============================================================================== 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 JUNE 30, 1999 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 June 30, 1999, was 44,966,199. ==============================================================================
PART I - FINANCIAL INFORMATION Murphy Oil Corporation and Consolidated Subsidiaries CONSOLIDATED BALANCE SHEETS (Thousands of dollars) <TABLE> <CAPTION> (unaudited) June 30, December 31, 1999 1998 --------- ------------ <S> <C> <C> ASSETS Current assets Cash and cash equivalents $ 44,895 28,271 Accounts receivable, less allowance for doubtful accounts of $10,777 in 1999 and $11,048 in 1998 264,676 233,906 Inventories Crude oil and blend stocks 54,561 41,090 Finished products 66,150 49,714 Materials and supplies 37,421 38,973 Prepaid expenses 38,529 32,292 Deferred income taxes 14,172 13,120 --------- --------- Total current assets 520,404 437,366 Property, plant and equipment, at cost less accumulated depreciation, depletion and amortization of $3,024,585 in 1999 and $2,985,854 in 1998 1,721,010 1,662,362 Deferred charges and other assets 65,897 64,691 --------- --------- Total assets $2,307,311 2,164,419 ========= ========= LIABILITIES AND STOCKHOLDERS' EQUITY Current liabilities Current maturities of long-term debt $ 67 5,951 Notes payable - 1,961 Accounts payable and accrued liabilities 378,346 349,887 Income taxes 27,510 22,951 --------- --------- Total current liabilities 405,923 380,750 Notes payable 344,233 189,705 Nonrecourse debt of a subsidiary 143,129 143,768 Deferred income taxes 142,318 124,543 Reserve for dismantlement costs 154,151 154,686 Reserve for major repairs 11,940 43,519 Deferred credits and other liabilities 147,712 149,215 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 511,019 510,116 Retained earnings 522,752 545,199 Accumulated other comprehensive income - foreign currency translation (22,413) (23,520) Unamortized restricted stock awards (2,663) (2,361) Treasury stock, 3,809,115 shares of Common Stock in 1999, 3,824,838 shares in 1998, at cost (99,565) (99,976) --------- --------- Total stockholders' equity 957,905 978,233 --------- --------- Total liabilities and stockholders' equity $2,307,311 2,164,419 ========= ========= </TABLE> See Notes to Consolidated Financial Statements, page 4. 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) <TABLE> <CAPTION> Three Months Ended Six Months Ended June 30, June 30, ------------------- ------------------- 1999 1998* 1999 1998* ------- ------- ------- ------- <S> <C> <C> <C> <C> REVENUES Crude oil and natural gas sales $100,673 79,682 184,736 160,183 Petroleum product sales 340,675 344,889 545,822 683,208 Other operating revenues 8,614 23,222 22,283 44,161 Interest and other nonoperating revenues 529 852 1,916 1,744 ------- ------- ------- ------- Total revenues 450,491 448,645 754,757 889,296 ------- ------- ------- ------- COSTS AND EXPENSES Crude oil, products and related operating expenses 334,985 323,975 555,000 653,396 Exploration expenses, including undeveloped lease amortization 13,694 21,906 40,033 39,960 Selling and general expenses 16,902 16,876 33,428 33,644 Depreciation, depletion and amortization 50,445 47,571 97,040 97,843 Provision for reduction in force - - 1,513 - Interest expense 7,701 4,094 13,317 7,970 Interest capitalized (1,435) (2,636) (2,580) (5,186) ------- ------- ------- ------- Total costs and expenses 422,292 411,786 737,751 827,627 ------- ------- ------- ------- Income before income taxes 28,199 36,859 17,006 61,669 Federal and state income tax expense 3,120 12,680 114 20,413 Foreign income tax expense 9,359 1,980 7,870 3,516 ------- ------- ------- ------- NET INCOME $ 15,720 22,199 9,022 37,740 ======= ======= ======= ======= Net income per Common share - basic $ .35 .49 .20 .84 ======= ======= ======= ======= Net income per Common share - diluted $ .35 .49 .20 .84 ======= ======= ======= ======= Cash dividends per Common share $ .35 .35 .70 .70 ======= ======= ======= ======= Average Common shares outstanding - basic 44,963,681 44,959,704 44,959,429 44,948,944 Average Common shares outstanding - diluted 45,035,215 45,034,378 44,981,607 45,024,016 *Revenues have been reclassified to conform to 1999 presentation. </TABLE> Murphy Oil Corporation and Consolidated Subsidiaries CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED) (Thousands of dollars) <TABLE> <CAPTION> Three Months Ended Six Months Ended June 30, June 30, ------------------ ---------------- 1999 1998 1999 1998 ------- ------ ------ ------ <S> <C> <C> <C> <C> Net income $15,720 22,199 9,022 37,740 Other comprehensive income (loss) - net gain (loss) from foreign currency translation 3,335 (14,328) 1,107 (7,949) ------ ------ ------ ------ COMPREHENSIVE INCOME $19,055 7,871 10,129 29,791 ====== ====== ====== ====== </TABLE> See Notes to Consolidated Financial Statements, page 4. 2
Murphy Oil Corporation and Consolidated Subsidiaries CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED) (Thousands of dollars) <TABLE> <CAPTION> Six Months Ended June 30, ------------------ 1999 1998 ------- ------- <S> <C> <C> OPERATING ACTIVITIES Net income $ 9,022 37,740 Adjustments to reconcile net income to net cash provided by operating activities Depreciation, depletion and amortization 97,040 97,843 Provisions for major repairs 8,337 11,347 Expenditures for major repairs and dismantlement costs (40,771) (17,210) Exploratory expenditures charged against income 34,511 34,554 Amortization of undeveloped leases 5,522 5,406 Deferred and noncurrent income tax charges 13,622 11,526 Pretax gains from disposition of assets (280) (708) Other - net 6,571 6,026 ------- ------- 133,574 186,524 Net increase in operating working capital other than cash and cash equivalents (33,396) (20,602) Other adjustments related to operating activities (8,858) (4,366) ------- ------- Net cash provided by operating activities 91,320 161,556 ------- ------- INVESTING ACTIVITIES Capital expenditures requiring cash (187,082) (197,088) Proceeds from sale of property, plant and equipment 2,355 3,584 Other investing activities - net (1,428) (62) ------- ------- Net cash required by investing activities (186,155) (193,566) ------- ------- FINANCING ACTIVITIES Increase in notes payable 152,630 62,344 Decrease in nonrecourse debt of a subsidiary (6,586) (561) Cash dividends paid (31,469) (31,468) Other financing activities - net (2,080) 346 ------- ------- Net cash provided by financing activities 112,495 30,661 ------- ------- Effect of exchange rate changes on cash and cash equivalents (1,036) (303) ------- ------- Net increase (decrease) in cash and cash equivalents 16,624 (1,652) Cash and cash equivalents at January 1 28,271 24,288 ------- ------- Cash and cash equivalents at June 30 $ 44,895 22,636 ======= ======= SUPPLEMENTAL DISCLOSURES OF CASH FLOW ACTIVITIES Cash income taxes paid (refunded) $ (5,976) 23,559 Interest paid, net of amounts capitalized 7,931 2,999 </TABLE> See Notes to Consolidated Financial Statements, page 4. 3
