UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-Q
(Mark One)
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
FOR THE QUARTERLY PERIOD ENDED JUNE 30, 1997
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 26,807,269 shares of the Registrant's Common Stock outstanding at
July 31, 1997.
TESORO PETROLEUM CORPORATION AND SUBSIDIARIES
QUARTERLY REPORT ON FORM 10-Q
FOR THE QUARTERLY PERIOD ENDED JUNE 30, 1997
TABLE OF CONTENTS
Page
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements (Unaudited)
Condensed Consolidated Balance Sheets - June 30, 1997 and
December 31, 1996. . . . . . . . . . . . . . . . . . . . . . 3
Condensed Statements of Consolidated Operations - Three Months
and Six Months Ended June 30, 1997 and 1996. . . . . . . . . 4
Condensed Statements of Consolidated Cash Flows - Six Months
Ended June 30, 1997 and 1996 . . . . . . . . . . . . . . . . 5
Notes to Condensed Consolidated Financial Statements. . . . . 6
Item 2. Management's Discussion and Analysis of Financial
Condition and Results of Operations . . . . . . . . . . . . . 9
PART II. OTHER INFORMATION
Item 1. Legal Proceedings. . . . . . . . . . . . . . . . . . . 22
Item 4. Submission of Matters to a Vote of Security Holders. . 22
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)
June 30, December 31,
1997 1996<FN1>
---- ----
ASSETS
CURRENT ASSETS
Cash and cash equivalents . . . . . . . . . . . . $ 34,856 22,796
Receivables, less allowance for doubtful accounts
of $1,466 ($1,515 at December 31, 1996). . . . . 70,160 128,013
Inventories:
Crude oil and wholesale refined products, at LIFO 52,205 55,858
Merchandise and other refined products . . . . . 16,308 13,539
Materials and supplies . . . . . . . . . . . . . 5,164 5,091
Prepayments and other . . . . . . . . . . . . . . 9,418 12,046
--------- ---------
Total Current Assets. . . . . . . . . . . . . . 188,111 237,343
--------- ---------
PROPERTY, PLANT AND EQUIPMENT
Refining and marketing. . . . . . . . . . . . . . 347,266 328,522
Exploration and production:
Oil and gas (full cost method of accounting) . . 213,961 191,777
Gas transportation . . . . . . . . . . . . . . . 6,703 6,703
Marine services . . . . . . . . . . . . . . . . . 37,041 33,820
Corporate . . . . . . . . . . . . . . . . . . . . 12,970 12,531
--------- ---------
617,941 573,353
Less accumulated depreciation, depletion and
amortization. . . . . . . . . . . . . . . . . . 279,832 256,842
--------- ---------
Net Property, Plant and Equipment. . . . . . . . 338,109 316,511
--------- ---------
OTHER ASSETS . . . . . . . . . . . . . . . . . . . 30,998 28,733
--------- ---------
TOTAL ASSETS . . . . . . . . . . . . . . . . $ 557,218 582,587
========= =========
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
Accounts payable. . . . . . . . . . . . . . . . . $ 49,105 80,747
Accrued liabilities . . . . . . . . . . . . . . . 32,027 33,256
Current income taxes payable. . . . . . . . . . . 353 13,822
Current maturities of long-term debt and other
obligations. . . . . . . . . . . . . . . . . . . 10,055 10,043
--------- ---------
Total Current Liabilities. . . . . . . . . . . . 91,540 137,868
--------- ---------
DEFERRED INCOME TAXES. . . . . . . . . . . . . . . 22,654 19,151
--------- ---------
OTHER LIABILITIES. . . . . . . . . . . . . . . . . 45,388 42,243
--------- ---------
LONG-TERM DEBT AND OTHER OBLIGATIONS, LESS
CURRENT MATURITIES. . . . . . . . . . . . . . . . 77,987 79,260
--------- ---------
COMMITMENTS AND CONTINGENCIES (Note 4)
STOCKHOLDERS' EQUITY
Common Stock, par value $.16-2/3; authorized
50,000,000 shares; 26,453,745 shares issued
(26,414,134 in 1996) . . . . . . . . . . . . . . 4,409 4,402
Additional paid-in capital. . . . . . . . . . . . 189,706 189,368
Retained earnings . . . . . . . . . . . . . . . . 126,064 110,295
Treasury stock, 40,800 shares at cost in 1997 . . (530) -
--------- ---------
Total Stockholders' Equity . . . . . . . . . . . 319,649 304,065
--------- ---------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY . . $ 557,218 582,587
========= =========
<FN>
The accompanying notes are an integral part of these condensed consolidated financial statements.
<FN1> The balance sheet at December 31, 1996 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 Six Months Ended
June 30, June 30,
------------------ ----------------
1997 1996 1997 1996
---- ---- ---- ----
REVENUES
Refining and marketing. . . . . . . . . . $ 161,771 172,327 336,171 360,106
Exploration and production. . . . . . . . 18,590 29,936 41,948 57,457
Marine services . . . . . . . . . . . . . 30,338 31,525 65,833 54,807
Other income. . . . . . . . . . . . . . . 2,607 98 4,206 5,103
-------- -------- -------- --------
Total Revenues . . . . . . . . . . . . . 213,306 233,886 448,158 477,473
-------- -------- -------- --------
OPERATING COSTS AND EXPENSES
Refining and marketing. . . . . . . . . . 149,758 163,890 320,912 351,147
Exploration and production. . . . . . . . 2,937 2,945 5,782 6,351
Marine services . . . . . . . . . . . . . 29,499 29,399 63,715 51,880
Depreciation, depletion and amortization 11,229 10,004 22,826 19,771
-------- -------- -------- --------
Total Operating Costs and Expenses . . . 193,423 206,238 413,235 429,149
-------- -------- -------- --------
OPERATING PROFIT . . . . . . . . . . . . . 19,883 27,648 34,923 48,324
General and Administrative . . . . . . . . (3,145) (2,933) (6,183) (5,904)
Interest Expense, Net of Capitalized
Interest in 1997. . . . . . . . . . . . . (1,583) (4,055) (3,153) (8,000)
Interest Income. . . . . . . . . . . . . . 890 172 1,324 581
Other Expense, Net . . . . . . . . . . . . (941) (2,116) (2,232) (7,548)
-------- -------- -------- --------
EARNINGS BEFORE INCOME TAXES . . . . . . . 15,104 18,716 24,679 27,453
Income Tax Provision . . . . . . . . . . . 5,466 6,706 8,910 9,473
-------- -------- -------- --------
NET EARNINGS . . . . . . . . . . . . . . . $ 9,638 12,010 15,769 17,980
======== ======== ======== ========
NET EARNINGS PER SHARE . . . . . . . . . . $ .36 .45 .59 .69
======== ======== ======== ========
WEIGHTED AVERAGE COMMON AND COMMON
EQUIVALENT SHARES . . . . . . . . . . . . 26,787 26,615 26,808 26,144
======== ======== ======== ========
<FN>
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)
Six Months Ended
June 30,
----------------
1997 1996
---- ----
CASH FLOWS FROM (USED IN) OPERATING ACTIVITIES
Net earnings . . . . . . . . . . . . . . . . . . . $ 15,769 17,980
Adjustments to reconcile net earnings to net cash
from operating activities:
Depreciation, depletion and amortization. . . . . 23,140 20,170
Amortization of deferred charges and other. . . . 333 703
Changes in operating assets and liabilities:
Receivable from Tennessee Gas Pipeline Company . - (16,191)
Receivables, other trade . . . . . . . . . . . . 57,853 (9,053)
Inventories. . . . . . . . . . . . . . . . . . . 811 (1,098)
Other assets . . . . . . . . . . . . . . . . . . 673 613
Accounts payable and other current liabilities . (46,362) (2,272)
Obligation payments to State of Alaska . . . . . (2,211) (1,981)
Deferred income taxes. . . . . . . . . . . . . . 3,503 6,293
Other liabilities and obligations. . . . . . . . 3,841 1,591
--------- ---------
Net cash from operating activities. . . . . . . 57,350 16,755
--------- ---------
CASH FLOWS FROM (USED IN) INVESTING ACTIVITIES
Capital expenditures . . . . . . . . . . . . . . . (44,799) (29,285)
Acquisition of Coastwide Energy Services, Inc. . . - (7,720)
Other. . . . . . . . . . . . . . . . . . . . . . . (143) (2,428)
--------- ---------
Net cash used in investing activities . . . . (44,942) (39,433)
--------- ---------
CASH FLOWS FROM (USED IN) FINANCING ACTIVITIES
Borrowings, net of repayments of $2,000 in 1997 and
$45,400 in 1996, under revolving credit facilities 2,182 15,000
Payments of long-term debt . . . . . . . . . . . . (2,293) (1,914)
Purchase of treasury stock . . . . . . . . . . . . (530) -
Other. . . . . . . . . . . . . . . . . . . . . . . 293 1,145
--------- ---------
Net cash from (used in) financing activities. (348) 14,231
--------- ---------
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS . . 12,060 (8,447)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD . . 22,796 13,941
--------- ---------
CASH AND CASH EQUIVALENTS AT END OF PERIOD . . . . . $ 34,856 5,494
========= =========
SUPPLEMENTAL CASH FLOW DISCLOSURES
Interest paid, net of $114 capitalized in 1997 . . $ 1,326 6,311
========= =========
Income taxes paid. . . . . . . . . . . . . . . . . $ 18,872 2,623
========= =========
<FN>
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, 1996.
