-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, KQFYuf/9eHbypYv+9Y9NdIYRNrYc+dH6q5aTZgos8BriCnOq0dwPRQ7ADUw1gfLs xnqbXKkz+9CEfK94MC9MRw== 0000899243-96-001009.txt : 19960812 0000899243-96-001009.hdr.sgml : 19960812 ACCESSION NUMBER: 0000899243-96-001009 CONFORMED SUBMISSION TYPE: 10-Q PUBLIC DOCUMENT COUNT: 4 CONFORMED PERIOD OF REPORT: 19960630 FILED AS OF DATE: 19960809 SROS: AMEX FILER: COMPANY DATA: COMPANY CONFORMED NAME: PLAINS RESOURCES INC CENTRAL INDEX KEY: 0000350426 STANDARD INDUSTRIAL CLASSIFICATION: WHOLESALE-PETROLEUM & PETROLEUM PRODUCTS (NO BULK STATIONS) [5172] IRS NUMBER: 132898764 STATE OF INCORPORATION: DE FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-Q SEC ACT: 1934 Act SEC FILE NUMBER: 001-10454 FILM NUMBER: 96607186 BUSINESS ADDRESS: STREET 1: 1600 SMITH ST STE 1500 CITY: HOUSTON STATE: TX ZIP: 77002 BUSINESS PHONE: 7136541414 MAIL ADDRESS: STREET 1: 1600 SMITH STREET STREET 2: SUITE 1500 CITY: HOUSTON STATE: TX ZIP: 77002 10-Q 1 FORM 10-Q UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 10-Q /x/ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE QUARTERLY PERIOD ENDED JUNE 30, 1996 / / 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: 0-9808 PLAINS RESOURCES INC. (Exact name of registrant as specified in its charter) DELAWARE 13-2898764 (State or other jurisdiction of (I.R.S. Employer incorporation or organization) Identification No.) 1600 SMITH STREET HOUSTON, TEXAS 77002 (Address of principal executive offices) (Zip Code) (713) 654-1414 (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 ---- ---- 16,278,170 shares of common stock $.10 par value, issued and outstanding at July 31, 1996. Page 1 PLAINS RESOURCES INC. AND SUBSIDIARIES TABLE OF CONTENTS - -------------------------------------------------------------------------------- GENERAL This Quarterly Report on Form 10-Q is filed on behalf of Plains Resources Inc. (the "Company") and the following wholly-owned subsidiaries, which are guarantors ("Subsidiary Guarantors") of $150 million principal amount of 10.25% Senior Subordinated Notes due 2006 (the "10.25% Notes").
State or other jurisdictions of I.R.S. Employer Subsidiary Guarantors incorporation or organization Identification No. - ---------------------------------------- ------------------------------- ------------------ Calumet Florida Inc. Delaware 35-1880416 Plains Illinois Inc. Delaware 76-0487569 Plains Marketing & Transportation Inc. Delaware 76-0339476 Plains Resources International Inc. Delaware 76-0040974 PRI Producing Inc. Delaware 73-1197243 PLX Crude Lines Inc. Delaware 76-0387477 PLX Ingleside Inc. Delaware 76-0493777 Plains Terminal & Transfer Corporation Delaware 76-0376679 Stocker Resources, Inc. California 33-0421175 Stocker Resources, L.P. California 33-0430755
PART I. FINANCIAL INFORMATION
PAGE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS: Condensed Consolidated Balance Sheets: June 30, 1996 and December 31, 1995...........................3 Condensed Consolidated Statements of Operations: For the three and six months ended June 30, 1996 and 1995.....4 Condensed Consolidated Statements of Cash Flows: For the six months ended June 30, 1996 and 1995...............5 Notes to Condensed Consolidated Financial Statements..........6
Separate financial statements of Calumet Florida Inc., Plains Illinois Inc., Plains Marketing & Transportation Inc., Plains Resources International Inc., PRI Producing Inc., PLX Crude Lines Inc., PLX Ingleside Inc., Plains Terminal & Transfer Corporation, Stocker Resources, Inc., and Stocker Resources, L.P., as Subsidiary Guarantors of the 10.25% Notes, have not been included herein because (a) such guarantors are jointly and severally liable for full and unconditional guarantees of the 10.25% Notes and (b) the aggregate earnings of such guarantors and the Company are equivalent, and the aggregate net assets and equity of such guarantors and the Company are substantially equivalent, to the net assets, earnings and equity of the Company on a consolidated basis. MANAGEMENT'S DISCUSSION AND ANALYSIS......................... 9 PART II. OTHER INFORMATION..................................18 Page 2 PLAINS RESOURCES INC. AND SUBSIDIARIES CONDENSED CONSOLIDATED BALANCE SHEETS (in thousands, except share data)
- -------------------------------------------------------------------------------------------------------------------------------- JUNE 30, DECEMBER 31, 1996 1995 ----------- ------------ (unaudited) ASSETS CURRENT ASSETS Cash and cash equivalents $ 5,605 $ 6,129 Accounts receivable and other 71,049 52,383 Inventory 4,385 5,120 --------- --------- Total current assets 81,039 63,632 --------- --------- PROPERTY AND EQUIPMENT Oil and natural gas properties - full cost method: Subject to amortization 346,897 328,712 Not subject to amortization 50,301 48,795 Downstream assets, primarily crude oil terminal and storage facility 34,634 32,788 Other property and equipment 7,527 7,789 --------- --------- 439,359 418,084 Less allowance for depreciation, depletion and amortization (147,285) (137,546) --------- --------- 292,074 280,538 --------- --------- DEFERRED INCOME TAXES, NET 11,000 -- OTHER ASSETS 9,869 7,876 --------- --------- $ 393,982 $ 352,046 ========= ========= LIABILITIES AND STOCKHOLDERS' EQUITY CURRENT LIABILITIES Accounts payable and other current liabilities $ 77,259 $ 56,573 Interest payable 5,253 3,977 Royalties payable and drilling advances 6,431 6,364 Notes payable and other current obligations 521 1,467 --------- --------- Total current liabilities 89,464 68,381 BANK DEBT 65,000 98,000 SUBORDINATED DEBT 149,093 100,000 OTHER LONG-TERM DEBT 4,089 7,089 OTHER LONG-TERM LIABILITIES 1,496 1,547 --------- --------- 309,142 275,017 --------- --------- STOCKHOLDERS' EQUITY Common stock, $.10 par value, 50,000,000 shares authorized; 1,628 1,618 issued and outstanding 16,276,490 at June 30, 1996, and 16,178,670 shares at December 31, 1995 Additional paid-in capital 118,680 118,090 Accumulated deficit (35,468) (42,679) --------- --------- 84,840 77,029 --------- --------- $ 393,982 $ 352,046 ========= =========
See notes to condensed consolidated financial statements. Page 3 PLAINS RESOURCES INC. AND SUBSIDIARIES CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (unaudited) (in thousands, except per share data)
- --------------------------------------------------------------------------------------------------------------------------- THREE MONTHS ENDED SIX MONTHS ENDED JUNE 30, JUNE 30, ------------------- --------------------- 1996 1995 1996 1995 -------- ------- --------- --------- REVENUE Oil and natural gas sales $ 25,115 $15,789 $ 45,772 $ 30,478 Marketing, transportation and storage 130,760 79,392 233,550 158,278 Interest and other income 55 75 121 147 -------- ------- --------- --------- 155,930 95,256 279,443 188,903 -------- ------- --------- --------- EXPENSES Production expenses 9,319 7,148 18,631 13,907 Purchases, transportation and storage 128,258 77,796 229,099 155,184 General and administrative 1,984 1,876 4,042 3,774 Depreciation, depletion and amortization 5,532 4,127 10,421 8,125 Interest expense 4,335 3,395 8,532 6,680 Litigation settlement -- -- 4,000 -- -------- ------- --------- --------- 149,428 94,342 274,725 187,670 -------- ------- --------- --------- Income before income taxes and extraordinary item 6,502 914 4,718 1,233 Income tax expense (benefit) 1,888 -- (9,112) -- -------- ------- --------- --------- INCOME BEFORE EXTRAORDINARY ITEM 4,614 914 13,830 1,233 EXTRAORDINARY ITEM: (Loss) on early extinguishment of debt, net of tax benefit 1,888 -- (6,619) -- -------- ------- --------- --------- NET INCOME $ 6,502 $ 914 $ 7,211 $ 1,233 ======== ======= ========= ========= Net income (loss) per common and common equivalent share: Before extraordinary item $.26 $.06 $.80 $.08 Extraordinary item .11 -- (.38) -- -------- ------- --------- --------- $.37 $.06 $.42 $.08 ======== ======= ========= ========= Weighted average number of common and common equivalent shares 17,573 16,002 17,335 15,737 ======== ======= ========= =========