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 3 of this Form 10-Q report. NOTE A - INTERIM FINANCIAL STATEMENT 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, 1998. 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 June 30, 1999, and the results of operations and cash flows for the three-month and six-month periods ended June 30, 1999 and 1998, in conformity with generally accepted accounting principles. Financial statements and notes to consolidated financial statements included in this Form 10-Q report should be read in conjunction with the Company's 1998 Form 10-K report, as certain notes and other pertinent information have been abbreviated or omitted in this report. Financial results for the six months ended June 30, 1999, are not necessarily indicative of future results. NOTE B - ENVIRONMENTAL CONTINGENCIES The Company's operations are subject to numerous laws and regulations intended to protect the environment and/or impose remedial obligations. The Company is also involved in personal injury and property damage claims, allegedly caused by exposure to or by the release or disposal of materials manufactured or used in the Company's operations. The Company operates or has previously operated certain sites and facilities, including refineries, oil and gas fields, service stations, and terminals, for which known or potential obligations for environmental remediation exist. Under the Company's accounting policies, a liability for an environmental obligation 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. Following a compliance inspection in 1998, Murphy's Superior, Wisconsin refinery received notices of violations of the Clean Air Act from the EPA. Although the penalty amounts were not listed, the statutes involved provide for rates of up to $27,500 per day of violation. The Company believes it has valid defenses to the allegations and plans a vigorous defense. The Company does not believe that this or other known environmental matters will have a material adverse effect on its financial condition. There is the possibility that expenditures could be required at currently unidentified sites, and new or revised regulatory requirements could necessitate additional expenditures at known sites. Such expenditures could materially affect the results of operations in a future period. 4
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTD.) NOTE B - ENVIRONMENTAL CONTINGENCIES (CONTD.) 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 recoveries from other sources will occur, the Company has not recognized a benefit for likely recoveries at June 30, 1999. NOTE C - 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; restrictions on production; 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 issuance of oil and gas or mineral leases; 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. The Company and its subsidiaries are engaged in a number of legal proceedings, all of which the Company considers routine and incidental to its business and none of which is considered material. In the normal course of its business, the Company is required under certain contracts with various governmental authorities and others to provide letters of credit that may be drawn upon if the Company fails to perform under those contracts. At June 30, 1999, the Company had contingent liabilities of $44.5 million on outstanding letters of credit and $46.6 million under certain financial guarantees. NOTE D - DERIVATIVE INSTRUMENTS Murphy uses derivative instruments on a limited basis to manage certain risks related to interest rates, foreign currency exchange rates and commodity prices. Instruments that reduce the exposure of assets, liabilities or anticipated transactions to interest rate, currency or price risks are accounted for as hedges. Gains or losses on derivatives that cease to qualify as hedges are recognized in income or expense. The use of derivative instruments for risk management is covered by operating policies and is closely monitored by the Company's senior management. The Company does not hold any derivatives for trading purposes, and it does not use derivatives with leveraged or complex features. Counterparties to derivative instruments are either creditworthy major financial institutions or national exchanges. Murphy uses interest rate swap agreements to convert certain variable rate long-term debt to fixed rates. Under the accrual/settlement method of accounting, the Company records the net amount to be received or paid under the swap agreements as part of "Interest Expense" in the Consolidated Statements of Income. If the Company should terminate an interest rate swap prior to maturity, any cash paid or received as settlement would be deferred and recognized as an adjustment to "Interest Expense" over the shorter of the remaining life of the debt or the remaining contractual life of the swap. The Company periodically uses crude oil swap agreements to reduce a portion of the financial exposure of its U.S. refineries to crude oil price movements. Unrealized gains or losses on such swap contracts are generally deferred and recognized in connection with the associated crude oil purchase. If conditions indicate that the market price of finished products would not allow for recovery of the costs of the finished products, including any unrealized loss on the crude oil swap, a liability will be provided for the nonrecoverable portion of the unrealized swap loss. The Company records pretax operating results associated with crude oil swaps in "Crude Oil, Products and Related Operating Expenses" in the Consolidated Statements of Income. The Company periodically uses natural gas swap agreements to reduce a portion of the financial exposure of its Meraux, Louisiana refinery to fluctuations in the price of certain future natural gas fuel purchases. Unrealized gains or losses on such swap contracts are deferred until the contracts are settled and the 5
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTD.) NOTE D - DERIVATIVE INSTRUMENTS (CONTD.) associated natural gas is purchased. The Company will record the related contract results in "Crude Oil, Products and Related Operating Expenses" in the Consolidated Statements of Income. NOTE E - EARNINGS PER SHARE Net income was used as the numerator in computing both basic and diluted income per Common share for the three-month and six-month periods ended June 30, 1999 and 1998. Reconciliations of the weighted-average shares outstanding for these computations are shown in the following table. <TABLE> <CAPTION> - ------------------------------------------------------------------------------ Reconciliation of Shares Outstanding Three Months Ended Six Months Ended June 30, June 30, - ----------------------------------------------------------------------------- (Weighted-average shares) 1999 1998 1999 1998 - ----------------------------------------------------------------------------- <S> <C> <C> <C> <C> Basic method . . . . . . . . . 44,963,681 44,959,704 44,959,429 44,948,944 Dilutive stock options . . . . 