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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark one)
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended March 31, 2002
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR
15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from _______________ to _______________
Commission File Number 1-8590
MURPHY OIL CORPORATION
(Exact name of registrant as specified in its charter)
Delaware 71-0361522
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification Number)
200 Peach Street
P. O. Box 7000, El Dorado, Arkansas 71731-7000
(Address of principal executive offices) (Zip Code)
(870) 862-6411
(Registrant's telephone number, including area code)
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.
X Yes No
--- ---
Number of shares of Common Stock, $1.00 par value, outstanding at March 31, 2002
was 45,723,653.
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PART I - FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
Murphy Oil Corporation and Consolidated Subsidiaries
CONSOLIDATED BALANCE SHEETS
(Thousands of dollars)
(Unaudited)
March 31, December 31,
2002 2001
----------- ------------
ASSETS
Current assets
Cash and cash equivalents .................................................. $ 91,129 82,652
Accounts receivable, less allowance for doubtful accounts
of $11,324 in 2002 and $11,263 in 2001 ................................... 323,952 262,022
Inventories, at lower of cost or market
Crude oil and blend stocks ............................................... 56,295 38,917
Finished products ........................................................ 95,075 85,133
Materials and supplies ................................................... 51,123 49,098
Prepaid expenses ........................................................... 56,089 61,062
Deferred income taxes ...................................................... 20,170 19,777
----------- ------------
Total current assets ................................................... 693,833 598,661
Property, plant and equipment, at cost less accumulated depreciation, depletion
and amortization of $3,307,539 in 2002 and $3,277,673 in 2001 ................ 2,606,733 2,525,807
Goodwill, net .................................................................. 50,291 50,412
Deferred charges and other assets .............................................. 87,231 84,219
----------- ------------
Total assets ........................................................... $ 3,438,088 3,259,099
=========== ============
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities
Current maturities of long-term debt ....................................... $ 49,003 48,250
Accounts payable and accrued liabilities ................................... 487,544 463,429
Income taxes ............................................................... 44,770 48,378
----------- ------------
Total current liabilities .............................................. 581,317 560,057
Notes payable .................................................................. 572,279 416,061
Nonrecourse debt of a subsidiary ............................................... 100,578 104,724
Deferred income taxes .......................................................... 300,149 302,868
Accrued dismantlement costs .................................................... 160,504 160,764
Accrued major repair costs ..................................................... 48,252 44,570
Deferred credits and other liabilities ......................................... 170,221 171,892
Stockholders' equity
Cumulative Preferred Stock, par $100, authorized 400,000
shares, none issued ...................................................... - -
Common Stock, par $1.00, authorized 200,000,000 shares,
issued 48,775,314 shares ................................................. 48,775 48,775
Capital in excess of par value ............................................. 543,762 527,126
Retained earnings .......................................................... 1,082,045 1,096,567
Accumulated other comprehensive loss ....................................... (88,681) (83,309)
Unamortized restricted stock awards ........................................ (1,346) (968)
Treasury stock, 3,051,661 shares of Common Stock in 2002,
3,444,234 shares in 2001, at cost ........................................ (79,767) (90,028)
----------- ------------
Total stockholders' equity ............................................. 1,504,788 1,498,163
----------- ------------
Total liabilities and stockholders' equity ............................. $ 3,438,088 3,259,099
=========== ============
See Notes to Consolidated Financial Statements, page 5.
The Exhibit Index is on page 18.
1
Murphy Oil Corporation and Consolidated Subsidiaries
CONSOLIDATED STATEMENTS OF INCOME (unaudited)
(Thousands of dollars, except per share amounts)
Three Months Ended
March 31,
--------------------------
2002 2001
----------- -----------
REVENUES
Crude oil and natural gas sales .......................................... $ 194,933 237,199
Petroleum product sales .................................................. 523,730 672,231
Crude oil trading sales .................................................. 63,220 238,460
Other operating revenues ................................................. 47,017 37,805
Interest and other nonoperating revenues ................................. 1,003 3,690
----------- -----------
Total revenues ................................................... 829,903 1,189,385
----------- -----------
COSTS AND EXPENSES
Crude oil, products and related operating expenses ....................... 686,082 913,211
Exploration expenses, including undeveloped lease amortization ........... 42,021 37,961
Selling and general expenses ............................................. 22,362 21,046
Depreciation, depletion and amortization ................................. 70,689 54,232
Amortization of goodwill ................................................. - 788
Interest expense ......................................................... 9,542 9,744
Interest capitalized ..................................................... (4,817) (3,586)
----------- -----------
Total costs and expenses ......................................... 825,879 1,033,396
----------- -----------
Income before income taxes ............................................... 4,024 155,989
Income tax expense ....................................................... 1,490 58,153
----------- -----------
NET INCOME ............................................................... $ 2,534 97,836
=========== ===========
NET INCOME PER COMMON SHARE
Basic ................................................................ $ .06 2.17
Diluted .............................................................. $ .06 2.16
Average Common shares outstanding
Basic ................................................................ 45,508,953 45,056,307
Diluted .............................................................. 45,903,046 45,314,981
See Notes to Consolidated Financial Statements, page 5.
2
Murphy Oil Corporation and Consolidated Subsidiaries
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (unaudited)
(Thousands of dollars)
Three Months Ended
March 31,
--------------------
2002 2001
-------- --------
Net income ........................................................................ $ 2,534 97,836
Other comprehensive income (loss), net of tax
Cash flow hedges
Net derivative gains ........................................................ 2,947 599
Reclassification adjustments ................................................ (3,323) 1,578
-------- --------
Total cash flow hedges .................................................... (376) 2,177
Net loss from foreign currency translation .................................... (4,996) (51,439)
-------- ---------
Other comprehensive loss before cumulative effect of accounting change .... (5,372) (49,262)
Cumulative effect of accounting change (Note B) ............................... - 6,642
-------- --------
Other comprehensive loss .................................................. (5,372) (42,620)
-------- --------
COMPREHENSIVE INCOME (LOSS) ....................................................... $ (2,838) 55,216
======== ========
See Notes to Consolidated Financial Statements, page 5.
