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 March 31, 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 24,538,167 shares of the Registrant's Common Stock outstanding at
April 30, 1995.
TESORO PETROLEUM CORPORATION AND SUBSIDIARIES
INDEX TO FORM 10-Q
FOR THE QUARTERLY PERIOD ENDED MARCH 31, 1995
PART I. FINANCIAL INFORMATION Page
Item 1. Financial Statements (Unaudited)
Condensed Consolidated Balance Sheets - March 31, 1995 and
December 31, 1994 . . . . . . . . . . . . . . . . . . . . . . . 3
Condensed Statements of Consolidated Operations - Three Months Ended
March 31, 1995 and 1994. . . . . . . . . . . . . . . . . . . . . . 4
Condensed Statements of Consolidated Cash Flows - Three Months Ended
March 31, 1995 and 1994. . . . . . . . . . . . . . . . . . . . . . 5
Notes to Condensed Consolidated Financial Statements. . . . . . . . 6
Item 2. Management's Discussion and Analysis of Financial Condition
and Results of Operations . . . . . . . . . . . . . . . . . . . . . 10
PART II. OTHER INFORMATION
Item 1. Legal Proceedings . . . . . . . . . . . . . . . . . . . . . . 21
Item 6. Exhibits and Reports on Form 8-K. . . . . . . . . . . . . . . 23
SIGNATURES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24
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)
March 31, December 31,
1995 1994*
---- ----
ASSETS
CURRENT ASSETS:
Cash and cash equivalents . . . . . . . . . . . . . $ 5,550 14,018
Receivables, less allowance for doubtful accounts
of $1,876 ($1,816 at December 31, 1994) . . . . . 86,376 91,140
Inventories:
Crude oil and wholesale refined products, at LIFO 66,263 58,798
Merchandise and retail refined products . . . . . 5,689 5,934
Materials and supplies. . . . . . . . . . . . . . 3,774 3,570
Prepaid expenses and other. . . . . . . . . . . . . 8,256 8,648
--------- ---------
Total Current Assets. . . . . . . . . . . . . . . 175,908 182,108
PROPERTY, PLANT AND EQUIPMENT, Net of Accumulated
Depreciation, Depletion and Amortization of $217,699
($205,782 at December 31, 1994) . . . . . . . . . . 280,717 273,334
INVESTMENT IN TESORO BOLIVIA PETROLEUM COMPANY . . . 11,544 10,295
OTHER ASSETS . . . . . . . . . . . . . . . . . . . . 20,864 18,623
--------- ---------
TOTAL ASSETS . . . . . . . . . . . . . . . . $489,033 484,360
========= =========
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES:
Accounts payable. . . . . . . . . . . . . . . . . . $ 58,509 53,573
Accrued liabilities . . . . . . . . . . . . . . . . 27,477 35,266
Current portion of long-term debt and other
obligations. . . . . . . . . . . . . . . . . . . . 8,107 7,404
--------- ---------
Total Current Liabilities . . . . . . . . . . . . 94,093 96,243
--------- ---------
DEFERRED INCOME TAXES. . . . . . . . . . . . . . . . 4,494 4,582
--------- ---------
OTHER LIABILITIES. . . . . . . . . . . . . . . . . . 36,806 30,593
--------- ---------
LONG-TERM DEBT AND OTHER OBLIGATIONS, LESS
CURRENT PORTION . . . . . . . . . . . . . . . . . . 189,995 192,210
--------- ---------
COMMITMENTS AND CONTINGENCIES (Note 3)
STOCKHOLDERS' EQUITY:
Common Stock, par value $.16-2/3; authorized
50,000,000 shares; 24,538,167 shares issued
and outstanding (24,389,801 in 1994). . . . . . . 4,090 4,065
Additional paid-in capital. . . . . . . . . . . . . 176,642 175,514
Accumulated deficit . . . . . . . . . . . . . . . . ( 17,087) ( 18,847)
--------- ---------
Total Stockholders' Equity. . . . . . . . . . . . 163,645 160,732
--------- ---------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY . $ 489,033 484,360
========= =========
The accompanying notes are an integral part of these condensed consolidated
financial statements.
*The balance sheet at December 31, 1994 has been taken from the audited
consolidated financial statements at that date and condensed.
3
TESORO PETROLEUM CORPORATION AND SUBSIDIARIES
CONDENSED STATEMENTS OF CONSOLIDATED OPERATIONS
(Unaudited)
(In thousands except per share amounts)
Three Months Ended
March 31,
-----------------------
1995 1994
---- ----
REVENUES:
Gross operating revenues. . . . . . . . . . . . . . $234,701 189,087
Interest income . . . . . . . . . . . . . . . . . . 236 523
Gain on sales of assets . . . . . . . . . . . . . . 7 2,680
Other . . . . . . . . . . . . . . . . . . . . . . . 81 450
--------- ---------
Total Revenues. . . . . . . . . . . . . . . . . . 235,025 192,740
--------- ---------
COSTS AND EXPENSES:
Costs of sales and operating expenses . . . . . . . 210,611 167,605
General and administrative. . . . . . . . . . . . . 3,814 3,627
Depreciation, depletion and amortization. . . . . . 11,915 6,677
Interest expense. . . . . . . . . . . . . . . . . . 5,293 4,877
Other . . . . . . . . . . . . . . . . . . . . . . . 922 1,191
--------- ---------
Total Costs and Expenses. . . . . . . . . . . . . 232,555 183,977
--------- ---------
EARNINGS BEFORE INCOME TAXES AND EXTRAORDINARY
LOSS ON EXTINGUISHMENT OF DEBT. . . . . . . . . . . 2,470 8,763
Income Tax Provision . . . . . . . . . . . . . . . . 710 1,561
--------- ---------
EARNINGS BEFORE EXTRAORDINARY LOSS ON
EXTINGUISHMENT OF DEBT. . . . . . . . . . . . . . . 1,760 7,202
Extraordinary Loss on Extinguishment of Debt . . . . - ( 4,752)
--------- ---------
NET EARNINGS . . . . . . . . . . . . . . . . . . . . 1,760 2,450
Dividend Requirements on Preferred Stocks. . . . . . - 1,889
--------- ---------
NET EARNINGS APPLICABLE TO COMMON STOCK. . . . . . . $ 1,760 561
========= =========
EARNINGS (LOSS) PER PRIMARY AND
FULLY DILUTED* SHARE:
Earnings Before Extraordinary Loss on
Extinguishment of Debt. . . . . . . . . . . . . . . $ .07 .27
Extraordinary Loss on Extinguishment of Debt. . . . - ( .24)
--------- ---------
Net Earnings. . . . . . . . . . . . . . . . . . . . $ .07 .03
========= =========
AVERAGE OUTSTANDING COMMON AND COMMON
EQUIVALENT SHARES . . . . . . . . . . . . . . . . . 25,119 19,455
========= =========
*Anti-dilutive.
