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, 1995
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 24,535,458 shares of the Registrant's Common Stock outstanding at
July 31,1995.
TESORO PETROLEUM CORPORATION AND SUBSIDIARIES
INDEX TO FORM 10-Q
FOR THE QUARTERLY PERIOD ENDED JUNE 30, 1995
PART I. FINANCIAL INFORMATION Page
Item 1. Financial Statements (Unaudited)
Condensed Consolidated Balance Sheets - June 30, 1995
and December 31, 1994 . . . . . . . . . . . . . . . . . . . . . . 3
Condensed Statements of Consolidated Operations - Three
Months and Six Months Ended June 30, 1995 and 1994 . . . . . . . . 4
Condensed Statements of Consolidated Cash Flows - Six Months
Ended June 30, 1995 and 1994 . . . . . . . . . . . . . . . . . . . 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 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,
1995 1994*
ASSETS
CURRENT ASSETS:
Cash and cash equivalents. . . . . . . . . . . . $ 7,356 14,018
Receivables, less allowance for doubtful accounts
of $1,962 ($1,816 at December 31, 1994) . . . . 64,489 73,406
Receivable from Tennessee Gas Pipeline Company
(Note 4) . . . . . . . . . . . . . . . . . . . 35,381 17,734
Inventories:
Crude oil and wholesale refined products,
at LIFO . . . . . . . . . . . . . . . . . . . 53,926 58,798
Merchandise and retail refined products . . . . 4,564 5,934
Materials and supplies. . . . . . . . . . . . . 3,867 3,570
Prepaid expenses and other . . . . . . . . . . . 13,661 8,648
--------- ---------
Total Current Assets. . . . . . . . . . . . . . 183,244 182,108
PROPERTY, PLANT AND EQUIPMENT, Net of Accumulated
Depreciation, Depletion and Amortization of
$228,708 ($205,782 at December 31, 1994) . . . . 285,623 273,334
INVESTMENT IN TESORO BOLIVIA PETROLEUM COMPANY . . 13,248 10,295
OTHER ASSETS . . . . . . . . . . . . . . . . . . . 20,487 18,623
--------- ---------
TOTAL ASSETS . . . . . . . . . . . . . . . $ 502,602 484,360
========= =========
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES:
Accounts payable . . . . . . . . . . . . . . . . $ 58,307 53,573
Accrued liabilities. . . . . . . . . . . . . . . 33,292 35,266
Current portion of long-term debt and other
obligations . . . . . . . . . . . . . . . . . . 8,694 7,404
--------- ---------
Total Current Liabilities . . . . . . . . . . . 100,293 96,243
--------- ---------
DEFERRED INCOME TAXES. . . . . . . . . . . . . . . 4,744 4,582
--------- ---------
OTHER LIABILITIES. . . . . . . . . . . . . . . . . 37,352 30,593
--------- ---------
LONG-TERM DEBT AND OTHER OBLIGATIONS, LESS
CURRENT PORTION. . . . . . . . . . . . . . . . . 189,096 192,210
--------- ---------
COMMITMENTS AND CONTINGENCIES (Notes 3 and 4)
STOCKHOLDERS' EQUITY:
Common Stock, par value $.16-2/3; authorized
50,000,000 shares; 24,539,497 shares issued
and outstanding (24,389,801 in 1994) . . . . . 4,090 4,065
Additional paid-in capital . . . . . . . . . . . 176,658 175,514
Accumulated deficit. . . . . . . . . . . . . . . ( 9,631) ( 18,847)
--------- ---------
Total Stockholders' Equity. . . . . . . . . . . 171,117 160,732
--------- ---------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY $ 502,602 484,360
========= =========
The accompanying notes are an integral part of these condensed consolidated
financial statements.
* The balance sheet at December 31, 1994 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,
------------------ ------------------
1995 1994 1995 1994
---- ---- ---- ----
REVENUES:
Gross operating revenues . . . . . . . . . . . . . $ 265,129 210,660 499,830 399,747
Interest income. . . . . . . . . . . . . . . . . . 188 452 424 975
Gain (loss) on sales of assets . . . . . . . . . . ( 9) ( 339) ( 2) 2,341
Other. . . . . . . . . . . . . . . . . . . . . . . 130 272 211 722
--------- --------- --------- ---------
Total Revenues. . . . . . . . . . . . . . . . . . 265,438 211,045 500,463 403,785
--------- --------- --------- ---------
COSTS AND EXPENSES:
Costs of sales and operating expenses . . . . . . 234,501 191,228 445,112 358,833
General and administrative . . . . . . . . . . . . 4,185 3,377 7,999 7,004
Depreciation, depletion and amortization . . . . . 11,412 7,718 23,327 14,395
Interest expense, net of $240 capitalized in 1994. 5,368 4,629 10,661 9,506
Other. . . . . . . . . . . . . . . . . . . . . . . 1,093 2,252 2,015 3,443
--------- --------- --------- ---------
Total Costs and Expenses. . . . . . . . . . . . . 256,559 209,204 489,114 393,181
--------- --------- --------- ---------
EARNINGS BEFORE INCOME TAXES AND
EXTRAORDINARY LOSS ON
EXTINGUISHMENT OF DEBT . . . . . . . . . . . . . . 8,879 1,841 11,349 10,604
Income Tax Provision . . . . . . . . . . . . . . . . 1,423 611 2,133 2,172
--------- --------- --------- ---------
EARNINGS BEFORE EXTRAORDINARY LOSS
ON EXTINGUISHMENT OF DEBT. . . . . . . . . . . . . 7,456 1,230 9,216 8,432
Extraordinary Loss on Extinguishment of Debt . . . . - - - ( 4,752)
--------- --------- --------- ---------
NET EARNINGS . . . . . . . . . . . . . . . . . . . . 7,456 1,230 9,216 3,680
Dividend Requirements on Preferred Stocks . . . . . - 791 - 2,680
--------- --------- --------- ---------
NET EARNINGS APPLICABLE TO
COMMON STOCK . . . . . . . . . . . . . . . . . . . $ 7,456 439 9,216 1,000
========= ========= ========= =========
EARNINGS (LOSS) PER PRIMARY AND
FULLY DILUTED<F1> SHARE:
Earnings Before Extraordinary Loss on
Extinguishment of Debt. . . . . . . . . . . . . . $ .30 .02 .37 .27
Extraordinary Loss on Extinguishment of Debt . . . - - - ( .22)
--------- --------- --------- ---------
Net Earnings . . . . . . . . . . . . . . . . . . . $ .30 .02 .37 .05
========= ========= ========= =========
AVERAGE OUTSTANDING COMMON AND
COMMON EQUIVALENT SHARES . . . . . . . . . . . . . 25,206 23,222 25,163 21,350
========= ========= ========= =========
<FN>
<F1> Anti-dilutive.
