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, 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
(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 26,329,156 shares of the Registrant's Common Stock outstanding at
July 31, 1996.
TESORO PETROLEUM CORPORATION AND SUBSIDIARIES
INDEX TO FORM 10-Q
FOR THE QUARTERLY PERIOD ENDED JUNE 30, 1996
PART I. FINANCIAL INFORMATION Page
Item 1. Financial Statements (Unaudited)
Condensed Consolidated Balance Sheets - June 30, 1996 and
December 31, 1995 . . . . . . . . . . . . . . . . . . . . . 3
Condensed Statements of Consolidated Operations - Three
Months and Six Months Ended June 30, 1996 and 1995. . . . . 4
Condensed Statements of Consolidated Cash Flows - Six Months
Ended June 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 . . . . . . . . . . . . . . . . . . 22
Item 2. Changes in Securities . . . . . . . . . . . . . . . . 23
Item 4. Submission of Matters to a Vote of Security Holders . 24
Item 6. Exhibits and Reports on Form 8-K. . . . . . . . . . . 24
SIGNATURES . . . . . . . . . . . . . . . . . . . . . . . . . . . 25
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,
1996 1995 <F1>
---- ----
ASSETS
CURRENT ASSETS:
Cash and cash equivalents. . . . . . . . . . $ 5,494 13,941
Receivables, less allowance for doubtful
accounts of $2,156 ($1,842 at
December 31, 1995). . . . . . . . . . . . . 94,525 77,534
Receivable from Tennessee Gas Pipeline
Company (Note 5). . . . . . . . . . . . . . 66,871 -
Inventories:
Crude oil and wholesale refined products,
at LIFO. . . . . . . . . . . . . . . . . . 72,734 70,406
Merchandise and retail refined products . . 5,393 5,153
Materials and supplies. . . . . . . . . . . 4,669 4,894
Prepayments and other. . . . . . . . . . . . 9,603 10,536
---------- ----------
Total Current Assets. . . . . . . . . . . . 259,289 182,464
---------- ----------
PROPERTY, PLANT AND EQUIPMENT:
Refining and marketing . . . . . . . . . . . 325,707 322,023
Exploration and production:
Oil and gas (full cost method of accounting) 145,484 124,954
Gas transportation. . . . . . . . . . . . . 6,703 6,703
Marine services. . . . . . . . . . . . . . . 32,024 12,757
Corporate. . . . . . . . . . . . . . . . . . 12,347 12,443
---------- ----------
522,265 478,880
Less accumulated depreciation, depletion
and amortization . . . . . . . . . . . . . 237,396 217,191
---------- ----------
Net Property, Plant and Equipment . . . . 284,869 261,689
---------- ----------
RECEIVABLE FROM TENNESSEE GAS PIPELINE COMPANY
(Note 5). . . . . . . . . . . . . . . . . . . - 50,680
OTHER ASSETS . . . . . . . . . . . . . . . . . 28,652 24,320
---------- ----------
TOTAL ASSETS. . . . . . . . . . . . . . . $ 572,810 519,153
========== ==========
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES:
Accounts payable . . . . . . . . . . . . . . $ 60,867 61,389
Accrued liabilities. . . . . . . . . . . . . 37,101 34,073
Current portion of long-term debt and other
obligations. . . . . . . . . . . . . . . . 9,681 9,473
---------- ----------
Total Current Liabilities . . . . . . . . . 107,649 104,935
---------- ----------
DEFERRED INCOME TAXES. . . . . . . . . . . . . 11,682 5,389
---------- ----------
OTHER LIABILITIES. . . . . . . . . . . . . . . 38,428 37,308
---------- ----------
LONG-TERM DEBT AND OTHER OBLIGATIONS, LESS
CURRENT PORTION. . . . . . . . . . . . . . . 168,599 155,007
---------- ----------
COMMITMENTS AND CONTINGENCIES (Note 5)
STOCKHOLDERS' EQUITY:
Common Stock, par value $.16-2/3; authorized
50,000,000 shares; 26,292,778 shares issued
and outstanding (24,780,134 in 1995). . . . 4,382 4,130
Additional paid-in capital . . . . . . . . . 188,305 176,599
Retained earnings. . . . . . . . . . . . . . 53,765 35,785
---------- ----------
Total Stockholders' Equity. . . . . . . . . 246,452 216,514
---------- ----------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY $ 572,810 519,153
========== ==========
<FN>
The accompanying notes are an integral part of these condensed consolidated
financial statements.
<F1> 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 Six Months Ended
June 30, June 30,
------------------ ----------------
1996 1995 1996 1995
---- ---- ---- ----
REVENUES:
Refining and marketing. . . . . . . $ 172,327 207,602 360,106 392,649
Exploration and production. . . . . 29,936 35,337 57,457 67,121
Marine services . . . . . . . . . . 31,525 21,216 54,807 38,381
Other income. . . . . . . . . . . . 98 6 5,103 22
--------- --------- --------- ---------
Total Revenues . . . . . . . . . . 233,886 264,161 477,473 498,173
--------- --------- --------- ---------
OPERATING COSTS AND EXPENSES:
Refining and marketing. . . . . . . 163,890 207,224 351,147 393,955
Exploration and production. . . . . 2,945 4,951 6,351 9,797
Marine services . . . . . . . . . . 29,399 21,632 51,880 40,031
Depreciation, depletion and
amortization . . . . . . . . . . . 10,004 11,177 19,771 22,841
--------- --------- --------- ---------
Total Operating Costs and Expenses 206,238 244,984 429,149 466,624
--------- --------- --------- ---------
OPERATING PROFIT . . . . . . . . . . 27,648 19,177 48,324 31,549
General and Administrative . . . . . (2,933) (4,185) (5,904) (7,999)
Interest Expense . . . . . . . . . . (4,055) (5,368) (8,000) (10,661)
Interest Income. . . . . . . . . . . 172 188 581 424
Other Expense, Net . . . . . . . . . (2,116) (933) (7,548) (1,964)
--------- --------- --------- ---------
Earnings Before Income Taxes . . . . 18,716 8,879 27,453 11,349
Income Tax Provision . . . . . . . . 6,706 1,423 9,473 2,133
--------- --------- --------- ---------
NET EARNINGS . . . . . . . . . . . . $ 12,010 7,456 17,980 9,216
========= ========= ========= =========
EARNINGS PER SHARE . . . . . . . . . $ .45 .30 .69 .37
========= ========= ========= =========
WEIGHTED AVERAGE OUTSTANDING COMMON
AND COMMON EQUIVALENT SHARES. . . . 26,615 25,206 26,144 25,163
========= ========= ========= =========
<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,
----------------
1996 1995
---- ----
CASH FLOWS FROM (USED IN) OPERATING ACTIVITIES:
Net earnings . . . . . . . . . . . . . . . . . $ 17,980 9,216
Adjustments to reconcile net earnings to net
cash from operating activities:
Depreciation, depletion and amortization. . . 20,170 23,327
Amortization of deferred charges and other. . 703 788
Changes in operating assets and liabilities:
Receivable from Tennessee Gas Pipeline
Company. . . . . . . . . . . . . . . . . . (16,191) (17,647)
Receivables, other trade. . . . . . . . . . (9,053) 8,917
Inventories . . . . . . . . . . . . . . . . (1,098) 6,146
Other assets. . . . . . . . . . . . . . . . 613 (7,304)
Accounts payable and other current
liabilities. . . . . . . . . . . . . . . . (2,272) 5,855
Obligation payments to State of Alaska. . . (1,981) (1,316)
Other liabilities and obligations . . . . . 7,884 1,461
---------- ----------
Net cash from operating activities. . . . 16,755 29,443
---------- ----------
CASH FLOWS USED IN INVESTING ACTIVITIES:
Capital expenditures . . . . . . . . . . . . . (29,285) (32,758)
Acquisition of Coastwide Energy Services, Inc. (7,720) -
Other. . . . . . . . . . . . . . . . . . . . . (2,428) (2,157)
---------- ----------
Net cash used in investing activities . . (39,433) (34,915)
---------- ----------
CASH FLOWS FROM (USED IN) FINANCING ACTIVITIES:
Borrowings, net of repayments of $45,400 in
1996 and $159,500 in 1995, under revolving
credit facilities. . . . . . . . . . . . . . 15,000 -
Payments of long-term debt . . . . . . . . . . (1,914) (1,200)
Other. . . . . . . . . . . . . . . . . . . . . 1,145 10
---------- ----------
Net cash from (used in) financing
activities . . . . . . . . . . . . . . . 14,231 (1,190)
---------- ----------
DECREASE IN CASH AND CASH EQUIVALENTS . . . . . (8,447) (6,662)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD. 13,941 14,018
---------- ----------
CASH AND CASH EQUIVALENTS AT END OF PERIOD . . . $ 5,494 7,356
========== ==========
SUPPLEMENTAL CASH FLOW DISCLOSURES:
Interest paid. . . . . . . . . . . . . . . . . $ 6,311 9,013
========== ==========
Income taxes paid . . . . . . . . . . . . . . $ 2,623 2,389
========== ==========
<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") are
unaudited but, in the opinion of management, incorporate all adjustments
necessary for a fair presentation of results for such periods. Such adjustments
are of a normal recurring nature. 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. 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.
