UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-Q
(Mark One)
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the quarterly period ended June 30, 1994
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 24,379,056 shares of the Registrant's Common Stock outstanding at
July 31, 1994.
<PAGE>
TESORO PETROLEUM CORPORATION AND SUBSIDIARIES
INDEX TO FORM 10-Q
FOR THE QUARTERLY PERIOD ENDED JUNE 30, 1994
PART I. FINANCIAL INFORMATION Page
Item 1. Financial Statements (Unaudited)
Condensed Consolidated Balance Sheets - June 30, 1994 and
December 31, 1993 . . . . . . . . . . . . . . . . . . . . . . . . 3
Condensed Statements of Consolidated Operations - Three Months
and Six Months Ended June 30, 1994 and 1993 . . . . . . . . . . . 4
Condensed Statements of Consolidated Cash Flows - Six Months
Ended June 30, 1994 and 1993 . . . . . . . . . . . . . . . . . . 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. . . . . . . . . . . . . . . . . . . . . . 22
Item 4. Submission of Matters to a Vote of Security Holders. . . . . 24
Item 6. Exhibits and Reports on Form 8-K . . . . . . . . . . . . . . 24
SIGNATURES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25
2
<PAGE>
PART I - FINANCIAL INFORMATION
Item 1. Financial Statements
TESORO PETROLEUM CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
(Dollars in thousands)
June 30, December 31,
1994 1993*
ASSETS
CURRENT ASSETS:
Cash and cash equivalents (includes restricted cash
of $25,420 at December 31, 1993) . . . . . . . . . $41,306 36,596
Short-term investments. . . . . . . . . . . . . . . . 1,974 5,952
Receivables, less allowance for doubtful accounts of
$2,233 ($2,487 at December 31, 1993). . . . . . . . 77,684 69,637
Inventories:
Crude oil, refined products and merchandise . . . . 58,382 71,011
Materials and supplies. . . . . . . . . . . . . . . 3,321 3,175
Prepaid expenses and other. . . . . . . . . . . . . . 12,427 10,136
--------- ---------
Total Current Assets. . . . . . . . . . . . . . . . 195,094 196,507
PROPERTY, PLANT AND EQUIPMENT, Net of Accumulated
Depreciation, Depletion and Amortization of
$184,495 ($172,312 at December 31, 1993). . . . . . . 240,657 213,151
INVESTMENT IN TESORO BOLIVIA PETROLEUM COMPANY . . . . 8,437 6,310
OTHER ASSETS . . . . . . . . . . . . . . . . . . . . . 19,111 18,554
--------- ---------
$ 463,299 434,522
========= =========
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES:
Accounts payable. . . . . . . . . . . . . . . . . . . $52,802 43,192
Accrued liabilities . . . . . . . . . . . . . . . . . 37,246 24,017
Current portion of long-term debt and other obligations 10,005 4,805
--------- ---------
Total Current Liabilities . . . . . . . . . . . . . 100,053 72,014
--------- ---------
OTHER LIABILITIES. . . . . . . . . . . . . . . . . . . 36,145 45,272
--------- ---------
LONG-TERM DEBT AND OTHER OBLIGATIONS, LESS
CURRENT PORTION . . . . . . . . . . . . . . . . . . . 178,665 180,667
--------- ---------
COMMITMENTS AND CONTINGENCIES (Note 5)
REDEEMABLE PREFERRED STOCK . . . . . . . . . . . . . . - 78,051
--------- ---------
COMMON STOCK AND OTHER STOCKHOLDERS' EQUITY:
$2.16 Cumulative convertible preferred stock. . . . . - 1,320
Common Stock. . . . . . . . . . . . . . . . . . . . . 4,049 2,348
Additional paid-in capital. . . . . . . . . . . . . . 175,476 86,985
Retained earnings (deficit) . . . . . . . . . . . . . ( 30,898) ( 31,898)
--------- ---------
148,627 58,755
Less deferred compensation. . . . . . . . . . . . . . 191 237
--------- ---------
148,436 58,518
--------- ---------
$ 463,299 434,522
========= =========
The accompanying notes are an integral part of these condensed consolidated
financial statements.
* The balance sheet at December 31, 1993 has been taken from the audited
consolidated financial statements at that date and condensed.
3
<PAGE>
<TABLE>
TESORO PETROLEUM CORPORATION AND SUBSIDIARIES
CONDENSED STATEMENTS OF CONSOLIDATED OPERATIONS
(Unaudited)
(In thousands, except per share amounts)
<CAPTION>
Three Months Ended Six Months Ended
June 30, June 30,
1994 1993 1994 1993
<S>
REVENUES: <C> <C> <C> <C>
Gross operating revenues. . . . . . . . . . $210,660 185,623 399,747 410,117
Interest income . . . . . . . . . . . . . . 452 471 975 922
Gain (loss) on sales of assets. . . . . . . ( 339) 4 2,341 52
Other . . . . . . . . . . . . . . . . . . . 272 97 722 1,585
---------- --------- --------- --------
Total Revenues. . . . . . . . . . . . . . 211,045 186,195 403,785 412,676
---------- --------- --------- ---------
COSTS AND EXPENSES:
Costs of sales and operating expenses . . . 191,228 172,132 358,833 385,869
General and administrative. . . . . . . . . 3,377 3,657 7,004 7,080
Depreciation, depletion and amortization. . 7,718 4,733 14,395 9,555
Interest expense, net of $240 capitalized
in 1994 . . . . . . . . . . . . . . . . . 4,629 2,812 9,506 7,825
Other . . . . . . . . . . . . . . . . . . . 2,252 1,306 3,443 2,969
---------- --------- --------- ---------
Total Costs and Expenses. . . . . . . . . 209,204 184,640 393,181 413,298
---------- --------- --------- ---------
EARNINGS (LOSS) BEFORE INCOME TAXES AND
EXTRAORDINARY LOSS ON EXTINGUISHMENT
OF DEBT . . . . . . . . . . . . . . . . . . 1,841 1,555 10,604 ( 622)
Income Tax Provision . . . . . . . . . . . . 611 67 2,172 799
---------- --------- --------- ---------
EARNINGS (LOSS) BEFORE EXTRAORDINARY LOSS
ON EXTINGUISHMENT OF DEBT . . . . . . . . . 1,230 1,488 8,432 ( 1,421)
Extraordinary Loss on Extinguishment of Debt - - ( 4,752) -
---------- --------- --------- ---------
NET EARNINGS (LOSS). . . . . . . . . . . . . 1,230 1,488 3,680 ( 1,421)
Dividend Requirements on Preferred Stock . . 791 2,302 2,680 4,604
---------- --------- --------- ---------
NET EARNINGS (LOSS) APPLICABLE TO
COMMON STOCK. . . . . . . . . . . . . . . . $ 439 ( 814) 1,000 ( 6,025)
========== ========= ========= =========
EARNINGS (LOSS) PER PRIMARY AND
FULLY DILUTED* SHARE:
Earnings (Loss) Before Extraordinary Loss on
Extinguishment of Debt. . . . . . . . . . $ .02 ( .06) .27 ( .43)
Extraordinary Loss on Extinguishment of Debt - - ( .22) -
---------- --------- --------- ---------
Net Earnings (Loss) . . . . . . . . . . . . $ .02 ( .06) .05 ( .43)
========== ========= ========= =========
AVERAGE OUTSTANDING COMMON AND COMMON
EQUIVALENT SHARES . . . . . . . . . . . . . 23,222 14,070 21,350 14,070
========== ========= ========= =========
*Anti-dilutive.
</TABLE>
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)
(Dollars in thousands)
Six Months Ended
June 30,
1994 1993
CASH FLOWS FROM (USED IN) OPERATING ACTIVITIES:
Net earnings (loss) . . . . . . . . . . . . . . . . . $ 3,680 ( 1,421)
Adjustments to reconcile net earnings (loss) to
net cash from operating activities:
Loss (gain) on extinguishment of debt . . . . . . . 4,752 ( 1,422)
Depreciation, depletion and amortization. . . . . . 14,395 9,555
Gain on sales of assets . . . . . . . . . . . . . . ( 2,341) ( 52)
Other . . . . . . . . . . . . . . . . . . . . . . . 792 1,334
Changes in assets and liabilities:
Receivables . . . . . . . . . . . . . . . . . . . ( 6,984) 16,080
Inventories . . . . . . . . . . . . . . . . . . . 12,483 7,678
Investment in Tesoro Bolivia Petroleum Company . . ( 2,127) ( 864)
Other assets . . . . . . . . . . . . . . . . . . . ( 1,824) 508
Accounts payable and other current liabilities . . 22,103 3,613
Obligation payments to State of Alaska . . . . . . ( 1,320) (11,517)
Other liabilities and obligations . . . . . . . . 1,442 1,543
--------- ----------
Net cash from operating activities . . . . . . . 45,051 25,035
--------- ----------
CASH FLOWS FROM (USED IN) INVESTING ACTIVITIES:
Capital expenditures . . . . . . . . . . . . . . . . (44,911) (12,765)
Proceeds from sales of assets, net of expenses . . . 2,247 121
Sales of short-term investments . . . . . . . . . . . 5,952 25,477
Purchases of short-term investments . . . . . . . . . ( 1,974) (20,293)
Other . . . . . . . . . . . . . . . . . . . . . . . . 3,850 ( 483)
--------- ----------
Net cash used in investing activities . . . . . . (34,836) ( 7,943)
--------- ----------
CASH FLOWS FROM (USED IN) FINANCING ACTIVITIES:
Proceeds from issuance of common stock, net . . . . . 56,967 -
Repurchase of common and preferred stock. . . . . . . (52,948) -
Dividends on preferred stock. . . . . . . . . . . . . ( 1,684) -
Payments of long-term debt. . . . . . . . . . . . . . (10,855) ( 841)
Issuance of long-term debt . . . . . . . . . . . . . 5,000 -
Repurchase of debentures . . . . . . . . . . . . . . - ( 9,675)
Other. . .. . . . . . . . . . . . . . . . . . . . . . ( 1,985) ( 5)
--------- ----------
Net cash used in financing activities. . . . . . . ( 5,505) (10,521)
--------- ----------
INCREASE IN CASH AND CASH EQUIVALENTS . . . . . . . . 4,710 6,571
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD . . . 36,596 46,869
--------- ----------
CASH AND CASH EQUIVALENTS AT END OF PERIOD . . . . . . $ 41,306 53,440
========= ==========
SUPPLEMENTAL CASH FLOW DISCLOSURES:
Interest paid, net of $240 capitalized in 1994. . . . $ 9,229 9,545
========= ==========
Income taxes paid . . . . . . . . . . . . . . . . . . $ 2,756 2,037
========= ==========
The accompanying notes are an integral part of these condensed consolidated
financial statements.