71,534 74,674 22,178 75,072 - ----------------------------------------------------------------------------- Diluted method 45,035,215 45,034,378 44,981,607 45,024,016 ============================================================================= </TABLE> The following table presents additional information about outstanding options that were not considered in calculating diluted earnings per share in the preceding table because the effects of these options would have improved the Company's earnings per share. <TABLE> <CAPTION> - ------------------------------------------------------------------------------ Information About Options at End of Periods Three Months Ended Six Months Ended June 30, June 30, - ----------------------------------------------------------------------------- 1999 1998 1999 1998 - ----------------------------------------------------------------------------- <S> <C> <C> <C> <C> Total options outstanding 1,346,899 1,064,409 1,346,899 1,064,409 Options not considered in diluted calculations 687,750 705,000 1,008,250 705,000 Exercise price per share - maximum $65.49 65.49 65.49 65.49 - minimum $49.75 49.75 35.69 49.75 - average $53.33 53.25 47.72 53.25 Remaining life in years - maximum 8.6 9.6 9.6 9.6 - minimum 7.6 8.6 7.6 8.6 - average 8.0 9.0 8.5 9.0 </TABLE> NOTE F - PROVISION FOR REDUCTION IN FORCE In early 1999, the Company offered enhanced voluntary retirement benefits to eligible exploration, production and administrative employees in its New Orleans and Calgary offices and severed certain other employees. As a result of this reduction in force, the Company recorded a "Provision for Reduction in Force" of $1.5 million, $1 million after taxes, in the Consolidated Statement of Income for the six months ended June 30, 1999. 6
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTD.) NOTE G - BUSINESS SEGMENTS <TABLE> <CAPTION> Three Mos. Ended June 30, 1999 Total Assets ------------------------------ at June 30, External Interseg. Income (Millions of dollars) 1999 Revenues Revenues (Loss) - ---------------------------------------------------------------------------- <S> <C> <C> <C> <C> Exploration and production* United States $ 386.0 36.6 10.5 7.8 Canada 665.9 34.9 13.1 8.4 United Kingdom 292.6 21.8 6.0 3.4 Ecuador 62.4 7.0 - 3.1 Other 9.9 .3 - (2.6) - ---------------------------------------------------------------------------- Total 1,416.8 100.6 29.6 20.1 - ---------------------------------------------------------------------------- Refining, marketing and transportation United States 527.8 280.3 1.1 (1.4) United Kingdom 181.0 61.6 - 2.5 Canada 61.4 7.5 .1 2.1 - ---------------------------------------------------------------------------- Total 770.2 349.4 1.2 3.2 - ---------------------------------------------------------------------------- Total operating segments 2,187.0 450.0 30.8 23.3 Corporate and other 120.3 .5 - (7.6) - ---------------------------------------------------------------------------- Total consolidated $2,307.3 450.5 30.8 15.7 ============================================================================ Three Mos. Ended June 30, 1998 ------------------------------ External Interseg. Income (Millions of dollars) Revenues Revenues (Loss) - ---------------------------------------------------------------------------- Exploration and production* United States $ 42.9 8.2 7.9 Canada 22.2 9.6 (.2) United Kingdom 24.3 - 1.0 Ecuador 6.1 - 2.6 Other .4 - (6.3) - ---------------------------------------------------------------------------- Total 95.9 17.8 5.0 - ---------------------------------------------------------------------------- Refining, marketing and transportation United States 278.6 .9 15.2 United Kingdom 67.8 - 4.1 Canada 5.5 - 1.0 - ---------------------------------------------------------------------------- Total 351.9 .9 20.3 - ---------------------------------------------------------------------------- Total operating segments 447.8 18.7 25.3 Corporate and other .8 - (3.1) - ---------------------------------------------------------------------------- Total consolidated $448.6 18.7 22.2 ============================================================================ Six Mos. Ended June 30, 1999 ----------------------------- External Interseg. Income (Millions of dollars) Revenues Revenues (Loss) - ---------------------------------------------------------------------------- Exploration and production* United States $ 69.5 17.9 3.1 Canada 61.6 21.4 8.6 United Kingdom 44.9 6.0 4.9 Ecuador 11.7 - 4.1 Other .9 - (3.8) - ---------------------------------------------------------------------------- Total 188.6 45.3 16.9 - ---------------------------------------------------------------------------- Refining, marketing and transportation United States 442.9 2.1 (1.4) United Kingdom 107.5 - 3.8 Canada 13.9 .2 3.7 - ---------------------------------------------------------------------------- Total 564.3 2.3 6.1 - ---------------------------------------------------------------------------- Total operating segments 752.9 47.6 23.0 Corporate and other 1.9 - (14.0) - ---------------------------------------------------------------------------- Total consolidated $754.8 47.6 9.0 ============================================================================ Six Mos. Ended June 30, 1998 ----------------------------- External Interseg. Income (Millions of dollars) Revenues Revenues (Loss) - ---------------------------------------------------------------------------- Exploration and production* United States $ 84.8 18.5 14.9 Canada 41.8 21.2 .3 United Kingdom 46.2 - 1.6 Ecuador 11.8 - 4.0 Other 1.2 - (9.8) - ---------------------------------------------------------------------------- Total 185.8 39.7 11.0 - ---------------------------------------------------------------------------- Refining, marketing and transportation United States 547.4 1.4 21.2 United Kingdom 141.9 - 8.6 Canada 12.5 - 2.9 - ---------------------------------------------------------------------------- Total 701.8 1.4 32.7 - ---------------------------------------------------------------------------- Total operating segments 887.6 41.1 43.7 Corporate and other 1.7 - (6.0) - ---------------------------------------------------------------------------- Total consolidated $889.3 41.1 37.7 ============================================================================ *Additional details about results of operations, excluding special items, are presented in the tables on page 14. </TABLE> 7
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION RESULTS OF OPERATIONS THREE MONTHS ENDED JUNE 30, 1999 COMPARED TO THREE MONTHS ENDED JUNE 30, 1998 Net income in the second quarter of 1999 totaled $15.7 million, $.35 a diluted share, compared to earnings before special items of $18 million, $.40 a diluted share, in the second quarter a year ago. Net income for the second quarter of 1998, including gains from special items of $4.2 million, $.09 a share, totaled $22.2 million, $.49 a diluted share. Special items benefiting exploration and production operations for the 1998 quarter were $2.8 million from modification of a natural gas sales contract in the United Kingdom and $1.4 million from partial recovery of a 1996 loss resulting from modification to a crude oil production contract in Ecuador. Cash flow from operating activities, excluding changes in noncash working capital items, totaled $76.8 million in the second quarter of 1999 compared to $99.1 million a year ago. A 20% increase in crude oil production and a 31% increase in average worldwide crude oil sales prices were significant contributors to Murphy's exploration and production operations, which earned $20.1 million in the current quarter compared to $.8 million in the second quarter of 1998. Worldwide downstream operations earned $3.2 million in the current quarter compared to $20.3 million a year ago, as margins in the United States and the United Kingdom were under pressure throughout the quarter. Exploration and production operations in the United States earned $7.8 million compared