The accompanying notes are an integral part of these condensed consolidated
financial statements.
4
TESORO PETROLEUM CORPORATION AND SUBSIDIARIES
CONDENSED STATEMENTS OF CONSOLIDATED CASH FLOWS
(Unaudited)
(In thousands)
Three Months Ended
March 31,
----------------------
1995 1994
---- ----
CASH FLOWS FROM (USED IN) OPERATING ACTIVITIES:
Net earnings . . . . . . . . . . . . . . . . . . . $ 1,760 2,450
Adjustments to reconcile net earnings to net
cash from operating activities:
Depreciation, depletion and amortization. . . . . 11,915 6,677
Loss on extinguishment of debt. . . . . . . . . . - 4,752
Gain on sales of assets . . . . . . . . . . . . .( 7) ( 2,680)
Amortization of deferred charges and other, net . 447 361
Changes in assets and liabilities:
Receivables . . . . . . . . . . . . . . . . . . 4,764 11,151
Inventories . . . . . . . . . . . . . . . . . . ( 7,223) ( 1,217)
Investment in Tesoro Bolivia Petroleum Company . ( 1,249) ( 513)
Other assets . . . . . . . . . . . . . . . . . . 621 1,834
Accounts payable and other current liabilities . ( 1,417) 8,272
Obligation payments to State of Alaska . . . . . ( 629) ( 710)
Other liabilities and obligations . . . . . . . 1,601 ( 118)
--------- ---------
Net cash from operating activities . . . . . 10,583 30,259
--------- ---------
CASH FLOWS FROM (USED IN) INVESTING ACTIVITIES:
Capital expenditures . . . . . . . . . . . . . . . (16,527) (18,475)
Acquisition of Kenai Pipe Line Company and other. . ( 3,000) 351
Proceeds from sales of assets . . . . . . . . . . . 1,011 2,014
Sales of short-term investments . . . . . . . . . . - 5,952
--------- ---------
Net cash used in investing activities . . . . (18,516) (10,158)
--------- ---------
CASH FLOWS FROM (USED IN) FINANCING ACTIVITIES:
Repayments, net of borrowings of $52,000 in
1995 and $5,000 in 1994, under revolving
credit facilities . . . . . . . . . . . . . . . . - ( 5,000)
Payments of long-term debt. . . . . . . . . . . . . ( 545) ( 222)
Dividends on preferred stocks . . . . . . . . . . . - ( 103)
Costs of recapitalization and other. . .. . . . . . 10 ( 1,960)
--------- ---------
Net cash used in financing activities . . . . ( 535) ( 7,285)
--------- ---------
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS ( 8,468) 12,816
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD 14,018 36,596
--------- ---------
CASH AND CASH EQUIVALENTS AT END OF PERIOD . . . . . $ 5,550 49,412
========= =========
SUPPLEMENTAL CASH FLOW DISCLOSURES:
Interest paid . . . . . . . . . . . . . . . . . . . $ 5,359 7,105
========= =========
Income taxes paid . . . . . . . . . . . . . . . . . $ 805 961
========= =========
The accompanying notes are an integral part of these condensed consolidated
financial statements.
5
TESORO PETROLEUM CORPORATION AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
(1) Basis of Presentation
The interim condensed consolidated financial statements are unaudited but, in
the opinion of management, incorporate all adjustments necessary for a fair
presentation of results for such periods. Such adjustments are of a normal
recurring nature. The preparation of these condensed consolidated financial
statements required the use of management's best estimates and judgment. The
results of operations for any interim period are not necessarily indicative of
results for the full year. The accompanying condensed consolidated financial
statements should be read in conjunction with the consolidated financial
statements and notes thereto contained in the Company's Annual Report on Form
10-K for the year ended December 31, 1994.
(2) Acquisition
In March 1995, the Company acquired all of the outstanding stock of Kenai Pipe
Line Company ("KPL") for $3 million. The Company transports its crude oil and a
substantial portion of its refined products utilizing KPL's pipeline and marine
terminal facilities in Kenai, Alaska.
(3) 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
(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 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 March 1995,
the Contract Price was in excess of $8.00 per Mcf, the Section 101 price was
$4.88 per Mcf and the average spot market price was $1.34 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 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 Supreme Court of Texas heard arguments in December 1994
regarding the output contract issue and certain of the issues raised by
Tennessee Gas but has not yet issued its opinion.
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. If the Supreme Court of Texas
were to affirm 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
6
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 March 31, 1995, under
the Tennessee Gas Contract based on the Contract Price, which net revenues
aggregated $44.3 million more than the Section 101 prices and $84.4 million in
excess of the spot market prices. If Tennessee Gas were ultimately to prevail
in this litigation, the Company could be required to return to Tennessee Gas
$52.5 million, plus interest if awarded by the court, representing the
difference between the spot market price and the Contract Price received by the
Company through September 17, 1994 (the date on which the Company entered into a
bond agreement discussed below). An adverse judgment in this case could have a
material adverse effect on the Company.
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 ("the "Bond Price"), and (iii) post a $120 million
bond with the court representing an amount which, together with anticipated
sales of natural gas to Tennessee Gas at the Bond Price, will equal the
anticipated value of the Tennessee Gas Contract during this interim period. The
Bond Price is nonrefundable by the Company, and the Company retains the right to
receive the full Contract Price for all gas sold to Tennessee Gas. The Company
continues to recognize revenues under the Tennessee Gas Contract based on the
Contract Price. At March 31, 1995, the Company had recognized cumulative
revenues in excess of spot market prices (through September 17, 1994) and in
excess of the Bond Price (subsequent to September 17, 1994) totaling $77.2
million. Receivables at March 31, 1995 included $26.6 million from Tennessee
Gas, of which $24.7 million represented the difference between the Contract
Price and the Bond Price.
