==============================================================================
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark one)
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended SEPTEMBER 30, 1998
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR
15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from _______________ to _______________
Commission File Number 1-8590
MURPHY OIL CORPORATION
(Exact name of registrant as specified in its charter)
DELAWARE 71-0361522
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification Number)
200 PEACH STREET
P. O. BOX 7000, EL DORADO, ARKANSAS 71731-7000
(Address of principal executive offices) (Zip Code)
(870) 862-6411
(Registrant's telephone number, including area code)
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to
such filing requirements for the past 90 days.
[X] Yes No
Number of shares of Common Stock, $1.00 par value, outstanding at September
30, 1998 was 44,965,866.
==============================================================================
<PAGE>
PART I - FINANCIAL INFORMATION
Murphy Oil Corporation and Consolidated Subsidiaries
CONSOLIDATED BALANCE SHEETS
(Thousands of dollars)
<TABLE>
<CAPTION>
(unaudited)
September 30, December 31,
1998 1997
------------- ------------
<S> <C> <C>
ASSETS
Current assets
Cash and cash equivalents $ 28,879 24,288
Accounts receivable, less allowance for
doubtful accounts of $12,069 in 1998
and $13,530 in 1997 242,947 272,447
Inventories
Crude oil and blend stocks 71,800 55,075
Finished products 36,866 64,394
Materials and supplies 38,889 38,947
Prepaid expenses 37,136 47,323
Deferred income taxes 13,167 15,278
--------- ---------
Total current assets 469,684 517,752
Property, plant and equipment, at cost less
accumulated depreciation, depletion and
amortization of $2,882,789 in 1998 and
$2,762,805 in 1997 1,726,900 1,655,838
Deferred charges and other assets 64,046 64,729
--------- ---------
Total assets $ 2,260,630 2,238,319
========= =========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities
Current maturities of long-term obligations $ 7,381 6,227
Notes payable - 2,175
Accounts payable and accrued liabilities 406,624 435,390
Income taxes 21,430 25,627
--------- ---------
Total current liabilities 435,435 469,419
Notes payable 95,864 28,367
Nonrecourse debt of a subsidiary 172,205 177,486
Deferred income taxes 144,971 136,390
Reserve for dismantlement costs 155,673 153,021
Reserve for major repairs 41,743 43,038
Deferred credits and other liabilities 151,616 151,247
Stockholders' equity
Capital stock
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 510,719 509,615
Retained earnings 622,083 622,532
Accumulated other comprehensive income - foreign
currency translation (16,227) 891
Unamortized restricted stock awards (2,653) (944)
Treasury stock, 3,809,448 shares of Common
Stock in 1998, 3,883,883 shares in 1997,
at cost (99,574) (101,518)
--------- ---------
Total stockholders' equity 1,063,123 1,079,351
--------- ---------
Total liabilities and stockholders' equity $ 2,260,630 2,238,319
========= =========
</TABLE>
See Notes to Consolidated Financial Statements, page 4.
The Exhibit Index is on page 16.
1
<PAGE>
Murphy Oil Corporation and Consolidated Subsidiaries
CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)
(Thousands of dollars, except per share amounts)
<TABLE>
<CAPTION>
Three Months Ended Nine Months Ended
September 30, September 30,
------------------- --------------------
1998 1997 1998 1997
------- ------- --------- ---------
<S> <C> <C> <C> <C>
REVENUES
Sales $ 422,235 540,307 1,265,626 1,527,914
Other operating revenues 9,769 14,897 53,483 40,835
Interest, income from equity
companies and other nonoperating
revenues 1,315 1,110 3,506 3,605
------- ------- --------- ---------
Total revenues 433,319 556,314 1,322,615 1,572,354
------- ------- --------- ---------
COSTS AND EXPENSES
Crude oil, products and related
operating expenses 338,650 391,954 992,046 1,131,421
Exploration expenses, including
undeveloped lease amortization 9,567 19,734 49,527 71,508
Selling and general expenses 15,387 18,660 49,031 47,691
Depreciation, depletion and
amortization 50,914 56,565 148,757 156,073
Impairment of long-lived assets - 5,100 - 5,100
Interest expense 4,891 3,263 12,861 9,207
Interest capitalized (1,476) (3,227) (6,662) (9,126)
------- ------- --------- ---------
Total costs and expenses 417,933 492,049 1,245,560 1,411,874
------- ------- --------- ---------
Income before income taxes 15,386 64,265 77,055 160,480
Federal and state income taxes 3,456 15,832 23,869 37,172
Foreign income taxes 2,915 6,108 6,431 22,811
------- ------- --------- ---------
NET INCOME $ 9,015 42,325 46,755 100,497
======= ======= ========= =========
Net income per Common
share - basic $ .20 .94 1.04 2.24
======= ======= ========= =========
Net income per Common
share - diluted $ .20 .94 1.04 2.23
======= ======= ========= =========
Cash dividends per Common share $ .35 .35 1.05 1.00
======= ======= ========= =========
Average Common shares
outstanding - basic 44,964,657 44,882,749 44,954,021 44,877,950
Average Common shares
outstanding - diluted 44,987,581 44,970,283 45,012,976 44,948,964
</TABLE>
Murphy Oil Corporation and Consolidated Subsidiaries
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)
(Thousands of dollars)
<TABLE>
<CAPTION>
Three Months Ended Nine Months Ended
September 30, September 30,
------------------ -----------------
1998 1997 1998 1997
------ ------ ------ -------
<S> <C> <C> <C> <C>
Net income $ 9,015 42,325 46,755 100,497
Other comprehensive
income - net loss from
foreign currency translation (9,169) (6,874) (17,118) (14,768)
----- ------ ------ ------
COMPREHENSIVE INCOME (LOSS) $ (154) 35,451 29,637 85,729
===== ====== ====== ======
</TABLE>
See Notes to Consolidated Financial Statements, page 4.
