-----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, N1Pu+3/phrFAebCzifFABqZaX8vxJbrklHaYVgJUw584ORDso2GDl5ESGaDLtJ/q Is4AcOKBEdCjgCLT9d7Zpw== 0000899243-96-001443.txt : 19961113 0000899243-96-001443.hdr.sgml : 19961113 ACCESSION NUMBER: 0000899243-96-001443 CONFORMED SUBMISSION TYPE: 10-Q PUBLIC DOCUMENT COUNT: 4 CONFORMED PERIOD OF REPORT: 19960930 FILED AS OF DATE: 19961112 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: 96659982 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 SEPTEMBER 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) AND EACH OF THE SUBSIDIARY GUARANTORS OF $150 MILLION 10.25% SENIOR SUBORDINATED NOTES DUE 2006 LISTED UNDER "GENERAL" ON PAGE 2 OF THIS REPORT 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 ____ ---- 16,501,195 shares of common stock $.10 par value, issued and outstanding at November 6, 1996. Page 1 of 20 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
PAGE PART I. FINANCIAL INFORMATION CONDENSED CONSOLIDATED FINANCIAL STATEMENTS: Condensed Consolidated Balance Sheets: September 30, 1996 and December 31, 1995......................... 3 Condensed Consolidated Statements of Operations: For the three and nine months ended September 30, 1996 and 1995.. 4 Condensed Consolidated Statements of Cash Flows: For the nine months ended September 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 of 20 PLAINS RESOURCES INC. AND SUBSIDIARIES CONDENSED CONSOLIDATED BALANCE SHEETS (in thousands, except share data) - --------------------------------------------------------------------------------
SEPTEMBER 30, DECEMBER 31, 1996 1995 -------------- ------------------ (unaudited) ASSETS CURRENT ASSETS Cash and cash equivalents $ 625 $ 6,129 Accounts receivable and other 79,336 52,383 Inventory 6,977 5,120 --------- --------- Total current assets 86,938 63,632 --------- --------- PROPERTY AND EQUIPMENT Oil and natural gas properties - full cost method: Subject to amortization 360,344 328,712 Not subject to amortization 51,665 48,795 Downstream assets, primarily crude oil terminal and storage facility 34,966 32,788 Other property and equipment 7,872 7,789 --------- --------- 454,847 418,084 Less allowance for depreciation, depletion and amortization (152,605) (137,546) --------- --------- 302,242 280,538 --------- --------- DEFERRED INCOME TAXES, NET 10,190 -- OTHER ASSETS 10,337 7,876 --------- --------- $ 409,707 $ 352,046 ========= ========= LIABILITIES AND STOCKHOLDERS' EQUITY CURRENT LIABILITIES Accounts payable and other current liabilities $ 89,535 $ 56,573 Interest payable 1,091 3,977 Royalties payable and drilling advances 6,745 6,364 Notes payable and other current obligations 521 1,467 --------- --------- Total current liabilities 97,892 68,381 BANK DEBT 66,100 98,000 SUBORDINATED DEBT 149,107 100,000 OTHER LONG-TERM DEBT 3,578 7,089 OTHER LONG-TERM LIABILITIES 2,170 1,547 --------- --------- 318,847 275,017 --------- --------- STOCKHOLDERS' EQUITY Common stock, $.10 par value, 50,000,000 shares authorized; issued and outstanding 16,426,816 at September 30, 1996, and 16,178,670 shares at December 31, 1995 1,643 1,618 Additional paid-in capital 119,684 118,090 Accumulated deficit (30,467) (42,679) --------- --------- 90,860 77,029 --------- --------- $ 409,707 $ 352,046 ========= =========
See notes to condensed consolidated financial statements. Page 3 of 20 PLAINS RESOURCES INC. AND SUBSIDIARIES CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (unaudited) (in thousands, except per share data) - -------------------------------------------------------------------------------
THREE MONTHS ENDED NINE MONTHS ENDED SEPTEMBER 30, SEPTEMBER 30, -------------------- --------------------- 1996 1995 1996 1995 -------- -------- --------- --------- REVENUE Oil and natural gas sales $ 24,825 $ 15,136 $ 70,597 $ 45,614 Marketing, transportation and storage 144,321 88,354 377,871 246,632 Interest and other income 99 117 220 264 -------- -------- --------- --------- 169,245 103,607 448,688 292,510 -------- -------- --------- --------- EXPENSES Production expenses 9,902 7,253 28,533 21,160 Purchases, transportation and storage 141,727 86,610 370,826 241,794 General and administrative 1,899 1,753 5,941 5,527 Depreciation, depletion and amortization 5,632 4,113 16,053 12,238 Interest expense 4,274 3,395 12,806 10,075 Litigation settlement -- -- 4,000 -- -------- -------- --------- --------- 163,434 103,124 438,159 290,794 -------- -------- --------- --------- Income before income taxes and extraordinary item 5,811 483 10,529 1,716 Income tax expense (benefit) 2,325 -- (6,787) -- -------- -------- --------- --------- INCOME BEFORE EXTRAORDINARY ITEM 3,486 483 17,316 1,716 EXTRAORDINARY ITEM: (Loss) on early extinguishment of debt, net of tax benefit 1,515 -- (5,104) -- -------- -------- --------- --------- NET INCOME $ 5,001 $ 483 $ 12,212 $ 1,716 ======== ======== ========= ========= Net income per common and common equivalent share: Before extraordinary item $ 0.20 $ 0.03 $ 0.98 $ 0.10 Extraordinary item 0.08 -- (0.29) -- -------- -------- --------- --------- $ 0.28 $ 0.03 $ 0.69 $ 0.10 ======== ======== ========= ========= Weighted average number of common and common equivalent shares 17,821 16,174 17,578 15,951 ======== ======== ========= =========
