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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 September 30, 2001
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 September 30,
2001, was 45,309,458.
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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)
September 30, December 31,
2001 2000
------------- ------------
ASSETS
Current Assets
Cash and cash equivalents $ 161,254 132,701
Accounts receivable, less allowance for doubtful accounts of $9,852 in
2001 and $10,208 in 2000 342,183 469,616
Inventories
Crude oil and blend stocks 65,671 47,875
Finished products 88,556 68,464
Materials and supplies 47,645 48,416
Prepaid expenses 52,013 23,949
Deferred income taxes 20,735 25,916
------------ ------------
Total current assets 778,057 816,937
Property, plant and equipment, at cost less accumulated depreciation,
depletion and amortization of $3,236,389 in 2001 and $3,144,369 in 2000 2,412,164 2,184,719
Goodwill, net 43,632 48,396
Deferred charges and other assets 84,414 84,301
------------ ------------
Total assets $3,318,267 3,134,353
============ ============
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities
Current maturities of long-term debt $ 47,868 37,242
Accounts payable and accrued liabilities 554,557 639,642
Income taxes 72,128 68,343
------------ ------------
Total current liabilities 674,553 745,227
Notes payable 374,383 398,375
Nonrecourse debt of a subsidiary 107,725 126,384
Deferred income taxes 279,903 229,968
Reserve for dismantlement costs 160,657 160,049
Reserve for major repairs 41,361 34,302
Deferred credits and other liabilities 185,194 180,488
Stockholders' equity
Cumulative Preferred Stock, par $100, authorized 400,000
shares, none issued - -
Common stock, par $1.00, authorized 200,000,000 shares at
September 30, 2001 and 80,000,000 shares at December 31, 2000,
issued 48,775,314 shares 48,775 48,775
Capital in excess of par value 526,012 514,474
Retained earnings 1,084,793 833,490
Accumulated other comprehensive loss (73,342) (38,266)
Unamortized restricted stock awards (1,154) (1,410)
Treasury stock, 3,465,856 shares of Common Stock at
September 30, 2001, 3,729,769 shares at December 31, 2000, at cost (90,593) (97,503)
------------ ------------
Total stockholders' equity 1,494,491 1,259,560
------------ ------------
Total liabilities and stockholders' equity $3,318,267 3,134,353
============ ============
See Notes to Consolidated Financial Statements, page 5.
The Exhibit Index is on page 17.
1
Murphy Oil Corporation and Consolidated Subsidiaries
CONSOLIDATED STATEMENTS OF INCOME (unaudited)
(Thousands of dollars, except per share amounts)
Three Months Ended Nine Months Ended
September 30, September 30,
----------------------- -----------------------
2001 2000* 2001 2000*
---------- ---------- ---------- ----------
REVENUES
Crude oil and natural gas sales $ 197,460 196,254 667,611 508,826
Petroleum product sales 767,296 725,592 2,217,598 1,979,104
Crude oil trading sales 134,939 286,086 531,265 794,574
Other operating revenues 36,682 24,332 202,632 61,464
Interest and other nonoperating revenues 2,959 15,045 9,994 20,611
---------- ---------- ---------- ----------
Total revenues 1,139,336 1,247,309 3,629,100 3,364,579
---------- ---------- ---------- ----------
COSTS AND EXPENSES
Crude oil, products and related operating expenses 935,122 994,578 2,770,746 2,700,570
Exploration expenses, including undeveloped lease
amortization 45,541 20,899 125,091 89,617
Selling and general expenses 25,698 22,962 71,727 61,603
Depreciation, depletion and amortization 58,090 51,389 170,578 154,522
Amortization of goodwill 782 - 2,355 -
Impairment of long-lived assets - 20,997 - 20,997
Interest expense 9,516 6,821 28,962 20,393
Interest capitalized (5,065) (3,325) (12,984) (10,064)
---------- ---------- ---------- ----------
Total costs and expenses 1,069,684 1,114,321 3,156,475 3,037,638
---------- ---------- ---------- ----------
Income before income taxes and cumulative
effect of accounting change 69,652 132,988 472,625 326,941
Income tax expense 27,923 42,878 170,492 114,643
---------- ---------- ---------- ----------
Income before cumulative effect of accounting change 41,729 90,110 302,133 212,298
Cumulative effect of accounting change,
net of tax (Note B) - - - (8,733)
---------- ---------- ---------- ----------
NET INCOME $ 41,729 90,110 302,133 203,565
========== ========== ========== ==========
INCOME PER COMMON SHARE - BASIC
Before cumulative effect of accounting change $ .92 2.00 6.69 4.71
Cumulative effect of accounting change - - - (.19)
---------- ---------- ---------- ----------
NET INCOME - BASIC $ .92 2.00 6.69 4.52
========== ========== ========== ==========
INCOME PER COMMON SHARE - DILUTED
Before cumulative effect of accounting change $ .91 1.99 6.63 4.69
Cumulative effect of accounting change - - - (.19)
---------- ---------- ---------- ----------
NET INCOME - DILUTED $ .91 1.99 6.63 4.50
========== ========== ========== ==========
Average Common shares outstanding - basic 45,306,674 45,043,061 45,190,224 45,025,280
Average Common shares outstanding - diluted 45,683,102 45,305,598 45,550,230 45,237,243
*Restated to conform to 2001 presentation.
See Notes to Consolidated Financial Statements, page 5.
