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, 2003
OR
¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
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
incorporation or organization)
(I.R.S. Employer
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 ¨
Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act).
xYes No ¨
Number of shares of Common Stock, $1.00 par value, outstanding at March 31, 2003 was 91,786,970.
PART I – FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Thousands of dollars)
March 31,
2003
December 31,
2002
(Unaudited)
ASSETS
Current assets
Cash and cash equivalents
$
216,889
164,957
Accounts receivable, less allowance for doubtful accounts of $10,070 in 2003 and $9,307 in 2002
471,375
408,782
Inventories, at lower of cost or market
Crude oil and blend stocks
42,481
41,961
Finished products
103,962
94,158
Materials and supplies
69,772
65,225
Prepaid expenses
45,264
59,962
Deferred income taxes
17,609
19,115
Total current assets
967,352
854,160
Property, plant and equipment, at cost less accumulated depreciation, depletion and amortization of $3,476,618 in 2003 and $3,361,726 in 2002
3,131,818
2,886,599
Goodwill, net
54,593
51,037
Deferred charges and other assets
90,561
93,979
Total assets
4,244,324
3,885,775
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities
Current maturities of long-term debt
58,939
57,104
Accounts payable and accrued liabilities
693,662
599,229
Income taxes
72,658
61,559
Total current liabilities
825,259
717,892
Notes payable
830,350
788,554
Nonrecourse debt of a subsidiary
65,147
74,254
338,894
327,771
Asset retirement obligations
259,198
160,543
Accrued major repair costs
57,074
52,980
Deferred credits and other liabilities
154,031
170,228
Stockholders’ equity
Cumulative Preferred Stock, par $100, authorized 400,000 shares, none issued
—
Common Stock, par $1.00, authorized 200,000,000 shares, issued 94,613,379 shares
94,613
Capital in excess of par value
503,791
504,983
Retained earnings
1,205,936
1,137,177
Accumulated other comprehensive loss
(16,088
)
(66,790
Treasury stock, 2,826,409 shares of Common Stock in 2003 and 2,923,925 shares in 2002, at cost
(73,881
(76,430
Total stockholders’ equity
1,714,371
1,593,553
Total liabilities and stockholders’ equity
See Notes to Consolidated Financial Statements, page 5.
The Exhibit Index is on page 22.
1
Murphy Oil Corporation and Consolidated Subsidiaries
CONSOLIDATED STATEMENTS OF INCOME (unaudited)
(Thousands of dollars, except per share amounts)
Three Months Ended
2002*
REVENUES
Sales and other operating revenues
1,321,314
748,470
Gain on sale of assets
24
5,736
Interest and other income
975
1,003
Total revenues
1,322,313
755,209
COSTS AND EXPENSES
Crude oil and product purchases
904,693
484,321
Operating expenses
154,013
128,362
Exploration expenses, including undeveloped lease amortization
24,150
42,021
Selling and general expenses
30,822
22,362
Depreciation, depletion and amortization
75,805
69,706
Accretion on discounted liabilities
3,115
Interest expense
13,961
9,542
Interest capitalized
(9,536
(4,817
Total costs and expenses
1,197,023
751,497
Income from continuing operations before income taxes
125,290
3,712
Income tax expense
31,185
1,381
Income from continuing operations
94,105
2,331
Discontinued operations, net of tax
203
Cumulative effect of change in accounting principle, net of tax
(6,993
NET INCOME
87,112
2,534
INCOME (LOSS) PER COMMON SHARE – BASIC
1.03
.03
Discontinued operations
Cumulative effect of change in accounting principle
(.08
NET INCOME – BASIC
.95
INCOME (LOSS) PER COMMON SHARE – DILUTED
1.02
NET INCOME – DILUTED
.94
Average common shares outstanding – basic
91,738,379
91,017,906
Average common shares outstanding – diluted
92,349,666
91,806,092
*Reclassified to conform to 2003 presentation.
