UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-Q/A
AMENDMENT NO. 1
This Form 10-Q/A is being filed to revise Item 2, Management's Discussion
and Analysis of Financial Condition and Results of Operations.
(Mark One)
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 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 24,389,801 shares of the Registrant's Common Stock outstanding at
October 31, 1994.
Item 2. TESORO PETROLEUM CORPORATION AND SUBSIDIARIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
RESULTS OF OPERATIONS - THREE AND NINE MONTHS ENDED SEPTEMBER 30, 1994 COMPARED
TO THREE AND NINE MONTHS ENDED SEPTEMBER 30, 1993
A summary of the Company's consolidated results of operations for the three and
nine months ended September 30, 1994 and 1993 is presented below:
<TABLE>
<CAPTION>
Consolidated Results of Operations Data Three Months Ended Nine Months Ended
September 30, September 30,
1994 1993 1994 1993
(Dollars in millions, except per share amounts)
<S> <C> <C> <C> <C>
Gross Operating Revenues . . . . . . . . $ 251.9 214.5 651.6 624.6
Interest Income. . . . . . . . . . . . . .6 .5 1.6 1.4
Gain on Sales of Assets. . . . . . . . . - - 2.4 .1
Other Income . . . . . . . . . . . . . . .2 .2 .9 1.8
------- ------- ------- -------
Total Revenues . . . . . . . . . . . . 252.7 215.2 656.5 627.9
Costs of Sales and Operating Expenses. . 235.7 195.7 594.5 581.6
General and Administrative . . . . . . . 3.5 3.9 10.5 10.9
Depreciation, Depletion and Amortization 9.5 5.8 23.9 15.4
Interest Expense, Net of Capitalized Interest 4.5 5.0 14.0 12.8
Other Expense. . . . . . . . . . . . . . 1.4 1.5 4.8 4.5
Income Tax Provision . . . . . . . . . . 1.4 1.6 3.6 2.4
------- ------- ------- -------
Earnings (Loss) Before Extraordinary Loss. ( 3.3) 1.7 5.2 .3
Extraordinary Loss on Extinguishment of Debt - - ( 4.8) -
------- ------- ------- -------
Net Earnings (Loss) . . . . . . . . . . ( 3.3) 1.7 .4 .3
Dividend Requirements on Preferred Stock - 2.3 2.7 6.9
------- ------- ------- -------
Net Loss Applicable to Common Stock. . . $( 3.3) ( .6) ( 2.3) ( 6.6)
======= ======= ======= =======
Earnings (Loss) per Primary and Fully Diluted<F3> Share:
Earnings (Loss) Before Extraordinary Loss $( .13) ( .04) .11 ( .47)
Extraordinary Loss on Extinguishment of Debt - - ( .21) -
------- ------- ------- -------
Net Loss . . . . . . . . . . . . . . . $( .13) ( .04) ( .10) ( .47)
======= ======= ======= =======
<FN>
<F3>Anti-dilutive
</TABLE>
A net loss of $3.3 million, or $.13 per share, for the three months ended
September 30, 1994 ("1994 third quarter") compares to net earnings of $1.7
million, or a net loss of $.04 per share after preferred stock dividend
requirements, for the three months ended September 30, 1993 ("1993 third
quarter"). The decline in the 1994 third quarter, as compared to the 1993 third
quarter, was primarily attributable to lower operating results from the
Company's refining and marketing segment. During the 1994 third quarter, the
pattern of depressed refined product margins which began in the second quarter
of 1994 continued. Results for the comparable 1993 quarter included a $5.0
million noncash charge for a LIFO inventory valuation.
