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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, 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 March 31, 2001
was 45,075,469.
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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,
2001 2000
----------- ------------
ASSETS
Current assets
Cash and cash equivalents $ 165,299 132,701
Accounts receivable, less allowance for doubtful accounts of $10,197 in 2001
and $10,208 in 2000 374,363 469,616
Inventories, at lower of cost or market
Crude oil and blend stocks 65,079 47,875
Finished products 73,221 68,464
Materials and supplies 46,685 48,416
Prepaid expenses 26,103 23,949
Deferred income taxes 21,871 25,916
----------- ------------
Total current assets 772,621 816,937
Property, plant and equipment, at cost less accumulated depreciation, depletion
and amortization of $3,138,572 in 2001 and $3,144,369 in 2000 2,221,386 2,184,719
Goodwill, net 45,256 48,396
Deferred charges and other assets 90,862 84,301
----------- ------------
Total assets $ 3,130,125 3,134,353
=========== ============
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities
Current maturities of long-term debt $ 44,615 37,242
Accounts payable and accrued liabilities 575,699 639,642
Income taxes 85,234 68,343
----------- ------------
Total current liabilities 705,548 745,227
Notes payable 390,404 398,375
Nonrecourse debt of a subsidiary 123,902 126,384
Deferred income taxes 239,487 229,968
Reserve for dismantlement costs 156,823 160,049
Reserve for major repairs 38,129 34,302
Deferred credits and other liabilities 175,908 180,488
Stockholders' equity
Cumulative Preferred Stock, par $100, authorized 400,000 shares, none issued - -
Common Stock, par $1.00, authorized 80,000,000 shares,
issued 48,775,314 shares 48,775 48,775
Capital in excess of par value 515,727 514,474
Retained earnings 914,430 833,490
Accumulated other comprehensive loss (80,886) (38,266)
Unamortized restricted stock awards (1,412) (1,410)
Treasury stock, 3,699,845 shares of Common Stock in 2001,
3,729,769 shares in 2000, at cost (96,710) (97,503)
----------- ------------
Total stockholders' equity 1,299,924 1,259,560
----------- ------------
Total liabilities and stockholders' equity $ 3,130,125 3,134,353
=========== ============
See Notes to Consolidated Financial Statements, page 5.
The Exhibit Index is on page 16.
1
Murphy Oil Corporation and Consolidated Subsidiaries
CONSOLIDATED STATEMENTS OF INCOME (unaudited)
(Thousands of dollars, except per share amounts)
Three Months Ended
March 31,
-------------------------------
2001 2000*
------------ ------------
REVENUES
Crude oil and natural gas sales $ 237,199 153,008
Petroleum product sales 672,231 569,431
Crude oil trading sales 238,460 277,426
Other operating revenues 37,805 19,440
Interest and other nonoperating revenues 3,690 1,209
------------ ------------
Total revenues 1,189,385 1,020,514
------------ ------------
COSTS AND EXPENSES
Crude oil, products and related operating expenses 913,211 821,614
Exploration expenses, including undeveloped lease amortization 37,961 47,858
Selling and general expenses 21,046 17,860
Depreciation, depletion and amortization 54,232 55,572
Amortization of goodwill 788 -
Interest expense 9,744 6,793
Interest capitalized (3,586) (3,198)
------------ ------------
Total costs and expenses 1,033,396 946,499
------------ ------------
Income before income taxes and cumulative effect of accounting change 155,989 74,015
Income tax expense 58,153 24,872
------------ ------------
Income before cumulative effect of accounting change 97,836 49,143
Cumulative effect of accounting change, net of tax (Note B) - (8,733)
------------ ------------
NET INCOME $ 97,836 40,410
============ ============
INCOME PER COMMON SHARE - BASIC
Before cumulative effect of accounting change $ 2.17 1.09
Cumulative effect of accounting change - (.19)
------------ ------------
NET INCOME - BASIC $ 2.17 .90
============ ============
INCOME PER COMMON SHARE - DILUTED
Before cumulative effect of accounting change $ 2.16 1.09
Cumulative effect of accounting change - (.19)
------------ ------------
NET INCOME - DILUTED $ 2.16 .90
============ ============
Average Common shares outstanding - basic 45,056,307 45,009,089
Average Common shares outstanding - diluted 45,314,981 45,159,265
*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
March 31,
-----------------------------
2001 2000*
----------- -----------
Net income $ 97,836 40,410
----------- -----------
Other comprehensive income (loss), net of tax
Cash flow hedges
Net derivative gains 599 -
Reclassification adjustments 1,578 -
----------- -----------
Total cash flow hedges 2,177 -
Net loss from foreign currency translation (51,439) (4,646)
----------- -----------
Other comprehensive loss before cumulative effect of accounting change (49,262) (4,646)
Cumulative effect of accounting change (Note B) 6,642 -
----------- -----------
Other comprehensive loss (42,620) (4,646)
----------- -----------
COMPREHENSIVE INCOME $ 55,216 35,764
=========== ===========