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,
--------------------
1995 1994
---- ----
CASH FLOWS FROM (USED IN) OPERATING ACTIVITIES:
Net earnings . . . . . . . . . . . . . . . . . . . . . $ 9,216 3,680
Adjustments to reconcile net earnings to net cash
from operating activities:
Depreciation, depletion and amortization . . . . . . 23,327 14,395
Loss on extinguishment of debt. . . . . . . . . . . . - 4,752
Loss (gain) on sales of assets . . . . . . . . . . . 2 ( 2,341)
Amortization of deferred charges and other, net . . . 786 792
Changes in assets and liabilities:
Receivables . . . . . . . . . . . . . . . . . . . . 8,917 2,767
Receivable from Tennessee Gas Pipeline Company . . . (17,647) ( 9,751)
Inventories . . . . . . . . . . . . . . . . . . . . 6,146 12,483
Investment in Tesoro Bolivia Petroleum Company . . . ( 2,953) ( 2,127)
Other assets . . . . . . . . . . . . . . . . . . . . ( 4,351) ( 1,824)
Accounts payable and other current liabilities . . . 5,855 22,103
Obligation payments to State of Alaska . . . . . . . ( 1,316) ( 1,320)
Other liabilities and obligations . . . . . . . . . 1,461 1,442
--------- ---------
Net cash from operating activities . . . . . . . . 29,443 45,051
--------- ---------
CASH FLOWS FROM (USED IN) INVESTING ACTIVITIES:
Capital expenditures . . . . . . . . . . . . . . . . . (32,758) (44,911)
Acquisition of Kenai Pipe Line Company . . . . . . . . ( 3,000) -
Proceeds from sales of assets. . . . . . . . . . . . . 1,015 2,247
Sales of short-term investments . . . . . . . . . . . - 5,952
Purchases of short-term investments. . . . . . . . . . - ( 1,974)
Other. . . . . . . . . . . . . . . . . . . . . . . . . ( 172) 3,850
--------- ---------
Net cash used in investing activities . . . . . . (34,915) (34,836)
--------- ---------
CASH FLOWS FROM (USED IN) FINANCING ACTIVITIES:
Repayments, net of borrowings of $159,500 in 1995
and $5,000 in 1994, under revolving credit facilities - ( 5,000)
Payments of long-term debt . . . . . . . . . . . . . . ( 1,200) ( 855)
Proceeds from issuance of common stock, net. . . . . . - 56,967
Repurchase of common and preferred stock . . . . . . . - (52,948)
Dividends on preferred stocks. . . . . . . . . . . . . - ( 1,684)
Costs of recapitalization and other. . . . . . . . . . 10 ( 1,985)
--------- ---------
Net cash used in financing activities. . . . . . . ( 1,190) ( 5,505)
--------- ---------
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS . . . . ( 6,662) 4,710
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD . . . . 14,018 36,596
--------- ---------
CASH AND CASH EQUIVALENTS AT END OF PERIOD . . . . . . . $ 7,356 41,306
========= =========
SUPPLEMENTAL CASH FLOW DISCLOSURES:
Interest paid, net of $240 capitalized in 1994 . . . . $ 9,013 9,229
========= =========
Income taxes paid . . . . . . . . . . . . . . . . . . $ 2,389 2,756
========= =========
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)
(1) Basis of Presentation
The interim condensed consolidated financial statements 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. The
results of operations for any interim period are not necessarily indicative of
results for the full year. 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, 1994.
(2) Acquisition
In March 1995, the Company acquired all of the outstanding stock of Kenai Pipe
Line Company ("KPL") for $3 million. The Company transports its crude oil and a
substantial portion of its refined products utilizing KPL's pipeline and marine
terminal facilities in Kenai, Alaska.
(3) Revolving Credit Facility
Under the terms of its Revolving Credit Facility, as amended, the Company is
required to maintain specified levels of working capital, tangible net worth,
consolidated cash flow and refinery cash flow, as defined. Among other matters,
the Revolving Credit Facility contains certain restrictions with respect to (i)
capital expenditures, (ii) incurrence of additional indebtedness, and (iii)
dividends on capital stock. The Revolving Credit Facility contains other
covenants customary in credit arrangements of this kind. At June 30, 1995, the
Company did not satisfy the refinery cash flow requirement, which required the
Company to obtain a waiver to the Revolving Credit Facility. Compliance with
certain financial covenants under the Revolving Credit Facility is primarily
dependent on the Company's maintenance of specified levels of cash flows from
operations, capital expenditures, levels of borrowings and the value of the
Company's domestic oil and gas reserves. Based on current depressed refinery
margins, the Company will be required to seek a waiver or an amendment to the
Revolving Credit Facility from its banks with respect to its refinery cash flow
requirement for the remainder of 1995. The Company believes it will be able to
negotiate terms and conditions with its banks under the Revolving Credit
Facility which will allow the Company to adequately finance its operations.
(4) Commitments and Contingencies
Gas Purchase and Sales Contract
The Company is selling a portion of the gas 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 June 1995, the Contract Price was in excess of $8.00 per Mcf, the Section
101 price was $4.94 per Mcf and the average spot market price was $1.56 per Mcf.
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
6
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, 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 Section 2.306 of the UCC. In
addition, the Supreme Court affirmed that the price under the Tennessee Gas
Contract is the Contract Price. The Company intends to file a motion for
rehearing before the Texas Supreme Court on the issue of whether the Tennessee
Gas Contract is an output contract. Through June 30, 1995, under the Tennessee
Gas Contract, the Company recognized cumulative revenues in excess of spot
market prices through September 17, 1994, and in excess of a nonrefundable $3.00
per Mcf bond price subsequent to September 17, 1994, totaling $86.6 million of
which $33.9 million is included in receivables. The Company and its outside
counsel are evaluating the impact of various aspects of the Supreme Court
decision. 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. An adverse outcome of this
litigation could require the Company to reverse some or all of the incremental
revenue and repay Tennessee Gas all or a portion of $52.5 million for amounts
received above spot market prices, plus interest if awarded by the court.
In September 1994, the court ordered that, effective until August 1, 1995,
Tennessee Gas (i) take at least its entire monthly take-or-pay obligation under
the Tennessee Gas Contract, (ii) pay for gas at $3.00 per Mmbtu, which
approximates $3.00 per Mcf ("Bond Price"), and (iii) post a $120 million bond
with the court representing an amount which, together with anticipated sales of
natural gas to Tennessee Gas at the Bond Price, will equal the anticipated value
of the Tennessee Gas Contract during this interim period. The Bond Price is
nonrefundable by the Company, and the Company retains the right to receive the
full Contract Price for all gas sold to Tennessee Gas. On August 10, 1995, a
hearing was held before the trial court regarding the extension of the Tennessee
Gas bond. The parties agreed and the court ordered that Tennessee Gas, for the
period August 14, 1995, until the earlier of October 16, 1995, or the date the
Supreme Court issues its rulings on motions for rehearing, (i) continue to take
at least its entire take-or-pay volume obligation, (ii) pay for gas at a price
of $3.00 per Mmbtu subject to potential refund of amounts in excess of market
prices if Tennessee Gas should ultimately prevail in the litigation, and (iii)
post a $25 million bond in addition to the $120 million bond presently in place.
Tennessee Gas had previously agreed to pay the Company the nonrefundable Bond
Price until August 14, 1995.
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 in Louisiana at which it has been
named a potentially responsible party under the Federal Superfund law. Although
this law might impose joint and several liability upon each party at the site,
the extent of the Company's allocated financial contributions to the cleanup of
this site is expected to be limited based upon the number of companies and the
volumes of waste involved. The Company believes that its liability at this site
is expected to be limited based upon the payment by the Company of a de minimis
settlement amount of $2,500 at a similar site in Louisiana. 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. In addition, the Company is holding discussions with the Department
of Justice ("DOJ") concerning the assessment of penalties with respect to
certain alleged violations of regulations promulgated under the Clean Air Act as
discussed below.
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. These allegations include failure to install, maintain and
operate
7
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. 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 is also alleging violation of certain
regulations related to asbestos materials. In October 1993, the EPA referred
these matters to the DOJ. The DOJ contacted the Company to begin negotiating a
resolution of these matters. The DOJ has indicated that it is willing to enter
into a judicial consent decree with the Company and that this decree would
include a penalty assessment. Negotiations on the penalty are in progress. The
DOJ has currently proposed a penalty assessment of approximately $2.3 million.
The Company is continuing to negotiate with the DOJ but cannot predict the
ultimate outcome of the negotiations.