Environmental
The Company is subject to extensive federal, state and local environmental laws
and regulations. These laws, which change frequently, regulate the discharge of
materials into the environment and may require the Company to remove or mitigate
the environmental effects of the disposal or release of petroleum or chemical
substances at various sites or install additional controls or other
modifications or changes in use for certain emission sources. The Company is
currently involved with a waste disposal site in Louisiana and a drum recycling
site in Grand Junction, Colorado, at which sites it has been named a potentially
responsible party under the Federal Superfund law. Although this law might
impose joint and several liability upon each party at the sites, the extent of
the Company's allocated financial contributions to the cleanup of these 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 Louisiana site
is expected to be limited based upon the payment by the Company of a de minimis
settlement amount of $2,500 at a similar site in Louisiana. The Company
believes that its liability at the Colorado site will be less than $1,500 (see
Legal Proceedings in Part II, Item 1). 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 (the "EPA") alleging violations by the
Company of the New Source Performance Standards under the Clean Air Act at its
Alaska refinery. These allegations include failure to install, maintain and
operate monitoring equipment over a period of approximately six years, failure
to perform accuracy testing on monitoring equipment, and failure to install
certain pollution control
7
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 proposed
a penalty assessment of approximately $3.7 million. The Company is continuing
to negotiate with the DOJ but cannot predict the ultimate outcome of the
negotiations.
At March 31, 1995, the Company's accruals for environmental matters, including
the alleged violations of the Clean Air Act, amounted to $11.7 million. Also
included in this amount is a $4 million noncurrent liability for remediation of
the KPL properties, which liability has been funded by the former owners of KPL
through a restricted escrow deposit. Based on currently available information,
including the participation of other parties or former owners in remediation
actions, the Company believes these accruals are adequate. In addition, to
comply with environmental laws and regulations, the Company anticipates that it
will be required to make capital improvements in 1995 of approximately $2
million, primarily for the removal and upgrading of underground storage tanks,
and approximately $8 million during 1996 for the installation of dike liners
required under Alaska environmental regulations. Conditions that require
additional expenditures may exist for various Company sites, including, but not
limited to, the Company's refinery, retail gasoline outlets (current and closed
locations) and petroleum product terminals, and for compliance with the Clean
Air Act. The amount of such future expenditures cannot currently be determined
by the Company.
Crude Oil Purchase Contract
The Company's contract with the State of Alaska ("State") for the purchase of
royalty crude oil expires on December 31, 1995. In May 1995, the Company
renegotiated a new three-year contract with the State for the period January 1,
1996 through December 31, 1998. The new contract provides for the purchase of
approximately 40,000 barrels per day of Alaska North Slope ("ANS") royalty crude
oil, the primary feedstock for the Company's refinery, and is priced at the
weighted average price reported to the State by a major North Slope producer for
ANS crude oil as valued at Pump Station No. 1 on the Trans Alaska Pipeline
System. Under this agreement, the Company is required to utilize in its
refinery operations volumes equal to at least 80% of the ANS crude oil to be
purchased from the State. This contract contains provisions that allow the
Company to temporarily or permanently reduce its purchase obligations.
Other
In February 1995, a lawsuit was filed in the U.S. District Court for the
Southern District of Texas, McAllen Division, by the Heirs of H.P. Guerra,
Deceased ("Plaintiffs") against the United States and Tesoro and other working
and overriding royalty interest owners to recover the oil and gas mineral estate
under 2,706.34 acres situated in Starr County, Texas. The oil and gas mineral
estate sought to be recovered underlies lands taken by the United States in
connection with the construction of the Falcon Dam and Reservoir. In their
lawsuit, the Plaintiffs allege that the original taking by the United States in
1948 was unlawful and void and the refusal of the United States to revest the
mineral estate to H.P. Guerra or his heirs was arbitrary and capricious and
unconstitutional. Plaintiffs seek (i) restoration of their oil and gas estate;
(ii) restitution of all proceeds realized from the sale of oil and gas from
their mineral estate, plus interest on the value thereof; and (iii) cancellation
of all oil and gas leases issued by the United States to Tesoro and the other
working interest owners covering their mineral estate. The lawsuit covers a
significant portion of the mineral estate in the Bob West Field; however, none
of the acreage covered is dedicated to the Tennessee Gas Contract. The Company
cannot predict the ultimate resolution of this matter but, based upon advice
from outside legal counsel, believes the lawsuit is without merit.
8
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. The Company cannot predict
the ultimate resolution of this matter but believes the claim is without merit.
The Company has entered into a price swap with another company for approximately
8.25 Bcf of its anticipated U.S. natural gas production for the period April 1,
1995 through December 31, 1995 at a fixed price of approximately $1.56 per Mcf.
The Company's average spot market sales price was $1.42 per Mcf during the three
months ended March 31, 1995.
9
Item 2. TESORO PETROLEUM CORPORATION AND SUBSIDIARIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
RESULTS OF OPERATIONS - THREE MONTHS ENDED MARCH 31, 1995 COMPARED TO THREE
MONTHS ENDED MARCH 31, 1994
A consolidated summary of the Company's operations for the three months ended
March 31, 1995 and 1994 is presented below (in millions except per share
amounts):
Three Months Ended
March 31,
------------------
1995 1994
---- ----
Summary of Operations
Segment Operating Profit (Loss)*:
Refining and Marketing. . . . . . . . . . . . . . . . . . $( 4.6) 6.4
Exploration and Production - United States. . . . . . . . 16.6 11.2
Exploration and Production - Bolivia . . . . . . . . . . 1.7 1.9
Oil Field Supply and Distribution . . . . . . . . . . . . ( 1.3) ( 1.2)
--------- ---------
Total Segment Operating Profit. . . . . . . . . . . . . 12.4 18.3
Corporate and Unallocated Costs:
Interest expense. . . . . . . . . . . . . . . . . . . . . 5.3 4.9
Interest income . . . . . . . . . . . . . . . . . . . . . ( .2) ( .5)
General and administrative expenses . . . . . . . . . . . 3.8 3.6
Other . . . . . . . . . . . . . . . . . . . . . . . . . . 1.0 1.5
--------- ---------
Earnings Before Income Taxes and Extraordinary Loss. . . . 2.5 8.8
Income Tax Provision . . . . . . . . . . . . . . . . . . . .7 1.6
--------- ---------
Earnings Before Extraordinary Loss . . . . . . . . . . . . 1.8 7.2
Extraordinary Loss on Extinguishment of Debt . . . . . . . - ( 4.8)
--------- ---------
Net Earnings . . . . . . . . . . . . . . . . . . . . . . . 1.8 2.4
Dividend Requirements on Preferred Stocks. . . . . . . . . - 1.9
--------- ---------
Net Earnings Applicable to Common Stock. . . . . . . . . . $ 1.8 .5
========= =========
Earnings (Loss) per Primary and Fully Diluted** Share:
Earnings Before Extraordinary Loss. . . . . . . . . . . . $ .07 .27
Extraordinary Loss on Extinguishment of Debt. . . . . . . - ( .24)
--------- ---------
Net Earnings. . . . . . . . . . . . . . . . . . . . . . . $ .07 .03
========= =========
* Operating profit (loss) represents pretax earnings (loss) before certain
corporate expenses, interest income and interest expense.
