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, 1996
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 1-3473
TESORO PETROLEUM CORPORATION
(Exact Name of Registrant as Specified in Its Charter)
Delaware 95-0862768
(State or Other Jurisdiction of (I.R.S. Employer
Incorporation or Organization) Identification No.)
8700 Tesoro Drive, San Antonio, Texas 78217-6218
(Address of Principal Executive Offices) (Zip Code)
210-828-8484
(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.
Yes X No _____
There were 26,409,961 shares of the Registrant's Common Stock outstanding at
October 31, 1996.
TESORO PETROLEUM CORPORATION AND SUBSIDIARIES
INDEX TO FORM 10-Q
FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 1996
PART I. FINANCIAL INFORMATION Page
Item 1. Financial Statements (Unaudited)
Condensed Consolidated Balance Sheets -
September 30, 1996 and December 31, 1995 . . . . . . . . . . . . . . 3
Condensed Statements of Consolidated Operations -
Three Months and Nine Months Ended September 30, 1996 and 1995 . . . 4
Condensed Statements of Consolidated Cash Flows -
Nine Months Ended September 30, 1996 and 1995 . . . . . . . . . . . . 5
Notes to Condensed Consolidated Financial Statements . . . . . . . . . 6
Item 2. Management's Discussion and Analysis of
Financial Condition and Results of Operations . . . . . . . . . . . . . 10
PART II. OTHER INFORMATION
Item 1. Legal Proceedings . . . . . . . . . . . . . . . . . . . . . . . 21
Item 2. Changes in Securities . . . . . . . . . . . . . . . . . . . . . 21
Item 6. Exhibits and Reports on Form 8-K. . . . . . . . . . . . . . . . 22
SIGNATURES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23
2
PART I - FINANCIAL INFORMATION
Item 1. Financial Statements
TESORO PETROLEUM CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
(Dollars in thousands except per share amounts)
September 30, December 31,
1996 1995*
---- ----
ASSETS
CURRENT ASSETS:
Cash and cash equivalents . . . . . . . . . . . . $ 103,572 13,941
Receivables, less allowance for doubtful
accounts of $1,990 ($1,842 at
December 31, 1995) . . . . . . . . . . . . . . . 91,700 77,534
Inventories:
Crude oil and wholesale refined products,
at LIFO . . . . . . . . . . . . . . . . . . . . 51,988 70,406
Merchandise and refined products . . . . . . . . 8,400 5,153
Materials and supplies . . . . . . . . . . . . . 4,409 4,894
Prepayments and other . . . . . . . . . . . . . . 8,597 10,536
------- -------
Total Current Assets . . . . . . . . . . . . . . 268,666 182,464
------- -------
PROPERTY, PLANT AND EQUIPMENT:
Refining and marketing. . . . . . . . . . . . . . 328,421 322,023
Exploration and production:
Oil and gas (full cost method of accounting) . . 157,971 124,954
Gas transportation . . . . . . . . . . . . . . . 6,703 6,703
Marine services . . . . . . . . . . . . . . . . . 33,199 12,757
Corporate . . . . . . . . . . . . . . . . . . . . 12,315 12,443
------- -------
538,609 478,880
Less accumulated depreciation, depletion
and amortization. . . . . . . . . . . . . . . . 248,238 217,191
------- -------
Net Property, Plant and Equipment . . . . . . 290,371 261,689
------- -------
RECEIVABLE FROM TENNESSEE GAS PIPELINE COMPANY
(Note 4) . . . . . . . . . . . . . . . . . . . . . - 50,680
OTHER ASSETS. . . . . . . . . . . . . . . . . . . . 28,069 24,320
------- -------
TOTAL ASSETS. . . . . . . . . . . . . . . . . $ 587,106 519,153
======= =======
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES:
Accounts payable. . . . . . . . . . . . . . . . . $ 69,946 61,389
Accrued liabilities . . . . . . . . . . . . . . . 37,550 34,073
Current portion of long-term debt and other
obligations. . . . . . . . . . . . . . . . . . . 83,513 9,473
------- -------
Total Current Liabilities. . . . . . . . . . . . 191,009 104,935
------- -------
DEFERRED INCOME TAXES . . . . . . . . . . . . . . . 16,554 5,389
------- -------
OTHER LIABILITIES . . . . . . . . . . . . . . . . . 38,302 37,308
------- -------
LONG-TERM DEBT AND OTHER OBLIGATIONS, LESS
CURRENT PORTION . . . . . . . . . . . . . . . . . 80,020 155,007
------- -------
COMMITMENTS AND CONTINGENCIES (Note 5)
STOCKHOLDERS' EQUITY:
Common Stock, par value $.16-2/3; authorized
50,000,000 shares; 26,399,371 shares issued
and outstanding (24,780,134 in 1995) . . . . . . 4,398 4,130
Additional paid-in capital. . . . . . . . . . . . 189,185 176,599
Retained earnings . . . . . . . . . . . . . . . . 67,638 35,785
------- -------
Total Stockholders' Equity . . . . . . . . . . . 261,221 216,514
------- -------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY. . $ 587,106 519,153
======= =======
The accompanying notes are an integral part of these condensed consolidated
financial statements.
* The balance sheet at December 31, 1995 has been taken from the audited
consolidated financial statements at that date and condensed.
3
TESORO PETROLEUM CORPORATION AND SUBSIDIARIES
CONDENSED STATEMENTS OF CONSOLIDATED OPERATIONS
(Unaudited)
(In thousands except per share amounts)
Three Months Ended Nine Months Ended
September 30, September 30,
------------------ -----------------
1996 1995 1996 1995
---- ---- ---- ----
REVENUES:
Refining and marketing. . . . . . . . $ 203,661 196,086 563,767 588,735
Exploration and production. . . . . . 26,476 29,626 83,933 96,747
Marine services . . . . . . . . . . . 32,660 18,467 87,467 56,848
Gain (loss) on sale of assets
and other income. . . . . . . . . . (725) 33,144 4,378 33,166
------- ------- ------- -------
Total Revenues . . . . . . . . . 262,072 277,323 739,545 775,496
------- ------- ------- -------
OPERATING COSTS AND EXPENSES:
Refining and marketing. . . . . . . . 194,156 190,463 545,303 584,418
Exploration and production. . . . . . 2,416 5,256 8,767 15,053
Marine services . . . . . . . . . . . 30,273 18,654 82,153 58,685
Depreciation, depletion and
amortization . . . . . . . . . . . . 10,026 9,175 29,797 32,016
------- ------- ------- -------
Total Operating Costs and Expenses. 236,871 223,548 666,020 690,172
------- ------- ------- -------
OPERATING PROFIT . . . . . . . . . . . 25,201 53,775 73,525 85,324
General and Administrative . . . . . . (3,056) (4,372) (8,960) (12,371)
Interest Expense . . . . . . . . . . . (4,142) (5,471) (12,142) (16,132)
Interest Income. . . . . . . . . . . . 7,100 192 7,681 616
Other Expense, Net . . . . . . . . . . (1,254) (5,678) (8,802) (7,642)
------- ------- ------- -------
EARNINGS BEFORE INCOME TAXES AND
EXTRAORDINARY LOSS. . . . . . . . . . 23,849 38,446 51,302 49,795
Income Tax Provision . . . . . . . . . 7,686 1,664 17,159 3,797
------- ------- ------- -------
EARNINGS BEFORE EXTRAORDINARY LOSS . . 16,163 36,782 34,143 45,998
Extraordinary Loss on Extinguishment
of Debt, Net of Income Tax Benefit
of $886. . . . . . . . . . . . . . . (2,290) - (2,290) -
------- ------- ------- -------
NET EARNINGS . . . . . . . . . . . . . $ 13,873 36,782 31,853 45,998
======= ======= ======= =======
EARNINGS PER SHARE:
Earnings Before Extraordinary Loss. . $ .61 1.47 1.30 1.83
Extraordinary Loss, Net of Income
Tax Benefit. . . . . . . . . . . . . (.09) - (.09) -
------- ------- ------- -------
Net Earnings . . . . . . . . . . . . $ .52 1.47 1.21 1.83
======= ======= ======= =======
WEIGHTED AVERAGE COMMON AND
COMMON EQUIVALENT SHARES. . . . . . . 26,816 25,093 26,370 25,140
======= ======= ======= =======
The accompanying notes are an integral part of these condensed consolidated
financial statements.