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 to
conform to the current presentation of financial information.
NOTE 2 - ACQUISITION
In July 1997, the Company purchased the interests held by Zapata Exploration
Company ("Zapata"), a wholly-owned subsidiary of Zapata Corporation, in two
jointly held contract blocks (Block 18 and Block 20) in southern Bolivia.
Zapata held a 25% interest in Block 18 and a 27.4% interest in Block 20. The
purchase price was approximately $20 million, which included working capital and
assumption of certain liabilities. The assignments of interests are subject to
approval by the Bolivian government; however, the Company acquired immediate
beneficial interest in respect to the contract blocks. The Company now holds a
100% interest in Block 18 and in Block 20. The Company's net proved Bolivian
reserves, which were estimated to be 253 billion cubic feet equivalent at 1996
year-end, will increase more than 30% as a result of the acquisition.
NOTE 3 - HYDROCRACKER EXPANSION AND FINANCING
During the third quarter of 1997, the Company has scheduled an expansion of the
hydrocracker unit at its Alaska refinery. The expansion, which has an estimated
cost of approximately $17 million, will improve the Company's refinery feedstock
and product slate beginning in the fourth quarter of 1997. In conjunction with
the expansion and other initiatives, including a turnaround and catalyst change,
downtimes ranging from 14 to 25 days for various refinery units are anticipated
during the 1997 third quarter.
In July 1997, the National Bank of Alaska ("NBA") and the Company entered into a
loan agreement ("Hydrocracker Loan"), under which NBA and the Alaska Industrial
Development and Export Authority ("AIDEA") will loan the Company an amount not
to exceed the lesser of (i) 90% of the total cost of the hydrocracker expansion
or (ii) $16.2 million. One-half of the loan will be funded by NBA and the other
half will be funded by AIDEA. The Hydrocracker Loan matures on April 1, 2005
and requires 28 equal quarterly principal payments beginning April 1998 together
with interest at the unsecured 90-day commercial paper rate (5.63% at June 30,
1997) plus 2.6% per annum on the amount borrowed from NBA and the unsecured
90-day commercial paper rate plus 2.35% per annum on the amount borrowed from
AIDEA, each to be adjusted quarterly. The Hydrocracker Loan is secured by a
second lien on the refinery. Under the terms of the Hydrocracker Loan, the
Company is required to maintain specified levels of working capital and tangible
net worth. The Company will borrow the full amount under the Hydrocracker Loan
when the hydrocracker expansion is operationally complete.
6
NOTE 4 - COMMITMENTS AND CONTINGENCIES
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 the 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 and other potentially responsible parties at the Abbeville,
Louisiana site. The Company expects, based on these discussions, that its
liability 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 June 30, 1997, the Company's accruals for environmental expenses amounted to
$9.1 million, which included a noncurrent liability of approximately $3.3
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 of
approximately $6 million in 1997 and $3 million in 1998. The Company also
expects to spend approximately $6 million by the year 2002 for secondary
containment systems for existing storage tanks in Alaska.
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.
NOTE 5 - STOCKHOLDERS' EQUITY
STOCK REPURCHASE PROGRAM
On May 7, 1997, the Company's Board of Directors authorized the repurchase of up
to 3 million shares (approximately 11% of the current outstanding shares) of
Tesoro Common Stock in a buyback program that will extend through the end of
1998. Under the program, subject to certain conditions, the Company may
repurchase from time to time Tesoro Common Stock in the open market and through
privately negotiated transactions. Purchases will depend on price, market
conditions and other factors and will be made primarily from cash flows. The
repurchased Common Stock is accounted for as treasury stock and may be used for
employee benefit plan requirements and other corporate purposes. For further
information on the repurchase program and related restrictions, see "Capital
Resources and Liquidity" in Management's Discussion and Analysis of Financial
Condition and Results of Operations in Item 2 herein.
INCENTIVE COMPENSATION STRATEGY
In June 1996, the Company's Board of Directors unanimously approved a special
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 twelve
complete months and certain executives have been granted, from the Company's
Amended and Restated
7
Executive Long-Term 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 - ACCOUNTING PRONOUNCEMENTS
In February 1997, the Financial Accounting Standards Board ("FASB") issued
Statement of Financial Accounting Standards ("SFAS") No. 128, "Earnings Per
Share." SFAS No. 128, which establishes standards for computing and presenting
earnings per share, is effective for interim period and annual financial
statements ending after December 15, 1997 and requires restatement of earnings
per share data presented in prior periods. Early adoption is not permitted.
The Company believes that the adoption of SFAS No. 128 will not materially
impact its earnings per share disclosures.
In June 1997, the FASB issued SFAS No.130, "Reporting Comprehensive Income," and
SFAS No.131, "Disclosures about Segments of an Enterprise and Related
Information." Both Statements become effective for periods beginning after
December 15, 1997 with early adoption permitted. The Company is evaluating the
effects these Statements will have on its financial reporting and disclosures.
The Statements will have no effect on the Company's results of operations,
financial position, capital resources or liquidity.