2
<PAGE>
Murphy Oil Corporation and Consolidated Subsidiaries
CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
(Thousands of dollars)
<TABLE>
<CAPTION>
Nine Months Ended
September 30,
-------------------
1998 1997
------- -------
<S> <C> <C>
OPERATING ACTIVITIES
Net income $ 46,755 100,497
Adjustments to reconcile net income to net
cash provided by operating activities
Depreciation, depletion and amortization 148,757 156,073
Impairment of long-lived assets - 5,100
Provisions for major repairs 15,946 17,402
Expenditures for major repairs and dismantlement costs (20,947) (12,749)
Exploratory expenditures charged against income 41,504 63,733
Amortization of undeveloped leases 8,023 7,775
Deferred and noncurrent income taxes 18,032 7,268
Pretax gains from disposition of assets (761) (6,247)
Other - net 6,534 5,701
------- -------
263,843 344,553
Net (increase) decrease in operating working capital
other than cash and cash equivalents 19,696 (21,362)
Other adjustments related to operating activities (1,779) (8,228)
------- -------
Net cash provided by operating activities 281,760 314,963
------- -------
INVESTING ACTIVITIES
Capital expenditures requiring cash (296,160) (335,596)
Proceeds from sale of property, plant and equipment 4,718 14,277
Other investing activities - net (201) 196
------- -------
Net cash required by investing activities (291,643) (321,123)
------- -------
FINANCING ACTIVITIES
Increase in notes payable 65,322 8,686
Increase (decrease) in nonrecourse debt of a subsidiary (4,127) 4,938
Cash dividends paid (47,204) (44,864)
Sale of treasury shares under employee stock purchase plan 520 -
------- -------
Net cash provided (required) by financing activities 14,511 (31,240)
------- -------
Effect of exchange rate changes on cash and
cash equivalents (37) (2,736)
------- -------
Net increase (decrease) in cash and cash equivalents 4,591 (40,136)
Cash and cash equivalents at January 1 24,288 109,707
------- -------
Cash and cash equivalents at September 30 $ 28,879 69,571
======= =======
SUPPLEMENTAL DISCLOSURES OF CASH FLOW ACTIVITIES
Cash income taxes paid, net of refunds $ 29,248 56,146
Interest paid, net of amounts capitalized 4,204 (2,728)
</TABLE>
See Notes to Consolidated Financial Statements, page 4.
3
<PAGE>
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 report on Form 10-Q.
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, 1997. In the opinion of Murphy's management, the
unaudited financial statements presented herein include all adjustments
(consisting only of normal, recurring accruals) necessary to present fairly
the Company's financial position at September 30, 1998, and the results of
operations and cash flows for the three-month and nine-month periods ended
September 30, 1998 and 1997, in conformity with generally accepted accounting
principles.
Financial statements and notes to consolidated financial statements included
in this report on Form 10-Q should be read in conjunction with the Company's
1997 Annual Report on Form 10-K, as certain notes and other pertinent
information have been abbreviated or omitted in this report. Financial
results for the nine months ended September 30, 1998, are not necessarily
indicative of future results.
NOTE B - ENVIRONMENTAL CONTINGENCIES
The Company's worldwide operations are subject to numerous laws and
regulations intended to protect the environment and/or impose remedial
obligations. In addition, the Company is 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 or 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 environmental
obligations 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 and
adjusted as needed. Actual cash expenditures often occur one or more years
after recognition of a liability.
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
two 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 three 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
any 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.
Although the Company is not aware of any environmental matters that might have
a material 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.
Certain liabilities for environmentally related obligations and prior
environmental expenditures are expected to be recovered by the Company from
other sources, primarily environmental funds maintained by the various states.
Since no assurance can be given that recoveries from other sources will occur,
the Company has not recognized a benefit for these potential recoveries at
September 30, 1998.
4
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTD.)
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; promotion of safety; governmental support for
other forms of energy; and laws and regulations affecting the Company's
relationships with employees, suppliers, customers, stockholders and others.
Because governmental actions are often motivated by political considerations,
may be taken without full consideration of their consequences, and may be
taken in response to actions of other governments, it is not practical to
attempt to predict the likelihood of such actions, the form the actions may
take or the effect such actions may have on the Company.
In the normal course of its business activities, the Company is required under
certain contracts with various governmental authorities and others to provide
letters of credit that may be drawn upon if the Company fails to perform under
those contracts. At September 30, 1998, the Company had contingent
liabilities of $8 million on outstanding letters of credit and $13 million
under certain financial guarantees.
NOTE D - DERIVATIVE INSTRUMENTS
Derivative instruments are used by the Company on a limited basis to manage
well-defined risks related to interest rates, foreign currency exchange rates
and commodity prices. The use of derivative instruments is closely monitored
by the Company's senior management, and all such transactions are designed to
address risk-management objectives. The Company does not hold any derivatives
for trading purposes, and it does not use derivatives with leveraged features.
Derivative instruments are traded either with creditworthy major financial
institutions or over national exchanges. Instruments that reduce the exposure
of assets, liabilities or anticipated transactions to price, currency or
interest rate risks are accounted for as hedges. Gains or losses on
derivatives that cease to qualify as hedges are recognized in income or
expense.
At September 30, 1998 and 1997, Murphy had interest rate swap agreements with
notional amounts totaling $100 million and $85 million, respectively; these
serve to convert an equal amount of variable rate long-term debt to fixed
rates. The swaps outstanding at September 30, 1998, will mature in 2002
and 2004 and have a weighted-average fixed interest rate of 6.46 percent.
Using the accrual/settlement method of accounting, the net amount to be
received or paid on a quarterly basis under the swap agreements is accrued as
part of "Interest Expense" in the Consolidated Statement of Income. Although
the Company has not terminated an interest rate swap prior to maturity, if it
did, 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.
