-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: keymaster@town.hall.org Originator-Key-Asymmetric: MFkwCgYEVQgBAQICAgADSwAwSAJBALeWW4xDV4i7+b6+UyPn5RtObb1cJ7VkACDq pKb9/DClgTKIm08lCfoilvi9Wl4SODbR1+1waHhiGmeZO8OdgLUCAwEAAQ== MIC-Info: RSA-MD5,RSA, ANYOK6uTO46FQD62R4mIsTtwVkPw2EVXP3DHJvthGTG5+aMqUgSHewCzAoD46JWB kzcabOfz7sPDoDug85ICSw== 0000050104-94-000018.txt : 19941121 0000050104-94-000018.hdr.sgml : 19941121 ACCESSION NUMBER: 0000050104-94-000018 CONFORMED SUBMISSION TYPE: 10-Q PUBLIC DOCUMENT COUNT: 4 CONFORMED PERIOD OF REPORT: 19940930 FILED AS OF DATE: 19941114 SROS: NYSE SROS: PSE FILER: COMPANY DATA: COMPANY CONFORMED NAME: TESORO PETROLEUM CORP /NEW/ CENTRAL INDEX KEY: 0000050104 STANDARD INDUSTRIAL CLASSIFICATION: 2911 IRS NUMBER: 950862768 STATE OF INCORPORATION: DE FISCAL YEAR END: 0930 FILING VALUES: FORM TYPE: 10-Q SEC ACT: 1934 Act SEC FILE NUMBER: 001-03473 FILM NUMBER: 94559512 BUSINESS ADDRESS: STREET 1: 8700 TESORO DR CITY: SAN ANTONIO STATE: TX ZIP: 78217 BUSINESS PHONE: 2108288484 10-Q 1 10Q FOR QUARTER ENDED 9/30/94 UNITED STATES SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 FORM 10-Q (Mark One) [X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the quarterly period ended September 30, 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. TESORO PETROLEUM CORPORATION AND SUBSIDIARIES INDEX TO FORM 10-Q FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 1994 PART I. FINANCIAL INFORMATION Page Item 1. Financial Statements (Unaudited) Condensed Consolidated Balance Sheets - September 30, 1994 and December 31, 1993 . . . . . . . . . . . . . . . . . . . . . . . . 3 Condensed Statements of Consolidated Operations - Three Months and Nine Months Ended September 30, 1994 and 1993 . . . . . . . . 4 Condensed Statements of Consolidated Cash Flows - Nine Months Ended September 30, 1994 and 1993 . . . . . . . . . . . . . . . . 5 Notes to Condensed Consolidated Financial Statements. . . . . . . . 6 Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations . . . . . . . . . . . . . . . . . . . . . 12 PART II. OTHER INFORMATION Item 1. Legal Proceedings. . . . . . . . . . . . . . . . . . . . . . 24 Item 6. Exhibits and Reports on Form 8-K . . . . . . . . . . . . . . 25 SIGNATURES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26 2 PART I - FINANCIAL INFORMATION Item 1. Financial Statements TESORO PETROLEUM CORPORATION AND SUBSIDIARIES CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) (Dollars in thousands)
September 30, December 31, 1994 1993 ASSETS CURRENT ASSETS: Cash and cash equivalents (includes restricted cash of $25,420 at December 31, 1993) . . . . . . . . . .$ 30,440 36,596 Short-term investments. . . . . . . . . . . . . . . . 1,974 5,952 Receivables, less allowance for doubtful accounts of $1,860 ($2,487 at December 31, 1993). . . . . . . . 73,543 69,637 Inventories: Crude oil, refined products and merchandise . . . . 49,548 71,011 Materials and supplies. . . . . . . . . . . . . . . 3,323 3,175 Prepaid expenses and other. . . . . . . . . . . . . . 12,610 10,136 ------- ------- Total Current Assets. . . . . . . . . . . . . . . . 171,438 196,507 PROPERTY, PLANT AND EQUIPMENT, Net of Accumulated Depreciation, Depletion and Amortization of $193,748 ($172,312 at December 31, 1993). . . . . . . 259,179 213,151 INVESTMENT IN TESORO BOLIVIA PETROLEUM COMPANY . . . . 10,290 6,310 OTHER ASSETS . . . . . . . . . . . . . . . . . . . . . 18,067 18,554 ------- ------- $ 458,974 434,522 ======= ======= LIABILITIES AND STOCKHOLDERS' EQUITY CURRENT LIABILITIES: Accounts payable. . . . . . . . . . . . . . . . . . .$ 51,012 43,192 Accrued liabilities . . . . . . . . . . . . . . . . . 27,425 24,017 Current portion of long-term debt and other obligations . . . . . . . . . . . . . . . . . . . 10,671 4,805 ------- ------- Total Current Liabilities . . . . . . . . . . . . . 89,108 72,014 ------- ------- OTHER LIABILITIES. . . . . . . . . . . . . . . . . . . 36,265 45,272 ------- ------- LONG-TERM DEBT AND OTHER OBLIGATIONS, LESS CURRENT PORTION . . . . . . . . . . . . . . . . . . . . . . . 188,228 180,667 ------- ------- COMMITMENTS AND CONTINGENCIES (Note 5) REDEEMABLE PREFERRED STOCK . . . . . . . . . . . . . . - 78,051 ------- ------- COMMON STOCK AND OTHER STOCKHOLDERS' EQUITY: $2.16 Cumulative convertible preferred stock. . . . . - 1,320 Common Stock. . . . . . . . . . . . . . . . . . . . . 4,064 2,348 Additional paid-in capital. . . . . . . . . . . . . . 175,638 86,985 Accumulated deficit . . . . . . . . . . . . . . . . . ( 34,161) ( 31,898) ------- ------- 145,541 58,755 Less deferred compensation. . . . . . . . . . . . . . 168 237 ------- ------- 145,373 58,518 ------- ------- $ 458,974 434,522 ======= ======= The accompanying notes are an integral part of these condensed consolidated financial statements. The balance sheet at December 31, 1993 has been taken from the audited consolidated financial statements at that date and condensed.