8
Item 2. TESORO PETROLEUM CORPORATION AND SUBSIDIARIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
RESULTS OF OPERATIONS - THREE AND SIX MONTHS ENDED JUNE 30, 1997 COMPARED TO
THREE AND SIX MONTHS ENDED JUNE 30, 1996
SUMMARY
Net earnings of $9.7 million, or $.36 per share, for the three months ended June
30, 1997 ("1997 quarter") compare with net earnings of $12.0 million, or $.45
per share, for the three months ended June 30, 1996 ("1996 quarter"). For the
year-to-date period, net earnings of $15.8 million, or $.59 per share, for the
six months ended June 30, 1997 ("1997 period") compare with net earnings of
$18.0 million, or $.69 per share, for the six months ended June 30, 1996 ("1996
period"). Results for the 1996 quarter and period included revenues from sales
of natural gas at above-market prices under a contract with Tennessee Gas
Pipeline Company ("Tennessee Gas") which was terminated effective October 1,
1996. Results of operations in 1997 and future years will no longer include
above-market revenues from this contract. Significant items, including the
impact of the Tennessee Gas contract, which affect the comparability between
results for 1997 and 1996 are highlighted in the table below (in millions except
per share amounts):
Three Months Ended Six Months Ended
June 30, June 30,
------------------ --------------
1997 1996 1997 1996
---- ---- ---- ----
Net Earnings As Reported . . . . . . . . . . . . . . . . $ 9.7 12.0 15.8 18.0
------ ------ ------ ------
Significant Items Affecting Comparability, Pretax:
Operating profit from excess of Tennessee Gas contract
prices over spot market prices. . . . . . . . . . . - 8.2 - 16.1
Income from collection of Bolivian receivable. . . . . 2.2 - 2.2 -
Income from retroactive severance tax refunds. . . . . .2 - 1.8 5.0
Costs of shareholder consent solicitation resolved
in April 1996 . . . . . . . . . . . . . . . . . . . - - - (2.3)
Employee terminations, restructuring costs and other . - (1.7) - (3.8)
------ ------ ------ ------
Total Significant Items, Pretax . . . . . . . . . . 2.4 6.5 4.0 15.0
Income Tax Effect . . . . . . . . . . . . . . . . . .7 2.0 1.2 3.9
------ ------ ------ ------
Total Significant Items, Aftertax . . . . . . . . . 1.7 4.5 2.8 11.1
------ ------ ------ ------
Net Earnings Excluding Significant Items . . . . . . . $ 8.0 7.5 13.0 6.9
====== ====== ====== ======
Net Earnings Per Share As Reported. . . . . . . . . . . $ .36 .45 .59 .69
Significant Items Affecting Comparability, Per Share,
Aftertax:
Impact of Tennessee Gas contract prices over
spot market prices. . . . . . . . . . . . . . . . . - (.22) - (.46)
Effect of other significant items. . . . . . . . . . . (.06) .05 (.10) .03
------ ------ ------ ------
Net Earnings Per Share Excluding Significant Items. . .. $ .30 .28 .49 .26
====== ====== ====== ======
As shown above, excluding the significant items, net earnings would have been
$8.0 million ($.30 per share) in the 1997 quarter as compared to $7.5 million
($.28 per share) in the 1996 quarter. The resulting increase in net earnings in
the 1997 quarter was primarily attributable to improvements in refining and
marketing operations and lower corporate interest expense, partially offset by
lower natural gas production and spot market prices. For the year-to-date
periods, excluding significant items, net earnings would have been $13.0 million
($.49 per share) for the 1997 period compared to $6.9 million ($.26 per share)
for the 1996 period. The increase in the 1997 period was primarily due to
higher spot market natural gas prices, better refined product margins and lower
corporate interest expense, partially offset by lower natural gas production. A
discussion and analysis of the factors contributing to the Company's results of
operations are presented below. The Company conducts its operations in the
following business segments: Refining and Marketing, Exploration and
Production, and Marine Services.
9
REFINING AND MARKETING Three Months Ended Six Months Ended
June 30, June 30,
------------------ ----------------
(Dollars in millions except per unit amounts) 1997 1996 1997 1996
---- ---- ---- ----
Gross Operating Revenues:
Refined products. . . . . . . . . . . . . . . . . . . . . $ 153.6 149.1 309.4 295.8
Other, primarily crude oil resales and merchandise. . . . 8.2 23.3 26.8 64.3
------ ------ ------ ------
Gross Operating Revenues . . . . . . . . . . . . . . . . $ 161.8 172.4 336.2 360.1
====== ====== ====== ======
Total Operating Profit:
Gross margin. . . . . . . . . . . . . . . . . . . . . . . $ 35.9 31.4 60.6 53.8
Operating and other expenses. . . . . . . . . . . . . . . 23.9 23.0 45.4 44.8
Depreciation and amortization . . . . . . . . . . . . . . 3.2 3.0 6.3 6.0
------ ------ ------ ------
Operating Profit . . . . . . . . . . . . . . . . . . . . $ 8.8 5.4 8.9 3.0
====== ====== ====== ======
Capital Expenditures . . . . . . . . . . . . . . . . . . . $ 15.9 2.0 18.8 3.8
====== ====== ====== ======
Refinery Throughput:
Barrels per day . . . . . . . . . . . . . . . . . . . . . 52,409 51,117 50,785 48,082
% Alaska North Slope crude oil. . . . . . . . . . . . . . 82% 74% 80% 71%
Refined Products Manufactured (average daily barrels)<FN1>:
Gasoline . . . . . . . . . . . . . . . . . . . . . . . . 13,276 13,524 13,082 13,619
Middle distillates. . . . . . . . . . . . . . . . . . . . 22,074 21,570 21,620 19,877
Heavy oils and residual product . . . . . . . . . . . . . 15,644 14,621 14,929 13,420
Other . . . . . . . . . . . . . . . . . . . . . . . . . . 2,952 3,165 2,801 2,960
------ ------ ------ ------
Total Refined Products Manufactured. . . . . . . . . . . 53,946 52,880 52,432 49,876
====== ====== ====== ======
Refinery Operations - Product Spread ($/barrel)<FN1>:
Average yield value of products manufactured. . . . . . . $ 22.50 24.65 23.82 23.38
Cost of raw materials . . . . . . . . . . . . . . . . . . 17.17 19.53 19.02 18.93
------ ------ ------ ------
Refinery Product Spread. . . . . . . . . . . . . . . . . $ 5.33 5.12 4.80 4.45
====== ====== ====== ======
Non-Refinery Margin, included in operating profit
above ($ millions)<FN1><FN2> . . . . . . . . . . . . . . $ 10.5 7.6 16.5 14.9
====== ====== ====== ======
Total Segment Product Sales (average daily barrels)<FN3>:
Gasoline. . . . . . . . . . . . . . . . . . . . . . . . . 19,118 18,167 17,935 19,094
Middle distillates. . . . . . . . . . . . . . . . . . . . 26,189 28,978 26,221 29,167
Heavy oils and residual product . . . . . . . . . . . . . 21,507 10,184 19,708 13,635
------ ------ ------ ------
Total Product Sales. . . . . . . . . . . . . . . . . . . 66,814 57,329 63,864 61,896
====== ====== ====== ======
Total Segment Product Sales Prices ($/barrel):
Gasoline. . . . . . . . . . . . . . . . . . . . . . . . . $ 32.82 35.35 33.20 31.32
Middle distillates. . . . . . . . . . . . . . . . . . . . $ 26.99 28.99 29.53 27.39
Heavy oils and residual product . . . . . . . . . . . . . $ 16.43 15.30 17.22 16.76
Total Segment - Gross Margins on Total Product
Sales ($/barrel)<FN4>:
Average sales price . . . . . . . . . . . . . . . . . . . $ 25.26 28.57 26.76 26.26
Average costs of sales. . . . . . . . . . . . . . . . . . 20.34 23.21 22.37 22.03
------ ------ ------ ------
Gross margin . . . . . . . . . . . . . . . . . . . . . . $ 4.92 5.36 4.39 4.23
====== ====== ====== ======
<FN>
<FN1> Amounts reported in prior periods have been reclassified to conform with
current presentation.
<FN2> Includes margins on products purchased and resold, margins on products
sold in markets outside of Alaska, intrasegment pipeline revenues, retail
margins, and adjustments due to selling a volume and mix of products that
is different than actual volumes manufactured.