2
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (unaudited)
Three Months Ended March 31,
Net income
Other comprehensive income (loss), net of tax
Cash flow hedges
Net derivative gains (losses)
(19,687
2,947
Reclassification adjustments
18,449
(3,323
Total cash flow hedges
(1,238
(376
Net gain (loss) from foreign currency translation
52,647
(4,996
Minimum pension liability adjustment
(707
COMPREHENSIVE INCOME (LOSS)
137,814
(2,838
3
CONSOLIDATED STATEMENTS OF CASH FLOWS (unaudited)
OPERATING ACTIVITIES
Adjustments to reconcile income from continuing operations to net cash provided by operating activities
Provisions for major repairs
6,410
4,579
Expenditures for major repairs and asset retirement obligations
(3,780
(2,104
Dry holes
7,114
23,112
Amortization of undeveloped leases
6,332
6,062
Deferred and noncurrent income tax benefits
(14,898
(264
Pretax gains from disposition of assets
(24
(5,736
Net (increase) decrease in operating working capital other than cash and cash equivalents
44,272
(66,189
Other
(5,905
32
Net cash provided by continuing operations
212,546
31,529
Net cash provided by discontinued operations
1,186
Net cash provided by operating activities
32,715
INVESTING ACTIVITIES
Property additions and dry holes
(183,281
(204,613
Proceeds from the sale of assets
8,006
27,877
Other – net
30
(145
Investing activities of discontinued operations
(247
Net cash required by investing activities
(175,245
(177,128
FINANCING ACTIVITIES
Increase in notes payable
42,024
156,992
Decrease in nonrecourse debt of a subsidiary
(9,056
(4,051
Proceeds from exercise of stock options and employee stock purchase plans
943
18,058
Cash dividends paid
(18,353
(17,057
(72
Net cash provided by financing activities
15,486
153,942
Effect of exchange rate changes on cash and cash equivalents
(855
(1,052
Net increase in cash and cash equivalents
51,932
8,477
Cash and cash equivalents at January 1
82,652
Cash and cash equivalents at March 31
91,129
SUPPLEMENTAL DISCLOSURES OF CASH FLOW ACTIVITIES
Cash income taxes paid
33,993
8,262
Interest capitalized in excess of amounts paid
(6,357
(87
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, 2002. 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, 2003, and the results of operations and cash flows for the three-month periods ended March 31, 2003 and 2002, 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 2002 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, 2003 are not necessarily indicative of future results.
Note B – New Accounting Principles
The Company adopted Emerging Issues Task Force (EITF) Topic 02-3 in the fourth quarter of 2002. Based on Topic
02-3, Murphy has reflected the results of its crude oil trading activities as net revenue in its income statement, and previously reported revenues and cost of sales in the three-month period ended March 31, 2002 have been reduced by equal and offsetting amounts, with no changes to net income or cash flows. The effect of this reclassification was a net reduction of both net sales and cost of crude oil and product purchases by approximately $63 million in the 2002 period.
On January 1, 2003, the Company adopted Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations, which requires the Company to record a liability equal to the fair value of the estimated cost to retire an asset. The asset retirement liability is recorded in the period in which the obligation meets the definition of a liability, which is generally when the asset is placed in service. When the liability is initially recorded, the Company will increase the carrying amount of the related long-lived asset by an amount equal to the original liability. The liability is accreted to its present value each period, and the capitalized cost is depreciated over the useful life of the related long-lived asset. Any difference between costs incurred upon settlement of an asset retirement obligation and the recorded liability will be recognized as a gain or loss in the Company’s earnings. The asset retirement obligation is based on a number of assumptions requiring professional judgment. The Company cannot predict the type of revisions to these assumptions that will be required in future periods due to the availability of additional information, including prices for oil field services, technological changes, governmental requirements and other factors. Upon adoption of SFAS No. 143, the Company recorded a charge of $7 million, net of $1.4 million in income taxes, as the cumulative effect of a change in accounting principle. The noncash transition adjustment increased property, plant and equipment, accumulated depreciation, and asset retirement obligations by $142.9 million, $58.8 million, and $92.5 million, respectively.
The majority of the asset retirement obligation (ARO) recognized by the Company at March 31, 2003 relates to the estimated costs to dismantle and abandon its investment in producing oil and gas properties and related equipment. A portion of the transition adjustment and ARO relates to its investment in retail gasoline stations. The Company did not record a retirement obligation for certain of its refining and marketing assets because sufficient information is presently not available to estimate a range of potential settlement dates for the obligation. In these cases, the obligation will be initially recognized in the period in which sufficient information exists to estimate the obligation.
A reconciliation of the beginning and ending aggregate carrying amount of the asset retirement obligations is shown in the following table.
December 31, 2002
Transition adjustment
92,500
Accretion expense
Liabilities settled
(1,353
Changes due to translation of foreign currencies
4,393
March 31, 2003
5
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)
Note B – New Accounting Principles (Contd.)
The pro forma asset retirement obligations as of January 1, 2002 and March 31, 2002 were $220 million and $223.2 million, respectively. Pro forma net income for the period ended March 31, 2002, assuming SFAS No. 143 had been applied retroactively, is shown in the following table.
(Thousands of dollars except per share data)
Net income – As reported
Pro forma
3,164
Net income per share – As reported, basic
Pro forma, basic
As reported, diluted
Pro forma, diluted
On January 1, 2003, the Company adopted SFAS No. 145, Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections, and SFAS No. 146, Accounting for Costs Associated with Exit or Disposal Activities. SFAS No. 145 amends existing guidance on reporting gains and losses on the extinguishment of debt to prohibit the classification of the gain or loss as extraordinary and also amends SFAS No. 13 to require sale-leaseback accounting for certain lease modifications that have economic effects similar to sale-leaseback transactions. SFAS No. 146 addresses financial accounting and reporting for costs associated with exit or disposal activities and nullifies EITF Issue 94-3, Liability Recognition for certain Employee Termination Benefits and Other Costs to Exit an Activity. The adoption of these two accounting standards did not have a material effect on the Company’s financial statements.