3 TESORO PETROLEUM CORPORATION AND SUBSIDIARIES CONDENSED STATEMENTS OF CONSOLIDATED OPERATIONS (Unaudited) (In thousands, except per share amounts)
Three Months Ended Nine Months Ended September 30, September 30, 1994 1993 1994 1993 REVENUES: Gross operating revenues. . . . . . . . . . $ 251,811 214,464 651,558 624,581 Interest income . . . . . . . . . . . . . . 627 484 1,602 1,406 Gain on sales of assets . . . . . . . . . . 18 12 2,359 64 Other . . . . . . . . . . . . . . . . . . . 219 212 941 1,797 ------- ------- ------- ------- Total Revenues. . . . . . . . . . . . . . 252,675 215,172 656,460 627,848 ------- ------- ------- ------- COSTS AND EXPENSES: Costs of sales and operating expenses . . . 235,638 195,667 594,471 581,536 General and administrative. . . . . . . . . 3,480 3,866 10,484 10,946 Depreciation, depletion and amortization. . 9,493 5,795 23,888 15,350 Interest expense, net of capitalized interest 4,483 4,976 13,989 12,801 Other . . . . . . . . . . . . . . . . . . . 1,409 1,472 4,852 4,441 ------- ------- ------- ------- Total Costs and Expenses. . . . . . . . . 254,503 211,776 647,684 625,074 ------- ------- ------- ------- EARNINGS (LOSS) BEFORE INCOME TAXES AND EXTRAORDINARY LOSS ON EXTINGUISHMENT OF DEBT . . . . . . . . . . . . . . . . . . ( 1,828) 3,396 8,776 2,774 Income Tax Provision . . . . . . . . . . . . 1,435 1,636 3,607 2,435 ------- ------- ------- ------- EARNINGS (LOSS) BEFORE EXTRAORDINARY LOSS ON EXTINGUISHMENT OF DEBT. . . . . . . ( 3,263) 1,760 5,169 339 Extraordinary Loss on Extinguishment of Debt - - ( 4,752) - ------- ------- ------- ------- NET EARNINGS (LOSS) . . . . . . . . . . . . ( 3,263) 1,760 417 339 Dividend Requirements on Preferred Stock . . - 2,302 2,680 6,906 ------- ------- ------- ------- NET LOSS APPLICABLE TO COMMON STOCK. . . . . $( 3,263) ( 542) ( 2,263) ( 6,567) ======= ======= ======= ======= EARNINGS (LOSS) PER PRIMARY AND FULLY DILUTED SHARE: Earnings (Loss) Before Extraordinary Loss on Extinguishment of Debt . . . . . . . . $( .13) ( .04) .11 ( .47) Extraordinary Loss on Extinguishment of Debt - - ( .21) - ------- ------- ------- ------- Net Loss . . . . . . . . . . . . . . . . . $( .13) ( .04) ( .10) ( .47) ======= ======= ======= ======= AVERAGE OUTSTANDING COMMON AND COMMON EQUIVALENT SHARES . . . . . . . . . . . . . 25,011 14,070 22,584 14,070 ======= ======= ======= ======= 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) (Dollars in thousands)
Nine Months Ended September 30, 1994 1993 CASH FLOWS FROM (USED IN) OPERATING ACTIVITIES: Net earnings . . . . . . . . . . . . . . . . . . . . . $ 417 339 Adjustments to reconcile net earnings to net cash from operating activities: Loss (gain) on extinguishment of debt . . . . . . . . 4,752 ( 1,422) Depreciation, depletion and amortization. . . . . . . 23,888 15,350 Gain on sales of assets . . . . . . . . . . . . . . . ( 2,359) ( 64) Other . . . . . . . . . . . . . . . . . . . . . . . . 1,187 2,125 Changes in assets and liabilities: Receivables . . . . . . . . . . . . . . . . . . . . ( 2,906) 10,795 Inventories . . . . . . . . . . . . . . . . . . . . 21,315 22,237 Investment in Tesoro Bolivia Petroleum Company . . . ( 3,980) ( 1,405) Other assets . . . . . . . . . . . . . . . . . . . . ( 1,090) 2,257 Accounts payable and other current liabilities . . . 11,108 (10,961) Obligation payments to State of Alaska . . . . . . . ( 2,011) (12,264) Other liabilities and obligations . . . . . . . . . 2,309 1,585 ------ ------ Net cash from operating activities . . . . . . . . 52,630 28,572 ------ ------ CASH FLOWS FROM (USED IN) INVESTING ACTIVITIES: Capital expenditures . . . . . . . . . . . . . . . . . (73,260) (26,286) Proceeds from sales of assets, net of expenses . . . . 2,526 141 Sales of short-term investments . . . . . . . . . . . . 5,952 38,837 Purchases of short-term investments . . . . . . . . . . ( 1,974) (20,293) Other . . . . . . . . . . . . . . . . . . . . . . . . . 3,950 ( 250) ------ ------ Net cash used in investing activities . . . . . . . (62,806) ( 7,851) ------ ------ CASH FLOWS FROM (USED IN) FINANCING ACTIVITIES: Proceeds from issuance of common stock, net . . . . . . 56,967 - Repurchase of common and preferred stock. . . . . . . . (52,948) - Dividends on preferred stock. . . . . . . . . . . . . . ( 1,684) - Payments of long-term debt. . . . . . . . . . . . . . . (11,097) ( 1,076) Issuance of long-term debt . . . . . . . . . . . . . . 15,206 - Repurchase of debentures . . . . . . . . . . . . . . . - ( 9,675) Other. . .. . . . . . . . . . . . . . . . . . . . . . . ( 2,424) ( 5) ------ ------ Net cash from (used in) financing activities . . . . 4,020 (10,756) ------ ------ INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS . . . . ( 6,156) 9,965 CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD . . . . 36,596 46,869 ------ ------ CASH AND CASH EQUIVALENTS AT END OF PERIOD . . . . . . . $ 30,440 56,834 ====== ====== SUPPLEMENTAL CASH FLOW DISCLOSURES: Interest paid, net of $607 capitalized in 1994 . . . . $ 13,220 17,543 ====== ====== Income taxes paid . . . . . . . . . . . . . . . . . . . $ 3,855 3,448 ====== ======
