UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-Q
(Mark One)
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
ACT OF 1934
For the quarterly period ended September 30, 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 24,565,889 shares of the Registrant's Common Stock outstanding at
October 31, 1995.
TESORO PETROLEUM CORPORATION AND SUBSIDIARIES
INDEX TO FORM 10-Q
FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 1995
PART I. FINANCIAL INFORMATION Page
Item 1. Financial Statements (Unaudited)
Condensed Consolidated Balance Sheets - September 30, 1995
and December 31, 1994 . . . . . . . . . . . . . . . . . . . 3
Condensed Statements of Consolidated Operations - Three
Months and Nine Months Ended September 30, 1995 and 1994 . . 4
Condensed Statements of Consolidated Cash Flows - Nine
Months Ended September 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 . . . . . . . . . . . . . 11
PART II. OTHER INFORMATION
Item 1. Legal Proceedings . . . . . . . . . . . . . . . . . . 24
Item 6. Exhibits and Reports on Form 8-K . . . . . . . . . . 25
SIGNATURES . . . . . . . . . . . . . . . . . . . . . . . . . . . 26
2
PART I - FINANCIAL INFORMATION
Item 1. Financial Statements
TESORO PETROLEUM CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
(Dollars in thousands except per share amounts)
September 30, December 31,
1995 1994<F1>
---- ----
ASSETS
CURRENT ASSETS:
Cash and cash equivalents. . . . . . . . . . . . . $ 59,370 14,018
Receivables, less allowance for doubtful accounts
of $2,075 ($1,816 at December 31, 1994) (Note 5). 69,126 91,140
Inventories:
Crude oil and wholesale refined products, at LIFO 54,046 58,798
Merchandise and retail refined products . . . . . 3,987 5,934
Materials and supplies. . . . . . . . . . . . . . 3,843 3,570
Prepaid expenses and other . . . . . . . . . . . . 11,066 8,648
----------- -----------
Total Current Assets. . . . . . . . . . . . . . . 201,438 182,108
PROPERTY, PLANT AND EQUIPMENT, Net of Accumulated
Depreciation, Depletion and Amortization of
$207,650 ($205,782 at December 31, 1994) . . . . . 256,345 273,334
RECEIVABLE FROM TENNESSEE GAS PIPELINE COMPANY
(Note 5). . . . . . . . . . . . . . . . . . . . . 42,689 -
INVESTMENT IN TESORO BOLIVIA PETROLEUM COMPANY . . . 12,735 10,295
OTHER ASSETS . . . . . . . . . . . . . . . . . . . . 20,492 18,623
----------- -----------
TOTAL ASSETS. . . . . . . . . . . . . . . . . $ 533,699 484,360
=========== ===========
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES:
Accounts payable . . . . . . . . . . . . . . . . . $ 48,600 53,573
Accrued liabilities. . . . . . . . . . . . . . . . 38,676 35,266
Current portion of long-term debt and other
obligations. . . . . . . . . . . . . . . . . . . 9,084 7,404
----------- -----------
Total Current Liabilities . . . . . . . . . . . . 96,360 96,243
----------- -----------
DEFERRED INCOME TAXES. . . . . . . . . . . . . . . . 5,193 4,582
----------- -----------
OTHER LIABILITIES. . . . . . . . . . . . . . . . . . 36,417 30,593
----------- -----------
LONG-TERM DEBT AND OTHER OBLIGATIONS, LESS
CURRENT PORTION. . . . . . . . . . . . . . . . . . 187,869 192,210
----------- -----------
COMMITMENTS AND CONTINGENCIES (Note 5)
STOCKHOLDERS' EQUITY:
Common Stock, par value $.16-2/3; authorized
50,000,000 shares; 24,545,889 shares issued and
outstanding (24,389,801 in 1994) . . . . . . . . 4,091 4,065
Additional paid-in capital . . . . . . . . . . . . 176,618 175,514
Retained earnings (accumulated deficit). . . . . . 27,151 ( 18,847)
----------- -----------
Total Stockholders' Equity. . . . . . . . . . . . 207,860 160,732
----------- -----------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY . . $ 533,699 484,360
=========== ===========
<FN>
The accompanying notes are an integral part of these condensed consolidated
financial statements.
<F1> 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 Nine Months Ended
September 30, September 30,
1995 1994 1995 1994
---- ---- ---- ----
REVENUES:
Gross operating revenues . . . . . . . . . . $ 245,132 251,811 744,962 651,558
Gain on sales of assets. . . . . . . . . . . 33,057 18 33,055 2,359
Interest income. . . . . . . . . . . . . . . 192 627 616 1,602
Other income . . . . . . . . . . . . . . . . 138 219 349 941
----------- ----------- ----------- -----------
Total Revenues. . . . . . . . . . . . . . . 278,519 252,675 778,982 656,460
----------- ----------- ----------- -----------
COSTS AND EXPENSES:
Costs of sales and operating expenses. . . . 215,237 235,638 660,349 594,471
General and administrative . . . . . . . . . 4,372 3,480 12,371 10,484
Depreciation, depletion and amortization . . 9,436 9,493 32,763 23,888
Interest expense, net of capitalized interest
in 1994 of $367 and $607, respectively. . . 5,471 4,483 16,132 13,989
Other expense. . . . . . . . . . . . . . . . 5,557 1,409 7,572 4,852
----------- ----------- ----------- -----------
Total Costs and Expenses. . . . . . . . . . 240,073 254,503 729,187 647,684
----------- ----------- ----------- -----------
EARNINGS (LOSS) BEFORE INCOME TAXES
AND EXTRAORDINARY LOSS ON
EXTINGUISHMENT OF DEBT . . . . . . . . . . . 38,446 ( 1,828) 49,795 8,776
Income Tax Provision . . . . . . . . . . . . . 1,664 1,435 3,797 3,607
----------- ----------- ----------- -----------
EARNINGS (LOSS) BEFORE EXTRAORDINARY
LOSS ON EXTINGUISHMENT OF DEBT. . . . . . . 36,782 ( 3,263) 45,998 5,169
Extraordinary Loss on Extinguishment of Debt . - - - ( 4,752)
----------- ----------- ----------- -----------
NET EARNINGS (LOSS). . . . . . . . . . . . . . 36,782 ( 3,263) 45,998 417
Dividend Requirements on Preferred Stocks. . . - - - 2,680
----------- ----------- ----------- -----------
NET EARNINGS (LOSS) APPLICABLE TO
COMMON STOCK . . . . . . . . . . . . . . . . $ 36,782 ( 3,263) 45,998 ( 2,263)
=========== =========== =========== ===========
EARNINGS (LOSS) PER PRIMARY AND
FULLY DILUTED SHARE:
Earnings (Loss) Before Extraordinary Loss on
Extinguishment of Debt. . . . . . . . . . . $ 1.47 ( .13) 1.83 .11
Extraordinary Loss on Extinguishment of Debt - - - ( .21)
----------- ----------- ----------- -----------
Net Earnings (Loss). . . . . . . . . . . . . $ 1.47 ( .13) 1.83 ( .10)
=========== =========== =========== ===========
AVERAGE OUTSTANDING COMMON AND
COMMON EQUIVALENT SHARES . . . . . . . . . . 25,093 25,011 25,140 22,584
=========== =========== =========== ===========
<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)
Nine Months Ended
September 30,
1995 1994
CASH FLOWS FROM (USED IN) OPERATING ACTIVITIES:
Net earnings . . . . . . . . . . . . . . . . . . . $ 45,998 417