5
TESORO PETROLEUM CORPORATION AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
(1) Basis of Presentation
The interim condensed consolidated financial statements are unaudited but,
in the opinion of management, incorporate all adjustments necessary for a
fair presentation of results for such periods. Such adjustments are of a
normal recurring nature. For information regarding the effects of the
Recapitalization and Offering (as hereinafter defined), see Note 2 below.
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, 1993.
(2) Recapitalization and Equity Offering
Recapitalization. In February 1994, the Company consummated exchange offers
and adopted amendments to its Restated Certificate of Incorporation pursuant
to which the Company's outstanding debt and preferred stocks were
restructured (the "Recapitalization"). Significant components of the
Recapitalization, together with the applicable accounting effects, were as
follows:
(i) The Company exchanged $44.1 million principal amount of new 13% Exchange
Notes ("Exchange Notes") due December 1, 2000 for a like principal
amount of 12 3/4% Subordinated Debentures ("Subordinated Debentures")
due March 15, 2001. This exchange satisfied the 1994 sinking fund
requirement and, except for $.9 million, will satisfy sinking fund
requirements for the Subordinated Debentures through 1997.
The exchange of the Subordinated Debentures was accounted for as an
early extinguishment of debt in the first quarter of 1994, resulting in
a charge of $4.8 million as an extraordinary loss on this transaction,
which represented the excess of the estimated market value of the
Exchange Notes over the carrying value of the Subordinated Debentures.
The carrying value of the Subordinated Debentures exchanged was reduced
by applicable unamortized debt issue costs. No tax benefit was
available to offset the extraordinary loss as the Company has provided a
100% valuation allowance to the extent of its deferred tax assets.
(ii) The 1,319,563 outstanding shares of the Company's $2.16 Preferred Stock,
together with accrued and unpaid dividends of $9.5 million at February
9, 1994, were reclassified into 6,465,859 shares of Common Stock. The
Company also agreed to issue an additional 132,416 shares of Common
Stock, of which 73,913 shares had been issued at June 30, 1994, on
behalf of the holders of $2.16 Preferred Stock in connection with the
settlement of litigation related to the reclassification of the $2.16
Preferred Stock. The Company also paid $500,000 for certain legal fees
and expenses in connection with such litigation. The remaining 58,503
shares of Common Stock were issued in July 1994. The reclassification
of the $2.16 Preferred Stock eliminates preferred dividend requirements
of $2.9 million per year on the $2.16 Preferred Stock.
The issuance of the Common Stock in connection with the reclassification
and settlement of litigation that was recorded in 1994 resulted in an
increase in Common Stock of approximately $1 million, equal to the
aggregate par value of the Common Stock issued, and an increase in
additional paid-in capital of approximately $9 million.
(iii) The Company and MetLife Security Insurance Company of Louisiana
("MetLife Louisiana"), the holder of all of the Company's outstanding
$2.20 Cumulative Convertible Preferred Stock ("$2.20 Preferred Stock"),
entered into an agreement (the "Amended MetLife Memorandum") pursuant to
which MetLife Louisiana agreed, among other matters, to waive all
existing mandatory redemption requirements, to consider all accrued and
unpaid dividends on the $2.20 Preferred Stock (aggregating $21.2 million
at February 9, 1994) to have been paid, and to grant to the Company a
three-year option (the "MetLife Louisiana Option") to purchase all of
MetLife Louisiana's holdings of $2.20 Preferred Stock and Common Stock
for approximately $53 million prior to June 30, 1994 (after giving
effect to the cash dividend paid in May 1994), all in consideration for,
among other things, the issuance by the Company to MetLife Louisiana of
1,900,075 shares of Common Stock. Such additional shares were subject
to the MetLife Louisiana Option.
6
These actions resulted in the reclassification of the $2.20 Preferred
Stock into equity capital at its aggregate liquidation preference of
$57.5 million and the recording of an increase in additional paid-in
capital of approximately $21 million in February 1994.
Equity Offering. In June 1994, the Company completed a public offering (the
"Offering") of 5,850,000 shares of its Common Stock for the purpose of
raising funds to exercise the MetLife Louisiana Option. Net proceeds to the
Company from the Offering, after deduction of underwriting discounts and
commissions and associated expenses, were approximately $57.0 million. On
June 29, 1994, the Company exercised the MetLife Louisiana Option in full
for approximately $53.0 million, acquiring 2,875,000 shares of $2.20
Preferred Stock having a liquidation value of $57.5 million and 4,084,160
shares of Common Stock having an aggregate market value of $45.9 million
(based on a closing price of $11.25 per share on June 28, 1994). The
exercise eliminates preferred dividend requirements of $6.3 million per year
on the $2.20 Preferred Stock. The Offering and the exercise in full of the
MetLife Louisiana Option resulted in a net increase of 1,765,840 outstanding
shares of Common Stock, the retirement of $57.5 million of the $2.20
Preferred Stock, and increases in Common Stock of approximately $.3 million,
additional paid-in capital of approximately $61.2 million and cash of
approximately $4.0 million in June 1994.
If the Recapitalization and Offering had been completed at the beginning of
the year, the pro forma earnings per share before extraordinary loss would
have increased from $.27 to $.34 on both a primary and fully diluted basis
for the six months ended June 30, 1994, reflecting the elimination of all
preferred stock dividend requirements and the issuance of additional shares
of Common Stock associated with the Recapitalization and Offering reduced by
shares of Common Stock acquired and retired upon exercise of the MetLife
Louisiana Option.
The following table summarizes changes in certain components of Common Stock
and Stockholders' Equity during the six months ended June 30, 1994 (in
millions):
<TABLE>
<CAPTION>
$2.16 $2.20
Preferred Preferred Common Additional
Stock Stock Stock Paid-In
Shares Amount Shares Amount Shares Amount Capital
<S> <C> <C> <C> <C> <C> <C> <C>
Balances at December 31, 1993 . . . . . . 1.3 $ 1.3 - $ - 14.1 $ 2.3 $ 87.0
Reclassification of $2.16 Preferred Stock (1.3) (1.3) - - 6.5 1.1 9.7
Reclassification of $2.20 Preferred Stock - - 2.9 57.5 1.9 .3 20.9
Costs of Recapitalization . . . . . . . . - - - - - - ( 3.3)
Offering, Net . . . . . . . . . . . . . . - - - - 5.9 1.0 56.0
Exercise of MetLife Louisiana Option . . - - (2.9) (57.5) ( 4.1) ( .7) 5.2
----- ------- ------ -------- ------ ------- --------
Balances at June 30, 1994 . . . . . . . . - $ - - $ - 24.3 $ 4.0 $ 175.5
===== ======= ====== ======== ====== ======= ========
</TABLE>
(3) Property, Plant and Equipment
In January 1994, the Company sold its terminal facilities in Valdez, Alaska
for cash proceeds of $2.0 million and a note receivable of $3.0 million,
which resulted in a pretax gain to the Company of approximately $2.8 million
during the six months ended June 30, 1994.
(4) Credit Arrangements
Revolving Credit Facility. During April 1994, the Company entered into a
new three-year $125 million corporate revolving credit facility ("Revolving
Credit Facility") with a consortium of ten banks. The Revolving Credit
Facility, which is subject to a borrowing base, provides for (i) the
issuance of letters of credit up to the full amount of the borrowing base as
calculated, but not to exceed $125 million, and (ii) cash borrowings up to
the amount of the borrowing base attributable to domestic oil and gas
reserves. Outstanding obligations under the Revolving Credit Facility are
secured by liens on substantially all of the Company's trade accounts
receivable and product inventory and mortgages on the Company's Kenai,
Alaska refinery (the "Refinery") and the Company's South Texas natural gas
reserves.
7
Letters of credit available under the Revolving Credit Facility are limited
to a borrowing base calculation. As of June 30, 1994, the borrowing base,
which is comprised of eligible accounts receivable, inventory and domestic
oil and gas reserves, was approximately $96 million. As of June 30, 1994,
the Company had outstanding letters of credit under the new facility of
approximately $36 million, with a remaining unused availability of
approximately $60 million. Cash borrowings are limited to the amount of the
oil and gas reserve component of the borrowing base, which was initially
determined to be approximately $32 million. Cash borrowings under the
Revolving Credit Facility will reduce the availability of letters of credit
on a dollar-for-dollar basis; however, letter of credit issuances will not
reduce cash borrowing availability unless the aggregate dollar amount of
outstanding letters of credit exceeds the sum of the accounts receivable and
inventory components of the borrowing base.