3
Murphy Oil Corporation and Consolidated Subsidiaries
CONSOLIDATED STATEMENTS OF CASH FLOWS (unaudited)
(Thousands of dollars)
Three Months Ended
March 31,
-----------------------
2002 2001
--------- ---------
OPERATING ACTIVITIES
Net income ......................................................................... $ 2,534 97,836
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation, depletion and amortization ....................................... 70,689 54,232
Provisions for major repairs ................................................... 4,579 5,500
Expenditures for major repairs and dismantlement costs ......................... (2,104) (2,449)
Dry holes ...................................................................... 23,112 19,005
Amortization of undeveloped leases ............................................. 6,062 5,230
Amortization of goodwill ....................................................... - 788
Deferred and noncurrent income tax charges (benefits) .......................... (264) 16,966
Pretax gains from disposition of assets ........................................ (5,736) (86)
Net (increase) decrease in operating working capital other than cash
and cash equivalents ......................................................... (66,189) 29,862
Other operating activities - net ............................................... 32 6,568
--------- ---------
Net cash provided by operating activities .................................... 32,715 233,452
--------- ---------
INVESTING ACTIVITIES
Property additions and dry holes ................................................... (204,860) (179,649)
Proceeds from the sale of assets ................................................... 27,877 2,266
Other investing activities - net ................................................... (145) (92)
--------- ---------
Net cash required by investing activities .................................... (177,128) (177,475)
--------- ---------
FINANCING ACTIVITIES
Increase (decrease) in notes payable ............................................... 156,992 (10)
Decrease in nonrecourse debt of a subsidiary ....................................... (4,051) (3,070)
Proceeds from exercise of stock options and employee stock purchase plans .......... 18,058 1,495
Cash dividends paid ................................................................ (17,057) (16,896)
--------- ---------
Net cash provided (required) by financing activities ......................... 153,942 (18,481)
--------- ---------
Effect of exchange rate changes on cash and cash equivalents ....................... (1,052) (4,898)
--------- ---------
Net increase in cash and cash equivalents .......................................... 8,477 32,598
Cash and cash equivalents at January 1 ............................................. 82,652 132,701
--------- ---------
Cash and cash equivalents at March 31 .............................................. $ 91,129 165,299
========= =========
SUPPLEMENTAL DISCLOSURES OF CASH FLOW ACTIVITIES
Cash income taxes paid ............................................................. $ 8,262 28,325
Interest paid, net of amounts capitalized .......................................... (87) (2,024)
See Notes to Consolidated Financial Statements, page 5.
4
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
These notes are an integral part of the financial statements of Murphy Oil
Corporation and Consolidated Subsidiaries (Murphy/the Company) on pages 1
through 4 of this Form 10-Q report.
Note A - Interim Financial Statements
The consolidated financial statements of the Company presented herein have not
been audited by independent auditors, except for the Consolidated Balance Sheet
at December 31, 2001. In the opinion of Murphy's management, the unaudited
financial statements presented herein include all accruals necessary to present
fairly the Company's financial position at March 31, 2002, and the results of
operations and cash flows for the three-month periods ended March 31, 2002 and
2001, in conformity with accounting principles generally accepted in the United
States.
Financial statements and notes to consolidated financial statements included in
this Form 10-Q report should be read in conjunction with the Company's 2001 Form
10-K report, as certain notes and other pertinent information have been
abbreviated or omitted in this report. Financial results for the three months
ended March 31, 2002 are not necessarily indicative of future results.
Note B - New Accounting Principles
Effective January 1, 2002, the Company was required to adopt SFAS No. 142,
"Goodwill and Other Intangible Assets", which requires that amortization of
goodwill be replaced with annual tests for impairment and that intangible assets
other than goodwill be amortized over their useful lives. Murphy assesses the
recoverability of goodwill by comparing the fair value of net assets for
conventional oil and natural gas operations in Canada with the carrying value of
these net assets, including goodwill. The fair value of the conventional oil and
natural gas reporting unit will be determined using the expected present value
of future cash flows. The carrying amount of goodwill at March 31, 2002 was
$50.3 million. The change in the carrying amount of goodwill for the period
ended March 31, 2002 was due to a change in the exchange rate of Canadian
dollars and U.S. dollars. Goodwill is tested for impairment at the end of the
Company's fiscal year after the oil and gas reserve information is available.
Adjusted net income, excluding goodwill amortization of $.8 million ($.02 basic
and $.01 diluted earnings per share), was $98.6 million for the period ended
March 31, 2001. Adjusted basic and diluted earnings per share for the period
ended March 31, 2001 were $2.19 and $2.18, respectively. At this time, it is not
practicable to reasonably estimate the impact of adopting SFAS No. 142 on the
Company's financial statements.
Also effective January 1, 2002, Murphy was required to adopt SFAS No. 144,
"Accounting for the Impairment or Disposal of Long-Lived Assets", which
supercedes SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and
for Long-Lived Assets to be Disposed of" and the accounting and reporting
provisions of APB Opinion No. 30, "Reporting the Results of Operations-Reporting
the Effects of Disposal of a Segment of a Business, and Extraordinary, Unusual,
and Infrequently Occurring Events and Transactions". There was no current-period
effect of adopting SFAS No. 144 on the Company's consolidated financial
statements.
In July 2001, the FASB issued SFAS No. 143, "Accounting for Asset Retirement
Obligations", which will require the Company to record a liability equal to the
fair value of the estimated cost to retire an asset. The asset retirement
liability must be recorded in the period in which the obligation meets the
definition of a liability, which is generally when the asset is placed in
service. When the liability is initially recorded, the Company will increase the
carrying amount of the related long-lived asset by an amount equal to the
original liability. The liability is accreted to its present value each period,
and the capitalized cost is depreciated over the useful life of the related
long-lived asset. Upon adoption of SFAS No. 143 on January 1, 2003, the Company
will recognize transition adjustments for existing asset retirement obligations,
long-lived assets and accumulated depreciation, all net of related income tax
effects, as the cumulative effect of a change in accounting principle. After
adoption, any difference between costs incurred upon settlement of an asset
retirement obligation and the recorded liability will be recognized as a gain or
loss in the Company's earnings. At this time, it is not practicable to
reasonably estimate the impact of adopting SFAS No. 143 on the Company's
financial statements.
Effective January 1, 2001, Murphy adopted Statement of Financial Accounting
Standards No. 133, "Accounting for Derivative Instruments and Hedging
Activities", as amended by Statement of Financial Accounting Standards No. 138
(SFAS Nos. 133/138). As a result of the change, Murphy records the fair values
of its derivative instruments as either assets or liabilities. All such
instruments have been designated as hedges of forecasted cash flow exposures.