4
TESORO PETROLEUM CORPORATION AND SUBSIDIARIES
CONDENSED STATEMENTS OF CONSOLIDATED CASH FLOWS
(Unaudited)
(In thousands)
Nine Months Ended
September 30,
-----------------
1996 1995
---- ----
CASH FLOWS FROM (USED IN) OPERATING ACTIVITIES:
Net earnings . . . . . . . . . . . . . . . . . . . . . . $ 31,853 45,998
Adjustments to reconcile net earnings to net
cash from operating activities:
Extraordinary loss on extinguishment of debt,
net of income tax benefit . . . . . . . . . . . . . . 2,290 -
Depreciation, depletion and amortization . . . . . . . 30,386 32,763
Loss (gain) on sale of assets. . . . . . . . . . . . . 678 (33,055)
Amortization of deferred charges and other . . . . . . 1,316 1,311
Changes in operating assets and liabilities:
Receivable from Tennessee Gas Pipeline Company . . . 50,680 (29,465)
Receivables, other trade . . . . . . . . . . . . . . (6,228) 9,916
Inventories. . . . . . . . . . . . . . . . . . . . . 16,901 6,006
Other assets . . . . . . . . . . . . . . . . . . . . 793 (4,434)
Accounts payable and other current liabilities . . . 8,066 (349)
Obligation payments to State of Alaska . . . . . . . (3,145) (2,129)
Deferred income taxes. . . . . . . . . . . . . . . . 12,051 611
Other liabilities and obligations. . . . . . . . . . 2,760 3,108
------- -------
Net cash from operating activities . . . . . . . . 148,401 30,281
------- -------
CASH FLOWS FROM (USED IN) INVESTING ACTIVITIES:
Capital expenditures . . . . . . . . . . . . . . . . . . (46,050) (48,881)
Acquisition of Coastwide Energy Services, Inc. . . . . . (7,720) -
Proceeds from sale of assets . . . . . . . . . . . . . . 1,079 69,711
Other. . . . . . . . . . . . . . . . . . . . . . . . . . (4,338) (3,201)
------- -------
Net cash from (used in) investing activities . . . . (57,029) 17,629
------- -------
CASH FLOWS FROM (USED IN) FINANCING ACTIVITIES:
Borrowings, net of repayments of $112,000 in 1996
and $262,500 in 1995, under revolving credit
facilities. . . . . . . . . . . . . . . . . . . . . . . - -
Payments of long-term debt . . . . . . . . . . . . . . . (2,885) (2,262)
Other. . . . . . . . . . . . . . . . . . . . . . . . . . 1,144 (296)
------- -------
Net cash used in financing activities. . . . . . . . (1,741) (2,558)
------- -------
INCREASE IN CASH AND CASH EQUIVALENTS. . . . . . . . . . . 89,631 45,352
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD . . . . . 13,941 14,018
------- -------
CASH AND CASH EQUIVALENTS AT END OF PERIOD . . . . . . . . $ 103,572 59,370
======= =======
SUPPLEMENTAL CASH FLOW DISCLOSURES:
Interest paid. . . . . . . . . . . . . . . . . . . . . . $ 8,879 13,600
======= =======
Income taxes paid. . . . . . . . . . . . . . . . . . . . $ 3,925 3,262
======= =======
The accompanying notes are an integral part of these condensed consolidated
financial statements.
5
TESORO PETROLEUM CORPORATION AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
NOTE 1 - BASIS OF PRESENTATION
The interim condensed consolidated financial statements of Tesoro Petroleum
Corporation and its subsidiaries (collectively, the "Company" or "Tesoro") have
been prepared by management without audit pursuant to the rules and regulations
of the Securities and Exchange Commission ("SEC"). Accordingly, the
accompanying financial statements reflect all adjustments that, in the opinion
of management, are necessary for a fair presentation of results for the periods
presented. Such adjustments are of a normal recurring nature. Certain
information and notes normally included in financial statements prepared in
accordance with generally accepted accounting principles have been condensed or
omitted pursuant to the SEC's rules and regulations. However, management
believes that the disclosures presented herein are adequate to make the
information not misleading. The accompanying condensed consolidated financial
statements should be read in conjunction with the consolidated financial
statements and notes thereto contained in the Company's Annual Report on Form
10-K for the year ended December 31, 1995.
The preparation of these condensed consolidated financial statements required
the use of management's best estimates and judgment that affect the reported
amounts of assets and liabilities and disclosures of contingent assets and
liabilities at the date of the financial statements and the reported amounts of
revenues and expenses during the periods. Actual results could differ from
those estimates. The results of operations for any interim period are not
necessarily indicative of results for the full year. Certain reclassifications
have been made to amounts previously reported for the interim periods of 1995 to
conform to the current presentation of financial information.
NOTE 2 - ACQUISITION
In February 1996, the Company purchased 100% of the capital stock of Coastwide
Energy Services, Inc. ("Coastwide"). The consideration for the stock of
Coastwide included approximately 1.4 million shares of Tesoro's Common Stock and
$7.7 million in cash. The market price of Tesoro's Common Stock was $9.00 per
share at closing of this transaction. In addition, upon closing, Tesoro repaid
approximately $4.5 million of Coastwide's outstanding debt. Coastwide is
primarily a provider of services and a wholesale distributor of diesel fuel and
lubricants to the offshore petroleum industry in the Gulf of Mexico. The
Company has combined its existing marine petroleum products distribution
operations with Coastwide, forming a Marine Services segment. The acquisition
of Coastwide was accounted for as a purchase whereby the purchase price was
allocated to the assets acquired and liabilities assumed based upon their
estimated fair values at the date of acquisition.
NOTE 3 - LONG-TERM DEBT
12-3/4% Subordinated Debentures and 13% Exchange Notes
In September 1996, the Company gave notice to fully redeem its two public debt
issues, totaling approximately $74 million, at a price equal to 100% of the
principal amount, plus accrued interest to the redemption date. The redemption
of the debt, which was comprised of $44.1 million of outstanding 13% Exchange
Notes ("Exchange Notes"), due December 1, 2000, and $30 million of outstanding
12-3/4% Subordinated Debentures ("Subordinated Debentures"), due March 15, 2001,
was completed in November 1996. The redemption was accounted for as an early
extinguishment of debt in the 1996 third quarter, resulting in a pretax charge
of $3.2 million ($2.3 million aftertax) which represented a write-off of
unamortized bond discount and issue costs. At September 30, 1996, the Exchange
Notes and Subordinated Debentures were classified as current liabilities in the
Consolidated Balance Sheet.
Credit Facility
In June 1996, the Company negotiated an amended and restated corporate revolving
credit agreement ("Credit Facility") which provides total commitments of $150
million from a consortium of nine banks. The Credit Facility, which is subject
to a borrowing base, provides for the issuance of letters of credit and cash
borrowings.
6
The Company, at its option, has currently activated $100 million of commitments.
Upon the resolution of the Tennessee Gas litigation and the collection of the
related bonded receivable in the 1996 third quarter (see Note 4), certain
provisions of the Credit Facility were enhanced, including an extension of the
Credit Facility's expiration date to April 30, 2000 and an increase in cash
borrowing availability from $50 million to $100 million.
The Company had outstanding letters of credit of $39 million and no cash
borrowings outstanding at September 30, 1996. Outstanding obligations under the
Credit Facility are secured by liens on substantially all of the Company's trade
accounts receivable and product inventory and by mortgages on the Company's
refinery and South Texas natural gas reserves.
Cash borrowings under the Credit Facility bear interest at the prime rate plus
.50% per annum or the London Interbank Offered Rate ("LIBOR") plus 1.5% per
annum. Fees on outstanding letters of credit under the Credit Facility are 1.5%
per annum. Under the terms of the Credit Facility, the Company is required to
maintain specified levels of consolidated working capital, tangible net worth,
cash flow and interest coverage. Among other matters, the Credit Facility
contains covenants which restrict the incurrence of additional indebtedness and
limit restricted payments. Under the Credit Facility, dividends up to $5
million per year are allowed, subject to the restricted payment covenant. See
"Changes in Securities" in Part II, Item 2, contained herein.
During the nine months ended September 30, 1996, the Company's gross borrowings
and repayments under its revolving credit line totaled $112 million which were
used on a short-term basis to finance working capital requirements and capital
expenditures.
NOTE 4 - GAS PURCHASE AND SALES CONTRACT
The Company is selling a portion of the gas produced from its Bob West Field to
Tennessee Gas Pipeline Company ("Tennessee Gas") under a Gas Purchase and Sales
Agreement ("Contract") which expires in January 1999 and provides that the price
of gas shall be the maximum price as calculated in accordance with Section
102(b)(2) ("Contract Price") of the Natural Gas Policy Act of 1978 ("NGPA"). In
August 1990, Tennessee Gas filed suit against the Company and the other sellers
under the Contract in the District Court of Bexar County, Texas, alleging that
the Contract is not applicable to the Company's properties and that the gas
sales price should be the price calculated under the provisions of Section 101
of the NGPA rather than the Contract Price. Tennessee Gas also claimed that the
Contract should be considered an "output contract" under Section 2.306 of the
Texas Uniform Commercial Code ("UCC") and that the increases in volumes tendered
under the Contract exceeded those allowable for an output contract.
The District Court judge returned a verdict in favor of the Company on all
issues. Tennessee Gas appealed the District Court decision which was reviewed
by the Supreme Court of Texas. On April 18, 1996, the Supreme Court of Texas
issued its decision and affirmed the judgment of the District Court in full.
Tennessee Gas filed a motion for rehearing and on August 16, 1996, the Supreme
Court of Texas issued its mandate denying Tennessee Gas' motion for rehearing
and upholding all aspects of the Contract. Tennessee Gas continues to take its
minimum monthly required amount of gas and resumed paying the Contract Price to
the Company for gas taken beginning with May 1996 volumes. On September 30,
1996, the Company received $67.5 million from Tennessee Gas, which included
collection of a $59.6 million bonded receivable for underpayment for natural gas
sold in prior periods. The remaining $7.9 million of cash received was for
interest and reimbursement of legal fees and court costs, which had not
previously been recorded by the Company resulting in income during the 1996
third quarter. For further information regarding the resolution of the
Tennessee Gas litigation, see "Legal Proceedings" in Part II, Item 1, contained
herein.