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 includes 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 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 - 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 and expires June 30, 1999. The Company,
at its option, has currently activated $100 million of these commitments, which
includes cash borrowing availability of $50 million at June 30, 1996. The
Credit Facility, which is subject to a borrowing base, provides for the issuance
of letters of credit and cash borrowings. Under the Credit Facility, cash
borrowings are limited to the lesser amount of (a) 50% of the active facility
amount or (b) the borrowing base attributable to domestic oil and gas reserves
(which has most recently been determined to be $45 million) plus $10 million.
At June 30, 1996, the Company had outstanding cash borrowings of $15 million and
letters of credit of $52 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.
Cash borrowings under the Credit Facility bear interest at the prime rate plus
.75% per annum or the London Interbank Offered Rate ("LIBOR") plus 1.75%. Fees
on outstanding letters of credit under the Credit Facility are 1.75% 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 a
restricted payment covenant which limits the payment of dividends.
The Credit Facility contains certain provisions that are contingent upon the
issuance of a mandate favorable to the Company by the Texas Supreme Court with
respect to the request for rehearing by Tennessee Gas ("Mandate Event") and
collection of the related bonded receivable ("Collection Event") (see Note 5).
In these regards, the Credit Facility provides, among other items, for an
extension of the expiration date to April 30, 2000 upon occurrence of the
Mandate Event and an increase in cash borrowing availability to $100 million
upon occurrence
6
of both the Mandate Event and the Collection Event. In addition, the Credit
Facility provides for reductions in fees on letters of credit and lower interest
rates on cash borrowings, subject to occurrence of the Mandate Event. After the
Mandate Event, the Credit Facility would allow dividends up to $5 million per
year, subject to the restricted payment covenant.
During the six months ended June 30,1996, the Company's gross borrowings under
its revolving credit line totaled $60 million which were used on a short-term
basis to finance working capital requirements and capital expenditures.
Repayments of these borrowings totaled $45 million for the six months ended June
30, 1996.
NOTE 4 - INCENTIVE COMPENSATION STRATEGY
In June 1996, the Company's Board of Directors unanimously approved an incentive
compensation strategy that provides eligible employees with added 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 Incentive
Plan, a total of 340,000 stock options at an exercise price of $11.375 per share
and 350,000 shares of restricted Common Stock, all of which vest only upon
achieving the Performance Target.
NOTE 5 - COMMITMENTS AND CONTINGENCIES
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 ("Tennessee Gas Contract") which 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 in the District Court of
Bexar County, Texas, alleging that the Tennessee Gas 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. During the month of June 1996, the Contract Price was $8.56 per
Mcf and the average spot market price was $2.14 per Mcf. For the six months
ended June 30, 1996, approximately 16% of the Company's net U.S. natural gas
production was sold under the Tennessee Gas Contract. 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. On appeal by Tennessee Gas, the Court of Appeals for the Fourth Supreme
Judicial District of Texas affirmed the validity of the Tennessee Gas Contract
as to the Company's properties and held that the price payable by Tennessee Gas
for the gas was the Contract Price. The Court of Appeals remanded the case to
the trial court based on its determination (i) that the Tennessee Gas Contract
was an output contract and (ii) that a fact issue existed as to whether the
increases in the volumes of gas tendered to Tennessee Gas under the contract
were made in bad faith or were unreasonably disproportionate to prior tenders.
The Company sought review of the appellate court ruling on the output contract
issue in the Supreme Court of Texas. Tennessee Gas also sought review of the
appellate court ruling denying the remaining Tennessee Gas claims in the Supreme
Court of Texas. The appellate court decision was the first decision reported in
Texas holding that a take-or-pay contract was an output contract. The Supreme
Court of Texas heard arguments in December 1994 regarding the output contract
issue and certain of the issues raised by Tennessee Gas. On August 1, 1995, the
Supreme Court of Texas, in a divided opinion, affirmed the decision of the
appellate court on all issues, including that the price under the Tennessee Gas
Contract is the Contract Price, and determined that the Tennessee Gas Contract
was an output contract and remanded the case to the trial court for
determination of whether gas volumes tendered by the Company to Tennessee Gas
were tendered in good faith
7
and were not unreasonably disproportionate to any normal or otherwise comparable
prior output or stated estimates in accordance with the UCC. The Company filed
a motion for rehearing before the Texas Supreme Court on the issue of whether
the Tennessee Gas Contract is an output contract. On April 18, 1996, the Texas
Supreme Court reversed its earlier ruling on the output contract issue and held
that the Tennessee Gas Contract was not an output contract and affirmed its
earlier decision in favor of the Company on all other issues. On June 3, 1996,
Tennessee Gas filed a motion for rehearing and on June 10, 1996, the Company
filed its response to Tennessee Gas' motion for rehearing. An order from the
Texas Supreme Court on Tennessee Gas' motion for rehearing is pending. The
Company believes that, if this issue is tried, the gas volumes tendered to
Tennessee Gas will be found to have been in good faith and otherwise in
accordance with the requirements of the UCC. However, there can be no assurance
as to the ultimate outcome at trial.
In conjunction with the District Court judgment and on behalf of all sellers
under the Tennessee Gas Contract, Tennessee Gas is presently required to post a
supersedeas bond in the amount of $206 million. Under the terms of this bond,
for the period September 17, 1994 through April 30, 1996, Tennessee Gas was
required to take at least its entire monthly take-or-pay obligation and pay for
gas taken at $3.00 per Mmbtu, which approximates $3.00 per Mcf ("Bond Price").
The $206 million bond represents an amount which together with anticipated sales
of natural gas at the Bond Price will equal the anticipated value of the
Tennessee Gas Contract from September 17, 1994 through April 30, 1996. Except
for the period September 17, 1994 through August 13, 1995, the difference
between the spot market price and the Bond Price is refundable in the event
Tennessee Gas ultimately prevails in the litigation. The Company retains the
right to receive the Contract Price for all gas sold to Tennessee Gas. The bond
shall remain in place until the Supreme Court issues its mandate on Tennessee
Gas' motion for rehearing. Tennessee Gas continues to take its minimum monthly
required amount of gas and has resumed paying the Contract Price to the Company
for gas taken beginning with May 1996 volumes.