At September 30, 1998, the Company had a forward foreign currency exchange
contract that serves to fix the U.S. dollar cost for Canadian dollar
nonrecourse debt associated with the Company's investment in the Syncrude
project. When the debt becomes due and the currency exchange contract matures
in December 1998, Murphy will pay US $28.5 million to acquire the Cdn $38
million needed to retire the debt. The Company records the unrealized
difference between the contract exchange rate and the actual period-ending
exchange rate in the Consolidated Balance Sheet as an adjustment to
"Nonrecourse Debt of a Subsidiary" with the offset to "Accumulated Other
Comprehensive Income." When the contract is settled, any adjustment to the
difference previously recorded will be included in the same accounts.
The Company previously used 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 were generally deferred and
recognized in connection with the associated crude oil purchase. If
conditions indicated 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 was provided for the
nonrecoverable portion of the unrealized swap loss. The final swap matured in
the third quarter of 1997. The Company recorded pretax operating results
associated with crude oil swaps in "Crude Oil, Products and Related Operating
Expenses" in the Consolidated Statement of Income. An after-tax gain of $5
million in the nine months ended September 30, 1997, was due to crude oil
swaps.
5
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTD.)
NOTE E - EARNINGS PER SHARE
Net income was used as the numerator in computing both basic and diluted
income per Common share for the three months and nine months ended September
30, 1998 and 1997. Reconciliations of the weighted-average shares
outstanding for these computations are shown in the following table.
<TABLE>
<CAPTION>
------------------------------------------------------------------------
Reconciliation of Shares Three Months Ended Nine Months Ended
Outstanding September 30, September 30,
------------------------------------------------------------------------
(Weighted average shares) 1998 1997 1998 1997
------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Basic method . . . . . . 44,964,657 44,882,749 44,954,021 44,877,950
Dilutive stock options . 22,924 87,534 58,955 71,014
------------------------------------------------------------------------
Diluted method 44,987,581 44,970,283 45,012,976 44,948,964
========================================================================
</TABLE>
The computation of diluted earnings per share in the preceding table did not
consider period-ending outstanding stock options for 705,000 shares in 1998
and 412,000 shares in 1997 because the effects of these options would have
been antidilutive. Such options outstanding at September 30, 1998, had
exercise prices of $49.75 to $65.49 a share, averaging $53.25 a share, and
remaining lives of 8.3 to 9.3 years, averaging 8.8 years.
6
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTD.)
NOTE F - BUSINESS SEGMENTS (UNAUDITED)
<TABLE>
<CAPTION>
Three Months Ended Three Months Ended
September 30, 1998 September 30, 1997
- -----------------------------------------------------------------------------
(Millions of dollars) Revenues Income Revenues Income
- -----------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Exploration and production*
United States . . . . . . . . . . $ 35.7 .9 66.1 13.5
Canada. . . . . . . . . . . . . . 34.8 1.7 44.7 6.4
United Kingdom. . . . . . . . . . 23.6 (.3) 30.5 1.8
Ecuador . . . . . . . . . . . . . 4.1 .1 9.3 3.1
Other international . . . . . . . .7 (2.7) .2 (3.7)
- -----------------------------------------------------------------------------
98.9 (.3) 150.8 21.1
- -----------------------------------------------------------------------------
Refining, marketing and transportation
United States . . . . . . . . . . 283.8 5.9 357.9 19.2
United Kingdom. . . . . . . . . . 60.8 5.4 76.1 3.9
Canada. . . . . . . . . . . . . . 5.3 .9 6.6 1.5
- -----------------------------------------------------------------------------
349.9 12.2 440.6 24.6
- -----------------------------------------------------------------------------
448.8 11.9 591.4 45.7
Intersegment transfers elimination (16.8) - (36.1) -
- -----------------------------------------------------------------------------
432.0 11.9 555.3 45.7
Corporate . . . . . . . . . . . . . 1.3 (2.9) 1.1 (3.3)
- -----------------------------------------------------------------------------
Revenues/income before special items 433.3 9.0 556.4 42.4
Refund of U.K. income taxes . . . . - - - 3.2
Impairment of long-lived assets . . - - - (3.3)
- -----------------------------------------------------------------------------
Total revenues/net income $ 433.3 9.0 556.4 42.3
=============================================================================
Nine Months Ended Nine Months Ended
September 30, 1998 September 30, 1997
- -----------------------------------------------------------------------------
(Millions of dollars) Revenues Income Revenues Income
- -----------------------------------------------------------------------------
Exploration and production*
United States . . . . . . . . . . $ 139.0 15.8 196.7 34.4
Canada. . . . . . . . . . . . . . 97.8 2.0 123.2 15.5
United Kingdom. . . . . . . . . . 65.8 (1.5) 90.7 10.1
Ecuador . . . . . . . . . . . . . 14.5 2.7 26.1 8.4
Other international . . . . . . . 1.9 (12.5) 1.3 (10.9)
- -----------------------------------------------------------------------------
319.0 6.5 438.0 57.5
- -----------------------------------------------------------------------------
Refining, marketing and transportation
United States . . . . . . . . . . 830.7 27.1 1,004.7 37.9
United Kingdom. . . . . . . . . . 202.7 14.0 195.2 6.0
Canada. . . . . . . . . . . . . . 17.8 3.8 19.1 4.5
- -----------------------------------------------------------------------------
1,051.2 44.9 1,219.0 48.4
- -----------------------------------------------------------------------------
1,370.2 51.4 1,657.0 105.9
Intersegment transfers elimination (56.5) - (88.2) -
- -----------------------------------------------------------------------------
1,313.7 51.4 1,568.8 105.9
Corporate . . . . . . . . . . . . . 3.5 (8.9) 3.6 (5.3)
- -----------------------------------------------------------------------------
Revenues/income before special items 1,317.2 42.5 1,572.4 100.6
Modification of U.K. natural gas
sales contract . . . . . . . . . . 4.0 2.8 - -
Net recovery pertaining to 1996
modifications of foreign crude oil
contracts. . . . . . . . . . . . . 1.4 1.4 - -
Refund of U.K. income taxes . . . . - - - 3.2
Impairment of long-lived assets . . - - - (3.3)
- -----------------------------------------------------------------------------
Total revenues/net income $1,322.6 46.7 1,572.4 100.5
=============================================================================
*Additional details are presented in the tables on page 14.