Under the terms of the Revolving Credit Facility, the Company is required to
maintain specified levels of working capital, tangible net worth and cash
flow. Among other matters, the Revolving Credit Facility has certain
restrictions with respect to (i) capital expenditures, (ii) incurrence of
additional indebtedness, and (iii) dividends on capital stock. The
Revolving Credit Facility contains other covenants customary in credit
arrangements of this kind.
The Revolving Credit Facility replaced certain interim financing
arrangements that the Company had been using since the termination of its
prior letter of credit facility in October 1993. The interim financing
arrangements that were cancelled in conjunction with the completion of the
new Revolving Credit Facility included a waiver and substitution of
collateral agreement with the State of Alaska and a $30 million reducing
revolving credit facility. In addition, the completion of the Revolving
Credit Facility provides the Company significant flexibility in the
investment of excess cash balances, as the Company is no longer required to
maintain minimum cash balances or to secure letters of credit with cash. At
June 30, 1994, there were no cash borrowings under the Revolving Credit
Facility.
Vacuum Unit Loan. During May 1994, the National Bank of Alaska and the
Alaska Industrial Development & Export Authority agreed to provide a loan to
the Company of up to $15 million of the $24 million estimated cost of the
new vacuum unit for the Refinery (the "Vacuum Unit Loan"). The Vacuum Unit
Loan matures on January 1, 2002, requires 28 equal quarterly payments
beginning April 1995 and bears interest at the unsecured 90-day commercial
paper rate, adjusted quarterly, plus 2.6% per annum for two-thirds of the
amount borrowed and at the National Bank of Alaska floating prime rate plus
1/4 of 1% per annum for the remainder. The Vacuum Unit Loan is secured by a
first lien on the Refinery. At June 30, 1994, there were no borrowings
under the Vacuum Unit Loan.
(5) Commitments and Contingencies
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 (the "Tennessee Gas Contract") which
provides that the price of gas shall be the maximum price as calculated in
accordance with Section 102(b)(2) (the "Contract Price") of the Natural Gas
Policy Act of 1978 (the "NGPA"). Tennessee Gas filed suit against the
Company alleging that the Tennessee Gas Contract is not applicable to the
Company's properties and that the gas sales price should be the price
calculated under the provisions of Section 101 of the NGPA rather than the
Contract Price. During June 1994, the Contract Price was $8.04 per Mcf, the
Section 101 price was $4.68 per Mcf and the average spot market price was
$1.76 per Mcf. Tennessee Gas also claimed that the contract should be
considered an "output contract" under Section 2.306 of the Texas Business
and Commerce Code and that the increases in volumes tendered under the
contract exceeded those allowable for an output contract. The Company
continues to receive payment from Tennessee Gas based on the Contract Price
for all volumes that are subject to the contract, subject to whether
Tennessee Gas posts a supersedeas bond as discussed below.
The District Court judge returned a verdict in favor of the Company on all
issues. On appeal by Tennessee Gas, the Court of Appeals 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
8
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 Supreme
Court of Texas has agreed to hear arguments on December 13, 1994 regarding
the output contract issue and certain of the issues raised by Tennessee Gas.
Although the outcome of any litigation is uncertain, management, based upon
advice from outside legal counsel, is confident that the decision of the
trial and appellate courts will ultimately be upheld as to the validity of
the Tennessee Gas Contract and the Contract Price. Therefore, if the
Supreme Court of Texas affirms the appellate court ruling, the Company
believes that the only issue for trial should be whether the increases in
the volumes of gas tendered to Tennessee Gas from the Company's properties
were made in bad faith or were unreasonably disproportionate. The appellate
court decision was the first reported decision in Texas holding that a
take-or-pay contract was an output contract. As a result, it is not clear
what standard the trial court would be required to apply in determining
whether the increases were in bad faith or unreasonably disproportionate.
The appellate court acknowledged in its opinion that the standards used in
evaluating other kinds of output contracts would not be appropriate in this
context. The Company believes that the appropriate standard would be
whether the development of the field was undertaken in a manner that a
prudent operator would have undertaken in the absence of an above-market
sales price. Under that standard, the Company believes that, if this issue
is tried, the development of the Company's gas properties and the resulting
increases in volumes tendered to Tennessee Gas will be found to have been
reasonable and in good faith. Accordingly, the Company has recognized
revenues, net of production taxes and marketing charges, for natural gas
sales through June 30, 1994, under the Tennessee Gas Contract based on the
Contract Price, which net revenues aggregated $26.5 million more than the
Section 101 prices and $49.4 million in excess of spot market prices. If
Tennessee Gas ultimately prevails in this litigation, the Company could be
required to return to Tennessee Gas the difference between the spot market
price for gas and the Contract Price, plus interest if awarded by the court.
An adverse judgment in this case could have a material adverse effect on the
Company.
On August 4, 1994, the trial court rejected a motion by Tennessee Gas to
post a supersedeas bond in the form of monthly payments into the registry of
the court representing the difference between the Contract Price and spot
market price of gas sold to Tennessee Gas pursuant to the Tennessee Gas
Contract. Approximately 16% of the Company's current deliverability of
natural gas from the Bob West Field is subject to this contract. The court
advised Tennessee Gas that should it wish to supersede the judgment,
Tennessee Gas had the option to post a bond which would be effective only
until August 1, 1995, and that such bond must be in an amount equal to the
anticipated value of the contract during that period of time, which amount
is expected to be well in excess of $150 million for all producers,
including the Company. The court further stated that it would allow the
parties to attempt to reach an agreement on the amount of the bond for that
period, or, if an agreement could not be reached, the court would set the
amount of the bond. The Company is unable to predict whether the parties
will agree on the amount of a bond or whether Tennessee Gas will post the
bond once an amount is determined. However, even if Tennessee Gas posts a
bond, based on present spot market prices, the Company believes it will be
able to fund its capital expenditure program and comply with the financial
covenants under the Revolving Credit Agreement.
Environmental. In March 1992, the Company received a Compliance Order and
Notice of Violation from the U. S. Environmental Protection Agency ("EPA")
alleging violations by the Company of the New Source Performance Standards
under the Clean Air Act at the 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 Refinery in May 1992. As a result of this audit,
the EPA is also alleging violation of certain regulations relating to
asbestos materials. In October 1993, the EPA referred these matters to the
Department of Justice ("DOJ"). The DOJ recently contacted Tesoro Alaska 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. The DOJ has not given
the Company any indication of the amount of the penalty but has indicated
that any assessment will be more than a nominal amount and will factor in
the multiple years of violations. Negotiations on the consent decree will
begin once the parties negotiate a penalty. The Company is presently in
compliance with all of the regulations cited by the EPA except for one, and
will be in total compliance by the end of this year. The
9
Company believes that the ultimate resolution of this matter will not have a
material adverse effect upon the Company's business or financial condition.
The Company is subject to extensive federal, state and local environmental
laws and regulations. These laws, which are constantly changing, 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. The Company is
currently involved with two waste disposal sites in Louisiana at which it
has been named a potentially responsible party under the Federal Superfund
law. Although this law might impose joint and several liability upon each
party at any site, the extent of the Company's allocated financial
contribution to the cleanup of these sites is expected to be limited based
on the number of companies and the volumes of waste involved. At each site,
a number of large companies have also been named as potentially responsible
parties and are expected to cooperate in the cleanup. The Company is also
involved in remedial response and has incurred cleanup expenditures
associated with environmental matters at a number of other sites including
certain of its own properties.
At June 30, 1994, the Company had accrued $5.8 million for environmental
costs. Based on currently available information, including the
participation of other parties or former owners in remediation actions, the
Company believes these accruals are adequate. Conditions which require
additional expenditures may exist for various Company sites, including, but
not limited to, the Refinery, service stations (current and closed
locations) and petroleum product terminals, and for compliance with the
Clean Air Act. The amount of such future expenditures cannot presently be
determined by the Company.
Proposed Pipeline Rate Increase. The Company transports its crude oil and a
substantial portion of its refined products utilizing Kenai Pipe Line
Company's ("KPL") pipeline and marine terminal facilities in Kenai, Alaska.
In March 1994, KPL filed a revised tariff with the Federal Energy Regulatory
Commission ("FERC") for dock loading services, which would have increased
the Company's annual cost of transporting products through KPL's facilities
from $1.2 million to $11.2 million, or an increase of $10 million per year.
Following the FERC's rejection of KPL's tariff and the commencement of
negotiations for the purchase by the Company of the dock facilities, KPL
filed a temporary tariff that would increase the Company's annual cost by
approximately $1.5 million. The negotiations between the Company and KPL
are continuing. The Company believes that the ultimate resolution of this
matter will not have a material adverse effect upon the financial condition
or results of operations of the Company.
Refund Claim. In July 1994, Simmons Oil Corporation, also known as David
Christopher Corporation, a former customer of the Company ("Customer"),
filed suit against the Company in the United States District Court for the
District of New Mexico for a refund in the amount of approximately $1.2
million, plus interest of approximately $4.4 million and attorney's fees,
related to a gasoline purchase from the Company in 1979. The Customer also
alleges entitlement to treble damages and punitive damages in the aggregate
amount of $16.8 million. The refund claim is based on allegations that the
Company renegotiated the acquisition price of gasoline sold to the Customer
and failed to pass on the benefit of the renegotiated price to the Customer
in violation of Department of Energy price and allocation controls then in
effect. The Company believes the claim is without merit and anticipates
that the ultimate resolution of this matter will not have a material adverse
effect on the Company.