Through June 30, 1996, under the Tennessee Gas Contract, the Company recognized
cumulative net revenues in excess of spot market prices totaling approximately
$133.3 million. Of the $133.3 million incremental net revenues, the Company has
received $11.1 million that is nonrefundable and $62.6 million which the Company
could be required to repay in the event of an adverse ruling. The remaining
$59.6 million of incremental net revenues represents the unpaid difference
between the Contract Price and the Bond Price as described above and is included
in the $66.9 million classified in the Company's Consolidated Balance Sheet as a
current receivable at June 30, 1996. An adverse outcome of this litigation
could require the Company to reverse as much as $122.2 million of the
incremental revenues and could require the Company to repay as much as $62.6
million for amounts received above spot prices, plus interest if awarded by the
court.
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 June 30, 1996, the Company's accruals for environmental matters amounted to
$10 million, which included a noncurrent liability of approximately $4 million
for remediation of Kenai Pipe Line Company's ("KPL")
8
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 be
required to make capital improvements in 1996 of approximately $3 million,
primarily for the removal and 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 has applied 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.
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. Current severance taxes will not be recorded for
production from exempt wells during 1996.
9
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, 1996 COMPARED WITH
THREE AND SIX MONTHS ENDED JUNE 30, 1995
Net earnings of $12.0 million, or $.45 per share, for the three months ended
June 30, 1996 ("1996 quarter") compare with net earnings of $7.4 million, or
$.30 per share, for the three months ended June 30, 1995 ("1995 quarter"). Net
earnings of $18.0 million, or $.69 per share, for the six months ended June 30,
1996 ("1996 period") compare with net earnings of $9.2 million, or $.37 per
share, for the six months ended June 30, 1995 ("1995 period"). The increases in
net earnings during the 1996 quarter and period were attributable to improved
operating profit levels, together with reduced general and administrative
expenses and interest expense. Partly offsetting these improvements in the 1996
quarter and period were increased other expenses and a higher effective tax
rate. A discussion and analysis of the factors contributing to the Company's
results of operations are presented below.
10
Refining and Marketing Three Months Ended Six Months Ended
June 30, June 30,
------------------ ----------------
(Dollars in millions except per unit 1996 1995 1996 1995
amounts) ---- ---- ---- ----
Gross Operating Revenues:
Refined products . . . . . . . . . . . $ 149.1 169.7 295.8 323.3
Other, primarily crude oil resales and
merchandise. . . . . . . . . . . . . 23.3 37.8 64.3 69.3
-------- -------- -------- --------
Gross Operating Revenues. . . . . . . $ 172.4 207.5 360.1 392.6
======== ======== ======== ========
Operating Profit (Loss):
Gross margin - refined products. . . . $ 27.9 18.9 47.6 34.0
Gross margin - other . . . . . . . . . 3.5 3.1 6.2 5.6
-------- -------- -------- --------
Gross margin. . . . . . . . . . . . . 31.4 22.0 53.8 39.6
Operating and other expenses . . . . . 23.0 21.7 44.8 40.9
Depreciation and amortization. . . . . 3.0 3.0 6.0 6.0
-------- -------- -------- --------
Operating Profit (Loss) . . . . . . . $ 5.4 (2.7) 3.0 (7.3)
======== ======== ======== ========
Capital Expenditures . . . . . . . . . . $ 2.0 3.0 3.8 5.3
======== ======== ======== ========
Refinery Operations - Throughput (average
daily barrels). . . . . . . . . . . . . 51,117 47,971 48,082 46,778
======== ======== ======== ========
Refinery Operations - Production (average
daily barrels):
Gasoline . . . . . . . . . . . . . . . 13,524 13,779 13,619 13,277
Middle distillates and other . . . . . 24,723 21,395 22,780 21,554
Heavy oils and residual product. . . . 14,633 14,347 13,477 13,391
-------- -------- -------- --------
Total Refinery Production . . . . . . 52,880 49,521 49,876 48,222
======== ======== ======== ========
Refinery Operations - Product Spread
($/barrel) <F1>:
Average yield value of products
manufactured. . . . . . . . . . . . . $ 25.14 20.70 23.58 20.22
Cost of raw materials. . . . . . . . . 19.35 17.87 18.68 17.33
-------- -------- -------- --------
Refinery Product Spread . . . . . . . $ 5.79 2.83 4.90 2.89
======== ======== ======== ========
Refining and Marketing - Total Product
Sales (average daily barrels):
Gasoline . . . . . . . . . . . . . . . 18,167 26,996 19,094 25,172
Middle distillates . . . . . . . . . . 28,978 37,725 29,167 37,970
Heavy oils and residual product. . . . 10,184 13,552 13,635 13,684
-------- -------- -------- --------
Total Product Sales . . . . . . . . . 57,329 78,273 61,896 76,826
======== ======== ======== ========
Refining and Marketing - Total Product
Sales Prices ($/barrel):
Gasoline . . . . . . . . . . . . . . . $ 35.35 28.76 31.32 27.87
Middle distillates . . . . . . . . . . $ 28.99 24.51 27.39 24.09
Heavy oils and residual product. . . . $ 15.30 12.35 16.76 12.50
Refining and Marketing - Gross Margins
on Total Product Sales ($/barrel) <F1>:
Average sales price. . . . . . . . . . $ 28.57 23.87 26.26 23.27
Average costs of sales . . . . . . . . 23.21 21.20 22.03 20.82
-------- -------- -------- --------
Gross margin . . . . . . . . . . . . $ 5.36 2.67 4.23 2.45
======== ======== ======== ========
<FN>
<F1> 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 11,900 and
28,700 average daily barrels for the three months ended June 30, 1996 and
1995, respectively, and 11,300 and 26,900 average daily barrels for the six
months ended June 30, 1996 and 1995, respectively.
11
Three Months Ended June 30, 1996 Compared With Three Months Ended June 30, 1995.
The Company's Refining and Marketing segment returned to profitability during
the 1996 quarter with operating profit of $5.4 million, as compared to a loss of
$2.7 million in the 1995 quarter. 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 refined product yield values increased by 21%, from
$20.70 per barrel in the 1995 quarter to $25.14 per barrel in the 1996 quarter,
while the Company's feedstock costs increased by only 8%, from $17.87 per barrel
in the 1995 quarter to $19.35 per barrel in the 1996 quarter.
In the Company's Refining and Marketing segment, revenues from sales of refined
products were lower in the 1996 quarter due to a 27% decrease in sales volumes.
Total refined product sales volumes averaged 57,329 barrels per day in the 1996
quarter as compared to 78,273 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
11,900 barrels per day in the 1996 quarter as compared to 28,700 barrels per day
in the 1995 quarter. The Company plans to sell three Company-owned facilities
and is in the process of discontinuing certain operations in California. In
addition, resales of crude oil in the 1996 quarter declined to $15.2 million, as
compared to $29.7 million in the 1995 quarter, due primarily to increased
throughput levels at the Company's refinery during the current quarter. The
decrease in revenues was partially offset by a 20% increase in the Company's
average sales price of refined products. Costs of sales were lower in the 1996
quarter due to the lower volumes of refined products, partially offset by higher
prices for refined products and crude oil. The $1.3 million increase in
operating expenses was primarily related to environmental matters.
Six Months Ended June 30, 1996 Compared With Six Months Ended June 30, 1995.
For the 1996 period, the Company's Refining and Marketing segment returned to
profitability with operating profit of $3.0 million, as compared to a loss of
$7.3 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
17%, from $20.22 per barrel in the 1995 period to $23.58 per barrel in the 1996
period, while the Company's average feedstock costs increased by only 8%, from
$17.33 per barrel in the 1995 period to $18.68 per barrel in the 1996 period.