See notes to condensed consolidated financial statements. Page 4 of 20 PLAINS RESOURCES INC. AND SUBSIDIARIES CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (unaudited) (in thousands) - --------------------------------------------------------------------------------
NINE MONTHS ENDED SEPTEMBER 30, ----------------------------- 1996 1995 --------- --------- NET CASH PROVIDED BY OPERATING ACTIVITIES $ 26,669 $ 14,585 --------- --------- CASH FLOWS FROM INVESTING ACTIVITIES Proceeds from the sale of oil and natural gas properties 3,066 1,827 Payment for acquisition, exploration and development costs (36,506) (16,885) Payment for additions to other property and assets (1,876) (887) --------- --------- Net cash used in investing activities (35,316) (15,945) --------- --------- CASH FLOWS FROM FINANCING ACTIVITIES Proceeds from long-term debt 217,323 23,750 Principal payments of long-term debt (208,357) (20,359) Costs incurred to redeem long-term debt (6,468) -- Proceeds from exercise of stock options 1,619 545 Other (974) 1,204 --------- --------- Net cash provided by financing activities 3,143 5,140 --------- --------- Net (decrease) increase in cash and cash equivalents (5,504) 3,780 Cash and cash equivalents, beginning of period 6,129 1,291 --------- --------- Cash and cash equivalents, end of period $ 625 $ 5,071 ========= =========
See notes to condensed consolidated financial statements Page 5 of 20 PLAINS RESOURCES INC. AND SUBSIDIARIES NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS SEPTEMBER 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 September 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%. On August 8, 1996, the Company exchanged a total of $149.5 million principal amount of the Series A 10.25% Notes for 10.25% Senior Subordinated Notes due 2006, Series B, (the "Series B 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 were exchanged, except for certain transfer restrictions relating to the Series A 10.25% Notes. The Series A 10.25% Notes and the Series B 10.25% Notes (collectively, the "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 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 of any Public Equity Offering (as both are defined in the indenture under which the 10.25% Notes were issued (the "Indenture")). The Indenture contains covenants including, but not limited 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 Page 6 of 20 an offer to repurchase the 10.25% Notes at 101% of the principal amount thereof, plus accrued and unpaid interest to the date of the repurchase. The 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 10.25% Notes, net of offering costs, were approximately $144.6 million and were used to redeem the Company's 12% Senior Subordinated Notes due 1999 (the "12% Notes") at 106% of the $100 million principal amount outstanding and to retire bridge bank indebtedness which was incurred in December 1995 in connection with the acquisition of certain oil properties. The 12% Notes were redeemed on April 18, 1996, and the Company has recognized an extraordinary loss of $8.5 million, $5.1 million net of deferred tax benefit, in connection therewith (See Note 4). 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. 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 September 30, 1996, the Company had $66.1 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. 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. By Order and Final Judgment entered on September 30, 1996, the Court approved the Stipulation of Settlement and the settlement amount was paid on November 1, 1996. Approximately $4.1 million of such amount was paid by the Company's insurance carrier and $2.2 million was paid by the Company. Page 7 of 20 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 September 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 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. For the nine months ended September 30, 1996, the Company recognized a net deferred tax benefit before extraordinary item of $6.8 million. Such amount consists of a $4.2 million deferred tax provision on the Company's income before extraordinary item and the $11 million valuation allowance reduction previously discussed. In addition, the Company reported a $3.4 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 of 20 MANAGEMENT'S DISCUSSION AND ANALYSIS RESULTS OF OPERATIONS Three month periods ended September 30, 1996 and 1995 For the quarter ended September 30, 1996, the Company reported net income before extraordinary item of $3.5 million, or $.20 per share, on total revenue of $169.2 million. This compares with net income of $.5 million, or $.03 per share, on total revenue of $103.6 million for the third quarter of 1995. Net income after extraordinary item was $5.0 million, or $.28 per share. Cash flow from operations (net income plus noncash expenses) more than doubled, increasing 149% to $11.4 million as compared to $4.6 million in the third quarter of 1995. Earnings before interest, taxes, depreciation, depletion and amortization ("EBITDA") was $15.7 million, nearly double the $8.0 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 SEPTEMBER 30, ---------------------------------- 1996 1995 ---------------- ---------------- (in thousands, except per unit data) (unaudited) AVERAGE DAILY PRODUCTION VOLUMES BARRELS OF OIL EQUIVALENT ("BOE") LA Basin (91% oil) 9.4 8.3 S. Florida (100% oil) 5.1 3.6 Illinois Basin (100% oil) 3.5 -- Other properties -- 0.8 ------ ------ Total (95% oil) 18.0 12.7 ====== ====== AVERAGE SALES PRICE Per barrel of oil $15.46 $13.72 ====== ====== Per mcf of natural gas $ 1.11 $ 0.94 ====== ====== UNIT ECONOMICS Average sales price per BOE $14.97 $12.94 Production expenses per BOE 5.97 6.20 ------ ------ Gross margin per BOE 9.00 6.74 Upstream G&A expenses per BOE 0.72 0.98 ------ ------ Gross profit per BOE $ 8.28 $ 5.76 ====== ====== Oil and natural gas production for the third quarter of 1996 increased 42% to 1.66 million BOE, as compared to the 1.17 million BOE produced in last year's comparative quarter. The Company's unit gross margin increased to $9.00 per BOE, a 34% improvement over the $6.74 per BOE recorded in last year's third quarter. Unit gross profit, which deducts all pre-interest cash costs attributable to the upstream segment, was $8.28 per BOE, up 44% over 1995's third quarter amount of $5.76 per BOE. Page 9 of 20 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 nine months of 1996, average net daily production from the Company's LA Basin properties increased to approximately 9,400 BOE per day, up 1,100 BOE per day, or 13% over last year's comparative quarter. Net production from the Company's South Florida Sunniland Trend properties increased approximately 43% to average 5,100 barrels of oil per day in the third quarter of 1996 as compared to 3,600 barrels per day in last year's third quarter. The current quarter average incorporates the impact of production from the Company's 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 third quarter averaged approximately 3,100 barrels of oil with an oil cut of around 85%. 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 and the acquisition of the Company's Illinois Basin properties in the fourth quarter of 1995. Net production attributable to properties sold totaled 77,000 BOE or an average of over 800 BOE per day during the 1995 third quarter. Net production from the Illinois Basin properties totaled 316,000 barrels of oil or an average of 3,500 barrels of oil per day during the third 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 64% to $24.8 million for the third 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 16% to $14.97 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 floating price barrels of increased crude oil prices. Financial swap arrangements and futures transactions entered into by the Company to hedge production are included in the foregoing product prices. Such transactions had the effect of decreasing the Company's average price per BOE by $2.68 and $.10 in the third quarter of 1996 and 1995, respectively. During the current year quarter, the NYMEX benchmark price averaged $22.35 per barrel, up 26% as compared to an average of $17.75 per barrel in the correlative period of 1995. Although the impact of higher commodity prices on the Company's results was substantially mitigated due to preexisting hedges, this commodity price increase over the prior year period, as well as strong demand for crude oil, had a positive impact on net income before extraordinary item of approximately $1.2 million and approximately $2.0 million on cash flow and EBITDA in the third quarter of 1996. Of this $2.0 million, approximately $1.75 million is related to the unhedged production in the upstream segment and approximately $.25 million is related to the Company's downstream activities. Approximately 73% of the Company's third quarter of 1996 oil production was hedged at an average NYMEX benchmark price of around $18.00 per barrel. The Company's downstream segment reported gross margin (marketing, transportation and storage revenues less purchases, transportation and storage expenses) of $2.6 million for the third quarter of 1996, reflecting an approximate 49% increase over the $1.7 million reported for the 1995 quarter. Gross revenues were $144.3 million and $88.4 million for the respective periods. Gross profit (gross margin less downstream general and administrative ("G&A") expenses) increased 67% to $1.9 million versus $1.1 million in the third quarter of 1995. 