7
NOTE 5 - COMMITMENTS AND CONTINGENCIES
Environmental
The Company is subject to extensive federal, state and local environmental laws
and regulations. These laws, which change frequently, regulate the discharge of
materials into the environment and may require the Company to remove or mitigate
the environmental effects of the disposal or release of petroleum or chemical
substances at various sites or install additional controls or other
modifications or changes in use for certain emission sources. The Company is
currently involved with a waste disposal site near Abbeville, Louisiana, at
which it has been named a potentially responsible party under the Federal
Superfund law. Although this law might impose joint and several liability upon
each party at each site, the extent of the Company's allocated financial
contributions to the cleanup of the site is expected to be limited based upon
the number of companies, volumes of waste involved and an estimated total cost
of approximately $500,000 among all of the parties to close the site. The
Company is currently involved in settlement discussions with the Environmental
Protection Agency ("EPA") and other potentially responsible parties at the
Abbeville, Louisiana site. The Company expects, based on these discussions,
that its liability at the site will not exceed $25,000. The Company is also
involved in remedial responses and has incurred cleanup expenditures associated
with environmental matters at a number of sites, including certain of its own
properties.
At September 30, 1996, the Company's accruals for environmental matters amounted
to $9.3 million, which included a noncurrent liability of approximately $4
million for remediation of Kenai Pipe Line Company's ("KPL") properties that has
been funded by the former owners of KPL through a restricted escrow deposit.
Based on currently available information, including the participation of other
parties or former owners in remediation actions, the Company believes these
accruals are adequate. In addition, to comply with environmental laws and
regulations, the Company anticipates that it will make capital improvements in
1996 and 1997 totaling approximately $2.3 million, primarily for upgrading of
underground storage tanks. Environmental regulations would also have required
the Company to make capital improvements starting in 1996 of approximately $9.5
million for the installation of dike liners. However, on April 18, 1996 the
Alaska Department of Environmental Conservation ("ADEC") issued a memorandum
stating that alternative compliance schedules allowing for delayed
implementation of the requirements for dike liners in secondary containment
systems for existing petroleum storage tanks would be approved. The April 18,
1996 ADEC Memorandum recognizes that secondary containment options other than
synthetic dike liners are appropriate, but essential ADEC guidelines addressing
other options will not be available before the end of 1996. The ADEC believes
it will be three to five years before all affected facilities fully implement
the provisions of the regulations. The Company is currently negotiating for an
alternative compliance schedule with ADEC to maintain the Company's existing
storage tank facilities in compliance with the state regulations. The Company
cannot presently determine when an alternative schedule will be granted.
Conditions that require additional expenditures may exist for various Company
sites, including, but not limited to, the Company's refinery, retail gasoline
outlets (current and closed locations) and petroleum product terminals, and for
compliance with the Clean Air Act. The amount of such future expenditures cannot
currently be determined by the Company.
Incentive Compensation Strategy
In June 1996, the Company's Board of Directors unanimously approved an incentive
compensation strategy in order to encourage a longer-term focus for all
employees to perform at an outstanding level. The strategy provides eligible
employees with incentives to achieve a significant increase in the market price
of the Company's Common Stock. Under the strategy, awards would be earned only
if the market price of the Company's Common Stock reaches an average price per
share of $20 or higher over any 20 consecutive trading days after June 30, 1997
and before December 31, 1998 (the "Performance Target"). In connection with
this strategy, non-executive employees will be able to earn cash bonuses equal
to 25% of their individual payroll amounts for the previous 12 complete months
and certain executives have been granted, from the Company's Executive Long-Term
8
Incentive Plan ("Plan"), a total of 340,000 stock options at an exercise price
of $11.375 per share, the fair market value (as defined in the Plan) of a share
of the Company's Common Stock on the date of grant, and 350,000 shares of
restricted Common Stock, all of which vest only upon achieving the Performance
Target.
NOTE 6 - SEVERANCE TAX EXEMPTION
In February 1996, the Texas Railroad Commission certified substantially all of
the Company's proved producing reserves in the Bob West Field as high-cost gas
from a designated tight formation. As a result of the Railroad Commission's
certification, the Texas Comptroller's office has issued certificates for the
majority of these wells, indicating that the wells have been classified as
high-cost gas wells that are exempt from state severance taxes from the date of
first production through August 2001. During the first quarter of 1996, based
on approved severance tax exemption certificates received to date by the Company
from the Texas Comptroller's office, the Company recorded $5 million of income
for retroactive refunds. These exemptions also had the effect of increasing the
pretax present value of the Company's 1995 year-end U.S. proved reserves by $7.7
million to $176.4 million. Severance tax expense will not be recorded for
current production from exempt wells during 1996.
9
Item 2. TESORO PETROLEUM CORPORATION AND SUBSIDIARIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONNDITION AND RESULTS OF OPERATIONS
RESULTS OF OPERATIONS
Summary
Net earnings of $13.9 million, or $.52 per share, for the three months ended
September 30, 1996 ("1996 quarter") compare with net earnings of $36.8 million,
or $1.47 per share, for the three months ended September 30, 1995 ("1995
quarter"). For the year-to-date period, net earnings of $31.9 million ($1.21
per share) for the nine months ended September 30, 1996 ("1996 period") compare
with net earnings of $46.0 million ($1.83 per share) for the nine months ended
September 30, 1995 ("1995 period"). A non-cash extraordinary loss of $3.2
million pretax, or $2.3 million after tax ($.09 per share), for early redemption
of the Company's 13% Exchange Notes ("Exchange Notes") and 12-3/4% Subordinated
Debentures ("Subordinated Debentures") was included in the 1996 quarter and
period. Earnings before the extraordinary loss amounted to $16.2 million ($.61
per share) for the 1996 quarter and $34.2 million ($1.30 per share) for the 1996
period. Comparability between the results for 1996 and 1995 was further
impacted by significant transactions which are highlighted in the table below
(in millions):
Three Months Ended Nine Months Ended
September 30, September 30,
------------------ -----------------
1996 1995 1996 1995
---- ---- ---- ----
Net Earnings Excluding Significant Items . . $ 11.0 6.7 30.5 13.0
---- ---- ---- ----
Significant Items Affecting Comparability:
Interest and reimbursement of fees
and costs from Tennessee Gas . . . . . . 7.9 - 7.9 -
Gain (loss) on sale of assets. . . . . . . (.7) 33.5 (.7) 33.5
Operating profit from Bob West Field
interests sold in 1995 . . . . . . . . . - 1.3 - 4.2
Employee terminations and restructuring
costs. . . . . . . . . . . . . . . . . . - (4.7) (2.6) (4.7)
Retroactive severance tax refund . . . . . - - 5.0 -
Costs of shareholder consent
solicitation resolved in April 1996 . . . - - (2.3) -
Other. . . . . . . . . . . . . . . . . . . - - (2.1) -
---- ---- ---- ----
Total Significant Items, Pretax. . . . . 7.2 30.1 5.2 33.0
Income Tax Effect. . . . . . . . . . . . 2.0 - 1.5 -
---- ---- ---- ----
Total Significant Items, Aftertax. . . . 5.2 30.1 3.7 33.0
---- ---- ---- ----
Earnings Before Extraordinary Item . . . . . 16.2 36.8 34.2 46.0
Extraordinary Loss on Debt Extinguishment,
Net . . . . . . . . . . . . . . . . . . . (2.3) - (2.3) -
---- ---- ---- ----
Net Earnings as Reported . . . . . . . . . $ 13.9 36.8 31.9 46.0
==== ==== ==== ====
As shown above, excluding significant items, the Company's net earnings would
have been $11.0 million ($.41 per share) in the 1996 quarter, compared to $6.7
million ($.27 per share) in the 1995 quarter, and $30.5 million ($1.16 per
share) for the 1996 period, compared to $13.0 million ($.52 per share) for the
1995 period. The resulting increase in net earnings in the 1996 quarter and
period was primarily attributable to improvements within the Company's Refining
and Marketing and Marine Services segments, each of which reported significant
profit improvements from the comparable prior year periods. Additionally, at
the corporate level, initiatives during the past twelve months helped reduce
general and administrative expenses and interest expense. These improvements
were partially offset by an increase in the Company's total effective rate in
1996 as earnings subject to U.S. taxes exceeded available net operating loss and
tax credit carryforwards.