<FN3> Sources of total products sales include products manufactured at the
refinery, products drawn from inventory balances and products purchased
from third parties. The Company's purchases of refined products for
resale were approximately 10,500 and 11,900 average daily barrels for the
three months ended June 30, 1997 and 1996, respectively, and approximately
10,800 and 11,300 average daily barrels for the six months ended June 30,
1997 and 1996, respectively.
<FN4> Margins on sales of purchased products, together with the effect of
changes in inventories, are included in the gross margin on total product
sales.
10
REFINING AND MARKETING
THREE MONTHS ENDED JUNE 30, 1997 COMPARED WITH THREE MONTHS ENDED JUNE 30, 1996.
Operating profit of $8.8 million from the Company's Refining and Marketing
segment during the 1997 quarter represented a 63% improvement from the 1996
quarter. Although industry conditions were generally weak on the West Coast
during the 1997 quarter, the Company's implementation of marketing strategies
and operational improvements in Alaska contributed in part to the increased
operating profit level. The Company's sales in Alaska increased at both the
retail and wholesale levels. Gasoline sales volumes in Alaska rose 19% over the
1996 quarter. Additionally, increased in-state asphalt sales, a market entered
into in 1996, improved operating profit by approximately $.5 million over last
year's quarter. Production of jet fuel, a product in short supply in Alaska,
remained essentially the same. A catalyst change made in the 1996 third quarter
helped maintain last year's level of jet fuel output despite a higher percentage
of heavier, Alaskan North Slope crude oil processed at the Company's Alaska
refinery.
The Company achieved a refinery product spread of $5.33 per barrel in the 1997
quarter, a 4% improvement from the $5.12 per barrel spread in the 1996 quarter.
The Company's refined product yield values decreased by 9% to $22.50 per barrel
in the 1997 quarter from $24.65 per barrel in the 1996 quarter, while the
Company's feedstock costs decreased by 12% to $17.17 per barrel in the 1997
quarter from $19.53 per barrel in the 1996 quarter. Margins from non-refinery
activities increased to $10.5 million during the 1997 quarter from $7.6 million
in the 1996 quarter due primarily to lower costs associated with operations that
were discontinued in the prior year, higher margins on foreign refined product
sales, increased retail sales and the impact of a buildup of refined product
inventory in the 1996 quarter with no similar buildup in the 1997 quarter.
Revenues from sales of refined products in the Company's Refining and Marketing
segment increased due primarily to higher sales volumes, which rose 17% to
66,814 barrels per day in the 1997 quarter from 57,329 barrels per day in the
1996 quarter. Partially offsetting this increase were lower average sales
prices which fell 12% to $25.26 per barrel in the 1997 quarter, compared to
$28.57 per barrel in the 1996 quarter. Other revenues declined by $15.1 million
due to sales of previously purchased crude oil in the 1996 quarter with no
comparable sales transactions in the 1997 quarter. During the 1997 quarter, the
Company had less crude oil available for resale as refinery throughput averaged
1,292 barrels per day more than in the 1996 quarter and no spot purchases of
crude oil were made. Costs of sales decreased in the 1997 quarter due to lower
prices for crude oil and refined products.
SIX MONTHS ENDED JUNE 30, 1997 COMPARED WITH SIX MONTHS ENDED JUNE 30, 1996.
Operating profit of $8.9 million in the 1997 period compares to operating profit
of $3.0 million in the 1996 period. The Company's refinery spread of $4.80 per
barrel in the 1997 period improved 8% from the prior year period. Margins from
non-refinery activities increased to $16.5 million during the 1997 period as
compared to $14.9 million in the 1996 period due primarily to higher margins on
foreign refined product sales and increased retail sales. Revenues from sales
of refined products in the Company's Refining and Marketing segment increased by
5% during the 1997 period due to higher sales volumes and prices. Other
revenues declined by $37.5 million due to higher sales volumes of previously
purchased crude oil in the 1996 period. During the 1997 period, the Company had
less crude oil available for resale as refinery throughput averaged 2,703
barrels per day more than in the 1996 period and no spot purchases of crude oil
were made. Costs of sales decreased in the 1997 period due to lower volumes of
crude oil.
FUTURE IMPACT. Although weak market conditions existed on the West Coast during
the 1997 quarter, results from the Refining and Marketing segment improved over
the prior year. This improvement, as discussed above, was due in part to
implementation of the Company's marketing initiatives to sell more of its
products in Alaska, a market which is seasonably strong during the second
quarter of the year. These favorable in-state sales have continued into the
early part of the third quarter of 1997, as Alaska has had a warm summer. To
further increase jet fuel production, the Company has scheduled an expansion of
the refinery hydrocracker during the third quarter of 1997 at an estimated cost
of $17 million. In conjunction with the expansion and other initiatives,
including a turnaround and catalyst change, downtimes ranging from 14 to 25 days
for various refinery units are anticipated during the 1997 third quarter. The
expansion of the hydrocracker is expected to have a two-year payback period and
to favorably impact this segment's profitability beginning in the fourth quarter
of 1997. The Company is also expanding its Alaskan retail operations with the
construction of new outlets and remodeling of existing outlets. Future
profitability of this segment, however, will continue to be 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.
11
EXPLORATION AND PRODUCTION Three Months Ended Six Months Ended
June 30, June 30,
------------------ ----------------
(Dollars in millions except per unit amounts) 1997 1996 1997 1996
---- ---- ---- ----
U.S. OIL AND GAS<FN1>:
Gross operating revenues. . . . . . . . . . . . . . . . . $ 14.6 24.6 34.7 47.7
Other income, primarily retroactive severance tax
refunds . . . . . . . . . . . . . . . . . . . . . . . . .3 - 1.9 5.0
Production costs . . . . . . . . . . . . . . . . . . . . 1.8 1.1 3.5 2.5
Administrative support and other operating expenses . . . .5 .9 .9 1.9
Depreciation, depletion and amortization. . . . . . . . . 7.3 6.3 15.1 12.6
------ ------ ------ ------
Operating Profit - U.S. Oil and Gas. . . . . . . . . . . 5.3 16.3 17.1 35.7
------ ------ ------ ------
U.S. GAS TRANSPORTATION:
Gross operating revenues. . . . . . . . . . . . . . . . . 1.3 1.3 2.7 2.7
Operating expenses. . . . . . . . . . . . . . . . . . . . .1 - .2 .1
Depreciation and amortization . . . . . . . . . . . . . . - - .1 .1
------ ------ ------ ------
Operating Profit - U.S. Gas Transportation . . . . . . . 1.2 1.3 2.4 2.5
------ ------ ------ ------
BOLIVIA:
Gross operating revenues. . . . . . . . . . . . . . . . . 2.7 4.0 4.6 7.1
Other income related to collection of a receivable. . . . 2.2 - 2.2 -
Production costs. . . . . . . . . . . . . . . . . . . . . .2 .2 .4 .4
Administrative support and other operating expenses . . . .3 .8 .8 1.5
Depreciation, depletion and amortization. . . . . . . . . .3 .3 .5 .6
------ ------ ------ ------
Operating Profit - Bolivia . . . . . . . . . . . . . . . 4.1 2.7 5.1 4.6
------ ------ ------ ------
TOTAL OPERATING PROFIT - EXPLORATION AND PRODUCTION. . . . $ 10.6 20.3 24.6 42.8
====== ====== ====== ======
U.S.:
Natural gas production, net (average daily Mcf)<FN1>. . . 85,324 91,551 89,689 92,822
Average natural gas sales prices ($/Mcf) -
Spot market<FN2> . . . . . . . . . . . . . . . . . . . . $ 1.85 1.90 2.11 1.80
Average<FN1> . . . . . . . . . . . . . . . . . . . . . . $ 1.85 2.95 2.11 2.82
Average operating expenses ($/Mcfe) -