At June 30, 1995, the Company's accruals for environmental matters, including
the alleged violations of the Clean Air Act, amounted to $11.3 million. Also
included in this amount is an approximate $4 million noncurrent liability for
remediation of the KPL properties, which liability 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 1995 of
approximately $2 million, primarily for the removal and upgrading of underground
storage tanks, and approximately $8 million during 1996 for the installation of
dike liners required under Alaska environmental regulations. 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.
Crude Oil Purchase Contract
The Company's contract with the State of Alaska ("State") for the purchase of
royalty crude oil expires on December 31, 1995. In May 1995, the Company
renegotiated a new three-year contract with the State for the period January 1,
1996 through December 31, 1998. The new contract provides for the purchase of
approximately 40,000 barrels per day of Alaska North Slope ("ANS") royalty crude
oil, the primary feedstock for the Company's refinery, and is priced at the
weighted average price reported to the State by a major North Slope producer for
ANS crude oil as valued at Pump Station No. 1 on the Trans Alaska Pipeline
System. Under this agreement, the Company is required to utilize in its
refinery operations volumes equal to at least 80% of the ANS crude oil to be
purchased from the State. This contract contains provisions that allow the
Company to temporarily or permanently reduce its purchase obligations.
Other
In February 1995, a lawsuit was filed in the U.S. District Court for the
Southern District of Texas, McAllen Division, by the Heirs of H.P. Guerra,
Deceased ("Plaintiffs") against the United States and Tesoro and other working
and overriding royalty interest owners to recover the oil and gas mineral estate
under 2,706.34 acres situated in Starr County, Texas. The oil and gas mineral
estate sought to be recovered underlies lands taken by the United States in
connection with the construction of the Falcon Dam and Reservoir. In their
lawsuit, the Plaintiffs allege that the original taking by the United States in
1948 was unlawful and void and the refusal of the United States to revest the
mineral estate to H.P. Guerra or his heirs was arbitrary and capricious and
unconstitutional. Plaintiffs seek (i) restoration of their oil and gas estate;
(ii) restitution of all proceeds realized from the sale of oil and gas from
their mineral estate, plus interest on the value thereof; and (iii) cancellation
of all oil and gas leases issued by the United States to Tesoro and the other
working interest owners covering their mineral estate. The lawsuit covers a
significant portion of the mineral estate in the Bob West Field; however, none
of the acreage covered is dedicated to the Tennessee Gas Contract. The Company
cannot predict the ultimate resolution of this matter but, based upon advice
from outside legal counsel, believes the lawsuit is without merit.
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
8
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. The Company cannot predict the ultimate resolution of this
matter but believes the claim is without merit.
(5) Oil and Gas Producing Activities
The Company has entered into a price swap with another company for approximately
8.25 Bcf of its anticipated U.S. natural gas production for the period April 1,
1995 through December 31, 1995 at a fixed price of approximately $1.56 per Mcf.
For the three months and six months ended June 30, 1995, the Company's average
spot market sales prices, which included the effect of this price swap, were
$1.52 and $1.48 per Mcf, respectively.
The Company's mid-year reserve report, prepared by the Company's independent
petroleum consultants, estimates that, during the first half of 1995, Tesoro's
proved domestic natural gas reserves increased 53%, from 129 Bcf of natural gas
at December 31, 1994, to 198 Bcf at June 30, 1995, after net production during
this period of approximately 23 Bcf. As a result, this change in estimate
reduced depreciation, depletion and amortization expense and increased net
earnings for the three months ended June 30, 1995 by approximately $4 million
($.16 per share).
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, reduce the asset
concentration associated with the Bob West Field and lower future capital
commitments. In these regards, the Company is evaluating offers to sell or
exchange approximately 40% of its total proved domestic natural gas reserves in
the Bob West Field. The proved reserves for which offers are being evaluated
are located in the C, D, E and F units of the Bob West Field and do not include
acreage covered by the Tennessee Gas Contract (see Note 4). No offer for a sale
or exchange has been accepted and there is no assurance that a sale or exchange
will be consummated. The Company is uncertain as to the impact of these
initiatives upon its capital resources and liquidity, if any.
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, 1995 COMPARED WITH
THREE AND SIX MONTHS ENDED JUNE 30, 1994
A consolidated summary of the Company's operations for the three and six months
ended June 30, 1995 and 1994 is presented below (in millions except per share
amounts):
Three Months Ended Six Months Ended
June 30, June 30,
------------------ ----------------
1995 1994 1995 1994
---- ---- ---- ----
Summary of Operations
Segment Operating Profit (Loss)<F1>:
Refining and Marketing . . . . . . . . . . . . . . . $ ( 2.7) ( 5.0) ( 7.3) 1.4
Exploration and Production - United States . . . . . 20.0 14.6 36.6 25.8
Exploration and Production - Bolivia . . . . . . . . 2.3 2.5 4.0 4.4
Oil Field Supply and Distribution. . . . . . . . . . ( .5) ( .4) ( 1.8) ( 1.6)
-------- ------- ------- --------
Total Segment Operating Profit. . . . . . . . . . . 19.1 11.7 31.5 30.0
Corporate and Unallocated Costs:
Interest expense . . . . . . . . . . . . . . . . . . 5.4 4.6 10.7 9.5
Interest income. . . . . . . . . . . . . . . . . . . ( .2) ( .5) ( .4) ( 1.0)
General and administrative expenses. . . . . . . . . 4.2 3.4 8.0 7.0
Other. . . . . . . . . . . . . . . . . . . . . . . . .9 2.3 1.9 3.8
-------- ------- ------- --------
Earnings Before Income Taxes and Extraordinary Loss . 8.8 1.9 11.3 10.7
Income Tax Provision . . . . . . . . . . . . . . . . . 1.4 .6 2.1 2.2
-------- ------- ------- --------
Earnings Before Extraordinary Loss . . . . . . . . . . 7.4 1.3 9.2 8.5
Extraordinary Loss on Extinguishment of Debt . . . . . - - - ( 4.8)
-------- ------- ------- --------
Net Earnings . . . . . . . . . . . . . . . . . . . . . 7.4 1.3 9.2 3.7
Dividend Requirements on Preferred Stocks. . . . . . . - .8 - 2.7
-------- ------- ------- --------
Net Earnings Applicable to Common Stock. . . . . . . . $ 7.4 .5 9.2 1.0
======== ======= ======= ========
Earnings (Loss) per Primary and Fully Diluted<F2> Share:
Earnings Before Extraordinary Loss . . . . . . . . . $ .30 .02 .37 .27
Extraordinary Loss on Extinguishment of Debt . . . . - - - ( .22)
-------- ------- ------- --------
Net Earnings . . . . . . . . . . . . . . . . . . . . $ .30 .02 .37 .05
======== ======= ======= ========
<FN>
<F1> Operating profit (loss) represents pretax earnings (loss) before certain
corporate expenses, interest income and interest expense.
<F2> Anti-dilutive.
Net earnings applicable to common stock of $7.4 million, or $.30 per share, for
the three months ended June 30, 1995 ("1995 quarter") compare with net earnings
applicable to common stock of $.5 million, or $.02 per share, for the three
months ended June 30, 1994 ("1994 quarter"). Net earnings for the 1995 quarter
included an aggregate benefit of approximately $4 million, or $.16 per share,
due to additions to the Company's proved domestic natural gas reserves which
reduced the domestic depletion rate to $.62 per Mcf, as compared to $.90 per Mcf
for the 1995 first quarter. Net earnings for the 1994 quarter were reduced by
$.8 million of dividend requirements on preferred stock. When comparing the
1995 quarter to the 1994 quarter, the increase in net earnings was primarily due
to the successful drilling program and increased natural gas production from the
Company's exploration and production operations in South Texas partially offset
by lower spot market prices for sales of natural gas. In addition, during the
1995 quarter, the Company narrowed its operating loss from the refining and
marketing segment to $2.7 million.