</TABLE>
7
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL
CONDITION
RESULTS OF OPERATIONS
THREE MONTHS ENDED SEPTEMBER 30, 1998, COMPARED TO THREE MONTHS ENDED
SEPTEMBER 30, 1997
Net income in the third quarter of 1998 totaled $9 million, $.20 a diluted
share, compared to $42.3 million, $.94 a diluted share, in the third quarter a
year ago. Special items included in earnings for the 1997 quarter were a
charge of $3.3 million, $.07 a diluted share, for an impairment of long-lived
assets that was nearly offset by a gain of $3.2 million, $.07 a share, from a
refund of U.K. income taxes. Cash flow from operating activities, excluding
changes in noncash working capital items, totaled $79.9 million in the third
quarter of 1998 compared to $124.7 million in the 1997 quarter.
Murphy's worldwide downstream operations earned $12.2 million in the 1998
quarter compared to $24.6 million a year ago. Exploration and production
operations, reflecting a decline of $5.00 a barrel in the Company's average
worldwide crude oil price, reported a loss of $.3 million in the current
quarter compared to earnings of $21.1 million in the third quarter of 1997.
Exploration and production operations in the United States earned $.9 million
compared to $13.5 million in the third quarter of 1997. Operations in Canada
earned $1.7 million, down from $6.4 million a year ago, and U.K. operations
reported a loss of $.3 million in the current quarter compared to earnings of
$1.8 million a year ago. Operations in Ecuador earned $.1 million in the
third quarter of 1998 compared to $3.1 million. Other international
operations reported a loss of $2.7 million compared to a $3.7 million loss a
year earlier. The Company's crude oil and condensate sales prices averaged
$12.19 a barrel in the United States and $12.43 in the United Kingdom,
decreases of 34 percent and 33 percent, respectively. In Canada, sales prices
averaged $11.55 a barrel for light oil, down 31 percent; $7.85 for heavy oil,
down 28 percent; and $13.61 for synthetic oil, down 29 percent. Sales prices
for the Hibernia field, off the east coast of Canada, which came on stream
during the fourth quarter of 1997, averaged $11.16 a barrel during the current
quarter. In Ecuador, sales prices averaged $6.73 a barrel, down 46 percent.
Murphy's average natural gas sales price in the United States was $2.03 a
thousand cubic feet (MCF) in the current quarter compared to $2.35 a year ago.
The average natural gas sales price in Canada increased from $1.08 an MCF to
$1.20. Total crude oil and gas liquids production averaged 60,864 barrels a
day compared to 61,194 in the third quarter of 1997. Production from new
fields being brought on stream in the United Kingdom and offshore Canada were
offset by lower U.S. production and a decline in Canadian heavy oil
production, with the latter due to a selective shut-in of production in
response to the drop in heavy oil prices. Total natural gas sales averaged
214 million cubic feet a day compared to 284 million a year ago. Sales of
natural gas in the United States averaged 154 million cubic feet a day, down
34 percent from the third quarter of 1997. Storm-related down time in the
Gulf of Mexico accounted for approximately 25 percent of the decline in U.S.
oil production and natural gas sales. Natural gas sales increased five
million cubic feet a day in Canada and three million in the United Kingdom.
Exploration expenses totaled $9.5 million in the current quarter compared to
$19.7 million in 1997. The tables on page 14 provide additional details of
the results of exploration and production operations for the third quarter of
each year.
Refining, marketing and transportation operations in the United States earned
$5.9 million compared to $19.2 million a year ago; margins in the 1998 quarter
were down because of much lower selling prices partially offset by lower crude
costs. Operations in the United Kingdom earned $5.4 million compared to $3.9
million in the third quarter of 1997. Earnings from purchasing, transporting
and reselling crude oil in Canada were $.9 million in the current quarter
compared to $1.5 million a year ago. Refinery crude runs worldwide were
162,842 barrels a day compared to 164,274 in the third quarter of 1997.
Worldwide refined product sales were 175,506 barrels a day, up from 172,530 a
year ago.
Corporate functions, which include interest income and expense and corporate
overhead not allocated to operating functions, reflected a loss of $2.9
million in the current quarter compared to a loss of $3.3 million in the third
quarter of 1997.
NINE MONTHS ENDED SEPTEMBER 30, 1998, COMPARED TO NINE MONTHS ENDED SEPTEMBER
30, 1997
For the first nine months of 1998, net income totaled $46.7 million, $1.04 a
diluted share, and included a benefit of $4.2 million, $.09 a diluted share,
from special items. For the same period in 1997, net income totaled $100.5
million, $2.23 a diluted share, and included the net $.1 million charge from
the previously
8
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS (CONTD.)
RESULTS OF OPERATIONS (CONTD.)
mentioned special items in the third quarter. The 1998 special items were a
$2.8 million benefit from modification of a natural gas sales contract in the
United Kingdom and a $1.4 million benefit from partial recovery of a 1996 loss
resulting from modification to a crude oil production contract in Ecuador.
The primary reason for the lower year-to-date earnings before special items
was a decrease in the earnings of exploration and production operations from
$57.5 million for the first nine months of 1997 to $6.5 million for the 1998
period. The decrease in exploration and production results was mainly caused
by a decline of $5.60 a barrel in the Company's average worldwide crude oil
price, lower natural gas sales prices, and lower U.S. natural gas sales
volumes, partially offset by the effects of lower exploration expenses.