10
Refining and Marketing Three Months Ended Nine Months Ended
- ---------------------- September 30, September 30,
------------------ -----------------
(Dollars in millions except per unit 1996 1995 1996 1995
amounts) ---- ---- ---- ----
Gross Operating Revenues:
Refined products . . . . . . . . . . . $ 169.9 176.3 465.7 499.6
Other, primarily crude oil resales and
merchandise. . . . . . . . . . . . . 33.8 19.8 98.1 89.1
------ ------ ------ ------
Gross Operating Revenues. . . . . . . $ 203.7 196.1 563.8 588.7
====== ====== ====== ======
Operating Profit (Loss):
Gross margin - refined products. . . . $ 27.8 23.2 75.4 57.2
Gross margin - other . . . . . . . . . 3.9 3.7 10.1 9.3
------ ------ ------ ------
Gross margin. . . . . . . . . . . . . 31.7 26.9 85.5 66.5
Operating expenses . . . . . . . . . . 22.3 21.3 67.1 62.0
Depreciation and amortization. . . . . 3.0 2.8 9.0 8.8
Loss on sale of assets and other . . . (.7) - (.7) (.2)
------ ------ ------ ------
Operating Profit (Loss) . . . . . . . $ 5.7 2.8 8.7 (4.5)
====== ====== ====== ======
Capital Expenditures . . . . . . . . . . $ 3.1 1.9 6.9 7.2
====== ====== ====== ======
Refinery Operations - Throughput (average
daily barrels) . . . . . . . . . . . . 41,165 56,504 45,760 50,056
====== ====== ====== ======
Refinery Operations - Production (average
daily barrels):
Gasoline . . . . . . . . . . . . . . . 11,007 16,221 12,742 14,269
Middle distillates and other . . . . . 18,782 25,626 21,438 22,927
Heavy oils and residual product. . . . 12,706 16,025 13,218 14,278
------ ------ ------ ------
Total Refinery Production . . . . . . 42,495 57,872 47,398 51,474
====== ====== ====== ======
Refinery Operations - Product Spread
($/barrel)*:
Average yield value of products
manufactured. . . . . . . . . . . . . $ 24.81 20.07 23.95 20.16
Cost of raw materials. . . . . . . . . 19.43 16.81 18.91 17.13
------ ------ ------ ------
Refinery Product Spread . . . . . . . $ 5.38 3.26 5.04 3.03
====== ====== ====== ======
Refining and Marketing - Total Product
Sales (average daily barrels):
Gasoline . . . . . . . . . . . . . . . 18,073 26,330 18,751 25,562
Middle distillates . . . . . . . . . . 32,123 38,925 30,159 38,292
Heavy oils and residual product. . . . 16,489 16,009 14,594 14,468
------ ------ ------ ------
Total Product Sales . . . . . . . . . 66,685 81,264 63,504 78,322
====== ====== ====== ======
Refining and Marketing - Total Product
Sales Prices ($/barrel):
Gasoline . . . . . . . . . . . . . . . $ 34.52 28.53 32.35 28.10
Middle distillates . . . . . . . . . . $ 29.33 24.07 28.08 24.08
Heavy oils and residual product. . . . $ 17.03 14.09 16.86 13.09
Refining and Marketing - Gross Margins
on Total Product Sales
($/barrel)*:
Average sales price. . . . . . . . . . $ 27.70 23.55 26.76 23.37
Average costs of sales . . . . . . . . 23.16 20.46 22.43 20.69
------ ------ ------ ------
Gross margin . . . . . . . . . . . . $ 4.54 3.09 4.33 2.68
====== ====== ====== ======
* The refinery product spread presented above represents the excess of yield
value of the products manufactured at the refinery over the cost of raw
materials used to manufacture such products. Sources of total product sales
include products manufactured at the refinery, existing inventory balances and
products purchased from third parties. Margins on sales of purchased
products, together with the effect of changes in inventories, are included in
the gross margin on total product sales presented above. The Company's
purchases of refined products for resale approximated 13,600 and 26,800
average daily barrels for the three months ended September 30, 1996 and 1995,
respectively, and 12,100 and 26,900 average daily barrels for the nine months
ended September 30, 1996 and 1995, respectively.
11
Three Months Ended September 30, 1996 Compared With Three Months Ended
September 30, 1995. Results from the Company's Refining and Marketing segment
improved during the 1996 quarter with operating profit of $5.7 million, as
compared to operating profit of $2.8 million in the 1995 quarter. This
improvement was achieved during a quarter when the industry was facing a
rapidly rising crude oil market and margins were weakening, particularly
towards the end of the 1996 quarter. At the same time, the Company had reduced
production levels to complete a scheduled turnaround at its refinery during
September 1996, but was able to maintain a refinery product spread of $5.38 per
barrel for the 1996 quarter, which compares to $3.26 per barrel in the 1995
quarter. The Company's results were helped by its initiatives to reduce costs
and improve marketing of its refined products. The Company's refined product
yield values increased by 24% to $24.81 per barrel in the 1996 quarter from
$20.07 per barrel in the 1995 quarter, while the Company's feedstock costs
increased by 16% to $19.43 per barrel in the 1996 quarter from $16.81 per
barrel in the 1995 quarter.
Revenues from sales of refined products in the Company's Refining and Marketing
segment were lower in the 1996 quarter due primarily to an 18% decrease in sales
volumes, partially offset by an 18% increase in average sales prices. Total
refined product sales volumes averaged 66,685 barrels per day in the 1996
quarter as compared to 81,264 barrels per day in the 1995 quarter. This
decrease reflected the Company's withdrawal from certain West Coast markets,
which also reduced the Company's purchases from other refiners and suppliers to
13,600 barrels per day in the 1996 quarter as compared to 26,800 barrels per day
in the 1995 quarter. The Company has curtailed certain operations in California
and plans to sell three Company-owned facilities, one of which was written down
by $.7 million during the 1996 third quarter. Resales of crude oil increased in
the 1996 third quarter to $24.8 million, compared to $11.0 million in the 1995
quarter, due primarily to sales of excess crude supply resulting from the
scheduled turnaround at the Company's refinery during the current quarter and to
increased crude oil prices. Costs of sales were higher in the 1996 quarter due
to the rising prices for crude oil and refined products, partially offset by
lower refined product volumes discussed above. Operating expenses were higher
in the 1996 quarter, as compared to the 1995 quarter, by $1.0 million primarily
due to a reduction of an environmental accrual in the 1995 quarter.
Nine Months Ended September 30, 1996 Compared With Nine Months Ended September
30, 1995. Operating profit of $8.7 million in the 1996 period compared to an
operating loss of $4.5 million in the 1995 period. This improvement was due
primarily to higher product margins, as experienced generally by the industry
and in part to initiatives by the Company to reduce costs and improve marketing
of its refined products. The Company's average yield value of refined products
increased by 19% to $23.95 per barrel in the 1996 period from $20.16 per barrel
in the 1995 period, while average feedstock costs increased by only 10% to
$18.91 per barrel in the 1996 period from $17.13 per barrel in the 1995 period.
Revenues from sales of refined products in the Company's Refining and Marketing
segment decreased in the 1996 period due primarily to a 19% decline in sales
volumes, partially offset by a 15% increase in average sales prices. Total
refined product sales averaged 63,504 barrels per day in the 1996 period as
compared to 78,322 barrels per day in the 1995 period. This decline, as
discussed above, reflected the Company's withdrawal from certain West Coast
markets, which also reduced refined product purchases from other refiners and
suppliers to 12,100 barrels per day in the 1996 period from 26,900 barrels per
day in the 1995 period. Resales of crude oil increased to $74.6 million in the
1996 period from $65.8 million in the 1995 period due primarily to sales of
excess crude supply resulting from the scheduled turnaround at the Company's
refinery during the 1996 period and to increased crude oil prices. Costs of
sales decreased in the 1996 period due to lower volumes of refined products,
partially offset by higher prices for crude oil and refined products. Operating
expenses were higher in the 1996 period, as compared to the 1995 period, by $5.1
million due primarily to the reduction of an environmental accrual in the 1995
period and, to a lesser extent, higher maintenance and employee termination
costs in the 1996 period.
Although results from the Company's Refining and Marketing segment for the 1996
quarter and period have improved over 1995 levels, margins continue to be
volatile. Future profitability of this segment will continue to be
significantly influenced by market conditions, particularly as these conditions
influence costs of crude oil relative to prices received for sales of refined
products, and other additional factors that are beyond the control of the
Company.
