fair-value hedges and gains on derivative instruments which do not qualify for
hedge accounting.
Costs and Expenses were $492 million in second quarter 2001 compared to
$479 million in 2000. The increase was primarily due to a $6 million increase in
production taxes, a $4 million increase in exploration costs and a $3 million
increase in depreciation, depletion and amortization ("DD&A"). Production taxes
increased primarily due to higher gas revenues. Exploration costs increased
primarily due to higher exploratory dry hole costs of $9 million partially
offset by lower geological and geophysical expense of $6 million. DD&A increased
due to a higher unit of production rate related to changes in production mix
partially offset by lower production volumes.
Interest Expense was $46 million in second quarter 2001 compared to $53
million in 2000. The decrease was primarily due to lower outstanding commercial
paper borrowings and fixed-rate debt balances during 2001.
Other Expense (Income) -- Net was income of $1 million in second quarter
2001 compared to expense of $10 million in 2000. This change was primarily due
to higher interest income and higher gains related to changes in foreign
currency exchange rates in 2001.
Income taxes were an expense of $149 million in second quarter 2001 as
compared to $44 million in 2000. The increase in tax expense was primarily due
to higher pretax income and beneficial adjustments to tax accruals in the second
quarter of 2000.
14
Results of Operations - First Six Months of 2001 Compared to First Six Months of
2000
The Company reported net income of $567 million or $2.66 diluted earnings
per common share in the first six months of 2001 compared to net income of $171
million or $.78 diluted earnings per common share in 2000. Net income in the
first six months of 2001 included an after tax gain of $3 million or $.01 per
diluted share consisting of the cumulative effect of change in accounting
principle related to SFAS No. 133. Net income in the first six months also
included an after tax gain of $18 million or $.09 per diluted share consisting
of ineffectiveness of cash-flow and fair-value hedges and gains on derivative
transactions which do not qualify for hedge accounting under SFAS No. 133. For
more discussion of SFAS No. 133, see ITEM 3.
Revenues were $2,060 million in the first six months of 2001 compared to
$1,388 million in 2000. Average gas prices, including a $1.13 loss per MCF
related to hedging activities, increased 77 percent to $4.72 per MCF in the
first six months of 2001 resulting in increased revenues of $735 million.
Average oil prices, including a $1.67 loss per barrel related to hedging
activities, increased 6 percent to $25.68 per barrel in the first six months of
2001 resulting in increased revenues of $18 million. Oil sales volumes decreased
18 percent in the first six months of 2001 to 69.7 MBbls per day and gas sales
volumes decreased 3 percent to 1,977 MMCF per day which decreased revenues $69
million and $37 million, respectively. Oil sales volumes decreased primarily due
to natural production declines and reduced capital spending in the Gulf Coast
and Mid-Continent areas and property sales in 2000. Revenues also included a $30
million gain related to ineffectiveness of cash-flow and fair-value hedges and
gains on derivative instruments which do not qualify for hedge accounting.
Costs and Expenses were $1,024 million in the first six months of 2001
compared to $1,000 million in 2000. The increase was primarily due to a $36
million increase in production taxes, a $12 million increase in transportation
expenses and a $5 million increase in administrative expenses partially offset
by a $24 million decrease in exploration costs and a $7 million decrease in
DD&A. Production taxes increased primarily due to higher gas revenues and
transportation expenses increased due to new agreements, higher tariffs and
higher fuel charges. Administrative expenses increased primarily due to
non-recurring payroll related costs. Exploration costs decreased primarily due
to lower geological and geophysical expense of $27 million. DD&A decreased due
to lower production volumes partially offset by a higher unit of production rate
related to changes in production mix.
Interest Expense was $91 million in the first six months of 2001 compared
to $103 million in 2000. The decrease was primarily due to lower outstanding
commercial paper borrowings and fixed-rate debt balances during 2001.
Other Expense (Income) -- Net was an expense of $8 million in the first six
months of 2001 compared to $10 million in 2000. This change was primarily due to
higher interest income in 2001.
Income taxes were an expense of $373 million in the first six months of
2001 as compared to $104 million in 2000. The increase in tax expense was
primarily due to higher pretax income and beneficial adjustments to tax accruals
in the second quarter of 2000.