Net earnings of $.4 million, or a net loss of $.10 per share after preferred
stock dividend requirements, for the nine months ended September 30, 1994 ("1994
period") compare to net earnings of $.3 million, or a net loss of $.47 per share
after preferred stock dividend requirements for the nine months ended September
30, 1993 ("1993 period"). 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 $5.2
million, or $.11 per share, for the 1994 period. 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 a $5.0 million noncash charge for a LIFO
inventory valuation partially offset by a $3.0 million reduction in expenses for
resolution of certain state tax issues and a gain of $1.4 million on the
repurchase and retirement of $11.25 million principal amount of Subordinated
Debentures. Excluding these transactions from both periods, the improvement of
$1.5 million in the 1994 period as compared to the 1993 period was primarily
attributable to increased natural gas production from the Company's exploration
and production operations in South Texas and Bolivia partially offset by the
lower operating results from the Company's refining and marketing segment and
the impact of lower spot market prices for sales of domestic natural gas.
2
<TABLE>
<CAPTION>
Refining and Marketing Three Months Ended Nine Months Ended
September 30, September 30,
1994 1993 1994 1993
(Dollars in millions, except per barrel amounts)
<S> <C> <C> <C> <C>
Gross Operating Revenues . . . . . . . $ 207.1 174.6 523.6 525.0
Costs of Sales . . . . . . . . . . . . 187.8 148.6 459.6 454.8
-------- -------- -------- --------
Gross Margin. . . . . . . . . . . . . 19.3 26.0 64.0 70.2
Operating Expenses . . . . . . . . . . 21.8 21.4 62.4 57.0
Depreciation and Amortization. . . . . 2.6 2.5 7.8 7.6
Other (Income) Expense, Including Gain
on Asset Sales . . . . . . . . . . - .1 ( 2.5) .2
-------- -------- -------- --------
Operating Profit (Loss) . . . . . . . $( 5.1) 2.0 ( 3.7) 5.4
======== ======== ======== ========
Capital Expenditures . . . . . . . . . $ 8.6 3.0 22.9 4.0
======== ======== ======== ========
Refinery Throughput (average daily barrels) 46,330 51,328 44,770 50,503
======== ======== ======== ========
Sales of Refinery Production:
Sales ($ per barrel). . . . . . . . . $ 21.80 22.59 20.42 22.45
Margin ($ per barrel) . . . . . . . . $ 1.86 4.40<F4> 3.08 4.06<F4>
Volume (average daily barrels). . . . 41,663 48,988 44,176 50,730
Sales of Products Purchased for Resale:
Sales ($ per barrel). . . . . . . . . $ 26.07 27.47 25.15 27.50
Margin ($ per barrel) . . . . . . . . $ 2.46 1.92 2.38 1.24
Volume (average daily barrels). . . . 38,946 17,882 26,923 19,111
Sales Volumes (average daily barrels):
Gasoline. . . . . . . . . . . . . . . 27,000 23,171 23,603 23,219
Jet fuel. . . . . . . . . . . . . . . 19,999 12,023 14,525 11,107
Diesel fuel and other distillates . . 20,490 17,123 18,772 19,225
Residual fuel oil . . . . . . . . . . 13,120 14,553 14,199 16,290
-------- -------- -------- --------
Total . . . . . . . . . . . . . . . 80,609 66,870 71,099 69,841
======== ======== ======== ========
Sales Price ($ per barrel):
Gasoline. . . . . . . . . . . . . . . $ 28.45 28.60 26.75 28.01
Jet fuel. . . . . . . . . . . . . . . $ 25.33 27.20 24.84 28.18
Diesel fuel and other distillates . . $ 23.68 26.14 23.37 26.50
Residual fuel oil . . . . . . . . . . $ 12.50 11.04 10.45 11.73
<FN>
<F4> Excludes the effect of a noncash charge of $5.0 million for a LIFO inventory valuation.