Additionally, in the first quarter of 2003, the Company has applied FASB issued Interpretation No. 45, Guarantor’s Accounting and Disclosure Requirement for Guarantees, Including Indirect Guarantees of Indebtedness to Others, an Interpretation of FASB Statements No. 5, 57 and 107 and a rescission of FASB Interpretation No. 34, and FASB Interpretation No. 46, Consolidation of Variable Interest Entities, an interpretation of ARB No. 51. Interpretation No. 45 elaborates on the disclosures to be made by a guarantor in its financial statements about its obligations under guarantees issued and requires a guarantor to recognize, at inception of a guarantee, a liability for the fair value of the obligation undertaken. Interpretation No. 46 addresses the consolidation by business enterprises of variable interest entities as defined in the Interpretation. The application of these two FASB Interpretations did not have a material effect on the Company’s financial statements.
Note C – Discontinued Operations
In December 2002, the Company sold its investment in Ship Shoal Block 113 in the Gulf of Mexico. Operations for the field in the first three months of 2002 have been reported as Discontinued Operations in the Consolidated Statements of Income. Revenues and pretax earnings from the field in the first quarter of 2002 were $2.9 million and $.3 million, respectively.
Note D – Environmental Contingencies
In addition to being 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 three refineries, 11 terminals, and approximately 80 service stations for which known or potential obligations for environmental remediation exist. In addition the Company operates or has operated numerous oil and gas fields that may require some form of remediation, which is generally provided for by the Company’s asset retirement obligation.
The Company’s liability for remedial obligations includes 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 accrued liability by up to an estimated $3 million.
6
Note D – Environmental Contingencies (Contd.)
The Company has received notices from the U.S. Environmental Protection Agency (EPA) that it is currently considered a Potentially Responsible Party (PRP) at two Superfund sites. The potential total cost to all parties to perform necessary remedial work at these sites may be substantial. At one site the Company paid $6,500 to obtain release from further obligations. The Company’s insurance carrier has agreed to reimburse the $6,500. Based on currently available information, the Company believes that it is a de minimus party as to ultimate responsibility at the other Superfund site. The Company could be required to bear a pro rata share of costs attributable to nonparticipating PRPs or could be assigned additional responsibility for remediation at the one remaining site or other Superfund sites. The Company does not believe that the ultimate costs to clean-up the two Superfund sites will have a material adverse effect on its net income or cash flows in a future period.
There is the possibility that environmental expenditures could be required at currently unidentified sites, and new or revised regulations could require additional expenditures at known sites. However, based on information currently available to the Company, the amount of future remediation costs incurred at known or currently unidentified sites is not expected to have a material adverse effect on future earnings or cash flows.
Note E – Other Contingencies
The Company’s operations and earnings have been and may be affected by various 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 and the protection and/or remediation of the environment; 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 and may be taken without full consideration of their consequences or 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 December 2000, two of the Company’s Canadian subsidiaries, Murphy Oil Company Ltd. (MOCL) and Murphy Canada Exploration Company (MCEC) 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, the Predator Corporation Ltd. and Predator Energies Partnership (collectively Predator) and Ricks Nova Scotia Co. (Ricks), acquired the lands after first inappropriately obtaining confidential and proprietary data belonging to the Company and its partner. In January 2001, Ricks, 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 partner at cost. In 2001, Predator, representing the remaining undivided 25% of the lands in question, filed a counterclaim, as subsequently amended, against MOCL and MCEC and MOCL’s president individually seeking compensatory damages of C$4.61 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.
On March 5, 2002, two of the Company’s subsidiaries filed suit against Enron Canada Corp. (Enron) to collect approximately $2.1 million owed to Murphy under canceled gas sales contracts. On May 1, 2002, Enron counterclaimed for approximately $19.8 million allegedly owed by Murphy under those same agreements. Although the lawsuit in the Court of Queen’s Bench, Alberta, is in its early stages and no assurance can be given, the Company does not believe that the Enron counterclaim is meritorious and does not believe that the ultimate resolution of this matter 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. Based on information currently available to the Company, the ultimate resolution of environmental and legal matters referred to in this note is not expected to have a material adverse effect on the Company’s earnings or financial condition in a future period.
7
Note E – Other Contingencies (Contd.)
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, 2003, the Company had contingent liabilities of $12.7 million under a financial guarantee and $44.5 million on outstanding letters of credit. The Company has not accrued a liability in its balance sheet related to these letters of credit because it is believed that the likelihood of having these drawn is remote.
Note F – Earnings per Share and Stock Options
Net income was used as the numerator in computing both basic and diluted income per Common share for the three months ended March 31, 2003 and 2002. The following table reconciles the weighted-average shares outstanding used for these computations.
March 31
(Weighted-average shares)
Basic method
Dilutive stock options
611,287
788,186
Diluted method
There were no antidilutive options for the periods ended March 31, 2003 or 2002.