In the Company's Refining and Marketing segment, revenues from sales of refined
products decreased in the 1996 period due primarily to a 19% decline in sales
volumes. Total refined product sales averaged 61,896 barrels per day in the
1996 period as compared to 76,826 barrels per day in the 1995 period. This
decline, as discussed above, reflected the Company's withdrawal from the West
Coast market, which also reduced refined product purchases from other refiners
and suppliers to 11,300 barrels per day in the 1996 period from 26,900 in the
1995 period. In addition, the Company resales of crude oil also decreased from
$54.8 million in the 1995 period to $49.7 million in the 1996 period. These
decreases in sales volumes were partially offset by a 13% increase in the
Company's average sales price of refined products. Costs of sales were lower in
the 1996 period due to lower volumes of refined product, partially offset by
higher prices for crude oil and refined products. Operating expenses increased
by $3.9 million primarily due to employee termination costs in the 1996 period
together with the impact of a reduction in an environmental accrual in the 1995
period.
Although the Company's results from its Refining and Marketing segment improved
during the 1996 quarter and period, future profitability of this segment will
continue to be dependent on 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 Six Months Ended
June 30, June 30,
------------------ ----------------
(Dollars in millions except per unit amounts) 1996 1995 1996 1995
---- ---- ---- ----
U.S. Oil and Gas:
Gross operating revenues . . . . . . . . . . $ 24.6 30.5 47.7 58.6
Other income - severance tax refunds . . . . - - 5.0 -
Production costs . . . . . . . . . . . . . . 1.1 3.3 2.5 6.7
Administrative support and other
operating expenses. . . . . . . . . . . . . .9 .7 1.9 1.2
Depreciation, depletion and amortization . . 6.3 8.0 12.6 16.6
-------- -------- -------- --------
Operating Profit - U.S. Oil and Gas. . . . 16.3 18.5 35.7 34.1
-------- -------- -------- --------
U.S. Gas Transportation:
Gross operating revenues . . . . . . . . . . 1.3 1.7 2.7 2.7
Operating expenses . . . . . . . . . . . . . - .1 .1 .1
Depreciation and amortization. . . . . . . . - .1 .1 .1
-------- -------- -------- --------
Operating Profit - U.S. Gas Transportation. 1.3 1.5 2.5 2.5
-------- -------- -------- --------
Bolivia:
Gross operating revenues . . . . . . . . . . 4.0 3.2 7.1 5.8
Production costs . . . . . . . . . . . . . . .2 .1 .4 .3
Administrative support and other
operating expenses. . . . . . . . . . . . . .8 .8 1.5 1.5
Depreciation, depletion and amortization . . .3 - .6 -
-------- -------- -------- --------
Operating Profit - Bolivia. . . . . . . . . 2.7 2.3 4.6 4.0
-------- -------- -------- --------
Total Operating Profit - Exploration and
Production. . . . . . . . . . . . . . . . . . $ 20.3 22.3 42.8 40.6
======== ======== ======== ========
U.S.:
Capital expenditures . . . . . . . . . . . . $ 5.9 13.0 15.4 27.0
======== ======== ======== ========
Net natural gas production (average daily Mcf) -
Spot market and other . . . . . . . . . . . 76,898 121,811 78,269 101,157
Tennessee Gas Contract<F1>. . . . . . . . . 14,653 20,401 14,553 22,988
-------- -------- -------- --------
Total production. . . . . . . . . . . . . 91,551 142,212 92,822 124,145
======== ======== ======== ========
Average natural gas sales ($/Mcf) -
Spot market<F2> . . . . . . . . . . . . . . $ 1.90 1.35 1.80 1.31
Tennessee Gas Contract<F1>. . . . . . . . . $ 8.45 8.36 8.31 8.30
Average . . . . . . . . . . . . . . . . . . $ 2.95 2.36 2.82 2.61
Average operating expenses ($/Mcf) -
Lease operating expenses. . . . . . . . . . $ .10 .09 .12 .12
Severance taxes . . . . . . . . . . . . . . .05 .16 .03 .18
-------- -------- -------- --------
Total production costs. . . . . . . . . . .15 .25 .15 .30
Administrative support. . . . . . . . . . . .09 .05 .11 .05
-------- -------- -------- --------
Total operating expenses. . . . . . . . . $ .24 .30 .26 .35
======== ======== ======== ========
Depletion ($/Mcf). . . . . . . . . . . . . . $ .75 .62 .74 .74
======== ======== ======== ========
Bolivia:
Capital expenditures . . . . . . . . . . . . $ 2.8 - 4.9 -
Net natural gas production (average daily Mcf) 24,067 19,715 21,563 18,321
Average natural gas sales price ($/Mcf). . . $ 1.36 1.30 1.34 1.28
Net condensate production
(average daily barrels) . . . . . . . . . . 679 610 614 581
Average condensate price ($/barrel). . . . . $ 16.75 15.69 16.29 15.22
Average operating expenses ($/Mcfe) -
Production costs. . . . . . . . . . . . . . $ .08 .09 .09 .09
Value-added taxes . . . . . . . . . . . . . .06 .05 .07 .04
Administrative support. . . . . . . . . . . .21 .30 .24 .32
-------- -------- -------- --------
Total operating expenses. . . . . . . . . $ .35 .44 .40 .45
======== ======== ======== ========
Depletion ($/Mcfe) . . . . . . . . . . . . . $ .13 - .13 -
======== ======== ======== ========
<FN>
<F1> The Company is involved in litigation with Tennessee Gas relating to a
natural gas sales contract. See "Capital Resources and
Liquidity--Tennessee Gas Contract," "Legal Proceedings--Tennessee Gas
Contract" and Note 5 of Notes
13
to Condensed Consolidated Financial Statements.
<F2> Includes effects of the Company's natural gas price swap agreements which
amounted to a loss of $.18 per Mcf and a gain of $.01 per Mcf for the
three months ended June 30, 1996 and 1995, respectively, and a loss of
$.12 per Mcf and a gain of $.03 per Mcf for the six months ended June 30,
1996 and 1995, respectively.
<F3> Mcf is defined as one thousand cubic feet; Mcfe is defined as net
equivalent one thousand cubic feet.
United States
Three Months Ended June 30, 1996 Compared With Three Months Ended June 30, 1995.
Operating profit of $16.3 million from the Company's U.S. oil and gas producing
operations in the 1996 quarter compares to $18.5 million in the 1995 quarter.
The comparability between these two quarters was impacted by several items,
including amounts recorded in the 1995 quarter related to certain interests that
have since been sold, while the 1996 quarter excludes current severance taxes on
production from exempt wells.
Operating profit from the Company's sales of natural gas in the spot market rose
19% during the 1996 quarter, as higher prices more than offset a reduction in
volumes. Prices for the Company's natural gas sales in the spot market
increased 41%, from $1.35 per Mcf in the 1995 quarter to $1.90 per Mcf in the
1996 quarter. The Company's weighted average sales price, including the
above-market pricing of the Tennessee Gas Contract, increased 25%, from $2.36
per Mcf in the 1995 quarter to $2.95 per Mcf in the 1996 quarter. Included in
the 1995 quarter were spot market natural gas production averaging 43.7 Mmcf per
day, revenues of $5.6 million and operating profit of $2.5 million related to
certain interests in the Bob West Field that were sold during the third quarter
of 1995. Excluding amounts related to the sold interests from the 1995 quarter,
operating profit from spot market sales rose 124% on essentially unchanged
volumes. Volumes sold under the above-market contract with Tennessee Gas
declined 28% during the 1996 quarter due to an expected decline in contract
deliverability.