2
Murphy Oil Corporation and Consolidated Subsidiaries
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (unaudited)
(Thousands of dollars)
Three Months Ended Nine Months Ended
September 30, September 30,
------------------ -----------------
2001 2000* 2001 2000*
-------- ------- ------- -------
Net income $ 41,729 90,110 302,133 203,565
Other comprehensive income (loss), net of tax
Cash flow hedges
Net derivative losses (2,057) - (4) -
Reclassification adjustments (2,001) - (655) -
-------- ------- ------- -------
Total cash flow hedges (4,058) - (659) -
Net loss from foreign currency translation (19,188) (15,671) (41,056) (43,888)
-------- ------- ------- -------
Other comprehensive income (loss) before
cumulative effect of accounting change (23,246) (15,671) (41,715) (43,888)
Cumulative effect of accounting change (Note B) - - 6,642 -
-------- ------- ------- -------
Other comprehensive loss (23,246) (15,671) (35,073) (43,888)
-------- ------- ------- -------
COMPREHENSIVE INCOME $ 18,483 74,439 267,060 159,677
======== ======= ======= =======
*Restated to conform to 2001 presentation.
See Notes to Consolidated Financial Statements, page 5.
3
Murphy Oil Corporation and Consolidated Subsidiaries
CONSOLIDATED STATEMENTS OF CASH FLOWS (unaudited)
(Thousands of dollars)
Nine Months Ended
September 30,
-----------------------
2001 2000*
-------- --------
OPERATING ACTIVITIES
Income before cumulative effect of accounting change $ 302,133 212,298
Adjustments to reconcile above income to net cash provided by operating activities
Depreciation, depletion and amortization 170,578 154,522
Impairment of long-lived assets - 20,997
Provisions for major repairs 16,870 17,141
Expenditures for major repairs (14,113) (9,185)
Dry holes 65,638 49,347
Amortization of undeveloped leases 17,268 9,792
Amortization of goodwill 2,355 -
Deferred and noncurrent income tax charges 61,815 30,280
Pretax gains from disposition of assets (95,604) (2,881)
Cumulative effect of accounting change on working capital - (11,170)
Net (increase) decrease in operating working capital other than cash and cash equivalents (13,867) 55,970
Other operating activities - net 13,863 12,900
-------- --------
Net cash provided by operating activities 526,936 540,011
-------- --------
INVESTING ACTIVITIES
Property additions and dry holes (587,702) (373,365)
Proceeds from sale of property, plant and equipment 159,882 14,550
Other investing activities - net (290) (5)
-------- --------
Net cash required by investing activities (428,110) (358,820)
-------- --------
FINANCING ACTIVITIES
Decrease in notes payable (17,319) (47)
Decrease in nonrecourse debt of a subsidiary (14,706) (6,382)
Cash dividend paid (50,830) (48,399)
Proceeds from exercise of stock options and sale of stock under employee stock purchase plan 14,919 674
Other financing activities - net (2,000) -
-------- --------
Net cash required by financing activities (69,936) (54,154)
-------- --------
Effect of exchange rate changes on cash and cash equivalents (337) (5,908)
-------- --------
Net increase in cash and cash equivalents 28,553 121,129
Cash and cash equivalents at January 1 132,701 34,132
-------- --------
Cash and cash equivalents at September 30 $ 161,254 155,261
======== ========
SUPPLEMENTAL DISCLOSURES OF CASH FLOW ACTIVITIES
Cash income taxes paid $ 102,092 27,466
Interest paid, net of amounts capitalized 7,236 5,201
*Restated to conform to 2001 presentation.
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, 2000. 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 September 30, 2001, and the results
of its operations and cash flows for the three-month and nine-month periods
ended September 30, 2001 and 2000, in conformity with accounting principles
generally accepted in the United States of America.
Financial statements and notes to consolidated financial statements included in
this Form 10-Q report should be read in conjunction with the Company's 2000 Form
10-K report, as certain notes and other pertinent information have been
abbreviated or omitted in this report. Financial results for the nine months
ended September 30, 2001 are not necessarily indicative of future results.
Note B - New Accounting Principles
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). Under SFAS Nos. 133/138, 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 Income (AOCI) in the
Consolidated Balance Sheet until the 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 recognized currently
in earnings. Adoption of SFAS Nos. 133/138 resulted in a transition adjustment
gain to AOCI of $6.6 million, net of $2.8 million in income taxes 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 AOCI for the nine months ended September 30, 2001 by $.7 million, net
of $.4 million in income taxes, and decreased net income for the same period by
$.3 million, net of $.2 million in taxes, but did not affect income per diluted
share. For the nine months ended September 30, 2001, losses of $.6 million, net
of $.1 million in taxes, associated with the transition adjustment were
reclassified from AOCI to earnings.
In 2000, Murphy adopted the revenue recognition guidance in the Securities and
Exchange Commission's Staff Accounting Bulletin 101. As a result of the change,
Murphy records revenues related to its crude oil as the oil is sold, and carries
its unsold crude oil production in inventory at cost or market, whichever is
lower, rather than at market value as in the past. Consequently, Murphy
restated its 2000 operating results and recorded a transition adjustment charge
of $8.7 million, net of income tax benefits of $3.9 million, for the cumulative
effect on prior years. Excluding the transition adjustment, this accounting
change decreased income for the nine months ended September 30, 2000 by $4.9
million.
In 2000, the Company also applied the provisions of Emerging Issues Task Force
(EITF) Issue 99-19, "Reporting Revenue Gross as a Principal Versus Net as an
Agent," and Issue 00-10, "Accounting for Shipping and Handling Fees." Prior to
applying EITF 99-19, the Company reported the results of crude oil trading and
certain other downstream activities on a net margin basis in either Other
Operating Revenues or Crude Oil, Products and Related Operating Expenses in its
Statements of Income and in its refining, marketing and transportation segment
disclosures. Under EITF 99-19, the Company began reporting these activities as
gross revenues and cost of sales. Before applying EITF 00-10, the Company
reduced Crude Oil and Natural Gas Sales for certain gathering and pipeline
charges incurred prior to the point of sale. Such costs have now been recorded
as cost of sales rather than as a reduction of revenues. Due to applying these
two accounting principles, the Company's previously reported revenues and cost
of sales for all 2000 periods have been reclassified to reflect the new
presentation.