Changes in the fair value of a qualifying cash flow hedging derivative are
deferred and recorded as a component of Accumulated Other Comprehensive Loss
(AOCL) in the Consolidated Balance Sheet until the
5
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)
Note B - New Accounting Principles (Contd.)
forecasted transaction occurs, at which time the derivative's fair value will be
recognized in earnings. Ineffective portions of a hedging derivative's change in
fair value are immediately recognized in earnings. Adoption of SFAS Nos. 133/138
resulted in a transition adjustment gain to AOCL of $6.6 million, net of $2.8
million in income taxes, in the first quarter of 2001 for the cumulative effect
on prior years; there was no cumulative effect on earnings. Excluding the
transition adjustment, the effect of this accounting change decreased AOCL for
the three months ended March 31, 2002 by $.4 million and increased AOCL for the
2001 period $2.2 million, net of $ .1 million and $1.6 million in income taxes,
respectively, and increased income by an insignificant amount for the same
periods, but did not affect income per diluted share. For the three months ended
March 31, 2002 gains of $3.3 million and losses of $1.6 million in the 2001
period, net of $1.8 million and $1.2 million in taxes, respectively, were
reclassified from AOCL to earnings.
Note C - Environmental Contingencies
The Company's operations are subject to numerous laws and regulations intended
to protect the environment and/or impose remedial obligations. The Company is
also involved in personal injury and property damage claims, allegedly caused by
exposure to or by the release or disposal of materials manufactured or used in
the Company's operations. The Company operates or has previously operated
certain sites and facilities, including refineries, oil and gas fields, service
stations, and terminals, for which known or potential obligations for
environmental remediation exist.
Under the Company's accounting policies, an environmental liability is recorded
when an obligation is probable and the cost can be reasonably estimated. If
there is a range of reasonably estimated costs, the most likely amount will be
recorded, or if no amount is most likely, the minimum of the range is used.
Recorded liabilities are reviewed quarterly. Actual cash expenditures often
occur one or more years after a liability is recognized.
The Company's reserve for remedial obligations, which is included in Deferred
Credits and Other Liabilities in the Consolidated Balance Sheets, contains
certain amounts that are based on anticipated regulatory approval for proposed
remediation of former refinery waste sites. If regulatory authorities require
more costly alternatives than the proposed processes, future expenditures could
exceed the amount reserved by up to an estimated $3 million.
The Company has received notices from the U.S. Environmental Protection Agency
(EPA) that it is currently considered a Potentially Responsible Party (PRP) at
three Superfund sites and has also been assigned responsibility by defendants at
another Superfund site. The potential total cost to all parties to perform
necessary remedial work at these sites may be substantial. Based on currently
available information, the Company has reason to believe that it is a "de
minimus" party as to ultimate responsibility at the four sites. The Company does
not expect that its related remedial costs will be material to its financial
condition or its results of operations, and it has not provided a reserve for
remedial costs on Superfund sites. Additional information may become known in
the future that would alter this assessment, including any requirement to bear a
pro rata share of costs attributable to nonparticipating PRPs or indications of
additional responsibility by the Company.
A lawsuit filed against Murphy by the U.S. Government is discussed under the
caption "Legal Proceedings" on page 17 of this Form 10-Q report. The Company
does not believe that this or other known environmental matters will have a
material adverse effect on its financial condition. There is the possibility
that expenditures could be required at currently unidentified sites, and new or
revised regulations could require additional expenditures at known sites. Such
expenditures could materially affect the results of operations in a future
period.
Certain environmental expenditures are likely to be recovered by the Company
from other sources, primarily environmental funds maintained by certain states.
Since no assurance can be given that future recoveries from other sources will
occur, the Company has not recognized a benefit for likely recoveries at March
31, 2002.
Note D - Other Contingencies
The Company's operations and earnings have been and may be affected by various
other forms of governmental action both in the United States and throughout the
world. Examples of such governmental action include, but are not limited to: tax
increases and retroactive tax claims; import and export controls; price
controls; currency controls;
6
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)
Note D - Other Contingencies (Contd.)
allocation of supplies of crude oil and petroleum products and other goods;
expropriation of property; restrictions and preferences affecting the issuance
of oil and gas or mineral leases; restrictions on drilling and/or production;
laws and regulations intended for the promotion of safety; governmental support
for other forms of energy; and laws and regulations affecting the Company's
relationships with employees, suppliers, customers, stockholders and others.
Because governmental actions are often motivated by political considerations,
may be taken without full consideration of their consequences, and may be taken
in response to actions of other governments, it is not practical to attempt to
predict the likelihood of such actions, the form the actions may take or the
effect such actions may have on the Company.
In addition to the lawsuits discussed under the caption "Legal Proceedings" on
page 17 of this Form 10-Q report, the Company and its subsidiaries are engaged
in a number of other legal proceedings, all of which the Company considers
routine and incidental to its business and none of which is considered material.
In the normal course of its business, the Company is required under certain
contracts with various governmental authorities and others to provide financial
guarantees or letters of credit that may be drawn upon if the Company fails to
perform under those contracts. At March 31, 2002, the Company had contingent
liabilities of $33.6 million under certain financial guarantees and $33.5
million on outstanding letters of credit.
Note E - Earnings per Share
Net income was used as the numerator in computing both basic and diluted income
per Common share for the three months ended March 31, 2002 and 2001. The
following table reconciles the weighted-average shares outstanding used for
these computations.
- ------------------------------------------------------------------
Reconciliation of Shares Outstanding Three Months Ended
March 31,
- ------------------------------------------------------------------
(Weighted-average shares) 2002 2001
- ------------------------------------------------------------------
Basic method .......................... 45,508,953 45,056,307
Dilutive stock options ................ 394,093 258,674
- ------------------------------------------------------------------
Diluted method 45,903,046 45,314,981
==================================================================
There were no antidilutive options for the periods ended March 31, 2002 or 2001.
Note F - Financial Instruments and Risk Management
Murphy utilizes derivative instruments on a limited basis to manage certain
risks related to interest rates, commodity prices, and foreign currency exchange
rates. The use of derivative instruments for risk management is covered by
operating policies and is closely monitored by the Company's senior management.
The Company does not hold any derivatives for trading purposes, and it does not
use derivatives with leveraged or complex features. Derivative instruments are
traded primarily with creditworthy major financial institutions or over national
exchanges.
o Interest Rate Risks - Murphy has variable-rate debt obligations that expose
the Company to the effects of changes in interest rates. To limit its
exposure to interest rate risk, Murphy has interest rate swap agreements
with notional amounts totaling $100,000,000 to hedge fluctuations in cash
flows of a similar amount of variable rate debt. The swaps mature in 2002
and 2004. Under the interest rate swaps, the Company pays fixed rates
averaging 6.46% over their composite lives and receives variable rates
which averaged 1.86% at March 31, 2002. The variable rate received by the
Company under each contract is repriced quarterly. The Company has a risk
management control system to monitor interest rate cash flow risk
attributable to the Company's outstanding and forecasted debt obligations
as well as the offsetting interest rate swaps. The control system involves
using analytical techniques, including cash flow sensitivity analysis, to
estimate the impact of interest rate changes on future cash flows.