The accompanying notes are an integral part of these condensed consolidated financial statements. 5 TESORO PETROLEUM CORPORATION AND SUBSIDIARIES NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited) (1) Basis of Presentation The interim condensed consolidated financial statements are unaudited but, in the opinion of management, incorporate all adjustments necessary for a fair presentation of results for such periods. Such adjustments are of a normal recurring nature. For information regarding the effects of the Recapitalization and Offering (as hereinafter defined), see Note 2 below. The results of operations for any interim period are not necessarily indicative of results for the full year. The accompanying condensed consolidated financial statements should be read in conjunction with the consolidated financial statements and notes thereto contained in the Company's Annual Report on Form 10-K for the year ended December 31, 1993. (2) Recapitalization and Equity Offering Recapitalization. In February 1994, the Company consummated exchange offers and adopted amendments to its Restated Certificate of Incorporation pursuant to which the Company's outstanding debt and preferred stocks were restructured (the "Recapitalization"). Significant components of the Recapitalization, together with the applicable accounting effects, were as follows: (i) The Company exchanged $44.1 million principal amount of new 13% Exchange Notes ("Exchange Notes") due December 1, 2000 for a like principal amount of 12 3/4% Subordinated Debentures ("Subordinated Debentures") due March 15, 2001. This exchange satisfied the 1994 sinking fund requirement and, except for $.9 million, will satisfy sinking fund requirements for the Subordinated Debentures through 1997. The exchange of the Subordinated Debentures was accounted for as an early extinguishment of debt in the first quarter of 1994, resulting in a charge of $4.8 million as an extraordinary loss on this transaction, which represented the excess of the estimated market value of the Exchange Notes over the carrying value of the Subordinated Debentures. The carrying value of the Subordinated Debentures exchanged was reduced by applicable unamortized debt issue costs. No tax benefit was available to offset the extraordinary loss as the Company has provided a 100% valuation allowance to the extent of its deferred tax assets. (ii) The 1,319,563 outstanding shares of the Company's $2.16 Preferred Stock, together with accrued and unpaid dividends of $9.5 million at February 9, 1994, were reclassified into 6,465,859 shares of Common Stock. The Company also 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. The reclassification of the $2.16 Preferred Stock eliminated preferred dividend requirements of $2.9 million per year on the $2.16 Preferred Stock. The issuance of the Common Stock in connection with the reclassification and settlement of litigation that was recorded in 1994 resulted in an increase in Common Stock of approximately $1 million, equal to the aggregate par value of the Common Stock issued, and an increase in additional paid-in capital of approximately $9 million. (iii) The Company and MetLife Security Insurance Company of Louisiana ("MetLife Louisiana"), the holder of all of the Company's outstanding $2.20 Cumulative Convertible Preferred Stock ("$2.20 Preferred Stock"), entered into an agreement (the "Amended MetLife Memorandum") pursuant to which MetLife Louisiana agreed, among other matters, to waive all existing mandatory redemption requirements, to consider all accrued and unpaid dividends on the $2.20 Preferred Stock (aggregating $21.2 million at February 9, 1994) to have been paid, and to grant to the Company a three-year option (the "MetLife Louisiana Option") to purchase all of MetLife Louisiana's holdings of $2.20 Preferred Stock and Common Stock for approximately $53 million prior to June 30, 1994 (after giving effect to the cash dividend on the $2.20 Preferred Stock paid in May 1994), all in consideration for, among other things, the issuance by the Company to MetLife Louisiana of 1,900,075 shares of Common Stock. Such additional shares were also subject to the MetLife Louisiana Option. 