Net earnings applicable to common stock of $9.2 million, or $.37 per share, for
the six months ended June 30, 1995 ("1995 period") compare to net earnings
applicable to common stock of $1.0 million, or $.05 per share, for the six
months ended June 30, 1994 ("1994 period"). The comparability between these two
periods was impacted by certain significant transactions. As discussed above,
the 1995 period included an aggregate benefit of approximately $4 million
resulting from a reduced depletion rate. Net earnings for the 1994 period were
reduced by $2.7 million of dividend requirements on preferred stock. Also
included in the 1994 period was a noncash extraordinary loss of $4.8 million, or
$.22 per share, attributable to the early extinguishment of debt in connection
with a recapitalization in 1994. Earnings before the extraordinary loss were
$8.5 million, or $.27 per share, for the 1994 period. The 1994 period was
favorably impacted by a gain of $2.4 million, or $.11 per share, from the sale
of assets. Excluding these significant transactions for both periods, the
decrease in net earnings was
10
largely due to lower operating results from the Company's refining and marketing
segment and lower spot market prices for sales of natural gas, partially offset
by increased natural gas production from the Company's exploration and
production operations in South Texas.
11
Refining and Marketing Three Months Ended Six Months Ended
June 30, June 30,
------------------ ----------------
1995 1994 1995 1994
---- ---- ---- ----
(Dollars in millions except per barrel amounts)
Gross Operating Revenues:
Refined products . . . . . . . . . . . . . . . . . $ 169.7 134.8 323.3 254.1
Other, primarily crude oil resales and merchandise 37.8 31.4 69.3 62.4
--------- --------- --------- ---------
Gross Operating Revenues. . . . . . . . . . . . . $ 207.5 166.2 392.6 316.5
========= ========= ========= =========
Operating Profit (Loss):
Gross margin - refined products. . . . . . . . . . $ 18.9 15.2 34.0 38.7
Gross margin - other . . . . . . . . . . . . . . . 3.1 3.4 5.6 6.0
--------- --------- --------- ---------
Gross margin. . . . . . . . . . . . . . . . . . . 22.0 18.6 39.6 44.7
Operating expenses . . . . . . . . . . . . . . . . 21.5 20.7 40.7 40.6
Depreciation and amortization. . . . . . . . . . . 3.0 2.6 6.0 5.2
Other, including gain on asset sales . . . . . . . .2 .3 .2 ( 2.5)
--------- --------- --------- ---------
Operating Profit (Loss) . . . . . . . . . . . . . $ ( 2.7) ( 5.0) ( 7.3) 1.4
========= ========= ========= =========
Capital Expenditures . . . . . . . . . . . . . . . . $ 3.0 8.2 5.3 14.3
========= ========= ========= =========
Refining and Marketing - Total Product Sales
(average daily barrels)<F1>:
Gasoline . . . . . . . . . . . . . . . . . . . . . 26,996 21,596 25,172 22,080
Middle distillates . . . . . . . . . . . . . . . . 35,174 32,043 36,688 29,437
Heavy oils and residual product. . . . . . . . . . 16,103 13,070 14,966 14,748
--------- --------- --------- ---------
Total Product Sales . . . . . . . . . . . . . . . 78,273 66,709 76,826 66,265
========= ========= ========= =========
Refining and Marketing - Product Sales Prices
($/barrel):
Gasoline . . . . . . . . . . . . . . . . . . . . . $ 28.76 27.01 27.87 25.44
Middle distillates . . . . . . . . . . . . . . . . $ 24.72 23.48 24.18 23.85
Heavy oils and residual product. . . . . . . . . . $ 13.80 11.14 13.27 9.52
Refining and Marketing - Gross Margins on Total
Product Sales ($/barrel)<F1>:
Average sales price. . . . . . . . . . . . . . . . $ 23.87 22.20 23.27 21.19
Average cost of sales. . . . . . . . . . . . . . . 21.20 19.71 20.82 17.96
--------- --------- --------- ---------
Gross margin . . . . . . . . . . . . . . . . . . . $ 2.67 2.49 2.45 3.23
========= ========= ========= =========
Refinery Operations - Throughput
(average daily barrels) . . . . . . . . . . . . . 47,971 42,651 46,778 43,978
========= ========= ========= =========
Refinery Operations - Production
(average daily barrels):
Gasoline . . . . . . . . . . . . . . . . . . . . . 13,779 10,896 13,277 11,391
Middle distillates . . . . . . . . . . . . . . . . 19,426 18,014 19,556 17,975
Heavy oils and residual product. . . . . . . . . . 14,347 13,295 13,391 14,345
Refinery fuel. . . . . . . . . . . . . . . . . . . 1,969 1,929 1,998 1,834
--------- --------- --------- ---------
Total Refinery Production . . . . . . . . . . . . 49,521 44,134 48,222 45,545
========= ========= ========= =========
Refinery Operations - Product Spread ($/barrel)<F1>:
Yield value of products produced -
Gasoline . . . . . . . . . . . . . . . . . . . . $ 26.49 25.42 25.30 23.99
Middle distillates . . . . . . . . . . . . . . . $ 24.16 23.19 23.67 23.28
Heavy oils and residual product. . . . . . . . . $ 9.77 8.77 9.48 6.87
Average yield value of products produced . . . . . $ 20.70 19.48 20.22 18.39
Cost of raw materials. . . . . . . . . . . . . . . 17.87 16.34 17.33 14.28
--------- --------- --------- ---------
Product Spread. . . . . . . . . . . . . . . . . . $ 2.83 3.14 2.89 4.11
========= ========= ========= =========
12
<FN>
<F1> Total products sold 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 28,700 and 22,000 average daily barrels for the 1995 and 1994
quarters, respectively, and 26,900 and 20,800 average daily barrels for the
1995 and 1994 periods, respectively. The product spread presented above
represents the excess of yield value of the products produced at the refinery
over the cost of the raw materials used to manufacture such products.
Three Months Ended June 30, 1995 Compared With Three Months Ended June 30, 1994.
While the refining industry market conditions strengthened as the 1995 quarter
advanced, margins on the Company's sales of refined products remained weak. The
Company's average feedstock costs increased to $17.87 per barrel for the 1995
quarter compared with $16.34 per barrel for the 1994 quarter, while the average
yield value of the Company's refinery production increased to $20.70 per barrel
for the 1995 quarter from $19.48 for the prior year quarter. As a result, the
Company's refinery spread remained depressed in the 1995 quarter and will
continue to be depressed as long as the cost of Alaska North Slope ("ANS") crude
oil remains high relative to the price received for the Company's sales of
refined products. The start-up in December 1994 of a vacuum unit at the
Company's refinery increased the yield of higher-valued products during the 1995
quarter and period and lessened the impact of these industry conditions on the
Company's refinery spread. In addition, margins on sales of inventories and
purchased volumes combined to improve the segment's gross margins as compared
with the prior year quarter.
Revenues from sales of refined products in the 1995 quarter were higher than the
1994 quarter due to higher sales prices and a 17% increase in sales volumes. In
addition, to optimize the refinery's feedstock mix and in response to market
conditions, the Company's resales of crude oil increased by $7.0 million. Costs
of sales, likewise, were higher in the 1995 quarter due to increased prices and
volumes. Depreciation and amortization increased $.4 million in the 1995
quarter due to capital additions, primarily the vacuum unit, completed in late
1994.
Six Months Ended June 30, 1995 Compared With Six Months Ended June 30, 1994.
