-----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, JO5oEItrm9HJw/axLGbtNdf0MVc80xLc7b7Ol8/XeeXEHBLldi9ko0PRD/kNG6Cc od7dUTJZLJiZ6TYaE/Q98w== 0000899243-99-001081.txt : 19990517 0000899243-99-001081.hdr.sgml : 19990517 ACCESSION NUMBER: 0000899243-99-001081 CONFORMED SUBMISSION TYPE: 10-Q PUBLIC DOCUMENT COUNT: 2 CONFORMED PERIOD OF REPORT: 19990331 FILED AS OF DATE: 19990514 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: SEC FILE NUMBER: 033-50572 FILM NUMBER: 99624125 BUSINESS ADDRESS: STREET 1: 500 DALLAS STREET 2: SUITE 700 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 March 31, 1999 [ ] 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.) 500 Dallas 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 [_] 16,911,713 shares of common stock $0.10 par value, issued and outstanding at April 30, 1999. Page 1 of 19 PLAINS RESOURCES INC. AND SUBSIDIARIES TABLE OF CONTENTS - ------------------------------------------------------------------------------- PAGE PART I. FINANCIAL INFORMATION CONSOLIDATED FINANCIAL STATEMENTS: Consolidated Balance Sheets: March 31, 1999 and December 31, 1998................................ 3 Consolidated Statements of Income: For the three months ended March 31, 1999 and 1998.................. 4 Consolidated Statements of Cash Flows: For the three months ended March 31, 1999 and 1998.................. 5 Notes to Consolidated Financial Statements............................ 6 MANAGEMENT'S DISCUSSION AND ANALYSIS..................................... 10 PART II. OTHER INFORMATION.............................................. 18 Page 2 of 19 PLAINS RESOURCES INC. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (in thousands, except per share data)
MARCH 31, DECEMBER 31, 1999 1998 --------------------------------- (unaudited) ASSETS CURRENT ASSETS Cash and cash equivalents $ 889 $ 6,544 Accounts receivable 161,742 128,875 Inventory 28,826 42,520 Prepaid expenses and other 2,464 1,527 ----------- ---------- Total current assets 193,921 179,466 ----------- ---------- PROPERTY AND EQUIPMENT Oil and natural gas properties - full cost method Subject to amortization 612,609 596,203 Not subject to amortization 56,603 54,545 Crude oil pipeline, gathering and terminal assets 380,956 378,254 Other property and equipment 8,869 8,606 ----------- ---------- 1,059,037 1,037,608 Less allowance for depreciation, depletion and amortization (382,382) (375,882) ----------- ---------- 676,655 661,726 ----------- ---------- OTHER ASSETS 134,405 133,075 ----------- ---------- $ 1,004,981 $ 974,267 =========== ========== LIABILITIES AND STOCKHOLDERS' EQUITY CURRENT LIABILITIES Accounts payable and other current liabilities $ 182,391 $ 170,985 Interest payable 3,190 7,950 Royalties payable 4,482 4,211 Notes payable and other current obligations 4,611 10,261 ----------- ---------- Total current liabilities 194,674 193,407 BANK DEBT 76,800 52,000 BANK DEBT OF A SUBSIDIARY 181,000 175,000 SUBORDINATED DEBT 202,365 202,427 OTHER LONG-TERM DEBT 2,556 2,556 OTHER LONG-TERM LIABILITIES 7,678 13,967 ----------- ---------- 665,073 639,357 ----------- ---------- MINORITY INTEREST 175,756 173,461 ----------- ---------- SERIES E CUMULATIVE CONVERTIBLE PREFERRED STOCK, STATED AT LIQUIDATION PREFERENCE 90,517 88,487 ----------- ---------- NON-REDEEMABLE PREFERRED STOCK, COMMON STOCK AND OTHER STOCKHOLDERS' EQUITY Series D Cumulative Convertible Preferred Stock, $1.00 par value, 46,600 shares authorized, issued and outstanding, net of discount of $1,023,000 and $1,354,000 at March 31, 1999 and December 31, 1998, respectively 22,277 21,946 Common Stock, $.10 par value, 50,000,000 shares authorized; issued and outstanding 16,891,617 and 16,881,938 shares at 1,689 1,688 March 31, 1999 and December 31, 1998, respectively Additional paid-in capital 124,815 124,679 Accumulated deficit (75,146) (75,351) ----------- ---------- 73,635 72,962 ----------- ---------- $ 1,004,981 $ 974,267 =========== ==========
See notes to consolidated financial statements. PLAINS RESOURCES INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF INCOME (unaudited) (in thousands, except per share data)
THREE MONTHS ENDED MARCH 31, --------------------------- 1999 1998 --------------------------- REVENUES Oil and natural gas sales $ 21,142 $ 26,164 Marketing, transportation, storage and terminalling revenues 455,760 167,204 Interest and other income 69 204 ---------- --------- 476,971 193,572 ---------- --------- EXPENSES Production expenses 11,563 12,838 Marketing, transportation, storage and terminalling expenses 436,396 163,200 General and administrative 4,062 2,376 Depreciation, depletion and amortization 7,170 6,755 Interest expense 8,753 6,109 ---------- --------- 467,944 191,278 ---------- --------- Income before income taxes and minority interest 9,027 2,294 Minority interest 4,820 - ---------- --------- Income before income taxes 4,207 2,294 Income tax expense: Current - 3 Deferred 1,641 860 ---------- --------- NET INCOME 2,566 1,431 Less: cumulative preferred stock dividends 2,361 312 ---------- --------- NET INCOME AVAILABLE TO COMMON STOCKHOLDERS $ 205 $ 1,119 ========== ========= EARNINGS PER COMMON SHARE: Basic $0.01 $0.07 ========== ========= Diluted $0.01 $0.06 ========== =========