12
Exploration and Production Three Months Ended Nine Months Ended
- -------------------------- September 30, September 30,
------------------ -----------------
(Dollars in millions except per unit 1996 1995 1996 1995
amounts) ---- ---- ---- ----
U.S. Oil and Gas:
Gross operating revenues. . . . . . . . . $ 21.7 24.9 69.4 83.5
Other income - severance tax refunds. . . - - 5.0 -
Gain on sale of assets. . . . . . . . . . - 33.5 - 33.5
Production costs. . . . . . . . . . . . . 1.3 3.2 3.8 9.9
Administrative support and other
operating expenses . . . . . . . . . . . .1 .8 2.0 2.0
Depreciation, depletion and amortization. 6.1 6.2 18.7 22.8
------ ------- ------ -------
Operating Profit - U.S. Oil and Gas. . . 14.2 48.2 49.9 82.3
------ ------- ------ -------
U.S. Gas Transportation:
Gross operating revenues. . . . . . . . . 1.3 1.5 4.0 4.2
Operating expenses. . . . . . . . . . . . .1 .1 .2 .2
Depreciation and amortization . . . . . . .1 .1 .2 .2
------ ------- ------ -------
Operating Profit - U.S. Gas
Transportation. . . . . . . . . . . . . 1.1 1.3 3.6 3.8
------ ------- ------ -------
Bolivia:
Gross operating revenues. . . . . . . . . 3.4 3.2 10.5 9.0
Production costs. . . . . . . . . . . . . .2 .2 .6 .5
Administrative support and other
operating expenses. . . . . . . . . . . .6 .8 2.1 2.3
Depreciation, depletion and
amortization . . . . . . . . . . . . . . .4 - 1.0 -
------ ------- ------ -------
Operating Profit - Bolivia . . . . . . . 2.2 2.2 6.8 6.2
------ ------- ------ -------
Total Operating Profit -
Exploration and Production. . . . . . . . $ 17.5 51.7 60.3 92.3
====== ======= ====== =======
U.S.:
Capital expenditures. . . . . . . . . . . $ 11.7 13.8 27.1 40.8
====== ======= ====== =======
Net natural gas production (average
daily Mcf) -
Spot market and other. . . . . . . . . . 66,447 93,641 74,300 98,625
Tennessee Gas Contract(1). . . . . . . . 14,165 18,048 14,423 21,323
------ ------- ------ -------
Total production . . . . . . . . . . 80,612 111,689 88,723 119,948
====== ======= ====== =======
Average natural gas sales ($/Mcf) -
Spot market(2) . . . . . . . . . . . . . $ 1.71 1.26 1.77 1.30
Tennessee Gas Contract(1). . . . . . . . $ 8.61 8.50 8.41 8.35
Average. . . . . . . . . . . . . . . . . $ 2.92 2.43 2.85 2.55
Average operating expenses ($/Mcf) -
Lease operating expenses . . . . . . . . $ .14 .13 .12 .13
Severance taxes. . . . . . . . . . . . . .04 .17 .04 .17
------ ------- ------ -------
Total production costs. . . . . . . . . .18 .30 .16 .30
Administrative support . . . . . . . . . .01 .10 .08 .06
------ ------- ------ -------
Total operating expenses. . . . . . . . $ .19 .40 .24 .36
====== ======= ====== =======
Depletion ($/Mcf) . . . . . . . . . . . . $ .82 .60 .77 .70
====== ======= ====== =======
Bolivia:
Capital expenditures. . . . . . . . . . . $ .8 - 5.7 -
Net natural gas production (average
daily Mcf) . . . . . . . . . . . . . . . 20,945 20,559 21,355 19,075
Average natural gas sales price ($/Mcf) . $ 1.31 1.32 1.33 1.29
Net condensate production (average
daily barrels) . . . . . . . . . . . . . 605 604 611 589
Average condensate price ($/barrel) . . . $ 16.92 12.95 16.50 14.44
Average operating expenses ($/Mcfe) -
Production costs . . . . . . . . . . . . $ .11 .05 .10 .08
Value-added taxes. . . . . . . . . . . . .08 .09 .07 .06
Administrative support . . . . . . . . . .24 .30 .24 .31
------ ------- ------ -------
Total operating expenses . . . . . . . $ .43 .44 .41 .45
====== ======= ====== =======
Depletion ($/Mcfe). . . . . . . . . . . . $ .17 - .15 -
====== ======= ====== =======
13
(1) The Company is selling a portion of the gas produced from its Bob West Field
to Tennessee Gas Pipeline Company ("Tennessee Gas") under a contract
("Tennessee Gas Contract") which expires in January 1999 (see Note 4 of
Notes to Condensed Consolidated Financial Statements).
(2) Includes effects of the Company's natural gas price swap agreements which
amounted to a loss of $.19 per Mcf and a gain of $.05 per Mcf for the three
months ended September 30, 1996 and 1995, respectively, and a loss of $.15
per Mcf and a gain of $.04 per Mcf for the nine months ended September 30,
1996 and 1995, respectively.
(3) Mcf is defined as one thousand cubic feet; Mcfe is defined as net equivalent
one thousand cubic feet.
United States
Three Months Ended September 30, 1996 Compared With Three Months Ended September
30, 1995. Operating profit of $14.2 million from the Company's U.S. oil and gas
operations in the 1996 quarter compares to $48.2 million in the 1995 quarter.
Included in the 1995 quarter was a gain of $33.5 million from the sale of
certain interests in the Bob West Field and operating profit of $1.3 million
related to these sold interests. Excluding these amounts from the 1995 quarter,
operating profit improved 6% in the 1996 quarter, due primarily to a reduction
in current severance taxes and other operating expenses together with higher
sales price for natural gas.
Prices realized by the Company on its spot natural gas production increased 36%
to $1.71 per Mcf in the 1996 quarter from $1.26 per Mcf in the 1995 quarter.
Excluding 26.6 Mmcf per day related to the sold interests from the 1995 quarter,
the Company's spot production was essentially unchanged, with a 4.5 Mmcf per day
decline in the Company's Bob West Field spot production offset by a 4.0 Mmcf per
day increase in production from the Company's exploration and acquisition
programs outside of the Bob West Field. The Company's weighted average sales
price, including the above-market pricing of the Tennessee Gas Contract,
increased 20% to $2.92 per Mcf in the 1996 quarter as compared to $2.43 per Mcf
in the 1995 quarter. Volumes sold under the Tennessee Gas Contract declined 22%
during the 1996 quarter due to an expected decline in contract deliverability.
Gross operating revenues from the Company's U. S. oil and gas operations, after
excluding revenues related to the sold interests from the 1995 quarter, remained
essentially unchanged due to higher prices for the Company's spot production
offsetting the decline in volumes sold under the Tennessee Gas Contract.
Production costs, after excluding costs related to the sold interests from the
1995 quarter, were lower during the 1996 quarter due to a $1.3 million reduction
in current severance taxes on exempt wells. On a per Mcf basis, production
costs were reduced to $.18 per Mcf in the 1996 quarter, compared to $.30 per Mcf
in the 1995 quarter, also due to the severance tax exemptions. Total operating
expenses on a per Mcf basis decreased due to the lower production costs together
with lower administrative expenses, primarily professional fees. Total
depreciation, depletion and amortization was lower in the 1996 quarter due to
lower production volumes, partially offset by a higher depletion rate.
The Company enters into commodity price swap agreements to reduce the risk
caused by fluctuations in the prices of natural gas in the spot market. During
both the 1996 and 1995 quarters, the Company used such arrangements to set the
price of approximately 38% of the natural gas production that it sold in the
spot market. The Company realized a loss of $1.2 million (or $.19 per Mcf)
during the 1996 quarter and a gain of $.5 million (or $.05 per Mcf) during the
1995 quarter from these price swap arrangements.
Nine Months Ended September 30, 1996 Compared With Nine Months Ended September
30, 1995. Operating profit of $49.9 million from the Company's U.S. oil and gas
operations in the 1996 period benefited from retroactive state severance tax
exemptions totaling approximately $5 million from its Bob West Field production
in prior years. Substantially all of the Company's proved producing reserves in
the Bob West Field were certified by the Texas Railroad Commission as high-cost
gas from a designated tight formation, eligible for state severance tax
exemptions from the date of first production through August 2001. These
exemptions also had the effect of increasing the pretax present value of the
Company's 1995 year-end U.S. proved reserves by $7.7 million to $176.4 million.
Severance tax expense will not be recorded for current production from exempt
wells during 1996. Operating profit of $82.3 million in the 1995 period
included a gain of $33.5 million from the sale of certain interests in the Bob
West Field together with operating profit of $4.2 million related to these sold
interests. Excluding the income related to the severance tax refund from the
1996 period and the operating profit related to sold interests from the 1995
period, operating profit from the U.S. oil and gas producing operations was
relatively unchanged from the 1995 period.
14
Prices for sales of the Company's natural gas production sold into the spot
market increased 36% to $1.77 per Mcf in the 1996 period from $1.30 per Mcf in
the 1995 period. Excluding 32.7 average daily Mmcf related to the sold
interests from the 1995 period, natural gas production sold into the spot market
increased by 13% during the 1996 period, reflecting the effects of a voluntary
curtailment by the Company during the early part of the 1995 period in response
to poor market conditions during that time and reflecting initiatives by the
Company during the 1996 period to add production through drilling and
acquisition activities. The Company's weighted average sales price, including
the effect of the above-market pricing of the Tennessee Gas Contract, increased
to $2.85 per Mcf in the 1996 period from $2.55 per Mcf in the 1995 period.
Production sold under the Tennessee Gas Contract decreased by 32% due to an
expected decline in contract deliverability during the 1996 period. A
compression facility will be installed in the Bob West Field by the end of 1996
that may impact the decline in future contract deliverability.
Gross operating revenues from the Company's U.S. oil and gas operations, after
excluding $11.7 million related to the sold interests from the 1995 period and
excluding the price swap transactions discussed below, increased by $1.5 million
due to increases in the Company's sales prices for its spot production and due
to new production from the Company's development, exploration and acquisition
programs offsetting the declines in volumes sold under the Tennessee Gas
Contract. The decrease in total production costs, after excluding costs related
to the sold interests in the 1995 period, reflected a reduction of $4.0 million
in current year severance taxes. On a per Mcf basis, production costs were
reduced to $.16 per Mcf compared to $.30 per Mcf due to the exemption of
severance taxes. Total depreciation, depletion and amortization was lower in
the 1996 period due to lower production volumes, partially offset by a higher
depletion rate.
The Company enters into commodity price swap agreements to reduce the risk
caused by fluctuations in the prices of natural gas in the spot market. During
the 1996 and 1995 periods, the Company used such arrangements to set the price
of 37% and 28%, respectively, of the natural gas production that it sold in the
spot market. During the 1996 and 1995 periods, the Company realized a loss of
$2.9 million (or $.15 per Mcf) and a gain of $1.0 million (or $.04 per Mcf),
respectively, from these price swap arrangements. As of September 30, 1996, the
Company had no material price swap arrangements remaining for 1996.