*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)
Three Months Ended
March 31,
------------------------------
2001 2000*
------------ ------------
OPERATING ACTIVITIES
Income before cumulative effect of accounting change $ 97,836 49,143
Adjustments to reconcile above income to net cash provided by operating activities
Depreciation, depletion and amortization 54,232 55,572
Provisions for major repairs 5,500 5,593
Expenditures for major repairs and dismantlement costs (2,449) (5,654)
Dry hole costs 19,005 36,562
Amortization of undeveloped leases 5,230 2,995
Amortization of goodwill 788 -
Deferred and noncurrent income tax charges 16,966 4,454
Pretax gains from disposition of assets (86) (541)
Cumulative effect of accounting change on working capital - (11,170)
Net decrease in operating working capital other than cash
and cash equivalents 29,862 27,465
Other operating activities - net 6,568 (4,140)
------------ ------------
Net cash provided by operating activities 233,452 160,279
------------ ------------
INVESTING ACTIVITIES
Property additions and dry hole costs (179,649) (127,541)
Proceeds from the sale of property, plant and equipment 2,266 4,360
Other investing activities - net (92) (10)
------------ ------------
Net cash required by investing activities (177,475) (123,191)
------------ ------------
FINANCING ACTIVITIES
Decrease in notes payable (10) (23)
Decrease in nonrecourse debt of a subsidiary (3,070) (272)
Cash dividends paid (16,896) (15,754)
Other financing activities - net 1,495 163
------------ ------------
Net cash required by financing activities (18,481) (15,886)
------------ ------------
Effect of exchange rate changes on cash and cash equivalents (4,898) (1,088)
------------ ------------
Net increase in cash and cash equivalents 32,598 20,114
Cash and cash equivalents at January 1 132,701 34,132
------------ ------------
Cash and cash equivalents at March 31 $ 165,299 54,246
============ ============
SUPPLEMENTAL DISCLOSURES OF CASH FLOW ACTIVITIES
Cash income taxes paid $ 28,325 14,220
Net interest paid (capitalized) (2,024) (649)
*Reclassified 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 March 31, 2001, and the results of
operations and cash flows for the three-month periods ended March 31, 2001 and
2000, 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 2000 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, 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). 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 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 immediately recognized 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, 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 increased AOCI for the three
months ended March 31, 2001 by $2.2 million, net of $1.6 million in income
taxes, and increased income for the same period by $.2 million, net of $.1
million in taxes, but did not affect income per diluted share. For the three
months ended March 31, 2001, losses of $1.6 million, net of $1.2 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 at cost or market, whichever is lower, rather
than at market value as in the past. Consequently, Murphy restated its operating
results for the first quarter of 2000 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 increased income for the three months ended March 31, 2000 by
$1.7 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 the first three months of 2000 have been reclassified to reflect
the new presentation.
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.
5
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)
Note C - Environmental Contingencies (Contd.)
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 15 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 March
31, 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.
In addition to the lawsuits discussed under the caption "Legal Proceedings" on
page 15 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, 2001, the Company had contingent
liabilities of $127.3 million under certain financial guarantees and $50.3
million on outstanding letters of credit.
6
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)
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, 2001 and 2000. 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) 2001 2000
---------------------------------------------------------------------------------------------------------
Basic method............................................................... 45,056,307 45,009,089
Dilutive stock options..................................................... 258,674 150,176
---------------------------------------------------------------------------------------------------------
Diluted method 45,314,981 45,159,265
=========================================================================================================
The computations of earnings per share in the Consolidated Statements of Income
did not consider outstanding options at the end of the periods of 73,000 shares
in 2001 and 543,000 shares in 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 $58.59, respectively.