See notes to condensed consolidated financial statements. Page 4 PLAINS RESOURCES INC. AND SUBSIDIARIES CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (unaudited) (in thousands)
- ---------------------------------------------------------------------------------------------------------------------------------- SIX MONTHS ENDED JUNE 30, ---------------------------- 1996 1995 --------- --------- NET CASH PROVIDED BY OPERATING ACTIVITIES $ 18,287 $ 6,718 --------- --------- CASH FLOWS FROM INVESTING ACTIVITIES Proceeds from the sale of oil and natural gas properties 3,066 1,765 Payment for acquisition, exploration and development costs (22,326) (8,343) Payment for additions to other property and assets (1,188) (695) --------- --------- Net cash used in investing activities (20,448) (7,273) --------- --------- CASH FLOWS FROM FINANCING ACTIVITIES Proceeds from long-term debt 202,223 23,750 Principal payments of long-term debt (189,900) (18,850) Costs incurred to redeem long-term debt (6,468) - Payments of other long-term debt (3,946) (1,505) Other (272) 224 --------- --------- Net cash provided by financing activities 1,637 3,619 --------- --------- Net increase (decrease) in cash and cash equivalents (524) 3,064 Cash and cash equivalents, beginning of period 6,129 1,291 --------- --------- Cash and cash equivalents, end of period $ 5,605 $ 4,355 ========= =========
See notes to condensed consolidated financial statements. Page 5 PLAINS RESOURCES INC. AND SUBSIDIARIES NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS JUNE 30, 1996 (UNAUDITED) NOTE 1 -- ACCOUNTING POLICIES The accompanying unaudited condensed consolidated financial statements have been prepared in accordance with the instructions to interim financial reporting as prescribed by the Securities and Exchange Commission ("SEC"). For further information, refer to the consolidated financial statements and notes thereto included in the Company's Annual Report on Form 10-K for the year ended December 31, 1995, filed with the SEC. All material adjustments consisting only of normal recurring adjustments which, in the opinion of management, were necessary for a fair statement of the results for the interim periods, have been reflected. Certain reclassifications have been made to the prior year statements to conform with the current year presentation. The Company evaluates the capitalized costs of its oil and natural gas properties on an ongoing basis and has utilized the most recently available information to estimate its reserves at June 30, 1996, in order to determine the realizability of such capitalized costs. Future events, including drilling activities, product prices and operating costs, may affect future estimates of such reserves. NOTE 2 -- LONG-TERM DEBT AND EXTRAORDINARY LOSS ON EARLY EXTINGUISHMENT On March 19, 1996, the Company sold $150 million of Senior Subordinated Notes due 2006, Series A, bearing a coupon rate of 10.25% (the "Series A 10.25% Notes"). Such notes were issued pursuant to a Rule 144A private placement at approximately 99.38% to yield 10.35%. The Series A 10.25% Notes are redeemable, at the option of the Company, on or after March 15, 2001 at 105.13%, at decreasing prices thereafter prior to March 15, 2004, and thereafter at 100% plus, in each case, accrued interest to the date of redemption. In addition, prior to March 15, 1999, up to $45 million in principal amount of the Series A 10.25% Notes are redeemable at the option of the Company, in whole or in part, from time to time, at 110.25% of the principal amount thereof, with the Net Proceeds (as defined therein) of any Public Equity Offering (as defined therein). The indenture under which the Series A 10.25% Notes were issued (the "Indenture") contains covenants including, but not limited to, covenants with respect to the following: (i) limitations on incurrence of additional indebtedness; (ii) limitations on certain investments; (iii) limitations on restricted payments; (iv) limitations on disposition of assets; (v) limitations on dividends and other payment restrictions affecting subsidiaries; (vi) limitations on transactions with affiliates; (vii) limitations on liens; and (viii) restrictions on mergers, consolidations and transfers of assets. In the event of a Change of Control and a corresponding Rating Decline, as both are defined in the Indenture, the Company will be required to make an offer to repurchase the Series A 10.25% Notes at 101% of the principal amount thereof, plus accrued and unpaid interest to the date of the repurchase. The Series A 10.25% Notes are unsecured general obligations of the Company and are subordinated in right of payment to all existing and future senior indebtedness of the Company and are guaranteed by all of the Company's principal subsidiaries. Proceeds from the sale of the Series A 10.25% Notes, net of offering costs, were approximately $144.9 million and were used to redeem the Company's 12% Senior Subordinated Notes (the "12% Notes") at 106% of the $100 million principal amount outstanding and to retire bridge bank indebtedness which was Page 6 incurred in December 1995 in connection with the acquisition of certain oil properties. Prior to redemption, the 12% Notes had an average remaining life of three years and scheduled maturities of $50 million in each of 1998 and 1999. On June 26, 1996, the Company commenced an offer to exchange 10.25% Senior Subordinated Notes due 2006, Series B, (the "Series B 10.25% Notes") for all of the outstanding Series A 10.25% Notes. The Series B 10.25% Notes are substantially identical (including principal amount, interest rate, maturity and redemption rights) to the Series A 10.25% Notes for which they may be exchanged, except for certain transfer restrictions and registration rights relating to the Series A 10.25% Notes and except for certain interest provisions relating to such rights. The exchange offer expired on August 8, 1996, with a total principal amount of $149.5 million of the Series A 10.25% Notes being exchanged. On March 19, 1996, the Company called for the redemption of the 12% Notes and deposited $112.6 million with the trustee of the 12% Notes to cover the principal amount called, the call premium of $6 million and $6.6 million for accrued interest through the redemption date. The 12% Notes were redeemed on April 18, 1996, and the Company has recognized an extraordinary loss of $6.6 million, net of deferred tax benefit of $1.9 million, through June 30, 1996 (See Note 4). In April 1996, the Company's revolving credit facility (the "Revolving Credit Facility") and borrowing base thereunder was increased to $125 million from $75 million. The Revolving Credit Facility, as amended, matures on May 1, 1998, at which time the remaining outstanding balance converts to a term loan which is repayable in twenty equal quarterly installments commencing August 1, 1998. The Revolving Credit Facility bears interest, at the option of the Company, at either LIBOR plus 1.75% or Base Rate (as defined therein) plus .375%. Final maturity of the Revolving Credit Facility occurs on May 1, 2003. The Revolving