</TABLE>
3
Refining and Marketing
Three Months Ended September 30, 1994 Compared to Three Months Ended September
30, 1993. During the 1994 third quarter, the pattern of depressed refined
product margins which began in the second quarter of 1994 continued. The
Company's refining and marketing operations continue to be affected by these
adverse market conditions, resulting in an operating loss of $5.1 million for
the 1994 third quarter compared to an operating profit of $2.0 million in the
1993 third quarter. The 1993 third quarter operating profit included a noncash
charge of $5.0 million for a LIFO inventory valuation. Gross operating revenues
increased by $32.5 million in the 1994 third quarter, as compared to the 1993
third quarter, primarily due to a 21% increase in refined product sales volumes
together with increased sales of crude oil. Costs of sales were higher by $39.2
million in the 1994 third quarter than in the comparable 1993 quarter due to the
increase in sales volumes and higher crude oil supply costs.
During the 1994 second quarter, decreased production of Alaska North Slope
("ANS") crude oil combined with an increased demand for ANS crude oil for use as
a feedstock in West Coast refineries resulted in an increase in the cost of ANS
crude oil supplied to the Company's refinery. These market conditions continued
through the 1994 third quarter. Sales prices of refined products produced at
the Company's refinery have not increased proportionately and, as a result,
refined product margins continue to be severely depressed. Results from the
Company's refining and marketing segment will be adversely affected by these
conditions for so long as such conditions exist. However, the Company expects
that the value of its refinery yield will improve when the Company's vacuum unit
becomes operational in December 1994.
Nine Months Ended September 30, 1994 Compared to Nine Months Ended September 30,
1993. Gross operating revenues decreased in the 1994 period as compared to the
1993 period, primarily due to lower sales prices for refined products
substantially offset by increased sales of crude oil. Costs of sales were
higher in the 1994 period due to higher crude oil costs, while the increase in
operating expenses included higher advertising, maintenance, environmental and
transportation 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.
4
<TABLE>
<CAPTION>
Exploration and Production Three Months Ended Nine Months Ended
September 30, September 30,
1994 1993 1994 1993
(Dollars in millions, except per unit amounts)
<S> <C> <C> <C> <C>
United States:
Gross operating revenues<F5>. . . . . . . $ 19.3 14.7 59.5 31.0
Lifting cost. . . . . . . . . . . . . . . 3.6 2.1 9.1 4.5
Depreciation, depletion and amortization. 6.6 3.0 15.1 6.9
Other. . . . . . . . . . . . . . . . . . ( .3) .1 .1 .7
------ ------ ------ ------
Operating profit - United States. . . . 9.4 9.5 35.2 18.9
------ ------ ------ ------
Bolivia:
Gross operating revenues. . . . . . . . . 4.0 3.1 10.1 9.0
Lifting cost. . . . . . . . . . . . . . . .2 .1 .5 1.0
Other . . . . . . . . . . . . . . . . . . .8 .9 2.2 2.4
------ ------ ------ ------
Operating profit - Bolivia. . . . . . . 3.0 2.1 7.4 5.6
------ ------ ------ ------
Total Operating Profit - Exploration and Production $ 12.4 11.6 42.6 24.5
====== ====== ====== ======
United States:
Capital expenditures. . . . . . . . . . . $ 19.4 10.1 48.8 21.4
====== ====== ====== ======
Net natural gas production (average daily Mcf) -
Spot market and other . . . . . . . . . 88,653 29,405 57,695 23,937
Tennessee Gas Contract<F5>. . . . . . . 9,369 12,469 15,126 8,376
------ ------ ------ ------
Total production . . . . . . . . . . 98,022 41,874 72,821 32,313
====== ====== ====== ======
Average natural gas sales price per Mcf -
Spot market . . . . . . . . . . . . . . $ 1.48 2.13 1.66 2.02
Tennessee Gas Contract<F5>. . . . . . . $ 7.89 7.60 7.89 7.51
Average . . . . . . . . . . . . . . . . $ 2.10 3.76 2.95 3.45
Average lifting cost per Mcf. . . . . . . $ .40 .54 .46 .51
Depletion per Mcf . . . . . . . . . . . . $ .73 .77 .76 .78
Bolivia:
Net natural gas production (average daily Mcf) 25,528 19,688 22,262 19,183
Average natural gas sales price per Mcf . $ 1.22 1.23 1.22 1.20
Net crude oil (condensate) production
(average daily barrels) . . . . . . . . 832 657 744 660
Average crude oil sales price per barrel $ 14.04 14.33 13.16 15.00
Average lifting cost per net equivalent Mcf $ .06 .06 .06 .16