Revenues from the Company's U.S. oil and gas operations decreased by $5.9
million during the 1996 quarter due to the lower production volumes sold into
the spot market and lower volumes sold to Tennessee Gas, partially offset by the
increases in the Company's sales prices. Total production costs were lower in
the 1996 quarter primarily due to the lower volumes and the exclusion of
severance taxes on exempt wells. On a per Mcf basis, production costs were
reduced to $.15 per Mcf compared to $.25 per Mcf due to the exemption of
severance taxes. Total operating expenses on a per Mcf basis decreased due to
the lower production costs, partially offset by higher expenses for
administrative support. Depreciation, depletion and amortization was lower in
the 1996 quarter, primarily due to lower production volumes partly 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 quarters, the Company used such arrangements to set the price
of 33% and 25%, respectively, of the natural gas production that it sold in the
spot market. During the 1996 and 1995 quarters, the Company realized a loss of
$1.2 million (or $.18 per Mcf) and a gain of $.1 million (or $.01 per Mcf),
respectively, from these price swap arrangements.
Six Months Ended June 30, 1996 Compared With Six Months Ended June 30, 1995.
Operating profit of $35.7 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.
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. Current severance taxes
will not be recorded for production from exempt wells during 1996. Included in
the 1995 period were spot market natural gas production averaging 35.8 Mmcf per
day, revenues of $8.6 million and operating profit of $2.9 million related to
certain interests in the Bob West Field that were sold during the third quarter
of 1995. 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 operations would have decreased $.5
million, relatively unchanged from the 1995 period.
Prices for sales of the Company's natural gas production into the spot market
increased 37%, from $1.31 per Mcf
14
in the 1995 period compared to $1.80 per Mcf in the 1996 period. The Company's
weighted average sales price, including the effect of the above-market pricing
of the Tennessee Gas Contract, increased from $2.61 per Mcf in the 1995 period
to $2.82 per Mcf in the 1996 period. The Company's U.S. natural gas production
sold into the spot market in the 1996 period was lower than the 1995 period due
to the sale of certain interests in the third quarter of 1995. Excluding the
impact of the sold interests, natural gas production sold into the spot market
would have increased by 20%, 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. Production sold under the Tennessee Gas Contract decreased by 37%,
reflecting higher takes by Tennessee Gas during the 1995 period together with a
decline in contract deliverability during the 1996 period.
Revenues from the Company's U.S. oil and gas operations decreased by $10.9
million due to the lower volumes, partly offset by increases in the Company's
sales prices. Total production costs were lower in the 1996 period primarily
due to exemptions from severance taxes discussed above and lower production
volumes. On a per Mcf basis, production costs were reduced to $.15 per Mcf
compared to $.30 per Mcf due to the exemption of severance taxes. Total
operating expenses on a per Mcf basis declined due to the lower production
costs, partially offset by increased expenses for administrative support.
Depreciation, depletion and amortization was lower in the 1996 period due to
lower production volumes.
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 23%, 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
$1.8 million (or $.12 per Mcf) and a gain of $.5 million (or $.03 per Mcf),
respectively, from these price swap arrangements. As of June 30, 1996, the
Company has remaining price swaps totaling 3.1 billion cubic feet at an average
Houston Ship Channel price of $1.73 per Mcf. In the 1996 period, the Company's
average spot market wellhead price per Mcf was approximately $.21 less than the
average Houston Ship Channel index, the difference representing transportation
and marketing costs from the wellhead in South Texas.
Bolivia
Three Months Ended June 30, 1996 Compared With Three Months Ended June 30, 1995.
Operating profit from the Company's Bolivian operations improved by $.4 million
during the 1996 quarter primarily due to a 22% increase in natural gas
production, together with increases in the prices received for both natural gas
and condensate. The increase in the Company's natural gas production was
primarily related to increased demand from the Bolivian state-owned oil and gas
company for higher quality natural gas, in order to meet contract specifications
for its 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 20% on a per unit basis
reflecting the Company's ability to increase volumes with minimal increases in
expenses. Partially offsetting these improvements was depreciation, depletion
and amortization of $.3 million recorded in the 1996 quarter.
Six Months Ended June 30, 1996 Compared With Six Months Ended June 30, 1995.
Operating results from the Company's Bolivian operations increased by $.6
million during the 1996 period, primarily due to an 18% increase in production
of natural gas together with higher prices received for both natural gas and
condensate. Production costs and other operating expenses remained relatively
unchanged in total but declined by 11% 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 $.6 million
recorded in the 1996 period.
Bolivian Hydrocarbons Law. 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 new Shared Risk Contracts. On
July 29, 1996, the Company signed new 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
15
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 will result in an immediate increase, possibly as high
as 35%, of 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 selected certain acreage to be relinquished
in Block 20, retained its producing fields and discoveries, and continues to
hold 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 government
regulations.
Marine Services Three Months Ended Six Months Ended
June 30, June 30,
----------------- ----------------
(Dollars in millions) 1996 1995 1996 1995
---- ---- ---- ----
Gross Operating Revenues . . . . . . . . . $ 31.5 21.2 54.8 38.4
Costs of Sales . . . . . . . . . . . . . . 23.6 18.3 42.2 33.4
-------- -------- -------- --------
Gross Margin . . . . . . . . . . . . . . 7.9 2.9 12.6 5.0
Operating and Other Expenses . . . . . . . 5.6 3.3 9.6 6.6
Depreciation and Amortization. . . . . . . .4 .1 .5 .2
-------- -------- -------- --------
Operating Profit (Loss). . . . . . . . . $ 1.9 (.5) 2.5 (1.8)
======== ======== ======== ========
Capital Expenditures . . . . . . . . . . . $ 4.3 .1 5.0 .1
======== ======== ======== ========
Refined Product Sales, Primarily Diesel
Fuel (thousands of gallons). . . . . . . 39,147 32,176 69,547 58,373
======== ======== ======== ========
Three Months Ended June 30, 1996 Compared With Three Months Ended June 30, 1995.
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 improvement in operating results of the Marine Services segment in the 1996
quarter was largely attributable to a 22% increase in volumes, mainly related to
the acquisition, and improved margins, partially offset by higher operating
expenses associated with the increased activity.
Six Months Ended June 30, 1996 Compared with Six Months Ended June 30, 1995. As
discussed above, during the 1996 period, the Company acquired Coastwide and
combined Coastwide's operations with the Company's marine petroleum products
distribution business. Operating results of Coastwide have been included in the
Company's Marine Services segment, since acquisition, or approximately four
months of the 1996 period, which contributed to a 19% increase in volumes. This
increase in volumes together with improved margins were partially offset by
higher operating expenses associated with the increased activity.
General and Administrative Expenses
General and administrative expenses decreased by $1.3 million, or 31%, during
the 1996 quarter and by $2.1 million, or 26%, during the 1996 period. These
decreases were primarily due to reduced professional fees and lower employee and
labor costs resulting from cost reduction measures implemented by the Company in
late 1995.
16
Interest Expense
Interest expense decreased by $1.3 million, or 24%, during the 1996 quarter and
by $2.7 million, or 25%, during the 1996 period. In December 1995, the Company
redeemed $34.6 million of its 12-3/4% Subordinated Debentures which, together
with lower borrowings under the Company's revolving credit facility, resulted in
interest expense savings of approximately $1.4 million and $2.7 million during
the 1996 quarter and period, respectively.
Other Expense
The increase of $1.2 million in other expense during the 1996 quarter was
primarily due to environmental and other expenses related to the Company's
former operations. For the 1996 period, other expense increased by $5.6
million, primarily due to costs of $2.3 million related to a shareholder consent
solicitation, which was resolved in April 1996, together with employee
termination costs and write-off of deferred financing costs.
Income Taxes
Income taxes increased by $5.3 million and $7.4 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. tax 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
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 from each of its business segments as well as cost savings at the
corporate level. Furthermore, the Texas Supreme Court's decision in April 1996,
which is subject to a motion for rehearing, may remove a major financial
uncertainty from the Company's capital structure that could improve the
predictability of the Company's cash flow and provide for additional financial
flexibility. See "Capital Resources and Liquidity - Tennessee Gas Contract."