Earnings of the Company's worldwide downstream operations for the first
nine months of 1998 were $44.9 million, down slightly from $48.4 million in
the 1997 period, as the effect of lower selling prices was nearly offset by
lower crude costs and higher sales volumes. Corporate functions reflected a
loss of $8.9 million for the 1998 period compared to a loss of $5.3 million a
year earlier; the increased loss was primarily due to higher interest expense
net of amounts capitalized.
Exploration and production operations in the United States earned $15.8
million for the 1998 period compared to $34.4 million a year ago, and Canadian
operations earned $2 million compared to $15.5 million in 1997. Decreases
from the prior year also occurred in the United Kingdom, which had a loss
of $1.5 million compared to earnings of $10.1 million, and in Ecuador, which
had earnings of $2.7 million compared to $8.4 million. Other international
operations recorded losses of $12.5 million in the first nine months of 1998
and $10.9 million in the 1997 period. The Company's crude oil and condensate
sales prices averaged $13.20 a barrel in the United States, down 33 percent,
and $13.06 in the United Kingdom, down 32 percent. In Canada, sales prices
averaged $12.26 a barrel for light oil, down 32 percent from last year; $6.24
for heavy oil, down 45 percent; and $14.24 for synthetic oil, down 29 percent.
The average crude oil sales price for production from the Hibernia field,
which came on stream in the fourth quarter of 1997, was $11.71 a barrel, while
the average sales price in Ecuador was $7.18 a barrel, down 43 percent. Crude
oil and gas liquids production for the first nine months of 1998 averaged
56,491 barrels a day compared to 56,870 during the same period of 1997. Oil
production at Hibernia averaged 3,401 barrels a day, and production of
Canadian synthetic oil increased 14 percent to 10,227. Production of crude
oil and gas liquids in the United Kingdom was up 2 percent to 14,205 barrels a
day as new fields came on stream in July. Canadian heavy oil production was
down 15 percent to 9,572 barrels a day due to a selective shut-in of wells in
response to the drop in heavy oil prices. In other areas, crude oil and gas
liquids production averaged 7,764 barrels a day in the United States, down 30
percent; 3,886 for Canadian light oil, down 2 percent; and 7,436 in Ecuador,
down 3 percent. Approximately 9 percent of the decline in U.S. oil production
was due to storm-related downtime in the Gulf of Mexico. Natural gas sales
prices for the first nine months of 1998 averaged $2.22 an MCF in the United
States, down 6 percent; $1.21 in Canada, down 8 percent; and $2.39 in the
United Kingdom, down 6 percent. Total natural gas sales averaged 231 million
cubic feet a day in the 1998 period compared to 268 million in 1997. Sales of
natural gas in the United States averaged 173 million cubic feet a day, down
18 percent from 1997. Storm-related downtime in the Gulf of Mexico accounted
for approximately 17 percent of the decline in U.S. natural gas sales. In
other areas, average natural gas sales volumes increased 8 percent in Canada
but were down 15 percent in the United Kingdom, where production from the
Amethyst field was shut in during early 1998 to repair pipeline damages.
Exploration expenses totaled $49.5 million for the nine months ended September
30, 1998, compared to $71.5 million a year ago. Exploration expenses were
down in the United States, the United Kingdom and Canada, but were up in other
international areas. The tables on page 14 provide additional details of the
results of exploration and production operations for the first nine months of
each year.
Refining, marketing and transportation operations in the United States earned
$27.1 million for the first nine months of 1998 compared to $37.9 million for
the same period last year. The U.S. results in 1997 included after-tax
benefits of $5 million related to crude oil swap agreements. Operations in
the United Kingdom earned $14 million in the nine months ended September 30,
1998, compared to $6 million in the prior year. Earnings from purchasing,
transporting and reselling crude oil in Canada were $3.8 million in the
current nine-month period compared to $4.5 million a year ago. The
Company's refinery crude runs worldwide for the 1998 period were 164,722
barrels a day compared to 159,583 a year ago. Petroleum product sales
worldwide were 174,075 barrels a day, up from 161,236 in 1997.
9
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS (CONTD.)
FINANCIAL CONDITION
Net cash provided by operating activities was $281.8 million for the nine
months ended September 30, 1998, compared to $315 million for the same period
in 1997. Changes in operating working capital other than cash and cash
equivalents provided cash of $19.7 million for the first nine months of 1998
but required cash of $21.4 million for the 1997 period. Cash provided by
operating activities was reduced by expenditures for refinery turnarounds and
abandonment of oil and gas properties totaling $20.9 million in the current
year and $12.7 million in 1997. Predominant uses of cash in both years
were for capital expenditures (which, including amounts expensed, are
summarized in the following table) and payment of dividends.
<TABLE>
<CAPTION>
-------------------------------------------------------------------------
Capital Expenditures Nine Months Ended September 30,
-------------------------------------------------------------------------
(Millions of dollars) 1998 1997
-------------------------------------------------------------------------
<S> <C> <C>
Exploration and production. . . . . . . . . . . . . $256.8 312.1
Refining, marketing and transportation. . . . . . . 37.6 22.3
Corporate . . . . . . . . . . . . . . . . . . . . . 1.8 1.2
-------------------------------------------------------------------------
$296.2 335.6
=========================================================================
</TABLE>
Working capital at September 30, 1998, was $34.2 million, down $14.1 million
from December 31, 1997. 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 $56.4 million below current costs at
September 30, 1998.
At September 30, 1998, long-term nonrecourse debt of a subsidiary was $172.2
million, down slightly from December 31, 1997, due to changes in foreign
currency exchange rates. Notes payable of $95.9 million increased $67.5
million in 1998 due to additional borrowings for certain oil and gas
development projects. A summary of capital employed at September 30, 1998,
and December 31, 1997, follows.