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 three months ended March 31, 2001, the income effect from cash flow
hedging ineffectiveness arising from expected differences between the
floating rates of the interest rate swaps and interest payments under the
hedged debt obligations was insignificant. The fair value 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. For the 12 months
following March 31, 2001, approximately $1.1 million of after-tax losses in
AOCI related to the interest rate swaps are expected to be reclassified
into earnings as a rate adjustment of the hedged interest expense.
. 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. In 1999, as a result of its belief that natural gas
prices would increase dramatically from 1999 levels in the following three
to five years, Murphy minimized the effect of fluctuations in the price of
natural gas used for fuel at Meraux in 2002, 2003 and 2004 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.
For the three months ended March 31, 2001, the income effect from cash flow
hedging ineffectiveness arising from the expected differences between the
floating prices of the natural gas swaps and purchase prices for the hedged
natural gas fuel purchase requirements was insignificant. The fair value 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. For the 12 months following March 31, 2001, approximately
$.9 million of after-tax gains in AOCI related to the natural gas swaps are
expected to be reclassified into earnings as an adjustment of the hedged
natural gas fuel purchases.
7
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)
Note F - Risk Management and Derivative Instruments (Contd.)
. 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 fluctuations in the selling price of a limited portion of its
U.S. natural gas production from April through October 2001 by entering
into a natural gas swap contract and a natural gas collar 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 as a part of 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 three months ended March 31, 2001, Murphy's earnings included
after-tax gains of $.2 million from cash flow hedging ineffectiveness
arising from the expected differences between the terms of the natural gas
swaps and collars and the selling prices for the hedged natural gas sales
in the United States and western Canada. The fair values of the effective
portions of the natural gas swaps 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. For the
12 months following March 31, 2001, approximately $.8 million of net after-
tax losses in AOCI related to the natural gas swaps are expected to be
reclassified into earnings as an adjustment of the hedged natural gas
sales.
. 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. For the 12 months following March 31, 2001, approximately
$3.6 million of net after-tax gains in AOCI related to the crude oil swaps
are expected to be reclassified into earnings as an adjustment of the
hedged crude oil purchases.
Note G - Accumulated Other Comprehensive Loss
Net gains (losses) in Accumulated Other Comprehensive Loss on the Consolidated
Balance Sheets at March 31, 2001 and December 31, 2000 were as follows.
- -------------------------------------------------------------------------------------------------------------
(Millions of dollars) March 31, December 31,
2001 2000
- -------------------------------------------------------------------------------------------------------------
Foreign currency translation $ (89.7) (38.3)
Cash flow hedging 8.8 -
- -------------------------------------------------------------------------------------------------------------
Accumulated other comprehensive loss $ (80.9) (38.3)
=============================================================================================================
8
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)
Note H - Subsequent Event
In May 2001, the Company completed the sale of its Canadian pipeline and
trucking operation for total proceeds of approximately $163,000,000, including
inventory. Murphy expects to record an after-tax gain of approximately
$68,000,000 on this transaction in the second quarter of 2001.
Note I - Business Segments
Three Mos. Ended March 31, 2001 Three Mos. Ended March 31, 2000*
Total Assets ------------------------------- -------------------------------
at March 31, External Interseg. Income External Interseg. Income
(Millions of dollars) 2001 Revenues Revenues (Loss) Revenues Revenues (Loss)
- --------------------------------------------------------------------------------------------------------------------
Exploration and production**
United States $ 426.8 79.4 17.2 31.1 38.0 18.5 (6.1)
Canada 1,157.0 99.7 20.9 28.1 57.2 29.8 27.7
United Kingdom 224.0 50.3 - 20.1 46.6 11.6 23.2
Ecuador 72.1 10.1 - 3.8 12.5 - 7.7
Other 18.2 .5 - (2.5) .7 - (1.5)
- --------------------------------------------------------------------------------------------------------------------
Total 1,898.1 240.0 38.1 80.6 155.0 59.9 51.0
- --------------------------------------------------------------------------------------------------------------------
Refining, marketing and
transportation
United States 701.1 706.2 - 15.0 603.3 .7 (1.6)
United Kingdom 165.1 78.5 - 1.8 121.9 - 4.9
Canada 112.4 161.0 .1 2.8 139.1 .1 1.5
- --------------------------------------------------------------------------------------------------------------------
Total 978.6 945.7 .1 19.6 864.3 .8 4.8
- --------------------------------------------------------------------------------------------------------------------
Total operating segments 2,876.7 1,185.7 38.2 100.2 1,019.3 60.7 55.8
Corporate and other 253.4 3.7 - (2.4) 1.2 - (6.7)
- --------------------------------------------------------------------------------------------------------------------
Total 3,130.1 1,189.4 38.2 97.8 1,020.5 60.7 49.1
Cumulative effect of accounting
change - - - - - - (8.7)
- --------------------------------------------------------------------------------------------------------------------
Total consolidated $3,130.1 1,189.4 38.2 97.8 1,020.5 60.7 40.4
====================================================================================================================
*Restated to conform to 2001 presentation.