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 SIX MONTHS ENDED JUNE 30, 1994 COMPARED TO
THREE AND SIX MONTHS ENDED JUNE 30, 1993
A summary of the Company's consolidated results of operations for the three and
six months ended June 30, 1994 and 1993 is presented below:
Consolidated Results of Operations Data
Three Months Six Months
Ended Ended
June 30, June 30,
1994 1993 1994 1993
(Dollars in millions,
except per share amounts)
Gross Operating Revenues . . . . . . . . $210.7 185.6 399.7 410.1
Interest Income. . . . . . . . . . . . . .5 .5 1.0 .9
Gain (Loss) on Sales of Assets . . . . . ( .4) - 2.4 .1
Other Income . . . . . . . . . . . . . . .2 .1 .7 1.6
------- -------- ------- --------
Total Revenues. . . . . . . . . . . . . 211.0 186.2 403.8 412.7
Costs of Sales and Operating Expenses. . 191.2 172.1 358.8 385.9
General and Administrative . . . . . . . 3.4 3.7 7.0 7.0
Depreciation, Depletion and Amortization 7.7 4.7 14.4 9.6
Interest Expense . . . . . . . . . . . . 4.6 2.8 9.5 7.8
Other Expense. . . . . . . . . . . . . . 2.3 1.3 3.4 3.0
Income Tax Provision . . . . . . . . . . .6 .1 2.2 .8
------- -------- ------- --------
Earnings (Loss) Before Extraordinary Loss. 1.2 1.5 8.5 ( 1.4)
Extraordinary Loss on Extinguishment of Debt - - ( 4.8) -
------- -------- ------- --------
Net Earnings (Loss). . . . . . . . . . . 1.2 1.5 3.7 ( 1.4)
Dividend Requirements on Preferred Stock .8 2.3 2.7 4.6
------- -------- ------- --------
Earnings (Loss) Applicable to Common Stock $ .4 ( .8) 1.0 ( 6.0)
======= ======== ======= ========
Earnings (Loss) per Primary and Fully
Diluted* Share:
Earnings (Loss) Before Extraordinary Loss $ .02 ( .06) .27 ( .43)
Extraordinary Loss on Extinguishment of
Debt . . . . . . . . . . . . . . . . - - ( .22) -
------- -------- ------- --------
Net Earnings (Loss) . . . . . . . . . . $ .02 ( .06) .05 ( .43)
======= ======== ======= ========
*Anti-dilutive
Net earnings of $1.2 million, or $.02 per share, for the three months ended June
30, 1994 ("1994 second quarter") compare to net earnings of $1.5 million, or a
loss of $.06 per share after preferred stock dividend requirements, for the
three months ended June 30, 1993 ("1993 second quarter"). Included in the 1993
second quarter was a $3.0 million reduction in expenses for resolution of
certain state tax issues. Excluding this reduction, the improvement in the 1994
second quarter, as compared to the 1993 second quarter, was substantially
attributable to increased natural gas production from the Company's Bob West
Field in South Texas offset by lower operating results from the Company's
refining and marketing segment.
Net earnings of $3.7 million, or $.05 per share, for the six months ended June
30, 1994 compare to a net loss of $1.4 million, or $.43 per share, for the six
months ended June 30, 1993. The comparability between these two periods was
impacted by certain transactions. The 1994 period included a noncash
extraordinary loss of $4.8 million on the extinguishment of debt in connection
with the Recapitalization. Earnings before the extraordinary loss were $8.5
million, or $.27 per share, for the six months ended June 30, 1994. Also
included in the 1994 period was a $2.8 million gain on the sale of the Company's
Valdez, Alaska terminal. The 1993 period included the $3.0 million reduction in
expenses for resolution of certain state tax issues and a gain of $1.4 million
on the repurchase at market value and retirement of $11.25 million principal
amount of Subordinated Debentures. Excluding these transactions from both
periods, the improvement in 1994 as compared to 1993 was primarily attributable
to higher natural gas sales prices on increased natural gas production from the
Bob West Field.
11
<TABLE>
<CAPTION>
Refining and Marketing Three Months Ended Six Months Ended
June 30, June 30,
1994 1993 1994 1993
(Dollars in millions, except per unit amounts)
<S> <C> <C> <C> <C>
Gross Operating Revenues . . . . . . . . . $ 166.2 155.8 316.5 350.4
Costs of Sales. . . . . .. . . . . . . . . 147.6 133.1 271.8 306.2
-------- ------- --------- -------
Gross Margin. . . . . . . . . . . . . . . 18.6 22.7 44.7 44.2
Operating Expenses . . . . . . . . . . . . 20.7 17.9 40.6 35.6
Depreciation and Amortization. . . . . . . 2.6 2.6 5.2 5.1
Other (Income) Expense . . . . . . . . . . .3 - ( 2.5) .1
-------- ------- --------- -------
Operating Profit (Loss) . . . . . . . . . $( 5.0) 2.2 1.4 3.4
======== ======== ========= =======
Refinery Throughput (average daily barrels) 42,651 47,288 43,978 50,084
Sales of Refinery Production:
Sales ($ per barrel). . . . . . . . . . . $ 20.88 22.97 19.66 21.87
Margin ($ per barrel) . . . . . . . . . . $ 2.94 3.51 3.60 3.17
Volume (average daily barrels). . . . . . 44,688 43,498 45,453 50,401
Sales of Products Purchased for Resale:
Sales ($ per barrel). . . . . . . . . . . $ 24.91 27.50 24.53 26.97
Margin ($ per barrel) . . . . . . . . . . $ 2.52 1.30 2.56 1.13
Volume (average daily barrels). . . . . . 22,021 19,324 20,812 20,950
Sales Volumes (average daily barrels):
Gasoline. . . . . . . . . . . . . . . . . 21,596 20,609 22,080 23,243
Jet fuel. . . . . . . . . . . . . . . . . 12,413 8,754 11,549 10,642
Diesel fuel and other distillates . . . . 19,630 19,938 17,888 20,293
Residual fuel oil . . . . . . . . . . . . 13,070 13,521 14,748 17,173
-------- ------- --------- -------
Total . . . . . . . . . . . . . . . . . 66,709 62,822 66,265 71,351
======== ======== ========= =======
Sales Price ($ per barrel):
Gasoline. . . . . . . . . . . . . . . . . $ 27.01 27.67 25.44 26.66
Jet fuel. . . . . . . . . . . . . . . . . $ 24.31 29.06 24.83 28.85
Diesel fuel and other distillates . . . . $ 22.97 26.63 23.22 26.33
Residual fuel oil . . . . . . . . . . . . $ 11.14 12.90 9.52 12.03
Capital Expenditures . . . . . . . . . . . $ 8.2 .8 14.3 1.0
</TABLE>
12
Three Months Ended June 30, 1994 Compared to Three Months Ended June 30, 1993.
During the 1994 second quarter, U.S. refiners experienced rapidly increasing
crude oil prices and only slight product price increases, resulting in a rapid
decline in product margins. The Company's refining and marketing operations
were affected by these market conditions, resulting in an operating loss of $5.0
million for the 1994 second quarter compared to operating profit of $2.2 million
in the 1993 second quarter. Gross operating revenues increased by $10.4 million
in the 1994 second quarter, as compared to the 1993 second quarter, primarily
due to increased sales of crude oil and to a 6% increase in refined product
sales volumes, primarily jet fuel, offset in part by lower refined product
prices. Cost of sales were higher by $14.5 million in the 1994 second quarter
than in the 1993 second quarter due to the increase in sales volumes. The
increase in operating expenses in the 1994 second quarter, as compared to the
1993 second quarter, included higher transportation and advertising costs.
Decreased production of Alaska North Slope ("ANS") crude oil due to seasonal
maintenance of the Trans Alaska Pipeline System coupled with an increased demand
for ANS crude oil for use as a feedstock in West Coast refineries and the
general increase in the world price for crude oil resulted in an increase in the
cost of ANS crude oil to the Refinery during the 1994 second quarter. Sales
prices of refined products produced at the Refinery have not increased
proportionately and, as a result, refined product margins during the 1994 second
quarter have been depressed. Results from the Company's refining and marketing
segment will be adversely affected by these conditions for so long as such
conditions exist.
Six Months Ended June 30, 1994 Compared to Six Months Ended June 30, 1993.
Gross operating revenues decreased in the 1994 period as compared to the 1993
period, primarily due to a 7% reduction in sales volumes of refined products.
Costs of sales were lower in the 1994 period due to reduced throughput levels
and lower crude oil costs, while the increase in operating expenses included
higher transportation and advertising costs. Included in other income for the
1994 period was the $2.8 million gain from the sale of the Company's Valdez,
Alaska terminal. See discussion above for information relating to current
market conditions.