<TABLE>
<CAPTION>
-------------------------------------------------------------------------
Capital Employed September 30, 1998 December 31, 1997
-------------------------------------------------------------------------
(Millions of dollars) Amount % Amount %
-------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Notes payable . . . . . . . . . . $ 95.9 7 28.4 2
Nonrecourse debt of a subsidiary. 172.2 13 177.5 14
Stockholders' equity . . . . . . 1,063.1 80 1,079.4 84
-------------------------------------------------------------------------
$1,331.2 100 1,285.3 100
=========================================================================
</TABLE>
OTHER MATTERS
NEW ACCOUNTING STANDARDS
The Financial Accounting Standards Board (FASB) issued Statement of Financial
Accounting Standards (SFAS) No. 131, "Disclosures about Segments of an
Enterprise and Related Information," in June 1997. This statement will alter
the Company's disclosures about its operating segments beginning with the
results for the year ending December 31, 1998, and for each period thereafter,
with restated comparative disclosures for earlier periods. This statement
does not amend any existing accounting procedures, but it requires disclosures
about an enterprise's components for which separate financial information is
available and regularly used by the chief operating decision maker in
allocating resources and assessing performance. The Company will comply with
this statement by providing certain additional segment and geographic
information for revenues, expenses and assets in its consolidated financial
statements for the year ending December 31, 1998.
In February 1998, the FASB issued SFAS No. 132, "Employers' Disclosures about
Pensions and Other Postretirement Benefits." This statement standardizes the
disclosure requirements for pensions and other postretirement benefits and
requires additional information on changes in the benefit obligations and fair
value of plan assets. SFAS No. 132 does not change the measurement or
recognition rules related to these benefit plans. To comply with this
statement, Murphy will change the benefit plan disclosures in its consolidated
financial statements for the year ending December 31, 1998.
10
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS (CONTD.)
OTHER MATTERS (CONTD.)
NEW ACCOUNTING STANDARDS (CONTD.)
In June 1998, the FASB issued SFAS No. 133, "Accounting for Derivative
Instruments and Hedging Activities." This statement establishes accounting
and reporting standards for derivative instruments and hedging activities.
Effective January 1, 2000, it will require Murphy to recognize all derivatives
as either assets or liabilities and to measure those instruments at fair value
in its Consolidated Balance Sheet. A derivative 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 net income or other comprehensive
income, as appropriate, as the cumulative effect of a change in accounting
principle. As described in Note D to the consolidated financial statements,
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.
During 1997, the Securities and Exchange Commission amended Regulation S-K to
require expanded disclosures concerning a broad range of market-sensitive
instruments, including debt and equity securities and derivative instruments,
beginning with the Company's 1998 Annual Report. Specifically, the new rules
require the Company to disclose both quantitative and qualitative information
concerning the market risks posed by risk-sensitive instruments; such
disclosures are to be outside of the consolidated financial statements. The
Company has not yet determined which of several acceptable methods it will use
for the required disclosures.
YEAR 2000 ISSUES
GENERAL
The Year 2000 issue affects all companies and relates 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), PricewaterhouseCoopers LLP
(PW*Sequel), and for certain E&P operations, Applied Terravision Systems Inc.
(Artesia) and EFA Software Services Ltd. (PRISM). Certain Company-developed
business software systems that will not be replaced with compliant vendor
systems by the Year 2000 are being 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.
PROJECT
The Company has established an Enterprise Project Office (EPO) and has engaged
KPMG Peat Marwick 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 Company-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) as necessary,
designing and implementing contingency and business continuation plans.
Material items are those 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. At September 30, 1998,
the inventorying and priority assessment phases of the Project had been
completed. 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.
11
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS (CONTD.)
OTHER MATTERS (CONTD.)
YEAR 2000 ISSUES (CONTD.)
A fourth major component of the Project, which involves the review of third
party suppliers, customers and business partners (Third Parties), 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.
Detailed evaluations of the most critical Third Parties began in the second
quarter of 1998 and are scheduled for completion by mid-1999, with follow-up
reviews scheduled for the remainder of 1999. The Company estimates that this
component was on schedule at September 30, 1998. Based on the results of
evaluations and other available information, contingency plans will be
developed as necessary during 1999 to address any anticipated Year 2000
problems related to critical Third Parties.
A Year 2000 compliant version of Edwards is fully implemented in the United
States and is approximately 50 percent complete in the United Kingdom, with
most remaining phases of the U.K. implementation scheduled for the first
quarter of 1999. Year 2000 testing of Artesia, including any required
corrections, is scheduled for the fourth quarter of 1998. In Canada, the
Company expects to have upgraded and tested Year 2000 compliant versions of
PW*Sequel and PRISM by the first quarter of 1999. Testing of U.S. offshore
production platform systems has been delayed somewhat due to storm-related
downtime during the third quarter of 1998; testing is now scheduled to be
completed in early 1999. Certain Company-developed downstream accounting,
customer invoicing and human resources systems in the United States are being
remedied to be Year 2000 compliant; this effort was estimated to be 80 percent
complete at September 30, 1998, and is projected to be completed by year-end
1998. U.S. refining and marketing systems testing is somewhat behind schedule
due to a recent implementation of a new refinery maintenance system at the
Meraux refinery; certain testing will be completed at the refinery during a
scheduled turnaround in the first quarter of 1999. Other refining and
marketing business systems that require release of compliant vendor upgrades
are scheduled to be completed near the end of the first quarter of 1999.
PROJECT SUMMARY
At September 30, 1998, the Company-wide Project is estimated to be 40 percent
complete. Thus far, no material noncompliant Year 2000 issues have been
discovered that were not identified in the completed Year 2000 inventory. The
material components of the Project are expected to be substantially complete
by early 1999.