The fair value of the effective portions of the interest rate swaps and
changes thereto is deferred in Accumulated Other Comprehensive Loss (AOCL)
and is subsequently reclassified into Interest Expense as a rate adjustment
in the periods in which the hedged interest payments on the variable-rate
debt affect earnings.
7
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)
Note F - Financial Instruments and Risk Management (Contd.)
For the periods ended March 31, 2002 and 2001, the income effect from cash
flow hedging ineffectiveness was insignificant. The fair value of the
interest rate swaps are estimated using projected Federal funds rates,
Canadian overnight funding rates and LIBOR forward curve rates obtained
from published indices and counterparties. The estimated fair value
approximates the values based on quotes from each of the counterparties.
o Natural Gas Fuel Price Risks - The Company purchases natural gas as fuel at
its Meraux, Louisiana refinery. The cost of natural gas is subject to
commodity price risk. Murphy has reduced the effect of changes in the price
of natural gas used for fuel at Meraux by entering into natural gas swap
contracts with a notional volume of 9.2 million British Thermal Units
(MMBTU) to hedge fluctuations in cash flows resulting from such risk during
2004 through 2006.
Under the natural gas swaps, the Company pays a fixed rate averaging $2.78
per MMBTU and receives a floating rate in each month of settlement based on
the average NYMEX price for the final three trading days of the month.
Murphy has a risk management control system to monitor natural gas price
risk attributable both to forecasted natural gas fuel requirements and to
Murphy's natural gas swaps. The control system involves using analytical
techniques, including various correlations of natural gas purchase prices
to futures prices, to estimate the impact of changes in natural gas fuel
prices on Murphy's cash flows.
The fair value of the effective portions of the natural gas swaps and
changes thereto is deferred in AOCL and is subsequently reclassified into
Crude Oil, Products and Related Operating Expenses in the periods in which
the hedged natural gas fuel purchases affect earnings. For the periods
ended March 31, 2002 and 2001, the income effect from cash flow hedging
ineffectiveness was insignificant.
o Natural Gas Sales Price Risks - The sales price of natural gas produced by
the Company is subject to commodity price risk. Murphy has minimized the
effect of changes in the selling price of a portion of its U.S. and western
Canada natural gas production during May through October 2002 by entering
into natural gas swap and natural gas collar contracts to hedge cash flow
fluctuations resulting from such risk.
The natural gas swaps are for a combined notional volume averaging
approximately 24,000 MMBTU equivalent per day and require Murphy to pay the
average relevant index (NYMEX or AECO "C") price for each month and receive
an average price of $3.29 per MMBTU equivalent. The natural gas collars are
for a combined notional volume averaging approximately 29,000 MMBTU
equivalent per day and based upon the relevant index prices provide Murphy
with an average floor price of $2.62 per MMBTU equivalent and an average
ceiling price of $4.71 per MMBTU equivalent.
Murphy has a risk management control system to monitor natural gas price
risk attributable both to forecasted natural gas sales prices and to
Murphy's hedging instruments. The control system involves using analytical
techniques, including various correlations of natural gas sales prices to
futures prices, to estimate the impact of changes in natural gas prices on
Murphy's cash flows from the sale of natural gas.
The natural gas price risk pertaining to a portion of gas sales from
properties Murphy acquired from Beau Canada in 2000 was limited by natural
gas swap agreements that expired in October 2001 that were obtained in the
acquisition. These agreements hedged fluctuations in cash flows resulting
from such risk. Certain swaps required Murphy to pay a floating price and
receive a fixed price and were partially offset by swaps on a lesser volume
that require Murphy to pay a fixed price and receive a floating price. The
fair value of these swaps was recorded as a net liability upon the
acquisition of Beau Canada and was adjusted on January 1, 2001 upon
transition to SFAS 133. Net payments by the Company were recorded as a
reduction of the associated liability, with any differences recorded as an
adjustment of natural gas revenue.
8
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)
Note F - Financial Instruments and Risk Management (Contd.)
The fair values of the effective portions of the natural gas swaps and
collars and changes thereto are deferred in AOCL and are subsequently
reclassified into Crude Oil and Natural Gas Sales in the periods in which
the hedged natural gas sales affect earnings. For the periods ended March
31, 2002 and 2001, Murphy's earnings were not significantly effected by
cash flow hedging ineffectiveness arising from the natural gas swaps and
collars in the United States and western Canada.
The fair value of the natural gas fuel swaps and the natural gas sales
swaps and collars are both based on the average fixed price of the
instruments and the published NYMEX or AECO "C" index futures price or
natural gas price quotes from counterparties.
o Crude Oil Purchase Price Risks - Each month, the Company purchases crude
oil as the primary feedstock for its U.S. refineries. Prior to April 2000,
the Company was a party to crude oil swap agreements that limited the
exposure of its U.S. refineries to the risks of fluctuations in cash flows
resulting from changes in the prices of crude oil purchased in 2001 and
2002. Under each swap, Murphy would have paid a fixed crude oil price and
would have received a floating price during the agreement's contractual
maturity period. In April 2000, the Company settled certain of the swaps by
receiving $5.8 million in cash and entered into offsetting contracts for
the remaining swap agreements, locking in an additional future net gain of
$1.9 million. The fair values of these settlement gains were recorded in
AOCL as part of the transition adjustment and are recognized as a reduction
of costs of crude oil purchases in the period the forecasted transaction
occurs. During the period ended March 31, 2002, pretax gains of $3.6
million were reclassified from AOCL into earnings.
The fair value of the offsetting crude oil swap contracts is based on the
fixed swap price and the NYMEX crude oil futures price.
The Company expects to reclassify approximately $.5 million in after-tax gains
from AOCL into earnings during the next 12 months as the forecasted transactions
actually occur. All forecasted transactions currently being hedged are expected
to occur by December 2006.
Note G - Accumulated Other Comprehensive Loss
Net gains (losses) in Accumulated Other Comprehensive Loss on the Consolidated
Balance Sheets at March 31, 2002 and December 31, 2001 were as follows.