5
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)
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, gasoline
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.
Lawsuits filed against Murphy by the U.S. Government and the State of Wisconsin
are discussed under the caption "Legal Proceedings" on page 16 of this Form 10-Q
report. The Company does not believe that these 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
September 30, 2001.
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 by no means
limited to: tax increases and retroactive tax claims; import and export
controls; price controls; currency controls; 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.
6
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)
Note D - Other Contingencies (Contd.)
The Company and its subsidiaries are engaged in a number of 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 letters of credit that may be drawn upon if
the Company fails to perform under those contracts. At September 30, 2001 the
Company had contingent liabilities of $38 million under certain financial
guarantees and $41.4 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-month and nine-month periods ended September 30,
2001 and 2000. The following table reconciles the weighted-average shares
outstanding used for these computations.
- --------------------------------------------------------------------------------------------------
Reconciliation of Shares Outstanding Three Months Ended Nine Months Ended
September 30, September 30,
- --------------------------------------------------------------------------------------------------
(Weighted-average shares) 2001 2000 2001 2000
- --------------------------------------------------------------------------------------------------
Basic method........................ 45,306,674 45,043,061 45,190,224 45,025,280
Dilutive stock options.............. 376,428 262,537 360,006 211,963
- --------------------------------------------------------------------------------------------------
Diluted method 45,683,102 45,305,598 45,550,230 45,237,243
==================================================================================================
The computations of earnings per share in the Consolidated Statements of Income
did not consider outstanding options of 73,500 shares for the three-month period
of 2000, and 147,000 shares for the nine-month period of 2000, because the
effects of these options would have improved the Company's earnings per share.
Average exercise prices per share of the options not used were $65.49 and
$62.97, respectively. There were no antidilutive options for the three-month and
nine-month periods of 2001.
Note F - Risk Management and Derivative Instruments
. Interest Rate Risks - Murphy has variable-rate debt obligations consisting
of commercial paper issued under nonrecourse guaranteed credit facilities
to finance certain expenditures for the Hibernia oil field. These
obligations expose the Company to the effects of changes in interest rates.
To limit its exposure to interest rate risk on a significant portion of the
variable-rate debt, Murphy has interest rate swap agreements to hedge
fluctuations in cash flows resulting from such risk. Under the interest
rate swaps, the Company pays fixed rates and receives variable rates. 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.
For the nine months ended September 30, 2001, the income effect from cash
flow hedging ineffectiveness was insignificant. The fair value of the
effective portions of the interest rate swaps and changes thereto is
deferred in Accumulated Other Comprehensive Income (AOCI) 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.
. 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 to hedge fluctuations in cash flows resulting from such risk.
Under the natural gas swaps, the Company pays a fixed rate and receives a
floating rate in each month of settlement. 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.
7
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)
Note F - Risk Management and Derivative Instruments (Contd.)
For the nine months ended September 30, 2001, the income effect from cash
flow hedging ineffectiveness was insignificant. The fair value of the
effective portions of the natural gas swaps and changes thereto is deferred
in AOCI 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.
. 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 limited portion of its U.S.
natural gas production through February 2002 by entering into natural gas
swap contracts and natural gas options to hedge cash flow fluctuations
resulting from such risk. 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 Exploration Ltd. in 2000 is
limited by natural gas swap agreements expiring in October 2001 that were
obtained in the acquisition. These agreements hedge fluctuations in cash
flows resulting from such risk. Certain swaps require Murphy to pay a
floating price and receive a fixed price and are partially offset by swaps
on a lesser volume that require Murphy to pay a fixed price and receive a
floating price.
For the nine months ended September 30, 2001, Murphy's earnings were not
significantly impacted from cash flow hedging ineffectiveness arising from
the natural gas swaps and options in the United States and western Canada.
The fair values of the effective portions of the natural gas swaps and
options and changes thereto are deferred in AOCI and are subsequently
reclassified into Crude Oil and Natural Gas Sales in the periods in which
the hedged natural gas sales affect earnings.
. 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
for cash and entered into offsetting contracts for the remaining swap
agreements, locking in a future net cash settlement gain. The fair values
of these settlement gains and changes thereto are deferred in AOCI and are
subsequently reclassified as a reduction of Crude Oil, Products and Related
Operating Expenses in the periods in which the hedged crude oil purchases
affect earnings.
The Company expects to reclassify approximately $3.8 million in after-tax gains
from AOCI 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 2005.
8
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)
Note G - Accumulated Other Comprehensive Loss
Net gains (losses) in Accumulated Other Comprehensive Loss on the Consolidated
Balance Sheets at September 30, 2001 and December 31, 2000 were as follows.