to $7.9 million in the second quarter of 1998. Operations in Canada earned $8.4 million compared to a loss of $.2 million a year ago, and U.K. operations earned $3.4 million compared to a loss of $1.8 million before special items. Operations in Ecuador earned $3.1 million in the second quarter of 1999 compared to $1.2 million before special items a year ago. Other international operations reported a loss of $2.6 million compared to a $6.3 million loss a year earlier. The Company's worldwide crude oil and condensate sales prices averaged $14.50 a barrel in the current quarter compared to $11.08 a year ago. Crude oil and condensate sales prices averaged $16.03 a barrel in the United States, up 27%, and $15.35 in the United Kingdom, up 18%. In Canada, sales prices averaged $15.35 a barrel for light oil, up 28% from last year; $10.91 for heavy oil, up 89%; $14.57 for production from the offshore Hibernia field, up 25%; and $17.00 for synthetic oil, up 21%. The average crude oil sales price in Ecuador was $10.50 a barrel, up 42%. Total crude oil and gas liquids production averaged 65,547 barrels a day compared to 54,476 in the second quarter of 1998. The increase was due to production from new fields in the United Kingdom and Canada. Production increased 59% in the United Kingdom and 11% in the United States. Production at the Hibernia field, off the east coast of Canada, increased 4,469 barrels a day. In other areas, production decreased 12% for Canadian light oil and 6% each for synthetic oil in Canada and crude oil in Ecuador, while being essentially unchanged for Canadian heavy oil. Natural gas sales prices in the United States averaged $2.13 a thousand cubic feet (MCF) in the current quarter, down 7%, and $1.73 an MCF in Canada, up 32%. Total natural gas sales averaged 246 million cubic feet a day in the current quarter compared to 230 million a year ago. Sales of natural gas in the United States averaged 183 million cubic feet a day, up from 175 million in the second quarter of 1998. Canadian natural gas sales averaged 55 million cubic feet a day in the current quarter, an increase of 21%. Exploration expenses totaled $13.7 million compared to $21.9 million in 1998. The tables on page 14 provide additional details of the results of exploration and production operations for the second quarter of each year. Refining, marketing and transportation operations in the United States reported a loss of $1.4 million compared to earnings of $15.2 million a year ago. Operations in the United Kingdom earned $2.5 million compared to $4.1 million in the second quarter of 1998. Earnings from purchasing, transporting and reselling crude oil in Canada were $2.1 million in the 1999 quarter compared to $1 million in last year's second quarter. Refinery crude runs worldwide were 161,321 barrels a day compared to 164,339 in the second quarter of 1998. Worldwide refined product sales were 163,663 barrels a day compared to 172,676 a year ago. Corporate functions, which include interest income and expense and corporate overhead not allocated to operating functions, reflected a loss of $7.6 million in the current quarter compared to a loss of $3.1 million in the second quarter of 1998. The additional loss was primarily caused by higher net interest expense. SIX MONTHS ENDED JUNE 30, 1999 COMPARED TO SIX MONTHS ENDED JUNE 30, 1998 For the first six months of 1999, net income totaled $9 million, $.20 a diluted share, compared to $37.7 million, $.84 a diluted share, a year ago. The current six-month period included an after-tax charge of $1 million, $.02 a diluted share, for a reduction in force, while the same period a year ago included total benefits in exploration and 8
MANAGEMENT'S DISCUSSION AND ANALYSIS (CONTD.) RESULTS OF OPERATIONS (CONTD.) production operations of $4.2 million, $.09 a share, from the previously mentioned special items in the second quarter. Year-to-date earnings from exploration and production operations before special items were up $10.1 million over the prior year, mainly due to increases in crude oil production, average worldwide crude oil prices, and Canadian natural gas sales volumes and prices, partially offset by lower U.S. natural gas sales prices. This improvement was more than offset by a $26.6 million decrease in earnings of the Company's worldwide downstream operations and an additional loss of $7 million from corporate functions. Earnings from refining, marketing and transportation activities decreased primarily because of pressure on product margins and lower product sales volumes in both the United States and the United Kingdom. Earnings from exploration and production operations for the six months ended June 30, 1999 were $16.9 million, up from $6.8 million before special items in 1998. Canadian operations earned $8.6 million for the first half of 1999 compared to $.3 million in the prior period, and U.K. operations earned $4.9 million compared to a loss of $1.2 million in 1998. An increase from the prior year also occurred in Ecuador, which had earnings of $4.1 million compared to $2.6 million, but earnings in the United States dropped from $14.9 million in 1998 to $3.1 million in the current year. Other international operations recorded losses of $3.8 million in the first six months of 1999 and $9.8 million in the 1998 period. Crude oil and gas liquids production for the first half of 1999 averaged 64,557 barrels a day compared to 54,269 during the same period of 1998. Production of crude oil and gas liquids in the United Kingdom averaged 19,748 barrels a day, up 59%, and crude oil production at Hibernia averaged 5,389 barrels a day, up 2,990. In other areas, crude oil and gas liquids production averaged 11,068 barrels a day for Canadian synthetic oil, up 8%; 8,590 in the United States, up 4%; 8,872 for Canadian heavy oil, down 7%; 3,615 for Canadian light oil, also down 7%; and 7,275 in Ecuador, down 3%. The Company's crude oil and condensate sales prices averaged $13.96 a barrel in the United States, up 2%, and $13.13 in the United Kingdom, down 3%. In Canada, sales prices averaged $13.29 a barrel for light oil, up 5% from last year; $9.53 for heavy oil, up 76%; $13.77 for production from the Hibernia field, up 12%; and $14.83 for synthetic oil, up 2%. The average crude oil sales price in Ecuador was $8.60 a barrel, up 12%. Natural gas sales prices for the first six months of 1999 averaged $1.98 an MCF in the United States, down 14%; $1.64 in Canada, up 36%; and $1.68 in the United Kingdom, down 28%. Total natural gas sales averaged 248 million cubic feet a day in 1999 compared to 240 million in 1998. Sales of natural gas in the United States averaged 180 million cubic feet a day, down 1% from 1998. In other areas, average natural gas sales volumes in Canada were 54 million cubic feet a day, up 19%, and 14 million in the United Kingdom, up 14%, as production from the Amethyst field was shut in during the early part of 1998 to repair pipeline damages. Exploration expenses totaled $40 million for the six months ended June 30, 1999, essentially the same as a year ago. Exploration expenses were higher in the United States, but were lower in other international areas. The tables on page 14 provide additional details of the results of exploration and production operations for the first half of each year. Refining, marketing and transportation operations in the United