--------------------------------------------------------------------------
March 31, December 31,
(Millions of dollars) 2002 2001
--------------------------------------------------------------------------
Foreign currency translation ................ $ (92.8) (87.8)
Cash flow hedging, net of income taxes ...... 4.1 4.5
--------------------------------------------------------------------------
Accumulated other comprehensive loss $ (88.7) (83.3)
==========================================================================
9
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)
Note H - Business Segments
Three Mos. Ended March 31, 2002 Three Mos. Ended March 31, 2001
Total Assets ------------------------------- ---------------------------------
at March 31, External Interseg. Income External Interseg. Income
(Millions of dollars) 2002 Revenues Revenues (Loss) Revenues Revenues (Loss)
- --------------------------------------------------------------------------------------------------------------------------
Exploration and production*
United States ........... $ 621.3 23.1 9.9 (2.6) 79.4 17.2 31.1
Canada .................. 1,275.0 120.6 - 17.8 99.7 20.9 28.1
United Kingdom .......... 204.7 45.5 - 13.2 50.3 - 20.1
Ecuador ................. 71.4 5.6 - .8 10.1 - 3.8
Malaysia ................ 30.6 - - (8.0) - - (1.2)
Other international ..... 7.0 .6 - (.5) .5 - (1.3)
- --------------------------------------------------------------------------------------------------------------------------
Total 2,210.0 195.4 9.9 20.7 240.0 38.1 80.6
- --------------------------------------------------------------------------------------------------------------------------
Refining and marketing
United States ........... 832.4 548.4 - (11.5) 706.2 - 15.0
United Kingdom .......... 197.3 85.1 - (2.2) 78.5 - 1.8
Canada .................. .1 - - - 161.0 .1 2.8
- --------------------------------------------------------------------------------------------------------------------------
Total 1,029.8 633.5 - (13.7) 945.7 .1 19.6
- --------------------------------------------------------------------------------------------------------------------------
Total operating
segments ............. 3,239.8 828.9 9.9 7.0 1,185.7 38.2 100.2
Corporate and other ......... 198.3 1.0 - (4.5) 3.7 - (2.4)
- --------------------------------------------------------------------------------------------------------------------------
Total consolidated $ 3,438.1 829.9 9.9 2.5 1,189.4 38.2 97.8
==========================================================================================================================
* Additional details about results of oil and gas operations are presented in
the tables on page 16.
Note I - Subsequent Event
In May 2002, the Company sold $350 million of 6.375% notes due in 2012. The
Company will use approximately $200 million of the $346.3 million in net
proceeds to repay outstanding indebtedness under existing credit facilities and
use the remaining proceeds for general corporate purposes.
10
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND
FINANCIAL CONDITION
Results of Operations
Murphy's net income in the first quarter of 2002 totaled $2.5 million, $.06 a
diluted share, compared to net income of $97.8 million, $2.16 a diluted share in
the first quarter a year ago. Cash flow from operating activities, excluding
changes in noncash working capital items, totaled $98.9 million for the current
quarter compared to $203.6 million in the same quarter last year.
In the current quarter, the Company's exploration and production operations
earned $20.7 million, a decrease of 74% from the $80.6 million earned in the
first quarter of 2001. The decline in income was primarily the result of
significantly lower North American natural gas and worldwide oil sales prices
partially offset by higher oil and gas sales volumes. Murphy's downstream
operations generated a loss of $13.7 million in the first quarter of 2002,
compared to earnings of $19.6 million in the same period of 2001. Financial
results from the Company's U.S. and U.K. downstream operations were hurt by
depressed operating margins at each of its refineries, and by decreases in
volumes of products sold in the United States.
Exploration and Production
- --------------------------
Results of exploration and production operations are presented by geographic
segment below.
Income (Loss)
--------------------------
Three Months Ended
March 31,
--------------------------
(Millions of dollars) 2002 2001
------------------- ---- ----
Exploration and production
United States ............... $(2.6) 31.1
Canada ...................... 17.8 28.1
United Kingdom .............. 13.2 20.1
Ecuador ..................... .8 3.8
Malaysia .................... (8.0) (1.2)
Other International ......... (.5) (1.3)
----- ----
Total ................... $20.7 80.6
===== ====
Exploration and production operations in the United States reported a loss of
$2.6 million compared to earnings of $31.1 million in the first quarter of 2001.
This decline was primarily due to lower natural gas and oil sales prices and was
partially offset by an $11.6 million decline in exploration expenses. Sales of
natural gas averaged 101 million cubic feet a day, down from 125 million in the
first quarter of 2001 due to lower production in the Gulf of Mexico. U.S.
production expenses were up $1.8 million or 15%, primarily because of higher
well workover costs.
Operations in Canada earned $17.8 million this quarter compared to $28.1 million
a year ago as increased production of oil and natural gas were more than offset
by significant declines in average oil and natural gas sales prices and
increased exploration expenses. Oil and gas liquids sales in Canada averaged
46,569 barrels a day, an increase of 33% over the prior year, primarily because
of the timings of liftings at Hibernia and initial production and sales from the
Terra Nova field in 2002. Canadian natural gas sales averaged 199 million cubic
feet a day in the current quarter, up 88%, with the increase primarily
attributable to higher production from the Ladyfern field. Canadian production
expenses in the 2002 quarter were virtually unchanged at $33 million, primarily
because of lower costs for synthetic oil operations offset by higher offshore
production costs caused by timings of liftings. Exploration expenses were $9.6
million higher than in the 2001 quarter primarily because of higher dry holes.
U.K. operations earned $13.2 million in the current quarter, down from $20.1
million in the prior year. Sales of oil and gas liquids in the United Kingdom
increased 24% primarily due to the timing of liftings. Higher sales volumes were
more than offset by lower sales prices for U.K. crude oil.
Operations in Ecuador earned $.8 million in the first quarter of 2002 compared
to $3.8 million a year ago, while Malaysia and other international operations
reported losses of $8.0 million and $.5 million, respectively, compared to
losses of $1.2 million and $1.3 million in 2001. The higher loss in Malaysia in
the current period was primarily due to increased dry holes. Crude oil
production in Ecuador decreased 28% and the average sales price decreased 16% to
$14.84 a barrel. Sales volumes in Ecuador were adversely affected by pipeline
restrictions. Production expenses in Ecuador were down $1.1 million due to lower
sales volumes.
11
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS (Contd.)
Results of Operations (Contd.)
Exploration and Production (Contd.)
- --------------------------
On a worldwide basis, the Company's crude oil and condensate prices averaged
$19.76 a barrel in the current quarter, a decrease of 13% from the average of
$22.65 in the 2001 period. Average crude oil and liquids production was a
quarterly record of 74,292 barrels a day, up 8% over last year, but average
sales volumes increased 22% to 80,208 barrels a day due to the timing of
liftings and new production from Terra Nova. Total natural gas sales volumes
were also a Company record and averaged 309 million cubic feet a day in 2002, up
24% from the 2001 period. The tables on page 16 provide additional details of
the results of exploration and production operations for the first quarter of
each year. Selected operating statistics for the three-month periods ended March
31, 2002 and 2001 follow.