- --------------------------------------------------------------------
(Millions of dollars) September 30, December 31,
2001 2000
- --------------------------------------------------------------------
Foreign currency translation.......... $(79.3) (38.3)
Cash flow hedging..................... 6.0 -
- --------------------------------------------------------------------
Accumulated other comprehensive loss $(73.3) (38.3)
====================================================================
Note H - Business Segments
Three Months Ended Three Months Ended
September 30, 2001 September 30, 2000/1/
Total Assets ----------------------------- ----------------------------
at Sept. 30, External Interseg. Income External Interseg. Income
(Millions of dollars) 2001 Revenues Revenues (Loss) Revenues Revenues (Loss)
- ----------------------------------------------------------------------------------------------------------------
Exploration and production/2/
United States........................ $ 534.3 31.2 12.9 4.6 56.2 18.7 8.7
Canada............................... 1,221.8 101.6 - 21.0 73.9 31.5 35.1
United Kingdom....................... 225.6 55.8 - 20.7 52.7 - 19.8
Ecuador.............................. 69.4 7.1 - 3.0 12.5 - 7.4
Other................................ 23.7 .3 - (16.8) .6 - (2.6)
- ----------------------------------------------------------------------------------------------------------------
Total 2,074.8 196.0 12.9 32.5 195.9 50.2 68.4
- ----------------------------------------------------------------------------------------------------------------
Refining, marketing and
transportation
United States........................ 786.3 827.5 - 9.0 775.1 - 4.1
United Kingdom....................... 199.0 112.4 - 5.0 113.2 - 7.3
Canada............................... - .4 - .2 148.1 .2 1.5
- ----------------------------------------------------------------------------------------------------------------
Total 985.3 940.3 - 14.2 1,036.4 .2 12.9
- ----------------------------------------------------------------------------------------------------------------
Total operating segments........... 3,060.1 1,136.3 12.9 46.7 1,232.3 50.4 81.3
Corporate and other................... 258.2 3.0 - (5.0) 15.0 - 8.8
- ----------------------------------------------------------------------------------------------------------------
Total consolidated $3,318.3 1,139.3 12.9 41.7 1,247.3 50.4 90.1
================================================================================================================
Nine Months Ended Nine Months Ended
September 30, 2001 September 30, 2000/1/
---------------------------- ----------------------------
External Interseg. Income External Interseg. Income
(Millions of dollars) Revenues Revenues (Loss) Revenues Revenues (Loss)
- ----------------------------------------------------------------------------------------------------------------
Exploration and production/2/
United States.............................. $ 163.8 43.8 60.3 140.2 54.8 22.5
Canada..................................... 320.6 30.0 72.9 188.5 84.7 85.5
United Kingdom............................. 157.3 - 62.2 140.4 11.6 58.8
Ecuador.................................... 27.4 - 11.1 38.1 - 22.1
Other...................................... 1.2 - (32.8) 1.9 - (13.4)
- ----------------------------------------------------------------------------------------------------------------
Total 670.3 73.8 173.7 509.1 151.1 175.5
- ----------------------------------------------------------------------------------------------------------------
Refining, marketing and
transportation
United States.............................. 2,372.4 - 58.3 2,060.8 .8 17.0
United Kingdom............................. 274.6 - 8.8 349.7 - 17.9
Canada..................................... 301.8 .2 71.4 424.4 .5 5.3
- ----------------------------------------------------------------------------------------------------------------
Total 2,948.8 .2 138.5 2,834.9 1.3 40.2
- ----------------------------------------------------------------------------------------------------------------
Total operating segments................. 3,619.1 74.0 312.2 3,344.0 152.4 215.7
Corporate and other......................... 10.0 - (10.1) 20.6 - (3.4)
- ----------------------------------------------------------------------------------------------------------------
Total.................................... 3,629.1 74.0 302.1 3,364.6 152.4 212.3
Cumulative effect of accounting
change.................................... - - - - - (8.7)
- ----------------------------------------------------------------------------------------------------------------
Total consolidated $3,629.1 74.0 302.1 3,364.6 152.4 203.6
================================================================================================================
/1/Restated to conform to 2001 presentation.
/2/Additional details about results of operations are presented in the tables on
page 15.
9
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
Results of Operations
Three Months Ended September 30, 2001 Compared to Three Months Ended September
30, 2000
Net income in the third quarter of 2001 totaled $41.7 million, $.91 a diluted
share, compared to income of $90.1 million, $1.99 a diluted share, in the third
quarter a year ago. Two essentially offsetting special items in the third
quarter of 2001 had no effect on diluted earnings per share. Third quarter 2000
net income included two special items with a net after-tax benefit of $1.9
million, $.04 a diluted share. Special items in the 2000 quarter included
settlement of prior years' U.S. income tax matters, which provided $15.5 million
of income to corporate functions, and an after-tax charge of $13.6 million for
impairment of two U.S. natural gas properties.
The reduction in the Company's third quarter 2001 earnings was attributable to
weaker exploration and production results. A combination of lower oil and
natural gas sales prices and higher exploration expenses, a large portion of
which was in foreign jurisdictions with no recorded tax benefits, caused the
decline in upstream results. U.S. refining and marketing income was stronger in
the current quarter compared to the 2000 quarter.
Murphy's exploration and production operations earned $26.7 million before
special items in the third quarter of 2001 compared to $82 million in the same
quarter of 2000. Exploration and production operations in the United States
earned $4.6 million compared to $22.3 million in the third quarter of 2000.
Operations in Canada earned $15.2 million compared to $35.1 million a year ago,
and U.K. operations earned $20.7 million compared to $19.8 million. Operations
in Ecuador earned $3 million in the third quarter of 2001 compared to $7.4
million a year ago. Other international operations reported a loss of $16.8
million compared to a $2.6 million loss a year earlier. The Company's worldwide
crude oil and condensate sales prices averaged $23.37 a barrel in the current
quarter compared to $27.06 a year ago. Crude oil and condensate sales prices
averaged $26.08 a barrel in the United States, down 18%, and $25.45 in the
United Kingdom, down 9%. In Canada, sales prices averaged $23.55 a barrel for
light oil, down 20% from last year; $16.50 for heavy oil, down 23%; $24.18 for
production from the offshore Hibernia field, down 9%; and $26.43 for synthetic
oil, down 15%. The average crude oil sales price in Ecuador was $18.75 a barrel,
down 22%. Total crude oil and gas liquids production averaged 64,779 barrels a
day compared to 61,852 in the third quarter of 2000. Production increased 3,967
barrels a day or 13% in Canada as light oil was up 1,632 barrels a day,
synthetic oil was up 1,022, heavy oil was up 791, and Hibernia was up 522. Oil
production also increased 877 barrels a day or 5% in the United Kingdom. In
other areas, production decreased 1,076 barrels a day or 17% in Ecuador and
declined 841 barrels a day or 13% in the United States. In the current quarter,
natural gas sales prices averaged $3.35 a thousand cubic feet (MCF) in the
United States, down 25% from the third quarter of 2000; $2.38 in Canada, down
31%; and $2.00 in the United Kingdom, up 69%. Total natural gas sales averaged a
record 295 million cubic feet a day in the current quarter compared to 211
million a year ago. Sales of natural gas in the United States averaged 111
million cubic feet a day, down from 141 million in the third quarter of 2000 as
a result of a decrease in production from mature fields in the Gulf of Mexico.