**Additional details about results of operations are presented in the tables on
page 14.
9
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 2001 set a quarterly record and
totaled $97.8 million, $2.16 a diluted share, compared to income of $49.1
million, $1.09 a diluted share, before the cumulative effect of an accounting
change in the first quarter a year ago. Net income in the first quarter of 2000
totaled $40.4 million, $.90 a share, and included an after-tax charge of $8.7
million, $.19 a share, for an accounting change to carry the Company's unsold
crude oil production at the lower of cost or market rather than at market. Cash
flow from operating activities, excluding changes in noncash working capital
items and the aforementioned accounting change, totaled $203.6 million for the
current quarter compared to $144 million in the same quarter last year.
In the current quarter, the Company's exploration and production operations
earned $80.6 million, an increase of 58% over the $51 million earned in the
first quarter of 2000. The increase was primarily the result of significantly
higher North American natural gas prices and higher gas sales volumes. Murphy's
downstream operations generated earnings of $19.6 million in the first quarter
of 2001, a substantial improvement over the $4.8 million earned in the same
period of 2000. Financial results from the Company's U.S. downstream operations
were noticeably stronger in the 2001 quarter, generating income of $15 million.
Exploration and production operations in the United States reported earnings of
$31.1 million compared to a loss of $6.1 million in the first quarter of 2000.
This improvement was primarily due to higher natural gas sales prices and lower
exploration expenses. U.S. natural gas sales prices averaged $7.21 a thousand
cubic feet in the current quarter, up 174% compared to $2.63 a year ago, and
U.S. exploration expenses were down $17.8 million. Sales of natural gas averaged
125 million cubic feet a day, down from 154 million in the first quarter of 2000
due to lower production in the Gulf of Mexico. The average crude oil and
condensate price in the United States was down 5% to $27.42 a barrel, while
crude oil and liquids sales decreased 26% to 5,503 barrels a day. U.S.
production costs were up $2.3 million or 23%, primarily because of more well
maintenance.
Operations in Canada earned $28.1 million compared to $27.7 million a year ago
as higher results from natural gas operations in western Canada were nearly
offset by increases in production costs and exploration expenses. Canadian
natural gas sales averaged 106 million cubic feet a day in the current quarter,
up 93%, and the average natural gas sales price nearly tripled. Canadian
production costs in the 2001 quarter were up 64% or $13 million, primarily
because of higher costs for natural gas used in producing synthetic and heavy
oils, and higher maintenance and other costs at the synthetic oil operations.
Exploration expenses were $7.8 million higher than in the 2000 quarter. Crude
oil and liquids sales in Canada averaged 35,091 barrels a day, an increase of 5%
over the prior year. Average Canadian crude oil sales increased 3,580 barrels a
day or 38% for heavy oil, 2,041 or 25% for synthetic oil, and 1,443 or 46% for
light oil. Crude oil sales decreased 5,313 barrels a day or 43% at the Hibernia
field, offshore Newfoundland, primarily because of the timing of liftings;
average daily production at Hibernia of 8,953 was down 6% because of
constrictions related to the disposal of associated gas production. Canadian
crude oil sales prices for the quarter averaged $25.03 a barrel for light oil,
down 5%; $9.43 for heavy oil, down 52%; $27.05 for offshore oil, up 5%; and
$28.17 for synthetic oil, virtually unchanged.