See notes to consolidated financial statements Page 4 of 19 PLAINS RESOURCES INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (unaudited) (in thousands)
THREE MONTHS ENDED MARCH 31, ---------------------------- 1999 1998 ------------ ----------- CASH FLOWS FROM OPERATING ACTIVITIES Net income $ 2,566 $ 1,431 Items not affecting cash flows from operating activities: Depreciation, depletion and amortization 7,170 6,755 Minority interest in income of a subsidiary 4,820 - Deferred income taxes 1,641 860 Other non-cash items 390 54 Change in assets and liabilities from operating activities: Accounts receivable (35,548) 27,749 Inventory 13,694 384 Prepaid expenses and other (937) (228) Purchase of pipeline linefill (2,490) - Accounts payable and other current liabilities 16,574 (18,881) Interest payable (4,303) (4,308) Royalties payable 271 13 ---------- ---------- Net cash provided by operating activities 3,848 13,829 ---------- ---------- CASH FLOWS FROM INVESTING ACTIVITIES Payment for acquisition, exploration and developments costs (27,936) (15,944) Payment for crude oil pipeline, gathering and terminal assets (2,702) - Payment for additions to other property and assets (532) (315) ---------- ---------- Net cash used in investing activities (31,170) (16,259) ---------- ---------- CASH FLOWS FROM FINANCING ACTIVITIES Proceeds from long-term debt 78,300 75,560 Proceeds from short-term debt 4,250 750 Principal payments of long-term debt (47,500) (29,000) Principal payments of short-term debt (9,900) (18,000) Distribution to public Unitholders (2,525) - Other (958) (688) ---------- ---------- Net cash provided by financing activities 21,667 28,622 ---------- ---------- Net increase (decrease) in cash and cash equivalents (5,655) 26,192 Cash and cash equivalents, beginning of period 6,544 3,714 ---------- ---------- Cash and cash equivalents, end of period $ 889 $ 29,906 ========== ==========
See notes to consolidated financial statements Page 5 of 19 PLAINS RESOURCES INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS March 31, 1999 (unaudited) Note 1 -- Accounting Policies The consolidated financial statements include the accounts of Plains Resources Inc. (the "Company"), its wholly-owned subsidiaries and Plains All American Pipeline, L.P. ("PAA") in which the Company has an approximate 57% ownership interest. The operations of PAA are conducted through Plains Marketing, L.P. and All American Pipeline, L.P. Plains All American Inc. ("PAAI"), a wholly owned subsidiary of the Company, is the general partner ("General Partner") of PAA. The accompanying unaudited 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, 1998, 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 March 31, 1999, 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. Recent Accounting Pronouncement In June 1998, the Financial Accounting Standards Board ("FASB") issued Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activities ("FAS 133"). FAS 133 is effective for all fiscal years beginning after June 15, 1999 (January 1, 2000 for the Company). FAS 133 requires that all derivative instruments be recorded on the balance sheet at their fair value. Changes in the fair value of derivatives are recorded each period in current earnings or other comprehensive income, depending on whether a derivative is designated as part of a hedge transaction and, if it is, the type of hedge transaction. For fair-value hedge transactions in which the Company is hedging changes in an asset's, liability's, or firm commitment's fair value, changes in the fair value of the derivative instrument will generally be offset in the income statement by changes in the hedged item's fair value. For cash- flow hedge transactions, in which the Company is hedging the variability of cash flows related to a variable-rate asset, liability, or a forecasted transaction, changes in the fair value of the derivative instrument will be reported in other comprehensive income. The gains and losses on the derivative instrument that are reported in other comprehensive income will be reclassified as earnings in the periods in which earnings are affected by the variability of the cash flows of the hedged item. The Company has not yet determined the impact that the adoption of FAS 133 will have on its earnings or financial position. Note 2 -- Inventory and Other Assets Inventory consists of the following: March 31, December 31, 1999 1998 -------- ----------- (in thousands) Crude oil $ 24,555 $ 37,702 Material and supplies 4,271 4,818 -------- -------- $ 28,826 $ 42,520 ======== ======== Page 6 of 19 Other assets consist of the following: March 31, December,31 1999 1998 --------- ----------- (in thousands) Pipeline linefill $ 57,001 $ 54,511 Deferred tax asset 46,738 47,785 Land 8,853 8,853 Debt issue costs 18,834 18,668 Other 9,027 8,245 --------- --------- 140,453 138,062 Accumulated amortization (6,048) (4,987) --------- --------- $ 134,405 $ 133,075 ========= ========= Note 3 -- Acquisitions On May 12, 1999, Plains Scurlock Permian, L.P. ("Plains Scurlock"), a newly formed limited partnership of which PAAI is the general partner and Plains Marketing, L.P. is the limited partner, completed the acquisition of Scurlock Permian LLC and certain other pipeline assets from Marathon Ashland