Adjustments to reconcile net earnings to net
cash from operating activities:
Depreciation, depletion and amortization. . . . . 32,763 23,888
Gain on sales of assets . . . . . . . . . . . . . ( 33,055) ( 2,359)
Amortization of deferred charges. . . . . . . . . 1,311 1,187
Loss on extinguishment of debt. . . . . . . . . . - 4,752
Changes in assets and liabilities:
Receivable from Tennessee Gas Pipeline Company. ( 29,465) ( 1,443)
Receivables, other trade. . . . . . . . . . . . 9,916 ( 1,463)
Inventories . . . . . . . . . . . . . . . . . . 6,006 21,315
Investment in Tesoro Bolivia Petroleum Company. ( 2,440) ( 3,980)
Other assets . . . . . . . . . . . . . . . . . ( 1,994) ( 1,090)
Accounts payable and other current liabilities. ( 349) 11,108
Obligation payments to State of Alaska . . . . ( 2,129) ( 2,011)
Other liabilities and obligations . . . . . . . 3,719 2,309
---------- ----------
Net cash from operating activities. . . . . . 30,281 52,630
---------- ----------
CASH FLOWS FROM (USED IN) INVESTING ACTIVITIES:
Capital expenditures . . . . . . . . . . . . . . . ( 48,881) ( 73,260)
Acquisition of Kenai Pipe Line Company . . . . . . ( 3,029) -
Proceeds from sales of assets. . . . . . . . . . . 69,711 2,526
Sales of short-term investments . . . . . . . . . - 5,952
Purchases of short-term investments. . . . . . . . - ( 1,974)
Other. . . . . . . . . . . . . . . . . . . . . . . ( 172) 3,950
---------- ----------
Net cash from (used in) investing activities . . 17,629 ( 62,806)
---------- ----------
CASH FLOWS FROM (USED IN) FINANCING ACTIVITIES:
Repayments, net of borrowings of $262,500 in 1995
and $5,000 in 1994, under revolving credit
facilities . . . . . . . . . . . . . . . . . . . - ( 5,000)
Payments of long-term debt . . . . . . . . . . . . ( 2,262) ( 1,097)
Issuance of long-term debt . . . . . . . . . . . . - 10,206
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. . . . . . . . ( 296) ( 2,424)
---------- ----------
Net cash from (used in) financing activities . . ( 2,558) 4,020
---------- ----------
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS . . 45,352 ( 6,156)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD . . 14,018 36,596
---------- ----------
CASH AND CASH EQUIVALENTS AT END OF PERIOD . . . . . $ 59,370 30,440
========== ==========
SUPPLEMENTAL CASH FLOW DISCLOSURES:
Interest paid, net of $607 capitalized in 1994 . . $ 13,600 13,220
========== ==========
Income taxes paid . . . . . . . . . . . . . . . . $ 3,262 3,855
========== ==========
<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)
(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. 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) Acquisitions and Divestitures
In September 1995, the Company sold, effective April 1, 1995, certain interests
in its U.S. onshore producing and non-producing oil and gas properties located
in the Bob West Field in South Texas. The interests sold included the Company's
approximate 55% net revenue interest and 70% working interest in Units C, D and
E and a convertible override in Unit F of the Bob West Field. These units do
not include acreage related to the Company's natural gas sales contract with
Tennessee Gas Pipeline Company, which, as discussed in Note 5, is the subject of
current litigation. Also excluded from the sale were the Company's interests in
the State Park and Sanchez-O'Brien leases and the Ramirez USA E-6 well within
the field. In total, the sale included interests in 14 gross producing wells,
or approximately 40% of the Company's total proved domestic reserves. For the
three months and nine months ended September 30, 1995, natural gas production
from the interests sold had contributed approximately $1.3 million and $4.2
million, respectively, to the Company's Exploration and Production segment
operating profit. For information regarding changes in proved domestic
reserves, see Note 6. Consideration for the sale was $74 million, which was
adjusted on a preliminary basis for production, capital expenditures and certain
other items after the effective date to approximately $68 million in cash
received at closing, resulting in a gain of approximately $33 million, or $1.34
per share, in the 1995 third quarter. No income taxes were provided on this
gain due to the utilization of previously unrecognized net operating loss and
other carryforwards. The consideration received by the Company, which is
subject to final post-closing adjustments, is expected to be used to redeem a
portion of the Company's outstanding 12-3/4% Subordinated Debentures, reduce
borrowings under the Company's Revolving Credit Facility and improve corporate
liquidity (see Note 4). The Company does not expect any final post-closing
adjustments to be material.
In September 1995, the Company signed a letter of intent to acquire all of the
outstanding capital stock of Coastwide Energy Services, Inc. ("Coastwide") for
approximately $21 million, to be paid 40% in cash and 60% in Tesoro Common
Stock. Coastwide is a wholesale distributor of diesel fuel and lubricants and a
provider of services to the offshore drilling industry in the U.S. Gulf of
Mexico. Upon completion of this acquisition, which is subject to regulatory
approvals and approval by Coastwide shareholders, the Company would merge its
existing marine petroleum distribution operations with Coastwide, forming a
Marine Services segment. If this acquisition is consummated, it would be
accounted for using the purchase method.
In March 1995, the Company acquired all of the outstanding stock of Kenai Pipe
Line Company ("KPL") for approximately $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. The acquisition was
accounted for using the purchase method.
(3) Employee Terminations and Other Costs
In September 1995, the Company incurred a pretax charge of $4.7 million, or $.19
per share, primarily for employee termination costs associated with
restructuring the Company's organization and operations. Other expense included
$3.8 million of this charge, representing primarily severance and related
benefits resulting from a reduction in administrative workforce and other
employee terminations together with settlements and curtailments under the
Company's executive security plan. Operating expenses and other included the
remaining $.9 million of this charge which was related to employee terminations
and exit costs in the Company's operating segments. The Company's Consolidated
Balance Sheet as of September 30, 1995 included an accrual of approximately $2.5
million relating to these costs, the majority of which will be paid by year-end
1995.