U.K. operations earned $20.1 million in the current quarter, down from $23.2
million in the prior year. Sales of crude oil and liquids in the United Kingdom
decreased 16% primarily due to the timing of liftings and averaged 18,808
barrels a day; average crude oil production decreased 6% to 20,825 barrels a
day. Sales prices for U.K. crude oil averaged $27.10 a barrel in the first
quarter of 2001, up 2% over last year. The average sales price for natural gas
in the United Kingdom increased 45%, but gas sales decreased 12% to 18 million
cubic feet a day.
Operations in Ecuador earned $3.8 million in the first quarter of 2001 compared
to $7.7 million a year ago, while other international operations reported a loss
of $2.5 million compared to a loss of $1.5 million in 2000. Although crude oil
production in Ecuador decreased 20% and the average sales price decreased 21% to
$17.75 a barrel, crude oil sales averaged 6,352 barrels a day, up slightly from
the prior year due to the timing of shipments. Production costs in Ecuador were
up $1.3 million.
10
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS (Contd.)
Results of Operations (Contd.)
On a worldwide basis, the Company's crude oil and condensate prices averaged
$22.65 a barrel in the current quarter, a decrease of 11% from the average of
$25.59 in the 2000 period. Average crude oil and liquids production was 69,054
barrels a day, up 3% over last year, but average sales volumes decreased 5% to
65,754 barrels a day due to the timing of liftings. Total natural gas sales
averaged 249 million cubic feet a day in 2001, up 9% from the 2000 period. The
tables on page 14 provide additional details of the results of exploration and
production operations for the first quarter of each year.
Refining, marketing and transportation operations in the United States earned
$15 million during the first quarter of 2001 compared to a loss of $1.6 million
a year ago. The Company's U.S. refineries processed a record volume of crude
oil, and refining margins per barrel were much improved in the current quarter
compared to margins experienced in the first quarter of 2000. U.S. petroleum
product sales averaged 164,556 barrels a day in 2001, a 21% increase from the
first quarter of 2000. Operations in the United Kingdom earned $1.8 million in
the first quarter of 2001 compared to $4.9 million a year ago as margins were
under pressure during most of the current quarter. Worldwide refinery crude runs
were 172,319 barrels a day in the first quarter of 2001 compared to 161,966, and
petroleum product sales were 189,097 barrels a day, up from 166,934 a year ago.
Earnings from purchasing, transporting and reselling crude oil in Canada were
$2.8 million in the current quarter compared to $1.5 million in the first
quarter of 2000. As discussed in Note H on page 9 of this Form 10-Q report, the
Company sold its Canadian pipeline and trucking operations in May 2001.
Corporate activities, which include interest income and expense and corporate
overhead not allocated to operating functions, reflected a loss of $2.4 million
in the current quarter compared to a loss of $6.7 million in the first quarter
of 2000.
Financial Condition
Net cash provided by operating activities was $233.5 million for the first three
months of 2001 compared to $160.3 million during the same period in 2000.
Changes in operating working capital other than cash and cash equivalents
required cash of $29.9 million in the first quarter of 2001 and $27.5 million in
the 2000 period. Cash from operating activities was reduced by $11.2 million in
the 2000 quarter for the cumulative effect of the aforementioned accounting
change.
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 $16.9 million in 2001 and $15.8 million in 2000.
---------------------------------------------------------------------------------------------
Three Months Ended March 31,
---------------------------------------------------------------------------------------------
(Millions of dollars) 2001 2000
---------------------------------------------------------------------------------------------
Capital Expenditures
Exploration and production ..................................... $ 163.2 114.6
Refining, marketing and transportation .......................... 28.3 20.3
Corporate and other ............................................. 1.9 .9
---------------------------------------------------------------------------------------------
Total capital expenditures................................... 193.4 135.8
Geological, geophysical and other exploration
expenses charged to income........................................ (13.8) (8.3)
---------------------------------------------------------------------------------------------
Total property additions and dry hole costs $ 179.6 127.5
=============================================================================================
Working capital at March 31, 2001 was $67.1 million, down $4.6 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 last-in first-out accounting were $122 million below current
costs at March 31, 2001.
At March 31, 2001, long-term notes payable of $390.4 million were down $8
million from December 31, 2000 due to a reclassification to current maturities.