Credit Facility is guaranteed by all of the Company's principal subsidiaries and is secured by the oil and gas properties of the Company and its subsidiaries and the stock and personal property of all subsidiary guarantors. At June 30, 1996, the Company had $65 million in borrowings and a $1 million standby letter of credit outstanding under the Revolving Credit Facility. NOTE 3 -- LITIGATION SETTLEMENT The Company and certain of its officers and directors and a former director and officer were named in two class action lawsuits filed in 1992 and 1993 seeking an aggregate of approximately $90 million in compensatory damages and punitive damages in an unspecified amount for alleged violations of the federal securities laws and state common law arising out of certain alleged misrepresentations and omissions in the Company's disclosure regarding its onshore natural gas exploration activities. On March 6, 1996, the Company announced that it had notified the court that a settlement in principle had been reached in such cases. Under the terms of the settlement, the plaintiffs agreed to dismiss all claims against the Company and its officers and directors in exchange for a cash payment of approximately $6.25 million. Approximately $4.1 million of such amount is expected to be paid by the Company's insurance carrier, leaving approximately $2.1 million to be contributed by the Company. Taking into account prior costs incurred by the Company to defend these suits, this settlement resulted in a charge to 1996 first quarter earnings of $4 million. The settlement is subject to the approval of the court. A hearing has been set for September 25, 1996, for the court to determine whether the settlement agreement should be approved. If the settlement is not consummated and if the Company ultimately were required to pay a substantial portion of the $90 million in compensatory damages sought by the plaintiffs, it would have a material adverse effect on the Company. Page 7 NOTE 4 -- INCOME TAXES During the first quarter of 1996, the Company reversed $11 million of the $18.3 million valuation allowance which was reserved against its net deferred tax asset of $18.3 million. Accordingly, a credit to deferred income tax expense of $11 million was reflected in the first quarter of 1996. As of June 30, 1996, the valuation allowance was approximately $7.3 million. The reversal of the valuation allowance was due to management's belief that the benefits derived from the net deferred tax asset will be realized prior to their expiration. This assessment is based on the cumulative progress made by the Company over the last three years to reduce unit expenses, increase gross margins and substantially increase its production and proved reserves through its acquisition and exploitation activities. This assessment was further confirmed during the first quarter of 1996 with the sale of the Series A 10.25% Notes, which enhanced the Company's financial flexibility and provided additional liquidity, achievement of substantial expense reductions on a significant property acquired late in the fourth quarter of 1995 and results of drilling and exploitation activities. Management believes that its current oil and natural gas properties and its downstream marketing and crude oil storage and terminalling activities provide lower risk opportunities to generate taxable income which can be offset by the tax net operating loss carryforwards which comprise a significant portion of the net deferred tax asset. Despite the significant turnaround achieved over the last four years and the current outlook for profitability, due to the uncertainties in the oil and gas industry, including but not limited to forecasting production, proved reserves, product prices, production expenses and similar events beyond management's control, there can be no assurance that the Company will generate any earnings or specific level of continuing earnings. During the second quarter of 1996, the Company recognized a deferred tax provision of $1.9 million and an offsetting $1.9 million deferred tax benefit reported as an extraordinary item. Such deferred tax benefit is attributable to the first quarter extraordinary loss from the redemption of the 12% Notes (See Note 2). NOTE 5 -- EARNINGS PER SHARE Earnings per share is based on the weighted average number of common and common equivalent shares of Common Stock outstanding. Common equivalent shares include employee stock options and warrants. Page 8 MANAGEMENT'S DISCUSSION AND ANALYSIS RESULTS OF OPERATIONS Three month periods ended June 30, 1996 and 1995 For the quarter ended June 30, 1996, the Company reported net income before extraordinary items of $4.6 million, or $.26 per share, on total revenue of $155.9 million. This compares with net income of $914,000, or $.06 per share, on total revenue of $95.3 million for the second quarter of 1995. Net income after extraordinary items was $6.5 million, or $.37 per share. Cash flow from operations (net income plus noncash expenses) more than doubled, increasing 139% to $12.0 million as compared to $5.0 million in the second quarter of 1995. Earnings before interest, taxes, depreciation, depletion and amortization ("EBITDA") increased 94% to $16.4 million as compared to $8.4 million in the 1995 comparative quarter. The improvement in operating results is primarily attributable to increased oil production and expanded unit operating margins in the upstream segment and continued growth in the downstream segment. The following table sets forth certain operating information of the Company for the periods presented:
THREE MONTHS ENDED JUNE 30, ---------------------------------- 1996 1995 ---------------- ---------------- (in thousands, except per unit data) (unaudited) AVERAGE DAILY PRODUCTION VOLUMES BARRELS OF OIL EQUIVALENT ("BOE") LA Basin (91% oil)................... 9.2 8.5 S. Florida (100% oil)................ 5.2 3.5 Illinois Basin (100% oil)............ 3.4 -- Sold properties...................... -- .9 ------ ------ Total (95% oil)...................... 17.8 12.9 ====== ====== AVERAGE SALES PRICE Per barrel of oil.................... $16.01 $14.31 ====== ====== Per mcf of natural gas............... $ .74 $ 1.02 ====== ====== UNIT ECONOMICS Average sales price per BOE.......... $15.47 $13.44 Production expenses per BOE.......... 5.74 6.09 ------ ------ Gross margin per BOE................. 9.73 7.35 Upstream G&A expenses per BOE........ .79 1.10 ------ ------ Gross profit per BOE................. $ 8.94 $ 6.25 ====== ======