At September 30, 1998, formal contingency plans for the Project had not been
developed. The Company does not expect to develop formal contingency plans
for Project issues that are resolved in accordance with the current schedule.
Any unresolved issues that fall significantly behind schedule or that lead to
a material risk of system failure will be addressed by contingency plans
during 1999.
COSTS
The total cost of required modifications to become Year 2000 compliant is not
expected to be material to Murphy's financial position. The most likely
estimate of the total cost of the Project is approximately $5 million,
including $2 million for the EPO (including assessment of Third Parties), $1
million for miscellaneous hardware replacement, $1 million for noncompliant
system renovation/upgrades and $.6 million for 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 obtained from internally
generated cash flows. This 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. The operator of the Company's
jointly owned U.K. refinery has estimated Murphy's costs to be $.5 million to
achieve Year 2000 compliance. The cost of implementing Edwards in the United
Kingdom, now estimated to be $.9 million, is also not included in the Project
cost estimate.
The total amount expended on the Project through September 30, 1998, and
recorded in selling and general expense in 1998 was $1.3 million, essentially
all of which related to the EPO. The cost of completing the Year 2000 Project
is estimated to be approximately $3.7 million.
12
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS (CONTD.)
OTHER MATTERS (CONTD.)
YEAR 2000 ISSUES (CONTD.)
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. 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 under the
heading "Forward-Looking Statements" below.
FORWARD-LOOKING STATEMENTS
This quarterly report on Form 10-Q includes 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.
13
<PAGE>
<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
SEPTEMBER 30, 1998
Oil and gas sales and
operating revenues $ 35.7 22.1 23.6 4.1 .7 12.7 98.9
Production costs 12.3 8.1 9.5 1.6 - 8.8 40.3
Depreciation, depletion
and amortization 15.5 10.3 11.2 2.4 - 1.5 40.9
Exploration expenses
Dry hole costs .4 1.0 - - - - 1.4
Geological and geophysical
costs .1 .7 .2 - 2.7 - 3.7
Other costs .8 .3 .4 - .3 - 1.8
- -----------------------------------------------------------------------------
1.3 2.0 .6 - 3.0 - 6.9
Undeveloped lease
amortization 1.7 .8 .1 - - - 2.6
- -----------------------------------------------------------------------------
Total exploration
expenses 3.0 2.8 .7 - 3.0 - 9.5
- -----------------------------------------------------------------------------
Selling and general expenses 3.8 1.3 1.1 - .3 .1 6.6
Income tax provisions
(benefits) .2 (.5) 1.4 - .1 .7 1.9
- -----------------------------------------------------------------------------
Results of operations
(excluding corporate
overhead and interest) $ .9 .1 (.3) .1 (2.7) 1.6 (.3)
=============================================================================
THREE MONTHS ENDED
SEPTEMBER 30, 1997
Oil and gas sales and
operating revenues $ 66.1 26.3 30.5 9.3 .2 18.4 150.8
Production costs 11.8 9.8 6.9 2.8 - 10.1 41.4
Depreciation, depletion and
amortization 22.2 8.2 11.9 2.9 - 1.8 47.0
Exploration expenses
Dry hole costs 1.9 .6 4.4 - .8 - 7.7
Geological and geophysical
costs 3.1 1.0 1.2 - 1.6 - 6.9
Other costs .6 .3 .4 - 1.1 - 2.4
- -----------------------------------------------------------------------------
5.6 1.9 6.0 - 3.5 - 17.0
Undeveloped lease
amortization 1.6 1.0 - - .1 - 2.7
- -----------------------------------------------------------------------------
Total exploration
expenses 7.2 2.9 6.0 - 3.6 - 19.7
- -----------------------------------------------------------------------------
Selling and general expenses 4.0 1.3 .7 .1 .6 .1 6.8
Income tax provisions
(benefits) 7.4 1.7 3.2 .4 (.3) 2.4 14.8
- -----------------------------------------------------------------------------
Results of operations
(excluding corporate
overhead and interest) $ 13.5 2.4 1.8 3.1 (3.7) 4.0 21.1
=============================================================================
NINE MONTHS ENDED
SEPTEMBER 30, 1998
Oil and gas sales and
operating revenues $139.0 57.6 65.8 14.5 1.9 40.2 319.0
Production costs 32.0 25.8 25.1 5.1 - 25.7 113.7
Depreciation, depletion and
amortization 50.9 26.7 30.1 7.4 - 4.7 119.8
Exploration expenses
Dry hole costs 11.4 4.2 - - 8.3 - 23.9
Geological and geophysical
costs 2.4 3.6 2.8 - 3.7 - 12.5
Other costs 1.7 .6 1.4 - 1.4 - 5.1
- -----------------------------------------------------------------------------
15.5 8.4 4.2 - 13.4 - 41.5
Undeveloped lease
amortization 4.9 3.0 .1 - - - 8.0
- -----------------------------------------------------------------------------
Total exploration
expenses 20.4 11.4 4.3 - 13.4 - 49.5
- -----------------------------------------------------------------------------
Selling and general expenses 11.9 4.5 2.8 .1 1.1 .1 20.5
Income tax provisions
(benefits) 8.0 (6.2) 5.0 (.8) (.1) 3.1 9.0
- -----------------------------------------------------------------------------
Results of operations
(excluding corporate
overhead and interest) $ 15.8 (4.6) (1.5) 2.7 (12.5) 6.6 6.5
=============================================================================
NINE MONTHS ENDED
SEPTEMBER 30, 1997
Oil and gas sales and
operating revenues $196.7 74.0 90.7 26.1 1.3 49.2 438.0
Production costs 33.5 28.0 25.0 8.4 - 28.2 123.1
Depreciation, depletion
and amortization 59.4 22.7 33.5 8.3 - 4.8 128.7
Exploration expenses
Dry hole costs 25.5 3.1 5.0 - 3.3 - 36.9
Geological and geophysical
costs 8.6 5.6 1.4 - 4.4 - 20.0
Other costs 1.7 .6 1.5 - 3.0 - 6.8
- -----------------------------------------------------------------------------
35.8 9.3 7.9 - 10.7 - 63.7
Undeveloped lease
amortization 5.0 2.7 - - .1 - 7.8
- -----------------------------------------------------------------------------
Total exploration
expenses 40.8 12.0 7.9 - 10.8 - 71.5
- -----------------------------------------------------------------------------
Selling and general expenses 10.6 3.9 1.8 .3 1.5 .1 18.2
Income tax provisions
(benefits) 18.0 2.0 12.4 .7 (.1) 6.0 39.0
- -----------------------------------------------------------------------------
Results of operations
(excluding corporate
overhead and interest) $ 34.4 5.4 10.1 8.4 (10.9) 10.1 57.5
=============================================================================
*Excludes special items.