** Anti-dilutive.
Net earnings applicable to common stock of $1.8 million, or $.07 per share, for
the three months ended March 31, 1995 ("1995 quarter") compare with net earnings
applicable to common stock of $.5 million, or $.03 per share, for the three
months ended March 31, 1994 ("1994 quarter"). Net earnings for the 1994 quarter
were reduced by $1.9 million of dividend requirements on preferred stock. Also
included in the 1994 quarter was a noncash extraordinary loss of $4.8 million,
or $.24 per share, attributable to the early extinguishment of debt in
connection with a recapitalization in early 1994. Earnings before the
extraordinary loss were $7.2 million, or $.27 per share, for the 1994 quarter.
The 1994 quarter was favorably impacted by a gain of $2.8 million, or $.14 per
share, from the sale of assets. When comparing the 1995 quarter to the 1994
quarter, the decrease in net earnings was primarily due to the impact of weak
market conditions on the Company's refining and marketing segment and low spot
market prices for sales of natural gas, partially offset by increased natural
gas production from the Company's exploration and production operations in South
Texas.
10
Refining and Marketing Three Months Ended
March 31,
---------------------
1995 1994
---- ----
(Dollars in millions
except per barrel
amounts)
Gross Operating Revenues:
Refined products. . . . . . . . . . . . . . . . . $ 153.6 119.3
Other, primarily crude oil resales and merchandise 31.5 31.0
--------- ---------
Gross Operating Revenues. . . . . . . . . . . . $ 185.1 150.3
========= =========
Operating Profit (Loss):
Gross margin - refined products . . . . . . . . . $ 15.1 23.5
Gross margin - other . . . . . . . . . . . . . . 2.5 2.6
--------- ---------
Gross margin. . . . . . . . . . . . . . . . . . 17.6 26.1
Operating expenses. . . . . . . . . . . . . . . . 19.2 19.9
Depreciation and amortization . . . . . . . . . . 3.0 2.6
Other, including gain on asset sales . . . . . . - ( 2.8)
--------- ---------
Operating Profit (Loss) . . . . . . . . . . . . $( 4.6) 6.4
========= =========
Capital Expenditures . . . . . . . . . . . . . . . $ 2.3 6.1
========= =========
Refining and Marketing Total Product Sales
(average daily barrels)*:
Gasoline. . . . . . . . . . . . . . . . . . . . . 23,328 22,570
Middle distillates. . . . . . . . . . . . . . . . 38,219 26,802
Heavy oils and residual product . . . . . . . . . 13,817 16,446
--------- ---------
Total Product Sales . . . . . . . . . . . . . . 75,364 65,818
========= =========
Refining and Marketing Product Sales Prices
($/barrel):
Gasoline. . . . . . . . . . . . . . . . . . . . . $ 26.84 24.36
Middle distillates. . . . . . . . . . . . . . . . $ 23.68 23.92
Heavy oils and residual product . . . . . . . . . $ 12.65 8.22
Refining and Marketing - Gross Margins on
Total Product Sales*:
Average sales price . . . . . . . . . . . . . . . $ 22.63 20.15
Average cost of sales . . . . . . . . . . . . . . 20.41 16.18
--------- ---------
Gross margin. . . . . . . . . . . . . . . . . . . $ 2.22 3.97
========= =========
Refinery Operations - Throughput (average daily
barrels) . . . . . . . . . . . . . . . . . . . . 45,572 45,320
========= =========
Refinery Operations - Production (average
daily barrels):
Gasoline . . . . . . . . . . . . . . . . . . . . 12,770 11,977
Middle distillates. . . . . . . . . . . . . . . . 19,687 17,851
Heavy oils and residual product . . . . . . . . . 12,424 15,407
Refinery fuel . . . . . . . . . . . . . . . . . . 2,027 1,737
--------- ---------
Total Refinery Production . . . . . . . . . . . 46,908 46,972
========= =========
Refinery Operations - Product Spread ($/barrel)*:
Average yield value of products produced. . . . . $ 19.70 17.35
Cost of raw materials . . . . . . . . . . . . . . 16.75 12.31
--------- ---------
Spread. . . . . . . . . . . . . . . . . . . . . $ 2.95 5.04
========= =========
11
* Total products sold include products manufactured at the refinery, existing
inventory balances and products purchased from third parties. Margins on
sales of purchased products, together with the effect of changes in
inventories, are included in the gross margin on total product sales
presented above. During the 1995 and 1994 quarters, the Company purchased
for resale approximately 26,500 and 19,500 average daily barrels of refined
products, respectively. Margins on refinery operations only are reflected as
the product spread presented above.
Refining and Marketing
The unusually weak industry conditions adversely affected the results from the
Company's refining and marketing segment. Increased demand for Alaska North
Slope ("ANS") crude oil for use as a feedstock in West Coast refineries combined
with an oversupply of products in Alaska and the West Coast resulted in higher
feedstock costs for the Company relative to increases in its refined product
sales prices. The Company's average feedstock costs increased to $16.75 per
barrel for the 1995 quarter compared with $12.31 per barrel for the 1994
quarter, while the average yield value of the Company's refinery production
increased to $19.70 per barrel for the 1995 quarter from $17.35 for the prior
year quarter. As a result, the Company's refined product margins were severely
depressed in the 1995 quarter 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. Although the industry conditions resulted
in depressed margins for the Company, 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 lessened the impact of these industry conditions on
the Company's refinery margins.
Revenues from sales of refined products in the 1995 quarter were higher than the
1994 quarter due to higher sales prices and a 15% increase in sales volumes.
Costs of sales, likewise, were higher in the 1995 quarter due to increased
prices and volumes. Depreciation and amortization increased $.4 million in the
1995 quarter due to capital additions, primarily the vacuum unit, completed in
late 1994. Included in the 1994 quarter was a $2.8 million gain from the sale
of the Company's Valdez, Alaska terminal.