States were affected by lower product margins and lower sales volumes, and reported a loss of $1.4 million in the first six months of 1999 compared to earnings of $21.2 million for the same period last year. Operations in the United Kingdom were affected by weaker product margins and lower product sales volumes and earned $3.8 million in the first half of 1999 compared to $8.6 million in the prior year. Earnings from purchasing, transporting and reselling crude oil in Canada were $3.7 million in the current year compared to $2.9 million a year ago. Refinery crude runs worldwide were 126,461 barrels a day compared to 165,678 a year ago. Petroleum product sales were 140,658 barrels a day, down from 173,348 in 1998. Crude runs and product sales were both adversely affected by a scheduled turnaround at the Company's Meraux, Louisiana refinery in early 1999. Financial results from corporate functions before special items reflected a loss of $13 million in the first half of 1999 compared to a loss of $6 million a year ago. The additional loss was primarily due to higher net interest expense. FINANCIAL CONDITION Net cash provided by operating activities was $91.3 million for the first six months of 1999 compared to $161.6 million for the same period in 1998. Changes in operating working capital other than cash and cash equivalents required cash of $33.4 million in the first six months of 1999 and $20.6 million in the 1998 period. The cash results for operating activities were also reduced by expenditures for refinery turnarounds and abandonment of oil and gas properties totaling $40.8 million in the current year and $17.2 million in 1998. Other predominant uses of cash in 9
MANAGEMENT'S DISCUSSION AND ANALYSIS (CONTD.) FINANCIAL CONDITION (CONTD.) each year were for capital expenditures (which, including amounts expensed, are summarized in the following table) and for dividends of 31.5 million. <TABLE> <CAPTION> -------------------------------------------------------------------- Capital Expenditures Six Months Ended June 30, -------------------------------------------------------------------- (Millions of dollars) 1999 1998 -------------------------------------------------------------------- <S> <C> <C> Exploration and production. . . . . . . . . . $147.3 174.9 Refining, marketing and transportation. . . . 38.8 21.1 Corporate and other . . . . . . . . . . . . . 1.0 1.1 -------------------------------------------------------------------- $187.1 197.1 ==================================================================== </TABLE> Working capital at June 30, 1999 was $114.5 million, up $57.9 million from December 31, 1998. This level of working capital does not fully reflect the Company's liquidity position, because the lower historical costs assigned to inventories under LIFO accounting were $56.8 million below current costs at June 30, 1999. At June 30, 1999, long-term notes payable of $344.2 million were up $154.5 million due to additional borrowing for certain oil and gas development projects and other capital needs. In May 1999, Murphy issued $250 million of 30-year, 7.05% notes and used the proceeds to retire floating rate debt with shorter maturities. Long-term nonrecourse debt of a subsidiary was $143.1 million, down slightly from December 31, 1998. A summary of capital employed at June 30, 1999 and December 31, 1998 follows. <TABLE> <CAPTION> ------------------------------------------------------------------------ Capital Employed June 30, 1999 December 31, 1998 ------------------------------------------------------------------------ (Millions of dollars) Amount % Amount % ------------------------------------------------------------------------ <S> <C> <C> <C> <C> Notes payable . . . . . . . . . . . $ 344.2 24 189.7 14 Nonrecourse debt of a subsidiary . . 143.1 10 143.8 11 Stockholders' equity . . . . . . . . 957.9 66 978.2 75 ------------------------------------------------------------------------ $1,445.2 100 1,311.7 100 ======================================================================== </TABLE> NEW ACCOUNTING STANDARD The Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards (SFAS) No. 133, Accounting for Derivative Instruments and Hedging Activities, in June 1998. This statement establishes accounting and reporting standards for derivative instruments and hedging activities. Effective January 1, 2001, Murphy must recognize the fair value of all derivative instruments as either assets or liabilities in its Consolidated Balance Sheet. A derivative instrument meeting certain conditions may be designated as a hedge of a specific exposure; accounting for changes in a derivative's fair value will depend on the intended use of the derivative and the resulting designation. Any transition adjustments resulting from adopting this statement will be reported in either net income or other comprehensive income, as appropriate, as the cumulative effect of a change in accounting principle. As described in Note D on page 5 of this Form 10-Q report, the Company makes limited use of derivative instruments to hedge specific market risks. The Company has not yet determined the effects that SFAS No. 133 will have on its future consolidated financial statements or the amount of the cumulative adjustment that will be made upon adopting this new standard. YEAR 2000 ISSUES GENERAL - Year 2000 issues affect all companies and relate to the possibility that computer programs and embedded computer chips may be unable to accurately process data with year dates of 2000 and beyond. Murphy is devoting significant internal and external resources to address Year 2000 compliance, and the Company's Year 2000 project (Project) is proceeding well. In 1993, Murphy began a worldwide business systems replacement project using systems primarily from J.D. Edwards & Company (Edwards) in the United States and the United Kingdom, PricewaterhouseCoopers LLP (PW*Sequel) in Canada, and for exploration and production operations, Applied Terravision Systems Inc. (Artesia) in the United States and EFA Software Services Ltd. (PRISM) in Canada. Certain U.S. business software systems developed by the Company will not be replaced with compliant vendor systems by the Year 2000 and have been remedied to be Year 2000 compliant. Remaining hardware, software and facilities are expected to be made Year 2000 compliant through the Project. None of the Company's other information technology projects are expected to be significantly delayed due to the implementation of the Project. 10