Oil and natural gas production for the second quarter of 1996 increased 38% to 1.62 million BOE, as compared to the 1.18 million BOE produced in last year's comparative quarter. The Company's unit gross margin increased to $9.73 per BOE, a 32% improvement over the $7.35 per BOE recorded in last year's second quarter. Unit gross profit, which deducts all pre-interest cash costs attributable to the upstream segment, was $8.94 per BOE, up 43% over 1995's second quarter amount of $6.25 per BOE. Page 9 The significant increase in production volumes is attributable to the Company's acquisition and exploitation activities. As a result of exploitation activities conducted in the first half of 1996, average net daily production from the Company's LA Basin properties increased to approximately 9,200 BOE per day, up 700 BOE per day, or 8% over last year's comparative quarter. Net production from the Company's South Florida Sunniland Trend properties increased approximately 50% to average 5,200 barrels of oil per day in the second quarter of 1996 as compared to 3,500 barrels per day in last year's second quarter. The current quarter average incorporates the impact of production from the Company's recent development well drilled at the Raccoon Point Field. This well was completed and placed on line in late March. Daily gross production from this well during the second quarter averaged around 3,100 barrels of oil and 300 barrels of water per day. The Company owns a 100% working interest and an 84% net revenue interest in this well. The quarter to quarter comparisons of production volumes and unit margins were affected by sales of nonstrategic properties in 1995 and 1996 and the acquisition of the Company's Illinois Basin properties in December 1995. Production attributable to properties sold totaled 87,000 BOE or an average of 956 BOE per day during the 1995 second quarter. Net production from the Illinois Basin properties totaled 314,000 barrels of oil or an average of 3,400 barrels of oil per day during the second quarter of 1996. The Illinois Basin properties have higher unit production expenses and also receive higher oil price realizations against the benchmark NYMEX index price than the Company's other properties. Oil and natural gas revenues increased 59% to $25.1 million for the second quarter of 1996 due to increased production volumes and higher average product prices. The Company's average product price, which represents a combination of fixed and floating price sales arrangements and incorporates location and quality discounts from the benchmark NYMEX prices, increased 15% to $15.47 per BOE. The increased product price is primarily attributable to the higher quality Illinois Basin production, a reduction in the quality and location differential for the South Florida Sunniland Trend production, the December 1995 purchase of a production payment which previously burdened the price on the Company's LA Basin production, and the impact on the Company's unhedged production of increased crude oil prices. During the current year quarter, the NYMEX benchmark price averaged $21.57 per barrel, up 12% as compared to an average of $19.32 per barrel in the correlative period of 1995. This price increase had an approximate $1.4 million impact on the Company's net income and cash flow in the 1996 second quarter. Approximately 58% of the Company's oil production was hedged during the 1996 second quarter. Financial swap arrangements and futures transactions entered into by the Company to hedge production are included in the foregoing product prices. Such transactions (which do not include fixed price, physical delivery arrangements) had the effect of decreasing the Company's average price per BOE by $2.12 and $.42 in the second quarter of 1996 and 1995, respectively. The Company's downstream segment reported a gross margin (marketing, transportation and storage revenues less purchases, transportation and storage expenses) of $2.5 million for the second quarter of 1996, reflecting an approximate 57% increase over the $1.6 million reported for the 1995 quarter. Gross revenues were $130.8 million and $79.4 million for the respective periods. Such results are directly attributable to the continued expansion of the downstream segment's base level activities and strong market demand for crude oil during the second quarter of 1996. Approximately $300,000 of the current year gross margin is attributable to the strong market demand for crude oil in the second quarter of 1996. Total average daily crude oil volumes marketed and terminalled during the 1996 second quarter were 59,000 barrels and 51,000 barrels, respectively. Such amounts represent respective increases of 37% and 31% as compared with average daily volumes of 43,000 barrels and 39,000 barrels in last year's second quarter. As a result of the relatively fixed portion of this segment's overhead and operating infrastructure, gross profit (gross margin less downstream general and administrative ("G&A") expenses) increased 75% to $1.8 million versus $1.0 million in last year's second quarter. Page 10 Aggregate unit production expenses declined 6% to $5.74 per BOE versus $6.09 per BOE in the second quarter of 1995. Unit production expenses were $6.56 per BOE in the first quarter of 1996. The reduction in average unit production expenses is attributable to increased production from fields with a high component of fixed production costs which do not increase with incremental production and reimbursements received in the second quarter of 1996 for electricity overcharges in the previous year. Excluding the electricity reimbursement, unit production expenses were $5.88 per BOE, or 3% below 1995's second quarter level. Total production expenses increased to $9.3 million from $7.1 million for the second quarter of 1995 primarily due to the acquisition of the Illinois Basin properties. Unit production expenses for the LA Basin properties were $5.90 per BOE for the second quarter of 1996, or 6% lower than last year's comparative quarter partially due to the electricity reimbursement previously discussed. Excluding this adjustment, unit production expenses were $6.18 per BOE, a 2% reduction compared to last year. Unit production expenses for the South Florida Sunniland Trend properties averaged $3.63 per BOE, approximately 32% lower than the 1995 second quarter average of $5.30 per BOE. This reduction is primarily attributable to increased production from fields with a high component of fixed production costs which do not increase with incremental production. The decrease in unit production expenses in these areas was offset to some extent by the addition of the higher cost Illinois Basin production. Unit production expenses for these properties, which averaged $12.00 per barrel in the fourth quarter of 1995, averaged approximately $8.50 per barrel during the first and second quarters of 1996. The significant reduction in production expenses for the Illinois Basin properties is a result of operational modifications implemented in late 1995 and throughout the first half of 1996. The Company extended its three year trend of reducing unit G&A expenses as unit upstream G&A expenses decreased 28% to $.79 per BOE as compared to $1.10 per BOE in last year's comparative quarter. Total G&A expenses, including downstream activities, were $2.0 million for the three months ended June 30, 1996, compared to $1.9 million for the 1995 period. The increase is primarily attributable to increased expenses associated with the Company's downstream activities. Depreciation, depletion and amortization ("DD&A") expense increased to $5.5 million from $4.1 million reported in the second quarter of 1995 due primarily to higher production volumes. The Company's DD&A rate was $3.00 per BOE in both quarters. Interest expense for the quarter ended June 30, 1996, increased to $4.3 million from $3.4 million for the comparative prior year quarter primarily due to higher outstanding debt levels which were partially offset by a lower overall average interest rate. Capitalized interest was $.9 million and $.8 million for the three months ended June 30, 1996 and 1995, respectively. During the second quarter, the Company recognized a deferred tax provision of $1.9 million and an offsetting $1.9 million deferred tax benefit reported as an extraordinary item. Such deferred tax benefit is attributable to the first quarter extraordinary loss from the early redemption of the Company's $100 million of 12% Senior Subordinated Notes (the "12% Notes"). Six month periods ended June 30, 1996 and 1995 For the six months ended June 30, 1996, the Company reported net income