12
Exploration and Production Three Months Ended
March 31,
----------------------
1995 1994
---- ----
(Dollars in millions
except per unit amounts)
United States:
Gross operating revenues* . . . . . . . . . . . . $ 29.8 17.4
Lifting costs . . . . . . . . . . . . . . . . . . 4.8 2.3
Depreciation, depletion and amortization . . . . 8.6 3.8
Other . . . . . . . . . . . . . . . . . . . . . . ( .2) .1
--------- ---------
Operating Profit - United States . . . . . . . 16.6 11.2
--------- ---------
Bolivia:
Gross operating revenues . . . . . . . . . . . . 2.6 2.8
Lifting costs . . . . . . . . . . . . . . . . . . .2 .2
Other . . . . . . . . . . . . . . . . . . . . . . .7 .7
--------- ---------
Operating Profit - Bolivia . . . . . . . . . . 1.7 1.9
--------- ---------
Total Operating Profit - Exploration and
Production . . . . . . . . . . . . . . . . . . . $ 18.3 13.1
========= =========
United States:
Capital expenditures. . . . . . . . . . . . . . . $ 14.0 11.7
========= =========
Net natural gas production (average daily Mcf) -
Spot market and other . . . . . . . . . . . . . 80,275 32,817
Tennessee Gas Contract* . . . . . . . . . . . . 25,603 16,181
--------- ---------
Total production . . . . . . . . . . . . . . . 105,878 48,998
========= =========
Average natural gas sales price per Mcf -
Spot market . . . . . . . . . . . . . . . . . . $ 1.42 2.01
Tennessee Gas Contract* . . . . . . . . . . . . $ 8.32 7.80
Average . . . . . . . . . . . . . . . . . . . . $ 3.09 3.92
Average lifting costs per Mcf** . . . . . . . . . $ .51 .53
Depletion per Mcf . . . . . . . . . . . . . . . . $ .90 .85
Bolivia:
Net natural gas production (average daily Mcf). . 16,912 19,137
Average natural gas sales price per Mcf . . . . . $ 1.25 1.23
Net crude oil (condensate) production (average
daily barrels) . . . . . . . . . . . . . . . . 552 662
Average crude oil price per barrel . . . . . . . $ 14.70 11.48
Average lifting costs per net equivalent Mcf. . . $ .09 .11
* 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 3 of
Notes to Condensed Consolidated Financial Statements.
** Average lifting costs for the Company's U.S. operations include such items
as severance taxes, property taxes, insurance, materials and supplies and
transportation of natural gas production through Company-owned pipelines.
Since severance taxes are based upon sales prices of natural gas, the average
lifting costs presented above include the impact of above-market prices for
sales under the Tennessee Gas Contract. Lifting costs per Mcf of natural gas
sold in the spot market were approximately $.41 and $.44 for the 1995 and
1994 quarters, respectively.
13
Exploration and Production
United States. Successful development drilling in the Bob West Field in South
Texas was the primary contributing factor to this segment's improvement when
comparing the 1995 quarter with the 1994 quarter. The number of producing wells
in South Texas in which the Company has a working interest increased to 54 wells
at the end of the 1995 quarter, compared with 33 wells at the end of the 1994
quarter. The Company's 1995 quarter results included a 116% increase in U.S.
natural gas production with a $12.4 million increase in revenues. Revenues for
natural gas sales during the 1995 quarter, however, were adversely affected by a
21% decline in the Company's weighted average sales price, which included a 29%
drop in spot market prices. In response to the depressed spot market prices,
during the 1995 quarter 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 have
resumed at higher rates, approximating 137 Mmcf per day. 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 quarter, compared with the 1994 quarter, due to the
increased production level, but were relatively unchanged on a per Mcf basis.
Tennessee Gas may elect, and from time to time has elected, not to take gas
under the Tennessee Gas Contract. The Company recognizes revenues under the
Tennessee Gas Contract based on the quantity of natural gas actually taken by
Tennessee Gas. While Tennessee Gas has the right to elect not to take gas
during any contract year, this right is subject to an obligation to pay within
60 days after the end of such contract year for gas not taken. The contract
year ends on January 31 of each year. Although the failure to take gas could
adversely affect the Company's income and cash flows from operating activities
within a contract year, the Company should recover reduced cash flows shortly
after the end of the contract year under the take-or-pay provisions of the
Tennessee Gas Contract, subject to the provisions of a bond posted by Tennessee
Gas which is discussed in "Capital Resources and Liquidity-- Tennessee Gas
Contract," "Legal Proceedings--Tennessee Gas Contract" and Note 3 of Notes to
Condensed Consolidated Financial Statements.
The Company has entered into a price swap with another company for approximately
8.25 Bcf of its anticipated U.S. natural gas production for the period April 1,
1995 through December 31, 1995 at a fixed price of approximately $1.56 per Mcf.
The Company's average spot market sales price was $1.42 per Mcf during the three
months ended March 31, 1995.
Bolivia. Results from the Company's Bolivian operations decreased by $.2
million during the 1995 quarter primarily due to a 12% decline in average daily
natural gas production. During the 1994 quarter, the Company benefited from
higher levels of production due to the inability of another producer to satisfy
gas supply requirements. Partially offsetting the production decline was a
$3.22 per barrel increase in the average price of condensate production. The
Company's Bolivian natural gas production is sold to Yacimientos Petroliferos
Fiscales Bolivianos ("YPFB"), which in turn sells the natural gas to 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, but with a small decrease in price. The Company's contract for the
sale of natural gas to YPFB expired in 1994. Although the Company's contract
with YPFB is subject to renegotiation, the Company is currently selling its
natural gas production to YPFB based on the pricing terms in the contract
between YPFB and YPF.
14
Oil Field Supply and Distribution Three Months Ended
March 31,
----------------------
1995 1994
---- ----
(Dollars in millions)
Gross Operating Revenues . . . . . . . . . . . . . . . $ 17.2 18.6
Costs of Sales . . . . . . . . . . . . . . . . . . . . 15.1 15.9
------- -------
Gross Margin. . . . . . . . . . . . . . . . . . . . . 2.1 2.7
Operating Expenses and Other . . . . . . . . . . . . . 3.3 3.8
Depreciation and Amortization. . . . . . . . . . . . . .1 .1
------- -------
Operating Loss. . . . . . . . . . . . . . . . . . . . $( 1.3) ( 1.2)
======= =======
Refined Product Sales (average daily barrels). . . . . 6,930 7,424
======= =======
Refined product sales prices and gross margins during the 1995 quarter continued
to be impacted by strong competition in an oversupplied market. Included in
operating expenses in the 1994 quarter were charges of $.9 million for
discontinuing the Company's environmental products marketing operations.
Interest Expense
Interest expense of $5.3 million in the 1995 quarter compares with $4.9 million
in the 1994 quarter. The increase was primarily due to interest on the vacuum
unit financing and cash borrowings under the Revolving Credit Facility.
Income Taxes
Income taxes of $.7 million in the 1995 quarter compare with $1.6 million in the
1994 quarter. The decrease was primarily due to lower federal and state income
taxes on the Company's decreased taxable earnings.