13
<TABLE>
<CAPTION>
Exploration and Production Three Months Ended Six Months Ended
June 30, June 30,
1994 1993 1994 1993
(Dollars in millions, except per unit amounts)
<S> <C> <C> <C> <C>
United States:
Gross operating revenues* . . . . . . . $ 22.8 8.6 40.2 16.3
Lifting cost. . . . . . . . . . . . . . 3.0 1.2 5.1 2.4
Depreciation, depletion and amortization 4.7 1.9 8.5 3.9
Other . . . . . . . . . . . . . . . . . .5 .3 .8 .6
-------- ------- --------- -------
Operating profit - United States. . . 14.6 5.2 25.8 9.4
-------- ------- --------- -------
Bolivia:
Gross operating revenues. . . . . . . . 3.3 3.1 6.1 5.9
Lifting cost. . . . . . . . . . . . . . .1 .5 .3 .9
Other . . . . . . . . . . . . . . . . . .7 .5 1.4 1.5
-------- ------- --------- -------
Operating profit - Bolivia. . . . . . 2.5 2.1 4.4 3.5
-------- ------- --------- -------
Total Operating Profit -
Exploration and Production . . . . . $ 17.1 7.3 30.2 12.9
======== ======= ========= =======
Natural Gas - United States:
Production (average daily Mcf) -
Spot market and other . . . . . . . . 51,003 21,656 41,960 21,157
Tennessee Gas Contract* . . . . . . . 19,902 6,237 18,052 6,296
-------- ------- --------- --------
Total production . . . . . . . . . . 70,905 27,893 60,012 27,453
======== ======= ========= =======
Average sales price per Mcf -
Spot market . . . . . . . . . . . . . $ 1.74 2.13 1.84 1.95
Tennessee Gas Contract* . . . . . . . $ 7.96 7.47 7.89 7.42
Average . . . . . . . . . . . . . . . $ 3.49 3.32 3.66 3.20
Average lifting cost per Mcf. . . . . . $ .49 .49 .51 .49
Depletion per Mcf . . . . . . . . . . . $ .73 .76 .78 .79
Capital expenditures. . . . . . . . . . $ 17.7 6.5 29.4 11.3
Natural Gas - Bolivia:
Production (average daily Mcf). . . . . 22,050 20,094 20,601 18,927
Average sales price per Mcf . . . . . . $ 1.20 1.20 1.21 1.19
Average lifting cost per net
equivalent Mcf . . . . . . . . . . . $ .03 .20 .07 .22
*The Company is involved in litigation with Tennessee Gas relating to a natural gas sales contract. See "Capital
Resources and Liquidity--Litigation", "Legal Proceedings--Tennessee Gas Contract" and Note 5 of Notes to Condensed
Consolidated Financial Statements.
</TABLE>
14
Three Months Ended June 30, 1994 Compared to Three Months Ended June 30, 1993.
Successful development drilling in the Bob West Field in South Texas was the
primary contributing factor to this segment's improvement when comparing the
1994 second quarter to the 1993 second quarter. The number of producing wells
in South Texas in which the Company has a working interest increased to 38 wells
at the end of the 1994 second quarter as compared to 15 wells at the end of the
1993 second quarter. The resulting 154% increase in the Company's production
levels in South Texas, together with higher average sales prices, contributed to
higher revenues. Total lifting costs and depreciation, depletion and
amortization also increased in the 1994 second quarter due to the higher
production levels. Production subject to spot market prices during the 1994
second quarter had been curtailed through mid-May due to limited transportation
facilities. The Company believes that recent expansions in pipeline capacity,
gathering systems and processing capacity have eliminated these constraints for
the foreseeable future.
The Company sells a portion of its share of natural gas production from the Bob
West Field to Tennessee Gas under the Tennessee Gas Contract which expires in
January 1999. Tennessee Gas may elect, and from time-to-time in the past has
elected, not to take gas under the Tennessee Gas Contract. Tennessee Gas has
the right to elect not to take gas during any contract year subject to an
obligation to pay for gas not taken at the end of such contract year. The
failure to take gas could adversely affect the Company's income and cash flows
from operating activities within a contract year, but the Company should recover
lost revenues shortly after the end of the contract year under the take-or-pay
provisions of the Tennessee Gas Contract. The contract year ends on January 31
of each year. See "Capital Resources and Liquidity--Litigation," "Legal
Proceedings--Tennessee Gas Contract" and Note 5 of Notes to Condensed
Consolidated Financial Statements regarding litigation involving the Tennessee
Gas Contract.
Results from the Company's Bolivian operations improved by $.4 million when
comparing the 1994 second quarter to the 1993 second quarter. Under a sales
contract with Yacimientos Petroliferos Fiscales Bolivianos ("YPFB"), the
Company's Bolivian natural gas production is sold to YPFB, which in turn sells
the natural gas to the Republic of Argentina. The contract between YPFB and the
Republic of Argentina has recently been extended for an additional three-year
period ending March 31, 1997. The contract extension will maintain
approximately the same volumes, but with a small decrease in price. The
Company's contract with YPFB, including the pricing provision, is presently
subject to renegotiation for up to a three-year period. As a result of the
terms of the contract extension between YPFB and the Republic of Argentina, the
Company expects the renegotiation of the Company's contract with YPFB to result
in a corresponding small decrease in the contract price. The renegotiation
could also result in a reduction of volumes purchased from the Company due to
new supply sources anticipated to commence production near the end of 1994.
Six Months Ended June 30, 1994 Compared to Six Months Ended June 30, 1993.
Revenues from the Company's South Texas exploration and production activities
increased by $23.9 million, or 147%, during the six months ended June 30, 1994,
as compared to the same period of 1993, primarily due to increased production
levels of natural gas. The Company had a working interest in 38 producing wells
in South Texas at June 30, 1994 as compared to 15 producing wells at June 30,
1993. The average sales price of the natural gas production was also up by 14%
during the 1994 period as compared to the 1993 period. The increased revenues
were partially offset by the correlating increase in lifting costs and
depreciation, depletion and amortization due to the higher production levels.
As discussed above, natural gas production subject to spot market sales prices
had been curtailed from February to mid-May 1994 due to constraints on
transportation facilities. The Company believes that the recent expansions in
pipeline capacity, gathering systems and processing capacities have eliminated
such constraints for the foreseeable future.
Operating results from the Company's Bolivian operations improved by $.9 million
during the six months ended June 30, 1994, as compared to the same period of
1993, due primarily to increased production of natural gas, higher natural gas
sales prices and reduced operating expenses. See discussion above for
information relating to the Company's contract with YPFB regarding sales of
natural gas production.
15
<TABLE>
<CAPTION>
Oil Field Supply and Distribution Three Months Ended Six Months Ended
June 30, June 30,
1994 1993 1994 1993
(Dollars in millions, except per unit amounts)
<S> <C> <C> <C> <C>
Gross Operating Revenues . . . . . . . . $ 18.3 18.1 36.9 37.5
Costs of Sales . . . . . . . . . . . . . 15.8 15.0 31.7 31.6
------- ------- ------- -------
Gross Margin . . . . . . . . . . . . . 2.5 3.1 5.2 5.9
Operating Expenses and Other . . . . . . 2.9 3.5 7.1 7.0
Depreciation and Amortization. . . . . . .1 .2 .2 .3
Other (Income) Expense . . . . . . . . . ( .1) - ( .5) -
------- ------- ------- -------
Operating Loss . . . . . . . . . . . . $( .4) ( .6) ( 1.6) ( 1.4)
======= ======= ======= =======
Refined Product Sales (average daily
barrels) . . . . . . . . . . . . 7,486 6,255 7,455 6,540
</TABLE>
Three Months Ended June 30, 1994 Compared to Three Months Ended June 30, 1993.
Although sales volumes of refined products were higher during the 1994 second
quarter as compared to the 1993 second quarter, refined product sales prices and
gross margins were lower due to the strong competition in an oversupplied
market. Partially offsetting the reduction in gross margins were lower
operating expenses due to consolidation of certain of the Company's terminals
and to the discontinuance of the Company's environmental products marketing
operations. The Company is continuing its wholesale marketing of fuels and
lubricants.
Six Months Ended June 30, 1994 Compared to Six Months Ended June 30, 1993.
Increased sales volumes of refined products in this segment during the 1994
period, as compared to the 1993 period, were offset by lower sales prices and
margins due to the strong competition in an oversupplied market. The decrease
in operating expenses during the 1994 period as compared to the 1993 period,
which resulted from consolidation of certain terminals, was substantially offset
by a $.9 million charge recorded in the 1994 period for winding up the Company's
environmental products marketing operations which was discontinued in the first
quarter of 1994.
Other Income
During the six months ended June 30, 1994, other income decreased by $.9 million
as compared to the same period of the prior year. This decrease was primarily
due to a $1.4 million gain recorded in the 1993 period for the purchase and
retirement of $11.25 million principal amount of Subordinated Debenture in
January 1993. Since this retirement satisfied the sinking fund requirement due
in March 1993, the gain was not reported as an extraordinary item.
Interest Expense
The increase of $1.8 million in interest expense during the 1994 second quarter,
as compared to the 1993 second quarter, was primarily due to a reduction
recorded in the 1993 second quarter related to the resolution of certain state
tax issues partially offset by capitalized interest of $.2 million recorded in
the 1994 second quarter. The increase of $1.7 million in interest expense for
the six months ended June 30, 1994, as compared to the prior year period, was
also due to the resolution of certain tax issues in 1993 partially offset by
capitalized interest in 1994.
Other Expense
Other expense increased by $1.0 million in the second quarter of 1994, as
compared to the 1993 quarter, primarily due to environmental expenses related to
former operations of the Company.
16
Income Taxes
The increase of $.5 million in the income tax provision during the 1994 second
quarter was primarily due to a reduction in income taxes in the 1993 second
quarter for resolution of certain state tax issues. The increase of $1.4
million in the income tax provision during the six months ended June 30, 1994,
as compared to the same period in 1993, included higher federal and state income
taxes on the Company's increased taxable earnings in the 1994 period and the
effect of a reduction recorded in the 1993 period for resolution of certain
state tax issues.
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 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 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
During the first half of 1994, the Company consummated a Recapitalization and
Offering pursuant to which the Company's outstanding debt and preferred stock
were restructured and which, among other matters, eliminated annual dividend
requirements of $9.2 million on the Company's preferred stocks, deferred $44
million of debt service requirements and increased stockholders' equity by
approximately $82 million. The Company also entered into a new $125 million
corporate Revolving Credit Facility and obtained $15 million additional
financing for a major addition to the Refinery. These accomplishments have
significantly improved the Company's short-term and long-term liquidity and
increased the Company's equity capital and financial resources. The combination
of these events together with the Company's capital investment program for 1994
are expected to significantly enhance future profitability.