The Company accounts for its stock options using the intrinsic-value based method of accounting as prescribed by Accounting Principles Board (APB) Opinion No. 25, Accounting for Stock Issued to Employees, and related interpretations. Under this method, compensation expense is not recorded for stock options since all option prices have been equal to or greater than the fair market value of the Company’s stock on the date of grant. The Company would record compensation expense for any stock options deemed to be variable in nature. The Company accrues compensation expense for restricted stock awards and adjusts such costs for changes in the fair market value of Common Stock. SFAS No. 123, Accounting for Stock-Based Compensation, established accounting and disclosure requirements using a fair-value based method for stock-based employee compensation plans. As allowed by SFAS No. 123, the Company has elected to continue to apply the intrinsic-value based method prescribed by APB No. 25 and has adopted only the disclosure requirements of SFAS No. 123. Had the Company recorded compensation expense for stock options as prescribed by SFAS No. 123, net income and earnings per share for the three-month periods ended March 31, 2003 and 2002, would be the pro forma amounts shown in the following table.
86,045
1,401
.02
.92
Note G – Financial Instruments and Risk Management
Murphy utilizes derivative instruments to manage certain risks related to interest rates, commodity prices, and foreign currency exchange rates. The use of derivative instruments for risk management is covered by operating policies and is closely monitored by the Company’s senior management. The Company does not hold any derivatives for speculative purposes, and it does not use derivatives with leveraged or complex features. Derivative instruments are traded primarily with creditworthy major financial institutions or over national exchanges.
8
Note G – Financial Instruments and Risk Management (Contd.)
Company pays fixed rates averaging 6.17% over their composite lives and receives variable rates which averaged 1.32% at March 31, 2003. The variable rate received by the Company under each contract is repriced quarterly. The Company has a risk management control system to monitor interest rate cash flow risk attributable to the Company’s outstanding and forecasted debt obligations as well as the offsetting interest rate swaps. The control system involves using analytical techniques, including cash flow sensitivity analysis, to estimate the impact of interest rate changes on future cash flows. The fair value of the effective portions of the interest rate swaps and changes thereto is deferred in Accumulated Other Comprehensive Loss (AOCL) and is subsequently reclassified into Interest Expense in the periods in which the hedged interest payments on the variable-rate debt affect earnings. For the periods ended March 31, 2003 and 2002, the income effect from cash flow hedging ineffectiveness of interest rates was insignificant. The fair value of the interest rate swaps are estimated using projected Federal funds rates, Canadian overnight funding rates and LIBOR forward curve rates obtained from published indices and counterparties. The estimated fair value approximates the values based on quotes from each of the counterparties.
The fair values of the effective portions of the natural gas swaps and collars and changes thereto are deferred in AOCL and are subsequently reclassified into Sales and Other Operating Revenues in the income statement in the periods in which the hedged natural gas sales affect earnings. For the periods ended March 31, 2003 and 2002, Murphy’s earnings were not significantly affected by cash flow hedging ineffectiveness.
During the three-month period ended March 31, 2003, the Company paid approximately $7 million for settlement of natural gas swap and collar agreements in the U.S. and Canada, and during the same period in 2002, received approximately $1.4 million.
The fair value of the natural gas fuel swaps and the natural gas sales swaps and collars are both based on the average fixed price of the instruments and the published NYMEX and AECO “C” index futures price or natural gas price quotes from counterparties.
9
The fair values of the effective portions of the crude oil hedges and changes thereto are deferred in AOCL and are subsequently reclassified into Sales and Other Operating Revenues in the income statement in the periods in which the hedged crude oil sales affect earnings. In the first quarter of 2003, cash flow hedging ineffectiveness relating to the crude oil sales swaps increased Murphy’s after-tax earnings by $.7 million.
During the three-month period ended March 31, 2003 the Company paid approximately $24.9 million for settlement of maturing swaps.
The fair value of the crude oil sales swaps are based on the average fixed price of the instruments and the published NYMEX index futures price or crude oil price quotes from counterparties.
During the next twelve months, the Company expects to reclassify approximately $11 million in net after-tax losses from AOCL into earnings as the forecasted transactions covered by hedging instruments actually occur. All forecasted transactions currently being hedged are expected to occur by December 2006.
Note H – Accumulated Other Comprehensive Loss
The components of Accumulated Other Comprehensive Loss on the Consolidated Balance Sheets at March 31, 2003 and December 31, 2002 are presented in the following table.
(Millions of dollars)
Foreign currency translation
(4.3
(56.9
Cash flow hedging, net
(9.7
(8.5
Minimum pension liability, net
(2.1
(1.4
(16.1
(66.8
10
Note H – Accumulated Other Comprehensive Loss (Contd.)
The effect of SFAS Nos. 133/138, Accounting for Derivative Instruments and Hedging Activities, decreased AOCL for the three months ended March 31, 2003 by $1.2 million, net of $1.3 million in income taxes, and hedging ineffectiveness increased net income by $.6 million, net of $.5 million in income taxes. For the 2003 period losses of $18.4 million, net of $12.9 million in taxes, were reclassified from AOCL to earnings. During the three-month period ended March 31, 2002, AOCL decreased $.4 million, net of $.1 million in income taxes, and hedging ineffectiveness increased net income by $.1 million net of tax. Gains of $3.3 million, net of $1.8 million in taxes, were reclassified from AOCL to earnings in the 2002 period.