IMPACT OF CHANGING PRICES
The Company's operating results and cash flows are sensitive to the volatile
changes in energy prices. Major shifts in the cost of crude oil and the price
of refined products can result in a change in gross margin from the refining and
marketing operations, as prices received for refined products may or may not
keep pace with changes in crude oil costs. These energy prices, together with
volume levels, also determine the carrying value of crude oil and refined
product inventory.
Likewise, major changes in natural gas prices impact revenues and the present
value of estimated future net revenues and cash flows from the Company's
exploration and production operations. The carrying value of oil and gas assets
may also be subject to noncash write-downs based on changes in natural gas
prices and other determining factors.
15
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 the Company's
natural gas or refined products and the resulting future impact on earnings and
cash flows. Due to the effect of depressed market conditions, the Company's
operations will continue to be adversely affected for so long as these market
conditions exist. The Company's future capital expenditures, borrowings under
its credit arrangements and other sources of capital will be affected by these
conditions.
The Company continues to assess its existing asset base in order to maximize
returns and financial flexibility through diversification, acquisitions and
divestitures in all of its operating segments. This ongoing assessment
includes, in the Exploration and Production segment, evaluating ways in which
the Company might diversify the mix of its oil and gas assets while at the same
time reduce the asset concentration associated with the Bob West Field. In
these regards, the Company is currently evaluating the potential benefits of
selling or exchanging approximately 30% of its proved reserves in the Bob West
Field. The reserves being evaluated do not include acreage covered by the
Tennessee Gas Contract. At the completion of the evaluation phase, the Company
will decide whether to continue to pursue a sale or exchange, but a final
decision could take several months. The Company is uncertain as to the impact
of these initiatives upon its capital resources and liquidity, if any.
Credit Arrangements
The Company has financing and credit arrangements under a three-year, $125
million corporate Revolving Credit Facility dated April 20, 1994 with a
consortium of ten banks. The Revolving Credit Facility, which is subject to a
borrowing base, provides for (i) the issuance of letters of credit up to the
full amount of the borrowing base and (ii) cash borrowings up to the amount of
the borrowing base attributable to domestic oil and gas reserves. Outstanding
obligations under the Revolving Credit Facility are secured by liens on
substantially all of the Company's trade accounts receivable and product
inventory and by mortgages on the Company's refinery and South Texas natural gas
reserves. At March 31, 1995, the borrowing base of approximately $116 million
included a domestic oil and gas reserve component of $45 million. At March 31,
1995, the Company had outstanding letters of credit under the Revolving Credit
Facility of approximately $47 million with no cash borrowings outstanding.
Although at March 31, 1995, there were no cash borrowings outstanding under the
Revolving Credit Facility, the Company from time to time borrowed under this
facility during the 1995 quarter on a short-term basis to finance working
capital requirements and capital expenditures.
Under the terms of the Revolving Credit Facility, as amended, the Company is
required to maintain specified levels of working capital, tangible net worth,
consolidated cash flow and refinery cash flow, as defined. Among other matters,
the Revolving Credit Facility contains certain restrictions with respect to (i)
capital expenditures, (ii) incurrence of additional indebtedness, and (iii)
dividends on capital stock. The Revolving Credit Facility contains other
covenants customary in credit arrangements of this kind. At March 31, 1995, the
Company was in compliance with all of the covenants under the Revolving Credit
Facility. Future compliance with certain financial covenants under the
Revolving Credit Facility is primarily dependent on the Company's cash flows
from operations, capital expenditures, levels of borrowings and the value of the
Company's domestic oil and gas reserves. Based upon current depressed refinery
margins, the Company anticipates that it will be required to seek a waiver or
amendment from
16
its banks with respect to its refinery cash flow requirement, possibly as early
as June 30, 1995. If such an event occurs, the Company believes it will be able
to negotiate terms and conditions with its banks under the Revolving Credit
Facility which will allow the Company to adequately finance its operations.
Debt Obligations
The Company's funded debt obligations as of March 31, 1995 included
approximately $64.6 million principal amount of 12-3/4% Subordinated Debentures
("Subordinated Debentures"), which bear interest at 12-3/4% per annum and
require sinking fund payments sufficient to annually retire $11.25 million
principal amount of Subordinated Debentures. As part of a recapitalization in
1994, $44.1 million principal amount of Subordinated Debentures was tendered in
exchange for a like principal amount of new 13% Exchange Notes ("Exchange
Notes"). This exchange satisfied the 1994 sinking fund requirement and, except
for $.9 million, will satisfy sinking fund requirements for the Subordinated
Debentures through 1997. The indenture governing the Subordinated Debentures
contains certain covenants, including a restriction that prevents the current
payment of cash dividends on Common Stock and currently limits the Company's
ability to purchase or redeem any shares of its capital stock. The Exchange
Notes bear interest at 13% per annum, mature December 1, 2000 and have no
sinking fund requirements. The limitation on dividend payments included in the
indenture governing the Exchange Notes is less restrictive than the limitation
imposed by the Subordinated Debentures. The Subordinated Debentures and
Exchange Notes are redeemable at the option of the Company at 100% of principal
amount, plus accrued interest. The Company continuously reviews financing
alternatives with respect to its Subordinated Debentures and Exchange Notes.
Reductions in long-term interest rates and increases in market capacity, along
with any further improvements in the Company's credit rating, may increase the
likelihood of refinancing all or a portion of the Company's public debt. A
resolution of the Tennessee Gas litigation could materially affect the Company's
credit rating. There can be no assurance whether or when the Company would
propose a refinancing, if any.
Capital Expenditures
Capital spending for 1995 is expected to be financed through a combination of
cash flows from operations and borrowings under the Revolving Credit Facility.
For the year 1995, the Company has under consideration total capital
expenditures of approximately $60 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 $47 million. The amount of
such expenditures for exploration and production activities is dependent upon,
among other factors, the price the Company receives for its natural gas
production. Capital expenditures for 1995 for the refining and marketing
segment are projected to be $11 million, primarily for capital improvements at
the refinery and expansion of the Company's retail locations in Alaska.