6 These actions resulted in the reclassification of the $2.20 Preferred Stock into equity capital at its aggregate liquidation preference of $57.5 million and the recording of an increase in additional paid-in capital of approximately $21 million in February 1994. Equity Offering. In June 1994, the Company completed a public offering (the "Offering") of 5,850,000 shares of its Common Stock for the purpose of raising funds to exercise the MetLife Louisiana Option. Net proceeds to the Company from the Offering, after deduction of underwriting discounts and commissions and associated expenses, were approximately $57.0 million. On June 29, 1994, the Company exercised the MetLife Louisiana Option in full for approximately $53.0 million, acquiring 2,875,000 shares of $2.20 Preferred Stock having a liquidation value of $57.5 million and 4,084,160 shares of Common Stock having an aggregate market value of $45.9 million (based on a closing price of $11.25 per share on June 28, 1994). The exercise eliminated preferred dividend requirements of $6.3 million per year on the $2.20 Preferred Stock. The Offering and the exercise in full of the MetLife Louisiana Option resulted in a net increase of 1,765,840 outstanding shares of Common Stock, the retirement of $57.5 million of the $2.20 Preferred Stock, and increases in Common Stock of approximately $.3 million, additional paid-in capital of approximately $61.2 million and cash of approximately $4.0 million in June 1994. If the Recapitalization and Offering had been completed at the beginning of the year, the pro forma earnings per share before extraordinary loss would have increased from $.11 to $.21 on both a primary and fully diluted basis for the nine months ended September 30, 1994, reflecting the elimination of all preferred stock dividend requirements and the issuance of additional shares of Common Stock associated with the Recapitalization and Offering reduced by shares of Common Stock acquired and retired upon exercise of the MetLife Louisiana Option. The following table summarizes changes in certain components of Common Stock and Other Stockholders' Equity during the nine months ended September 30, 1994 (in millions):
$2.16 $2.20 Preferred Preferred Common Additional Stock Stock Stock Paid-In Shares Amount Shares Amount Shares Amount Capital Balances at December 31, 1993. . . . . . . 1.3 $ 1.3 - $ - 14.1 $ 2.3 $ 87.0 Reclassification of $2.16 Preferred Stock (1.3) (1.3) - - 6.5 1.1 9.7 Reclassification of $2.20 Preferred Stock - - 2.9 57.5 1.9 .3 20.9 Costs of Recapitalization . . . . . . . . - - - - - - ( 3.3) Offering, Net. . . . . . . . . . . . . . . - - - - 5.9 1.0 56.0 Exercise of MetLife Louisiana Option . . . - - (2.9) (57.5) ( 4.1) ( .7) 5.2 Other . . . . . . . . . . . . . . . . . . - - - - .1 .1 .1 ----- ----- ----- ------ ------ ------ ------- Balances at September 30, 1994 . . . . . . - $ - - $ - 24.4 $ 4.1 $ 175.6 ===== ===== ===== ====== ====== ====== =======
(3) Property, Plant and Equipment In January 1994, the Company sold its terminal facilities in Valdez, Alaska for cash proceeds of $2.0 million and a note receivable of $3.0 million, which resulted in a pretax gain to the Company of approximately $2.8 million during the nine months ended September 30, 1994. During the three and nine months ended September 30, 1994, the Company capitalized interest of $367,000 and $607,000, respectively, in conjunction with the installation of a vacuum unit at the Company's refinery. 7 (4) Credit Arrangements Revolving Credit Facility. During April 1994, the Company entered into a three-year $125 million corporate revolving credit facility ("Revolving Credit Facility") with a consortium of ten banks. The Revolving Credit Facility, which is subject to a borrowing base, provides for (i) the issuance of letters of credit up to the full amount of the borrowing base as calculated, but not to exceed $125 million, and (ii) cash borrowings up to the amount of the borrowing base attributable to domestic oil and gas reserves. Outstanding obligations under the Revolving Credit Facility are secured by liens on substantially all of the Company's trade accounts receivable and product inventory and mortgages on the Company's Kenai, Alaska refinery 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. 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. Vacuum Unit Loan. During May 1994, the National Bank of Alaska and the Alaska Industrial Development & Export Authority agreed to provide a loan to the Company of up to $15 million of the $24 million estimated cost of a new vacuum unit for the Company's refinery (the "Vacuum Unit Loan"). The Vacuum Unit Loan matures on January 1, 2002, requires 28 equal quarterly payments beginning April 1995 and bears interest at the unsecured 90-day commercial paper rate, adjusted quarterly, plus 2.6% per annum (7.34% at September 30, 1994) for two-thirds of the amount borrowed and at the National Bank of Alaska floating prime rate plus 1/4 of 1% per annum (8.0% at September 30, 1994) for the remainder. The Vacuum Unit Loan is secured by a first lien on the Company's refinery. At September 30, 1994, the Company had borrowed $10.2 million under the Vacuum Unit Loan. 8 (5) Commitments and Contingencies Tennessee Gas Contract. The Company is