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 reduce the
asset concentration associated with the Bob West Field through
17
domestic development, exploration and acquisition activity outside of this area.
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 its 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).
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 and expires June 30, 1999. The Credit
Facility, which replaced a previous higher-cost $90 million facility, provides
more financial flexibility for the Company, 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 the available commitments under the Credit Facility, which includes cash
borrowing availability of $50 million at June 30, 1996. The Credit Facility,
which is subject to a borrowing base, provides for the issuance of letters of
credit and cash borrowings. Under the Credit Facility, cash borrowings are
limited to the lesser amount of (a) 50% of the active facility amount or (b) the
borrowing base attributable to domestic oil and gas reserves (which has most
recently been determined to be $45 million) plus $10 million. At June 30, 1996,
the Company had outstanding cash borrowings of $15 million and letters of credit
of $52 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 restrict the incurrence of additional
indebtedness and a restricted payment covenant which limits the payment of
dividends.
The Credit Facility contains certain provisions that are contingent upon the
issuance of a mandate favorable to the Company by the Texas Supreme Court with
respect to the request for rehearing by Tennessee Gas and collection of the
related bonded receivable. In these regards, the Credit Facility provides,
among other items, for an extension of the expiration date to April 30, 2000, an
increase in cash borrowing availability to $100 million, reductions in fees on
letters of credit, lower interest rates on cash borrowings and favorable changes
in certain restrictions and limitations. For further information regarding the
Tennessee Gas litigation and the Credit Facility, see Notes 3 and 5 of Notes to
Condensed Consolidated Financial Statements.
Debt and Other Obligations
The Company's funded debt obligations at June 30, 1996 include $30 million
principal amount of 12-3/4% Subordinated Debentures ("Subordinated Debentures"),
which is due March 15, 2001 and bears interest at 12-3/4% per annum, and $44.1
million principal amount of 13% Exchange Notes ("Exchange Notes"), which bear
interest at 13% per annum and become due December 1, 2000. The Subordinated
Debentures and Exchange Notes are redeemable at the option of the Company at
100% of principal amount, plus accrued interest. The Company continuously
reviews financing alternatives with respect to its Subordinated Debentures and
Exchange Notes and currently intends, upon a final resolution of the Tennessee
Gas litigation, to redeem the Subordinated Debentures and Exchange Notes.
However, there can be no assurance whether or when the Company would propose
other refinancings or would be able to retire such indebtedness.
The indenture governing the Subordinated Debentures contains certain covenants,
including a restriction that prevents the current payment of cash dividends on
Common Stock and currently limits the Company's ability to purchase or redeem
any shares of its capital stock. The limitation of dividend payments included
in the indenture governing the Exchange Notes is less restrictive than the
limitation imposed by the Subordinated Debentures.
18
Capital Expenditures
For the year 1996, the Company's total capital budget is approximately $84
million (excluding amounts related to the purchase of Coastwide), based upon an
outlook which includes a favorable resolution of the Tennessee Gas litigation.
The exploration and production segment accounts for $64 million of the budgeted
expenditures with $56 million planned for U.S. activities and $8 million for
Bolivia. The planned U.S. expenditures include $39 million for exploration,
development and acquisition outside of the Bob West Field and $17 million for
development drilling and facilities in the Bob West Field. In Bolivia, the
drilling program includes two exploratory wells and workovers of current
producing wells to increase deliverability. Capital spending for the refining
and marketing segment is projected to be $13 million, which includes amounts for
installation of facilities to allow the Company to produce and market asphalt in
Alaska, improvements and upgrades at the Company's refinery and convenience
store operations, and environmental projects. Capital spending for 1996 is
expected to be financed through a combination of cash flows from operations and
borrowings under the Credit Facility.
During the six months ended June 30, 1996, total capital expenditures of $29
million (excluding amounts related to Coastwide) were funded primarily by cash
flows from operations, available cash reserves and borrowings under the Credit
Facility. Capital expenditures for U.S. oil and gas activities totaled $15
million for the 1996 period, principally for participation in the drilling of
eight development wells, seven of which were completed, and four exploratory
wells, all of which were in progress at quarter-end, and the acquisition of
other working interests. In Bolivia, the Company's capital expenditures of $5
million during the 1996 period, related primarily to one exploratory well which
was completed and resulted in a discovery of oil and gas reserves, and another
exploratory well currently being completed. Capital expenditures for the
Company's refining and marketing segment totaled $4 million for the 1996 period,
primarily for installation of facilities to produce and market asphalt and for
expansion of its retail marketing facilities. The Marine Services segment's
capital spending totaled $5 million for the 1996 period primarily reflecting
efforts to improve operating efficiencies.
Cash Flows From Operating, Investing and Financing
At June 30, 1996, the Company's working capital totaled $151.6 million, which
included a receivable from Tennessee Gas of $66.9 million and cash of $5.5
million. For information on litigation related to a natural gas sales contract
and the related impact on the Company's cash flows from operations, see
"Tennessee Gas Contract" below and Note 5 of Notes to Condensed Consolidated
Financial Statements. Components of the Company's cash flows are set forth
below (in millions):
Six Months Ended
June 30,
----------------
1996 1995
---- ----
Cash Flows From (Used In):
Operating Activities . . . . . . . . . . . . . . $ 16.7 29.4
Investing Activities . . . . . . . . . . . . . . (39.4) (34.9)
Financing Activities . . . . . . . . . . . . . . 14.2 (1.2)
------- -------
Decrease in Cash and Cash Equivalents. . . . . . . $ (8.5) (6.7)
======= =======
Net cash from operating activities of $17 million during the 1996 period, which
compares to $29 million for the 1995 period, included higher net earnings
partially offset by increased working capital balances. Net cash used in
investing activities during the 1996 period of $39 million included capital
expenditures of $29 million and cash consideration of $7.7 million for the
acquisition of Coastwide. Capital expenditures for the 1996 period included $20
million for the Company's exploration and production activities in South Texas
and Bolivia. Net cash from financing activities of $14 million during the 1996
period was primarily related to an outstanding borrowing of $15 million under
the Company's Credit Facility, partially offset by payments of other long-term
debt. During the 1996 period, the Company's gross borrowings under its
revolving credit line amounted to $60 million, with repayments of $45 million.
19
Tennessee Gas 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 ("Tennessee Gas Contract") which 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 in the District Court of
Bexar County, Texas, alleging that the Tennessee Gas 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. During the month of June 1996, the Contract Price was $8.56 per
Mcf and the average spot market price was $2.14 per Mcf. For the six months
ended June 30, 1996, approximately 16% of the Company's net U.S. natural gas
production was sold under the Tennessee Gas Contract. 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. On appeal by Tennessee Gas, the Court of Appeals for the Fourth Supreme
Judicial District of Texas affirmed the validity of the Tennessee Gas Contract
as to the Company's properties and held that the price payable by Tennessee Gas
for the gas was the Contract Price. The Court of Appeals remanded the case to
the trial court based on its determination (i) that the Tennessee Gas Contract
was an output contract and (ii) that a fact issue existed as to whether the
increases in the volumes of gas tendered to Tennessee Gas under the contract
were made in bad faith or were unreasonably disproportionate to prior tenders.
The Company sought review of the appellate court ruling on the output contract
issue in the Supreme Court of Texas. Tennessee Gas also sought review of the
appellate court ruling denying the remaining Tennessee Gas claims in the Supreme
Court of Texas. The appellate court decision was the first decision reported in
Texas holding that a take-or-pay contract was an output contract. The Supreme
Court of Texas heard arguments in December 1994 regarding the output contract
issue and certain of the issues raised by Tennessee Gas. On August 1, 1995, the
Supreme Court of Texas, in a divided opinion, affirmed the decision of the
appellate court on all issues, including that the price under the Tennessee Gas
Contract is the Contract Price, and determined that the Tennessee Gas Contract
was an output contract and remanded the case to the trial court for
determination of whether gas volumes tendered by the Company to Tennessee Gas
were tendered in good faith and were not unreasonably disproportionate to any
normal or otherwise comparable prior output or stated estimates in accordance
with the UCC. The Company filed a motion for rehearing before the Texas Supreme
Court on the issue of whether the Tennessee Gas Contract is an output contract.