Lease operating expenses . . . . . . . . . . . . . . . . $ .19 .10 .17 .12
Severance taxes. . . . . . . . . . . . . . . . . . . . . .04 .05 .04 .03
------ ------ ------ ------
Total production costs. . . . . . . . . . . . . . . . . .23 .15 .21 .15
Administrative support . . . . . . . . . . . . . . . . . .06 .09 .06 .11
------ ------ ------ ------
Total operating expenses. . . . . . . . . . . . . . . . $ .29 .24 .27 .26
====== ====== ====== ======
Depletion ($/Mcfe). . . . . . . . . . . . . . . . . . . . $ .93 .75 .92 .74
====== ====== ====== ======
Capital expenditures. . . . . . . . . . . . . . . . . . . $ 9.2 5.9 16.2 15.4
====== ====== ====== ======
BOLIVIA:
Natural gas production, net (average daily Mcf) . . . . . 17,326 24,067 14,180 21,563
Average natural gas sales price ($/Mcf) . . . . . . . . . $ 1.25 1.36 1.28 1.34
Condensate production, net (average daily barrels) . . . 506 679 412 614
Average condensate price ($/barrel) . . . . . . . . . . . $ 16.21 16.75 17.38 16.29
Average operating expenses ($/Mcfe) -
Production costs . . . . . . . . . . . . . . . . . . . . $ .09 .08 .12 .09
Value-added taxes. . . . . . . . . . . . . . . . . . . . .01 .06 - .07
Administrative support . . . . . . . . . . . . . . . . . .23 .21 .30 .24
------ ------ ------ ------
Total operating expenses. . . . . . . . . . . . . . . . $ .33 .35 .42 .40
====== ====== ====== ======
Depletion ($/Mcfe). . . . . . . . . . . . . . . . . . . . $ .16 .13 .16 .13
====== ====== ====== ======
Capital expenditures. . . . . . . . . . . . . . . . . . . $ 2.0 2.8 6.0 4.9
====== ====== ====== ======
<FN>
<FN1> Results for 1996 included revenues from above-market pricing provisions of
a contract with Tennessee Gas which was terminated effective October 1,
1996. Operating profit for the three and six months ended June 30, 1996
included $8.2 million and $16.1 million, respectively, for the excess of
these contract prices over spot market prices. Net natural gas production
sold under the contract averaged approximately 14.6 Mmcf per day for both
the three months and six months ended June 30, 1996.
12
<FN2> Includes effects of the Company's natural gas commodity price agreements
which amounted to a loss of $.18 per Mcf for the three months ended June
30, 1996, and losses of $.10 per Mcf and $.12 per Mcf for the six months
ended June 30, 1997 and 1996, respectively.
<FN3> Mcf is defined as one thousand cubic feet; Mcfe is defined as net
equivalent one thousand cubic feet.
U.S. OIL AND GAS
THREE MONTHS ENDED JUNE 30, 1997 COMPARED WITH THREE MONTHS ENDED JUNE 30, 1996.
Operating profit of $5.3 million from the Company's U.S. oil and gas operations
in the 1997 quarter compares to operating profit of $16.3 million in the 1996
quarter. The 1996 quarter included revenues from the sale of natural gas at
above-market prices under a contract with Tennessee Gas. The excess of these
contract prices over spot market prices contributed $8.2 million to operating
profit in the 1996 quarter. Excluding the incremental value of the Tennessee
Gas contract from the 1996 quarter and a $.2 million retroactive severance tax
refund from the 1997 quarter, operating profit from the Company's U.S. oil and
gas operations would have been $5.1 million in the 1997 quarter compared to $8.1
million in the 1996 quarter. The resulting decrease of $3.0 million was
primarily due to lower spot market prices for sales of natural gas, lower
production volumes and higher depreciation and depletion.
Prices realized by the Company on spot market natural gas production decreased
to $1.85 per Mcf in the 1997 quarter from $1.90 per Mcf in the 1996 quarter. On
a weighted-average basis, the Company's natural gas sales price was $2.95 per
Mcf in the 1996 quarter due to sales under the Tennessee Gas contract. The
decrease of 6.2 Mmcf per day in the Company's natural gas production included a
17.6 Mmcf per day decline in the Bob West Field partially offset by an 11.4 Mmcf
per day production increase at other domestic fields. In June 1997, the Company
announced the discovery of the Vinegarone East Field in the Val Verde Basin in
Edwards County in Southwest Texas. The field is scheduled to start production
in the 1997 third quarter at an initial gross rate of approximately 6 Mmcf per
day and additional drilling is planned on the prospect.
Gross operating revenues from the Company's U.S. oil and gas operations, after
excluding amounts related to Tennessee Gas, decreased due to the lower spot
market prices and volumes. Production costs increased by $.7 million in the
1997 quarter due to higher per-unit lease operating expenses and severance taxes
from the Company's newer fields. Administrative support and other operating
expenses decreased by $.4 million. Depreciation and depletion increased by $1.0
million, or 16%, due to a higher depletion rate.
From time to time, the Company enters into commodity price agreements to reduce
the risk caused by fluctuation in the prices of natural gas in the spot market.
During the 1996 quarter, the Company used such agreements to set the price of
33% of the natural gas production that it sold in the spot market and recognized
a loss of $1.2 million ($.18 per Mcf) related to these price agreements. The
Company did not have any such transactions during the 1997 quarter and, as of
June 30, 1997, has no remaining price agreements for the year.
SIX MONTHS ENDED JUNE 30, 1997 COMPARED WITH SIX MONTHS ENDED JUNE 30, 1996.
Operating profit of $17.1 million from the Company's U.S. oil and gas operations
in the 1997 period compares to $35.7 million in the 1996 period. Comparability
between these periods was impacted by certain significant items. The 1996
period included operating profit of $16.1 million from the excess of Tennessee
Gas contract prices over spot market prices. Results of operations in 1997 and
future years will no longer include above-market revenues from this contract
which was terminated effective October 1, 1996. Operating profit also included
retroactive severance tax refunds of $1.8 million and $5.0 million in the 1997
and 1996 periods, respectively. Excluding the incremental value of the
Tennessee Gas contract and retroactive severance tax refunds, operating profit
from the Company's U.S. oil and gas operations would have been $15.3 million in
the 1997 period compared to $14.6 million in the 1996 period. The resulting
increase of $.7 million was primarily attributable to higher spot market prices
for sales of natural gas realized early in 1997 partially offset by higher
depreciation and depletion.
Prices realized by the Company on its spot natural gas production increased 17%
to $2.11 per Mcf in the 1997 period from $1.80 per Mcf in the 1996 period. The
1997 increase in average spot market prices was attributable to unusually high
prices received during January and February when there was cold weather combined
with below-normal natural gas storage levels. On a weighted-average basis, the
Company's natural gas sales price was $2.82 per Mcf in the 1996 period due to
sales under the Tennessee Gas contract. The Company's natural gas production
averaged 89.7 Mmcf per day in the 1997 period, a decrease of 3.2 Mmcf per day
from the 1996 period. This decrease represented a 13.8 Mmcf per day decline in
the Bob West Field production partially offset by a
13
10.6 Mmcf per day production increase from other domestic fields. Production
from the Bob West Field which accounted for 95% of the Company's total domestic
production in June 1996 has now been reduced to 80% of the total in June 1997.
Gross operating revenues from the Company's U.S. oil and gas operations, after
excluding amounts related to Tennessee Gas, increased due to the higher spot
market prices. Production costs increased by $1.0 million during the 1997
period due to higher per-unit lease operating expenses and severance taxes from
the Company's newer fields. Administrative support and other operating expenses
decreased by $1.0 million. Depreciation and depletion increased by $2.5
million, or 20%, due to a higher depletion rate.