6
(4) Credit Arrangements
Revolving Credit Facility
The Company has financing and credit arrangements under a three-year corporate
Revolving Credit Facility ("Facility") dated April 20, 1994, with a consortium
of ten banks. The 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 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 Facility,
which has been amended from time to time, the Company is required to maintain
specified levels of working capital, tangible net worth, consolidated cash flow
and refining and marketing cash flow, as defined. Among other matters, the
Facility contains certain restrictions with respect to (i) capital expenditures,
(ii) incurrence of additional indebtedness, and (iii) dividends on capital
stock. The Facility contains other covenants customary in credit arrangements
of this kind. Future compliance with certain financial covenants 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. In October 1995, the Facility was
amended which, among other matters, (i) reduced available commitments from $100
million to $90 million, (ii) permits the Company to redeem a portion of its
outstanding 12-3/4% Subordinated Debentures, and (iii) reduced the required
level of refining and marketing cash flow. If the Company's refining and
marketing cash flow, as defined, does not meet required levels, the $90 million
availability will be incrementally reduced, but not below $80 million.
At September 30, 1995, the Company had available commitments under the Facility
of $100 million which were fully supported by the borrowing base as defined.
Included in the borrowing base at September 30, 1995 was a domestic oil and gas
reserve component of $40 million. At September 30, 1995, the Company had
outstanding letters of credit under the Facility of approximately $50 million
with no cash borrowings outstanding. For the nine months ended September 30,
1995, the Company's gross borrowings and repayments under the Facility totaled
$262.5 million, which were used on a short-term basis to finance working capital
requirements and capital expenditures.
Partial Redemption of 12-3/4% Subordinated Debenture
The Company has given notice of its intention to redeem approximately $34.6
million of its outstanding 12-3/4% Subordinated Debentures ("Subordinated
Debentures"). The redemption date will be December 1, 1995 at a price equal to
100% of the principal amount, plus accrued interest to the redemption date. In
the fourth quarter of 1995, the Company expects to record a noncash
extraordinary loss of approximately $3 million from this early extinguishment of
debt, reflecting a write-off of unamortized bond discount and issue costs.
Following this partial redemption, which will satisfy all future sinking fund
requirements, the Company will have $30 million principal amount of Subordinated
Debentures outstanding, due on March 15, 2001.
(5) 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 September 1995, the Contract Price was in excess of $8.00 per Mcf and the
average spot market price was $1.45 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")
7
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 the UCC. In
addition, the Supreme Court affirmed that the price under the Tennessee Gas
Contract is the Contract Price. 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. Through September 30, 1995, under the Tennessee Gas Contract,
the Company recognized cumulative net revenues in excess of spot market prices
(in excess of a $3.00 per Mcf nonrefundable Bond Price, as defined below, from
September 18, 1994 through August 13, 1995) totaling approximately $96.6
million. The Company's noncurrent receivable from Tennessee Gas totaled $42.7
million at September 1995, representing the difference between the Contract
Price and the Bond Price, as defined below. 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 $53.9 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 for
this period is nonrefundable by the Company. On August 10, 1995, a hearing was
held before the trial court regarding the extension of the Tennessee Gas bond.
Pursuant to agreement of the parties, 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. On November 8, 1995, pursuant to agreement of the parties, the court
ordered that Tennessee Gas will, for the period October 16, 1995, until the
earlier of January 31, 1996, or the date the Supreme Court issues its ruling 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 $35 million bond in
addition to the $145 million bond presently in place. Tennessee Gas had
previously agreed to pay the Company the nonrefundable Bond Price until August
14, 1995. Under the provisions of the bond agreement, the Company retains the
right to receive the full Contract Price for all gas sold to Tennessee Gas.
8
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 waste disposal sites near Abbeville, Louisiana and in
Grand Junction, Colorado, 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 both sites is expected to be
limited based upon the number of companies and the volumes of waste involved.
The Company believes that its liability at the Abbeville, Louisiana site will be
limited based upon the payment by the Company of a de minimis settlement amount
of $2,500 at a similar site in Louisiana. With respect to the Grand Junction,
Colorado site, the Company has executed an Administrative Order on Consent for
De Minimis Settlement with the EPA in which the Company has agreed to settle all
claims at the site for approximately $1,400. 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 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 $2.1 million.
The Company is continuing to negotiate with the DOJ but cannot predict the
ultimate outcome of the negotiations.
At September 30, 1995, the Company's accruals for environmental matters,
including the alleged violations of the Clean Air Act, amounted to $10.5
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 $1 million, primarily for the removal and upgrading of
underground storage tanks, and approximately $10 million during 1997 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
9
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, under certain conditions, allow the Company to temporarily or permanently
reduce its purchase obligations.
Other Contingencies
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. The Company cannot predict the ultimate resolution of this matter but
believes the claim is without merit.
Sales Commitment
The Company has entered into an agreement with another company for the sale of
approximately 8.25 Bcf of the Company's 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 nine months ended
September 30, 1995, the Company's average spot market sales prices, which
included the effect of this agreement, were $1.44 and $1.47 per Mcf,
respectively.
(6) Changes in Proved Domestic Reserves
The Company's mid-year reserve report, prepared by the Company's independent
petroleum consultants, estimated 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. Subsequently, in September 1995, the
Company sold approximately 40% of its proved domestic natural gas reserves (see
Note 2).