Note I – Business Segments
Total Assets at March 31, 2003
Three Mos. Ended
March 31, 2002
External Revenues
Interseg. Revenues
Income (Loss)
Exploration and production*
United States
702.7
50.7
12.8
30.0
.1
(2.8
Canada
1,394.8
168.6
13.0
55.9
101.9
18.7
17.8
United Kingdom
244.9
58.2
19.1
45.5
13.2
Ecuador
97.1
11.3
5.5
5.6
.8
Malaysia
140.5
(5.5
(8.0
17.3
.7
(.9
.6
(.5
Total
2,597.3
289.5
86.9
183.6
18.8
20.5
Refining and marketing
North America
1,086.4
909.5
(6.4
489.9
(11.5
229.8
122.3
2.9
80.7
(2.2
1,316.2
1,031.8
(3.5
570.6
(13.7
Total operating segments
3,913.5
1,321.3
83.4
754.2
6.8
Corporate and other
330.8
1.0
10.7
(4.5
Total from continuing operations
4,244.3
1,322.3
94.1
755.2
2.3
11
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 2003 totaled $87.1 million, $.94 a diluted share, compared to net income of $2.5 million, $.03 a diluted share, in the first quarter a year ago. The 2003 period included a $20.1 million gain related to resolution of prior years’ income tax matters. Additionally, upon adoption of Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations, effective January 1, 2003, the Company recorded a charge of $7 million, $.08 per share, as the cumulative effect of a change in accounting principle.
In the first quarter of 2003, the Company’s exploration and production operations earned $86.9 million compared to continuing operating results of $20.5 million in the same quarter of 2002. Higher sales prices for crude oil and natural gas and lower exploration expenses in Canada and Malaysia were the primary reasons for improved earnings. The Company’s refining and marketing operations incurred a loss of $3.5 million in the 2003 first quarter compared to a $13.7 million loss in the 2002 quarter. The loss in the Company’s North American operations were approximately one-half of the loss in the first quarter of 2002, with the primary improvement coming from stronger retail marketing margins.
Exploration and Production
Results of continuing exploration and production operations are presented by geographic segment below.
Exploration and production
Other International
Exploration and production operations in the United States reported earnings of $12.8 million in the first quarter 2003 compared to a loss of $2.8 million in the 2002 quarter. This increase was primarily due to higher natural gas and oil sales prices. Sales of natural gas averaged 78 million cubic feet a day, down from 98 million in the first quarter of 2002 due to lower production in the Gulf of Mexico. U.S. production expenses were down $4.6 million, primarily because of lower well workover costs in the 2003 period.
Operations in Canada earned $55.9 million this quarter compared to $17.8 million a year ago due to record oil production, higher average oil and natural gas sales prices and lower exploration expenses. Oil and gas liquids sales in Canada averaged 51,871 barrels a day, an increase of 11% over the prior year, primarily because of higher production at the Terra Nova field in 2003. Canadian natural gas sales averaged 139 million cubic feet a day in the current quarter, down 31%, with the decrease primarily attributable to lower production from the Ladyfern field. Canadian production expenses in the 2003 quarter were virtually unchanged at $37 million, primarily because of lower natural gas production partially offset by higher costs of synthetic oil operations. Exploration expenses were $14.4 million lower than in the 2002 quarter primarily because of lower dry hole costs and less geological and geophysical spending.
U.K. operations earned $19.1 million in the current quarter, up from $13.2 million in the prior year. Higher sales prices for crude oil in 2003 were partially offset by lower sales volumes of oil and gas liquids.
Operations in Ecuador earned $5.5 million in the first quarter of 2003 compared to $.8 million a year ago, while Malaysia and other international operations reported losses of $5.5 million and $.9 million, respectively, compared to losses of $8 million and $.5 million in 2002. The increase in earnings in Ecuador was primarily the result of increased sales prices. The lower loss in Malaysia in the current period was primarily due to decreased dry hole costs partially offset by increased geological and geophysical expenses primarily associated with the Company’s contract in peninsular Malaysia.
12
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)
Results of Operations (Contd.)
Exploration and Production (Contd.)
On a worldwide basis, the Company’s crude oil and condensate sales prices averaged $26.87 a barrel in the current quarter, an increase of 36% from the average of $19.76 in the 2002 period. Average crude oil and liquids production was 74,984 barrels a day, up 1% over last year, but average sales volumes decreased 2% to 78,299 barrels a day due to the timing of liftings. Total natural gas sales volumes averaged 228 million cubic feet a day in 2003, down 26% from the 2002 period. The tables on page 18 provide additional details of the results of exploration and production operations for the first quarter of each year. Selected operating statistics for the three-month periods ended March 31, 2003 and 2002 follow.