</TABLE>
14
<PAGE>
PART II - OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
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 material as defined by the rules and
regulations of the U.S. Securities and Exchange Commission.
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
(a) The Exhibit Index on page 16 of this Form 10-Q report lists the
exhibits that are hereby filed or incorporated by reference.
(b) No reports on Form 8-K have been filed for the quarter covered by
this report.
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)
November 12, 1998
(Date)
15
<PAGE>
EXHIBIT INDEX
Exhibit Page Number or
No. Incorporation by Reference to
- ------- -----------------------------
3.1 Certificate of Incorporation of Exhibit 3.1, Page Ex 3.1-1,
Murphy Oil Corporation as of of Murphy's Annual Report on
September 25, 1986 Form 10-K for the year ended
December 31, 1996
3.2 Bylaws of Murphy Oil Corporation Exhibit 3.2, Page Ex. 3.2-1,
at January 24, 1996 of Murphy's Annual Report on
Form 10-K for the year ended
December 31, 1997
4 Instruments Defining the Rights of
Security Holders. Murphy is party
to several long-term debt instruments
in addition to the one in Exhibit 4.1,
none of which authorizes securities
exceeding 10 percent of the total
consolidated assets of Murphy and its
subsidiaries. Pursuant to Regulation
S-K, item 601(b), paragraph 4(iii)(A),
Murphy agrees to furnish a copy of each
such instrument to the Securities and
Exchange Commission upon request.
4.1 Credit Agreement among Murphy Oil Exhibit 4.1, Page Ex. 4.1-0,
Corporation and certain subsidiaries of Murphy's Annual Report on
and the Chase Manhattan Bank et al as Form 10-K for the year ended
of November 13, 1997 December 31, 1997
4.2 Rights Agreement dated as of Exhibit 4.1, Page Ex. 4.1-0,
December 6, 1989, between Murphy Oil of Murphy's Annual Report on
Corporation and Harris Trust Company Form 10-K for the year ended
of New York, as Rights Agent December 31, 1994
4.3 Amendment No. 1 dated as of April 6, Exhibit 3 of Murphy's Form
1998, to Rights Agreement dated as of 8-A/A, Amendment No. 1, filed
December 6, 1989, between Murphy Oil April 14, 1998, under the
Corporation and Harris Trust Company Securities Exchange Act of
of New York, as Rights Agent 1934
10.1 1987 Management Incentive Plan as Exhibit 10.2, Page Ex. 10.2-0,
amended February 7, 1990, retroactive of Murphy's Annual Report on
to February 3, 1988 Form 10-K for the year ended
December 31, 1994
10.2 1992 Stock Incentive Plan as amended Exhibit 10.2, Page Ex. 10.2-1,
May 14, 1997 of Murphy's Report on Form
10-Q 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 Only in electronic filing
nine months ended September 30, 1998
Exhibits other than those listed above have been omitted since they are either
not required or not applicable.
16
<TABLE> <S> <C>
<ARTICLE> 5
<LEGEND>
THIS FINANCIAL DATA SCHEDULE CONTAINS SUMMARY UNAUDITED FINANCIAL INFORMATION
EXTRACTED FROM THE CONSOLIDATED BALANCE SHEET AT SEPTEMBER 30, 1998, AND THE
CONSOLIDATED STATEMENT OF INCOME FOR THE NINE MONTHS THEN ENDED OF MURPHY OIL
CORPORATION AND CONSOLIDATED SUBSIDIARIES AND IS QUALIFIED IN ITS ENTIRETY BY
REFERENCE TO SUCH FINANCIAL STATEMENTS.
</LEGEND>
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 9-MOS
<FISCAL-YEAR-END> DEC-31-1998
<PERIOD-END> SEP-30-1998
<CASH> 28,879
<SECURITIES> 0
<RECEIVABLES> 255,016
<ALLOWANCES> 12,069
<INVENTORY> 147,555
<CURRENT-ASSETS> 469,684
<PP&E> 4,609,689
<DEPRECIATION> 2,882,789
<TOTAL-ASSETS> 2,260,630
<CURRENT-LIABILITIES> 435,435
<BONDS> 268,069
0
0
<COMMON> 48,775
<OTHER-SE> 1,014,348
<TOTAL-LIABILITY-AND-EQUITY> 2,260,630
<SALES> 1,265,626
<TOTAL-REVENUES> 1,322,615
<CGS> 1,140,803
<TOTAL-COSTS> 1,140,803
<OTHER-EXPENSES> 49,527
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 6,199
<INCOME-PRETAX> 77,055
<INCOME-TAX> 30,300
<INCOME-CONTINUING> 46,755
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 46,755
<EPS-PRIMARY> 1.04
<EPS-DILUTED> 1.04
</TABLE>