Petroleum LLC (the "Scurlock Acquisition"). Including working capital adjustments and associated closing and financing costs, the cash purchase price paid at closing was approximately $146 million. Scurlock Permian LLC, a wholly owned subsidiary of Marathon Ashland Petroleum LLC, is engaged in crude oil transportation, trading and marketing, operating in 14 states with more than 2,400 miles of active pipelines, numerous storage terminals and a fleet of more than 225 trucks. Its largest asset is an 800-mile pipeline and gathering system located in the Spraberry Trend in West Texas that extends into Andrews, Glasscock, Martin, Midland, Regan and Upton Counties, Texas. The assets acquired also include approximately 2.4 million barrels of crude oil used for working inventory. Financing for the Scurlock Acquisition was provided through (i) Plains Scurlock's limited recourse bank facility with BankBoston, N.A. (the "Plains Scurlock Credit Facility"), (ii) the sale to the General Partner of 1.3 million Class B Common Units of PAA at $19.125 per unit, the price equal to the market value of PAA's common units and (ii) a $25 million draw under its existing revolving credit agreement. The Plains Scurlock Credit Facility consists of (i) a five year $130 million term loan and (ii) a three year $35 million revolving credit facility. The Plains Scurlock Credit Facility is nonrecourse to PAA, Plains Marketing, L.P. and All American Pipeline, L.P. and is secured by the assets acquired. Borrowings under the term loan bear interest at LIBOR plus 3% and under the revolving credit facility at LIBOR plus 2.75%. A commitment fee equal to one- half of one percent per year is charged on the unused portion of the revolving credit facility. The term loan matures in May 2004 and the revolving credit facility matures in May 2002. No principal payment is scheduled for amortization prior to maturity. In April 1999, PAA signed a definitive agreement to acquire a West Texas crude oil pipeline and gathering system from Chevron Pipe Line Company for approximately $40 million (the "Chevron Asset Acquisition"). Principal assets to be acquired include approximately 400 miles of crude oil transmission lines, associated gathering and lateral lines and three million barrels of crude oil storage and terminalling capacity in Crane, Ector, Midland, Upton, Ward and Winkler Counties, Texas. Closing of the transaction is subject to regulatory review and approval, consents from third parties, and customary due diligence. Subject to satisfaction of the foregoing conditions, the transaction is expected to close early in the third quarter of 1999. It is anticipated that the Chevron Asset Acquisition will be made by Plains Scurlock, with financing provided by the Plains Scurlock Credit Facility. Chevron will continue transporting crude oil through the pipeline under a contractual arrangement. PAA will also enter into a five-year contractual arrangement to sell up to 30,000 barrels of crude oil per day at market prices to another Chevron entity. Such arrangement may be extended by Chevron for up to five additional years. The system is currently moving an aggregate of approximately 98,000 barrels of crude oil per day under various gathering and transportation arrangements. Page 7 of 19 On July 30, 1998, PAAI acquired all of the outstanding capital stock of the All American Pipeline Company, Celeron Gathering Corporation and Celeron Trading & Transportation Company (collectively the "Celeron Companies") from Wingfoot Ventures Seven, Inc., a wholly-owned subsidiary of The Goodyear Tire & Rubber Company ("Goodyear") for approximately $400 million, including transaction costs. The principal assets of the entities acquired include the All American Pipeline System, a 1,233-mile crude oil pipeline extending from California to Texas, and a 45-mile crude oil gathering system in the San Joaquin Valley of California, as well as other assets related to such operations. Financing for the acquisition was provided through (i) PAAI's $325 million, limited recourse bank facility and (ii) an approximate $114 million capital contribution to PAAI by the Company. Approximately $29 million of such capital contribution was funded by cash flow and the Company's revolving credit facility and the remaining $85 million was provided by the issuance of the Company's Series E Preferred Stock. The assets, liabilities and results of operations of the Celeron Companies are included in the Consolidated Financial Statements of the Company effective July 30,1998. The following unaudited pro forma information is presented to show pro forma revenues, net income and net income per share as if the acquisition occurred on January 1, 1998. Three Months Ended March 31, 1998 ------------------- (in thousands, except per share data) Revenues $ 385,000 ========== Net income $ 6,543 ========== Net income per share: Basic $ 0.11 ========== Diluted $ 0.10 ========== Note 4 -- Earnings Per Share The following is a reconciliation of the numerators and the denominators of the basic and diluted earnings per share ("EPS") computations for income from continuing operations for the three months ended March 31, 1999 and 1998, as required by Statement of Financial Accounting Standards No. 128, Earnings Per Share.