<FN>
<F5>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>
5
Exploration and Production
Three Months Ended September 30, 1994 Compared to Three Months Ended September
30, 1993. Successful development drilling in the Bob West Field in South Texas
continued to be the primary contributing factor to this segment's operating
profit. The number of producing wells in South Texas in which the Company has a
working interest increased to 44 wells at the end of the 1994 third quarter, as
compared to 20 wells at the end of the 1993 third quarter. The Company's 1994
third quarter results included a 134% increase in domestic natural gas
production with a $4.6 million increase in revenues as compared to the prior
year quarter. However, revenues for the 1994 third quarter were significantly
affected by a decline in spot market prices for natural gas and reduced takes of
natural gas by Tennessee Gas. In response to the depressed spot market prices,
the Company elected to curtail its domestic natural gas production by an
estimated 23 million cubic feet per day during the month of September 1994. The
Company may elect to curtail natural gas production in the future, depending
upon market conditions. Additionally, Tennessee Gas, under the provisions of
the Tennessee Gas Contract which is further discussed below, elected not to take
gas from early August through mid-September 1994. Total lifting cost and
depreciation, depletion and amortization were higher in the 1994 third quarter,
as compared to the 1993 third quarter, due to the increased production level.
The Company, based on quarterly deliverability tests, 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 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 for gas not taken within 60 days
after the end of such contract year. 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 the bond Tennessee Gas posted in September 1994.
As discussed above, during the 1994 third quarter, Tennessee Gas elected not to
take an average of approximately 9,300 Mcf of natural gas per day which reduced
the Company's revenues in the 1994 third quarter. However, during the fourth
quarter of 1994, Tennessee Gas has been taking natural gas from the dedicated
acreage under the Tennessee Gas Contract and the Company has also allowed
Tennessee Gas to make-up gas takes from the nondedicated acreage, all at the
Bond Price. The Company continues to recognize revenues for these sales at the
Contract Price. 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 $.9 million when
comparing the 1994 third quarter to the 1993 third quarter, primarily due to a
30% increase in average daily natural gas production. The Company was producing
gas at higher levels during the 1994 third quarter due to the inability of
another producer to satisfy gas supply requirements. The Company does not know
how long this condition will exist, but expects these higher production rates to
continue into the fourth quarter of 1994. 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 been extended through March 31, 1997. The contract extension
maintains approximately the same volumes as the previous contract between YPFB
and the Republic of Argentina, 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.
Nine Months Ended September 30, 1994 Compared to Nine Months Ended September 30,
1993. Revenues from the Company's South Texas exploration and production
activities increased by $28.5 million, or 92%, during the 1994 period as
compared to the same period of 1993, primarily due to increased production
levels of natural gas partially offset by
6
lower spot market prices. The increased production volumes contributed to the
correlative increase in lifting costs and depreciation, depletion and
amortization. Due to expansions in pipeline capacity, gathering systems and
processing capacity during the 1994 period, the Company believes that previous
production constraints caused by limited transportation facilities have been
eliminated for the foreseeable future. See discussion above for information
relating to current market conditions.
Operating results from the Company's Bolivian operations improved by $1.8
million during the 1994 period, as compared to the 1993 period, due primarily to
increased production of natural gas. See discussion above for information
relating to the Company's contract with YPFB regarding sales of natural gas
production.