Bolivia
Three Months Ended September 30, 1996 Compared With Three Months Ended September
30, 1995. Operating profit from the Company's Bolivian operations during the
1996 quarter remained relatively unchanged from the 1995 quarter, as increased
revenues from higher condensate prices together with lower operating expenses
were offset by increased depreciation, depletion and amortization. During the
1996 quarter, the Company's net production of natural gas in Bolivia averaged
20.9 Mmcf per day, relatively constant with the 1995 quarter.
Nine Months Ended September 30, 1996 Compared With Nine Months Ended September
30, 1995. Operating profit from the Company's Bolivian operations increased by
$.6 million during the 1996 period, primarily due to a 12% increase in
production of natural gas together with higher prices received for both natural
gas and condensate. During the second and third quarters of 1996, the Company
benefited from increased demand from the Bolivian state-owned oil and gas
company for higher quality natural gas, in order to meet contract specifications
for exports to Argentina, together with the inability of another producer to
meet supply requirements. Production costs and other operating expenses
remained relatively unchanged in total but declined by 9% on a per unit basis
reflecting the increase in volumes with minimal increases in expenses.
Partially offsetting these improvements was depreciation, depletion and
amortization of $1.0 million recorded in the 1996 period.
Bolivian Hydrocarbons Laws. On April 30, 1996, a new Hydrocarbons Law that
significantly impacts the Company's operations in Bolivia was enacted by the
Bolivian government. Among other matters, the new law granted the Company the
option to convert its Contracts of Operation to Shared Risk Contracts. On July
29, 1996, the Company signed agreements converting its Contracts of Operation to
Shared Risk Contracts subject to recision at the option of the Company if the
Company is not satisfied with modifications to Bolivian fiscal law to be enacted
not later than January 31, 1997. The Shared Risk Contracts extend the term of
operation, provide more favorable acreage relinquishment terms and a revised
fiscal regime of taxes and tariffs. The new contracts will extend the Company's
operations on Block 18 and Block 20 to 2017 and 2029 from their current
expiration dates of 2007 and 2008, respectively, except for an Exploitation Area
in Block 20 which will have an expiration date of 2018. The new contract
provisions may result in an immediate increase, which the Company believes could
be as high
15
as 35%, in the Company's proved Bolivian reserves that have been previously
limited by the contract termination dates. In connection with the conversion to
Shared Risk Contracts, the Company retained its productive fields on Block 18
with no relinquishment of acreage. On Block 20, the Company selected certain
acreage to be relinquished, retaining its discoveries and approximately
two-thirds of the remaining unexplored Block 20 acreage. Block 20 is subject to
a seven-year exploration period, certain future acreage relinquishments and
exploration drilling obligations required by law.
Marine Services Three Months Ended Nine Months Ended
- --------------- September 30, September 30,
------------------ -----------------
(Dollars in millions) 1996 1995 1996 1995
---- ---- ---- ----
Gross Operating Revenues . . . . . . . $ 32.7 18.5 87.5 56.9
Costs of Sales . . . . . . . . . . . . 24.5 15.8 66.7 49.2
------ ------ ------- ------
Gross Margin . . . . . . . . . . . . 8.2 2.7 20.8 7.7
Operating and Other Expenses . . . . . 5.8 3.3 15.4 9.9
Depreciation and Amortization. . . . . .4 .1 .9 .3
------ ------ ------- ------
Operating Profit (Loss). . . . . . . $ 2.0 (.7) 4.5 (2.5)
====== ====== ======= ======
Capital Expenditures . . . . . . . . . $ 1.2 .1 6.2 .2
====== ====== ======= ======
Refined Product Sales, Primarily
Diesel Fuel (thousands of gallons). . 37,829 27,837 107,376 86,210
====== ====== ======= ======
On February 20, 1996, the Company acquired Coastwide Energy Services, Inc.
("Coastwide") and combined Coastwide's operations with the Company's marine
petroleum products distribution business, forming a Marine Services segment. As
a combined operation, the Marine Services segment is a wholesale distributor of
diesel fuel and lubricants and a provider of services to the offshore petroleum
industry in the Gulf of Mexico. Operating results from Coastwide have been
included in the Company's Marine Services segment since the date of acquisition.
The Marine Services segment currently consists of 22 terminals, primarily
marine-based, as compared to 15 terminals in the prior year. The added
locations and volumes, mainly related to the acquisition discussed above,
combined with higher refined product prices, have contributed to revenue
increases for the segment of $14.2 million and $30.6 million during the 1996
quarter and period, respectively, when compared to the same periods of the prior
year. Sales of refined products, primarily diesel fuel, have increased by 36%
during the 1996 quarter and 25% during the 1996 period. These increases in
volumes together with improved margins during the 1996 quarter and period were
partially offset by higher operating and other expenses associated with the
increased activity. Depreciation and amortization increased during the 1996
quarter and period due to capital additions during the year. In total, results
for the Marine Services segment reflected a turnaround from the losses incurred
in the prior year with operating profit of $2.0 million for the 1996 quarter and
$4.5 million for the 1996 period.
General and Administrative Expenses
General and administrative expenses decreased by $1.3 million, or 30%, during
the 1996 quarter and by $3.4 million, or 27%, during the 1996 period. These
decreases were primarily due to lower employee and labor costs resulting from
cost reduction measures implemented by the Company in late 1995.
Interest Expense
Interest expense decreased by $1.3 million, or 24%, during the 1996 quarter and
by $4.0 million, or 25%, during the 1996 period. In December 1995, the Company
redeemed $34.6 million of its Subordinated Debentures which, together with lower
borrowings under the Company's revolving credit facility, resulted in the
interest expense savings during the 1996 quarter and period. In November 1996,
the Company fully redeemed its two public debt issues, totaling approximately
$74 million, which will further reduce the Company's interest expense by
approximately $10 million annually.
16
Interest Income
On September 30, 1996, the Company received interest of approximately $7 million
from Tennessee Gas in conjunction with the collection of a receivable which
resulted from underpayment for natural gas sold in prior periods (see Note 4 of
Notes to Condensed Consolidated Financial Statements). Interest income for the
1996 quarter and period benefited from this receipt, which had not previously
been recorded by the Company.
Other Expense, Net
The decrease of $4.4 million in other expense during the 1996 quarter resulted
primarily from severance costs and related benefits of $3.8 million incurred for
an administrative workforce reduction and other employee terminations during the
1995 quarter. For the 1996 period, other expense increased by $1.2 million,
primarily due to costs of $2.3 million related to a shareholder consent
solicitation which was resolved in April 1996 together with a write-off of
deferred financing costs , partially offset by lower employee termination costs.
Income Taxes
Income taxes increased by $5.9 million and $13.3 million during the 1996 quarter
and period, respectively. These increases were primarily due to a higher
effective tax rate for the Company during the 1996 quarter and period as
earnings subject to U.S. taxes exceeded available net operating loss and tax
credit carryforwards.
IMPACT OF CHANGING PRICES
The Company's operating results and cash flows are sensitive to the volatile
changes in energy prices. Major shifts in the cost of crude oil used for
refinery feedstocks and the price of refined products can result in a change in
gross margin from the refining and marketing operations, as prices received for
refined products may or may not keep pace with changes in crude oil costs.
These energy prices, together with volume levels, also determine the carrying
value of crude oil and refined product inventory.
Likewise, changes in natural gas prices impact revenues and the present value of
estimated future net revenues and cash flows from the Company's exploration and
production operations. From time to time, the Company may increase or decrease
its natural gas production in response to market conditions. The carrying value
of natural gas assets may also be subject to noncash write-downs based on
changes in natural gas prices and other determining factors.
CAPITAL RESOURCES AND LIQUIDITY
Overview
The Company operates in an environment where its liquidity and capital resources
are impacted by changes in the supply of and demand for crude oil, natural gas
and refined petroleum products, market uncertainty and a variety of additional
factors that are beyond the control of the Company. These factors include,
among others, the level of consumer product demand, weather conditions, the
proximity of the Company's natural gas reserves to pipelines, the capacities of
such pipelines, fluctuations in seasonal demand, governmental regulations, the
price and availability of alternative fuels and overall market and economic
conditions. The Company's future capital expenditures, borrowings under its
credit facility and other sources of capital will be affected by these
conditions.
During the 1996 period, the Company achieved improvement in profitability,
primarily from its Refining and Marketing and Marine Services segments.
Furthermore, the resolution of the Tennessee Gas litigation in August 1996
removed a major financial uncertainty from the Company's capital structure that
will improve the predictability of the Company's cash flow, provide for
additional financial flexibility, and allow the Company to focus on growth
initiatives. In these regards, the receipt of $67.5 million from Tennessee Gas
on September 30, 1996 has enabled the Company to fully redeem its two public
debt issues, reducing the Company's debt-to-capital ratio to 23%.
The Company continues to assess its existing asset base in order to maximize
returns and financial flexibility through diversification, acquisitions and
divestitures in all of its operating segments. This ongoing assessment
includes, in the Exploration and Production segment, evaluating ways in which
the Company might diversify the mix of its oil and gas assets and offset the
impact of declining production under the Tennessee Gas Contract
17
through domestic development, exploration and acquisition activity outside of
the Bob West Field. In the Refining and Marketing segment, the Company has been
engaged in an ongoing effort to evaluate these assets and operations and has
considered possible joint ventures, strategic alliances or business
combinations; however, such evaluations have not resulted in any transaction.