10
Item 2. TESORO PETROLEUM CORPORATION AND SUBSIDIARIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
RESULTS OF OPERATIONS - THREE AND NINE MONTHS ENDED SEPTEMBER 30, 1995
COMPARED WITH THREE AND NINE MONTHS ENDED SEPTEMBER 30, 1994
A consolidated summary of the Company's operations for the three and nine months
ended September 30, 1995 and 1994 is presented below (in millions except per
share amounts):
Three Months Ended Nine Months Ended
September 30, September 30,
1995 1994 1995 1994
------------------ -----------------
Summary of Operations
Segment Operating Profit (Loss), Including Gain
on Sales of Assets<F1>:
Refining and Marketing . . . . . . . . . . . . . . $ 2.8 ( 5.1) ( 4.5) ( 3.7)
Exploration and Production - United States . . . . 49.5 9.4 86.1 35.2
Exploration and Production - Bolivia . . . . . . . 2.2 3.0 6.2 7.4
Oil Field Supply and Distribution. . . . . . . . . ( .7) ( .2) ( 2.5) ( 1.8)
------- ------- ------- -------
Total Segment Operating Profit. . . . . . . . . . 53.8 7.1 85.3 37.1
Corporate and Unallocated Costs:
General and administrative expenses. . . . . . . . 4.4 3.5 12.4 10.5
Interest expense . . . . . . . . . . . . . . . . . 5.4 4.5 16.1 14.0
Interest income. . . . . . . . . . . . . . . . . . ( .2) ( .6) ( .6) ( 1.6)
Other. . . . . . . . . . . . . . . . . . . . . . . 5.7 1.6 7.6 5.4
------- ------- ------- -------
Earnings (Loss) Before Income Taxes and
Extraordinary Loss . . . . . . . . . . . . . . . . 38.5 ( 1.9) 49.8 8.8
Income Tax Provision . . . . . . . . . . . . . . . . 1.7 1.4 3.8 3.6
------- ------- ------- -------
Earnings (Loss) Before Extraordinary Loss. . . . . . 36.8 ( 3.3) 46.0 5.2
Extraordinary Loss on Extinguishment of Debt . . . . - - - ( 4.8)
------- ------- ------- -------
Net Earnings (Loss). . . . . . . . . . . . . . . . . 36.8 ( 3.3) 46.0 .4
Dividend Requirements on Preferred Stocks. . . . . . - - - 2.7
------- ------- ------- -------
Net Earnings (Loss) Applicable to Common Stock . . . $ 36.8 ( 3.3) 46.0 ( 2.3)
======= ======= ======= =======
Earnings (Loss) per Primary and Fully Diluted Share:
Earnings (Loss) Before Extraordinary Loss. . . . . $ 1.47 ( .13) 1.83 .11
Extraordinary Loss on Extinguishment of Debt . . . - - - ( .21)
------- ------- ------- -------
Net Earnings (Loss). . . . . . . . . . . . . . . . $ 1.47 ( .13) 1.83 ( .10)
======= ======= ======= =======
<FN>
<F1> Operating profit (loss) represents pretax earnings (loss) before certain corporate
expenses, interest income and interest expense.
Net earnings of $36.8 million, or $1.47 per share, for the three months ended
September 30, 1995 ("1995 quarter") compare with a net loss of $3.3 million, or
$.13 per share, for the three months ended September 30, 1994 ("1994 quarter").
Net earnings for the 1995 quarter included an after-tax gain of approximately
$33 million, or $1.34 per share, from the sale of certain interests in the Bob
West Field and a charge of nearly $5 million, or $.19 per share, for employee
terminations and other restructuring costs. Excluding these items, net earnings
for the 1995 quarter would have been $8 million, or $.32 per share, reflecting
significantly higher results attributable primarily to the successful drilling
program and increased natural gas production from the Company's exploration and
production operations in South Texas together with improved operating results
from the Company's refining and marketing operations.
Net earnings applicable to common stock of $46.0 million, or $1.83 per share,
for the nine months ended September 30, 1995 ("1995 period") compare to a net
loss applicable to common stock of $2.3 million, or $.10 per share, for the nine
months ended September 30, 1994 ("1994 period"). The comparability between
these two periods was impacted by certain significant transactions. As
discussed above, the 1995 period included an after-tax gain of approximately $33
million from the sale of certain interests in the Bob West Field. In addition,
11
the Company benefited from a reduced depletion rate resulting from increases to
its estimates of proved reserves in the 1995 second quarter and the elimination
of future development costs associated with the interests that were sold in the
1995 third quarter. As discussed above, employee terminations and other
restructuring costs of approximately $5 million were incurred during the 1995
period. 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 $.21 per share, attributable to
the early extinguishment of debt in connection with a recapitalization in 1994.
Earnings applicable to common stock before the extraordinary loss were $2.5
million, or $.11 per share, for the 1994 period. The 1994 period was favorably
impacted by a net gain of $2.4 million, or $.11 per share, from the sale of
assets. Excluding these significant transactions from both periods, the
increase in net earnings during the 1995 period was largely due to increased
natural gas production from the Company's exploration and production activities
in South Texas, partially offset by lower operating results from the Company's
refining and marketing segment and lower spot market prices for sales of natural
gas.
12
Refining and Marketing Three Months Ended Nine Months Ended
September 30, September 30,
------------------ -----------------
1995 1994 1995 1994
---- ---- ---- ----
(Dollars in millions except per barrel amounts)
Gross Operating Revenues:
Refined products . . . . . . . . . . . . . . . . . $ 176.3 176.7 499.6 430.8
Other, primarily crude oil resales
and merchandise . . . . . . . . . . . . . . . . . 19.8 30.4 89.1 92.8
--------- --------- --------- ---------
Gross Operating Revenues. . . . . . . . . . . . . $ 196.1 207.1 588.7 523.6
========= ========= ========= =========
Operating Profit (Loss):
Gross margin - refined products. . . . . . . . . . $ 23.2 15.6 57.2 54.3
Gross margin - other . . . . . . . . . . . . . . . 3.7 3.7 9.3 9.7
--------- --------- --------- ---------
Gross margin. . . . . . . . . . . . . . . . . . . 26.9 19.3 66.5 64.0
Operating expenses . . . . . . . . . . . . . . . . 21.3 21.8 62.0 62.4
Depreciation and amortization 2.8 2.6 8.8 7.8
Other, including (gain) on asset sales . . . . . . - - .2 ( 2.5)
--------- --------- --------- ---------
Operating Profit (Loss) . . . . . . . . . . . . . $ 2.8 ( 5.1) ( 4.5) ( 3.7)
========= ========= ========= =========
Capital Expenditures . . . . . . . . . . . . . . . . $ 1.9 8.6 7.2 22.9
========= ========= ========= =========
Refining and Marketing - Total Product Sales
(average daily barrels)<F1>:
Gasoline . . . . . . . . . . . . . . . . . . . . . 26,330 27,000 25,562 23,603
Middle distillates . . . . . . . . . . . . . . . . 38,925 40,489 38,292 33,297
Heavy oils and residual product. . . . . . . . . . 16,009 13,120 14,468 14,199
--------- --------- --------- ---------
Total Product Sales . . . . . . . . . . . . . . . 81,264 80,609 78,322 71,099