Significant components of the Recapitalization and Offering were as follows:
(i) Subordinated Debentures in the principal amount of $44.1 million were
tendered in exchange for a like principal amount of new Exchange Notes,
which satisfied the 1994 sinking fund requirement and, except for $.9
million, will satisfy sinking fund requirements for the Subordinated
Debentures through 1997. The Exchange Notes bear interest at 13% per
annum, are scheduled to mature on December 1, 2000 and have no sinking
fund requirements.
(ii) The 1,319,563 outstanding shares of the Company's $2.16 Preferred Stock,
together with accrued and unpaid dividends of $9.5 million at February
9, 1994, were reclassified into 6,465,859 shares of Common Stock. The
Company also agreed to issue an additional 132,416 shares of Common
Stock, of which 73,913 shares had been issued at June 30, 1994, on
behalf of the holders of $2.16 Preferred Stock in connection with the
settlement of litigation related to the reclassification of the $2.16
Preferred Stock. The Company also paid $500,000 for certain legal fees
and expenses in connection with such litigation. The remaining 58,503
shares of Common Stock were issued in July 1994.
(iii) The Company and MetLife Louisiana, the holder of all the Company's
outstanding $2.20 Preferred Stock, entered into the Amended MetLife
Memorandum, pursuant to which MetLife Louisiana agreed, among other
matters, to waive all existing mandatory redemption requirements, to
consider all accrued and unpaid dividends thereon through February 9,
1994 (aggregating approximately $21.2 million) to have been paid, and to
grant to the Company the MetLife Louisiana Option (pursuant to which the
Company had the option to purchase all shares of the $2.20 Preferred
Stock and Common Stock held by MetLife Louisiana), all in consideration
for, among other things, the issuance by the Company to MetLife
Louisiana of 1,900,075 shares of Common Stock. At June 29, 1994, the
option price under the MetLife Louisiana Option was approximately $52.9
million, after giving effect to a reduction for cash dividends paid on
the $2.20 Preferred Stock in May 1994.
17
(iv) Net proceeds of approximately $57.0 million from the issuance of
5,850,000 shares of the Company's Common Stock were used to exercise the
MetLife Louisiana Option in full for approximately $52.9 million. The
net effects of the Offering and exercise of the MetLife Louisiana Option
include the Company's reacquisition of 2,875,000 shares of $2.20
Preferred Stock and a net increase of 1,765,840 shares of Common Stock
outstanding.
For further information regarding the Recapitalization and Offering, see Note 2
of Notes to Condensed Consolidated Financial Statements.
Credit Arrangements
During April 1994, the Company entered into a new three-year $125 million
corporate Revolving Credit Facility with a consortium of ten banks. The
Revolving Credit Facility, which is subject to a borrowing base, provides for
(i) the issuance of letters of credit up to the full amount of the borrowing
base as calculated, but not to exceed $125 million and (ii) cash borrowings up
to the amount of the borrowing base attributable to domestic oil and gas
reserves. Outstanding obligations under the Revolving Credit Facility are
secured by liens on substantially all of the Company's trade accounts receivable
and product inventory and mortgages on the Refinery and the Company's South
Texas natural gas reserves.
Letters of credit available under the Revolving Credit Facility are limited to a
borrowing base calculation. As of June 30, 1994, the borrowing base, which is
comprised of eligible accounts receivable, inventory and domestic oil and gas
reserves, was approximately $96 million. As of June 30, 1994, the Company had
outstanding letters of credit under the new facility of approximately $36
million, with a remaining unused availability of approximately $60 million.
Cash borrowings are limited to the amount of the oil and gas reserve component
of the borrowing base, which was initially determined to be approximately $32
million. Under the terms of the Revolving Credit Facility, the cash component
of the borrowing base is subject to quarterly reevaluations. Based on the
increase in the Company's proved domestic oil and gas reserves during the 1994
second quarter, the Company anticipates a substantial increase in cash borrowing
availability. Cash borrowings under the Revolving Credit Facility will reduce
the availability of letters of credit on a dollar-for-dollar basis; however,
letter of credit issuances will not reduce cash borrowing availability unless
the aggregate dollar amount of outstanding letters of credit exceeds the sum of
the accounts receivable and inventory components of the borrowing base. The
terms of the Revolving Credit Facility include standard and customary
restrictions and covenants. For information concerning such restrictions and
covenants, see Note 4 of Notes to Condensed Consolidated Financial Statements.
The Revolving Credit Facility replaced certain interim financing arrangements
that the Company had been using since the termination of its prior letter of
credit facility in October 1993. The interim financing arrangements that were
cancelled in conjunction with the completion of the new Revolving Credit
Facility included a waiver and substitution of collateral agreement with the
State of Alaska and a $30 million reducing revolving credit facility. In
addition, the completion of the Revolving Credit Facility provides the Company
significant flexibility in the investment of excess cash balances, as the
Company is no longer required to maintain minimum cash balances or to secure
letters of credit with cash. At June 30, 1994, there were no cash borrowings
under the Revolving Credit Facility.
During May 1994, the National Bank of Alaska and the Alaska Industrial
Development & Export Authority agreed to provide a loan to the Company of up to
$15 million of the $24 million estimated cost of the vacuum unit for the
Refinery (the "Vacuum Unit Loan"). The Vacuum Unit Loan matures on January 1,
2002 and is secured by a first lien on the Refinery. At June 30, 1994, there
were no borrowings under the Vacuum Unit Loan. For further information on the
Vacuum Unit Loan, see Note 4 of Notes to Condensed Consolidated Financial
Statements.
18
Debt and Other Obligations
The Company's funded debt obligations as of December 31, 1993 included
approximately $108.8 million principal amount of Subordinated Debentures, which
bear interest at 12 3/4% per annum and require sinking fund payments sufficient
to annually retire $11.25 million principal amount of Subordinated Debentures.
As part of the Recapitalization, $44.1 million principal amount of Subordinated
Debentures was tendered in exchange for a like principal amount of Exchange
Notes. Such exchange satisfied the 1994 sinking fund requirement and, except
for $.9 million, will satisfy sinking fund requirements for the Subordinated
Debentures through 1997. The indenture governing the Subordinated Debentures
contains certain covenants, including a restriction which prevents the current
payment of cash dividends on Common Stock and currently limits the Company's
ability to purchase or redeem any shares of its capital stock. The Exchange
Notes bear interest at 13% per annum, mature on December 1, 2000 and have no
sinking fund requirements. The limitation on dividend payments included in the
indenture governing the Exchange Notes is less restrictive than the limitation
imposed by the Subordinated Debentures. The Subordinated Debentures and
Exchange Notes are redeemable at the option of the Company at 100% of principal
amount, plus accrued interest.
Cash Flows From Operating, Investing and Financing Activities
During the six months ended June 30, 1994, cash and cash equivalents increased
by $4.7 million and short-term investments decreased by $4.0 million. At June
30, 1994, the Company's cash and short-term investments totaled $43.3 million
and working capital amounted to $95.0 million. Net cash from operating
activities of $45.0 million during the six months ended June 30, 1994, compared
to $25.0 million for the comparable 1993 period, was primarily due to net
earnings adjusted for certain noncash charges and reduced working capital
requirements. The 1993 comparable period included payments totaling $11.5
million to the State of Alaska in connection with the settlement of a
contractual dispute, as compared to $1.3 million paid to the State of Alaska in
the 1994 period. Net cash used in investing activities of $34.8 million during
the six months ended June 30, 1994 included capital expenditures of $44.9
million, an increase of $32.1 million from the comparable prior year period.
Capital expenditures for the six months ended June 30, 1994 included $29.4
million for exploration and production activities in the Bob West Field, where
11 natural gas development wells were completed and gas processing facilities
and pipelines were constructed. The refining and marketing segment's capital
expenditures totaled $14.3 million for the six months ended June 30, 1994
primarily for installation costs for the vacuum unit at the Refinery. These
uses of cash in investing activities were partially offset by the net decrease
of $4.0 million in short-term investments and cash proceeds of $2.2 million,
primarily from the sale of the Company's Valdez, Alaska terminal. Net cash used
in financing activities of $5.5 million during the six months ended June 30,
1994 included the repayment of net borrowings of $5.0 million under the reducing
revolving credit facility which was replaced by the Revolving Credit Facility
(see Note 4 of Notes to Condensed Consolidated Financial Statements). In
addition, dividends totaling $1.7 million were paid on preferred stock and $4.0
million net proceeds were received from the Offering after the exercise of the
MetLife Louisiana Option.
The Company has under consideration total capital expenditures for 1994 of
approximately $100 million, compared to $37.5 million during 1993. Capital
expenditures for 1994 in the Company's domestic exploration and production
operations are projected to be approximately $65 million, primarily for
continued development of the Bob West Field and construction of gas processing
facilities and pipelines for the increased production from this field. The
Company expects to participate in the drilling of 27 development gas wells in
the Bob West Field during 1994, of which 11 wells had been completed during the
first six months of 1994. Capital projects for the Company's refining and
marketing operations for 1994 are anticipated to total approximately $35
million, of which $24 million is associated with the installation of the vacuum
unit at the Refinery to allow the Company to further upgrade residual fuel oil
production into higher-valued products. For the six months ended June 30, 1994,
total capital expenditures amounted to $44.9 million, including $29.4 million
for exploration and production operations and $14.3 million for refining and
marketing operations, which were funded by the Company's cash flows from
operating activities and existing cash. The Company anticipates that capital
expenditures for the remainder of 1994 will be funded with cash flows from
operating activities, existing cash balances and borrowings under the Vacuum
Unit Loan. If necessary, the Company has additional cash borrowing availability
under the Revolving Credit Facility. As discussed in "Capital Resources and
Liquidity--Litigation," "Legal Proceedings-- Tennessee Gas Contract" and Note 5
of Notes to Condensed Consolidated Financial Statements, the Company's cash
flows from the Tennessee Gas Contract could be significantly reduced.