For the Quarter Ended March 31, -------------------------------------------------------------------------- 1999 1998 ------------------------------------- --------------------------------- Per Per Income Shares Share Income Shares Share (Numerator) (Denominator) Amount (Numerator) (Denominator) Amount ---------- ----------- --------- ----------- ----------- ------- (in thousands, except per share data) Net income $ 2,566 $ 1,431 Less: preferred stock dividends (2,361) (312) -------- --------- Income available to common stockholders 205 16,890 $ 0.01 1,119 16,724 $ 0.07 ========= ========= Effect of dilutive securities: Employee stock options - 628 - 1,029 Warrants - 393 - 518 -------- -------- --------- -------- Income available to common stockholders assuming dilution $ 205 17,911 $ 0.01 $ 1,119 18,271 $ 0.06 ======== ======== ========= ========= ======== =========
Certain options and warrants to purchase shares of the Company's common stock ("Common Stock") were not included in the computations of diluted EPS because the exercise prices were greater than the average market price of the Common Stock during the periods of the EPS calculations, resulting in antidilution. In addition, the Company's preferred stock is convertible into Common Stock but was not included in the computation of diluted EPS because the effect was antidilutive. Page 8 of 19 Note 5 -- Operating Segments The Company's operations consist of two operating segments: (1) Upstream Operations - engages in the acquisition, exploitation, development, exploration and production of crude oil and natural gas and (2) Midstream Operations - engages in crude oil gathering, marketing, terminalling, storage and transportation. The Company evaluates segment performance based on gross margin, gross profit and income before income taxes and minority interest. (In thousands) Upstream Midstream Total ---------------------------------------------------------------------------- For the Three Months Ended March 31, 1999 Revenues: External Customers $ 21,142 $ 455,760 $476,902 Intersegment (a) - 327 327 Other income (expense) (28) 97 69 -------- --------- -------- Total revenues of reportable segments $ 21,114 $ 456,184 $477,298 ======== ========= ======== Segment gross margin (b) $ 9,579 $ 19,364 $ 28,943 Segment gross profit (c) 7,968 16,913 24,881 Segment income/(loss) before income taxes and minority interest (1,959) 10,986 9,027 ---------------------------------------------------------------------------- For the Three Months Ended March 31, 1998 Revenues: External Customers $ 26,164 $ 167,204 $193,368 Intersegment (a) - 257 257 Interest income 27 177 204 -------- --------- -------- Total revenues of reportable segments $ 26,191 $ 167,638 $193,829 ======== ========= ======== Segment gross margin (b) $ 13,326 $ 4,004 $ 17,330 Segment gross profit (c) 11,936 3,018 14,954 Segment income before income taxes and minority interest 301 1,993 2,294 ---------------------------------------------------------------------------- (a) Intersegment revenues and transfers were conducted on an arm's-length basis. (b) Gross margin is calculated as operating revenues less operating expenses. (c) Gross profit is calculated as operating revenues less operating expenses and general and administrative expenses. Page 9 of 19 MANAGEMENT'S DISCUSSION AND ANALYSIS General On November 23, 1998, Plains All American Pipeline, L.P. ("PAA"), through which the Company's midstream activities are conducted, completed its initial public offering of 13.1 million common units representing limited partner interests. PAA's results are consolidated into the Company's results with the public's 43% ownership reflected as a minority interest deduction from income. The operations of PAA are conducted through Plains Marketing, L.P. and All American Pipeline, L.P. Plains All American Inc. ("PAAI"), a wholly owned subsidiary of the Company is the general partner ("General Partner") of PAA. PAA was formed to acquire the midstream crude oil business and assets of the Company, including the All American Pipeline and the SJV Gathering System, which the Company purchased from Goodyear in July 1998 (the "All American Pipeline Acquisition"). The assets, liabilities and results of operations of the All American Pipeline Acquisition are included in the Company's Consolidated Financial Statements effective July 30, 1998. See Note 3 to the accompanying Consolidated Financial Statements for pro forma information giving effect to the All American Pipeline Acquisition as if such transaction occurred on January 1, 1998. Results of Operations Three month periods ended March 31, 1999 and 1998 The Company reported net income for the first quarter of 1999 of $2.6 million as compared with net income of $1.4 million, or $0.07 per common share ($0.06 assuming dilution) in the 1998 first quarter. After deducting accrued preferred stock dividends, net income per common share was $0.01 per common share in the 1999 first quarter (also $0.01 per share assuming dilution). Cash flow from operations (net income before noncash expenses) increased approximately 29% to $11.8 million in the 1999 period as compared to $9.1 million in the first quarter of 1998. Earnings before interest, taxes, depreciation, amortization and minority interest ("EBITDA") increased 65% to $25.0 million versus $15.2 million in the first quarter of 1998. Net cash provided by operating activities, as reported in the consolidated statements of cash flows was $3.8 million for the three months ended March 31, 1999, as compared to $13.8 million for the 1998 comparative period. The decrease is primarily attributable to (i) the purchase of approximately $2.5 million of pipeline linefill and the payment of approximately $2.5 million of property taxes related to pipeline operations in the 1999 first quarter and (ii) the sale of crude oil inventory