Canadian natural gas sales were a record 176 million cubic feet a day in the
current quarter, an increase of 108 million cubic feet a day due to production
from new fields in Western Canada, and U.K. sales were 8 million cubic feet a
day, up 6 million from the previous year. Exploration expenses totaled $45.5
million in the third quarter 2001 compared to $20.9 million in 2000. Exploration
expenses in the current quarter reflect increased dry hole expense versus the
prior year and $14.2 million to acquire 3-D seismic covering the Company's
significant deepwater prospects in Malaysia. The tables on page 15 provide
additional details of the results of exploration and production operations for
the third quarter of each year.
Earnings from Murphy's downstream operations before special items for the three
months ended September 30, 2001 were $19.6 million, up from $12.9 million in
2000. Refining, marketing and transportation operations in the United States
reported earnings of $14.4 million compared to $4.1 million a year ago.
Operations in the United Kingdom earned $5 million compared to $7.3 million in
the third quarter of 2000. The Company earned $1.5 million in the third quarter
of 2000 from purchasing, transporting and reselling crude oil in Canada, while
the third quarter of 2001 included earnings of $.2 million from disposal of
residual inventory following the sale of this business in the second quarter of
2001. Refinery crude runs worldwide for the quarter were 167,297 barrels a day
compared to 164,350 in the third quarter of 2000. Worldwide refined product
sales were a record at 215,091 barrels a day compared to 184,237 a year ago.
Corporate functions, which include interest income and expense and corporate
overhead not allocated to operating functions, reflected losses before special
items of $4.6 million in the current quarter compared to $6.7 million in the
third quarter of 2000.
10
MANAGEMENT'S DISCUSSION AND ANALYSIS (Contd.)
Results of Operations (Contd.)
Nine Months Ended September 30, 2001 Compared to Nine Months Ended September 30,
2000
For the first nine months of 2001, income excluding special items totaled $234.5
million, $5.15 a diluted share, compared to $208.9 million, $4.62 a diluted
share, a year ago. Net income for the current nine-month period was $302.1
million, $6.63 a diluted share, and included an after-tax benefit of $67.6
million, $1.48 a diluted share, from the gain on sale of the Company's pipeline
assets in Canada. Net income for the 2000 period was $203.6 million, $4.50 a
diluted share. Special items in 2000 included the aforementioned settlement of
prior years' U.S. income tax matters, which provided $15.5 million of income to
corporate functions, and the after-tax charge of $13.6 million for impairment of
two U.S. natural gas properties. Additionally, 2000 included an after-tax gain
of $1.5 million, $.03 a diluted share, from the sale of corporate assets.
Earnings from exploration and production operations before a special item for
the nine months ended September 30, 2001 were $167.9 million, down from $189.1
million in 2000. Canadian operations earned $67.1 million in 2001, down from
$85.5 million in 2000, and earnings in Ecuador declined from $22 million in the
2000 period to $11.1 million in 2001. Other international operations recorded
losses of $32.8 million in the first nine months of 2001 and $13.4 million in
the 2000 period. United States operations earned $60.3 million for 2001
compared to $36.1 million in the prior period, and the United Kingdom earned
$62.2 million compared to $58.8 million in 2000. The Company's worldwide crude
oil and condensate sales prices averaged $23.04 a barrel in the 2001 period
compared to $26.09 a year ago. Crude oil and condensate sales prices averaged
$26.93 a barrel in the United States, down 10%, and $26.09 in the United
Kingdom, down 4%. In Canada, sales prices averaged $24.34 a barrel for light
oil, down 10%; $12.13 for heavy oil, down 40%; $26.14 for Hibernia production,
down 3%; and $27.41 for synthetic oil, down 6%. The average crude oil sales
price in Ecuador was $18.33 a barrel, down 18%. Crude oil and gas liquids
production for the nine months of 2001 averaged 66,232 barrels a day compared to
65,065 barrels a day during the same period of 2000. Production of crude oil
and gas liquids averaged 11,942 barrels a day for Canadian heavy oil, up 18%;
4,335 for Canadian light oil, up 52%; and 9,583 for Canadian synthetic oil, up
11%. In other areas, crude oil and gas liquids production averaged 5,714 in the
United States, down 17%; 5,534 in Ecuador, down 16%; 20,154 in the United
Kingdom, down 3%; and 8,970 at Hibernia, down 2%. Natural gas sales prices for
the first nine months of 2001 averaged $5.23 per MCF in the United States, up
49%; $3.73 in Canada, up 33%; and $2.33 in the United Kingdom, up 38%. Total
natural gas sales averaged 276 million cubic feet a day in 2001 compared to 223
million in 2000. Sales of natural gas in the United States averaged 118 million
cubic feet a day, down 20%. Average natural gas sales volumes were 145 million
cubic feet a day in Canada, up 126%, and 13 million in the United Kingdom, up
19%. Exploration expenses totaled $125.1 million for the nine months ended
September 30, 2001, up from $89.6 million a year ago. The increase in
exploration expenses in the first nine months of 2001 primarily occurred in
Canada and Malaysia, partially offset by lower expenses in the United States.
The tables on page 15 provide additional details of the results of exploration
and production operations for the first nine months of each year.