Long-term nonrecourse debt of a subsidiary was $123.9 million, down slightly
from December 31, 2000 due to changes in foreign currency exchange rates. A
summary of capital employed at March 31, 2001 and December 31, 2000 follows.
11
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS (Contd.)
Financial Condition (Contd.)
-------------------------------------------------------------------------------------------
Capital Employed March 31, 2001 Dec. 31, 2000
-------------------------------------------------------------------------------------------
(Millions of dollars) Amount % Amount %
-------------------------------------------------------------------------------------------
Notes payable .................................. $ 390.4 21 398.4 22
Nonrecourse debt of a subsidiary................ 123.9 7 126.4 7
Stockholders' equity............................ 1,299.9 72 1,259.6 71
-------------------------------------------------------------------------------------------
Total capital employed $ 1,814.2 100 1,784.4 100
===========================================================================================
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 the first quarter 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
the first quarter of 2000.
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.
12
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, 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 March 31, 2001, the interest rate to be received by the
Company averaged 5.44%. 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 $3.3 million
at March 31, 2001.
At March 31, 2001, 19% of the Company's debt had variable interest rates and 12%
was denominated in Canadian dollars. Based on debt outstanding at March 31,
2001, a 10% increase in variable interest rates would reduce the Company's
interest expense for the next 12 months by $.1 million after a $.5 million
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 $.2 million and increase current maturities of long-term debt
by $.8 million for debt denominated in Canadian dollars.
Murphy was a party to natural gas price swap agreements at March 31, 2001 for a
total notional volume of 7 million MMBTU that are intended to hedge a portion of
the financial exposure of its Meraux, Louisiana refinery to fluctuations in the
price of natural gas purchased for fuel in 2002 through 2004. In each month of
settlement, the swaps require Murphy to pay an average natural gas price of
$2.61 an MMBTU and to receive the average NYMEX price for the final three
trading days of the month. At March 31, 2001, the estimated fair value of these
agreements was recorded as an asset of $10.4 million. A 10% increase in the
average NYMEX price of natural gas would have increased this asset by $2.6
million, while a 10% decrease would have reduced the asset by a similar amount.
At March 31, 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 March 31,
2001, the estimated net fair value of these agreements was recorded as a
liability of $10.5 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 a natural gas swap agreement and a
natural gas collar agreement at March 31, 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 October 2001. The swap is for a notional
volume of 10,000 MMBTU a day and requires Murphy to pay the average NYMEX price
for the final trading day of each month and receive a price of $5.50 an MMBTU.
The collar is 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 but will pay any
difference between $8.00 and a higher average NYMEX price. At March 31, 2001,
the estimated fair value of these agreements was recorded as an asset of $.9
million. A 10% increase in the average NYMEX price of natural gas would have
reduced this asset by $1.2 million, while a 10% decrease would have increased
the asset by a similar amount.
13
OIL AND GAS OPERATING RESULTS (unaudited)
- --------------------------------------------------------------------------------------------------------------------------
United Synthetic
United King- Ecua- Oil -
(Millions of dollars) States Canada dom dor Other Canada Total
- --------------------------------------------------------------------------------------------------------------------------
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 costs.................................. 12.2 18.1 7.2 4.4 - 15.2 57.1
Depreciation, depletion and amortization.......... 10.3 18.2 9.8 1.8 .2 2.1 42.4
Amortization of goodwill.......................... - .8 - - - - .8
Exploration expenses
Dry hole costs................................. 15.5 3.4 .1 - - - 19.0
Geological and geophysical costs............... 3.7 7.4 - - .4 - 11.5
Other costs ................................... .3 .7 .2 - 1.1 - 2.3
- --------------------------------------------------------------------------------------------------------------------------
19.5 11.5 .3 - 1.5 - 32.8
Undeveloped lease amortization................. 2.0 3.2 - - - - 5.2
- --------------------------------------------------------------------------------------------------------------------------
Total exploration expenses 21.5 14.7 .3 - 1.5 - 38.0
- --------------------------------------------------------------------------------------------------------------------------
Selling and general expenses ..................... 3.8 2.1 .6 .1 1.4 - 8.0
Income tax provisions............................. 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 (2.5) 5.4 80.6
==========================================================================================================================
Three Months Ended March 31, 2000*
Oil and gas sales, other operating revenues....... $ 56.5 65.6 58.2 12.5 .7 21.4 214.9
Production costs.................................. 9.9 12.0 7.6 3.1 - 8.3 40.9
Depreciation, depletion and amortization.......... 14.1 15.2 12.5 1.7 .1 1.8 45.4
Exploration expenses
Dry hole costs................................. 33.7 2.9 - - - - 36.6
Geological and geophysical costs............... 3.5 2.6 .1 - .3 - 6.5
Other costs.................................... .3 .2 .2 - 1.1 - 1.8
- --------------------------------------------------------------------------------------------------------------------------
37.5 5.7 .3 - 1.4 - 44.9
Undeveloped lease amortization................. 1.8 1.2 - - - - 3.0
- --------------------------------------------------------------------------------------------------------------------------
Total exploration expenses................. 39.3 6.9 .3 - 1.4 - 47.9
- --------------------------------------------------------------------------------------------------------------------------
Selling and general expenses...................... 3.0 1.3 .8 - .6 - 5.7
Income tax provisions............................. (3.7) 9.9 13.8 - .1 3.9 24.0
- --------------------------------------------------------------------------------------------------------------------------
Results of operations (excluding
corporate overhead and interest) $ (6.1) 20.3 23.2 7.7 (1.5) 7.4 51.0
==========================================================================================================================
*Restated to conform to 2001 presentation.