19
Proposed Pipeline Rate Increase
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. In March 1994, KPL filed a revised tariff with the FERC for dock
loading services, which would have increased the Company's annual cost of
transporting products through KPL's facilities from $1.2 million to $11.2
million, or an increase of $10 million per year. Following the FERC's rejection
of KPL's tariff and the commencement of negotiations for the purchase by the
Company of the dock facilities, KPL filed a temporary tariff that would increase
the Company's annual cost by approximately $1.5 million. The negotiations
between the Company and KPL are continuing. The Company believes that the
ultimate resolution of this matter will not have a material adverse effect upon
the financial condition or results of operations of the Company.
Litigation
The Company is subject to certain commitments and contingencies, including a
contingency relating to a natural gas sales contract dispute with Tennessee Gas.
The Company is selling a portion of the gas from its Bob West Field to Tennessee
Gas under a Gas Purchase and Sales Agreement which provides that the price of
gas shall be the maximum price as calculated in accordance with Section
102(b)(2) (the "Contract Price") of the Natural Gas Policy Act of 1978 (the
"NGPA"). Tennessee Gas filed suit against the Company alleging that the gas
contract is not applicable to the Company's properties and that the gas sales
price should be the price calculated under the provisions of Section 101 of the
NGPA rather than the Contract Price. During June 1994, the Contract Price was
$8.04 per Mcf, the Section 101 price was $4.68 per Mcf and the average spot
market price was $1.76 per Mcf. Tennessee Gas also claimed that the contract
should be considered an "output contract" under Section 2.306 of the Texas
Business and Commerce Code and that the increases in volumes tendered under the
contract exceeded those allowable for an output contract. The Company continues
to receive payment from Tennessee Gas based on the Contract Price for all
volumes that are subject to the contract, subject to whether Tennessee Gas posts
a supersedeas bond as discussed below.
The District Court judge returned a verdict in favor of the Company on all
issues. On appeal by Tennessee Gas, the Court of Appeals 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 Supreme Court
of Texas has agreed to hear arguments on December 13, 1994 regarding the output
contract issue and certain of the issues raised by Tennessee Gas.
Although the outcome of any litigation is uncertain, management, based upon
advice from outside legal counsel, is confident that the decision of the trial
and appellate courts will ultimately be upheld as to the validity of the
Tennessee Gas Contract and the Contract Price. Therefore, if the Supreme Court
of Texas affirms the appellate court ruling, the Company believes that the only
issue for trial should be whether the increases in the volumes of gas tendered
to Tennessee Gas from the Company's properties were made in bad faith or were
unreasonably disproportionate. The appellate court decision was the first
reported decision in Texas holding that a take-or-pay contract was an output
contract. As a result, it is not clear what standard the trial court would be
required to apply in determining whether the increases were in bad faith or
unreasonably disproportionate. The appellate court acknowledged in its opinion
that the standards used in evaluating other kinds of output contracts would not
be appropriate in this context. The Company believes that the appropriate
standard would be whether the development of the field was undertaken in a
manner that a prudent operator would have undertaken in the absence of an
above-market sales price. Under that standard, the Company believes that, if
this issue is tried, the development of the Company's gas properties and the
resulting increases in volumes tendered to Tennessee Gas will be found to have
been reasonable and in good faith. Accordingly, the Company has recognized
revenues, net of production taxes and marketing charges, for natural gas sales
through June 30, 1994, under the Tennessee Gas Contract based on the Contract
Price, which net revenues aggregated $26.5 million more than the Section 101
prices and $49.4 million in excess of the spot market prices. If Tennessee Gas
ultimately prevails in this litigation, the Company could be required to return
to Tennessee Gas the difference between the spot market price for gas and the
Contract Price, plus interest if awarded by the court. An
20
adverse judgment in this case could have a material adverse effect on the
Company. See "Legal Proceedings--Tennessee Gas Contract" and Note 5 of Notes to
Condensed Consolidated Financial Statements.
On August 4, 1994, the trial court rejected a motion by Tennessee Gas to post a
supersedeas bond in the form of monthly payments into the registry of the court
representing the difference between the Contract Price and spot market price of
gas sold to Tennessee Gas pursuant to the Tennessee Gas Contract. Approximately
16% of the Company's current deliverability of natural gas from the Bob West
Field is subject to this contract. The court advised Tennessee Gas that should
it wish to supersede the judgment, Tennessee Gas had the option to post a bond
which would be effective only until August 1, 1995, and that such bond must be
in an amount equal to the anticipated value of the contract during that period
of time, which amount is expected to be well in excess of $150 million for all
producers, including the Company. The court further stated that it would allow
the parties to attempt to reach an agreement on the amount of the bond for that
period, or, if an agreement could not be reached, the court would set the amount
of the bond. The Company is unable to predict whether the parties will agree on
the amount of a bond or whether Tennessee Gas will post the bond once an amount
is determined. However, even if Tennessee Gas posts a bond, based on present
spot market prices, the Company believes it will be able to fund its capital
expenditure program and comply with the financial covenants under the Revolving
Credit Agreement.
Environmental
The Company is subject to extensive federal, state and local environmental laws
and regulations. These laws, which are constantly changing, 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 in
discussions with the DOJ concerning the assessment of penalties with respect to
certain alleged violations of environmental laws and regulations. Although the
level of future expenditures for environmental purposes, including cleanup
obligations, is impossible to determine with any degree of probability, it is
management's opinion that, based on current knowledge and the extent of such
expenditures to date, the ultimate aggregate cost of environmental remediation
will not have a material adverse effect on the Company's financial condition.
At June 30, 1994, the Company's accrual for environmental liabilities was $5.8
million. See "Legal Proceedings--Clean Air Act Matters" and Note 5 of Notes to
Condensed Consolidated Financial Statements..
21
PART II - OTHER INFORMATION
Item 1. Legal Proceedings
Tennessee Gas Contract. The Company is selling a portion of the gas from its
Bob West Field to Tennessee Gas under a Gas Purchase and Sales Agreement
which provides that the price of gas shall be the maximum price as calculated
in accordance with Section 102(b)(2) of the NGPA. Tennessee Gas filed suit
against the Company alleging that the gas contract is not applicable to the
Company's properties and that the gas sales price should be the price
calculated under the provisions of Section 101 of the NGPA rather than the
Contract Price. During June 1994, the Contract Price was $8.04 per Mcf, the
Section 101 price was $4.68 per Mcf and the average spot market price was
$1.76 per Mcf. Tennessee Gas also claimed that the contract should be
considered an "output contract" under Section 2.306 of the Texas Business and
Commerce Code and that the increases in volumes tendered under the contract
exceeded those allowable for an output contract. The Company continues to
receive payment from Tennessee Gas based on the Contract Price for all
volumes that are subject to the contract, subject to whether Tennessee Gas
posts a supersedeas bond as discussed below.
The District Court judge returned a verdict in favor of the Company on all
issues. On appeal by Tennessee Gas, the Court of Appeals 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 Supreme Court of Texas has agreed to hear arguments on
December 13, 1994 regarding the output contract issue and certain of the
issues raised by Tennessee Gas.
Although the outcome of any litigation is uncertain, management, based upon
advice from outside legal counsel, is confident that the decision of the
trial and appellate courts will ultimately be upheld as to the validity of
the Tennessee Gas Contract and the Contract Price. Therefore, if the Supreme
Court of Texas affirms the appellate court ruling, the Company believes that
the only issue for trial should be whether the increases in the volumes of
gas tendered to Tennessee Gas from the Company's properties were made in bad
faith or were unreasonably disproportionate. The appellate court decision
was the first reported decision in Texas holding that a take-or-pay contract
was an output contract. As a result, it is not clear what standard the trial
court would be required to apply in determining whether the increases were in
bad faith or unreasonably disproportionate. The appellate court acknowledged
in its opinion that the standards used in evaluating other kinds of output
contracts would not be appropriate in this context. The Company believes
that the appropriate standard would be whether the development of the field
was undertaken in a manner that a prudent operator would have undertaken in
the absence of an above-market sales price. Under that standard, the Company
believes that, if this issue is tried, the development of the Company's gas
properties and the resulting increases in volumes tendered to Tennessee Gas
will be found to have been reasonable and in good faith. Accordingly, the
Company has recognized revenues, net of production taxes and marketing
charges, for natural gas sales through June 30, 1994, under the Tennessee Gas
Contract based on the Contract Price, which net revenues aggregated $26.5
million more than the Section 101 prices and $49.4 million in excess of the
spot market prices. If Tennessee Gas ultimately prevails in this litigation,
the Company could be required to return to Tennessee Gas the difference
between the spot market price for gas and the Contract Price, plus interest
if awarded by the court. An adverse judgment in this case could have a
material adverse effect on the Company. See Note 5 of Notes to Condensed
Consolidated Financial Statements.
On August 4, 1994, the trial court rejected a motion by Tennessee Gas to post
a supersedeas bond in the form of monthly payments into the registry of the
court representing the difference between the Contract Price and spot market
price of gas sold to Tennessee Gas pursuant to the Tennessee Gas Contract.