MANAGEMENT'S DISCUSSION AND ANALYSIS (CONTD.) YEAR 2000 ISSUES (CONTD.) PROJECT - The Company has established an Enterprise Project Office (EPO) and has engaged KPMG LLP to assist with Project management. The Project is primarily being managed by major operating location. At each location, the Project is divided into three major components: Computer Hardware, Applications Software, and Process Control and Instrumentation (Embedded Technology). The Computer Hardware component consists of computing equipment and systems software other than Applications Software. Applications Software includes both internally developed and vendor software systems. Embedded Technology includes the hardware, software and associated embedded computer chips (other than computing equipment) that are used in facilities operated by the Company. The general phases common to all components are: (1) inventorying Year 2000 items; (2) assigning priorities to identified items; (3) assessing the Year 2000 compliance of identified items; (4) repairing or replacing material items that are determined not to be Year 2000 compliant; (5) evaluating and testing required material items; and (6) designing and implementing contingency and business continuation plans as necessary. Material items are those that the Company believes to have safety, environmental or property damage risks, or that may adversely affect the Company's ability to process and record revenues if not properly addressed. The inventorying and priority assessment phases of the Project were completed during 1998. The remaining four phases of the Project are in progress and are being performed primarily by employees of the Company, with assistance from vendors and independent contractors. A fourth major component of the Project involves the review of third party suppliers, customers and business partners (Third Parties) and is being managed for all locations by the EPO. This includes the process of identifying and prioritizing critical Third Parties and communicating with them about their plans and progress in addressing the Year 2000 problem. Evaluations of the most critical Third Parties began in the second quarter of 1998 and will continue throughout 1999. Based on the results of evaluations and other available information, contingency plans are being developed as necessary to address potential Year 2000 problems related to critical Third Parties. The Company has also engaged an engineering firm to perform independent evaluations of the Company's Year 2000 readiness at selected U.S. operating sites. These evaluations will be completed during the third quarter of 1999 and the findings will be considered during the remainder of the project. A Year 2000 compliant version of Edwards has been fully implemented in the United States and is approximately 80% complete in the United Kingdom. Implementation of Edwards is ongoing in the United Kingdom and final phases are expected to be completed in October 1999. A Year 2000 compliant version of Artesia was implemented in the United States at the end of 1998 and testing was completed in January 1999. In Canada, the Company upgraded to a Year 2000 compliant version of PRISM during the first quarter of 1999, and Year 2000 testing was completed in July 1999. A compliant version of PW*Sequel has been implemented and testing was completed in July 1999. Testing of U.S. offshore production platform systems was essentially completed at March 31, 1999. Exploration system upgrades were released by the vendor in early 1999 and were installed and tested in July 1999. Remedy of certain internally developed downstream accounting, customer invoicing and human resources systems in the United States had been completed at December 31, 1998. Upgrading and testing of U.S. refining and marketing systems were substantially completed in July 1999. The operator at the Company's jointly owned U.K. refinery is directing that location's Year 2000 action plan and has reported that the plan is scheduled to be completed by October 31, 1999. Company employees are monitoring the operator's progress and believe the work is on schedule. Systems at U.K. marketing terminals are being upgraded to a Year 2000 compliant version; certain terminals have been upgraded and the remaining locations are scheduled to be completed in the third quarter of 1999. Supply and transportation systems in Canada were substantially Year 2000 ready at June 30, 1999. Murphy maintains comprehensive disaster recovery plans for significant worldwide operating facilities. In addition to these plans, the Company is developing Year 2000 specific contingency plans in certain operating areas that are deemed critical. Contingency plans have been prepared to address the possibility that the last phases of the U.K. Edwards implementation will not be achieved by the end of 1999. If necessary, the contingency plans call for activation of certain temporary back-up systems, which could be triggered as late as the third quarter of 1999. Other contingency plans will be prepared and monitored throughout the remainder of 1999, and are likely to include accumulating higher than normal levels of crude oil, finished products and critical supplies inventories for short-term needs, and identifying alternative providers of services and supplies for the Company's longer-term needs. The Company is also likely to supplement its normal emergency response teams to be prepared to assist with Year 2000 transition issues that may arise. Staffing may also be increased at certain locations during the critical 11
MANAGEMENT'S DISCUSSION AND ANALYSIS (CONTD.) YEAR 2000 ISSUES (CONTD.) year-end period. Additionally, Murphy is monitoring the state of its partner's contingency planning at the jointly owned U.K. refinery. At July 31, 1999, the overall Project is estimated to be 95% complete. Thus far, no material noncompliant Year 2000 issues have been discovered that were not identified in the completed Year 2000 inventory. Significant components of the Project have been completed by July 31, 1999, except for certain activities in the United Kingdom. The final stages of the Company's U.K. Edwards implementation and certain Year 2000 compliance activities at the jointly owned U.K. refinery will be completed in the fourth quarter of 1999. COSTS - The Company's total cost to become Year 2000 compliant is not expected to be material to its financial position. The most likely estimate of the total cost of the Project is approximately $5 million, including the costs of new systems that concurrently provide improved business functionality and Year 2000 compliance. These costs include $2 million for the EPO (including assessment of Third Parties); the remaining costs are for miscellaneous hardware replacement, noncompliant system renovations and upgrades, and Embedded Technology issues. It is reasonably possible that total costs could exceed the most likely estimate by up to $1 million. Funds for the Project are primarily obtained from internally generated cash flows. This cost estimate does not include the Company's potential share of Year 2000 costs that may be incurred by partnerships and joint ventures that the Company does not operate, except for an estimated $.7 million to make Murphy's jointly owned U.K. refinery Year 2000 compliant. The total amount expended on the Project through June 30, 1999 was $3.1 million, including $1.5 million in the first six months of 1999. Of this amount, $1.9 million has been included in selling and general expenses, including $.3 million in the first six months of 1999. The remaining cost to complete the Year 2000 Project is estimated to be approximately $1.9 million. RISKS - Not correcting material Year 2000 problems could result in interruptions in, or failures of, certain normal business activities or operations. Such failures could materially and adversely affect the Company's results of operations, liquidity or financial condition by impeding the Company's ability to produce and deliver crude oil, natural gas and finished petroleum products, and to invoice and collect related revenues from customers. The Company has anticipated that certain operations may be disrupted on a short-term basis, but does not believe such disruptions will be either