7
<TABLE>
<CAPTION>
Oil Field Supply and Distribution Three Months Ended Nine Months Ended
September 30, September 30,
1994 1993 1994 1993
(Dollars in millions)
<S> <C> <C> <C> <C>
Gross Operating Revenues . . . . . . . . . $ 21.5 22.1 58.4 59.6
Costs of Sales . . . . . . . . . . . . . . 19.0 18.8 50.7 50.4
------ ------ ------ ------
Gross Margin . . . . . . . . . . . . . . 2.5 3.3 7.7 9.2
Operating Expenses and Other . . . . . . . 2.6 3.8 9.7 10.8
Depreciation and Amortization. . . . . . . .1 - .3 .3
Other (Income) Expense . . . . . . . . . . - - ( .5) -
------ ------ ------ ------
Operating Loss . . . . . . . . . . . . . $ ( .2) ( .5) ( 1.8) ( 1.9)
====== ====== ====== ======
Refined Product Sales (average daily barrels) 8,582 8,244 7,835 7,114
====== ====== ====== ======
</TABLE>
Three Months Ended September 30, 1994 Compared to Three Months Ended September
30, 1993. Refined product sales prices and gross margins during the 1994 third
quarter continued to be impacted by 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.
Nine Months Ended September 30, 1994 Compared to Nine Months Ended September 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 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 $1.4
million in charges recorded in the 1994 period for winding up the Company's
environmental products marketing operations which were discontinued in the first
quarter of 1994.
Other Income
During the 1994 period, 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 Debentures 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 decrease of $.5 million in interest expense during the 1994 third quarter,
as compared to the 1993 third quarter, was primarily due to the capitalization
of $.4 million in interest expense in the 1994 third quarter. The increase of
$1.2 million in interest expense during the 1994 period, as compared to the 1993
period, was primarily due to a reduction recorded in the 1993 period related to
the resolution of certain state tax issues partially offset by capitalized
interest of $.6 million recorded in the 1994 period.
Other Expense
Other expense increased by $.3 million during the 1994 period, as compared to
the 1993 period, primarily due to environmental expenses related to former
operations of the Company partially offset by reduced financing and other costs.
8
Income Taxes
The increase of $1.2 million in the income tax provision during the 1994 period,
as compared to the same period in 1993, included the effect of a reduction
recorded in the 1993 period for resolution of certain state tax issues together
with higher foreign income taxes on increased Bolivian earnings in the 1994
period.
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 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 nine months 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 $125
million corporate Revolving Credit Facility and obtained $15 million additional
financing for a major addition to the Company's 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 issued an additional 132,416 shares of Common Stock 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. In addition, the Company paid $500,000 for certain
legal fees and expenses in connection with such litigation.
(iii) The Company and MetLife Louisiana, the holder of all of 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.
9
(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 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 Company's 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 September 30, 1994, the borrowing base, which
is comprised of eligible accounts receivable, inventory and domestic oil and gas
reserves, was $100 million. As of September 30, 1994, the Company had
outstanding letters of credit under the facility of approximately $36 million,
with a remaining unused availability of approximately $64 million. Cash
borrowings are limited to the amount of the oil and gas reserve component of the
borrowing base, which has most recently been determined to be approximately $45
million. Under the terms of the Revolving Credit Facility, the oil and gas
component of the borrowing base is subject to quarterly reevaluations. 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. At September 30,
1994, there were no cash borrowings under the Revolving Credit Facility. Under
the terms of the Revolving Credit Facility, the Company is required to maintain
specified levels of working capital, tangible net worth, consolidated cash flow
and refinery cash flow, as defined in the Revolving Credit Facility. 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. At September 30,
1994, the Company satisfied all of its covenant requirements under the Revolving
Credit Facility except for the refinery cash flow requirement which was not met
due to the downturn in the refining and marketing industry, which also adversely
affected the Company's operations. The Company's lenders waived the refinery
cash flow requirement for the period ended September 30, 1994. Currently, the
Company is discussing a proposed amendment with its lenders, which would include
a revision to the refinery cash flow requirement, and expects to finalize such
amendment by December 31, 1994. For further 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.
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
Company's refinery (the "Vacuum Unit Loan"). The Vacuum Unit Loan matures on
January 1, 2002 and is secured by
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a first lien on the refinery. At September 30, 1994, the Company had borrowed
$10.2 million under the Vacuum Unit Loan. For further information on the Vacuum
Unit Loan, see Note 4 of Notes to Condensed Consolidated Financial Statements.