selling a portion of the gas from its Bob West Field to Tennessee Gas Pipeline Company ("Tennessee Gas") under a Gas Purchase and Sales Agreement (the "Tennessee Gas Contract") which provides that the price of gas shall be the maximum price as calculated in accordance with Section 102(b)(2) (the "Contract Price") of the Natural Gas Policy Act of 1978 (the "NGPA"). Tennessee Gas filed suit against the Company alleging that the Tennessee Gas Contract is not applicable to the Company's properties and that the gas sales price should be the price calculated under the provisions of Section 101 of the NGPA rather than the Contract Price. During 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 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 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. 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 9 $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. The Company is currently involved with two waste disposal sites in Louisiana at which it has been named a potentially responsible party under the Federal Superfund law. Although this law might impose joint and several liability upon each party at any site, the extent of the Company's allocated financial contribution to the cleanup of these sites is expected to be limited based on the number of companies and the volumes of waste involved. At each site, a number of large companies have also been named as potentially responsible parties and are expected to cooperate in the cleanup. The Company is also involved in remedial response and has incurred cleanup expenditures associated with environmental matters at a number of other sites including certain of its own properties. In March 1992, the Company received a Compliance Order and Notice of Violation from the U. S. Environmental Protection Agency ("EPA") alleging violations by the Company of the New Source Performance Standards under the Clean Air Act at the Company's refinery. These allegations include failure to install, maintain and operate monitoring equipment over a period of approximately six years, failure to perform accuracy testing on monitoring equipment, and failure to install certain pollution control equipment. From March 1992 to July 1993, the EPA and the Company exchanged information relevant to these allegations. In addition, the EPA conducted an environmental audit of the Company's refinery in May 1992. As a result of this audit, the EPA is also alleging violation of certain regulations relating to asbestos materials. In October 1993, the EPA referred these matters to the Department of Justice ("DOJ"). The DOJ contacted Tesoro Alaska to begin negotiating a resolution of these matters. The DOJ has indicated that it is willing to enter into a judicial consent decree with the Company and that this decree would include a penalty assessment. The DOJ has not given the Company any indication of the amount of the penalty but has indicated that any assessment will be more than a nominal amount and will factor in the multiple years of violations. Negotiations on the consent decree will begin once the parties negotiate a penalty. The Company believes that it is presently in compliance with all of the regulations cited by the EPA except for one, and expects to be in total compliance by the end of this year. 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. Proposed Pipeline Rate Increase. The Company transports its crude oil and a substantial portion of its refined products utilizing Kenai Pipe Line Company's ("KPL") pipeline and marine terminal facilities in Kenai, Alaska. In March 1994, KPL filed a revised tariff with the Federal Energy Regulatory Commission ("FERC") for dock loading services, which would have increased the Company's annual cost of transporting products through KPL's facilities from $1.2 million to $11.2 million, or an increase of $10 million per year. Following the FERC's rejection of KPL's tariff and the commencement of negotiations for the purchase by the Company of the dock facilities, KPL filed a temporary tariff that would increase the Company's annual cost by approximately $1.5 million. The negotiations between the Company and KPL are continuing. The Company believes that the ultimate resolution of this matter will not have a material adverse effect upon the financial condition or results of operations of the Company. 10 Refund Claim. In July 1994, Simmons Oil Corporation, also known as David Christopher Corporation, a former customer of the Company ("Customer"), filed suit against the Company in the United States District Court for the District of New Mexico for a refund in the amount of approximately $1.2 million, plus interest of approximately $4.4 million and attorney's fees, related to a gasoline purchase from the Company in 1979. The Customer also alleges entitlement to treble damages and punitive damages in the aggregate amount of $16.8 million. The refund claim is based on allegations that the Company renegotiated the acquisition price of gasoline sold to the Customer and failed to pass on the benefit of the renegotiated price to the Customer in violation of Department of Energy price and allocation controls then in effect. The Company believes the claim is without merit and anticipates that the ultimate resolution of this matter will not have a material adverse effect on the Company. 11 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:
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) 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 Share: Earnings (Loss) Before Extraordinary Loss $( .13) ( .04) .11 ( .47) Extraordinary Loss on Extinguishment of Debt - - ( .21) - ------- ------- ------- ------- Net Loss . . . . . . . . . . . . . . . $( .13) ( .04) ( .10) ( .47) ======= ======= ======= ======= Anti-dilutive
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. 12
Refining and Marketing Three Months Ended Nine Months Ended September 30, September 30, 1994 1993 1994 1993 (Dollars in millions, except per barrel amounts) 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) . . . . . . . . $ .10 4.40 2.57 4.06 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 Excludes the effect of a noncash charge of $5.0 million for a LIFO inventory valuation.
13 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. 14
Exploration and Production Three Months Ended Nine Months Ended September 30, September 30, 1994 1993 1994 1993 (Dollars in millions, except per unit amounts) United States: Gross operating revenues. . . . . . . $ 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. . . . . . . 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. . . . . . . $ 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 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.
15 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 16 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. 17
Oil Field Supply and Distribution Three Months Ended Nine Months Ended September 30, September 30, 1994 1993 1994 1993 (Dollars in millions) 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 ====== ====== ====== ======
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. 18 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. 19 (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 20 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. 21 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 22 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. 23 PART II - OTHER INFORMATION Item 1. Legal Proceedings Tennessee Gas Contract. The Company is selling a portion of the gas from its Bob West Field to Tennessee Gas under a Gas Purchase and Sales Agreement which provides that the price of gas shall be the maximum price as calculated in accordance with Section 102(b)(2) of the NGPA. Tennessee Gas filed suit against the Company alleging that the gas contract is not applicable to the Company's properties and that the gas sales price should be the price calculated under the provisions of Section 101 of the NGPA rather than the Contract Price. During 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 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 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 of time. 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, 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 24 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. Clean Air Act Matters. As previously reported, the EPA issued a notice of violation/compliance order to the Company's subsidiary, Tesoro Alaska Petroleum Company ("Tesoro Alaska"), in March 1992 for alleged violations of regulations promulgated under the Clean Air Act. These allegations include failure to install, maintain and operate monitoring equipment over a period of approximately six years, failure to perform accuracy testing on monitoring equipment, and failure to install certain pollution control equipment. From March 1992 to July 1993, the EPA and Tesoro Alaska exchanged information relevant to these allegations. In addition, the EPA conducted an environmental audit of Tesoro Alaska's refinery in May 1992. As a result of this audit, the EPA is also alleging violation of certain regulations relating to asbestos materials. In October 1993, the EPA referred these matters to the DOJ. The DOJ contacted Tesoro Alaska to begin negotiating a resolution of these matters. The DOJ has indicated that it is willing to enter into a judicial consent decree with Tesoro Alaska and that this decree would include a penalty assessment. The DOJ has not given Tesoro Alaska any indication of the amount of the penalty but has indicated that any assessment will be more than a nominal amount and will factor in the multiple years of violations. Negotiations on the consent decree will begin once the parties negotiate a penalty. The Company believes that it is presently in compliance with all of the regulations cited by the EPA except for one, and expects to be in total compliance by the end of this year. 