========= ========= ========= =========
Refining and Marketing - Product Sales Prices
($/barrel):
Gasoline . . . . . . . . . . . . . . . . . . . . . $ 28.53 28.31 28.10 26.69
Middle distillates . . . . . . . . . . . . . . . . $ 24.07 24.49 24.08 24.01
Heavy oils and residual product. . . . . . . . . . $ 14.09 12.50 13.09 10.45
Refining and Marketing - Gross Margins on Total
Product Sales ($/barrel)<F1>:
Average sales price. . . . . . . . . . . . . . . . $ 23.55 23.82 23.37 22.19
Average cost of sales. . . . . . . . . . . . . . . 20.46 21.72 20.69 19.40
--------- --------- --------- ---------
Gross margin . . . . . . . . . . . . . . . . . . . $ 3.09 2.10 2.68 2.79
========= ========= ========= =========
Refinery Operations - Throughput
(average daily barrels) . . . . . . . . . . . . . 56,504 46,330 50,056 44,770
========= ========= ========= =========
Refinery Operations - Production
(average daily barrels):
Gasoline . . . . . . . . . . . . . . . . . . . . . 16,221 10,792 14,269 11,189
Middle distillates . . . . . . . . . . . . . . . . 23,243 19,912 20,799 18,628
Heavy oils and residual product. . . . . . . . . . 16,025 15,141 14,278 14,613
Refinery fuel. . . . . . . . . . . . . . . . . . . 2,383 1,593 2,128 1,753
--------- --------- --------- ---------
Total Refinery Production . . . . . . . . . . . . 57,872 47,438 51,474 46,183
========= ========= ========= =========
Refinery Operations - Product Spread ($/barrel)<F1>:
Yield value of products produced -
Gasoline. . . . . . . . . . . . . . . . . . . . . $ 25.47 27.31 25.37 25.07
Middle distillates. . . . . . . . . . . . . . . . $ 23.75 23.87 23.70 23.49
Heavy oils and residual product . . . . . . . . . $ 9.15 9.90 9.35 7.93
Average yield value of products produced . . . . . $ 20.07 20.20 20.16 19.02
Cost of raw materials. . . . . . . . . . . . . . . 16.81 17.43 17.13 15.38
--------- --------- --------- ---------
Product Spread. . . . . . . . . . . . . . . . . . $ 3.26 2.77 3.03 3.64
========= ========= ========= =========
13
<FN>
<F1> 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 26,800 and 38,900 average daily barrels for the 1995 and 1994
quarters, respectively, and 26,900 average daily barrels for both the 1995 and 1994
periods. The product spread presented above represents the excess of yield value of the
products manufactured at the refinery over the cost of the raw materials used to
manufacture such products.
Three Months Ended September 30, 1995 Compared With Three Months Ended September
30, 1994. Lower feedstock costs enabled the Company's margins to improve during
the 1995 quarter. The Company's average feedstock costs decreased to $16.81 per
barrel for the 1995 quarter compared with $17.43 per barrel for the 1994
quarter, while the average yield value of the Company's refinery production
decreased to $20.07 per barrel for the 1995 quarter from $20.20 per barrel for
the prior year quarter. Although the Company's refinery product spread
improved, the Company's results continue to remain volatile, particularly as to
the cost of Alaska North Slope ("ANS") crude oil in relation 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 relatively
unchanged from the 1994 quarter, both in volumes and prices. However, to
optimize the refinery's feedstock mix and in response to market conditions, the
Company's resales of crude oil decreased by $10.1 million. Costs of sales,
likewise, were lower in the 1995 quarter due to decreased crude oil prices and
volumes. Depreciation and amortization increased $.2 million in the 1995
quarter due to capital additions, primarily the vacuum unit, completed in late
1994.
Nine Months Ended September 30, 1995 Compared With Nine Months Ended September
30, 1994. The Company's average feedstock costs increased to $17.13 per barrel
for the 1995 period compared with $15.38 per barrel for the 1994 period, while
the average yield value of the Company's refinery production increased to $20.16
per barrel for the 1995 period from $19.02 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
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 10% increase in sales volumes.
Costs of sales were higher in the 1995 period due to higher volumes and prices.
Depreciation and amortization increased $1.0 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. See
discussion above for information on the Company's vacuum unit and marketing
initiatives.
14
Exploration and Production Three Months Ended Nine Months Ended
September 30, September 30,
------------------ -----------------
1995 1994 1995 1994
---- ---- ---- ----
(Dollars in millions except per unit amounts)
United States:
Gross operating revenues:
Natural gas producing activities<F1> . . . . . . $ 26.6 18.9 88.5 58.7
Natural gas transportation . . . . . . . . . . . .7 .4 1.8 .8
Lifting costs<F2>. . . . . . . . . . . . . . . . . 5.2 3.6 15.4 9.1
Depreciation, depletion and amortization . . . . . 6.3 6.6 23.0 15.1
Gain on sale of assets . . . . . . . . . . . . . . 33.5 - 33.5 -
Other. . . . . . . . . . . . . . . . . . . . . . . ( .2) ( .3) ( .7) .1
--------- --------- --------- ---------
Operating Profit - United States. . . . . . . . . 49.5 9.4 86.1 35.2
--------- --------- --------- ---------
Bolivia:
Gross operating revenues . . . . . . . . . . . . . 3.3 4.0 9.1 10.1
Lifting costs. . . . . . . . . . . . . . . . . . . .2 .2 .5 .5
Other . . . . . . . . . . . . . . . . . . . . . . .9 .8 2.4 2.2
--------- --------- --------- ---------
Operating Profit - Bolivia. . . . . . . . . . . . 2.2 3.0 6.2 7.4
--------- --------- --------- ---------
Total Operating Profit - Exploration
and Production . . . . . . . . . . . . . . . . . . $ 51.7 12.4 92.3 42.6
========= ========= ========= =========
United States:
Capital expenditures . . . . . . . . . . . . . . . $ 13.8 19.4 40.8 48.8
========= ========= ========= =========
Net natural gas production (average daily Mcf) -
Spot market and other . . . . . . . . . . . . . . 93,641 88,653 98,625 57,695
Tennessee Gas Contract<F1>. . . . . . . . . . . . 18,048 9,369 21,323 15,126
--------- --------- --------- ---------
Total production . . . . . . . . . . . . . . . . 111,689 98,022 119,948 72,821
========= ========= ========= =========
Average natural gas sales price per Mcf -
Spot market . . . . . . . . . . . . . . . . . . . $ 1.44 1.48 1.47 1.66
Tennessee Gas Contract<F1>. . . . . . . . . . . . $ 8.57 7.89 8.43 7.89
Average . . . . . . . . . . . . . . . . . . . . . $ 2.60 2.10 2.70 2.95
Average lifting costs per Mcf<F2>. . . . . . . . . $ .50 .40 .47 .46
Depletion per Mcf. . . . . . . . . . . . . . . . . $ .60 .73 .70 .76
Bolivia:
Net natural gas production
(average daily Mcf). . . . . . . . . . . . . . . 20,559 25,528 19,075 22,262
Average natural gas sales price per Mcf. . . . . . $ 1.32 1.22 1.29 1.22
Net crude oil (condensate) production. . . . . . .