Earnings from the Company's downstream operations before special items for the
nine months ended September 30, 2001 were $76.3 million, up from $40.2 million
in 2000. Refining, marketing and transportation operations in the United States
reported earnings of $63.7 million in the first nine months of 2001 compared to
$17 million for the same period last year; the improvement resulted from higher
product margins and higher product sales volumes. Operations in the United
Kingdom were affected by lower product margins and lower sales volumes and
earned $8.8 million in 2001 compared to $17.9 million in the prior year. The
Company sold its Canadian pipeline assets in the second quarter of 2001 for an
after-tax gain of $67.6 million. Excluding the gain, earnings from purchasing,
transporting and reselling crude oil in Canada were $3.8 million in the current
year compared to $5.3 million a year ago. Refinery crude runs worldwide were
168,269 barrels a day compared to 166,487 a year ago. Petroleum product sales
were 198,879 barrels a day, up from 177,326 in 2000, with the increase primarily
related to higher U.S. product sales volumes at stations built on Wal-Mart
parking lots.
Excluding special items, financial results from corporate functions reflected
losses of $9.7 million in the first nine months of 2001 and $20.4 million a year
ago.
11
MANAGEMENT'S DISCUSSION AND ANALYSIS (Contd.)
Financial Condition
Net cash provided by operating activities was $526.9 million for the first nine
months of 2001 compared to $540 million for the same period in 2000. Changes in
operating working capital other than cash and cash equivalents used cash of
$13.9 million in the first nine months of 2001, while providing cash of $56
million in the 2000 period. Cash from operating activities was reduced by
expenditures for refinery turnarounds and abandonment of oil and gas properties
totaling $14.1 million in the current year and $9.2 million in 2000. Other
predominant uses of cash in each year were for capital expenditures, which
including amounts expensed, are summarized in the following table, and for
dividends, which totaled $50.8 million in 2001 and $48.4 million in 2000.
---------------------------------------------------------------------
Nine Months Ended September 30,
---------------------------------------------------------------------
(Millions of dollars) 2001 2000
---------------------------------------------------------------------
Capital Expenditures
Exploration and production......................... $514.5 282.7
Refining, marketing and transportation............. 110.3 111.7
Corporate and other................................ 5.2 9.4
---------------------------------------------------------------------
Total capital expenditures..................... 630.0 403.8
Geological, geophysical and other exploration
expenses charged to income......................... (42.3) (30.4)
---------------------------------------------------------------------
Total property additions and dry hole costs $587.7 373.4
=====================================================================
Working capital at September 30, 2001 was $103.5 million, up $31.8 million from
December 31, 2000. This level of working capital does not fully reflect the
Company's liquidity position, because the lower historical costs assigned to
inventories under LIFO accounting were $103.9 million below current costs at
September 30, 2001.
At September 30, 2001, long-term notes payable of $374.4 million were down $24
million from December 31, 2000 due to repayments and reclassification to current
maturities. Long-term nonrecourse debt of a subsidiary was $107.7 million, down
$18.7 million from December 31, 2000 primarily due to repayments. A summary of
capital employed at September 30, 2001 and December 31, 2000 follows.
- -----------------------------------------------------------------------------
Capital Employed September 30, 2001 December 31, 2000
- -----------------------------------------------------------------------------
(Millions of dollars) Amount % Amount %
- -----------------------------------------------------------------------------
Notes payable........................ $ 374.4 19 398.4 22
Nonrecourse debt of a subsidiary..... 107.7 5 126.4 7
Stockholders' equity................. 1,494.5 76 1,259.6 71
- -----------------------------------------------------------------------------
$1,976.6 100 1,784.4 100
=============================================================================
12
MANAGEMENT'S DISCUSSION AND ANALYSIS (Contd.)
Accounting Matters
As described in Note B on page 5 of this Form 10-Q report, 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, effective January 1, 2001. In addition, the
Company adopted a change in accounting for unsold crude oil production effective
January 1, 2000, restating operating results for all of 2000, and also has
retroactively applied two consensuses of the Financial Accounting Standard
Board's Emerging Issues Task Force to the Consolidated Statement of Income for
all of 2000.
In July 2001, the Financial Accounting Standards Board (FASB) issued SFAS No.
141, "Business Combinations", and SFAS No. 142, "Goodwill and Other Intangible
Assets". SFAS No. 141 requires that all future business combinations be
accounted for using the purchase method of accounting and that certain acquired
intangible assets in a business combination be recognized and reported as assets
apart from goodwill. SFAS No. 142 requires that amortization of goodwill be
replaced with periodic tests of the goodwill's impairment at least annually in
accordance with the provisions of this statement and that intangible assets
other than goodwill be amortized over their useful lives. The Company will
adopt SFAS No. 141 immediately and SFAS No. 142 on January 1, 2002. As of the
date of adoption, the Company expects to have unamortized goodwill of
approximately $43 million, which will be subject to the transition provisions of
SFAS No. 142. Amortization expense related to goodwill was $2.4 million for the
nine months ended September 30, 2001.
In July 2001, the FASB issued SFAS No. 143, "Accounting for Asset Retirement
Obligations". SFAS No. 143 requires the Company to record the fair value of a
liability for an asset retirement obligation in the period in which the
obligation meets the definition of a liability. 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 the Statement, the Company will recognize transition amounts for existing
asset retirement obligations, long-lived assets and accumulated depreciation 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 results of operations. The Company is required to adopt the
provisions of SFAS No. 143 effective January 1, 2003.
In October 2001, the FASB issued SFAS No. 144, "Accounting for the Impairment or
Disposal of Long-Lived Assets." SFAS No. 144 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," for the disposal of a segment of a business as defined
in APB Opinion No. 30. The Company is required to adopt the provisions of SFAS
No. 144 effective January 1, 2002. The provisions of SFAS No. 144 generally are
to be applied prospectively.