during the first quarter of 1999 for which payment was received during the second quarter. Upstream Results The following table sets forth certain upstream operating information of the Company for the periods presented: Three Months Ended March 31, ------------------ 1999 1998 -------- ------- (in thousands) Average Daily Production Volumes Barrels of oil equivalent ("BOE") California (approximately 91% oil) 14.9 13.7 Gulf Coast (100% oil) 2.9 4.9 Illinois Basin (100% oil) 3.2 3.7 -------- ------- Total (approximately 94% oil) 21.0 22.3 ======== ======= Unit Economics Average sales price per BOE $11.21 $13.03 Production expense per BOE 6.13 6.39 -------- ------- Gross margin per BOE 5.08 6.64 Upstream G&A expense per BOE 0.85 0.69 -------- ------- Gross profit per BOE $ 4.23 $ 5.95 ======== ======= During the 1999 first quarter, production volumes were affected by shut-ins and production cutbacks related to lower prices and curtailments related to refinery disruptions in California as well as declines in the Company's Gulf Coast production. As a result, total oil equivalent production decreased approximately 6% to an average of 21,000 BOE per day as compared to the first quarter 1998 average of 22,300 barrels per day. Excluding production from the Mt. Poso Field, which was acquired in the fourth quarter of 1998, total production decreased approximately 10% from the prior year quarter. Net daily production in California increased approximately 9% to 14,900 BOE in the first quarter of 1999 compared to 13,700 BOE in the same quarter of 1998. Excluding production from the Mt. Poso field, total California production was up Page 10 of 19 approximately 3% over the comparative prior year quarter. Net daily production for the Company's Gulf Coast properties averaged approximately 2,900 barrels per day during the first quarter of 1999, compared to 4,900 barrels per day in the 1998 comparative period. Net daily production in the Illinois Basin averaged approximately 3,200 barrels per day during the first quarter of 1999, a decrease of approximately 14% as compared to the 1998 first quarter average of 3,700 barrels per day. Oil and natural gas revenues were $21.1 million for the first quarter of 1999, a decrease of approximately 19% from the 1998 first quarter amount of $26.2 million. The decrease is due to decreased crude oil prices and the production decreases discussed above. 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 price was $11.21 per BOE, a decrease of approximately 14% as compared to the 1998 first quarter average wellhead price of $13.03 per BOE. The NYMEX benchmark West Texas Intermediate ("WTI") crude oil price averaged $13.06 per barrel during the first quarter of 1999, or nearly $3.00 per barrel below the $15.97 per barrel average for the first quarter of 1998 and $9.77 below the $22.83 in the first quarter of 1997. The Company maintained hedges on approximately 45% and 60% of its crude oil production in the first quarter of 1999 and 1998, respectively, with the hedge price averaging a NYMEX WTI price of approximately $18.25 per barrel and $19.80 per barrel in the respective periods. Hedging transactions had the effect of increasing the Company's average price per BOE by $2.21 and $2.10 in the first quarter of 1999 and 1998, respectively. Unit production expenses averaged $6.13 per BOE, a 4% decrease as compared to the 1998 first quarter average of $6.39 per BOE. Unit gross margin in the upstream segment was $5.08 per BOE, a 23% decrease as compared to $6.64 per BOE reported for the first quarter of 1998 on substantially higher oil prices. Upstream unit gross profit, which deducts all pre-interest cash costs, was $4.23 per BOE, 29% lower than the 1998 amount of $5.95 per BOE. Total production expenses decreased to $11.6 million from $12.8 million for the first quarter of 1998. Unit general and administrative ("G&A") expenses in the upstream segment were $0.85 per BOE in the first quarter of 1999, compared to $0.69 per BOE in the prior year comparative quarter. The increase is primarily due to decreased production volumes, increased public company expenses and the Company's upstream activity. Depreciation, depletion and amortization ("DD&A") per BOE was $2.10 for the first quarter of 1999 compared to $3.00 per BOE in the 1998 comparative quarter. Such decrease is primarily due to a $174 million reduction in the carrying cost of the Company's proved oil and natural gas properties recorded in the 1998 fourth quarter due to low crude oil prices, and the impact of subsequent price recovery on proved reserve volumes. The NYMEX WTI price was $12.05 per barrel at December 31, 1998, compared to $16.76 at March 31, 1999. Total upstream DD&A expense was $4.0 million in the first quarter of 1999, compared to $6.0 million in the 1998 comparative quarter due to the lower per unit rate and decreased production volumes. Midstream Results The following table sets forth certain midstream operating information of the Company for the periods presented: Three Months Ended March 31, ------------------ 1999 1998 -------- ------- (in thousands) Operating Results: Gross margin Pipeline $ 11,882 $ - Terminalling and storage and gathering and marketing 7,482 4,004 -------- ------- Total 19,364 4,004 General and administrative expense (2,451) (986) -------- ------- Gross profit $ 16,913 $ 3,018 ======== ======= Average Daily Volumes (barrels) Pipeline tariff activities 126 - Pipeline margin activities 47 - -------- ------- Total 173 - ======== ======= Lease gathering 99 81 Bulk purchases 94 95 Terminal throughput 75 66 Pipeline Operations. The Company's results for the first quarter of 1998 do not include the results of operations of the All American Pipeline and the SJV Gathering System which were acquired effective July 30, 1998. Gross margin from pipeline Page 11 of 19 activities was $11.9 