The Company's average feedstock costs increased to $17.33 per barrel for the
1995 period compared with $14.28 per barrel for the 1994 period, while the
average yield value of the Company's refinery production increased to $20.22 per
barrel for the 1995 period from $18.39 for the prior year period. Increased
demand for ANS crude oil for use as a feedstock in West Coast refineries
combined with an oversupply of products in Alaska and on the West Coast resulted
in higher feedstock costs for the Company relative to increases in refined
product sales prices. As a result, the Company's refined product margins were
severely depressed in the 1995 period and will continue to be depressed as long
as the cost of ANS crude oil remains high relative to the price received for the
Company's sales of refined products.
Revenues from sales of refined products in the 1995 period were higher than the
1994 period due to higher sales prices and a 16% increase in sales volumes.
Resales of crude oil increased by $7.5 million. Costs of sales, likewise, were
higher in the 1995 period due to increased prices and volumes. Depreciation and
amortization increased $.8 million in the 1995 period due to capital additions,
primarily the vacuum unit, completed in late 1994. Included in the 1994 period
was a $2.4 million gain from the sale of assets.
13
Exploration and Production Three Months Ended Six Months Ended
June 30, June 30,
------------------ ----------------
1995 1994 1995 1994
---- ---- ---- ----
(Dollars in millions except per unit amounts)
United States:
Gross operating revenues<F1> . . . . . . . . . . $ 33.2 22.8 63.0 40.2
Lifting costs. . . . . . . . 5.4 3.2 10.2 5.5
Depreciation, depletion and amortization . . . . 8.1 4.7 16.7 8.5
Other . . . . . . . . . . . ( .3) .3 ( .5) .4
---------- --------- ---------- ---------
Operating Profit - United States . . . . . . . 20.0 14.6 36.6 25.8
---------- --------- ---------- ---------
Bolivia:
Gross operating revenues . . . . . . . . . . . . 3.2 3.3 5.8 6.1
Lifting costs. . . . . . . . . . . . . . . . . . .1 .1 .3 .3
Other . . . . . . . . . . . . . . . . . . . . . .8 .7 1.5 1.4
---------- --------- ---------- ---------
Operating Profit - Bolivia. . . . . . . . . . . 2.3 2.5 4.0 4.4
---------- --------- ---------- ---------
Total Operating Profit - Exploration
and Production . . . . . . . . . . . . . . . . . $ 22.3 17.1 40.6 30.2
========== ========= ========== =========
United States:
Capital expenditures . . . . . . . . . . . . . . $ 13.0 17.7 27.0 29.4
========== ========= ========== =========
Net natural gas production (average daily Mcf) -
Spot market and other . . . . . . . . . . . . . 121,811 51,003 101,157 41,960
Tennessee Gas Contract<F1>. . . . . . . . . . . 20,401 19,902 22,988 18,052
---------- --------- ---------- ---------
Total production . . . . . . . . . . . . . . . 142,212 70,905 124,145 60,012
========== ========= ========== =========
Average natural gas sales price per Mcf -. . . .
Spot market . . . . . . . . . . . . . . . . . . $ 1.52 1.74 1.48 1.84
Tennessee Gas Contract<F1>. . . . . . . . . . . $ 8.43 7.96 8.37 7.89
Average . . . . . . . . . . . . . . . . . . . . $ 2.51 3.49 2.75 3.66
Average lifting costs per Mcf<F2>. . . . . . . . $ .42 .49 .46 .51
Depletion per Mcf. . . . . . . . . . . . . . . . $ .62 .73 .74 .78
Bolivia:
Net natural gas production (average daily Mcf) . 19,715 22,050 18,321 20,601
Average natural gas sales price per Mcf. . . . . $ 1.30 1.20 1.28 1.21
Net crude oil (condensate) production
(average daily barrels) . . . . . . . . . . . . 610 735 581 699
Average crude oil price per barrel . . . . . . . $ 15.69 13.65 15.22 12.63
Average lifting costs per net equivalent Mcf . . $ .09 .03 .09 .07
<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 4 of Notes to Condensed Consolidated Financial
Statements.
<F2> Average lifting costs for the Company's U.S. operations include such items
as severance taxes, property taxes, insurance, materials and supplies and
transportation of natural gas production through Company-owned pipelines.
Since severance taxes are based upon sales prices of natural gas, the
average lifting costs presented above include the impact of above-market
prices for sales under the Tennessee Gas Contract. Lifting costs per Mcf
of natural gas sold in the spot market were approximately $.36 and $.40 for
the 1995 and 1994 quarters, respectively, and approximately $.38 and $.42
for the 1995 and 1994 periods, respectively.
14
United States
Three Months Ended June 30, 1995 Compared With Three Months Ended June 30, 1994.
The improvement in the 1995 quarter was attributable to the continued
development of the Bob West Field in South Texas. This success was indicated in
the Company's mid-year reserve report, prepared by the Company's independent
petroleum consultants, which reflected a 53% increase in the Company's domestic
proved reserves of natural gas from 129 Bcf of natural gas at December 31, 1994,
to 198 Bcf at June 30, 1995, after net production during this period of
approximately 23 Bcf. The pre-tax net present value of the Company's proved
reserves rose 10% to $198 million from $179 million at year-end 1994. Results
for the 1995 quarter benefited by nearly $4 million in the aggregate due to the
additions to proved reserves which reduced the domestic depletion rate to $.62
per Mcf, as compared with $.90 per Mcf for the 1995 first quarter. The number
of producing wells in South Texas in which the Company has a working interest
increased to 58 wells at the end of the 1995 quarter, compared with 38 wells at
the end of the 1994 quarter. The Company's 1995 quarter results included a 101%
increase in U.S. natural gas production with a $10.4 million increase in
revenues. Revenues for natural gas sales during the 1995 quarter, however, were
adversely affected by a 28% decline in the Company's weighted average sales
price, which included a 13% drop in average spot market prices. Total lifting
costs and depreciation, depletion and amortization were higher in the 1995
quarter, compared with the 1994 quarter, due to the increased production level,
but declined on a per Mcf basis.
Tennessee Gas may elect, and from time to time has elected, not to take gas
under the Tennessee Gas Contract. The Company recognizes revenues under the
Tennessee Gas Contract based on the quantity of natural gas actually taken by
Tennessee Gas. While Tennessee Gas has the right to elect not to take gas
during any contract year, this right is subject to an obligation to pay within
60 days after the end of such contract year for gas not taken. The contract
year ends on January 31 of each year. Although the failure to take gas could
adversely affect the Company's income and cash flows from operating activities
within a contract year, the Company should recover reduced cash flows shortly
after the end of the contract year under the take-or-pay provisions of the
Tennessee Gas Contract, subject to the provisions of a bond posted by Tennessee
Gas which is discussed in "Capital Resources and Liquidity--Tennessee Gas
Contract," "Legal Proceedings--Tennessee Gas Contract" and Note 4 of Notes to
Condensed Consolidated Financial Statements.
The Company has entered into a price swap with another company for approximately
8.25 Bcf of its anticipated U.S. natural gas production for the period April 1,
1995 through December 31, 1995 at a fixed price of approximately $1.56 per Mcf.
For the three months and six months ended June 30, 1995, the Company's average
spot market sales prices, which included the effect of this price swap, were
$1.52 and $1.48 per Mcf, respectively.
Six Months Ended June 30, 1995 Compared With Six Months Ended June 30, 1994.
Results for the 1995 period included a 107% increase in U.S. natural gas
production with a $22.8 million increase in revenues. Revenues for natural gas
sales during the 1995 period, however, were adversely affected by a 25% decline
in the Company's weighted average sales price, which included a 20% drop in
average spot market prices. In response to the depressed spot market prices,
during the first quarter of the 1995 period the Company and one of its partners
initiated a voluntary reduction of natural gas production sold in the spot
market. The Company's share of this reduction was estimated to be approximately
30 Mmcf per day. In April 1995, the Company's U.S. natural gas production
levels resumed at higher rates. The Company may elect to curtail natural gas
production in the future, depending upon market conditions. Total lifting costs
and depreciation, depletion and amortization were higher in the 1995 period
compared with the 1994 period due to the increased production level, but
declined on a per Mcf basis. See discussion above for information relating to
additions to proved reserves and a price swap contract.