Cash Flows
At March 31, 1995, the Company's net working capital totaled $81.8 million,
which included $5.6 million of cash. Components of the Company's cash flows are
set forth below (in millions):
Three Months Ended
March 31,
---------------------
1995 1994
---- ----
Cash Flows From (Used In):
Operating Activities. . . . . . . . . . . . . . . . $ 10.6 30.3
Investing Activities. . . . . . . . . . . . . . . . ( 18.5) ( 10.2)
Financing Activities. . . . . . . . . . . . . . . . ( .6) ( 7.3)
-------- --------
Increase (Decrease) in Cash and Cash Equivalents . . $ ( 8.5) 12.8
======== ========
17
Net cash from operating activities of $10.6 million during the 1995 quarter
compares to $30.3 million for the 1994 quarter. Although natural gas production
from the Bob West Field increased during the 1995 quarter, lower prices received
for sales of natural gas and reduced cash flows from the refining and marketing
operations adversely affected the Company's cash flows from operations. 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 3 of Notes to Condensed Consolidated Financial
Statements. Net cash used in investing activities of $18.5 million included
$16.5 million of capital expenditures and $3.0 million for acquisition of the
Kenai Pipe Line Company. Capital expenditures for the 1995 quarter included
$14.0 million for the Company's exploration and production activities in South
Texas, primarily for completion of five natural gas development wells. Net cash
used in financing activities of $.5 million during the 1995 quarter was
primarily related to payments of long-term debt. The Company's gross borrowings
and repayments under its Revolving Credit Facility totaled $52.0 million during
the 1995 quarter.
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) ("Contract
Price") of the Natural Gas Policy Act of 1978 ("NGPA"). 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 March 1995,
the Contract Price was in excess of $8.00 per Mcf, the Section 101 price was
$4.88 per Mcf and the average spot market price was $1.34 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 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 Supreme Court of Texas heard arguments in December 1994
regarding the output contract issue and certain of the issues raised by
Tennessee Gas but has not yet issued its opinion.
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. If the Supreme Court of Texas
were to affirm 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
18
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 March 31, 1995, under the Tennessee Gas Contract based on the Contract
Price, which net revenues aggregated $44.3 million more than the Section 101
prices and $84.4 million in excess of the spot market prices. If Tennessee Gas
were ultimately to prevail in this litigation, the Company could be required to
return to Tennessee Gas $52.5 million, plus interest if awarded by the court,
representing the difference between the spot market price and the Contract Price
received by the Company through September 17, 1994 (the date on which the
Company entered into a bond agreement discussed below). In addition, the
Company's calculation of the standardized measure of discounted future net cash
flows relating to proved reserves in the United States at December 31, 1994 of
$127 million was determined in part using the Contract Price as compared with
$73 million at spot market prices. An adverse judgment in this case could have
a material adverse effect on the Company.
In September 1994, the court ordered that, effective until August 1, 1995,
Tennessee Gas (i) take at least its entire monthly take-or-pay obligation under
the Tennessee Gas Contract, (ii) pay for gas at $3.00 per Mmbtu, which
approximates $3.00 per Mcf ("Bond Price"), and (iii) post a $120 million bond
with the court representing an amount which, together with anticipated sales of
natural gas to Tennessee Gas at the Bond Price, will equal the anticipated value
of the Tennessee Gas Contract during this interim period. The Bond Price is
nonrefundable by the Company, and the Company retains the right to receive the
full Contract Price for all gas sold to Tennessee Gas. The Company continues to
recognize revenues under the Tennessee Gas Contract based on the Contract Price.
At March 31, 1995, the Company had recognized cumulative revenues in excess of
spot market prices (through September 17, 1994) and in excess of the Bond Price
(subsequent to September 17, 1994) totaling $77.2 million. Receivables at March
31, 1995, included $26.6 million from Tennessee Gas, of which $24.7 million
represented the difference between the Contract Price and the Bond Price. For
further information regarding the Tennessee Gas Contract, see "Legal Proceedings
- -- Tennessee Gas Contract" and Note 3 of Notes to Condensed Consolidated
Financial Statements.
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 March 31, 1995 the
Company's accruals for environmental matters, including the alleged violations
of the Clean Air Act, amounted to $11.7 million. Also included in this amount
is a $4 million noncurrent liability for remediation of the KPL properties,
which liability has been funded by the former owners of KPL through a restricted
escrow deposit. Based on currently available information, including the
participation of other parties or former owners in remediation actions, the
Company believes these accruals are adequate. In addition, to comply with
environmental laws and regulations, the Company anticipates that it will be
required to make capital improvements in 1995 of approximately $2 million,
primarily for the removal and upgrading of underground storage tanks, and
approximately $8 million during 1996 for the installation of dike liners
required under Alaska environmental regulations. Conditions that require
additional expenditures may exist for various Company sites, including, but not
limited to, the Company's refinery, retail gasoline outlets (current and closed
locations) and petroleum product terminals, and for compliance with the Clean
Air Act. The amount of such future expenditures
19
cannot currently be determined by the Company. For further information on
environmental contingencies, see Note 3 of Notes to Condensed Consolidated
Financial Statements.
The Company's contract with the State of Alaska ("State") for the purchase of
royalty crude oil expires on December 31, 1995. In May 1995, the Company
renegotiated a new three-year contract with the State for the period January 1,
1996 through December 31, 1998. The new contract provides for the purchase of
approximately 40,000 barrels per day of ANS royalty crude oil, the primary
feedstock for the Company's refinery, and is priced at the weighted average
price reported to the State by a major North Slope producer for ANS crude oil as
valued at Pump Station No. 1 on the Trans Alaska Pipeline System. Under this
agreement, the Company is required to utilize in its refinery operations volumes
equal to at least 80% of the ANS crude oil to be purchased from the State. This
contract contains provisions that allow the Company to temporarily or
permanently reduce its purchase obligations.
As discussed in Note 3 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.
20
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 (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) ("Contract Price") of the Natural Gas Policy Act of 1978
("NGPA"). 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 March 1995, the Contract Price was in excess of $8.00
per Mcf, the Section 101 price was $4.88 per Mcf and the average spot market
price was $1.34 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 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 Supreme Court of Texas heard arguments in December 1994
regarding the output contract issue and certain of the issues raised by
Tennessee Gas but has not yet issued its opinion.
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. If the Supreme Court of Texas
were to affirm 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 March 31, 1995, under the Tennessee Gas Contract based on the Contract
Price, which net revenues aggregated $44.3 million more than the Section 101
prices and $84.4 million in excess of the spot market prices. If Tennessee Gas
were ultimately to prevail in this litigation, the Company could be required to
return to Tennessee Gas $52.5 million, plus interest if awarded by the court,
representing the difference between the spot market price and the Contract Price
received by the Company through September 17, 1994 (the date on which the
Company entered into a bond agreement discussed below). In addition, the
Company's calculation of the standardized measure of discounted future net cash
flows relating to proved reserves in the United States at December 31, 1994 of
$127 million was determined in part using the Contract Price as compared with
$73 million at spot market prices. An adverse judgment in this case could have
a material adverse effect on the Company.