million for the first quarter of 1999. Tariff revenues were $13.1 million and are primarily attributable to transport volumes from the Santa Ynez field and the Point Arguello field. Volumes related to margin activities averaged approximately 47,000 barrels per day. The margin between revenue and direct cost of crude purchased was $5.0 million for the first quarter of 1999. Operations and maintenance expenses were $3.0 million for such period. The following table sets forth the All American Pipeline average deliveries per day within and outside California for the three months ended March 31, 1999. Deliveries: Average daily volumes (thousand barrels): Within California 112 Outside California 61 ---- Total 173 ==== Terminalling and Storage Activities and Gathering and Marketing Activities. Gross margin from terminalling and storage and gathering and marketing activities was $7.5 million for the quarter ended March 31, 1999, reflecting a 87% increase over the $4.0 million reported for the 1998 period. Net of interest expense associated with contango inventory transactions, gross margin for the first quarter of 1999 was $7.3 million, representing an increase of approximately 90% over the 1998 first quarter amount, likewise net of contango interest. The increase in gross margin was primarily attributable to an increase in the volumes gathered and marketed in West Texas, Louisiana and the Gulf of Mexico and activities at the Cushing Terminal. General Total G&A expenses, including midstream activities, were approximately $4.1 million for the three months ended March 31, 1999, an increase of $1.7 million as compared to the 1998 comparative period. Approximately $1.5 million of the increase is attributable to the Company's midstream activities. Approximately $1.2 million of the midstream increase is associated with the July 1998 All American Pipeline Acquisition and expenses incurred by PAA as a result of its being a separate public entity. An additional $0.3 million is due to a one time expense related to a staff reduction and relocation of certain functions related to the midstream segment's pipeline operations. Interest expense for the quarter ended March 31, 1999 increased to $8.8 million from $6.1 million for the comparative prior year quarter primarily due to the debt incurred for the All American Pipeline Acquisition. Capitalized interest was $1.0 million and $0.9 million for the three months ended March 31, 1999 and 1998, respectively. During the first quarter of 1999, the Company reported a minority interest deduction from income of approximately $4.8 million. Such amount represents the public's 43% share in the earnings of PAA. The Company's total tax provision for the quarter ended March 31, 1999, was approximately $1.6 million, as compared to the first quarter 1998 tax provision of approximately $0.9 million. Such increase is due to the increase in income before taxes between the two periods. In both periods, substantially all of the Company's income tax provision was deferred. In June 1998, the Financial Accounting Standards Board ("FASB") issued Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activities ("FAS 133"). FAS 133 is effective for all fiscal years beginning after June 15, 1999 (January 1, 2000 for the Company). FAS 133 requires that all derivative instruments be recorded on the balance sheet at their fair value. Changes in the fair value of derivatives are recorded each period in current earnings or other comprehensive income, depending on whether a derivative is designated as part of a hedge transaction and, if it is, the type of hedge transaction. For fair value hedge transactions in which the Company is hedging changes in an asset's, liability's, or firm commitment's fair value, changes in the fair value of the derivative instrument will generally be offset in the income statement by changes in the hedged item's fair value. For cash flow hedge transactions, in which the Company is hedging the variability of cash flows related to a variable-rate asset, liability, or a forecasted transaction, changes in the fair value of the derivative instrument will be reported in other comprehensive income. The gains and losses on the derivative instrument that are reported in other comprehensive income will be reclassified as earnings in the periods in which earnings are affected by the variability of the cash flows of the hedged item. The Company has not yet determined the impact that the adoption of FAS 133 will have on its results of operations or financial position. Page 12 of 19 Capital Resources, Liquidity and Financial Condition Acquisitions On May 12, 1999, Plains Scurlock Permian, L.P. ("Plains Scurlock"), a newly formed limited partnership of which PAAI is the general partner and Plains Marketing, L.P. is the limited partner, completed the acquisition of Scurlock Permian LLC and certain other pipeline assets from Marathon Ashland Petroleum LLC (the "Scurlock Acquisition"). Including working capital adjustments and associated closing and financing costs, the cash purchase price paid at closing was approximately $146 million. Scurlock Permian LLC, a wholly owned subsidiary of Marathon Ashland Petroleum LLC, is engaged in crude oil transportation, trading and marketing, operating in 14 states with more than 2,400 miles of active pipelines, numerous storage terminals and a fleet of more than 225 trucks. Its largest asset is an 800-mile pipeline and gathering system located in the Spraberry Trend in West Texas that extends into Andrews, Glasscock, Martin, Midland, Regan and Upton Counties, Texas. The assets acquired also include approximately 2.4 million barrels of crude oil used for working inventory. Financing for the Scurlock Acquisition was provided through (i) Plains Scurlock's limited recourse bank facility with BankBoston, N.A. (the "Plains Scurlock Credit Facility"), (ii) the