before nonrecurring items of $6.8 million, or $.39 per share, on total revenue of $279.4 million. This compares with net income of $1.2 million, or $.08 per share, on total revenue of $188.9 million for the first half of 1995. Cash flow from operations (net income plus noncash expenses) was $19.1 million, more than double the $9.4 million reported in the 1995 period. EBITDA increased 73% to $27.7 million as compared to $16.0 million in the first six months of 1995. Such amounts are also presented before the effects of the nonrecurring items. Net cash provided by operating activities, as reported in the consolidated statements of cash flows, Page 11 increased to $18.3 million for the six months ended June 30, 1996, as compared to $6.7 million for the 1995 comparative period. The improvement in operating results is primarily attributable to increased oil production and expanded unit operating margins in the upstream segment and continued growth in the downstream segment. Nonrecurring items include a $6.6 million extraordinary loss associated with the early redemption of the 12% Notes, a $4.0 million charge related to the settlement of a four year old lawsuit and an $11.0 million tax benefit related to the reversal of a portion of the valuation reserve against the Company's deferred tax asset. Such items resulted in an aggregate increase to net income of $400,000 or $.02 per share. After giving effect to such nonrecurring items, the Company reported net income for the first six months of 1996 of $7.2 million, or $.42 per share. Before extraordinary items, net income was $13.8 million or $.80 per share. The following table sets forth certain operating information of the Company for the periods presented:
SIX MONTHS ENDED JUNE 30, ---------------------------------- 1996 1995 ---------------- ---------------- (in thousands, except per unit data) (unaudited) AVERAGE DAILY PRODUCTION VOLUMES BARRELS OF OIL EQUIVALENT LA Basin (91% oil).............. 9.0 8.3 S. Florida (100% oil)........... 4.2 3.5 Illinois Basin (100% oil)....... 3.4 -- Sold properties................. .1 1.0 ------ ------ Total (95% oil)................. 16.7 12.8 ====== ====== AVERAGE SALES PRICE Per barrel of oil............... $15.65 $13.97 ====== ====== Per mcf of natural gas.......... $ .77 $ 1.05 ====== ====== UNIT ECONOMICS Average sales price per BOE..... $15.04 $13.14 Production expenses per BOE..... 6.12 5.99 ------ ------ Gross margin per BOE............ 8.92 7.15 Upstream G&A expenses per BOE... .85 1.10 ------ ------ Gross profit per BOE............ $ 8.07 $ 6.05 ====== ======
Oil and natural gas production for the first six months of 1996 increased 31% to 3.0 million BOE versus the 2.3 million BOE produced in the 1995 comparative period. The Company's unit gross margin increased to $8.92 per BOE, a 25% improvement over the $7.15 per BOE recorded in last year's first half. Unit gross profit, which deducts all pre-interest cash costs attributable to the upstream segment, was $8.07 per BOE, up 33% over 1995's first half average of $6.05 per BOE. The significant increase in production volumes is attributable to the Company's acquisition and exploitation activities. As a result of exploitation activities conducted in the first half of 1996, average net daily production from the Company's LA Basin properties for the first half of 1996 increased to approximately 9,000 BOE per day, up 700 BOE per day, or 8% over last year's comparative period. Net production Page 12 from the Company's South Florida Sunniland Trend properties increased approximately 20% to average 4,200 barrels of oil per day in the first half of 1996 as compared to 3,500 barrels per day in last year's comparative period. The current year South Florida Sunniland Trend average incorporates the impact of production from the Company's recent development well drilled at the Raccoon Point Field. This well was completed and placed on line in late March. Daily gross production from this well during the second quarter averaged around 3,100 barrels of oil and 300 barrels of water per day. The Company owns a 100% working interest and an 84% net revenue interest in this well. The period to period comparisons of production volumes and unit margins were affected by sales of nonstrategic properties in 1995 and 1996 and the acquisition of the Company's Illinois Basin properties in December 1995. Production attributable to properties sold totaled 179,000 BOE or an average of 983 BOE per day during the first half of 1995. Net production from the Illinois Basin properties totaled 632,000 barrels of oil or an average of 3,400 barrels of oil per day during the first six months of 1996. Oil and natural gas revenues increased 50% to $45.8 million for the first six months of 1996 due to increased production volumes and higher average product prices. The Company's average product price, which represents a combination of fixed and floating price sales arrangements and incorporates location and quality discounts from the benchmark NYMEX prices, increased 14% to $15.04 per BOE. The increased product price is primarily attributable to the higher quality Illinois Basin production, a reduction in the quality and location differential for the South Florida Sunniland Trend production, the December 1995 purchase of a production payment which previously burdened the price on the Company's LA Basin production, and the impact on the Company's unhedged production of increased crude oil prices. During the current year, the NYMEX benchmark price averaged $20.56 per barrel, up 9% as compared to an average of $18.84 in the correlative period of 1995. This price increase had an approximate $1.6 million impact on the Company's net income and cash flow for the six months ended June 30, 1996. Approximately 66% of the Company's oil production was hedged during the first half of 1996. Financial swap arrangements and futures transactions entered into by the Company to hedge production are included in the foregoing product prices. Such transactions (which do not include fixed price, physical delivery arrangements) had the effect of decreasing the average price per BOE by $1.82 and $.43 in the first half of 1996 and 1995, respectively. The Company's downstream segment reported a gross margin (marketing, transportation and storage revenues less purchases, transportation and storage expenses) of $4.5 million for the first half of 1996, reflecting an approximate 44% increase over the $3.1 million reported for the 1995 period. Gross revenues were $233.6 million and $158.3 million for the respective periods. Such results are directly attributable to continued expansion of the downstream segment's base level activities and strong market demand for crude oil during the second quarter of 1996. Approximately $300,000 of the current year gross margin is attributable to the strong market demand for crude oil in the second quarter of 1996. Total average daily crude oil volumes marketed and terminalled during the 1996 first half were 56,000 barrels and 55,000 barrels, respectively. Such amounts represent respective increases of 24% and 41% as compared with average daily volumes of 45,000 barrels and 39,000 barrels in last year's first half. As a result of the relatively fixed portion of this segment's overhead and operating infrastructure, gross profit (gross margin less downstream G&A expenses) increased 59%, totaling $3.0 million versus $1.9 million in first six months of last year. Primarily as a result of the higher cost Illinois Basin production, unit production expenses in the first half of 1996 increased approximately 