Approximately 16% of the Company's current deliverability of natural gas from
the Bob West Field is subject to this contract. The court advised Tennessee
Gas that should it wish to supersede the judgment, Tennessee Gas had the
option to post a bond which would be effective only until August 1, 1995, and
that such bond must be in an amount equal to the anticipated value of the
contract during that period of time, which amount is expected to be well in
excess of $150 million for all producers, including the Company. The court
further stated that it would allow the parties to attempt to reach an
agreement on the amount of the bond for that period, or, if an agreement
could not be reached, the court would set the amount of the bond. The
Company is unable to predict whether the parties will agree on the amount of
a bond or whether Tennessee Gas will post the bond once an amount is
determined.
22
Item 1. Legal Proceedings (Continued)
Clean Air Act Matters. As previously reported, the EPA issued a notice of
violation/compliance order to the Company's subsidiary, Tesoro Alaska
Petroleum Company ("Tesoro Alaska"), in March 1992 for alleged violations of
regulations promulgated under the Clean Air Act. 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 Tesoro Alaska exchanged information
relevant to these allegations. In addition, the EPA conducted an
environmental audit of Tesoro Alaska's refinery in May 1992. As a result of
this audit, the EPA is also alleging violation of certain regulations
relating to asbestos materials. In October 1993, the EPA referred these
matters to the DOJ. The DOJ recently contacted Tesoro Alaska to begin
negotiating a resolution of these matters. The DOJ has indicated that it is
willing to enter into a judicial consent decree with Tesoro Alaska and that
this decree would include a penalty assessment. The DOJ has not given Tesoro
Alaska any indication of the amount of the penalty but has indicated that any
assessment will be more than a nominal amount and will factor in the multiple
years of violations. Negotiations on the consent decree will begin once the
parties negotiate a penalty. Tesoro Alaska is presently in compliance with
all of the regulations cited by the EPA except for one, and will be in total
compliance by the end of this year. The Company believes that the ultimate
resolution of this matter will not have a material adverse effect upon the
Company's business or financial condition.
Recapitalization Matters. As previously reported, in October 1993 Croyden
Associates, a holder of shares of the Company's $2.16 Preferred Stock, filed
a class action suit in Delaware Chancery Court on behalf of itself and all
other holders of the $2.16 Preferred Stock. The suit alleged that the
Company and its directors breached their fiduciary duties to the holders of
the $2.16 Preferred Stock in formulating the originally proposed terms of the
Recapitalization, which provided for the reclassification of each share of
$2.16 Preferred Stock into 3.5 shares of Common Stock or, at the holder's
option, 2.75 shares of Common Stock and .25 share of a new issue of preferred
stock. The suit sought, among other things, monetary damages and to enjoin
the Recapitalization. On April 13, 1994, the court entered an order that
approved a settlement agreement which provided for (i) the exchange of each
share of $2.16 Preferred Stock into 4.9 shares of Common Stock and (ii) the
issuance of up to 131,956 shares (subsequently increased to 132,416 shares to
eliminate fractional shares) of Common Stock and the payment of $500,000 by
the Company for plaintiff's attorneys' fees and expenses awarded by the
Delaware Chancery Court. By order dated April 20, 1994, the court awarded
plaintiff's counsel $500,000 and 73,913 shares of Common Stock out of the
131,956 shares of Common Stock applied for by such counsel for legal fees and
expenses, with the remaining shares to be issued to the former holders of
$2.16 Preferred Stock as of the close of business on February 9, 1994.
Subsequently, counsel retained by a party objecting to the settlement was
awarded legal fees and expenses totaling approximately $11,500 to be paid in
the form of 1,127 shares of Common Stock out of the 58,503 shares of Common
Stock to be issued to the former holders of the $2.16 Preferred Stock. The
shares awarded to counsel for the holders of $2.16 Preferred Stock were
issued in May 1994; the shares awarded to the former holders of $2.16
Preferred Stock and to counsel for the objecting party were issued in July
1994.
Refund Claim. On July 5, 1994, Simmons Oil Corporation, also known as David
Christopher Corporation, a former customer of the Company ("Customer"), filed
suit against the Company in the United States District Court for the District
of New Mexico for a refund in the amount of approximately $1.2 million, plus
interest of approximately $4.4 million and attorney's fees, related to a
gasoline purchase from the Company in 1979. The Customer also alleges
entitlement to treble damages and punitive damages in the aggregate amount of
$16.8 million. The refund claim is based on allegations that the Company
renegotiated the acquisition price of the 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. The Company believes the claim is without merit and anticipates that
the ultimate resolution of this matter will not have a material adverse
effect on the Company.
23
Item 4. Submission of Matters to a Vote of Security Holders
(a) The 1994 annual meeting of stockholders of the Company was held on
May 26, 1994.
(b) The names of the directors elected at the meeting and a tabulation of
the number of votes cast for, against or withheld with respect to
each such director are set forth below:
Votes Votes Votes
Name For Against Withheld
Ray C. Adam 20,623,523 0 1,569,961
Michael D. Burke 20,636,743 0 1,556,741
Robert J. Caverly 16,465,560 0 5,727,924
Peter M. Detwiler 9,511,204 0 12,682,280
Steven H. Grapstein 20,625,201 0 1,568,283
Charles F. Luce 20,619,788 0 1,573,696
Raymond K. Mason, Sr. 9,503,813 0 12,689,671
John J. McKetta, Jr. 18,088,461 0 4,105,023
Stewart G. Nagler 20,574,487 0 1,618,997
William S. Sneath 20,625,597 0 1,567,887
Arthur Spitzer 20,573,939 0 1,619,545
Murray L. Weidenbaum 19,454,515 0 2,738,969
Charles Wohlstetter 18,302,910 0 3,890,574
Pursuant to the terms of the Amended MetLife Memorandum, Ray C.
Adam, Charles F. Luce, Stewart G. Nagler and William S. Sneath
resigned as directors of the Company effective June 29, 1994.
(c) With respect to a proposal to appoint Deloitte & Touche as
independent auditors for the Company for 1994, there were 16,876,870
votes for; 30,747 votes against; 59,967 votes withheld; 5,225,900
broker non-votes; and no abstentions.
Item 6.Exhibits and Reports on Form 8-K
(a) Exhibits
See the Exhibit Index immediately preceding the exhibits filed
herewith.
(b) Reports on Form 8-K
No reports on Form 8-K have been filed during the quarter for which
this report is filed.
24
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
Registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
TESORO PETROLEUM CORPORATION
Registrant
Date: August 15, 1994 /s/ Michael D. Burke
-----------------------------
Michael D. Burke
President and
Chief Executive Officer
Date: August 15, 1994 /s/ Bruce A. Smith
--------------------------------
Bruce A. Smith
Executive Vice President and
Chief Financial Officer
25
EXHIBIT INDEX
Exhibit
Number
11 Information Supporting Earnings (Loss) Per Share Computations.
26
Exhibit 11
<TABLE>
TESORO PETROLEUM CORPORATION AND SUBSIDIARIES
INFORMATION SUPPORTING EARNINGS (LOSS)
PER SHARE COMPUTATIONS
(Unaudited)
(In thousands, except per share amounts)
<CAPTION>
Three Months Ended Six Months Ended
June 30, June 30,
1994 1993 1994 1993
<S> <C> <C> <C> <C>
PRIMARY EARNINGS (LOSS) PER SHARE
COMPUTATION:
Earnings (loss) before extraordinary item $ 1,230 1,488 8,432 ( 1,421)
Extraordinary loss on extinguishment of debt - - ( 4,752) -
-------- -------- -------- --------
Net earnings (loss) . . . . . . . . . . . 1,230 1,488 3,680 ( 1,421)
Less dividend requirements on preferred stocks 791 2,302 2,680 4,604
-------- -------- -------- --------
Net earnings (loss) applicable to common stock $ 439 ( 814) 1,000 ( 6,025)
======== ======== ======== ========
Average outstanding common shares . . . . 22,525 14,070 20,688 14,070
Average outstanding common equivalent shares 697 - 662 -
-------- -------- -------- --------
Average outstanding common and common
equivalent shares. . . . . . . . . . . 23,222 14,070 21,350 14,070
======== ======== ======== ========
Primary Earnings (Loss) Per Share:
Earnings (loss) before extraordinary item $ .02 ( .06) .27 ( .43)
Extraordinary loss on extinguishment of debt - - ( .22) -
-------- -------- -------- --------
Net earnings (loss) . . . . . . . . . . $ .02 ( .06) .05 ( .43)
======== ======== ======== ========
FULLY DILUTED EARNINGS (LOSS) PER SHARE
COMPUTATION:
Net earnings (loss) applicable to common stock $ 439 ( 814) 1,000 ( 6,025)
Add dividend requirements on preferred stock 791 2,302 2,680 4,604
-------- -------- -------- --------
Net earnings (loss) applicable to common
stock - fully diluted. . . . . . . . . $ 1,230 1,488 3,680 ( 1,421)
======== ======== ======== ========
Average outstanding common and common
equivalent shares . . . . . . . . . . . 23,222 14,070 21,350 14,070
Shares issuable on conversion of preferred shares 2,473 4,775 2,976 4,775
-------- -------- -------- --------
Fully diluted shares. . . . . . . . . . 25,695 18,845 24,326 18,845
======== ======== ======== ========
Fully Diluted Earnings (Loss) Per Share -
Anti-dilutive* . . . . . . . . . . . . . $ .02 ( .06) .05 ( .43)
======== ======== ======== ========
*This calculation is submitted in accordance with paragraph 601 (b)(11) of
Regulation S-K although it is not required by APB Opinion No. 15 because it
produces an anti-dilutive result.
27
</TABLE>