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 third quarter Page 10 of 20 of 1996. Total average daily crude oil volumes marketed and terminalled during the 1996 third quarter were 56,000 barrels and 53,000 barrels, respectively. Such amounts represent respective increases of 22% and 43% as compared with average daily volumes of 46,000 barrels and 37,000 barrels in last year's third quarter. Aggregate unit production expenses declined 4% to $5.97 per BOE versus $6.20 per BOE in the third quarter of 1995. The reduction is attributable to decreases in the company's LA Basin and Sunniland Trend properties which have a component of fixed production costs that do not increase with incremental production. Such reductions were partially offset by the addition of the higher cost Illinois Basin production. Total production expenses increased to $9.9 million from $7.3 million for the third quarter 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 upstream unit G&A expenses decreased 27% to $.72 per BOE as compared to $.98 per BOE in last year's comparative quarter. Such decrease is primarily due to increased production volumes. Total G&A expenses, including downstream activities, were $1.9 million for the three months ended September 30, 1996, compared to $1.8 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 $5.6 million from $4.1 million reported in the third 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 September 30, 1996, increased to $4.3 million from $3.4 million for the comparative prior year quarter primarily due to higher outstanding debt which was partially offset by a lower overall average interest rate. Capitalized interest was $.9 million and $.8 million for the three months ended September 30, 1996 and 1995, respectively. During the third quarter, the Company recognized a deferred tax provision of $2.3 million. The Company also recognized a $1.5 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 due 1999 (the "12% Notes"). Nine month periods ended September 30, 1996 and 1995 For the nine months ended September 30, 1996, the Company reported net income before nonrecurring items of $10.3 million, or $.59 per share, on total revenue of $448.7 million. This compares with net income of $1.7 million, or $.10 per share, on total revenue of $292.5 million for the first nine months of 1995. Cash flow from operations (net income plus noncash expenses) was $30.6 million, more than double the $14.0 million reported in the 1995 period. EBITDA increased 81% to $43.4 million as compared to $24.0 million in the first nine months of 1995. Cash flow and EBITDA are also presented before the nonrecurring items. Net cash provided by operating activities, as reported in the condensed consolidated statements of cash flows, increased to $26.7 million for the nine months ended September 30, 1996, as compared to $14.6 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 an $8.5 million extraordinary loss associated with the early redemption of the 12% Notes ($5.1 million net of tax), 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 Page 11 of 20 the Company's net deferred tax asset. After giving effect to such nonrecurring items, the Company reported net income for the first nine months of 1996 of $12.2 million, or $.69 per share. Before extraordinary items, net income was $17.3 million or $.98 per share. The following table sets forth certain operating information of the Company for the periods presented: NINE MONTHS ENDED SEPTEMBER 30, ---------------------------------- 1996 1995 ---------------- ---------------- (in thousands, except per unit data) (unaudited) AVERAGE DAILY PRODUCTION VOLUMES BARRELS OF OIL EQUIVALENT LA Basin (91% oil) 9.1 8.3 S. Florida (100% oil) 4.5 3.5 Illinois Basin (100% oil) 3.5 -- Other properties 0.1 1.0 ------ ------ Total (95% oil) 17.2 12.8 ====== ====== AVERAGE SALES PRICE Per barrel of oil $15.58 $13.88 ====== ====== Per mcf of natural gas $ 0.89 $ 1.02 ====== ====== UNIT ECONOMICS Average sales price per BOE $15.02 $13.07 Production expenses per BOE 6.07 6.06 ------ ------ Gross margin per BOE 8.95 7.01 Upstream G&A expenses per BOE 0.80 1.06 ------ ------ Gross profit per BOE $ 8.15 $ 5.95 ====== ====== Oil and natural gas production for the first nine months of 1996 increased 35% to 4.70 million BOE versus the 3.49 million BOE produced in the 1995 comparative period. The Company's unit gross margin increased to $8.95 per BOE, a 28% improvement over the $7.01 per BOE recorded in last year's period. Unit gross profit, which deducts all pre-interest cash costs attributable to the upstream segment, was $8.15 per BOE, up 37% over 1995's nine month average of $5.95 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 nine months of 1996, average net daily production from the Company's LA Basin properties for the nine months ended