It is not practicable to reasonably estimate the impact of adopting these
accounting standards on the Company's financial statements at the date of this
report, including whether any transitional goodwill impairment losses will be
required to be recognized as the cumulative effect of a change in accounting
principle.
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.
13
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 September 30, 2001 with
notional amounts totaling $100 million that were designed to convert a similar
amount of variable-rate debt to fixed rates. 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 September 30, 2001, the interest rate to be
received by the Company averaged 3.58%. The variable interest rate received by
the Company under each swap contract is repriced quarterly. The Company
considers these swaps to be a hedge of its exposure to fluctuations in interest
rates. The estimated fair value of these interest rate swaps was recorded as a
liability of $4.9 million at September 30, 2001.
At September 30, 2001, 19% of the Company's debt had variable interest rates and
10% was denominated in Canadian dollars. Based on debt outstanding at September
30, 2001, a 10% increase in variable interest rates would have an insignificant
impact on the Company's interest expense 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 September 30, 2001
for a total notional volume of 7.7 million 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 $2.68 an MMBTU and to receive the average NYMEX price for the final
three trading days of the month. At September 30, 2001, the estimated fair
value of these agreements was recorded as an asset of $4.2 million. A 10%
increase in the average NYMEX price of natural gas would have increased this
asset by $2.2 million, while a 10% decrease would have reduced the asset by a
similar amount.
At September 30, 2001, Murphy was also a party to certain natural gas swap
agreements for a total notional volume of 20,000 gigajoules (GJ) a day through
October 2001 that are intended to hedge a portion of the financial exposure of
its Canadian natural gas production to changes in gas sales prices. In each
month, the swaps require Murphy to pay the AECO "C" index price and to receive
an average of C$2.47 per GJ. The Company also has a natural gas swap agreement
for the purchase of 10,000 GJ per day through October 2001 that requires Murphy
to pay C$5.64 per GJ and to receive based on the AECO "C" index. At September
30, 2001, the estimated net fair value of these agreements was recorded as a
liability of $1 million. A 10% increase in the average price of the AECO "C"
index would have increased this liability by $.1 million, while a 10% decrease
would have reduced the liability by a similar amount.
In addition, the Company was a party to natural gas swap agreements and natural
gas options at September 30, 2001 that are intended to hedge the financial
exposure of a limited portion of its U.S. natural gas production to changes in
gas sales prices through February 2002. The swaps are for a notional volume
ranging from 5,000 to 10,000 MMBTU a day and require Murphy to pay the average
NYMEX price for the final trading day of each month and receive a price ranging
from $2.91 to $5.50 an MMBTU. The options are for a notional volume of 5,000
MMBTU a day and provides that in each month, Murphy will receive any difference
between $4.50 an MMBTU and a lower average NYMEX price for the last three
trading days of the first nearby month futures contract for the relevant
delivery month. At September 30, 2001, the estimated fair value of these
agreements was recorded as an asset of $1.6 million. A 10% increase in the
average NYMEX price of natural gas would have reduced this asset by $.2 million,
while a 10% decrease would have increased the asset by a similar amount.
14
OIL AND GAS OPERATING RESULTS/1/ (unaudited)
- ----------------------------------------------------------------------------------------------------------------
Synthetic
United United Oil -
(Millions of dollars) States Canada Kingdom Ecuador Other Canada Total
- ----------------------------------------------------------------------------------------------------------------
Three Months Ended September 30, 2001
Oil and gas sales, other operating revenues...... $ 44.1 79.4 55.8 7.1 .3 22.2 208.9
Production expenses.............................. 11.2 17.4 10.0 2.7 - 11.3 52.6
Depreciation, depletion and amortization......... 9.8 23.6 9.5 1.3 .2 2.0 46.4
Goodwill amortization............................ - .8 - - - - .8
Exploration expenses
Dry holes....................................... 8.0 11.3 - - (.3) - 19.0
Geological and geophysical...................... 1.7 .7 - - 13.7 - 16.1
Other........................................... 1.0 .4 .3 - 2.3 - 4.0
- ----------------------------------------------------------------------------------------------------------------
10.7 12.4 .3 - 15.7 - 39.1
Undeveloped lease amortization.................. 2.9 3.5 - - - - 6.4
- ----------------------------------------------------------------------------------------------------------------
Total exploration expenses 13.6 15.9 .3 - 15.7 - 45.5
- ----------------------------------------------------------------------------------------------------------------
Selling and general expenses..................... 3.1 3.3 .5 .1 1.4 .1 8.5
Income tax provisions (benefits)................. 1.8 8.6 14.8 - (.2) 3.4 28.4
- ----------------------------------------------------------------------------------------------------------------
Results of operations (excluding
corporate overhead and interest) $ 4.6 9.8 20.7 3.0 (16.8) 5.4 26.7
================================================================================================================
Three Months Ended September 30, 2000/2/
Oil and gas sales, other operating revenues...... $ 74.9 82.0 52.7 12.5 .6 23.4 246.1
Production expenses.............................. 10.6 14.6 8.0 3.6 - 10.1 46.9
Depreciation, depletion and amortization......... 12.3 15.8 8.4 1.4 .2 1.9 40.0
Exploration expenses
Dry holes....................................... 10.2 .6 - - - - 10.8
Geological and geophysical...................... .9 2.5 - - .8 - 4.2
Other........................................... .9 .1 .4 - .9 - 2.3
- ----------------------------------------------------------------------------------------------------------------
12.0 3.2 .4 - 1.7 - 17.3
Undeveloped lease amortization.................. 2.0 1.6 - - - - 3.6
- ----------------------------------------------------------------------------------------------------------------
Total exploration expenses 14.0 4.8 .4 - 1.7 - 20.9