Three Months Ended
March 31,
----------------------
2002 2001
-------- --------
Net crude oil, condensate and gas liquids produced - barrels per day ............... 74,292 69,054
United States .................................................................. 6,185 5,503
Canada - light .............................................................. 4,069 4,584
- heavy .............................................................. 9,722 13,000
- offshore ........................................................... 19,759 8,953
- synthetic .......................................................... 11,342 10,352
United Kingdom ................................................................. 19,031 20,825
Ecuador ........................................................................ 4,184 5,837
Net crude oil, condensate and gas liquids sold - barrels per day ................... 80,208 65,754
United States .................................................................. 6,185 5,503
Canada - light .............................................................. 4,069 4,584
- heavy .............................................................. 9,722 13,000
- offshore ........................................................... 21,436 7,155
- synthetic .......................................................... 11,342 10,352
United Kingdom ................................................................. 23,247 18,808
Ecuador ........................................................................ 4,207 6,352
Net natural gas sold - thousands of cubic feet per day ............................. 309,290 248,799
United States .................................................................. 101,294 124,844
Canada ......................................................................... 199,486 106,006
United Kingdom ................................................................. 8,510 17,949
Total net hydrocarbons produced - equivalent barrels per day (1) ................... 125,840 110,521
Total net hydrocarbons sold - equivalent barrels per day (1) ....................... 131,756 107,221
Weighted average sales prices
Crude oil and condensate - dollars a barrel (2)
United States ................................................................ $ 20.20 27.42
Canada (3) - light ........................................................ 17.86 25.03
- heavy ........................................................ 13.39 9.43
- offshore ..................................................... 21.95 27.05
- synthetic .................................................... 21.23 28.17
United Kingdom ............................................................... 20.73 27.10
Ecuador ...................................................................... 14.84 17.75
Natural gas - dollars a thousand cubic feet
United States (2) ............................................................ $ 2.60 7.21
Canada (3) ................................................................... 2.12 5.79
United Kingdom (3) ........................................................... 2.96 2.53
(1) Natural gas converted on an energy equivalent basis of 6:1
(2) Includes intracompany transfers at market prices.
(3) U.S. dollar equivalent.
12
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS (Contd.)
Results of Operations (Contd.)
Refining and Marketing
- ----------------------
Results of refining and marketing operations are presented below by geographic
segment.
Income (Loss)
--------------------------
Three Months Ended
March 31,
--------------------------
(Millions of dollars) 2002 2001
------------------- ------ ----
Refining and marketing
United States ............... $(11.5) 15.0
United Kingdom .............. (2.2) 1.8
Canada ...................... - 2.8
------ ----
Total ................... $(13.7) 19.6
====== ====
Refining and marketing operations in the United States reported a loss of $11.5
million during the first quarter of 2002 compared to earnings of $15 million a
year ago. The Company's U.S. refining margins per barrel were significantly
lower in the current quarter compared to margins experienced in the first
quarter of 2001. U.S. petroleum product sales averaged 157,505 barrels a day in
2002, a 4% decrease from the first quarter of 2001. The first quarter 2002
results included a net gain of $3.5 million from sale of the Company's interest
in Butte Pipe Line. Operations in the United Kingdom reflected a loss of $2.2
million in the first quarter of 2002 compared to earnings of $1.8 million a year
ago as margins were depressed throughout much of the current quarter. Worldwide
refinery crude runs were 142,441 barrels a day in the first quarter of 2002
compared to 172,319 in the 2001 quarter, and petroleum product sales were
191,318 barrels a day, up from 189,097 a year ago. Refinery crude runs in the
U.S. declined significantly due to unplanned maintenance caused by power outages
at the Meraux and Superior refineries. Earnings from purchasing, transporting
and reselling crude oil in Canada were $2.8 million in the first quarter of
2001. The Company sold its Canadian pipeline and trucking operations in May
2001.
Selected operating statistics for the three-month periods ended March 31, 2002
and 2001 follow.
Three Months Ended
March 31,
---------------------
2002 2001
------- -------
Refinery inputs - barrels a day .................... 154,512 178,694
United States .................................. 117,730 151,654
United Kingdom ................................. 36,782 27,040
Petroleum products sold - barrels a day ............ 191,318 189,097
United States .................................. 157,504 164,556
Gasoline ..................................... 96,903 86,306
Kerosine ..................................... 8,448 12,381
Diesel and home heating oils ................. 35,725 42,700
Residuals .................................... 13,044 17,880
Asphalt, LPG and other ....................... 3,384 5,289
United Kingdom ................................. 33,814 24,541
Gasoline ..................................... 12,848 9,378
Kerosine ..................................... 2,656 2,584
Diesel and home heating oils ................. 13,856 7,403
Residuals .................................... 2,812 2,522
LPG and other ................................ 1,642 2,654
Corporate and other
- -------------------
Corporate activities, which include interest income and expense and corporate
overhead not allocated to operating functions, reflected a loss of $4.5 million
in the current quarter compared to a loss of $2.4 million in the first quarter
of 2001. A decrease in interest earned and increased unallocated corporate
overhead were partially offset by lower net interest expense.
13
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS (Contd.)
Financial Condition
Net cash provided by operating activities was $32.7 million for the first three
months of 2002 compared to $233.5 million during the same period in 2001.
Changes in operating working capital other than cash and cash equivalents
required cash of $66.2 million in the first quarter of 2002 and provided cash of
$29.9 million in the 2001 period.
Other predominant uses of cash in both years were for capital expenditures,
which, including amounts expensed, are summarized in the following table, and
for dividends, which totaled $17.1 million in 2002 and $16.9 million in 2001.
Three Months Ended March 31,
----------------------------
(Millions of dollars) 2002 2001
------------------- ---- ----
Capital Expenditures
Exploration and production ................................... $177.1 163.2
Refining and marketing ....................................... 40.3 28.3
Corporate and other .......................................... .3 1.9
------ -----
Total capital expenditures ................................ 217.7 193.4
Geological, geophysical and other exploration
expenses charged to income ..................................... (12.9) (13.8)
------ -----
Total property additions and dry holes .................... $204.8 179.6
====== =====
Working capital at March 31, 2002 was $112.5 million, up $73.9 million from
December 31, 2001. This level of working capital does not fully reflect the
Company's liquidity position, because the lower historical costs assigned to
inventories under last-in first-out accounting were $97.2 million below fair
value at March 31, 2002.
At March 31, 2002, long-term notes payable of $572.3 million were up $156.2
million from December 31, 2001 due to borrowings to fund certain capital
expenditures. Long-term nonrecourse debt of a subsidiary was $100.6 million,
down $4.1 million from December 31, 2001 due to scheduled repayments. A summary
of capital employed at March 31, 2002 and December 31, 2001 follows.