14
PART II - OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
On June 29, 2000, the U.S. Government and the State of Wisconsin each
filed a lawsuit against Murphy in the U.S. District Court for the
Western District of Wisconsin. The State action was subsequently
dismissed by the federal court and refiled in state court in Douglas
County, Wisconsin. The suits, arising out of a 1998 compliance
inspection, include claims for alleged violations of federal and state
environmental laws at Murphy's Superior, Wisconsin refinery. The suits
seek compliance as well as substantial federal and state monetary
penalties, which could exceed $100,000. The Company believes it has
valid defenses to these allegations and plans a vigorous defense. The
enforcement actions are ongoing, and while no assurance can be given
about the outcome, the Company does not believe that the resolution of
these matters will have a material adverse effect on its financial
condition. The federal court trial is scheduled to commence on June 4,
2001.
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. On February 9, 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. 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 16 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,
2001.
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
Registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
MURPHY OIL CORPORATION
(Registrant)
By /s/ JOHN W. ECKART
-----------------------------
John W. Eckart, Controller
(Chief Accounting Officer and
Duly Authorized Officer)
May 8, 2001
(Date)
15
EXHIBIT INDEX
Exhibit
No. Incorporated by Reference to
- ------- ------------------------------------------
3.1 Certificate of Incorporation of Murphy Oil Corporation as amended Exhibit 4.01 to Murphy's Form S-8
registration statement filed May 19, 1997
under the Securities Act of 1933
3.2 By-Laws of Murphy Oil Corporation as amended effective February 7, Exhibit 3.2 of Murphy's Form 10-K report
2001 for 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 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 certain subsidiaries Exhibit 4.1 of Murphy's Form 10-K report
and the Chase Manhattan Bank et al as of November 13, 1997 for the year ended December 31, 1997
4.2 Form of Indenture and Form of Supplemental Indenture between Murphy Exhibits 4.1 and 4.2 of Murphy's Form 8-K
Oil Corporation and SunTrust Bank, Nashville, N.A., as Trustee report filed April 29, 1999 under the
Securities Exchange Act of 1934
4.3 Rights Agreement dated as of December 6, 1989 between Murphy Oil Exhibit 4.3 of Murphy's Form 10-K report
Corporation and Harris Trust Company of New York, as Rights Agent for the year ended December 31, 1999
4.4 Amendment No. 1 dated as of April 6, 1998 to Rights Agreement dated as Exhibit 3 of Murphy's Form 8-A/A,
of December 6, 1989 between Murphy Oil Corporation and Harris Trust Amendment No. 1, filed April 14, 1998
Company of New York, as Rights Agent under the Securities Exchange Act of 1934
4.5 Amendment No. 2 dated as of April 15, 1999 to Rights Agreement dated Exhibit 4 of Murphy's Form 8-A/A,
as of December 6, 1989 between Murphy Oil Corporation and Harris Trust Amendment No. 2, filed April 19, 1999
Company of New York, as Rights Agent under the Securities Exchange Act of 1934
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.
16