Net crude oil, condensate and gas liquids produced–barrels per day
74,984
74,292
Continuing operations
73,130
3,319
5,023
Canada–light
3,434
4,069
–heavy
9,287
9,722
–offshore
27,792
19,759
–synthetic
9,343
11,342
18,439
19,031
3,370
4,184
1,162
Net crude oil, condensate and gas liquids sold–barrels per day
78,299
80,208
79,046
29,807
21,436
18,618
23,247
4,491
4,207
Net natural gas sold–thousands of cubic feet per day
228,164
309,290
305,737
77,958
97,741
138,570
199,486
11,636
8,510
3,553
Total net hydrocarbons produced–equivalent barrels per day (1)
113,011
125,840
Total net hydrocarbons sold–equivalent barrels per day (1)
116,326
131,756
Weighted average sales prices
Crude oil and condensate–dollars a barrel (2)
24.78
(4)
19.94
Canada (3)–light
29.69
17.86
12.65
13.39
28.12
21.95
25.63
21.23
32.46
20.73
27.88
14.84
Natural gas–dollars a thousand cubic feet
United States (2)
6.30
2.60
Canada (3)
5.20
2.12
United Kingdom (3)
3.51
2.96
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Refining and Marketing
Results of refining and marketing operations are presented below by geographic segment.
Refining and marketing operations in North America reported a loss of $6.4 million during the first quarter of 2003 compared to a loss of $11.5 million a year ago. The Company’s U.S. retail marketing margins were improved in the current quarter compared to margins experienced in the first quarter of 2002. The first quarter 2002 results included a net gain of $3.5 million from sale of the Company’s interest in Butte Pipe Line. Operations in the United Kingdom reflected earnings of $2.9 million in the first quarter of 2003 compared to a loss of $2.2 million a year ago, with the improvement mostly associated with better refining margins compared to the 2002 period. Worldwide refinery inputs were 160,940 barrels a day in the first quarter of 2003 compared to 154,512 in the 2002 quarter, and petroleum product sales were 228,261 barrels a day, up from 191,318 a year ago.
Selected operating statistics for the three-month periods ended March 31, 2003 and 2002 follow.
Refinery inputs–barrels a day
160,940
154,512
124,778
117,730
36,162
36,782
Petroleum products sold–barrels a day
228,261
191,318
195,689
157,504
Gasoline
130,489
96,903
Kerosine
7,969
8,448
Diesel and home heating oils
37,687
35,725
Residuals
14,421
13,044
Asphalt, LPG and other
5,123
3,384
32,572
33,814
10,001
12,848
2,546
2,656
13,177
13,856
4,506
2,812
LPG and other
2,342
1,642
Corporate activities, which include interest income and expense and corporate overhead not allocated to operating functions, reflected earnings of $10.7 million in the current quarter compared to a loss of $4.5 million in the first quarter of 2002. The 2003 results included a $20.1 million gain from the resolution of prior years’ income tax matters that was partially offset by higher retirement and medical expenses and lower other income tax benefits.
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Financial Condition
Net cash provided by continuing operating activities was $212.5 million for the first three months of 2003 compared to $31.5 million during the same period in 2002. Changes in operating working capital other than cash and cash equivalents provided cash of $44.3 million in the first quarter of 2003, but required cash of $66.2 million in the 2002 period.
Other predominant uses of cash in both years were for dividends, which totaled $18.4 million in 2003 and $17.1 million in 2002 and for capital expenditures, which, including amounts expensed, are summarized in the following table.
Capital Expenditures
143.4
176.9
50.4
40.3
.2
.3
Total capital expenditures
194.0
217.5
Geological, geophysical and other exploration expenses charged to income
(10.7
(12.9
Total property additions and dry holes
183.3
204.6
Working capital at March 31, 2003 was $142.1 million, up $5.8 million from December 31, 2002. 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 $139.4 million below fair value at March 31, 2003.
At March 31, 2003, long-term notes payable of $830.4 million were up $41.8 million from December 31, 2002 due to borrowings to fund certain capital expenditures. Long-term nonrecourse debt of a subsidiary was $65.1 million, down $9.1 million from December 31, 2002 due to scheduled repayments. A summary of capital employed at March 31, 2003 and December 31, 2002 follows.
Dec. 31, 2002
Capital Employed
Amount
%
830.4
788.6
65.1
74.2
1,714.4
66
1,593.6
65
Total capital employed
2,609.9
100
2,456.4
Accounting and Other Matters
Early in the first quarter of 2003, the Company signed a letter of intent to sell its interest in the Ninian and Columba fields in the U.K. for total proceeds of approximately $36 million. Additionally, in April 2003 the Company announced it had agreed to sell its interest in various Canadian oil and natural gas properties for consideration of $35 million. The combined net daily production in 2002 from these properties was slightly over 5,500 barrels of oil equivalent per day. The transactions are expected to close in the second quarter 2003.
As described in Note B on page 5 of this Form 10-Q report, Murphy adopted Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations, effective January 1, 2003.
Murphy holds a 20% interest in Block 16 Ecuador, where the Company and its partners produce oil for export. In 2001, the local tax authorities announced that Value Added Taxes (VAT) paid on goods and services related to Block 16 and many oil fields held by other companies will no longer be reimbursed. In response to this announcement, oil producers have filed actions in the Ecuador Tax Court seeking determination that the VAT in question is reimbursable. As of March 31, 2003, the Company has a receivable of approximately $6.5 million related to VAT. Murphy believes that its claim for reimbursement of VAT under applicable Ecuador tax law is valid, and it does not expect that the resolution of this matter will have a material adverse affect on the Company’s financial position.