- ----------------------------------------------------------------------------------------------------------------
Selling and general expenses..................... 3.5 1.4 .7 .1 1.3 - 7.0
Income tax provisions............................ 12.2 17.0 15.4 - - 4.7 49.3
- ----------------------------------------------------------------------------------------------------------------
Results of operations (excluding
corporate overhead and interest) $ 22.3 28.4 19.8 7.4 (2.6) 6.7 82.0
================================================================================================================
Nine Months Ended September 30, 2001
Oil and gas sales, other operating revenues...... $ 207.6 278.9 157.3 27.4 1.2 71.7 744.1
Production expenses.............................. 36.0 53.7 24.8 11.1 - 39.8 165.4
Depreciation, depletion and amortization......... 30.5 65.5 28.2 4.9 .5 6.2 135.8
Goodwill amortization............................ - 2.4 - - - - 2.4
Exploration expenses
Dry holes....................................... 23.7 34.5 .1 - 7.3 - 65.6
Geological and geophysical...................... 5.4 9.7 .1 - 17.2 - 32.4
Other........................................... 2.4 1.7 .8 - 5.0 - 9.9
- ----------------------------------------------------------------------------------------------------------------
31.5 45.9 1.0 - 29.5 - 107.9
Undeveloped lease amortization.................. 7.0 10.2 - - - - 17.2
- ----------------------------------------------------------------------------------------------------------------
Total exploration expenses 38.5 56.1 1.0 - 29.5 - 125.1
- ----------------------------------------------------------------------------------------------------------------
Selling and general expenses..................... 9.8 8.4 1.7 .3 4.4 .1 24.7
Income tax provisions (benefits)................. 32.5 41.4 39.4 - (.4) 9.9 122.8
- ----------------------------------------------------------------------------------------------------------------
Results of operations (excluding
corporate overhead and interest) $ 60.3 51.4 62.2 11.1 (32.8) 15.7 167.9
================================================================================================================
Nine Months Ended September 30, 2000/2/
Oil and gas sales, other operating revenues...... $ 195.0 204.2 152.0 38.1 1.9 69.0 660.2
Production expenses.............................. 31.1 38.6 21.8 10.8 - 29.2 131.5
Depreciation, depletion and amortization......... 39.5 43.1 29.2 5.0 .3 5.7 122.8
Exploration expenses
Dry holes....................................... 45.2 3.9 - - .3 - 49.4
Geological and geophysical...................... 6.1 8.9 .2 - 8.5 - 23.7
Other........................................... 2.0 .5 1.1 - 3.1 - 6.7
- ----------------------------------------------------------------------------------------------------------------
53.3 13.3 1.3 - 11.9 - 79.8
Undeveloped lease amortization.................. 5.6 4.2 - - - - 9.8
- ----------------------------------------------------------------------------------------------------------------
Total exploration expenses 58.9 17.5 1.3 - 11.9 - 89.6
- ----------------------------------------------------------------------------------------------------------------
Selling and general expenses..................... 9.9 3.6 2.3 .2 2.9 .1 19.0
Income tax provisions............................ 19.5 36.9 38.6 - .2 13.0 108.2
- ----------------------------------------------------------------------------------------------------------------
Results of operations (excluding
corporate overhead and interest) $ 36.1 64.5 58.8 22.1 (13.4) 21.0 189.1
================================================================================================================
/1/ Excludes special items.
/2/ Restated to conform to 2001 presentation.
15
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. The damage phase of the trial has
been continued while the parties attempt to conclude a settlement. The
Company expects that the resolution of the lawsuit will likely include
monetary fines and future capital and environmental improvements at the
Superior refinery. While settlement discussions are confidential and not
finalized, the Company has established a reserve of $5.5 million towards
resolution of the lawsuit. Although no assurance can be given, the Company
does not believe that the ultimate resolution of this matter will have a
material adverse effect on its financial condition.
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 February 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. While the
litigation is in its preliminary stages and no assurance can be given about
the outcome, 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.
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
(a) The Exhibit Index on page 17 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 September 30,
2001.
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)
November 9, 2001
(Date)
16
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 the
as amended, effective May 17, 2001 quarterly period ended June 30, 2001
3.2 By-Laws of Murphy Oil Corporation as amended, Exhibit 3.2 of Murphy's Form 10-K report for the
effective February 7, 2001 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 ones in Exhibits 4.1 and 4.2, 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 Credit Agreement among Murphy Oil Corporation and Exhibit 4.1 of Murphy's Form 10-K report for the
certain subsidiaries and the Chase Manhattan Bank et year ended December 31, 1997
al as of November 13, 1997
4.2 Form of Indenture and Form of Supplemental Indenture Exhibits 4.1 and 4.2 of Murphy's Form 8-K report
between Murphy Oil Corporation and SunTrust Bank, filed April 29, 1999 under the Securities
Nashville, N.A., as Trustee Exchange Act of 1934
4.3 Rights Agreement dated as of December 6, 1989 between Exhibit 4.3 of Murphy's Form 10-K report for the
Murphy Oil Corporation and Harris Trust Company of New year ended December 31, 1999
York, as Rights Agent
4.4 Amendment No. 1 dated as of April 6, 1998 to Rights Exhibit 3 of Murphy's Form 8-A/A, Amendment No.
Agreement dated as of December 6, 1989 between Murphy 1, filed April 14, 1998 under the Securities
Oil Corporation and Harris Trust Company of New York, Exchange Act of 1934
as Rights Agent
4.5 Amendment No. 2 dated as of April 15, 1999 to Rights Exhibit 4 of Murphy's Form 8-A/A, Amendment No.
Agreement dated as of December 6, 1989 between Murphy 2, filed April 19, 1999 under the Securities
Oil Corporation and Harris Trust Company of New York, Exchange Act of 1934
as Rights Agent
10.1 1992 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.
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