September 30, 1996, increased to approximately 9,100 BOE per day, up 800 BOE per day, or 10% over last year's comparative period. Net production from the Company's South Florida Sunniland Trend properties increased approximately 28% to average 4,500 barrels of oil per day in the first nine months 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 development well drilled at the Raccoon Point Field. This well was completed and placed on line in late March and since such time daily gross production from this well has averaged approximately 3,100 barrels of oil (2,600 net to the Company). Page 12 of 20 The period to period comparisons of production volumes and unit margins were affected by sales of nonstrategic properties and the acquisition of the Company's Illinois Basin properties in the fourth quarter of 1995. Net production attributable to properties sold totaled 256,000 BOE or an average of just under 1,000 BOE per day during the first nine months of 1995. Net production from the Illinois Basin properties totaled 948,000 barrels of oil or an average of 3,500 barrels of oil per day during the first nine months of 1996. Oil and natural gas revenues increased 55% to $70.6 million for the first nine 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 15% to $15.02 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 floating price barrels of increased crude oil prices. 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 $1.94 and $.26 in the first nine months of 1996 and 1995, respectively. During the current year, the NYMEX benchmark price averaged approximately $21.15 per barrel, up 14% as compared to an average of $18.48 in the correlative period of 1995. Although the impact of higher commodity prices on the Company's results was substantially mitigated due to preexisting hedges, this commodity price increase over the prior year period, as well as strong demand for crude oil, had a positive impact on net income before extraordinary item of approximately $2.2 million and approximately $3.7 million on cash flow and EBITDA for the nine months ended September 30, 1996. Of this $3.7 million, approximately $3.1 million is related to the unhedged production in the upstream segment and approximately $.6 million is related to the Company's downstream activities. Approximately 69% of the Company's oil production was hedged during the first nine months of 1996 at an average NYMEX benchmark price of around $18 per barrel. The Company's downstream segment reported gross margin (marketing, transportation and storage revenues less purchases, transportation and storage expenses) of $7.0 million for the nine months ended September 30, 1996, reflecting an approximate 46% increase over the $4.8 million reported for the 1995 period. Gross revenues were $377.9 million and $246.6 million for the respective periods. Gross profit (gross margin less downstream G&A expenses) increased 62%, totaling $4.9 million versus $3.0 million in first nine months of last year. Such results are directly attributable to continued expansion of the downstream segment's base level activities and strong market demand for crude oil during 1996. Total average daily crude oil volumes marketed and terminalled during the nine months ended September 30, 1996 were 57,000 barrels and 55,000 barrels, respectively. Such amounts represent respective increases of 27% and 45% as compared with average daily volumes of 45,000 barrels and 38,000 barrels in last year's nine month period. Primarily as a result of the higher cost Illinois Basin production, aggregate unit production expenses for the first nine months of 1996 increased slightly to $6.07 per BOE. Unit production expenses for the Illinois Basin properties, which averaged $12.00 per barrel in the fourth quarter of 1995, averaged approximately $8.53 per barrel for the 1996 nine-month period. The significant reduction in production expenses for the Illinois Basin properties is a result of operational modifications implemented throughout 1996. The overall increase in unit production expenses attributable to the Illinois Basin properties was offset by decreases in unit production expenses in the Company's other core areas. Unit production expenses for the LA Basin Page 13 of 20 properties were $6.19 per BOE for the first nine months of 1996, or 6% lower than last year's comparative period. Unit production expenses for the South Florida Sunniland Trend properties averaged $3.98 per BOE, approximately 20% lower than the 1995 average of $4.97 per BOE. These reductions are primarily attributable to increased production from fields with a component of fixed production costs which do not increase with incremental production and to reimbursements received in the second quarter of 1996 for electricity overcharges in the previous year. Total production expenses increased to $28.5 million from $21.2 million for the first nine months 