From time to time, the Company enters into commodity price agreements to reduce
the risk caused by fluctuations in the prices of natural gas in the spot market.
In addition, from time to time the Company has entered into price agreements
with collars, under which no payments will be made by either party unless the
price falls below a designated floor price or above a designated ceiling price,
at which time the Company receives or pays the difference, respectively. During
the 1997 and 1996 periods, the Company used such agreements to set the price of
17% and 37%, respectively, of the natural gas production that it sold in the
spot market. During the 1997 and 1996 periods, the Company realized losses of
$1.6 million ($.10 per Mcf) and $1.8 million ($.12 per Mcf), respectively, from
these price agreements.
BOLIVIA
HYDROCARBONS LAW. In 1996, a new Hydrocarbons Law was passed by the Bolivian
government that significantly impacts the Company's operations in Bolivia. The
new law, among other matters, granted the Company the option to convert its
Contracts of Operation to new Shared Risk Contracts. During mid-1996, the
Company signed agreements to convert its Contracts of Operation to Shared Risk
Contracts subject to recision at the option of the Company if the Company was
not satisfied with modifications to the Bolivian fiscal law which were enacted
in November 1996. On June 19, 1997, the Company gave notice to the Bolivian
government of its intent to execute Shared Risk Contracts and the Company
expects to complete this conversion during the second half of 1997. The new
contracts extend the Company's term of operation, provide more favorable acreage
relinquishment terms and provide for a more favorable fiscal regime of royalties
and taxes. The new contract for Block 18 will extend the term of the Company's
operations for ten additional years to the year 2017. The new contract for
Block 20 extends the Company's term 21 additional years to the year 2029 for
acreage that is in the exploration phase of the contract, and 10 additional
years to the year 2018 for an area within Block 20 that is designated as being
in the development phase of the new contract. The new contract provisions,
along with a substantial discovery during 1996, significantly increased the
Company's reserves at year-end 1996.
YPFB AND YPF CONTRACT. The Company's Bolivian natural gas production is sold to
Yacimientos Petroliferos Fiscales Bolivianos ("YPFB"), which in turn sells the
natural gas to Yacimientos Petroliferos Fiscales, SA ("YPF"), a publicly-held
company based in Argentina. Currently, the Company is selling its natural gas
production to YPFB based on the volume and pricing terms in the contract between
YPFB and YPF. The contract to sell gas to YPF expired March 31, 1997 and a
contract extension was signed effective April 1, 1997 extending the contract
term two years to March 31, 1999 with an option to extend the contract a maximum
of one additional year if the pipeline from Bolivia to Brazil is not complete.
In the contract extension, YPF negotiated an 11% reduction in the minimum
contract volume it is required to import from Bolivia, which in turn resulted in
a corresponding 11% reduction of Tesoro's minimum contract volume.
ACCESS TO NEW MARKETS. A lack of market access has constrained natural gas
production in Bolivia. Ceremonies marking the official launch of construction
of a new 1,900-mile pipeline that will link Bolivia's gas reserves with markets
in Brazil were held in July 1997. First gas deliveries are expected in early
1999.
THREE MONTHS ENDED JUNE 30, 1997 COMPARED WITH THREE MONTHS ENDED JUNE 30, 1996.
Operating profit of $4.1 million from the Company's Bolivian operations in the
1997 quarter compares to operating profit of $2.7 million in the 1996 quarter.
Included in the 1997 quarter was income of $2.2 million related to the
collection of a receivable for production in 1989 through May 1996. Excluding
this income, operating profit would have decreased from the prior year period by
$.8 million due to lower production and prices. During the 1997 quarter, the
Company's Bolivian natural gas production was lower due to reduced minimum takes
under the new contract between YPFB and YPF and also due to requests in 1996
from YPFB for additional production from the Company
14
to meet export specifications. Natural gas prices for Bolivian production fell
to $1.25 per Mcf in the 1997 quarter, an 8% drop from the 1996 quarter.
Administrative support and other operating expenses decreased by $.5 million in
the 1997 quarter due primarily to reduced production levels.
SIX MONTHS ENDED JUNE 30, 1997 COMPARED WITH SIX MONTHS ENDED JUNE 30, 1996.
Operating profit of $5.1 million from the Company's Bolivian operations compares
to operating profit of $4.6 million in the 1996 period. The 1997 period
included income of $2.2 million related to the collection of a receivable for
prior years production. Excluding this income, operating profit would have
decreased by $1.7 million as production of natural gas and condensate fell by
over 30%. During the 1997 period, the Company's Bolivian natural gas production
was lower due to a reduction in minimum takes under the new contract between
YPFB and YPF and also due to constraints arising from repairs to a
non-Company-owned pipeline that transports gas from Bolivia to Argentina. A
replacement pipeline is now operational, which has restored full capacity.
During the 1996 period, production was higher due to requests from YPFB for
additional production from the Company to meet export specifications. Natural
gas prices declined to $1.28 per Mcf in the 1997 period compared to $1.34 per
Mcf in the 1996 period. Partially offsetting these decreases was a 7% rise in
condensate prices. Administrative support and other operating expenses
decreased by $.7 million in the 1997 period due primarily to reduced production
levels. After the July 1997 purchase of Zapata's interest in Block 18 and in
Block 20, the Company now holds a 100% interest in both blocks (see Note 2 of
Notes to Condensed Consolidated Financial Statements). As a result of the
acquisition, the Company's net share of production from Block 18 will increase
by approximately 33% beginning in the 1997 third quarter. Block 20 is currently
shut-in waiting on the construction of the pipeline to Brazil, which is
scheduled for first gas deliveries in early 1999.
15
MARINE SERVICES Three Months Ended Six Months Ended
June 30, June 30,
------------------ ----------------
(Dollars in millions) 1997 1996 1997 1996
---- ---- ---- ----
Gross Operating Revenues:
Fuels . . . . . . . . . . . . . . . . . . . . . . . . . $ 24.2 25.1 52.4 44.4
Lubricants and other. . . . . . . . . . . . . . . . . . 3.8 4.1 8.1 6.8
Services. . . . . . . . . . . . . . . . . . . . . . . . 2.3 2.3 5.3 3.6
------ ------ ------ ------
Gross Operating Revenues . . . . . . . . . . . . . . . 30.3 31.5 65.8 54.8
Costs of Sales . . . . . . . . . . . . . . . . . . . . . 22.4 23.6 49.7 42.2
------ ------ ------ ------
Gross Profit. . . . . . . . . . . . . . . . . . . . . . 7.9 7.9 16.1 12.6
Operating and Other Expenses . . . . . . . . . . . . . . 7.0 5.6 13.9 9.6
Depreciation and Amortization. . . . . . . . . . . . . . .4 .4 .8 .5
------ ------ ------ ------
Operating Profit . . . . . . . . . . . . . . . . . . . $ .5 1.9 1.4 2.5
====== ====== ====== ======
Sales Volumes (millions of gallons):
Fuels, primarily diesel . . . . . . . . . . . . . . . . 37.5 39.2 77.1 69.6
Lubricants. . . . . . . . . . . . . . . . . . . . . . . .7 .8 1.3 1.2
Capital Expenditures . . . . . . . . . . . . . . . . . . $ 1.1 4.3 3.3 5.0
====== ====== ====== ======
In February 1996, the Company acquired Coastwide Energy Services, Inc.
("Coastwide") and combined these operations with the Company's marine petroleum
products distribution business. Operating results from Coastwide have been
included in the Company's Marine Services segment since the date of acquisition.