Bolivia
Three Months Ended June 30, 1995 Compared With Three Months Ended June 30, 1994.
Operating results from the Company's Bolivian operations decreased by $.2
million during the 1995 quarter primarily due to an 11% decline in average daily
natural gas production, partially offset by an 8% increase in the average
natural gas sales price. During the 1994 quarter, the Company benefited from
higher levels of production due to the inability of another producer to satisfy
gas supply requirements. Also offsetting the decrease in production was a $2.04
per barrel increase in the average price of condensate production. The
Company's Bolivian natural gas production is sold to Yacimientos Petroliferos
Fiscales Bolivianos ("YPFB"), which in turn sells the natural gas to
15
Yacimientos Petroliferos Fiscales, S.A. ("YPF"), a publicly-held company based
in Argentina. During 1994, the contract between YPFB and YPF was extended
through March 31, 1997, maintaining approximately the same volumes as the
previous contract. Currently, the Company is selling its natural gas production
to YPFB based on the volume and pricing terms in the contract between YPFB and
YPF.
Six Months Ended June 30, 1995 Compared With Six Months Ended June 30, 1994.
Operating results from the Company's Bolivian operations decreased by $.4
million during the 1995 period, primarily due to an 11% decrease in production
of natural gas, partially offset by a 6% increase in natural gas prices. As
discussed above, the 1994 period benefited from higher production levels due to
the inability of another producer to satisfy gas supply requirements. Also
offsetting the decrease in production was a $2.59 per barrel increase in the
average price of condensate production. See discussion above for information
relating to the Company's contract with YPFB regarding sales of natural gas
production.
Oil Field Supply and Distribution Three Months Ended Six Months Ended
June 30, June 30,
------------------ ----------------
1995 1994 1995 1994
---- ---- ---- ----
(Dollars in millions)
Gross Operating Revenues . . . . . . . . . . . $ 21.2 18.3 38.4 36.9
Costs of Sales . . . . . . . . . . . . . . . . 18.3 15.8 33.4 31.7
-------- -------- -------- --------
Gross Margin . . . . . . . . . . . . . . . . 2.9 2.5 5.0 5.2
Operating Expenses and Other . . . . . . . . . 3.3 2.8 6.6 6.6
Depreciation and Amortization. . . . . . . . . .1 .1 .2 .2
-------- -------- -------- --------
Operating Loss . . . . . . . . . . . . . . . $ ( .5) ( .4) ( 1.8) ( 1.6)
======== ======== ======== ========
Refined Product Sales (average daily barrels) 8,419 7,486 7,679 7,455
======== ======== ======== ========
Three Months Ended June 30, 1995 Compared With Three Months Ended June 30, 1994.
Although sales volumes of refined products increased over 12%, gross margins
remained tight and were substantially offset by increased operating costs
resulting in a moderate increase in operating loss.
Six Months Ended June 30, 1995 Compared With Six Months Ended June 30, 1994.
Although refined product sales volumes increased during the 1995 period, gross
margin decreased primarily as a result of lower merchandise margins due to
continued strong competition in an oversupplied market. Included in operating
expenses in the 1994 period were charges of $1.2 million for discontinuing the
Company's environmental products marketing operations.
Interest Expense
The increases of $.8 million and $1.2 million in interest expense during the
1995 quarter and period, respectively, were primarily due to interest on the
vacuum unit financing and cash borrowings under the Revolving Credit Facility
during 1995 and to capitalized interest in 1994.
General and Administrative Expense
The increases of $.8 million and $1.0 million in general and administrative
expense during the 1995 quarter and period, respectively, were primarily due to
higher employee costs.
Other Expense
The decreases of $1.4 million and $1.9 million in other expense during the 1995
quarter and period, respectively, were largely attributable to lower
environmental expenses related to former operations.
16
Income Taxes
Income taxes of $1.4 million in the 1995 quarter compare with $.6 million in the
1994 quarter. The increase was primarily due to higher state income taxes on
the Company's increased taxable earnings.
IMPACT OF CHANGING PRICES
The Company's operating results and cash flows are sensitive to the volatile
changes in energy prices. Major shifts in the cost of crude oil 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, major changes in natural gas prices impact revenues and the present
value of estimated future net revenues and cash flows from the Company's
exploration and production operations. The carrying value of oil and 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 markets for crude oil, natural gas
and refined products historically have been volatile and are likely to continue
to be volatile in the future. The Company's liquidity and capital resources are
significantly 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 economic conditions.
The Company cannot predict the future markets and prices for its natural gas or
refined products and the resulting future impact on earnings and cash flows.
The Company's operations have been adversely affected by depressed market
conditions and will continue to be adversely affected for so long as these
market conditions exist. The Company's future capital expenditures, borrowings
under its credit arrangements and other sources of capital will be affected by
these conditions.
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, reduce the asset
concentration associated with the Bob West Field and lower future capital
commitments. In these regards, the Company is evaluating offers to sell or
exchange approximately 40% of its total proved domestic natural gas reserves in
the Bob West Field. The proved reserves for which offers are being evaluated
are located in the C, D, E and F units of the Bob West Field and do not include
acreage covered by the Tennessee Gas Contract (see Note 4 of Notes to Condensed
Consolidated Financial Statements). No offer for a sale or exchange has been
accepted and there is no assurance that a sale or exchange will be consummated.
The Company is uncertain as to the impact of these initiatives upon its capital
resources and liquidity, if any.
In July 1995, the Company completed the Longoria #1 exploratory well in Webb
County of South Texas, marking the discovery of a new natural gas field. This
well tested at an initial gross rate of 3.5 Mmcf per day of natural gas. Tesoro
serves as operator of this well with a 45% working interest and a 33.33% net
revenue interest. The discovery was made on Tesoro's 2,200-acre S. Guerra
prospect. Initial estimates are that this new field is analogous to the Guerra
field (four miles to the northeast), which remains under development but has
already produced a cumulative 125 Bcf of natural gas. Additional tests
currently are being conducted on the Longoria #1 to determine the producing
zone's permeability and the need to fracture the pay sands to stimulate higher
production rates. The well will remain shut-in until such tests are completed
and the well can be tied in to one of several pipelines in the area. The
Company is uncertain as to the future impact of this discovery upon its capital
resources and liquidity.
17
Credit Arrangements
The Company has financing and credit arrangements under a three-year, $125
million corporate Revolving Credit Facility dated April 20, 1994 with a
consortium of ten banks. The Revolving Credit Facility, which is subject to a
borrowing base, provides for (i) the issuance of letters of credit up to the
full amount of the borrowing base and (ii) cash borrowings up to the amount of
the borrowing base attributable to domestic oil and gas reserves. Outstanding
obligations under the Revolving 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. At June 30, 1995, the borrowing base of approximately $111 million
included a domestic oil and gas reserve component of $45 million. At June 30,
1995, the Company had outstanding letters of credit under the Revolving Credit
Facility of approximately $51 million with no cash borrowings outstanding. The
Company has borrowed from time to time under this facility during 1995 on a
short-term basis to finance working capital requirements and capital
expenditures.