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 upstream unit G&A expenses decreased 25% to $.80 per BOE as compared to $1.06 per BOE in last year's nine month period. Such decrease is primarily due to increased production volumes. Total G&A expenses, including downstream activities, were $5.9 million for the nine months ended September 30, 1996, compared to $5.5 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 $16.1 million from $12.2 million reported in the first nine months 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 nine months ended September 30, 1996, increased to $12.8 million from $10.1 million reported for the comparative prior year period primarily due to higher outstanding debt which was partially offset by a lower overall average interest rate. Capitalized interest was $2.7 million and $2.3 million for the nine months ended September 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. 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. By Order and Final Judgment entered on September 30, 1996, the Court approved the Stipulation of Settlement and the settlement amount was paid on November 1, 1996. Approximately $4.1 million of such amount was paid by the Company's insurance carrier and $2.2 million was paid by the Company. 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 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 of 20 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 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 the 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 asset 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. For the nine months ended September 30, 1996, the Company recognized a net deferred tax benefit before extraordinary item of $6.8 million. Such amount consists of a $4.2 million deferred tax provision on the Company's income before extraordinary item and the $11 million valuation allowance reduction previously discussed. In addition, the Company reported a $3.4 million deferred tax benefit reported as an extraordinary item. Such deferred tax benefit is attributable to the $8.5 million pre-tax first quarter extraordinary loss from the early redemption of the Company's 12% Notes. Page 15 of 20 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%. On August 8, 1996, the Company exchanged a total of $149.5 million principal amount of the Series A 10.25% Notes for 10.25% Senior Subordinated Notes due 2006, Series B, (the "Series B 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 were exchanged, except for certain transfer restrictions relating to the Series A 10.25% Notes. The Series A 10.25% Notes and the Series B 10.25% Notes (collectively, the "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 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 of any Public Equity Offering (as both are defined in the indenture under which the 10.25% Notes were issued ("the "Indenture")). The Indenture contains covenants including, but not limited 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 10.25% Notes at 101% of the principal amount thereof, plus accrued and unpaid interest to the date of the repurchase. The 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 10.25% Notes, net of offering costs, were approximately $144.6 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. In April 1996, the Revolving Credit Facility and borrowing base thereunder were 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 September 30, 1996, the Company had $66.1 million in borrowings and a $1 million standby letter of credit outstanding under the Revolving Credit Facility. Page 16 of 20 At September 30, 1996, the Company had a working capital deficit of approximately $11 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 $35.3 million and $15.9 million for the nine months ended September 30, 1996 and 1995, respectively. Investing activities include payments for acquisition, exploration and development costs of $36.5 million and $16.9 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 nine months ended September 30, 1996 and 1995, respectively. Net cash provided by financing activities amounted to $3.1 million and $5.1 million for the nine months ended September 30, 1996 and 1995, respectively. Financing activities during 1996 include net proceeds of approximately $144.6 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 fourth quarter of 1996, the Company has committed an average of approximately 12,500 barrels of oil per day to fixed price arrangements at a NYMEX index price of approximately $18 per barrel. Such amount represents approximately 73% of 1996 third quarter average daily oil production. For 1997, the Company has established hedges on (i) 12,000 barrels per day for the first quarter at a NYMEX price of approximately $18.50 per barrel; (ii) 9,200 barrels per day for April through December at a NYMEX price of approximately $18.65 per barrel; and (iii) 2,000 barrels per day for January through December at a NYMEX floor price of $19.00 per barrel and a NYMEX ceiling price of $24.00 per barrel. All hedge prices are before applicable location and quality discounts. Such arrangements partially mitigate the adverse impact of potential oil price declines on the Company's operating results. Page 17 of 20 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 was filed with the Court in these cases. By Order and Final Judgment entered on September 30, 1996, the Court approved the Stipulation of Settlement and the settlement amount was paid on November 1, 1996. 