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. 25 SIGNATURES Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. TESORO PETROLEUM CORPORATION Registrant Date: November 14, 1994 /s/ Michael D. Burke Michael D. Burke President and Chief Executive Officer Date: November 14, 1994 /s/ Bruce A. Smith Bruce A. Smith Executive Vice President and Chief Financial Officer 26 EXHIBIT INDEX Exhibit Number 4 Copy of Consent and Waiver No. 1 dated October 27, 1994 to the Company's Credit Agreement dated as of April 20, 1994 11 Information Supporting Earnings (Loss) Per Share Computations 27 Financial Data Schedule 27 EX-4 2 CONSENT AND WAIVER NO. 1 DATED OCTOBER 27, 1994 Exhibit 4 CONSENT AND WAIVER NO. 1 CONSENT AND WAlVER NO. 1 (the "Consent and Waiver"), dated as of October 27, 1994, by and among Tesoro Petroleum Corporation (the "Company"), Texas Commerce Bank National Association ("TCB"), individually, as an Issuing Bank and as Agent (the "Agent"), Banque Paribas ("BP"), individually, as an Issuing Bank and as Co-Agent, and Bank of Scotland, Christiania Bank, The Bank of Nova Scotia, NBD Bank, N.A., Continental Bank, N.A., First Union National Bank of North Carolina, National Bank of Canada and The Frost National Bank. WITNESSETH WHEREAS, the Company has entered into a Credit Agreement, dated as of April 20, 1994, among the Company, TCB, individually, as an Issuing Bank and as Agent, BP, individually, as an Issuing Bank and as Co-Agent, and the other financial institutions parties thereto (the "Credit Agreement"; all capitalized terms used herein and not otherwise defined herein shall have the meanings ascribed thereto in the Credit Agreement); WHEREAS, the Company has requested that Majority Lenders consent to the waiver of the Company's obligation to (i) maintain its Consolidated Working Capital Ratio to, but excluding, December 31, 1994 and (ii) cause Tesoro Alaska to maintain the Tesoro Alaska EBITDA for the Rolling Period ending on September 30, 1994; WHEREAS, the Agent, the Issuing Banks and the Lenders are willing to agree to the consent and waiver contained herein upon the terms and conditions set forth below; NOW, THEREFORE, the parties hereto agree as follows: SECTION 1. Consent and Waiver. The Majority Lenders hereby consent to the waiver of the Company's obligations (i) under Section 5.03(b) of the Credit Agreement to maintain its Consolidated Working Capital Ratio of at least 1.50 to 1.00 to, but excluding, December 31,1994 and (ii) under Section 5.03(d) to the Credit Agreement to cause Tesoro Alaska to maintain the Tesoro Alaska EBITDA of at least $15,000,000 for the Rolling Period ending on September 30, 1994; provided, however, the Company agrees that it will comply in full with such Sections 5.03(b) and (d) of the Credit Agreement on December 31, 1994. SECTION 2. Representations and Warranties. On and as of the date hereof, after giving effect to this Consent and Waiver, the Company represents and warrants the following: (a) all of the representations and warranties in Article IV of the Credit Agreement are true and correct in all material respects as if made on and as of the date of this Consent and Waiver, except to the extent any such representation or warranty relates specifically to an earlier date; (b) no Default or Event of Default has occurred and is continuing, or would result from the effectiveness of this Consent and Waiver; and -1- (c) The execution and delivery by the Company of this Consent and Waiver are within the Company's powers and have been duly authorized by all necessary corporate or other action. SECTION 3. Effect on Credit Agreement. Except to the extent of the consents and waivers specifically set forth herein, all provisions of the Credit Agreement and the other Security Instruments are and shall remain in full force and effect and are hereby ratified and confirmed in all respects, and the execution, delivery and effectiveness of this Consent and Waiver shall not operate as a waiver of any provision of the Credit Agreement or any other Security Instrument not specifically referred to herein. SECTION 4. Execution in Counterparts. This Consent and Waiver may be executed in any number of counterparts, and by the parties hereto in separate counterparts, each of which when so executed shall be deemed to be an original and all of which taken together shall constitute one and the same agreement. SECTION 5. GOVERNING LAW. THIS CONSENT AND WAIVER SHALL BE GOVERNED BY AND CONSTRUED IN ACCORDANCE WITH THE APPLICABLE LAWS OF THE STATE OF TEXAS WITHOUT REFERENCE TO PRINCIPLES OF CONFLICT OF LAWS. SECTlON 6. Previous