The Company continues to assess its Marine Services segment, pursuing
opportunities to consolidate operations and improve efficiencies. In these
regards, during the 1996 period, the Company completed the acquisition of
Coastwide for approximately 1.4 million shares of Tesoro's Common Stock and $7.7
million in cash (see Note 2 of Notes to Condensed Consolidated Financial
Statements).
Resolution of Tennessee Gas Litigation
The Company is selling a portion of the gas produced from its Bob West Field to
Tennessee Gas Pipeline Company ("Tennessee Gas") under a Gas Purchase and Sales
Agreement ("Contract") which expires in January 1999 and provides that the price
of gas shall be the maximum price as calculated in accordance with Section
102(b)(2) ("Contract Price") of the Natural Gas Policy Act of 1978 ("NGPA"). In
August 1990, Tennessee Gas filed suit against the Company and the other sellers
under the Contract in the District Court of Bexar County, Texas, alleging that
the Contract is not applicable to the Company's properties and that the gas
sales price should be the price calculated under the provisions of Section 101
of the NGPA rather than the Contract Price. Tennessee Gas also claimed that the
Contract should be considered an "output contract" under Section 2.306 of the
Texas Uniform Commercial Code ("UCC") and that the increases in volumes tendered
under the Contract exceeded those allowable for an output contract.
The District Court judge returned a verdict in favor of the Company on all
issues. Tennessee Gas appealed the District Court decision which was reviewed
by the Supreme Court of Texas. On April 18, 1996, the Supreme Court of Texas
issued its decision and affirmed the judgment of the District Court in full.
Tennessee Gas filed a motion for rehearing and on August 16, 1996, the Supreme
Court of Texas issued its mandate denying Tennessee Gas' motion for rehearing
and upholding all aspects of the Contract. Tennessee Gas continues to take its
minimum monthly required amount of gas and resumed paying the Contract Price to
the Company for gas taken beginning with May 1996 volumes. On September 30,
1996, the Company received $67.5 million from Tennessee Gas, which included
collection of a $59.6 million bonded receivable for underpayment for natural gas
sold in prior periods. The remaining $7.9 million of cash received was for
interest and reimbursement of legal fees and court costs, which had not
previously been recorded by the Company resulting in income during the 1996
third quarter. For further information regarding the resolution of the
Tennessee Gas litigation, see "Legal Proceedings" in Part II, Item 1, contained
herein.
Redemption of Debt
In September 1996, the Company gave notice to fully redeem its two public debt
issues, totaling approximately $74 million, at a price equal to 100% of the
principal amount, plus accrued interest to the redemption date. The redemption
of the debt, which was comprised of $44.1 million of outstanding Exchange Notes,
due December 1, 2000, and $30 million of outstanding Subordinated Debentures,
due March 15, 2001, was completed in November 1996. See Note 3 of Notes to
Condensed Consolidated Financial Statements for further information on the
redemption of debt and "Changes in Securities" in Part II, Item 2, contained
herein, regarding dividend restrictions.
Credit Arrangements
In June 1996, the Company negotiated an amended and restated corporate revolving
credit agreement ("Credit Facility") which provides total commitments of $150
million from a consortium of nine banks. The Credit Facility, which is subject
to a borrowing base, provides for the issuance of letters of credit and cash
borrowings. The Credit Facility replaced a higher-cost $90 million facility and
provides the Company with more financial flexibility, including lower interest
rates, reduced fees on letters of credit, elimination of certain restrictive
financial tests, an increased borrowing base, increased cash borrowing
availability, and the right to restructure non-recourse or limited financings
for certain subsidiaries. The Company, at its option, has currently activated
$100 million of commitments. Upon the resolution of the Tennessee Gas
litigation and the collection of the related bonded receivable in the 1996 third
quarter (see Note 4 of Notes to Condensed Consolidated Financial Statements),
certain provisions of the Credit Facility were enhanced, including an extension
of the Credit Facility's expiration date to April 30, 2000 and an increase in
cash borrowing availability from $50 million to $100 million.
18
At September 30, 1996, the Company had outstanding letters of credit of $39
million and no cash borrowings outstanding. Outstanding obligations under the
Credit Facility are secured by liens on substantially all of the Company's trade
accounts receivable and product inventory and by mortgages on the Company's
refinery and South Texas natural gas reserves.
Under the terms of the Credit Facility, the Company is required to maintain
specified levels of consolidated working capital, tangible net worth, cash flow
and interest coverage. Among other matters, the Credit Facility contains
covenants which restrict the incurrence of additional indebtedness and limit
restricted payments. Under the Credit Facility, dividends up to $5 million per
year are allowed, subject to the restricted payment covenant. See "Changes in
Securities" in Part II, Item 2, contained herein.
Capital Expenditures
For the year 1996, the Company's capital budget is approximately $85 million, of
which approximately $46 million had been spent during the nine months ended
September 30, 1996. The Company expects to continue funding of its capital
expenditures for 1996 through a combination of cash flows from operations and
borrowings under its Credit Facility.
The Exploration and Production segment accounts for $64 million of the 1996
budgeted expenditures, including as much as $56 million for U.S. activities and
$8 million for Bolivia. The Company's planned U.S. expenditures include $36
million for exploration, development and acquisition outside of the Bob West
Field and $20 million for development drilling and facilities in the Bob West
Field. Through the nine months ended September 30, 1996, total U.S.
expenditures were $27 million, principally for participation in the drilling of
ten development wells (nine completed) and four exploratory wells (two
completed) and acquisitions of proved properties. The Company's U.S. budget for
the remainder of 1996 of $29 million includes $19 million for drilling projects,
some of which may not be commenced by year-end, and $10 million for unspecified
acquisitions. Although the Company continues to pursue exploration, development
and acquisition opportunities, actual capital expenditures may vary from budget
due to a number of factors, including the timing of drilling projects and the
extent to which proved properties are acquired. In Bolivia, capital spending
totaled $6 million during the first nine months of 1996, primarily for the
drilling and completion of two exploratory wells.
Capital spending for the Refining and Marketing segment is projected to be $13
million for 1996, of which $7 million had been spent through the first nine
months, primarily for installation of facilities to produce and market asphalt,
improvements and upgrades at the refinery, expansion of its retail marketing
facilities, and environmental projects.
In the Marine Services segment, capital spending for 1996 is budgeted at $7
million, of which $6 million had been spent through the first nine months
(excluding amounts for the Coastwide acquisition). Capital expenditures have
contributed to this segment's improved operating efficiencies and marketing
efforts.
Cash Flows From Operating, Investing and Financing
At September 30, 1996, the Company's working capital totaled $78 million, which
included cash of $104 million and current liabilities for debt and other
obligations of $84 million. In November 1996, the Company redeemed its two
public debt issues, using approximately $74 million of cash and reducing current
liabilities. Components of the Company's cash flows are set forth below (in
millions):
Nine Months Ended
September 30,
-----------------
1996 1995
---- ----
Cash Flows From (Used In):
Operating Activities . . . . . . . . . . . . . . . $ 148.4 30.3
Investing Activities . . . . . . . . . . . . . . . (57.0) 17.6
Financing Activities . . . . . . . . . . . . . . . (1.8) (2.5)
----- ----
Increase in Cash and Cash Equivalents. . . . . . . . $ 89.6 45.4
===== ====
Net cash from operating activities of $148 million during the 1996 period, which
compares to $30 million for the 1995 period, included the receipt of $67.5
million from Tennessee Gas (see Note 4 of Notes to Condensed Consolidated
Financial Statements) and reduced working capital balances. Net cash used in
investing activities during the 1996 period of $57 million included capital
expenditures of $46 million and cash consideration of $7.7 million for the
acquisition of Coastwide. Capital expenditures for the 1996 period included $33
million for the
19
Company's exploration and production activities in South Texas and Bolivia. Net
cash used in financing activities of $2 million during the 1996 period was
primarily due to payments of long-term debt. During the 1996 period, the
Company's gross borrowings and repayments under its revolving credit line
amounted to $112 million.
Environmental
The Company is subject to extensive federal, state and local environmental laws
and regulations. These laws, which change frequently, regulate the discharge of
materials into the environment and may require the Company to remove or mitigate
the environmental effects of the disposal or release of petroleum or chemical
substances at various sites or install additional controls or other
modifications or changes in use for certain emission sources. The Company is
currently involved in remedial responses and has incurred cleanup expenditures
associated with environmental matters at a number of sites, including certain of
its own properties. At September 30, 1996, the Company's accruals for
environmental matters amounted to $9.3 million, which included a noncurrent
liability of approximately $4 million for remediation of Kenai Pipe Line
Company's ("KPL") properties that has been funded by the former owners of KPL
through a restricted escrow deposit. Based on currently available information,
including the participation of other parties or former owners in remediation
actions, the Company believes these accruals are adequate. In addition, to
comply with environmental laws and regulations, the Company anticipates that it
will make capital improvements in 1996 and 1997 totaling approximately $2.3
million, primarily for upgrading of underground storage tanks. Environmental
regulations would also have required the Company to make capital improvements
starting in 1996 of approximately $9.5 million for the installation of dike
liners. However, on April 18, 1996, the Alaska Department of Environmental
Conservation ("ADEC") issued a memorandum stating that alternative compliance
schedules allowing for delayed implementation of the requirements for dike
liners in secondary containment systems for existing petroleum storage tanks
would be approved. The April 18, 1996 ADEC Memorandum recognizes that secondary
containment options other than synthetic dike liners are appropriate, but
essential ADEC guidelines addressing other options will not be available before
the end of 1996. The ADEC believes it will be three to five years before all
affected facilities fully implement the provisions of the regulations. The
Company is currently negotiating for an alternative compliance schedule with
ADEC to maintain the Company's existing storage tank facilities in compliance
with the state regulations. The Company cannot presently determine when an
alternative schedule will be granted.