(Millions of dollars) March 31, 2002 Dec. 31, 2001
------------------- ----------------- --------------
Amount % Amount %
-------- --- ------- ---
Capital Employed
Notes payable ................................................ $ 572.3 26 416.1 21
Nonrecourse debt of a subsidiary ............................. 100.6 5 104.7 5
Stockholders' equity ......................................... 1,504.8 69 1,498.2 74
-------- --- ------- ---
Total capital employed .................................... $2,177.7 100 2,019.0 100
======== === ======= ===
Accounting and Other Matters
As described in Note B on page 5 of this Form 10-Q report, Murphy adopted
Statement of Financial Accounting Standards No. 142, "Goodwill and Other
Intangible Assets", and SFAS No. 144, "Accounting for the Impairment of Disposal
of Long-Lived Assets" effective January 1, 2002.
In April 2002, U.K. tax authorities announced that the corporation tax rate
would increase from 30% to 40% for profits associated with North Sea oil
production. It was also announced that the first-year allowance for North Sea
capital expenditures would increase from 25% to 100%. Based on current Company
estimates, the net effect of these changes is expected to reduce U.K. income
during the last three quarters of 2002 by approximately $4.8 million.
Forward-Looking Statements
This Form 10-Q report contains statements of the Company's expectations,
intentions, plans and beliefs that are forward-looking and are dependent on
certain events, risks and uncertainties that may be outside of the Company's
control. These forward-looking statements are made in reliance upon the safe
harbor provisions of the Private Securities Litigation Reform Act of 1995.
Actual results and developments could differ materially from those expressed or
implied by such statements due to a number of factors including those described
in the context of such forward-looking statements as well as those contained in
the Company's January 15, 1997 Form 8-K report on file with the U.S. Securities
and Exchange Commission.
14
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The Company is exposed to market risks associated with interest rates, prices of
crude oil, natural gas and petroleum products, and foreign currency exchange
rates. As described in Note F to this Form 10-Q report, Murphy makes limited use
of derivative financial and commodity instruments to manage risks associated
with existing or anticipated transactions.
The Company was a party to interest rate swaps at March 31, 2002 with notional
amounts totaling $100 million that were designed to hedge fluctuations in cash
flows of a similar amount of variable-rate debt. These swaps mature in 2002 and
2004. The swaps require the Company to pay an average interest rate of 6.46%
over their composite lives, and at March 31, 2002, the interest rate to be
received by the Company averaged 1.86%. The variable interest rate received by
the Company under each swap contract is repriced quarterly. The Company
considers these swaps to be a hedge against potentially higher future interest
rates. The estimated fair value of these interest rate swaps was recorded as a
liability of $3.3 million at March 31, 2002.
At March 31, 2002, 43% of the Company's debt had variable interest rates and
6.5% was denominated in Canadian dollars. Based on debt outstanding at March 31,
2002, a 10% increase in variable interest rates would increase the Company's
interest expense approximately $.3 million for the next 12 months after
including the favorable effect resulting from lower net settlement payments
under the aforementioned interest rate swaps. A 10% increase in the exchange
rate of the Canadian dollar versus the U.S. dollar would increase interest
expense for the next 12 months by $.1 million for debt denominated in Canadian
dollars.
Murphy was a party to natural gas price swap agreements at March 31, 2002 for a
total notional volume of 9.2 MMBTU that are intended to hedge a portion of the
financial exposure of its Meraux, Louisiana refinery to fluctuations in the
future price of natural gas purchased for fuel. In each month of settlement, the
swaps require Murphy to pay an average natural gas price of $2.78 an MMBTU and
to receive the average NYMEX price for the final three trading days of the
month. At March 31, 2002, the estimated fair value of these agreements was
recorded as an asset of $7.2 million. A 10% increase in the average NYMEX price
of natural gas would have increased this asset by $2.9 million, while a 10%
decrease would have reduced the asset by a similar amount.
In addition, the Company was a party to natural gas swap agreements and natural
gas collar agreements at March 31, 2002 that are intended to hedge the financial
exposure of a limited portion of its U.S. and Canadian natural gas production to
changes in gas sales prices through October 2002. The swaps are for a combined
notional volume that averages 24,000 MMBTU equivalent a day from May 1 through
October 2002 and require Murphy to pay the average relevant index price for each
month and receive an average equivalent price of $3.29 per MMBTU. The collars
are for a combined notional volume of 29,000 MMBTU a day and based upon the
relevant index prices provide Murphy with an average floor price of $2.62 per
MMBTU equivalent and an average ceiling price of $4.71 per MMBTU equivalent. At
March 31, 2002, the estimated fair value of these agreements was recorded as an
asset of $.7 million. A 10% increase in the average index price of natural gas
would have reduced this asset by $1.3 million, while a 10% decrease would have
increased the asset by a similar amount.