Agreements. This Consent and Waiver supersedes any and all previous agreements, documents and understandings relating to the consents and waivers set forth herein, to the extent inconsistent herewith. IN WITNESS WHEREOF, the parties hereto have caused this Consent and Waiver to be duly executed and delivered by their respective officers or other duly authorized representatives as of the date first above written. COMPANY: TESORO PETROLEUM CORPORATION By: /s/ William T. Van Kleef Name: William T. Van Kleef Title: Vice President, Treasurer -2- AGENT, ISSUING BANKS AND LENDERS: TEXAS COMMERCE BANK NATIONAL ASSOCIATION, individually, as an Issuing Bank and as Agent By: /s/ P. Stan Burge P. Stan Burge Vice President -3- BANQUE PARIBAS, individually, as an Issuing Bank and as Co-Agent By: /s/ Brian Malone Name: BRIAN MALONE Title: VICE PRESIDENT By: /S/ Patrick J. Milon Name: PATRICK J. MILON Title: SVP-DEPUTY GENERAL MANAGER -4- BANK OF SCOTLAND By: /s/ Elizabeth Wilson Name: ELIZABETH WILSON Title: VICE PRESIDENT AND BRANCH MANAGER -5- CHRISTIANIA BANK By: /s/ Peter M. Dodge Name: PETER M. DODGE Title: VICE PRESIDENT By: /s/ Jahn O. Roising Name: JAHN O. ROISING Title: FIRST VICE PRESIDENT -6- THE BANK OF NOVA SCOTIA By: /s/ F. C. H. Ashby Name: F. C. H. Ashby Title: Senior Manager Loan Operations -7- NBD BANK, N.A. By: /s/ Russell H. Liebetrau, Jr. Name: Russell H. Liebetrau, Jr. Title: Vice President -8- BANK OF AMERICA ILLINOIS By: /s/ Ronald E. McKaig Name: Ronald E. McKaig Title: Vice President -9- FIRST UNION NATIONAL BANK OF NORTH CAROLINA By: FIRST UNION CORPORATION OF NORTH CAROLINA, as agent By: /s/ Paul N. Riddle Name: Mr. Paul N. Riddle Title: Vice President -10- NATIONAL BANK OF CANADA By: /s/ Larry L. Sears Name: Larry L. Sears Title: Group Vice President By: /s/ Charley Collie Name: Charley Collie Title: Vice President -11- THE FROST NATIONAL BANK By: /s/ Jim Crosby Name: Jim Crosby Title: Senior Vice President -12- EX-11 3 EARNINGS PER SHARE COMPUTATIONS Exhibit 11 TESORO PETROLEUM CORPORATION AND SUBSIDIARIES INFORMATION SUPPORTING EARNINGS (LOSS) PER SHARE COMPUTATIONS (Unaudited) (In thousands, except per share amounts)
Three Months Ended Nine Months Ended September 30, September 30, 1994 1993 1994 1993 PRIMARY EARNINGS (LOSS) PER SHARE COMPUTATION: Earnings (loss) before extraordinary item $ ( 3,263) 1,760 5,169 339 Extraordinary loss on extinguishment of debt - - ( 4,752) - -------- -------- -------- -------- Net earnings (loss) . . . . . . . . . . . ( 3,263) 1,760 417 339 Less dividend requirements on preferred stock - 2,302 2,680 6,906 -------- -------- -------- -------- Net loss applicable to common stock . . $ ( 3,263) ( 542) ( 2,263) ( 6,567) ======== ======== ======== ======== Average outstanding common shares . . . . 24,381 14,070 21,933 14,070 Average outstanding common equivalent shares 630 - 651 - -------- -------- -------- -------- Average outstanding common and common equivalent shares. . . . . . . . . . . 25,011 14,070 22,584 14,070 ======== ======== ======== ======== Primary Earnings (Loss) Per Share: Earnings (loss) before extraordinary item $ ( .13) ( .04) .11 ( .47) Extraordinary loss on extinguishment of debt - - ( .21) - -------- -------- -------- -------- Net loss . . . . . . . . . . . . . . . $ ( .13) ( .04) ( .10) ( .47) ======== ======== ======== ======== FULLY DILUTED EARNINGS (LOSS) PER SHARE COMPUTATION: Net loss applicable to common stock . . . $ ( 3,263) ( 542) ( 2,263) ( 6,567) Add dividend requirements on preferred stock - 2,302 2,680 6,906 -------- -------- -------- -------- Net earnings (loss) applicable to common stock - fully diluted. . . . . . . . . $ ( 3,263) 1,760 417 339 ======== ======== ======== ======== Average outstanding common and common equivalent shares . . . . . . . . . . . 25,011 14,070 22,584 14,070 Shares issuable on conversion of preferred shares - 4,775 1,973 4,775 -------- -------- -------- -------- Fully diluted shares. . . . . . . . . . 25,011 18,845 24,557 18,845 ======== ======== ======== ======== Fully Diluted Loss Per Share - Anti-dilutive $ ( .13) ( .04) ( .10) ( .47) ======== ======== ======== ======== 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.
EX-27 4 FINANCIAL DATA SCHEDULE
5 THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM TESORO PETROLEUM CORPORATION'S FINANCIAL STATEMENTS AS OF AND FOR THE NINE MONTH PERIOD ENDED SEPTEMBER 30, 1994, AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH FINANCIAL STATEMENTS. 1,000 9-MOS DEC-31-1994 SEP-30-1994 30,440 1,974 75,403 1,860 52,871 171,438 452,927 193,748 458,974 89,108 188,228 0 0 4,064 141,309 458,974 651,558 654,858 594,471 594,471 23,888 0 13,989 8,776 3,607 5,169 0 (4,752) 0 417 (.10) (.10) Loss per share is after an extraordinary loss of $4.8 million ($.21 loss per share) on extinguishment of debt.
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