long-term in nature or of major consequence to the Company's operations. The Company can not completely eliminate, however, the possibility of significant disruptions. Due to the general uncertainty inherent in the Year 2000 problem, resulting in part from uncertainty about the Year 2000 readiness of critical Third Parties, the Company is unable to determine at this time whether or not the consequences of possible Year 2000 failures will materially affect its results of operations, liquidity or financial condition. The Project is expected to significantly reduce the Company's level of uncertainty about the Year 2000 issue, and in particular, about the Year 2000 compliance and readiness of the Company's critical Third Parties. The Company believes that it is taking reasonable steps to address potentially material Year 2000 failures, and with completion of the Project as scheduled, the possibility of significant interruptions of normal operations should be greatly reduced. Readers are cautioned that forward-looking statements contained in this Year 2000 section should be read in conjunction with Murphy's disclosures in the following paragraph of this Form 10-Q report. OTHER MATTERS In July 1999, Murphy sold 60 Company-owned Spur-branded retail stations located throughout the southeastern United States. The Company received consideration totaling $31.5 million, which was primarily used to reduce outstanding debt. In August 1999, Murphy filed a registration statement, which when declared effective by the U.S. Securities and Exchange Commission, will allow the Company to issue up to $1 billion in common and preferred stock, debt securities, depositary shares and warrants. Any proceeds from sales of these securities will be used for general corporate purposes, which may include working capital, capital expenditures, debt repayment, or financing of possible acquisitions. 12
MANAGEMENT'S DISCUSSION AND ANALYSIS (CONTD.) 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 on file with the U.S. Securities and Exchange Commission. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK The Company is exposed to market risks associated with interest rates, foreign currency exchange rates, and prices of crude oil, natural gas and petroleum products. As described in Note D on page 5 of the Form 10-Q report, Murphy makes limited use of derivative financial and commodity instruments to manage risks associated with existing or anticipated transactions. At June 30, 1999, the Company was a party to interest rate swaps with notional amounts totaling $100 million that were designed to convert a similar amount of variable-rate debt to fixed rates. The interest rate 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 June 30, 1999, the interest rate to be received by the Company averaged 5.03%. 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 a liability of $1.8 million at June 30, 1999. At June 30, 1999, 42% of the Company's long-term debt had variable interest rates and 21% was denominated in Canadian dollars. Based on debt outstanding at June 30, 1999, a 10% increase in variable interest rates would increase the Company's interest expense over the next 12 months by an estimated $.6 million after a $.5 million favorable effect of 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 by an estimated $.4 million over the next 12 months on Canadian dollar denominated debt. At June 30, 1999, the Company was a party to crude oil swap agreements for a total notional volume of two million barrels that reduce a portion of the financial exposure of Murphy's U.S. refineries to crude oil price movements. The agreements mature in 2001 and 2002. At termination, the swaps require Murphy to pay an average crude oil price of $16.63 a barrel and to receive the average of the near-month NYMEX West Texas Intermediate (WTI) crude oil prices during the respective contractual maturity periods. The estimated fair value of these crude oil swaps was an asset of $1.8 million at June 30, 1999; a 10% fluctuation in the price of WTI crude oil over the next 12 months would change the estimated fair value of these swaps by $3 million. At June 30, 1999, Murphy was also a party to natural gas price swap agreements for a total notional volume of 5 million MMBTU that are intended to reduce a portion of the financial exposure of its Meraux, Louisiana refinery to fluctuations in the price of natural gas purchased for fuel. The agreements are to be settled equally over the 12 months of 2004. In each month of settlement, the swaps require Murphy to pay an average natural gas price of $2.62 an MMBTU and to receive the average NYMEX Henry Hub price for the final three trading days of the month. The estimated fair value of these agreements was a liability of $.2 million at June 30, 1999; a 10% fluctuation in the average NYMEX Henry Hub price of natural gas over the next 12 months would change the estimated fair value by $.9 million. 13
<TABLE> <CAPTION> OIL AND GAS OPERATING RESULTS* (UNAUDITED) - ------------------------------------------------------------------------------ United Synthetic United King- Ecua- Oil - (Millions of dollars) States Canada dom dor Other Canada Total - ------------------------------------------------------------------------------ <S> <C> <C> <C> <C> <C> <C> <C> THREE MONTHS ENDED JUNE 30, 1999 Oil and gas sales and operating revenues $ 47.1 30.8 27.8 7.0 .3 17.2 130.2 Production costs 9.9 8.7 7.5 1.8 - 9.4 37.3 Depreciation, depletion and amortization 16.3 10.7 9.8 2.0 - 1.8 40.6 Exploration expenses Dry hole costs .5 - 2.3 - 1.1 - 3.9 Geological and geophysical costs 2.3 1.7 .3 - .8 - 5.1 Other costs .8 .1 .3 - .7 - 1.9 - ------------------------------------------------------------------------------ 3.6 1.8 2.9 - 2.6 - 10.9 Undeveloped lease amortization 1.7 1.1 - - - - 2.8 - ------------------------------------------------------------------------------ Total exploration expenses 5.3 2.9 2.9 - 2.6 - 13.7 - ------------------------------------------------------------------------------ Selling and general expenses 3.8 1.5 .8 .1 .2 - 6.4 Income tax provisions 4.0 2.6 3.4 - .1 2.0 12.1 - ------------------------------------------------------------------------------ Results of operations (excluding corporate overhead and interest) $ 7.8 4.4 3.4 3.1 (2.6) 4.0 20.1 ============================================================================== THREE MONTHS ENDED JUNE 30, 1998 Oil and gas sales and operating revenues $ 51.1 16.7 20.3 4.7 .4 15.1 108.3 Production costs 9.8 8.1 7.7 1.7 - 9.8 37.1 Depreciation, depletion and amortization 17.1 7.7 9.0 2.5 - 1.7 38.0 Exploration expenses Dry hole costs 5.6 2.2 - - 5.6 - 13.4 Geological and geophysical costs .2 .9 2.3 - .7 - 4.1 Other costs .6 .1 .6 - .4 - 1.7 - ------------------------------------------------------------------------------ 6.4 3.2 2.9 - 6.7 - 19.2 Undeveloped lease amortization 1.6 1.1 - - - - 2.7 - ------------------------------------------------------------------------------ Total exploration expenses 8.0 4.3 2.9 - 6.7 - 21.9 - ------------------------------------------------------------------------------ Selling and general expenses 4.0 1.5 .9 .1 .4 - 6.9 Income tax provisions (benefits) 4.3 (2.4) 1.6 (.8) (.4) 1.3 3.6 - ------------------------------------------------------------------------------ Results of operations (excluding corporate overhead and