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Outlook
The Company expects the sales prices for oil and natural gas for the remainder of 2003 to be lower than the average prices experienced in the first quarter of 2003. Production is expected to average 120,000 barrels of oil equivalent per day in the second quarter. New production is set to commence at the West Patricia field in Malaysia in May and the Medusa field should start up production in the third quarter 2003. Refining and marketing margins in the U.S. have been stronger early in the second quarter of 2003 compared to the margins experienced in the just completed first quarter. The Company’s Superior, Wisconsin refinery will be off-line for turnaround for most of May 2003 and based on present plans, the Meraux, Louisiana refinery will have a scheduled turnaround, with related tie-in of new equipment, in the third quarter 2003.
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.
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 G to this Form 10-Q report, Murphy makes 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, 2003 with notional amounts totaling $50 million that were designed to hedge fluctuations in cash flows of a similar amount of variable-rate debt. These swaps mature in 2004. The swaps require the Company to pay an average interest rate of 6.17% over their composite lives, and at March 31, 2003, the interest rate to be received by the Company averaged 1.32%. The variable interest rate received by the Company under each swap contract is repriced quarterly. The Company considers these swaps to be a hedge against potentially higher future interest rates. The estimated fair value of these interest rate swaps was recorded as a liability of $3.5 million at March 31, 2003, with the offsetting loss recorded in Accumulated Other Comprehensive Loss (AOCL) in Stockholders’ Equity.
At March 31, 2003, 24% of the Company’s debt had variable interest rates and 4% was denominated in Canadian dollars. Based on debt outstanding at March 31, 2003, a 10% increase in variable interest rates would increase the Company’s interest expense approximately $.2 million for the next 12 months after including the favorable effect resulting from lower net settlement payments under the aforementioned interest rate swaps. A 10% increase in the exchange rate of the Canadian dollar versus the U.S. dollar would increase interest expense for the next 12 months by less than $.1 million for debt denominated in Canadian dollars.
Murphy was a party to natural gas price swap agreements at March 31, 2003 for a total notional volume of 9.2 MMBTU that are intended to hedge the financial exposure of its Meraux, Louisiana refinery to fluctuations in the future price of a portion of natural gas to be purchased for fuel during 2004 through 2006. In each month of settlement, the swaps require Murphy to pay an average natural gas price of $2.78 per MMBTU and to receive the average NYMEX price for the final three trading days of the month. At March 31, 2003, the estimated fair value of these agreements was recorded as an asset of $15.5 million. A 10% increase in the average NYMEX price of natural gas would have increased this asset by $4 million, while a 10% decrease would have reduced the asset by a similar amount.
The Company was a party to natural gas swap agreements and natural gas collar agreements at March 31, 2003 that are intended to hedge the financial exposure of a portion of its 2003 U.S. and Canadian natural gas production to changes in gas sales prices. The swap agreements are for a combined notional volume that averages 24,200 MMBTU equivalents per day and require Murphy to pay the average relevant index price for each month and
16
receive an average price of $3.76 per MMBTU equivalent. The collar agreements are for a combined notional volume of 26,700 MMBTU equivalents per day and based upon the relevant index prices provide Murphy with an average floor price of $3.24 per MMBTU and an average ceiling price of $4.64 per MMBTU. At March 31, 2003, the estimated fair value of these agreements was recorded as a liability of $11 million, with the offsetting loss recorded in Accumulated Other Comprehensive Loss (AOCL) in Stockholders’ Equity. A 10% increase in the average index price of natural gas would have increased this liability by $3.2 million, while a 10% decrease would have reduced the liability by a similar amount.
In addition, the Company was a party to crude oil swap agreements at March 31, 2003 that are intended to hedge the financial exposure of a portion of its 2003 U.S. and Canadian crude oil production to changes in crude oil sales prices. A portion of the swap agreements cover a notional volume of 22,000 barrels per day of light oil and require Murphy to pay the average of the closing settlement price on the NYMEX for the Nearby Light Crude Futures Contract for each month and receive an average price of $25.30 per barrel. Additionally, there are heavy oil swap agreements with a notional volume of 10,000 barrels per day (which equates to approximately 7,700 barrels per day of the Company’s heavy oil production) that require Murphy to pay the arithmetic average of the posted prices for each month at the Kerrobert and Hardisty terminals in Canada and receive an average price of $16.74 per barrel. At March 31, 2003, the estimated fair value of these agreements was recorded as a liability of $19.4 million, with the offsetting loss recorded in AOCL in Stockholders’ Equity. A 10% increase in the average index prices of light oil and heavy oil would have increased this liability by $21.7 million, while a 10% decrease would have reduced the liability by a similar amount.
ITEM 4. CONTROLS AND PROCEDURES
The Company, under the direction of its principal executive officer and principal financial officer, has established controls and procedures to ensure that material information relating to the Company and its consolidated subsidiaries is made known to the officers who certify the Company’s financial reports and to other members of senior management and the Board of Directors.