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. Finalization of this settlement has been delayed due to a dispute between the defendants over certain title issues. The defendants have filed motions requesting the Court to rule on this dispute, but no hearing date has been set. The Company does not believe that this dispute will adversely affect the settlement reached between the Company and the defendants. 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 None Item 5 - Other Information None Item 6 - A. Exhibits Page 18 of 20 11(a) Computation of per share earnings for the three months ended September 30, 1996 and 1995 11(b) Computation of per share earnings for the nine months ended September 30, 1996 and 1995 27. Financial Data Schedule B. Report on Form 8-K None Page 19 of 20 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: November 12, 1996 By: /s/ Cynthia A. Feeback ------------------------------------- Cynthia A. Feeback, Controller and Principal Accounting Officer (Principal Accounting Officer) Page 20 of 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 SEPTEMBER 30, ----------------------------------------------- 1996 1995 ----------------------------------------------- Common and Common and Common Common Equivalent Full Equivalent Full Shares Dilution Shares Dilution ----------- ---------- ----------- --------- Weighted average common shares outstanding 16,342 16,342 15,286 15,286 Incremental shares assumed to be issued 1,479 1,521 888 888 ------- ------- ------- ------- Total shares outstanding for calculation 17,821 17,863 16,174 16,174 ======= ======= ======= ======= Net income before extraordinary item as reported $ 3,486 $ 3,486 $ 483 $ 483 Deduct dividends on Cumulative Convertible Preferred Stock -- -- (11) (11) ------- ------- ------- ------- Net income available to common shareholders before $ 3,486 $ 3,486 $ 472 $ 472 extraordinary item Extraordinary item 1,515 1,515 -- -- ------- ------- ------- ------- Net income for calculation $ 5,001 $ 5,001 $ 472 $ 472 ======= ======= ======= ======= Net income per share: Before extraordinary item $ .20 $ .20 $ .03 $ .03 Extraordinary item .08 .08 -- -- ------- ------- ------- ------- $ .28 $ .28 $ .03 $ .03 ======= ======= ======= =======
EX-11.B 3 COMPUTATION OF PER SHARE EARNINGS - 9 MONTHS EXHIBIT 11b. - Computation of Per Share Earnings (in thousands except per share data) (unaudited) - --------------------------------------------------------------------------------
NINE MONTHS ENDED SEPTEMBER 30, ---------------------------------------------- 1996 1995 -------------------- --------------------- Common and Common and Common Common Equivalent Full Equivalent Full Shares Dilution Shares Dilution ---------- --------- ---------- -------- Weighted average common shares outstanding 16,253 16,253 13,333 13,333 Incremental shares assumed to be issued 1,325 1,610 2,618 2,618 ------- ------- ------- ------- Total shares outstanding for calculation 17,578 17,863 15,951 15,951 ======= ======= ======= ======= Net income before extraordinary item as reported $17,316 $17,316 $ 1,716 $ 1,716 Deduct dividends on Cumulative Convertible Preferred Stock -- -- (42) (42) ------- ------- ------- ------- Net income available to common shareholders before extraordinary item $17,316 $17,316 $ 1,674 $ 1,674 Extraordinary item (5,104) (5,104) -- -- ------- ------- ------- ------- Net income for calculation $12,212 $12,212 $ 1,674 $ 1,674 ======= ======= ======= ======= Net income (loss) per share: Before extraordinary item $ .98 $ .97 $ .10 $ .10 Extraordinary item (.29) (.29) - - ------- ------- ------- ------- $ .69 $ .68 $ .10 $ .10 ======= ======= ======= =======
EX-27 4 ARTICLE 5 - FINANCIAL DATA SCHEDULE
5 THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM PLAINS RESOURCES INC. AND SUBSIDIARIES CONDENSED CONSOLIDATED BALANCE SHEET AS OF SEPTEMBER 30, 1996, AND CONDENSED CONSOLIDATED STATEMENT OF OPERATIONS FOR THE NINE MONTHS ENDED SEPTEMBER 30, 1996 AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH FINANCIAL STATEMENTS. 1,000 9-MOS DEC-31-1996 JAN-01-1996 SEP-30-1996 625 0 79,336 0 6,977 86,938 454,847 152,605 409,707 97,892 218,785 0 0 1,643 89,217 409,707 448,468 448,688 399,359 415,412 0 0 12,806 10,529 (6,787) 17,316 0 (5,104) 0 12,212 .69 .68
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