On April 18, 1996, the Texas Supreme Court reversed its earlier ruling on the
output contract issue and held that the Tennessee Gas Contract was not an output
contract and affirmed its earlier decision in favor of the Company on all other
issues. On June 3, 1996, Tennessee Gas filed a motion for rehearing and on June
10, 1996, the Company filed its response to Tennessee Gas' motion for rehearing.
An order from the Texas Supreme Court on Tennessee Gas' motion for rehearing is
pending. The Company believes that, if this issue is tried, the gas volumes
tendered to Tennessee Gas will be found to have been in good faith and otherwise
in accordance with the requirements of the UCC. However, there can be no
assurance as to the ultimate outcome at trial.
In conjunction with the District Court judgment and on behalf of all sellers
under the Tennessee Gas Contract, Tennessee Gas is presently required to post a
supersedeas bond in the amount of $206 million. Under the terms of this bond,
for the period September 17, 1994 through April 30, 1996, Tennessee Gas was
required to take at least its entire monthly take-or-pay obligation and pay for
gas taken at $3.00 per Mmbtu, which approximates $3.00 per Mcf ("Bond Price").
The $206 million bond represents an amount which together with anticipated sales
of natural gas at the Bond Price will equal the anticipated value of the
Tennessee Gas Contract from September 17, 1994 through April 30, 1996. Except
for the period September 17, 1994 through August 13, 1995, the difference
between the spot market price and the Bond Price is refundable in the event
Tennessee Gas ultimately prevails in the litigation. The Company retains the
right to receive the Contract Price for all gas sold to Tennessee Gas. The bond
shall remain in place until the Supreme Court issues its mandate on Tennessee
Gas' motion for rehearing. Tennessee Gas continues to take its minimum monthly
required amount of gas and has resumed paying the Contract Price to the Company
for gas taken beginning with May 1996 volumes.
20
Through June 30, 1996, under the Tennessee Gas Contract, the Company recognized
cumulative net revenues in excess of spot market prices totaling approximately
$133.3 million. Of the $133.3 million incremental net revenues, the Company has
received $11.1 million that is nonrefundable and $62.6 million which the Company
could be required to repay in the event of an adverse ruling. The remaining
$59.6 million of incremental net revenues represents the unpaid difference
between the Contract Price and the Bond Price as described above and is included
in the $66.9 million classified in the Company's Consolidated Balance Sheet as a
current receivable at June 30, 1996. An adverse outcome of this litigation
could require the Company to reverse as much as $122.2 million of the
incremental revenues and could require the Company to repay as much as $62.6
million for amounts received above spot prices, plus interest if awarded by the
court.
Environmental and Other Matters
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, 1996, the Company's accruals for environmental
matters amounted to $10 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 be
required to make capital improvements in 1996 of approximately $3 million,
primarily for the removal and 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 has applied 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.
21
PART II - OTHER INFORMATION
Item 1. Legal Proceedings
Tennessee Gas 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 ("Tennessee Gas Contract") which
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 in the District Court of Bexar County, Texas, alleging that the
Tennessee Gas 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. During the month of
June 1996, the Contract Price was $8.56 per Mcf and the average spot market
price was $2.14 per Mcf. For the six months ended June 30, 1996, approximately
16% of the Company's net U.S. natural gas production was sold under the
Tennessee Gas Contract. 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. On appeal by Tennessee Gas, the Court of Appeals for the Fourth Supreme
Judicial District of Texas affirmed the validity of the Tennessee Gas Contract
as to the Company's properties and held that the price payable by Tennessee Gas
for the gas was the Contract Price. The Court of Appeals remanded the case to
the trial court based on its determination (i) that the Tennessee Gas Contract
was an output contract and (ii) that a fact issue existed as to whether the
increases in the volumes of gas tendered to Tennessee Gas under the contract
were made in bad faith or were unreasonably disproportionate to prior tenders.
The Company sought review of the appellate court ruling on the output contract
issue in the Supreme Court of Texas. Tennessee Gas also sought review of the
appellate court ruling denying the remaining Tennessee Gas claims in the Supreme
Court of Texas. The appellate court decision was the first decision reported in
Texas holding that a take-or-pay contract was an output contract. The Supreme
Court of Texas heard arguments in December 1994 regarding the output contract
issue and certain of the issues raised by Tennessee Gas. On August 1, 1995, the
Supreme Court of Texas, in a divided opinion, affirmed the decision of the
appellate court on all issues, including that the price under the Tennessee Gas
Contract is the Contract Price, and determined that the Tennessee Gas Contract
was an output contract and remanded the case to the trial court for
determination of whether gas volumes tendered by the Company to Tennessee Gas
were tendered in good faith and were not unreasonably disproportionate to any
normal or otherwise comparable prior output or stated estimates in accordance
with the UCC. The Company filed a motion for rehearing before the Texas Supreme
Court on the issue of whether the Tennessee Gas Contract is an output contract.
On April 18, 1996, the Texas Supreme Court reversed its earlier ruling on the
output contract issue and held that the Tennessee Gas Contract was not an output
contract and affirmed its earlier decision in favor of the Company on all other
issues. On June 3, 1996, Tennessee Gas filed a motion for rehearing and on June
10, 1996, the Company filed its response to Tennessee Gas' motion for rehearing.
An order from the Texas Supreme Court on Tennessee Gas' motion for rehearing is
pending. The Company believes that, if this issue is tried, the gas volumes
tendered to Tennessee Gas will be found to have been in good faith and otherwise
in accordance with the requirements of the UCC. However, there can be no
assurance as to the ultimate outcome at trial.
In conjunction with the District Court judgment and on behalf of all sellers
under the Tennessee Gas Contract, Tennessee Gas is presently required to post a
supersedeas bond in the amount of $206 million. Under the terms of this bond,
for the period September 17, 1994 through April 30, 1996, Tennessee Gas was
required to take at least its entire monthly take-or-pay obligation and pay for
gas taken at $3.00 per Mmbtu, which approximates $3.00 per Mcf ("Bond Price").
The $206 million bond represents an amount which together with anticipated sales
of natural gas at the Bond Price will equal the anticipated value of the
Tennessee Gas Contract from September 17, 1994 through April 30, 1996. Except
for the period September 17, 1994 through August 13, 1995, the difference
between the spot market price and the Bond Price is refundable in the event
Tennessee Gas ultimately prevails in the litigation. The Company retains the
right to receive the Contract Price for all gas sold to Tennessee Gas. The bond
shall remain in place until the Supreme Court issues its mandate on Tennessee
Gas' motion for rehearing. Tennessee Gas continues to take its minimum monthly
required amount of gas and has resumed paying the Contract Price to the Company
for gas taken beginning with May 1996 volumes.
Through June 30, 1996, under the Tennessee Gas Contract, the Company recognized
cumulative net revenues in excess of spot market prices totaling approximately
$133.3 million. Of the $133.3 million incremental net revenues, the Company has
received $11.1 million that is nonrefundable and $62.6 million which the Company
22
could be required to repay in the event of an adverse ruling. The remaining
$59.6 million of incremental net revenues represents the unpaid difference
between the Contract Price and the Bond Price as described above and is included
in the $66.9 million classified in the Company's Consolidated Balance Sheet as a
current receivable at June 30, 1996. An adverse outcome of this litigation
could require the Company to reverse as much as $122.2 million of the
incremental revenues and could require the Company to repay as much as $62.6
million for amounts received above spot prices, plus interest if awarded by the
court.