interest) $ 7.9 (2.5) (1.8) 1.2 (6.3) 2.3 .8 ============================================================================== SIX MONTHS ENDED JUNE 30, 1999 Oil and gas sales and operating revenues $ 87.4 53.3 50.9 11.7 .9 29.7 233.9 Production costs 19.5 17.4 17.1 3.4 - 18.1 75.5 Depreciation, depletion and amortization 32.0 19.6 20.8 4.1 - 3.5 80.0 Exploration expenses Dry hole costs 13.5 2.0 2.3 - 1.1 - 18.9 Geological and geophysical costs 5.8 4.2 .6 - 1.5 - 12.1 Other costs 1.2 .3 .6 - 1.4 - 3.5 - ------------------------------------------------------------------------------ 20.5 6.5 3.5 - 4.0 - 34.5 Undeveloped lease amortization 3.5 2.0 - - - - 5.5 - ------------------------------------------------------------------------------ Total exploration expenses 24.0 8.5 3.5 - 4.0 - 40.0 - ------------------------------------------------------------------------------ Selling and general expenses 7.9 3.0 1.6 .1 .5 - 13.1 Income tax provisions .9 1.6 3.0 - .2 2.7 8.4 - ------------------------------------------------------------------------------ Results of operations (excluding corporate overhead and interest) $ 3.1 3.2 4.9 4.1 (3.8) 5.4 16.9 ============================================================================== SIX MONTHS ENDED JUNE 30, 1998 Oil and gas sales and operating revenues $ 103.3 35.5 42.2 10.4 1.2 27.5 220.1 Production costs 19.7 17.7 15.6 3.5 - 16.9 73.4 Depreciation, depletion and amortization 35.4 16.4 18.9 5.0 - 3.2 78.9 Exploration expenses Dry hole costs 11.0 3.2 - - 8.3 - 22.5 Geological and geophysical costs 2.3 2.9 2.6 - 1.0 - 8.8 Other costs .9 .3 1.0 - 1.1 - 3.3 - ------------------------------------------------------------------------------ 14.2 6.4 3.6 - 10.4 - 34.6 Undeveloped lease amortization 3.2 2.2 - - - - 5.4 - ------------------------------------------------------------------------------ Total exploration expenses 17.4 8.6 3.6 - 10.4 - 40.0 - ------------------------------------------------------------------------------ Selling and general expenses 8.1 3.2 1.7 .1 .8 - 13.9 Income tax provisions (benefits) 7.8 (5.7) 3.6 (.8) (.2) 2.4 7.1 - ------------------------------------------------------------------------------ Results of operations (excluding corporate overhead and interest) $ 14.9 (4.7) (1.2) 2.6 (9.8) 5.0 6.8 ============================================================================== *Excludes special items. </TABLE> 14
PART II - OTHER INFORMATION ITEM 1. LEGAL PROCEEDINGS Following a 1998 compliance inspection of the Superior, Wisconsin refinery, the Company received notices of violations of the Clean Air Act from the U.S. Environmental Protection Agency. Although the penalty amounts were not listed, the statutes involved provide for rates of up to $27,500 per day of violation, and penalties therefore could exceed $100,000. The Company believes it has valid defenses to the alleged violations and plans a vigorous defense. While the notices of violation are preliminary in nature and no assurance can be given, the Company does not believe that the ultimate resolution of the matter will have a material adverse effect on the financial condition of the Company. Murphy and its subsidiaries are engaged in a number of other legal proceedings, all of which Murphy considers routine and incidental to its business and none of which is expected to have a material adverse effect on the Company's financial condition. ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS At the annual meeting of security holders on May 12, 1999, the directors proposed by management were elected with a tabulation of votes to the nearest share as shown below. <TABLE> <CAPTION> For Withheld ---------- --------- <S> <C> <C> B. R. R. Butler 40,600,017 258,419 George S. Dembroski 40,539,430 319,006 Claiborne P. Deming 40,600,526 257,910 H. Rodes Hart 37,998,359 2,860,077 Vester T. Hughes Jr. 40,254,348 604,088 C. H. Murphy Jr. 40,124,444 733,992 Michael W. Murphy 40,601,636 256,800 R. Madison Murphy 40,601,653 256,783 William C. Nolan Jr. 40,601,216 257,220 Caroline G. Theus 40,600,776 257,660 Lorne C. Webster 40,596,992 261,444 </TABLE> In addition, the earlier appointment by the Board of Directors of KPMG LLP as independent auditors for 1999 was ratified with 40,769,599 shares voted in favor, 73,112 shares voted in opposition, and 15,724 shares not voted. 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) A report on Form 8-K was filed on April 29, 1999, that included the Form of Indenture and Form of Supplemental Indenture between Murphy and SunTrust Bank, Nashville, N.A., as Trustee of Murphy's 30-year, 7.05% notes for $250 million. 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/ Ronald W. Herman -------------------- Ronald W. Herman, Controller (Chief Accounting Officer and Duly Authorized Officer) August 12, 1999 (Date) 15
EXHIBIT INDEX Exhibit No. Incorporated by Reference to - ------- ---------------------------- 3.1 Certificate of Incorporation of Exhibit 3.1 of Murphy's Form Murphy Oil Corporation as of 10-K report for the year ended September 25, 1986 December 31, 1996 3.2 By-laws of Murphy Oil Corporation Exhibit 3.2 of Murphy's Form at January 24, 1996 10-K report for the year ended December 31, 1997 3.3 By-laws of Murphy Oil Corporation Exhibit 3.3 filed herewith as amended May 12, 1999 4 Instruments Defining the Rights of Security Holders. Murphy is party to several long-term debt instruments in addition to the ones below, 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 Exhibit 4.1 of Murphy's Form Oil Corporation and certain 10-K report for the year ended subsidiaries and the Chase December 31, 1997 Manhattan Bank et al as of November 13, 1997 4.2 Form of Indenture and Form of Exhibits 4.1 and 4.2 of Murphy's Supplemental Indenture between Form 8-K report filed April 29, Murphy Oil Corporation and SunTrust 1999, under the Securities Bank, Nashville, N.A., as Trustee Exchange Act of 1934 4.3 Rights Agreement dated as of Exhibit 4.1 of Murphy's Form December 6, 1989, between Murphy 10-K report for the year ended Oil Corporation and Harris Trust December 31, 1994 Company of New York, as Rights Agent 4.4 Amendment No. 1 dated as of April 6, Exhibit 3 of Murphy's Form 1998, to Rights Agreement dated as 8-A/A, Amendment No. 1, filed of December 6, 1989, between Murphy April 14, 1998, under the Oil Corporation and Harris Trust Securities Exchange Act of Company of New York, as Rights Agent 1934 4.5 Amendment No. 2 dated as of Exhibit 4 of Murphy's Form April 15, 1999, to Rights 8-A/A, Amendment No. 2, filed Agreement dated as of December April 19, 1999, under the 6, 1989, between Murphy Oil Securities Exchange Act of Corporation and Harris Trust 1934 Company of New York, as Rights Agent 10.1 1987 Management Incentive Plan as Exhibit 10.2 of Murphy's amended February 7, 1990, Form 10-K report for the retroactive to February 3, 1988 year ended December 31, 1994 10.2 1992 Stock Incentive Plan as Exhibit 10.2 of Murphy's Form amended May 14, 1997 10-Q report for the quarterly period ended June 30, 1997 10.3 Employee Stock Purchase Plan Exhibit 99.01 of Murphy's Form S-8 Registration Statement filed May 19, 1997, under the Securities Act of 1933 27 Financial Data Schedule for the Filed herewith in electronic six months ended June 30, 1999 filing Exhibits other than those listed above have been omitted since they are either not required or not applicable. 16