sale to the General Partner of 1.3 million Class B Common Units of PAA at $19.125 per unit, the price equal to the market value of PAA's common units and (ii) a $25 million draw under its existing revolving credit agreement. The Plains Scurlock Credit Facility consists of (i) a five year $130 million term loan and (ii) a three year $35 million revolving credit facility. The Plains Scurlock Credit Facility is nonrecourse to PAA, Plains Marketing, L.P. and All American Pipeline, L.P. and is secured by the assets acquired. Borrowings under the term loan bear interest at LIBOR plus 3% and under the revolving credit facility at LIBOR plus 2.75%. A commitment fee equal to one- half of one percent per year is charged on the unused portion of the revolving credit facility. The term loan matures in May 2004 and the revolving credit facility matures in May 2002. No principal payment is scheduled for amortization prior to maturity. In April 1999, PAA signed a definitive agreement to acquire a West Texas crude oil pipeline and gathering system from Chevron Pipe Line Company for approximately $40 million (the "Chevron Asset Acquisition"). Principal assets to be acquired include approximately 400 miles of crude oil transmission lines, associated gathering and lateral lines and three million barrels of crude oil storage and terminalling capacity in Crane, Ector, Midland, Upton, Ward and Winkler Counties, Texas. Closing of the transaction is subject to regulatory review and approval, consents from third parties, and customary due diligence. Subject to satisfaction of the foregoing conditions, the transaction is expected to close early in the third quarter of 1999. It is anticipated that the Chevron Asset Acquisition will be made by Plains Scurlock, with financing provided by the Plains Scurlock Credit Facility. Chevron will continue transporting crude oil through the pipeline under a contractual arrangement. PAA will also enter into a five-year contractual arrangement to sell up to 30,000 barrels of crude oil per day at market prices to another Chevron entity. Such arrangement may be extended by Chevron for up to five additional years. The system is currently moving an aggregate of approximately 98,000 barrels of crude oil per day under various gathering and transportation arrangements. PAA Distributions PAA will distribute 100% of its Available Cash within 45 days after the end of each quarter to Unitholders of record and to the General Partner. Available Cash is generally defined as all cash and cash equivalents of PAA on hand at the end of each quarter less reserves established by the General Partner for future requirements. Distributions of Available Cash to holders of Subordinated Units are subject to the prior rights of holders of Common Units to receive the minimum quarterly distribution ("MQD") for each quarter during the subordination period (which will not end earlier than December 31, 2003) and to receive any arrearages in the distribution of the MQD on the Common Units for the prior quarters during the subordination period. The MQD is $0.45 per unit ($1.80 per unit on an annual basis). Approximately 10 million of the 17 million Units held by PAAI are Subordinated Units. Upon expiration of the Subordination Period, all Subordinated Units will be converted on a one-for-one basis into Common Units and will participate pro rata with all other Common Units in future distributions of Available Cash. Under certain circumstances, up to 50% of the Subordinated Units may convert into Common Units prior to the expiration of the Subordination Period. Common Units will not accrue arrearages with respect to distributions for any quarter after the Subordination Period and Subordinated Units will not accrue any arrearages with respect to distributions for any quarter. Page 13 of 19 If quarterly distributions of Available Cash exceed the MQD or the Target Distribution Levels (as defined), the General Partner will receive distributions which are generally equal to 15%, then 25% and then 50% of the distributions of Available Cash that exceed the MQD or Target Distribution Level. The Target Distribution Levels are based on the amounts of Available Cash from PAA's Operating Surplus (as defined) distributed with respect to a given quarter that exceed distributions made with respect to the MQD and Common Unit arrearages, if any. On February 12, 1999, PAA paid a cash distribution of $0.193 per unit on its outstanding Common Units and Subordinated Units. The $5.8 million distribution was paid to all Unitholders of record at the close of business on January 29, 1999. A distribution of approximately $3.4 million was paid to the Company for its limited partner and general partner interests with the remainder being distributed to PAA's public Unitholders. The distributions represented a partial quarterly distribution for the 39-day period from November 23, 1998, the closing of the IPO, through December 31, 1998. On April 19, 1999, PAA declared a cash distribution of $0.45 per unit on its outstanding Common Units and Subordinated Units. This distribution is the first full quarterly distribution since PAA was formed. The distribution is payable on May 14, 1999, to holders of record of Common Units and Subordinated Units at the close of business on May 3, 1999. The Company's share of the distribution will be approximately $7.8 million. Credit Facilities The Company has a $225 million revolving credit facility (the "Revolving Credit Facility") with a group of banks (the "Lenders"). The Revolving Credit Facility is guaranteed by all of the Company's upstream subsidiaries and is collateralized by the oil and gas properties of the Company and the guaranteeing subsidiaries and the stock of all upstream subsidiaries. The borrowing base under the Revolving Credit Facility at March 31, 1999, is $225 million and is