2% to $6.12 per BOE. Unit production expenses for the Illinois Basin properties, which averaged $12.00 per barrel in the fourth quarter of 1995, averaged approximately $8.50 per barrel for the six month period. The significant reduction in production expenses for the Illinois Basin Page 13 properties is a result of operational modifications implemented in late 1995 and throughout the first half of 1996. The increase in unit production expenses attributable to the Illinois Basin properties was partially offset by decreases in unit production expenses in the Company's other core areas. Unit production expenses for the LA Basin properties were $6.22 per BOE for the first six months of 1996, or 3% lower than last year's comparative period primarily due to expense reimbursements received in the second quarter of 1996 for electricity overcharges in the previous year. Unit production expenses for the South Florida Sunniland Trend properties averaged $4.02 per BOE, approximately 21% lower than the 1995 first half average of $5.06 per BOE. This reduction is primarily attributable to increased production from fields with a high component of fixed production costs which do not increase with incremental production. Total production expenses increased to $18.6 million from $13.9 million for the first half of 1995 primarily due to the acquisition of the Illinois Basin properties. The Company extended its three year trend of reducing unit G&A expenses as unit upstream G&A expenses decreased 23% to $.85 per BOE as compared to $1.10 per BOE in last year's first half. Total G&A expenses, including downstream activities, were $4.0 million for the six months ended June 30, 1996, compared to $3.8 million for the 1995 period. The increase is primarily attributable to increased expenses associated with the Company's downstream activities. DD&A expense increased to $10.4 million from $8.1 million reported in the first half of 1995 due primarily to higher production volumes. The Company's DD&A rate was $3.00 per BOE in both periods. Interest expense for the six months ended June 30, 1996, increased to $8.5 million from $6.7 million reported for the comparative prior year period primarily due to higher outstanding debt levels which were partially offset by a lower overall average interest rate. Capitalized interest was $1.8 million and $1.5 million for the six months ended June 30, 1996 and 1995, respectively. The Company and certain of its officers and directors and a former director and officer were named in two class action lawsuits filed in 1992 and 1993 seeking an aggregate of approximately $90 million in compensatory damages and punitive damages in an unspecified amount for alleged violations of the federal securities laws and state common law arising out of certain alleged misrepresentations and omissions in the Company's disclosure regarding its onshore natural gas exploration activities. On March 6, 1996, the Company announced that it had notified the court that a settlement in principle had been reached in such cases. Under the terms of the settlement, the plaintiffs agreed to dismiss all claims against the Company and its officers and directors in exchange for a cash payment of approximately $6.25 million. Approximately $4.1 million of such amount is expected to be paid by the Company's insurance carrier, leaving approximately $2.1 million to be contributed by the Company. Taking into account prior costs incurred by the Company to defend these suits, this settlement resulted in a charge to 1996 first quarter earnings of $4 million. The settlement is subject to the approval of the Court. A hearing has been set for September 25, 1996, for the Court to determine whether the settlement agreement should be approved. Effective in 1992, Financial Accounting Standard 109 ("FAS 109") required companies to record an asset or a liability, as appropriate for the net tax position of each company as a result of temporary differences between financial reporting standards and tax reporting requirements. However, FAS 109 also required companies with deferred tax assets to provide a valuation allowance for the portion of the deferred tax asset that management concluded was more likely than not to expire before the company would generate sufficient income to realize such tax asset. The Company adopted FAS 109 in 1992 and at such time recorded a net tax asset of approximately $20.8 million, but also recorded a valuation reserve against the full amount of such asset to reflect management's uncertainty, based on all information then available, with respect to the realization of such asset. Page 14 At December 31, 1995, the Company had a net deferred tax asset of approximately $18.3 million. While such amount was fully reserved, management was reassessing the Company's ability to realize a portion of such asset in light of recent and anticipated improvement in the Company's outlook for sustained profitability. In the first quarter of 1996, the Company reduced its valuation allowance resulting in the recognition of an $11 million credit to deferred income tax expense. Management believes that it is more likely than not that it will generate taxable income sufficient to realize the $11 million of unreserved tax benefits associated with certain of the Company's net operating loss ("NOL") carryforwards prior to their expiration. The reserve adjustment incorporates management's assessment of the significant, cumulative progress made by the Company over the last three years to reduce unit expenses, increase unit gross margins and substantially increase its production and proved reserves through its acquisition and exploitation activities. From 1992 to 1995, unit G&A expenses declined 60%, unit gross profit increased 26% and production and proved reserves increased 84% and 154%, respectively. Such reassessment is also reinforced by first quarter 1996 events which include refinancing of long-term debt, achievement of substantial expense reductions on the Illinois Basin properties and results of drilling and other exploitation activities in the Company's other core areas. The remaining $7.3 million of deferred tax asset was not recognized due to limitations imposed by the IRS regarding the utilization of NOLs generated prior to certain of the Company's subsidiaries being acquired and the uncertainty of utilizing the Company's investment tax credit ("ITC") carryforwards. While the Company's tax planning strategies address certain of these restrictions on the application of subsidiary NOLs, management is currently uncertain as to the extent such strategies will be successful and therefor concluded that a reserve for these amounts was appropriate. Estimates of future taxable income generated using future net cash flows contained in reserve reports prepared by independent consulting firms in accordance with regulations prescribed by the Securities and Exchange Commission (the "SEC") also indicate that the unreserved portion of such deferred tax assets will be realized. Such reserve data was utilized in calculating the standardized measure of discounted future net cash flows (the "Standardized Measure") presented in the Company's year-end financial statements. See Form 10- K, Item 2, "Properties--Oil and Natural Gas Reserves". Despite the significant turnaround achieved over the last three years and the current outlook for profitability, due to the uncertainties in the oil and gas industry, including but not limited to forecasting production, proved reserves, product prices, production expenses and similar events beyond management's control, there