Based on their evaluation as of a date within 90 days of the filing of this Quarterly Report on Form 10-Q, the principal executive officer and principal financial officer of Murphy Oil Corporation have concluded that the Company’s disclosure controls and procedures (as defined in Rules 13a-14(c) and 15d-14(c) under the Securities Exchange Act of 1934) are effective to ensure that the information required to be disclosed by Murphy Oil Corporation in reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms.
There were no significant changes in the Company’s internal controls or in other factors that could significantly affect those controls subsequent to the date of their most recent evaluation.
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CONTINUING OIL AND GAS OPERATING RESULTS (unaudited)
Synthetic Oil–
Three Months Ended March 31, 2003
Oil and gas sales and other operating revenues
160.1
21.5
302.5
Production expenses
7.8
19.3
11.5
4.2
14.4
57.2
8.3
9.6
1.5
2.0
62.0
1.2
.9
3.1
Exploration expenses
7.1
Geological and geophysical
3.6
4.4
9.5
.5
7.0
6.2
Undeveloped lease amortization
2.6
3.7
6.3
Total exploration expenses
9.9
24.1
4.6
4.1
1.1
1.6
12.5
Income tax provisions (benefits)
32.7
15.9
(.3
56.7
Results of operations (excluding corporate overhead and interest)
52.6
3.3
Three Months Ended March 31, 2002
30.1
98.9
21.7
202.4
12.4
20.1
11.4
12.9
60.1
8.8
34.8
9.8
1.3
2.1
5.0
5.7
23.1
10.2
.4
(.1
2.7
7.4
20.8
7.7
36.0
2.5
3.5
6.0
24.3
42.0
3.9
3.0
10.1
2.2
13.1
13.4
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PART II – OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
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. Based on information currently available to the Company, the ultimate resolution of matters referred to in this Item is not expected to have a material adverse effect on the Company’s earnings or financial condition in a future period.
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
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.
(Registrant)
By
/s/ JOHN W. ECKART
John W. Eckart, Controller
(Chief Accounting Officer and Duly Authorized Officer)
May 13, 2003
(Date)
19
CERTIFICATION PURSUANT TO
SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002
I, Claiborne P. Deming, certify that:
Date: May 13, 2003
/s/ Claiborne P. Deming
Claiborne P. Deming
Principal Executive Officer
20
I, Steven A. Cossé, certify that:
/s/ Steven A. Cossé
Steven A. Cossé
Principal Financial Officer
21
EXHIBIT INDEX
Exhibit
No.
Incorporated by Reference to
Certificate of Incorporation of Murphy Oil Corporation
as amended, effective May 17, 2001
Exhibit 3.1 of Murphy’s Form 10-Q report for the quarterly period ended June 30, 2001
3.2
By-Laws of Murphy Oil Corporation as amended effective April 2, 2003
Exhibit 3.2 filed herewith
Instruments Defining the Rights of Security Holders. Murphy is party to several long-term debt instruments in addition to the one in Exhibit 4.1, none of which authorizes securities exceeding 10% of the total consolidated assets of Murphy and its subsidiaries. Pursuant to Regulation S-K, item 601(b), paragraph 4(iii)(A), Murphy agrees to furnish a copy of each such instrument to the Securities and Exchange Commission upon request
Form of Second Supplement Indenture between Murphy Oil Corporation and SunTrust Bank, as Trustee
Exhibit 4.1 of Murphy’s Form 8-K report filed May 3, 2002 under the Securities Exchange Act of 1934
Form of Indenture and Form of Supplemental Indenture between Murphy Oil Corporation and SunTrust Bank, as Trustee
Exhibits 4.1 and 4.2 of Murphy’s Form 8-K 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 Corporation and Harris Trust Company of New York, as Rights Agent
Exhibit 4.3 of Murphy’s Form 10-K report for the year ended December 31, 1999
Amendment No. 1 dated as of April 6, 1998 to Rights Agreement dated as of December 6, 1989 between Murphy Oil Corporation and Harris Trust Company of New York, as Rights Agent
Exhibit 3 of Murphy’s Form 8-A/A, Amendment No. 1, filed April 14, 1998 under the Securities Exchange Act of 1934
4.5
Amendment No. 2 dated as of April 15, 1999 to Rights Agreement dated as of December 6, 1989 between Murphy Oil Corporation and Harris Trust Company of New York, as Rights Agent
Exhibit 4 of Murphy’s Form 8-A/A, Amendment No. 2, filed April 19, 1999 under the Securities Exchange Act of 1934
1982 Stock Incentive Plan as amended May 14, 1997 and December 1, 1999
Exhibit 10.1 filed herewith
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
10.3
Motor Vehicle Fueling Station Master Ground Lease Agreement
Exhibit 10.3 of Murphy’s Form 10-K report for the year ended December 31, 2002
12.1
Computation of Ratio of Earnings to Fixed Charges
Exhibit 12.1 filed herewith
22
99.1
Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002
Exhibit 99.1 filed herewith
99.2
Exhibit 99.2 filed herewith
Exhibits other than those listed above have been omitted since they are either not required or not applicable.
23