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 nine months ended September 30, 1994, cash and cash equivalents
decreased by $6.2 million and short- term investments decreased by $4.0 million.
At September 30, 1994, the Company's cash and short-term investments totaled
$32.4 million and working capital amounted to $82.3 million. Net cash from
operating activities of $52.6 million during the nine months ended September 30,
1994, compared to $28.6 million for the 1993 period, was primarily due to net
earnings adjusted for certain noncash charges and reduced working capital
requirements. The comparable 1993 period included payments totaling $12.3
million to the State of Alaska in connection with the settlement of a
contractual dispute, as compared to $2.0 million paid to the State of Alaska in
the 1994 period. Net cash used in investing activities of $62.8 million during
the 1994 period included capital expenditures of $73.3 million, an increase of
$47.0 million from the comparable prior year period. Included in capital
expenditures for the 1994 period were $48.8 million for the Company's
exploration and production activities in South Texas, primarily for completion
of 17 natural gas development wells and construction of gas processing
facilities and pipelines. The Company's refining and marketing segment's
capital expenditures totaled $22.9 million for the 1994 period, primarily for
installation costs of the vacuum unit at the Company's refinery. These uses of
cash in investing activities in the 1994 period were partially offset by the net
decrease of $4.0 million in short-term investments and cash proceeds of $2.5
million, primarily from the sale of the Company's Valdez, Alaska terminal. The
1993 comparable period included an $18.5 million reduction in short-term
investments. Net cash from financing activities of $4.0 million during the 1994
period included $10.2 million in borrowings under the Vacuum Unit Loan and $4.0
million net proceeds received from the Offering after exercise of the MetLife
Louisiana Option. These financing sources of cash during the 1994 period were
partially offset by 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)
and dividends of $1.7 million paid on preferred stock. The comparable 1993
period included $9.7 million of cash used for repurchase of a portion of the
Company's Subordinated Debentures.
The Company's total capital expenditures for 1994 are estimated to be $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 25 development gas wells in the Bob West Field during 1994, of which
17 wells had been completed during the first nine 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.
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The vacuum unit is scheduled to become operational in December 1994. For the
nine months ended September 30, 1994, total capital expenditures of $73.3
million have been substantially funded by the Company's cash flows from
operating activities, existing cash and an initial borrowing of $10.2 million
under the Vacuum Unit Loan. 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 sales of natural gas under the Tennessee Gas Contract have been
significantly reduced. The Company anticipates that capital expenditures for
the remainder of 1994 will be funded with cash flows from operating activities,
existing cash balances and additional borrowings under the Vacuum Unit Loan. If
necessary, the Company has additional cash borrowing availability under the
Revolving Credit Facility.
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 September 1994, the Contract Price
was in excess of $8.00 per Mcf, the Section 101 price was $4.80 per Mcf and the
average spot market price was $1.32 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 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
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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 September 30, 1994, under the Tennessee Gas Contract based on the
Contract Price, which net revenues aggregated $29.1 million more than the
Section 101 prices and $54.4 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 $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. 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. 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, in an amount equal to the anticipated value of the Tennessee Gas Contract
during that period. 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 non-refundable 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 September 30, 1994, the Company's receivables
included $1.5 million representing 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 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 holding
discussions with the DOJ concerning the assessment of penalties with respect to
certain alleged violations of environmental laws and regulations. At September
30, 1994, the Company's accruals for environmental matters amounted to $6.7
million. 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
Company's 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. See Note 5 of Notes to Condensed Consolidated Financial Statements.
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SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of 1934, the
Registrant has duly caused this Amendment to be signed on its behalf by the
undersigned thereunto duly authorized.
TESORO PETROLEUM CORPORATION
Registrant
Date: November 28, 1994 /s/ Bruce A. Smith
Bruce A. Smith
Executive Vice President and
Chief Financial Officer
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