(average daily barrels) . . . . . . . . . . . . . 604 832 589 744
Average crude oil price per barrel . . . . . . . . $ 12.95 14.04 14.44 13.16
Average lifting costs per net equivalent Mcf . . . $ .06 .06 .08 .06
<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 to Condensed Consolidated Financial
Statements.
<F2> Lifting costs for the Company's U.S. operations include such items as
severance taxes, property taxes, insurance and materials and supplies. In
addition, for the periods presented above, lifting costs included
approximately $.06 to $.07 per Mcf for transportation of natural gas
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 $.44 and $.36 for the 1995 and 1994 quarters,
respectively, and approximately $.40 and $.39 for the 1995 and 1994
periods, respectively.
15
United States
Three Months Ended September 30, 1995 Compared With Three Months Ended September
30, 1994. Operating profit of $49.5 million in the 1995 quarter included a gain
of approximately $33 million from the sale of certain interests in the Bob West
Field. Excluding this gain, operating profit would have been approximately $16
million in the 1995 third quarter as compared with $9.4 million in the 1994
quarter, reflecting the successful drilling program and increased production in
South Texas. The number of producing wells in South Texas in which the Company
has a working interest increased to 67 wells (reduced to 53 wells after the sale
of certain interests) at the end of the 1995 quarter, compared with 44 wells at
the end of the 1994 quarter. The Company's 1995 quarter results included a 14%
increase in U.S. natural gas production with an $8.0 million increase in
revenues. Revenues benefited from higher sales volumes to Tennessee Gas who
elected to take their entire take-or-pay obligation during the 1995 quarter, as
compared to the 1994 quarter when sales volumes to Tennessee Gas had been
curtailed. The Company's weighted average sales price increased to $2.60 per
Mcf during the 1995 quarter as compared with $2.10 per Mcf in the 1994 quarter.
The Company recognizes revenues, net of expenses, for sales to Tennessee Gas
based on a contract price, which resulted in net revenues exceeding a
nonrefundable cash price by an aggregate of $10 million for the 1995 quarter.
Total lifting costs were higher in the 1995 quarter, compared with the 1994
quarter, due to the increased production levels and higher severance taxes
related to the above-market pricing of sales to Tennessee Gas. Depreciation,
depletion and amortization were lower during the 1995 quarter due to an 18%
reduction in the depletion rate which benefited by additions to proved reserves
in the 1995 second quarter and elimination of future development costs on the
reserves sold during the 1995 quarter.
For the 1995 quarter, operating results from the Exploration and Production
segment included natural gas production of approximately 27 Mmcf per day,
revenues of $3.4 million and operating profit of $1.3 million related to the
interests in the Bob West Field that were sold. For further information
regarding the sale of these interests, see Note 2 of Notes to Condensed
Consolidated Financial Statements.
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, subject to the provisions
of a bond posted by Tennessee Gas. 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. For a discussion of the bond
posting, see "Capital Resources and Liquidity--Tennessee Gas Contract," "Legal
Proceedings--Tennessee Gas Contract" and Note 5 of Notes to Condensed
Consolidated Financial Statements.
The Company has entered into an agreement with another company for the sale of
approximately 8.25 Bcf of the Company's 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 nine months ended
September 30, 1995, the Company's average spot market sales prices, which
included the effect of this agreement, were $1.44 and $1.47 per Mcf,
respectively.
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 (the
"Tea Jay Field"). Tesoro serves as operator of this well with a 45% working
interest and a 33.33% net revenue interest. As a result of the initial
exploratory well, the Company anticipates that approximately 4 Bcf will be added
to its net proved reserves. A seismic program is underway at the Tea Jay Field
to assist in identifying future drilling locations. The Company anticipates
drilling the first development well in early 1996. The Company is uncertain as
to the future impact of this discovery upon its results of operations.
Nine Months Ended September 30, 1995 Compared With Nine Months Ended September
30, 1994. Operating profit of $86.1 million in the 1995 period included a gain
of approximately $33 million from the sale of certain interests in the Bob West
Field. Excluding this gain, operating profit would have been approximately $53
million
16
in the 1995 period as compared with $35.2 million in the 1994 period. Results
for the 1995 period included a 65% increase in U.S. natural gas production with
a $30.8 million increase in revenues. Revenues benefited from higher sales
volumes to Tennessee Gas, but were adversely affected by an 8% decline in the
Company's weighted average sales price, which included an 11% drop in average
spot market prices. The Company recognizes revenues, net of expenses, for sales
to Tennessee Gas based on a contract price, which resulted in net revenues
exceeding a nonrefundable cash price by an aggregate of $30.8 million for the
1995 period. In response to 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. The Company continues to benefit
from an 8% reduction in the depletion rate resulting mainly from additions to
proved reserves in the 1995 second quarter and elimination of future development
costs on reserves sold in the 1995 quarter.
For the 1995 period, operating results from the Exploration and Production
segment included natural gas production of approximately 33 Mmcf per day,
revenues of $12.9 million and operating profit of $4.2 million related to the
interests in the Bob West Field that were sold. For further information
regarding the sale of these interests, see Note 2 of Notes to Condensed
Consolidated Financial Statements.
Bolivia
Three Months Ended September 30, 1995 Compared With Three Months Ended September
30, 1994. Operating results from the Company's Bolivian operations decreased by
$.8 million during the 1995 quarter primarily due to a 19% 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 contributing to the decrease was a $1.09 per
barrel reduction 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 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.
Nine Months Ended September 30, 1995 Compared With Nine Months Ended September
30, 1994. Operating results from the Company's Bolivian operations decreased by
$1.2 million during the 1995 period, primarily due to a 14% 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. Partially offsetting the decrease in production was a $1.28 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.
17
Oil Field Supply and Distribution Three Months Ended Nine Months Ended
September 30, September 30,
------------------ -----------------
1995 1994 1995 1994
---- ---- ---- ----
(Dollars in millions)
Gross Operating Revenues . . . . . . . . . . . . . . $ 18.5 21.5 56.9 58.4
Costs of Sales . . . . . . . . . . . . . . . . . . . 15.8 19.0 49.2 50.7
--------- --------- --------- ---------
Gross Margin . . . . . . . . . . . . . . . . . . . 2.7 2.5 7.7 7.7
Operating Expenses and Other . . . . . . . . . . . . 3.4 2.6 10.0 9.2
Depreciation and Amortization. . . . . . . . . . . . - .1 .2 .3
--------- --------- --------- ---------
Operating Loss . . . . . . . . . . . . . . . . . . $( .7) ( .2) ( 2.5) ( 1.8)
========= ========= ========= =========
Refined Product Sales (average daily barrels). . . . 7,158 8,582 7,519 7,835
========= ========= ========= =========
Three Months Ended September 30, 1995 Compared With Three Months Ended September
30, 1994. During the 1995 quarter, the Company consolidated certain operations
in this segment by exiting the land-based portion of its petroleum product
distribution business in Texas. In these regards, the Company incurred a $.4
million charge related to the sale of four locations. Revenues and costs of
sales were lower during the 1995 quarter due to reduced volumes resulting from
the disposition of these locations, while margins improved by $.2 million. In
September 1995, the Company signed a letter of intent to acquire all of the
outstanding capital stock of Coastwide Energy Services, Inc. ("Coastwide") for
approximately $21 million, to be paid 40% in cash and 60% in Tesoro Common
Stock. Coastwide is a wholesale distributor of diesel fuel and lubricants and a
provider of services to the offshore drilling industry in the U.S. Gulf of
Mexico. Upon completion of the acquisition, which is subject to regulatory
approvals and approval by Coastwide shareholders, the Company would merge its
existing marine petroleum distribution operations with Coastwide, forming a
Marine Services segment.