Under the terms of the Revolving Credit Facility, as amended, the Company is
required to maintain specified levels of working capital, tangible net worth,
consolidated cash flow and refinery cash flow, as defined. Among other matters,
the Revolving Credit Facility contains certain restrictions with respect to (i)
capital expenditures, (ii) incurrence of additional indebtedness, and (iii)
dividends on capital stock. The Revolving Credit Facility contains other
covenants customary in credit arrangements of this kind. At June 30, 1995, the
Company did not satisfy the refinery cash flow requirement which required the
Company to obtain a waiver to the Revolving Credit Facility. Compliance with
certain financial covenants under the Revolving Credit Facility is primarily
dependent on the Company's maintenance of specified levels of cash flows from
operations, capital expenditures, levels of borrowings and the value of the
Company's domestic oil and gas reserves. Based on current depressed refinery
margins, the Company will be required to seek a waiver or an amendment to the
Revolving Credit Facility from its banks with respect to its refinery cash flow
requirement for the remainder of 1995. The Company believes it will be able to
negotiate terms and conditions with its banks under the Revolving Credit
Facility which will allow the Company to adequately finance its operations. See
Note 3 of Notes to Condensed Consolidated Financial Statements.
Debt Obligations
The Company's funded debt obligations as of June 30, 1995 included approximately
$64.6 million principal amount of 12-3/4% Subordinated Debentures ("Subordinated
Debentures"), which bear interest at 12-3/4% per annum and require sinking fund
payments sufficient to annually retire $11.25 million principal amount of
Subordinated Debentures. As part of a recapitalization in 1994, $44.1 million
principal amount of Subordinated Debentures was tendered in exchange for a like
principal amount of new 13% Exchange Notes ("Exchange Notes"). This exchange
satisfied the 1994 sinking fund requirement and, except for $.9 million, will
satisfy sinking fund requirements for the Subordinated Debentures through 1997.
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 Exchange Notes bear interest at 13% per
annum, mature December 1, 2000 and have no sinking fund requirements. The
limitation on dividend payments included in the indenture governing the Exchange
Notes is less restrictive than the limitation imposed by the Subordinated
Debentures. 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. However, there can be no assurance
whether or when the Company would propose a refinancing, if any.
Capital Expenditures
The Company has under consideration total capital expenditures for 1995 of
approximately $60 million, compared with $100 million for 1994. Capital
expenditures for the continued development of the Bob West Field and exploratory
drilling in other areas of South Texas in 1995 are projected to be $47 million.
The amount of such expenditures for exploration and production activities is
dependent upon, among other factors, the price the Company receives for its
natural gas production. Capital expenditures for 1995 for the refining and
marketing segment are projected to be $11 million, primarily for capital
improvements at the refinery and expansion of the Company's retail locations in
Alaska. For the six months ended June 30, 1995, total capital expenditures
amounted to $33 million, including $27 million for exploration and production
and $5 million for refining and
18
marketing, which were funded through cash flows from operations, existing cash
and borrowings under the Revolving Credit Facility. The Company expects to
finance capital expenditures for the remainder of 1995 through a combination of
cash flows from operations and borrowings under the Revolving Credit Facility.
Cash Flows
At June 30, 1995, the Company's net working capital totaled $83.0 million, which
included cash of $7.4 million and a receivable from Tennessee Gas of $35.4
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 4 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,
-----------------------
1995 1994
------ ------
Cash Flows From (Used In):
Operating Activities . . . . . . . . . . . . . . . $ 29.4 45.0
Investing Activities . . . . . . . . . . . . . . . (34.9) (34.8)
Financing Activities . . . . . . . . . . . . . . . ( 1.2) ( 5.5)
------ ------
Increase (Decrease) in Cash and Cash Equivalents . . $ ( 6.7) 4.7
====== ======
Net cash from operating activities of $29.4 million during the 1995 period
compares to $45.0 million for the 1994 period. Although natural gas production
from the Bob West Field increased during the 1995 period, lower cash receipts
for sales of natural gas and reduced cash flows from the refining and marketing
operations adversely affected the Company's cash flows from operations. Net
cash used in investing activities of $34.9 million included $32.8 million of
capital expenditures and $3.0 million for acquisition of the Kenai Pipe Line
Company. Capital expenditures for the 1995 period included $27.0 million for
the Company's exploration and production activities in South Texas, primarily
for completion of nine natural gas development wells. Net cash used in
financing activities of $1.2 million during the 1995 period was primarily
related to payments of long-term debt. The Company's gross borrowings and
repayments under its Revolving Credit Facility totaled $159.5 million during the
1995 period.
Tennessee Gas Contract
The Company is selling a portion of the gas 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 June 1995, the Contract Price was in excess of $8.00 per Mcf, the Section
101 price was $4.94 per Mcf and the average spot market price was $1.56 per Mcf.
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
19
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, 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 Section 2.306 of the UCC.
In addition, the Supreme Court affirmed that the price under the Tennessee Gas
Contract is the Contract Price. The Company intends to file a motion for
rehearing before the Texas Supreme Court on the issue of whether the Tennessee
Gas Contract is an output contract. Through June 30, 1995, under the Tennessee
Gas Contract, the Company recognized cumulative revenues in excess of spot
market prices through September 17, 1994, and in excess of a nonrefundable $3.00
per Mcf bond price subsequent to September 17, 1994, totaling $86.6 million of
which $33.9 million is included in receivables. The Company and its outside
counsel are evaluating the impact of various aspects of the Supreme Court
decision. 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. An adverse outcome of this
litigation could require the Company to reverse some or all of the incremental
revenue and repay Tennessee Gas all or a portion of $52.5 million for amounts
received above spot market prices, plus interest if awarded by the court.
In September 1994, the court ordered that, effective until August 1, 1995,
Tennessee Gas (i) take at least its entire monthly take-or-pay obligation under
the Tennessee Gas Contract, (ii) pay for gas at $3.00 per Mmbtu, which
approximates $3.00 per Mcf ("Bond Price"), and (iii) post a $120 million bond
with the court representing an amount which, together with anticipated sales of
natural gas to Tennessee Gas at the Bond Price, will equal the anticipated value
of the Tennessee Gas Contract during this interim period. The Bond Price is
nonrefundable by the Company, and the Company retains the right to receive the
full Contract Price for all gas sold to Tennessee Gas. On August 10, 1995 a
hearing was held before the trial court regarding the extension of the Tennessee
Gas bond. The parties agreed and the court ordered that Tennessee Gas, for the
period August 14, 1995, until the earlier of October 16, 1995, or the date the
Supreme Court issues its rulings on motions for rehearing, (i) continue to take
at least its entire take-or-pay volume obligation, (ii) pay for gas at a price
of $3.00 per Mmbtu subject to potential refund of amounts in excess of market
prices if Tennessee Gas should ultimately prevail in the litigation, and (iii)
post a $25 million bond in addition to the $120 million bond presently in place.
Tennessee Gas had previously agreed to pay the Company the nonrefundable Bond
Price until August 14, 1995.
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. In addition, the Company is holding discussions with the
Department of Justice concerning the assessment of penalties with respect to
certain alleged violations of the Clean Air Act. At June 30, 1995 the Company's
accruals for environmental matters, including the alleged violations of the
Clean Air Act, amounted to $11.3 million. Also included in this amount is an
approximate $4 million noncurrent liability for remediation of the KPL
properties, which liability 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 1995 of approximately $2
million, primarily for the removal and upgrading of underground storage tanks,
and approximately $8 million during 1996 for the installation of dike liners
required under Alaska environmental regulations. 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
20
further information on environmental contingencies, see Note 4 of Notes to
Condensed Consolidated Financial Statements.
The Company's contract with the State of Alaska ("State") for the purchase of
royalty crude oil expires on December 31, 1995. In May 1995, the Company
renegotiated a new three-year contract with the State for the period January 1,
1996 through December 31, 1998. The new contract provides for the purchase of
approximately 40,000 barrels per day of ANS royalty crude oil, the primary
feedstock for the Company's refinery, and is priced at the weighted average
price reported to the State by a major North Slope producer for ANS crude oil as
valued at Pump Station No. 1 on the Trans Alaska Pipeline System. Under this
agreement, the Company is required to utilize in its refinery operations volumes
equal to at least 80% of the ANS crude oil to be purchased from the State. This
contract contains provisions that allow the Company to temporarily or
permanently reduce its purchase obligations.