can be no assurance that the Company will generate any earnings or specific level of continuing earnings. The Company had carryforwards of approximately $164.1 million of regular tax NOLs at December 31, 1995, which expire as follows: 1996 - $7.2 million; 1997 - $3.6 million; 1998 - $5.1 million; 1999 - $7.1 million; 2000 - $7.9 million; 2001 - $4.4 million; 2002 - $11.8 million; 2003 - $9.4 million; 2004 - $0; 2005 - - $7.2 million; and thereafter through 2010 - $100.4 million. During the second quarter, the Company recognized a deferred tax provision of $1.9 million and an offsetting $1.9 million deferred tax benefit reported as an extraordinary item. Such deferred tax benefit is attributable to the first quarter extraordinary loss from the early redemption of the Company's 12% Notes. In April 1996, the Company redeemed the 12% Notes and in connection therewith, the Company has recognized an extraordinary loss of $6.6 million, net of deferred tax benefit, through June 30, 1996. Page 15 CAPITAL RESOURCES, LIQUIDITY AND FINANCIAL CONDITION On March 19, 1996, the Company sold $150 million of Senior Subordinated Notes due 2006, Series A, bearing a coupon rate of 10.25% (the "Series A 10.25% Notes"). Such notes were issued pursuant to a Rule 144A private placement at approximately 99.38% to yield 10.35%. The Series A 10.25% Notes are redeemable, at the option of the Company, on or after March 15, 2001 at 105.13%, at decreasing prices thereafter prior to March 15, 2004, and thereafter at 100% plus, in each case, accrued interest to the date of redemption. In addition, prior to March 15, 1999, up to $45 million in principal amount of the Series A 10.25% Notes are redeemable at the option of the Company, in whole or in part, from time to time, at 110.25% of the principal amount thereof, with the Net Proceeds (as defined therein) of any Public Equity Offering (as defined therein). The indenture under which the Series A 10.25% Notes were issued (the "Indenture") contains covenants including, but not limited to, covenants with respect to the following: (i) limitations on incurrence of additional indebtedness; (ii) limitations on certain investments; (iii) limitations on restricted payments; (iv) limitations on disposition of assets; (v) limitations on dividends and other payment restrictions affecting subsidiaries; (vi) limitations on transactions with affiliates; (vii) limitations on liens; and (viii) restrictions on mergers, consolidations and transfers of assets. In the event of a Change of Control and a corresponding Rating Decline, as both are defined in the Indenture, the Company will be required to make an offer to repurchase the Series A 10.25% Notes at 101% of the principal amount thereof, plus accrued and unpaid interest to the date of the repurchase. The Series A 10.25% Notes are unsecured general obligations of the Company and are subordinated in right of payment to all existing and future senior indebtedness of the Company and are guaranteed by all of the Company's principal subsidiaries. Proceeds from the sale of the Series A 10.25% Notes, net of offering costs, were approximately $144.9 million and were used to redeem the 12% Notes at 106% of the $100 million principal amount outstanding and, together with amounts borrowed under the Company's revolving credit facility (the "Revolving Credit Facility"), to retire the Illinois Basin acquisition bridge indebtedness. Prior to redemption, the 12% Notes had an average remaining life of three years and scheduled maturities of $50 million in each of 1998 and 1999. On June 26, 1996, the Company commenced an offer to exchange 10.25% Senior Subordinated Notes due 2006, Series B, (the "Series B 10.25% Notes") for all of the outstanding Series A 10.25% Notes. The Series B 10.25% Notes are substantially identical (including principal amount, interest rate, maturity and redemption rights) to the Series A 10.25% Notes for which they may be exchanged, except for certain transfer restrictions and registration rights relating to the Series A 10.25% Notes and except for certain interest provisions relating to such rights. The exchange offer expired on August 8, 1996, with a total principal amount of $149.5 million of the Series A 10.25% Notes being exchanged. In April 1996, the Revolving Credit Facility and borrowing base thereunder was increased to $125 million from $75 million. The Revolving Credit Facility, as amended, matures on May 1, 1998, at which time the remaining outstanding balance converts to a term loan which is repayable in twenty equal quarterly installments commencing August 1, 1998. The Revolving Credit Facility bears interest, at the option of the Company, at either LIBOR plus 1.75% or Base Rate (as defined therein) plus .375%. Final maturity of the Revolving Credit Facility occurs on May 1, 2003. The Revolving Credit Facility is guaranteed by all of the Company's principal subsidiaries and is secured by the oil and gas properties of the Company and its subsidiaries and the stock and personal property of all subsidiary guarantors. At June 30, 1996, the Company had $65 million in borrowings and a $1 million standby letter of credit outstanding under the Revolving Credit Facility. Page 16 At June 30, 1996, the Company had a working capital deficit of approximately $8.4 million compared to a deficit of $4.7 million at December 31, 1995. The Company has historically operated with a working capital deficit due primarily to ongoing capital expenditures that have been financed through cash flow and the Revolving Credit Facility. Investing and Financing Activities Net cash flows used in investing activities were $20.4 million and $7.3 million for the six months ended June 30, 1996 and 1995, respectively. Investing activities include payments for acquisition, exploration and development costs of $22.3 million and $8.3 million for these same periods, respectively. Also included in investing activities are proceeds from the sale of certain nonstrategic properties of $3.1 million and $1.8 million for the six months ended June 30, 1996 and 1995, respectively. Net cash provided by financing activities amounted to $1.6 million and $3.6 million for the six months ended June 30, 1996 and 1995, respectively. Financing activities during 1996 include net proceeds of approximately $144.9 million from the Series A 10.25% Notes, approximately $107 million for the repayment of the 12% Notes, including the 6% call premium and the net defeasance costs, and approximately $42 million for the repayment of the Illinois Basin acquisition bridge indebtedness. Included in both years are proceeds and payments under the Revolving Credit Facility as a result of acquisition, exploration and development activities. Changing Oil and Natural Gas Prices The Company is heavily dependent on crude oil prices which have historically been volatile. Although the Company has routinely hedged a substantial portion of its crude oil production and intends to continue this practice, future crude oil price declines would have a negative impact on the Company's overall results, and therefore its liquidity. Furthermore, low crude oil prices could affect the Company's ability to raise capital on terms favorable to the Company. For the second half of 1996, the Company has committed an average of approximately 12,500 barrels of oil per day, or approximately 70% of 1996 second quarter average daily production, to fixed price arrangements at a NYMEX index price (before location and quality discounts) of approximately $18 per barrel. The Company has also established hedges on approximately 11,000 