Accordingly, results for the 1997 quarter and 1996 quarter include three full
months of Coastwide operations, while the 1997 period compares to a prior year
period which included only a portion of Coastwide's operations.
For the 1997 quarter, gross operating revenues declined by $1.2 million
primarily due to lower fuel sales volumes as efforts were made to minimize low
margin activities. Costs of sales experienced a correlating decrease resulting
in gross profit in the 1997 quarter that was unchanged from the prior year
quarter. Operating and other expenses increased by $1.4 million due to expenses
incurred for upgrading facilities and services.
For the 1997 period, gross operating revenues increased by $11.0 million, with
an 18% increase in fuels and lubricants revenues and a 47% increase in service
revenues. These increases were mainly due to added locations and associated
volumes stemming from the Coastwide acquisition together with internal growth
initiatives. Costs of sales during the 1997 period increased due to the higher
volumes and also included $.9 million associated with inventory valuations as
market prices declined from year-end levels. The improvement of $3.5 million in
gross profit during the 1997 period was offset by higher operating and other
expenses associated with the increased activity and upgrades to facilities and
services.
The Marine Services segment's business is largely dependent upon the volume of
oil and gas drilling, workover, construction and seismic activity in the Gulf of
Mexico.
GENERAL AND ADMINISTRATIVE
The $.3 million increase in general and administrative expense during both the
1997 quarter and period was primarily due to higher employee costs partially
offset by reduced insurance costs.
INTEREST EXPENSE AND INTEREST INCOME
Interest expense decreased by $2.6 million and $4.9 million (approximately 60%)
during the 1997 quarter and period, respectively. In November 1996, the Company
redeemed $74.1 million of public debt resulting in interest expense savings of
$2.5 million and $4.9 million in the 1997 quarter and period, respectively.
Interest income increased by $.6 million and $.7 million during the 1997 quarter
and period, respectively. During the 1997 quarter, the Company recorded
interest income of approximately $.4 million related to the collection of a
Bolivia receivable.
16
OTHER EXPENSE, NET
The decrease of $1.2 million in other expense during the 1997 quarter was
primarily due to charges incurred in the prior year quarter for environmental
and other expenses related to former operations of the Company with no material
comparable costs recorded in the current quarter. For the 1997 period, other
expense decreased by $5.3 million primarily due to charges incurred in the prior
year period for shareholder consent solicitation costs of $2.3 million, which
was resolved in April 1996, together with a write-off of deferred financing
costs and employee termination costs with no material comparable costs recorded
in the current period.
INCOME TAX PROVISION
Income taxes decreased by $1.3 million and $.6 million during the 1997 quarter
and period, respectively. These decreases were primarily due to lower taxable
earnings.
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
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. The Company uses the last-in,
first-out ("LIFO") method of accounting for inventories of crude oil and U.S.
wholesale refined products. This method results in inventory carrying amounts
that are less likely to represent current values and in costs of sales which
more closely represent current costs.
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. The Company may increase or decrease its natural gas
production in response to market conditions. The carrying value of oil and
natural gas assets may be subject to noncash writedowns based on changes in
natural gas prices and other determining factors.
Changes in natural gas prices also influence the level of drilling activity in
the Gulf of Mexico. The Company's Marine Services operation, whose customers
include offshore drilling contractors and related industries, could be impacted
by significant fluctuations in natural gas prices. The Company's Marine
Services segment uses the first-in, first-out ("FIFO") method of accounting for
its inventories of fuel. Changes in fuel prices can significantly impact
inventory valuations and costs of sales in this segment.
CAPITAL RESOURCES AND LIQUIDITY
OVERVIEW
The Company's primary sources of liquidity are its cash and cash equivalents,
internal cash generation and external financing. Accomplishments in 1996,
including the resolution of litigation with Tennessee Gas and termination of the
remainder of the Tennessee Gas Contract combined with redemption of public debt,
strengthened the Company's financial condition and improved its ability to
access capital markets. During the first half of 1997, the Company has built on
these strengths making capital expenditures totaling $45 million, with no
significant borrowings, and maintaining a debt-to-capitalization ratio of 20%.
Subsequently, in July 1997, the Company purchased additional contract interests
in the Company's Bolivian operations for approximately $20 million, which was
funded by cash flows from operations (see Note 2 of Notes to Condensed
Consolidated Financial Statements). In July 1997, the Company increased its
external borrowing capacity with a loan agreement to finance an expansion of the
refinery hydrocracker unit (see Note 3 of Notes to Condensed Consolidated
Financial Statements).
The Company is focused on its strategic plans to make operational improvements
and continues to assess its asset base in order to maximize returns and develop
full value through strategic diversification and acquisitions in all of its
operating segments. This ongoing assessment includes, in the Exploration and
Production segment, evaluating ways in which the Company could diversify its oil
and gas reserve base and offset the impact of declining production through
domestic development, exploration and acquisition outside of the Bob West Field.
17
In the Refining and Marketing segment, the Company has been engaged in studies
to improve profitability and has also evaluated possible joint ventures,
strategic alliances or business combinations; such evaluations have not resulted
in any transaction but operating strategies have been developed to optimize the
product and feedstock slates, improve efficiencies and reliability, and expand
marketing to increase placement of products in Alaska. In the Marine Services
segment, the Company continues to pursue opportunities for expansion as well as
optimizing existing operations.
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
risks that are beyond the control of the Company. These risks 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 as well as borrowings
under its credit facility and other sources of capital will be affected by these
conditions.
STOCK REPURCHASE PROGRAM
On May 7, 1997, the Company's Board of Directors authorized the repurchase of up
to 3 million shares (approximately 11% of the current outstanding shares) of
Tesoro Common Stock in a buyback program that will extend through the end of
1998. Under the program, subject to certain conditions, the Company may
repurchase from time to time Tesoro Common Stock in the open market and through
privately negotiated transactions. Purchases will depend on price, market
conditions and other factors and will be made primarily from cash flows. The
repurchased Common Stock is accounted for as treasury stock and may be used for
employee benefit plan requirements and other corporate purposes. Repurchases of
Common Stock are subject to the restricted payments provision of the Credit
Facility as described below.
CREDIT ARRANGEMENTS
The Company has financing and credit arrangements with a consortium of nine
banks under a corporate revolving credit agreement ("Credit Facility") which
provides total commitments of $150 million. The Credit Facility, which extends
through April 2000, provides for cash borrowings up to $100 million and issuance
of letters of credit, subject to a borrowing base (which was approximately $118
million at June 30, 1997). The Company, at its option, has currently activated
total commitments of $100 million. 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 limit the incurrence
of additional indebtedness and restricted payments. At June 30, 1997, the
Company had outstanding letters of credit of $32 million with no cash borrowings
outstanding. Cash borrowings made under the Credit Facility were minimal during
the 1997 period.
The terms of the Credit Facility allow for the payment of cash dividends and
open market stock repurchases subject to a cumulative amount available for
restricted payments (defined as the difference of (i) the sum since December 31,
1995, of (a) $5 million and (b) 50% of consolidated net earnings of the Company
in any calendar year and (ii) any restricted payments made since June 1996). At
June 30, 1997, the cumulative amount available for restricted payments was
approximately $50 million. Annually, however, the aggregate of cash dividends
and other restricted payments cannot exceed a maximum of $5 million. In
addition, the Credit Facility permits the Company to repurchase a limited amount
of Common Stock up to $5 million annually, specifically for oddlot buyback
programs and employee benefit plans. While the Board of Directors has no
present plans to pay dividends, from time to time the Board of Directors
reevaluates the feasibility of declaring future dividends.