Nine Months Ended September 30, 1995 Compared With Nine Months Ended September
30, 1994. As discussed above, during the 1995 period the Company discontinued
certain operations in this segment, resulting in a charge of $.4 million.
Revenues and cost of sales were lower in the 1995 period due to reduced volumes
resulting from the disposition of certain locations. In the 1994 period,
operating expenses included charges of $1.4 million for discontinuing the
Company's environmental products marketing operations.
Interest Income
The decreases of $.4 million and $1.0 million in interest income during the 1995
quarter and period, respectively, were primarily due to lower cash balances
available for investment.
Interest Expense
The increases of $.9 million and $2.1 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 capitalized interest in 1994. As discussed in Note 4 of Notes
to Condensed Consolidated Financial Statements, the Company expects to redeem
$34.6 million of its 12-3/4% Subordinated Debentures ("Subordinated Debentures")
which will result in a 1995 fourth quarter extraordinary loss of approximately
$3 million. This reduction in debt, together with lower borrowings under the
Company's Revolving Credit Facility, are expected to result in future annual
interest expense savings of approximately $5 million.
General and Administrative Expense
The increases of $.9 million and $1.9 million in general and administrative
expense during the 1995 quarter and period, respectively, were primarily due to
higher employee and other benefit costs.
18
Other Expense
The increase of $4.1 million in other expense during the 1995 quarter was
primarily due to severance costs and related benefits resulting from a reduction
in administrative workforce and other employee terminations (see Note 3 of Notes
to Condensed Consolidated Financial Statements). For the 1995 period, other
expense increased $2.2 million primarily due to the employee termination costs,
partially offset by lower environmental expenses related to former operations.
The Company anticipates a future annual cost savings of $4 million to $5 million
related to the reduction in workforce and other restructuring initiatives.
Income Taxes
Income taxes of $1.7 million in the 1995 quarter and $3.8 million in the 1995
period compare with $1.4 million in the 1994 quarter and $3.6 million in the
1994 period. No income taxes were provided on the gain on sales of assets
during the 1995 quarter or period due to the utilization of previously
unrecognized net operating loss and other 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 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 future capital expenditures, borrowings under its credit
arrangements, and other sources of capital will be affected by these conditions.
Although the Company expects continued market improvement, the Company's
operations in the past have been adversely affected by depressed market
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, in September 1995 the Company sold, effective
April 1, 1995, certain interests in the Bob West Field. For further information
on the sale of these interests, see Note 2 of Notes to Condensed Consolidated
Financial Statements. Net proceeds from the sale of these interests in the Bob
West Field are expected to be used to redeem a portion of the Company's
outstanding Subordinated Debentures, reduce borrowing under its Revolving Credit
Facility and improve corporate liquidity (see Note 4 of Notes to Condensed
Consolidated Financial Statements).
19
During the 1995 quarter, the Company consolidated certain operations in its Oil
Field Supply and Distribution segment by exiting the land-based portion of its
petroleum product distribution business in Texas. In these reguards, four
land-based locations have been sold. In September 1995, the Company signed a
letter of intent to acquire all of the outstanding capital stock of Coastwide
for approximately $21 million, to be paid 40% in cash and 60% in Tesoro Common
Stock. The Company expects to fund the cash portion of this purchase through
its available cash reserves. Upon completion of the acquisition, which is
subject to regulatory approvals and approval by Coastwide shareholders, the
Company would merge its existing marine petroleum distribution operations with
Coastwide, forming a Marine Services segment.
Credit Arrangements
The Company has financing and credit arrangements under a three-year corporate
Revolving Credit Facility ("Facility") dated April 20, 1994, with a consortium
of ten banks. The 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 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 Facility,
which has been amended from time to time, the Company is required to maintain
specified levels of working capital, tangible net worth, consolidated cash flow
and refining and marketing cash flow, as defined. Among other matters, the
Facility contains certain restrictions with respect to (i) capital expenditures,
(ii) incurrence of additional indebtedness, and (iii) dividends on capital
stock. The Facility contains other covenants customary in credit arrangements
of this kind. Future compliance with certain financial covenants 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. In October 1995, the Facility was
amended which, among other matters, (i) reduced available commitments from $100
million to $90 million, (ii) permits the Company to redeem a portion of its
outstanding Subordinated Debentures, and (iii) reduced the required level of
refining and marketing cash flow. If the Company's refining and marketing cash
flow, as defined, does not meet required levels, the $90 million availability
will be incrementally reduced, but not below $80 million.
At September 30, 1995, the Company had available commitments under the Facility
of $100 million which were fully supported by the borrowing base, as defined.
Included in the borrowing base at September 30, 1995 was a domestic oil and gas
reserve component of $40 million. At September 30, 1995, the Company had
outstanding letters of credit under the Facility of approximately $50 million
with no cash borrowings outstanding. For the nine months ended September 30,
1995, the Company's gross borrowings and repayments under the Facility totaled
$262.5 million, which were used on a short-term basis to finance working capital
requirements and capital expenditures.
Debt Obligations
The Company has given notice of its intention to redeem approximately $34.6
million of its outstanding Subordinated Debentures. The redemption date will be
December 1, 1995 at a price equal to 100% of the principal amount, plus accrued
interest to the redemption date. In the fourth quarter of 1995, the Company
expects to incur a noncash extraordinary loss of approximately $3 million from
this early extinguishment of debt, reflecting a write-off of unamortized bond
discount and issue costs. Following this partial redemption, which will satisfy
all future sinking fund requirements, the Company will have $30 million
principal amount of Subordinated Debentures outstanding, due on March 15, 2001.
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 other refinancings. On a pro forma
basis, if the Company would have redeemed $34.6 million principal amount of
Subordinated Debentures on September 30, 1995, the Company's ratio of debt to
capitalization would have been reduced from 47% to 43%.