Environmental Matters. As previously reported, in March 1992, the Company
received a Compliance Order and Notice of Violation from the Environmental
Protection Agency ("EPA") alleging violations by the Company of the New Source
Performance Standards under the Clean Air Act at its Alaska refinery. The
allegations included failure to install, maintain and operate monitoring
equipment over a period of approximately six years, failure to perform accuracy
testing on monitoring equipment, and failure to install certain pollution
control equipment. The Company denied these allegations. From March 1992 to
July 1993, the EPA and the Company exchanged information relevant to these
allegations. In addition, the EPA conducted an environmental audit of the
Company's refinery in May 1992. As a result of this audit, the EPA alleged
violation of certain regulations related to asbestos materials. In October
1993, the EPA referred these matters to the Department of Justice ("DOJ"). On
June 4, 1996, the U.S. District Court of Alaska approved a consent decree
between the Company and the DOJ. The decree included a penalty assessment of
$1.3 million, which was paid on July 3, 1996, and the agreement by the Company
to incur $200,000 in costs to complete a supplemental environmental project.
As previously reported, the Company, along with numerous other parties, has been
identified by the EPA as a potentially responsible party ("PRP") pursuant to the
Comprehensive Environmental Response, Compensation and Liability Act ("CERCLA")
for the Mud Superfund site in Abbeville, Louisiana (the "Site"). The Company
arranged for the disposal of a minimal amount of materials at the Site, but
CERCLA might impose joint and several liability on each PRP at the Site. The
EPA is seeking reimbursement for its response costs incurred to date at the
Site, as well as a commitment from the PRPs either to conduct future remedial
activities or to finance such activities. 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 EPA and
other PRPs involved at the Site. The Company expects, based on these
discussions, that its liability at the Site will not exceed $25,000.
Refund Claim. As previously reported, in July 1994, a former customer of the
Company ("Customer") filed suit against the Company in the United States
District Court for the District of New Mexico for a refund in the amount of
approximately $1.2 million, plus interest of approximately $4.4 million and
attorney's fees, related to a gasoline purchase from the Company in 1979. The
Customer also alleges entitlement to treble damages and punitive damages in the
aggregate amount of $16.8 million. The refund claim is based on allegations
that the Company renegotiated the acquisition price of gasoline sold to the
Customer and failed to pass on the benefit of the renegotiated price to the
Customer in violation of Department of Energy price and allocation controls then
in effect. In May 1995, the court issued an order granting the Company's motion
for summary judgment and dismissed with prejudice all the claims in the
Customer's complaint. In June 1995, the Customer filed a notice of appeal with
the U.S. Court of Appeals for the Federal Circuit. On June 13, 1996, the U.S.
Court of Appeals for the Federal Circuit issued its decision affirming the lower
court's ruling in favor of the Company.
Item 2. Changes in Securities
In June 1996, the Company entered into an Amended and Restated Credit Agreement
("Credit Facility") under which the Company is required to maintain specified
levels of consolidated working capital, tangible net worth, cash flow and
interest coverage. The Credit Facility has certain restrictions with respect to
dividends on its capital stock. For further information on the Credit Facility,
see Note 3 of Notes to Condensed Consolidated Financial Statements in Part I,
Item 1.
23
Item 4. Submission of Matters to a Vote of Security Holders
(a) The 1996 annual meeting of stockholders of the Company was held on June
6, 1996.
(b) The names of the directors elected at the meeting and 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
---- ------------ -------------
Robert J. Caverly 22,748,535 679,648
Steven H. Grapstein 22,793,629 634,554
Alan J. Kaufman 22,769,092 659,091
Raymond K. Mason, Sr. 22,748,925 679,258
Sanford B. Prater 22,771,425 656,758
Bruce A. Smith 22,691,524 736,659
Patrick J. Ward 22,800,367 627,816
Murray L. Weidenbaum 22,751,313 676,870
Effective June 6, 1996, the Company's Board of Directors elected Mr.
William J. Johnson as a director.
(c) A brief description of each matter, other than the election of
directors, voted upon at the meeting and the number of votes cast for,
against or withheld, as well as the number of abstentions and broker
non-votes as to each matter, is set forth below:
With respect to a proposal to increase the number of shares which can
be granted under the Executive Long-Term Incentive Plan and limit the
awards of restricted stock under such plan, there were 11,207,150 votes
for; 6,174,725 votes against; 5,805,905 broker non-votes; and 240,403
abstentions.
With respect to the ratification of the appointment of Deloitte &
Touche LLP as independent auditors for the Company for fiscal year
1996, there were 23,252,961 votes for; 128,568 votes against; and
46,654 abstentions.
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.
24
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, 1996 /s/ BRUCE A. SMITH
Bruce A. Smith
Chairman of the Board of Directors,
President and Chief Executive Officer
Date: August 14, 1996 /s/ WILLIAM T. VAN KLEEF
William T. Van Kleef
Senior Vice President
and Chief Financial Officer
25
EXHIBIT INDEX
Exhibit
Number
4.1 Amended and Restated Credit Agreement ("Credit Facility") dated as of
June 7, 1996 among the Company and Banque Paribas, individually, as
an Issuing Bank and as Administrative Agent, and The Bank of Nova
Scotia, individually and as Documentation Agent, and certain other
financial institutions named therein.
4.2 Amended and Restated Guaranty Agreement dated as of June 7, 1996
among various subsidiaries of the Company and Banque Paribas,
individually, as Administrative Agent and as an Issuing Bank, and
certain other financial institutions named therein, entered into in
connection with the Credit Facility.
4.3 Amended and Restated Security Agreement (Accounts and Inventory)
dated as of June 7, 1996 between the Company and Banque Paribas,
entered into in connection with the Credit Facility.
4.4 Amended and Restated Security Agreement (Accounts and Inventory)
dated as of June 7, 1996 between Tesoro Alaska Petroleum Company and
Banque Paribas, entered into in connection with the Credit Facility.
4.5 Amended and Restated Security Agreement (Accounts and Inventory)
dated as of June 7, 1996 between Tesoro Refining, Marketing & Supply
Company and Banque Paribas, entered into in connection with the
Credit Facility.
4.6 Security Agreement (Accounts and Inventory) dated as of June 7, 1996
between Kenai Pipe Line Company and Banque Paribas, entered into in
connection with the Credit Facility.
4.7 Security Agreement (Accounts and Inventory) dated as of June 7, 1996
between Tesoro Coastwide Services Company and Banque Paribas, entered
into in connection with the Credit Facility.
4.8 Security Agreement (Accounts and Inventory) dated as of June 7, 1996
between Coastwide Marine Services, Inc. and Banque Paribas, entered
into in connection with the Credit Facility.
4.9 Security Agreement (Accounts) dated as of June 7, 1996 between Tesoro
Vostok Company and Banque Paribas, entered into in connection with
the Credit Facility.
4.10 Amended and Restated Security Agreement (Pledge) dated as of June 7,
1996 by the Company in favor of Banque Paribas, entered into in
connection with the Credit Facility.
4.11 First Amendment to Deed of Trust, Security Agreement and Financing
Statement dated as of June 7, 1996 among Tesoro Alaska Petroleum
Company, TransAlaska Title Insurance Agency, Inc., as Trustee, and
Banque Paribas, as Administrative Agent, entered into in connection
with the Credit Facility.
4.12 First Amendment to Mortgage, Deed of Trust, Assignment of Production,
Security Agreement and Financing Statement dated as of June 7, 1996
from Tesoro E&P Company, L.P., entered into in connection with the
Credit Facility.
4.13 Mortgage, Deed of Trust, Assignment of Production, Security Agreement
and Financing Statement dated as of June 7, 1996 from Tesoro E&P
Company, L.P., entered into in connection with the Credit Facility.
27 Financial Data Schedule.
26