21
In September 1994, the court ordered that, effective until August 1, 1995,
Tennessee Gas (i) take at least its entire monthly take-or-pay obligation under
the Tennessee Gas Contract, (ii) pay for gas at $3.00 per Mmbtu, which
approximates $3.00 per Mcf ("Bond Price"), and (iii) post a $120 million bond
with the court representing an amount which, together with anticipated sales of
natural gas to Tennessee Gas at the Bond Price, will equal the anticipated value
of the Tennessee Gas Contract during this interim period. The Bond Price is
nonrefundable by the Company, and the Company retains the right to receive the
full Contract Price for all gas sold to Tennessee Gas. The Company continues to
recognize revenues under the Tennessee Gas Contract based on the Contract Price.
At March 31, 1995, the Company had recognized cumulative revenues in excess of
spot market prices (through September 17, 1994) and in excess of the Bond Price
(subsequent to September 17, 1994) totaling $77.2 million. Receivables at March
31, 1995, included $26.6 million from Tennessee Gas, of which $24.7 million
represented the difference between the Contract Price and the Bond Price. For
further information regarding the Tennessee Gas Contract, see Note 3 of Notes to
Condensed Consolidated Financial Statements.
Environmental Matters. The Company has been identified by the Environmental
Protection Agency ("EPA") as a potentially responsible party ("PRP") pursuant to
the Comprehensive Environmental Response, Compensation, and Liability Act of
1980 ("CERCLA") for the Hansen Container Site, Grand Junction, Mesa County,
Colorado ("Site"). The Site was a drum recycling site which accepted and
recycled used containers from the mid-1960's through 1989. Over 220 parties
have been identified as PRP's at the Site. The Company sold a minimum number of
containers to the Site in the mid-1970's. CERCLA imposes joint and several
liability on PRP's; each PRP is therefore responsible for 100% of the costs of
the response actions necessary to remediate the Site in the event a settlement
with the EPA cannot be reached. The EPA has spent approximately $2.35 million
at the Site through September 1994 and is seeking reimbursement from over 220
PRP's. The EPA has offered an Administrative Order on Consent for De Minimis
Settlement to those PRP's who each contributed less than 2% of the total
contamination at the Site. The Company is eligible for a de minimis settlement
at the Site, and believes that its total liability for settlement will be less
than $1,500.
22
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.
23
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: May 15, 1995 /s/ Michael D. Burke
Michael D. Burke
President and
Chief Executive Officer
Date: May 15, 1995 /s/ Bruce A. Smith
Bruce A. Smith
Executive Vice President and
Chief Financial Officer
24
EXHIBIT INDEX
Exhibit
Number
- -------
11 Information Supporting Earnings (Loss) Per Share Computations.
27 Financial Data Schedule.
25
Exhibit 11
TESORO PETROLEUM CORPORATION AND SUBSIDIARIES
INFORMATION SUPPORTING EARNINGS (LOSS)
PER SHARE COMPUTATIONS
(Unaudited)
(In thousands, except per share amounts)
Three Months Ended
March 31,
-------------------
1995 1994
---- ----
PRIMARY EARNINGS (LOSS) PER SHARE COMPUTATION:
Earnings before extraordinary item. . . . . . . . . . . $ 1,760 7,202
Extraordinary loss on extinguishment of debt. . . . . . - ( 4,752)
-------- --------
Net earnings . . . . . . . . . . . . . . . . . . . . . 1,760 2,450
Less dividend requirements on preferred stocks. . . . . - 1,889
-------- --------
Net earnings applicable to common stock . . . . . . . $ 1,760 561
======== ========
Average outstanding common shares . . . . . . . . . . . 24,512 18,830
Average outstanding common equivalent shares. . . . . . 607 625
-------- --------
Average outstanding common and common equivalent
shares. . . . . . . . . . . . . . . . . . . . . . . 25,119 19,455
======== ========
Primary Earnings (Loss) Per Share:
Earnings before extraordinary item. . . . . . . . . . $ .07 .27
Extraordinary loss on extinguishment of debt. . . . . - ( .24)
-------- --------
Net earnings . . . . . . . . . . . . . . . . . . . . $ .07 .03
======== ========
FULLY DILUTED EARNINGS (LOSS) PER SHARE COMPUTATION:
Net earnings applicable to common stock . . . . . . . . $ 1,760 561
Add dividend requirements on preferred stocks . . . . . - 1,889
-------- --------
Net earnings (loss) applicable to common stock -
fully diluted . . . . . . . . . . . . . . . . . . . $ 1,760 2,450
======== ========
Average outstanding common and common equivalent shares 25,119 19,455
Shares issuable on conversion of preferred shares . . . - 3,486
Other . . . . . . . . . . . . . . . . . . . . . . . . . - 77
-------- --------
Fully diluted shares. . . . . . . . . . . . . . . . . 25,119 23,018
======== ========
Fully Diluted Earnings Per Share - Anti-dilutive* . . . $ .07 .03
======== ========
* 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.
26
<TABLE> <S> <C>
<ARTICLE> 5
<LEGEND>
THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM
TESORO PETROLEUM CORPORATION'S FINANCIAL STATEMENTS AS OF AND FOR THE
THREE MONTH PERIOD ENDED MARCH 31, 1995, AND IS QUALIFIED IN ITS ENTIRETY BY
REFERENCE TO SUCH FINANCIAL STATEMENTS.
</LEGEND>
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 3-MOS
<FISCAL-YEAR-END> DEC-31-1995
<PERIOD-END> MAR-31-1995
<CASH> 5,550
<SECURITIES> 0
<RECEIVABLES> 88,252
<ALLOWANCES> 1,876
<INVENTORY> 75,726
<CURRENT-ASSETS> 175,908
<PP&E> 498,416
<DEPRECIATION> 217,699
<TOTAL-ASSETS> 489,033
<CURRENT-LIABILITIES> 94,093
<BONDS> 189,995
0
0
<COMMON> 4,090
<OTHER-SE> 159,555
<TOTAL-LIABILITY-AND-EQUITY> 489,033
<SALES> 234,701
<TOTAL-REVENUES> 234,789
<CGS> 210,611
<TOTAL-COSTS> 210,611
<OTHER-EXPENSES> 11,915
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 5,293
<INCOME-PRETAX> 2,470
<INCOME-TAX> 710
<INCOME-CONTINUING> 1,760
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 1,760
<EPS-PRIMARY> .07
<EPS-DILUTED> .07
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