In addition to the Credit Facility, a subsidiary of the Company has a three-year
line of credit with a bank which provides up to $10 million for the purchase of
real estate and equipment for the Company's Marine Services segment at the
bank's prime rate. The loan facility is not guaranteed by the Company and is
secured only by such real estate and equipment that are financed. Beginning in
March 1998, credit availability is reduced quarterly by 6.667%. At June 30,
1997, $ 3.1 million was outstanding under the loan facility.
18
During the third quarter of 1997, the Company has scheduled an expansion of the
hydrocracker unit at its Alaska refinery at an estimated cost of approximately
$17 million. In July 1997, NBA and the Company entered into the Hydrocracker
Loan, under which NBA and the AIDEA will loan the Company an amount not to
exceed the lesser of (i) 90% of the total cost of the hydrocracker expansion or
(ii) $16.2 million. The Hydrocracker Loan matures on April 1, 2005 and is
secured by a second lien on the refinery. Under the terms of the Hydrocracker
Loan, the Company is required to maintain specified levels of working capital
and tangible net worth. The Company will borrow the full amount under the
Hydrocracker Loan when the hydrocracker expansion is operationally complete.
See Note 3 of Notes to Condensed Consolidated Financial Statements.
CAPITAL SPENDING
For the year 1997, the Company projects its capital expenditures to total $161
million, of which $45 million had been spent during the first half of 1997. The
Company has financed these capital expenditures, together with the purchase of
additional contract interests in Bolivia in July 1997, with available cash
reserves and internally-generated cash flows from operations. In addition, the
Company has obtained outside financing, as discussed above, for an expansion of
the refinery hydrocracker. The remaining capital expenditures for the year are
expected to be funded by cash flows from operations and external borrowings
under the Company's credit arrangements.
The Exploration and Production segment accounts for $102 million of the
projected capital expenditures, with $73 million planned for U.S. activities and
$29 million in Bolivia. Planned U.S. expenditures include $30 million for
property acquisitions; $15 million for development drilling (participation in 16
wells) and workovers; $11 million for leasehold, geological and geophysical; and
$15 million for exploratory drilling (participation in 18 wells). For the first
half of 1997, actual U.S. expenditures were $16 million, principally for
participation in the drilling of 3 development wells (all completed) and 6
exploratory wells (4 completed). In Bolivia, projected capital expenditures of
$29 million for the year include an increase for the purchase of contract
interests which was consummated in July 1997 (see Note 2 of Notes to Condensed
Consolidated Financial Statements). The projection in Bolivia includes $3
million for one exploratory well and $2 million for workovers and field
facilities, with the remainder planned for three-dimensional seismic and the
purchase of contract interests. Capital spending for the first half of 1997
totaled $6 million in Bolivia, primarily for exploratory drilling, seismic
activity and workovers. Although the Company continues to pursue exploratory,
development and acquisition opportunities, actual capital expenditures for the
remainder of the year may vary from projections due to a number of factors,
including the timing of drilling projects and the extent to which properties are
acquired.
Capital spending for the Refining and Marketing segment is projected to be $50
million for the year, including $17 million for expansion of the refinery
hydrocracker and $20 million towards a three-year capital program to build new
retail outlets and remodel existing stations. During the first half of 1997,
the Refining and Marketing segment had spent approximately $19 million towards
these capital projects.
In the Marine Services segment, capital spending for 1997 is currently projected
at $8 million, a $21 million reduction from the original budget. This
projection, of which $3 million was spent during the first half of 1997, is now
primarily directed towards expansion and improvement of operations along the
Gulf of Mexico rather than acquisitions.
19
CASH FLOWS
Components of the Company's cash flows are set forth below (in millions):
Six Months Ended
June 30,
----------------
1997 1996
---- ----
Cash Flows From (Used In):
Operating Activities . . . . . . . . . . . . . . $ 57.4 16.7
Investing Activities . . . . . . . . . . . . . . (45.0) (39.4)
Financing Activities . . . . . . . . . . . . . . (.3) 14.2
------ ------
Increase (Decrease) in Cash and Cash Equivalents . $ 12.1 (8.5)
====== ======
Net cash from operating activities of $57 million during the 1997 period, which
compares to $17 million during the 1996 period, included a $58 million decrease
in receivables due in part to collections related to high product and crude oil
sales volumes at 1996 year-end and to a Bolivian receivable representing
production sold from 1989 through May 1996. These receipts were partially
offset by income tax and other payments. Net cash used in investing activities
of $45 million during the 1997 period included capital expenditures of $22
million for the Company's Exploration and Production activities, $19 million for
Refining and Marketing operations and $3 million for Marine Services. Net cash
used in financing activities during the 1997 period included borrowings under a
loan facility for the Marine Services sector partially offset by payments of
other long-term debt and purchases of treasury stock. At June 30, 1997, the
Company's net working capital totaled $97 million, which included cash and cash
equivalents of $35 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 June 30, 1997, the Company's accruals for environmental
expenses amounted to $9.1 million, which included a noncurrent liability of $3.3
million for remediation of KPL's 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 of approximately $6 million
in 1997 and $3 million in 1998. The Company also expects to spend approximately
$6 million by the year 2002 for secondary containment systems for existing
storage tanks in Alaska.
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 4 of Notes to Condensed Consolidated
Financial Statements.
FORWARD-LOOKING STATEMENTS
Statements in this Quarterly Report on Form 10-Q, including those contained in
the foregoing discussion and other items herein, concerning the Company 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
20
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 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.
21
PART II - OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
On June 21, 1997, the Company received a letter from the Office of the
Attorney General of the State of Alaska ("State") alleging that Kenai Pipe
Line Company ("KPL"), a wholly-owned subsidiary of the Company, failed to
follow the terms of its Oil Discharge Prevention and Contingency Plan
("Contingency Plan"), which allegation arose out of the State's
investigation of a December 5, 1995 spill into the Cook Inlet from KPL's
facility. The State has proposed that KPL (i) pay $100,000 to the State as
a civil penalty and to reimburse the State for its costs; and (ii)
establish an escrow fund in the amount of $75,000 for an audit of KPL's
Contingency Plan. The Company is addressing this allegation with the
Attorney General's office with respect to resolving the issues raised in
the June 21, 1997 letter.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
(a) The 1997 Annual Meeting of Stockholders of the Company was held on May
7, 1997.
(b) The following directors were elected at the 1997 Annual Meeting of
Stockholders to hold office until the 1998 Annual Meeting of
Stockholders or until their successors are elected and qualified. A
tabulation of the number of votes cast for or withheld with respect to
each such director are set forth below:
Votes Votes
Name For Withheld
---------------------- ---------- --------
Steven H. Grapstein 23,980,740 145,192
William J. Johnson 23,975,240 150,692
Alan J. Kaufman 23,980,203 145,729
Raymond K. Mason, Sr. 23,966,892 159,040
Bruce A. Smith 23,981,728 144,204
Patrick J. Ward 23,981,120 144,812
Murray L. Weidenbaum 23,964,890 161,042
(c) With respect to the ratification of the appointment of Deloitte &
Touche LLP as the Company's independent auditors for fiscal year 1997,
there were 24,006,124 votes for; 36,084 votes against; 83,724
abstentions; and no broker non-votes.
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
(a) Exhibits
See the Exhibit Index immediately preceding the exhibits filed
herewith.
(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: August 14, 1997 /s/ BRUCE A. SMITH
Bruce A. Smith
Chairman of the Board of Directors,
President and Chief Executive Officer
Date: August 14, 1997 /s/ DON E. BEERE
Don E. Beere
Vice President, Controller
(Chief Accounting Officer)
23
EXHIBIT INDEX
EXHIBIT
NUMBER
27 Financial Data Schedule.
24