15
OIL AND GAS OPERATING RESULTS (unaudited)
- -----------------------------------------------------------------------------------------------------------------------------
United Synthetic
United King- Ecua- Oil -
(Millions of dollars) States Canada dom dor Malaysia Other Canada Total
- -----------------------------------------------------------------------------------------------------------------------------
Three Months Ended March 31, 2002
Oil and gas sales, other operating revenues .......... $33.0 98.9 45.5 5.6 - .6 21.7 205.3
Production expenses .................................. 14.0 20.1 11.4 3.3 - - 12.9 61.7
Depreciation, depletion and amortization ............. 9.8 34.8 9.8 1.3 .3 .1 2.1 58.2
Exploration expenses
Dry holes ......................................... 5.0 12.4 - - 5.7 - - 23.1
Geological and geophysical ........................ 2.0 7.8 - - .4 - - 10.2
Other ............................................. .4 .6 .2 - 1.6 (.1) - 2.7
- -----------------------------------------------------------------------------------------------------------------------------
7.4 20.8 .2 - 7.7 (.1) - 36.0
Undeveloped lease amortization .................... 2.5 3.5 - - - - - 6.0
- -----------------------------------------------------------------------------------------------------------------------------
Total exploration expenses ..................... 9.9 24.3 .2 - 7.7 (.1) - 42.0
- -----------------------------------------------------------------------------------------------------------------------------
Selling and general expenses ......................... 3.9 3.3 .8 .2 - 1.2 .1 9.5
Income tax provisions (benefits) ..................... (2.0) 3.0 10.1 - - (.1) 2.2 13.2
- -----------------------------------------------------------------------------------------------------------------------------
Results of operations (excluding
corporate overhead and interest) ................... $(2.6) 13.4 13.2 .8 (8.0) (.5) 4.4 20.7
=============================================================================================================================
Three Months Ended March 31, 2001
Oil and gas sales, other operating revenues .......... $96.6 94.4 50.3 10.1 - .5 26.2 278.1
Production expenses .................................. 12.2 18.1 7.2 4.4 - - 15.2 57.1
Depreciation, depletion and amortization ............. 10.3 18.2 9.8 1.8 .1 .1 2.1 42.4
Amortization of goodwill ............................. - .8 - - - - - .8
Exploration expenses
Dry holes ......................................... 15.5 3.4 .1 - - - - 19.0
Geological and geophysical ........................ 3.7 7.4 - - .3 .1 - 11.5
Other ............................................. .3 .7 .2 - .8 .3 - 2.3
- -----------------------------------------------------------------------------------------------------------------------------
19.5 11.5 .3 - 1.1 .4 - 32.8
Undeveloped lease amortization .................... 2.0 3.2 - - - - - 5.2
- -----------------------------------------------------------------------------------------------------------------------------
Total exploration expenses ..................... 21.5 14.7 .3 - 1.1 .4 - 38.0
- -----------------------------------------------------------------------------------------------------------------------------
Selling and general expenses ......................... 3.8 2.1 .6 .1 - 1.4 - 8.0
Income tax provisions (benefits) ..................... 17.7 17.8 12.3 - - (.1) 3.5 51.2
- -----------------------------------------------------------------------------------------------------------------------------
Results of operations (excluding
corporate overhead and interest) ................... $31.1 22.7 20.1 3.8 (1.2) (1.3) 5.4 80.6
=============================================================================================================================
16
PART II - OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
In June 2000, the U.S. Government filed a lawsuit against Murphy Oil USA, Inc.,
the Company's wholly-owned subsidiary, in federal court in Madison, Wisconsin,
alleging violations of environmental laws at the Company's Superior, Wisconsin
refinery. The lawsuit was divided into liability and damage phases, and on
August 1, 2001, the court ruled against the Company in the liability phase of
the trial. Subsequent to the court ruling, the Company and the U.S. Government
reached a tentative agreement that was filed with the federal court in January
2002. The settlement was approved by the court following a 30-day public comment
period that expired March 7, 2002. According to the settlement agreement, the
Company paid a civil penalty of $5.5 million in April 2002 and must implement
specified environmental projects to resolve Clean Air Act violations. The
Company had previously recorded a liability of $5.5 million to cover the
penalty.
In December 2000, two of the Company's Canadian subsidiaries as plaintiffs filed
an action in the Court of Queen's Bench of Alberta seeking a constructive trust
over oil and gas leasehold rights to Crown lands in British Columbia. The suit
alleges that the defendants acquired the lands after first inappropriately
obtaining confidential and proprietary data belonging to the Company and its
joint venturer. In January 2001, one of the defendants, representing an
undivided 75% interest in the lands in question, settled its portion of the
litigation by conveying its interest to the Company and its joint venturer at
cost. In 2001, the remaining defendants, representing the remaining undivided
25% of the lands in question, filed a counterclaim against the Company's two
Canadian subsidiaries and one officer individually seeking compensatory damages
of C$6.14 billion. The Company believes that the counterclaim is without merit
and that the amount of damages sought is frivolous and the Company does not
believe that the ultimate resolution of this suit will have a material adverse
effect on its financial condition.
Murphy and its subsidiaries are engaged in a number of other legal proceedings,
all of which Murphy considers routine and incidental to its business and none of
which is expected to have a material adverse effect on the Company's financial
condition. The ultimate resolution of matters referred to in this Item could
have a material adverse effect on the Company's results of operations in a
future period.
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
(a) The Exhibit Index on page 18 of this Form 10-Q report lists the exhibits
that are hereby filed or incorporated by reference.
(b) No reports on Form 8-K were filed for the quarter ended March 31, 2002.
SIGNATURE
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.
MURPHY OIL CORPORATION
(Registrant)
By /s/ JOHN W. ECKART
-----------------------------------
John W. Eckart, Controller
(Chief Accounting Officer and Duly
Authorized Officer)
May 6, 2002
(Date)
17
EXHIBIT INDEX
Exhibit
No. Incorporated by Reference to
- ------- ---------------------------------------------
3.1 Certificate of Incorporation of Murphy Oil Corporation Exhibit 3.1 of Murphy's Form 10-Q report for
as amended, effective May 17, 2001 the quarterly period ended June 30, 2001
3.2 By-Laws of Murphy Oil Corporation as amended effective Exhibit 3.2 of Murphy's Form 10-K report for
February 7, 2001 the year ended December 31, 2000
4 Instruments Defining the Rights of Security Holders.
Murphy is party to several long-term debt instruments in
addition to the one in Exhibit 4.1, none of which
authorizes securities exceeding 10% of the total
consolidated assets of Murphy and its subsidiaries.
Pursuant to Regulation S-K, item 601(b), paragraph
4(iii)(A), Murphy agrees to furnish a copy of each such
instrument to the Securities and Exchange Commission upon
request
4.1 Form of Indenture and Form of Supplemental Indenture Exhibits 4.1 and 4.2 of Murphy's Form 8-K
between Murphy Oil Corporation and SunTrust Bank, report filed April 29, 1999 under the
as Trustee Securities Exchange Act of 1934
4.2 Rights Agreement dated as of December 6, 1989 between Exhibit 4.3 of Murphy's Form 10-K report for
Murphy Oil Corporation and Harris Trust Company of New the year ended December 31, 1999
York, as Rights Agent
4.3 Amendment No. 1 dated as of April 6, 1998 to Rights Exhibit 3 of Murphy's Form 8-A/A, Amendment
Agreement dated as of December 6, 1989 between Murphy Oil No. 1, filed April 14, 1998 under the
Corporation and Harris Trust Company of New York, as Securities Exchange Act of 1934
Rights Agent
4.4 Amendment No. 2 dated as of April 15, 1999 to Rights Exhibit 4 of Murphy's Form 8-A/A, Amendment
Agreement dated as of December 6, 1989 between Murphy Oil No. 2, filed April 19, 1999 under the
Corporation and Harris Trust Company of New York, as Securities Exchange Act of 1934
Rights Agent
10.1 1982 Stock Incentive Plan as amended May 14, 1997 Exhibit 10.2 of Murphy's Form 10-Q report for
the quarterly period ended June 30, 1997
10.2 Employee Stock Purchase Plan as amended May 10, 2000 Exhibit 99.01 of Murphy's Form S-8
registration statement filed August 4, 2000
under the Securities Act of 1933
Exhibits other than those listed above have been omitted since they are either
not required or not applicable.
18