Conditions that require additional expenditures may exist for various Company
sites, including, but not limited to, the Company's refinery, retail gasoline
outlets (current and closed locations) and petroleum product terminals, and for
compliance with the Clean Air Act. The amount of such future expenditures cannot
currently be determined by the Company. For further information on
environmental contingencies, see Note 5 of Notes to Condensed Consolidated
Financial Statements.
FORWARD-LOOKING STATEMENTS
Statements concerning the Company, including those contained in the foregoing
discussion, which are (a) projections of revenues, earnings, earnings per share,
capital expenditures or other financial items, (b) statements of plans and
objectives for future operations, (c) statements of future economic performance,
or (d) statements of assumptions or estimates underlying or supporting the
foregoing are forward-looking statements within the meaning of Section 27A of
the Securities Act of 1933 and Section 21E of the Securities Exchange Act of
1934. The ultimate accuracy of forward-looking statements is subject to a wide
range of business risks and changes in circumstances, and actual results and
outcomes often differ from expectations. Any number of important factors could
cause actual results to differ materially from those in the forward-looking
statements herein, including the following: the timing and extent of changes in
commodity prices and underlying demand and availability of crude oil and other
refinery feedstocks, refined products, and natural gas; actions of our customers
and competitors; changes in the cost or availability of third-party vessels,
pipelines and other means of transporting feedstocks and products; state and
federal environmental, economic, safety and other policies and regulations, any
changes therein, and any legal or regulatory delays or other factors beyond the
Company's control; execution of planned capital projects; weather conditions
affecting the Company's operations or the areas in which the Company's products
are marketed; future well performance; the extent of Tesoro's success in
acquiring oil and gas properties and in discovering, developing and producing
reserves; political developments in foreign countries, the conditions of the
capital markets and equity markets during the periods covered by the
forward-looking statements; earthquakes or other natural disasters affecting
operations; adverse rulings, judgments, or settlements in litigation or other
legal matters, including unexpected environmental remediation costs in excess of
any reserves; and adverse changes in the credit ratings assigned to the
Company's trade credit. For more information with respect
20
to the foregoing, see the Company's Annual Report on Form 10-K. The Company
undertakes no obligation to publicly release the result of any revisions to any
such forward-looking statements that may be made to reflect events or
circumstances after the date hereof or to reflect the occurrence of
unanticipated events.
PART II - OTHER INFORMATION
Item 1. Legal Proceedings
The Company is selling a portion of the gas produced from its Bob West Field to
Tennessee Gas Pipeline Company ("Tennessee Gas") under a Gas Purchase and Sales
Agreement ("Contract") which expires in January 1999 and provides that the price
of gas shall be the maximum price as calculated in accordance with Section
102(b)(2) ("Contract Price") of the Natural Gas Policy Act of 1978 ("NGPA"). In
August 1990, Tennessee Gas filed suit against the Company and the other sellers
under the Contract in the District Court of Bexar County, Texas, alleging that
the Contract is not applicable to the Company's properties and that the gas
sales price should be the price calculated under the provisions of Section 101
of the NGPA rather than the Contract Price. Tennessee Gas also claimed that the
Contract should be considered an "output contract" under Section 2.306 of the
Texas Uniform Commercial Code ("UCC") and that the increases in volumes tendered
under the Contract exceeded those allowable for an output contract.
The District Court judge returned a verdict in favor of the Company on all
issues. Tennessee Gas appealed the District Court decision which was reviewed
by the Supreme Court of Texas. On April 18, 1996, the Supreme Court of Texas
issued its decision and affirmed the judgment of the District Court in full.
Tennessee Gas filed a motion for rehearing and on April 16, 1996, the Supreme
Court of Texas issued its mandate denying Tennessee Gas' motion for rehearing
and upholding all aspects of the Contract. Subsequently, the parties entered
into an Agreement Regarding Partial Satisfaction of Judgment ("Judgment")
effective September 30, 1996, pursuant to which Tennessee Gas paid the Company
$67,500,063.87 including interest and attorney fees, and the issue of how
interest should ultimately be computed was referred to the District Court for
final decision. On October 31, 1996, the District Court ruled that interest on
the Judgment should be computed at a rate of 9% per annum compounded, rather
than 9% simple, the rate that the Company was paid under the Judgment. As a
result, Tennessee Gas paid the Company an additional $154,348.15 in November
1996. The District Court has entered Agreed Orders Releasing Supersedeas Bonds
and discharging Tennessee Gas and its surety from all obligations with respect
to the Supersedeas Bonds in the amount of $206 million posted by Tennessee Gas
during the appeal process and releasing funds in the Registry of the Court
whereby three Certificates of Deposit, in the total amount of $220,088.81, will
be distributed among the Company and the other sellers under the Contract.
Tennessee Gas continues to take its minimum monthly required amount of gas and
resumed paying the Contract Price to the Company for gas taken beginning with
May 1996 volumes. See Note 4 of Notes to Condensed Consolidated Financial
Statements in Part I, Item 1, contained herein.
Item 2. Changes in Securities
In September 1996, the Company gave notice to redeem its 13% Exchange Notes
("Exchange Notes") and 12-3/4% Subordinated Debentures ("Subordinated
Debentures"). See Note 3 of Notes to Condensed Consolidated Financial
Statements in Part I, Item 1, contained herein. With the redemption of this
debt in November 1996, the Company is no longer subject to the indenture
governing the Subordinated Debentures which contained covenants that prevented
the payment of cash dividends on Common Stock and limited the Company's ability
to purchase or redeem any shares of its capital stock.
As previously reported, the Company will continue to be subject to covenants
under its Amended and Restated Credit Agreement ("Credit Facility") with respect
to dividends on its capital stock. Although the terms of the Credit Facility
allow for the payment of cash dividends subject to a cumulative amount available
for dividend payments (which is defined as the difference of (i) the sum since
December 31, 1995, of (a) $5,000,000 and (b) 50% of consolidated net earnings of
the Company in any calendar year and (ii) any amount previously paid for
dividends since June 1996), cash dividends cannot exceed a maximum of $5,000,000
annually. The Credit Facility also permits the Company to repurchase a limited
amount of Common Stock for oddlot buyback programs, employee benefit plans and
open market repurchases.
The Board of Directors has no present plans to pay dividends. However, from
time to time, the Board of Directors will reevaluate the feasibility of
declaring future dividends.
21
Item 6. Exhibits and Reports on Form 8-K
(a) Exhibits
Exhibit
Number Description
27 Financial Data Schedule.
(b) Reports on Form 8-K
No reports on Form 8-K have been filed during the quarter for
which this report is filed.
22
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.
TESORO PETROLEUM CORPORATION
Registrant
Date: November 14, 1996 /s/ BRUCE A. SMITH
Bruce A. Smith
Chairman of the Board of Directors,
President and Chief Executive Officer
Date: November 14, 1996 /s/ DON E. BEERE
Don E. Beere
Vice President, Controller
(Chief Accounting Officer)
23
<TABLE> <S> <C>
<ARTICLE> 5
<LEGEND>
THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM TESORO
PETROLEUM CORPORATION'S FINANCIAL STATEMENTS AS OF AND FOR THE NINE MONTH PERIOD
ENDED SEPTEMBER 30, 1996, 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-31-1996
<PERIOD-END> SEP-30-1996
<CASH> 103,572
<SECURITIES> 0
<RECEIVABLES> 93,690
<ALLOWANCES> 1,990
<INVENTORY> 64,797
<CURRENT-ASSETS> 268,666
<PP&E> 538,609
<DEPRECIATION> 248,238
<TOTAL-ASSETS> 587,106
<CURRENT-LIABILITIES> 191,009
<BONDS> 80,020
<COMMON> 4,398
0
0
<OTHER-SE> 256,823
<TOTAL-LIABILITY-AND-EQUITY> 587,106
<SALES> 735,167
<TOTAL-REVENUES> 739,545
<CGS> 636,223
<TOTAL-COSTS> 636,223
<OTHER-EXPENSES> 30,386
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 12,142
<INCOME-PRETAX> 51,302
<INCOME-TAX> 17,159
<INCOME-CONTINUING> 34,143
<DISCONTINUED> 0
<EXTRAORDINARY> (2,290)
<CHANGES> 0
<NET-INCOME> 31,853
<EPS-PRIMARY> 1.21<F1>
<EPS-DILUTED> 1.21<F1>
<FN>
<F1>EARNINGS PER SHARE IS AFTER AN EXTRAORDINARY LOSS OF $2.3 MILLION ($.09 LOSS
PER SHARE) ON EXTINGUISHMENT OF DEBT.
<FN>
</TABLE>