20
Capital Expenditures
The Company's total capital expenditures for 1995 are estimated to be
approximately $58 million. 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 approximately $49 million. As a result of the sale in
September 1995 of certain interests in the Bob West Field, the Company has
reduced future capital expenditures by approximately $19 million which would
otherwise have been required to develop the proved reserves that were sold.
Capital expenditures for 1995 for the refining and marketing segment are
projected to be $8 million, primarily for capital improvements at the refinery
and expansion of the Company's retail locations in Alaska. For the nine months
ended September 30, 1995, total capital expenditures amounted to $49 million,
including $41 million for exploration and production and $7 million for refining
and 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 its available cash reserves.
Cash Flows
At September 30, 1995, the Company's net working capital totaled $105.1 million,
which included cash of $59.4 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 5 of Notes to
Condensed Consolidated Financial Statements.
Components of the Company's cash flows are set forth below (in millions):
Nine Months Ended
September 30,
1995 1994
Cash Flows From (Used In):
Operating Activities . . . . . . . . . . . . . $ 30.3 52.6
Investing Activities . . . . . . . . . . . . . 17.6 ( 62.8)
Financing Activities . . . . . . . . . . . . . ( 2.5) 4.0
--------- ---------
Increase (Decrease) in Cash and Cash Equivalents $ 45.4 ( 6.2)
========= =========
Net cash from operating activities of $30.3 million during the 1995 period
compares to $52.6 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 from investing activities during the 1995 period of $17.6 million included
proceeds of $70 million from sales of assets, primarily certain interests in the
Bob West Field, partially offset by $49 million of capital expenditures and $3
million for acquisition of the Kenai Pipe Line Company. Capital expenditures
for the 1995 period included $41 million for the Company's exploration and
production activities in South Texas, primarily for drilling and completion of
19 natural gas wells. Net cash used in financing activities of $2.5 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 $262.5 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 September 1995, the Contract Price was in excess of $8.00 per Mcf and the
average spot market price was $1.45 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")
21
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 the UCC. In
addition, the Supreme Court affirmed that the price under the Tennessee Gas
Contract is the Contract Price. 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. Through September 30, 1995, under the Tennessee Gas Contract,
the Company recognized cumulative net revenues in excess of spot market prices
(in excess of a $3.00 per Mcf nonrefundable Bond Price, as defined below, from
September 18, 1994 through August 13, 1995) totaling approximately $96.6
million. The Company's noncurrent receivable from Tennessee Gas totaled $42.7
million at September 30, 1995, representing the difference between the Contract
Price and the Bond Price, as defined below. 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 $53.9 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 for
this period is nonrefundable by the Company. On August 10, 1995, a hearing was
held before the trial court regarding the extension of the Tennessee Gas bond.
Pursuant to agreement of the parties, 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. On November 8, 1995, pursuant to agreement of the parties, the court
ordered that Tennessee Gas will, for the period October 16, 1995, until the
earlier of January 31, 1996, or the date the Supreme Court issues its ruling 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 $35 million bond in
addition to the $145 million bond presently in place. Tennessee Gas had
previously agreed to pay the Company the nonrefundable Bond Price until August
14, 1995. Under the provisions of the bond agreement, the Company retains the
right to receive the full contract price for all gas sold to Tennessee Gas.
22
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 September 30, 1995 the
Company's accruals for environmental matters, including the alleged violations
of the Clean Air Act, amounted to $10.5 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 $1
million, primarily for the removal and upgrading of underground storage tanks,
and approximately $10 million during 1997 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 further information on environmental contingencies, see
Note 5 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, under certain conditions, allow the Company
to temporarily or permanently reduce its purchase obligations.
As discussed in Note 5 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.
23
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 September 1995, the Contract Price was in excess of
$8.00 per Mcf and the average spot market price was $1.45 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 the UCC. In
addition, the Supreme Court affirmed that the price under the Tennessee Gas
Contract is the Contract Price. 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. Through September 30, 1995, under the Tennessee Gas Contract,
the Company recognized cumulative net revenues in excess of spot market prices
(in excess of a $3.00 per Mcf nonrefundable Bond Price, as defined below, from
September 18, 1994 through August 13, 1995) totaling approximately $96.6
million. The Company's noncurrent receivable from Tennessee Gas totaled $42.7
million at September 30, 1995, representing the difference between the Contract
Price and the Bond Price, as defined below. 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 $53.9 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 for
this period is nonrefundable by the Company. On August 10, 1995, a hearing was
held before the trial court regarding the extension of the Tennessee Gas bond.
Pursuant to agreement of the parties, 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. On November 8, 1995, pursuant to the agreement of the parties, the court
ordered that Tennessee Gas will, for the period October 16, 1995, until the
earlier of January 31, 1996, or the date the
24
Supreme Court issued its ruling 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 $35 million bond in addition to the $145 million bond presently in place.
Tennessee Gas had previously agreed to pay the Company the nonrefundable Bond
Price until August 14, 1995. Under the provisions of the bond agreement, the
Company retains the right to receive the full Contract Price for all gas sold to
Tennessee Gas.
Mineral Estate Claim. As previously reported, 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. On September 20, 1995, Plaintiffs filed a motion to
dismiss their lawsuit against all defendants except the United States. On
October 26, 1995, the court entered an order dismissing the Company and other
working and overriding royalty interest owners with prejudice.
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
The Company filed a report on Form 8-K dated October 11, 1995 reporting
under Item 2, Acquisition or Disposition of Assets, that on September
26, 1995 the Company sold effective April 1, 1995, certain interests in
the Company's onshore producing and non-producing oil and gas
properties located in the Bob West Field, Zapata and Starr Counties,
Texas.
25
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
Registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
TESORO PETROLEUM CORPORATION
Registrant
Date: November 14, 1995 /s/ Bruce A. Smith
Bruce A. Smith
President and Chief Executive Officer
Date: November 14, 1995 /s/ William T. Van Kleef
William T. Van Kleef
Senior Vice President
and Chief Financial Officer
26
EXHIBIT INDEX
Exhibit
Number
3 By-Laws of the Company, as amended through September 27, 1995.
4.1 Copy of Second Amendment and Supplement to Credit Agreement
effective as of September 1, 1995 among the Company and Texas
Commerce Bank National Association ("TCB") as Issuing Bank and
Agent, and certain other banks named therein.
4.2 Copy of Third Amendment to Credit Agreement effective as of
October 24, 1995 among the Company and TCB as Issuing Bank and
Agent, and certain other banks named therein.
11 Information Supporting Earnings (Loss) Per Share Computations.
27 Financial Data Schedule.
27