15
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 Henry Hub futures contract
price for a particular month and the actual cash price received for that month
in a U.S. producing basin or at a U.S. market hub, which is referred to as the
"basis differential."
The Company utilizes over-the-counter price and basis swaps as well as
options to hedge its production in order to decrease its price risk exposure.
The gains and losses realized as a result of these price and basis derivative
transactions are substantially offset when the hedged commodity is delivered. In
order to accommodate the needs of its customers, the Company also uses price
swaps to convert natural gas sold under fixed-price contracts to market
sensitive prices.
The Company 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. At June
30, 2001, the potential decrease in fair value of derivative instruments
assuming a 10 percent adverse movement (an increase in the underlying
commodities prices) would result in a $50 million decrease in the fair value of
the net assets 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.
On January 1, 2001, the Company adopted SFAS No. 133. This pronouncement
establishes accounting and reporting standards for derivative instruments and
for hedging activities. It requires enterprises to recognize all derivatives as
either assets or liabilities in the balance sheet and measure those instruments
at fair value. The requisite accounting for changes in the fair value of a
derivative depends on the intended use of the derivative and the resulting
designation.
In accordance with the transition provisions of SFAS No. 133, the Company
recorded a net-of-tax cumulative-effect-type loss adjustment of $366 million in
accumulated other comprehensive income to recognize at fair value all
derivatives that are designated as cash-flow hedging instruments. The Company
recorded cash-flow hedge derivatives liabilities of $582 million ($361 million
after tax), fair-value hedge derivative assets of $16 million ($10 million after
tax), related liability adjustments to book value of fair-value hedged items of
$16 million ($10 million after tax) and a $3 million after tax non-cash gain was
recorded in current earnings as a cumulative effect of accounting change.
16
During the first six months of 2001, losses of $426 million ($264 million
after tax) were transferred from accumulated other comprehensive income to
earnings related to settlements of oil and gas price hedging contracts, credit
adjustments of $90 million ($56 million after tax) were made to accumulated
other comprehensive income to reflect current period changes in fair value of
settled contracts, and the fair value of outstanding hedging position
liabilities decreased $121 million ($75 million after tax) resulting in an
ending balance of a $47 million credit ($29 million after tax) related to
hedging activities in accumulated other comprehensive income at June 30, 2001.
Based on commodity prices and foreign exchange rates as of June 30, 2001, the
Company expects to reclassify gains of $36 million ($22 million after tax) to
earnings from the balance in accumulated other comprehensive income during the
next twelve months. As of June 30, 2001, the Company had cash-flow hedge
derivative assets of $103 million and derivative liabilities of $31 million (a
net asset of $44 million after tax). The Company had liabilities and assets
related to fair-value hedges of $7 million and $8 million, respectively. The
Company also had commodity-related derivative instruments that do not qualify
for hedge accounting with related assets of $16 million and liabilities of $1
million.
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 2000
Form 10-K.
17
PART II - OTHER INFORMATION
ITEM 1. Legal Proceedings
See Note 4 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 18, 2001. 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
--------- ------- ----------
S. P. Gilbert 187,599,315 1,725,236
L. I. Grant 187,636,523 1,688,028
J. T. LaMacchia 187,593,343 1,731,208
J. F. McDonald 187,617,987 1,706,564
K. W. Orce 183,102,990 6,221,561
D. M. Roberts 187,614,260 1,710,291
J. F. Schwarz 187,620,169 1,704,382
W. Scott, Jr. 184,934,326 4,390,225
B. S. Shackouls 185,658,515 3,666,036
18
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.
* Exhibit incorporated by reference.
B. Reports on Form 8-K
The Company filed no reports on Form 8-K during the second quarter
of 2001.
Items 2, 3 and 5 of Part II are not applicable and have been omitted.
19
Pursuant to the requirements of Section 13 or 15(d) 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
Senior Vice President and
Chief Financial Officer
By /s/JOSEPH P. MCCOY
------------------------------
Joseph P. McCoy
Vice President, Controller and
Chief Accounting Officer
Date: July 25, 2001
20