barrels per day for the first quarter of 1997 at approximately $18.50 per barrel, and an average of approximately 5,000 barrels per day at approximately $18.00 per barrel through the remainder of 1997. Such arrangements partially mitigate the adverse impact of potential oil price declines on the Company's operating results. Page 17 PART II. OTHER INFORMATION Item 1 - Legal Proceedings The information set forth in "Note 3 -- Litigation Settlement" to the Company's financial statements included in "Part I of this report and in "Part II, Item 1 - Legal Proceedings" of the Company's Form 10-Q for the quarterly period ended March 31, 1996, is incorporated herein by reference. The Company and certain of its officers and directors and a former director and officer were named as defendants in two class action lawsuits filed in the United States District Court for the Southern District of Texas captioned Judith Rubinstein, et al v. Collins, et al (C.A. No. 92-1297) and Gloria Moroson, v. Collins, et al (C.A. No. H-93-2305). As previously reported, a Stipulation of Settlement has been filed with the Court in these cases. A hearing has been set for September 25, 1996, for the court to determine whether the settlement agreement set forth in the Stipulation of Settlement should be approved. As previously reported, Calumet Florida, Inc., a wholly-owned subsidiary of the Company, is a party to a lawsuit in the United States District Court for the Middle District of Florida styled Exxon Corporation v. E.W. Adams, et al., Case Number 87-976-CIV-T-23-B. The Company has reached an agreement in principle with all parties to settle this case. In consideration for full and final settlement, and dismissal with prejudice of all issues in this case, the Company has agreed to pay to the defendants the total sum of $100,000, and release certain royalty amounts held in suspense and in the court registry during the pendency of this case. The parties have agreed to use their best efforts to draft and execute by August 24, 1996, the definitive settlement documents required to finalize this settlement. Item 2 - Material Modification of Rights of Registrant's Securities None Item 3 - Defaults on Senior Securities None Item 4 - Submission of Matters to a Vote of Security Holders The 1996 Annual Meeting of Stockholders (the "Meeting") of the Company was held on May 23, 1996. At the Meeting, holders of common stock, $.10 par value, of the Company ("Common Stock"), elected eight members of the Company's Board of Directors and approved the Company's 1996 Stock Incentive Plan. No other matters were voted on at the Meeting. Out of the 16,183,320 shares of Common Stock entitled to vote at the Meeting, there were 13,670,523 shares of Common Stock represented at the Meeting either by proxies solicited in accordance with Schedule 14A or by security holders voting in person. The tabulation of votes for each director nominee is as follows:
NOMINEES FOR ELECTION TO THE COMPANY'S BOARD OF DIRECTORS Votes "For" Withheld ----------- -------- Greg L. Armstrong 13,646,882 23,641 Robert A. Bezuch 13,646,847 23,676 Tom H. Delimitros 13,646,847 23,676 William H. Hitchcock 13,646,987 23,536 Dan M. Krausse 13,646,484 24,039 John H. Lollar 13,646,832 23,691 Robert V. Sinnott 13,647,047 23,476 J. Taft Symonds 13,647,087 23,436
Page 18 With respect to the 1996 Stock Incentive Plan, 7,608,658 votes were cast in favor of the plan, 2,493,491 votes were cast against the plan, 29,547 shares abstained from voting and there were 3,538,827 broker non-votes. Item 5 - Other Information None Item 6 - A. Exhibits 11(a) Computation of per share earnings for the three months ended June 30, 1996 and 1995 11(b) Computation of per share earnings for the six months ended June 30, 1996 and 1995 27. Financial Data Schedule B. Report on Form 8-K None Page 19 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 and thereunto duly authorized. PLAINS RESOURCES INC. Date: August 9, 1996 By: /s/ Cynthia A. Feeback ------------------------- Cynthia A. Feeback, Controller and Principal Accounting Officer (Principal Accounting Officer) Page 20 EX-11.A 2 COMPUTATION OF PER SHARE EARNINGS - 3 MONTHS EXHIBIT 11a. - Computation of Per Share Earnings (in thousands except per share data) (unaudited) - --------------------------------------------------------------------------------
THREE MONTHS ENDED JUNE 30, -------------------------------------------- 1996 1995 -------------------------------------------- Common and Common and Common Common Equivalent Full Equivalent Full Shares Dilution Shares Dilution ---------- -------- ----------- --------- Weighted average common shares outstanding 16,233 16,233 13,078 13,078 Incremental shares assumed to be issued 1,340 1,469 2,924 2,924 ------- ------- ------- ------- Total shares outstanding for calculation 17,573 17,702 16,002 16,002 ======= ======= ======= ======= Net income before extraordinary item as reported $ 4,614 $ 4,614 $ 914 $ 914 Deduct dividends on Cumulative Convertible Preferred Stock -- -- (16) (16) ------- ------- ------- ------- Net income available to common shareholders before $ 4,614 $ 4,614 $ 898 $ 898 extraordinary item Extraordinary item 1,888 1,888 -- -- ------- ------- ------- ------- Net income for calculation $ 6,502 $ 6,502 $ 898 $ 898 ======= ======= ======= ======= Net income per share: Before extraordinary item $ .26 $ .26 $ .06 $ .06 Extraordinary item .11 .11 -- -- ------- ------- ------- ------- $ .37 $ .37 $ .06 $ .06 ======= ======= ======= =======
EX-11.B 3 COMPUTATION OF PER SHARE EARNINGS - 6 MONTHS EXHIBIT 11b. - Computation of Per Share Earnings (in thousands except per share data) (unaudited) - --------------------------------------------------------------------------------
SIX MONTHS ENDED JUNE 30, ---------------------------------------------- 1996 1995 ---------------------------------------------- Common and Common and Common Common Equivalent Full Equivalent Full Shares Dilution Shares Dilution ----------- --------- ----------- --------- Weighted average common shares outstanding 16,208 16,208 12,340 12,340 Incremental shares assumed to be issued 1,127 1,494 3,397 3,635 ------- ------- ------- ------- Total shares outstanding for calculation 17,335 17,702 15,737 15,975 ======= ======= ======= ======= Net income before extraordinary item as reported $13,830 $13,830 $ 1,233 $ 1,233 Deduct dividends on Cumulative Convertible Preferred Stock -- -- (31) (31) ------- ------- ------- ------- Net income available to common shareholders before $13,830 $13,830 $ 1,202 $ 1,202 extraordinary item Extraordinary item (6,619) (6,619) -- -- ------- ------- ------- ------- Net income for calculation $ 7,211 $ 7,211 $ 1,202 $ 1,202 ======= ======= ======= ======= Net income (loss) per share: Before extraordinary item $ .80 $ .78 $ .08 $ .08 Extraordinary item (.38) (.37) -- -- ------- ------- ------- ------- $ .42 $ .41 $ .08 $ .08 ======= ======= ======= =======
EX-27 4 ARTICLE 5 - FINANCIAL DATA SCHEDULES
5 This schedule contains summary financial information extracted from Plains Resources Inc. and Subsidiaries Condensed Consolidated Balance Sheet as of June 30, 1996, and Condensed Consolidated Statement of Operations for the six months ended June 30, 1996 and is qualified in its entirety by reference to such financial statements. 1,000 6-MOS DEC-31-1996 JAN-01-1996 JUN-30-1996 5,605 0 71,049 0 4,385 81,039 439,359 147,285 393,982 89,464 218,182 0 0 1,628 83,212 393,982 279,322 279,443 247,730 258,151 0 0 8,532 4,718 (9,112) 13,830 0 (6,619) 0 7,211 .42 .41
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