As discussed in Note 4 of Notes to Condensed Consolidated Financial Statements,
the Company is involved with other litigation and claims, none of which is
expected to have a material adverse effect on the financial condition of the
Company.
21
PART II - OTHER INFORMATION
Item 1. Legal Proceedings
Tennessee Gas Contract. The Company is selling a portion of the gas 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 June 1995, the Contract Price was in excess of $8.00
per Mcf, the Section 101 price was $4.94 per Mcf and the average spot market
price was $1.56 per Mcf. 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, 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 Section 2.306 of
the UCC. In addition, the Supreme Court affirmed that the price under the
Tennessee Gas Contract is the Contract Price. The Company intends to file a
motion for rehearing before the Texas Supreme Court on the issue of whether the
Tennessee Gas Contract is an output contract. Through June 30, 1995, under the
Tennessee Gas Contract, the Company recognized cumulative revenues in excess of
spot market prices through September 17, 1994, and in excess of a nonrefundable
$3.00 per Mcf bond price subsequent to September 17, 1994, totaling $86.6
million of which $33.9 million is included in receivables. The Company and its
outside counsel are evaluating the impact of various aspects of the Supreme
Court decision. 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. An adverse outcome of this
litigation could require the Company to reverse some or all of the incremental
revenue and repay Tennessee Gas all or a portion of $52.5 million for amounts
received above spot market prices, plus interest if awarded by the court.
In September 1994, the court ordered that, effective until August 1, 1995,
Tennessee Gas (i) take at least its entire monthly take-or-pay obligation under
the Tennessee Gas Contract, (ii) pay for gas at $3.00 per Mmbtu, which
approximates $3.00 per Mcf ("Bond Price"), and (iii) post a $120 million bond
with the court representing an amount which, together with anticipated sales of
natural gas to Tennessee Gas at the Bond Price, will equal the anticipated value
of the Tennessee Gas Contract during this interim period. The Bond Price is
nonrefundable by the Company, and the Company retains the right to receive the
full Contract Price for all gas sold to Tennessee Gas. On August 10, 1995, a
hearing was held before the trial court regarding the extension of the Tennessee
Gas bond. The parties agreed and the court ordered that Tennessee Gas, for the
period August 14, 1995, until the earlier of October 16, 1995, or the date the
Supreme Court issues its rulings on motions for rehearing, (i) continue to take
at least its entire take-or-pay volume obligation, (ii) pay for gas at a price
of $3.00 per Mmbtu subject to potential refund of amounts in excess of market
prices if Tennessee Gas should ultimately prevail in litigation, and (iii) post
a $25 million bond in addition to the $120 million bond presently in place.
Tennessee Gas had previously agreed to pay the Company the nonrefundable Bond
Price until August 14, 1995.
22
Environmental Matters. As previously reported, the Company has been identified
by the Environmental Protection Agency ("EPA") as a potentially responsible
party ("PRP") pursuant to the Comprehensive Environmental Response,
Compensation, and Liability Act of 1980 ("CERCLA") for the Hansen Container
Site, Grand Junction, Mesa County, Colorado ("Site"). The Site was a drum
recycling site which accepted and recycled used containers from the mid-1960's
through 1989. Over 220 parties have been identified as PRP's at the Site. The
Company sold a minimum number of containers to the Site in the mid-1970's.
CERCLA imposes joint and several liability on PRP's; each PRP is therefore
responsible for 100% of the costs of the response actions necessary to remediate
the Site in the event a settlement with the EPA cannot be reached. The EPA has
spent approximately $2.35 million at the Site through September 1994 and is
seeking reimbursement from over 220 PRP's. The Company has entered into an
Administrative Order on Consent for De Minimis Settlement with the EPA
applicable to those PRP's who each contributed less than 2% of the total
contamination at the Site. The Company has agreed to contribute approximately
$1,400 in full settlement of claims against the Company.
As previously reported, in March 1992, the Company received a Compliance Order
and Notice of Violation from the EPA alleging violations by the Company of the
New Source Performance Standards under the Clean Air Act at its Alaska refinery.
These allegations include 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. 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 is also alleging violation of certain regulations
related to asbestos materials. In October 1993, the EPA referred these matters
to the Department of Justice ("DOJ"). The DOJ contacted the Company to begin
negotiating a resolution of these matters. The DOJ has indicated that it is
willing to enter into a judicial consent decree with the Company and that this
decree would include a penalty assessment. Negotiations on the penalty are in
progress. The DOJ has currently proposed a penalty assessment of approximately
$2.3 million. The Company is continuing to negotiate with the DOJ but cannot
predict the ultimate outcome of the negotiations.
Refund Claim. As previously reported, in July 1994, Simmons Oil Corporation,
also known as David Christopher Corporation, 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. The Company cannot predict the
ultimate resolution of this matter but believes the claim is without merit.
23
Item 4. Submission of Matters to a Vote of Security Holders
(a) The 1995 annual meeting of stockholders of the Company was held on May
4, 1995.
(b) The names of the directors elected at the meeting and a tabulation of
the number of votes cast for, against or withheld with respect to each
such director are set forth below:
Name Votes Votes Votes
For Against Withheld
Michael D. Burke 21,058,262 0 946,368
Robert J. Caverly 12,649,742 0 9,354,888
Peter M. Detwiler 11,118,264 0 10,886,366
Steven H. Grapstein 21,041,619 0 963,011
Raymond K. Mason, Sr. 11,112,707 0 10,891,923
John J. McKetta, Jr. 11,085,270 0 10,919,360
Joel V. Staff 13,377,871 0 8,626,759
Murray L. Weidenbaum 12,653,329 0 9,351,301
At the annual meeting of stockholders, a dissident slate of directors
consisting of six individuals was nominated from the floor. The
dissident slate subsequently challenged the results of the election.
The challenge was rejected by the inspector of election and,
thereafter, by the Delaware Chancery Court which upheld the votes set
forth above.
Joel V. Staff resigned as a director of the Company effective June 13,
1995.
Bruce A. Smith was elected as a director of the Company effective July
26, 1995.
(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 approve and adopt the 1995 Non-Employee
Director Stock Option Plan, there were 10,957,145 votes for; 10,403,943
votes against; 284,496 votes withheld; 359,046 broker non-votes; and no
abstentions.
With respect to a proposal to limit the number of shares which can be
granted to any single participant in one year under the Executive
Long-Term Incentive Plan, there were 12,198,512 votes for; 9,287,131
votes against; 163,941 votes withheld; 355,046 broker non-votes; and no
abstentions.
With respect to a proposal to appoint Deloitte & Touche LLP as
independent auditors for the Company for fiscal year 1995, there were
21,235,489 votes for; 256,468 votes against; 157,627 votes withheld;
355,046 broker non-votes; and no 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, 1995 /s/ Michael D. Burke
Michael D. Burke
President and
Chief Executive Officer
Date: August 14, 1995 /s/ Bruce A. Smith
Bruce A. Smith
Chief Operating Officer,
Executive Vice President and
Chief Financial Officer
25
EXHIBIT INDEX
Exhibit
Number
4 Copy of Consent and Waiver No. 2 dated as of July 31, 1995 to the
Company's Credit Agreement dated as of April 20, 1994.
10 Agreement for the Sale and Purchase of State Royalty Oil dated as of
April 21, 1995 by and between Tesoro Alaska Petroleum Company and the
State of Alaska.
11 Information Supporting Earnings (Loss) Per Share Computations.
27 Financial Data Schedule.
26