subject to redetermination from time to time by the Lenders in good faith, in the exercise of the Lenders' sole discretion, and in accordance with customary practices and standards in effect from time to time for oil and natural gas loans to borrowers similar to the Company. Such borrowing base may be affected from time to time by the performance of the Company's oil and natural gas properties and changes in oil and natural gas prices. The Company incurs a commitment fee of 3/8% per annum on the unused portion of the borrowing base. The Revolving Credit Facility, as amended, matures on July 1, 2000, at which time the remaining outstanding balance converts to a term loan which is repayable in twenty equal quarterly installments commencing October 1, 2000, with a final maturity of July 1, 2005. The Revolving Credit Facility bears interest, at the Company's option of either LIBOR plus 1 3/8% or Base Rate (as defined therein). At March 31, 1999, outstanding borrowings under the Revolving Credit Facility were approximately $77 million. Concurrently with the closing of the IPO, PAA entered into a $225 million bank credit agreement (the "Bank Credit Agreement") that includes a $175 million term loan facility (the "Term Loan Facility") and a $50 million revolving credit facility (the "PAA Revolving Credit Facility"). PAA may borrow up to $50 million under the PAA Revolving Credit Facility for acquisitions, capital improvements, working capital and general business purposes. At March 31, 1999, PAA had $175 million outstanding under the Term Loan Facility, representing indebtedness assumed from the General Partner and $6.0 million outstanding under the PAA Revolving Credit Facility. The Term Loan Facility matures in 2005, and no principal is scheduled for payment prior to maturity. The Term Loan Facility may be prepaid at any time without penalty. The PAA Revolving Credit Facility expires in November 2000. PAA has a $175 million letter of credit and borrowing facility (the "Letter of Credit Facility"), the purpose of which is to provide (i) standby letters of credit to support the purchase and exchange of crude oil for resale and (ii) borrowings to finance crude oil inventory which has been hedged against future price risk or designated as working inventory. Aggregate availability under the Letter of Credit Facility for direct borrowings and letters of credit is limited to a borrowing base which is determined monthly based on certain current assets and current liabilities of PAA, primarily crude oil inventory and accounts receivable and accounts payable related to the purchase and sale of crude oil. At March 31, 1999, the borrowing base under the Letter of Credit Facility was $175 million. The Letter of Credit Facility has a $40 million sublimit for borrowings to finance crude oil purchased in connection with operations at PAA's crude oil terminal and storage facilities. At March 31, 1999, there were letters of credit of approximately $73 million and borrowings of $4.1 million outstanding under the Letter of Credit Facility. Page 14 of 19 Investing and Financing Activities At March 31, 1999, the Company had a working capital deficit of approximately $0.8 million compared to a working capital deficit of $13.9 million at December 31, 1998. 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. Net cash flows used in investing activities were $31.2 million and $16.3 million for the three months ended March 31, 1999, and 1998, respectively. Investing activities include payments for acquisition, exploration and development costs of $27.9 million and $15.9 million for the three months ended March 31, 1999 and 1998, respectively. Investing activities for the first quarter of 1999 include payments for crude oil pipeline, gathering and terminal assets of approximately $2.7 million, including approximately $2.4 million related to the expansion of the Company's crude oil terminal and storage facility in Cushing, Oklahoma (the "Cushing Terminal"). Net cash provided by financing activities amounted to $21.7 million and $28.6 million for the three months ended March 31, 1999 and 1998, respectively. Included in both years are net proceeds from borrowings under the Revolving Credit Facility as a result of acquisition, exploration and development activities. Financing activities include approximately $4.3 million and $0.8 million in short-term borrowings for the three months ended March 31, 1999 and 1998, respectively, and approximately $9.9 million and $18 million of repayments for the respective periods, related to contango crude oil inventory transactions at the Cushing Terminal. Changing Oil and Natural Gas Prices The Company's upstream activities are affected by changes in 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, substantial future crude oil price declines would adversely affect 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. In order to manage its exposure to commodity price risk, the Company has routinely hedged a portion of its crude oil production. The Company has entered into various fixed price arrangements which provide the Company with downside price protection on approximately 13,000 barrels of oil per day at a NYMEX WTI crude oil price of approximately $17.45 per barrel for April 1, 1999, through June 30, 1999, and approximately 13,000 barrels of oil per day at a NYMEX WTI crude oil price of $18.30 per barrel for July 1, 1999, through December 31, 1999. Thus, based on the Company's average first quarter 1999 crude oil production rate, these arrangements generally provide the Company with downside price protection for approximately 65% of its crude oil production. For 2000, the Company has entered into various arrangements which will provide for it to receive a minimum price of approximately $15.00 per barrel on 6,000 barrels per day (equivalent to 30% of first quarter 1999 crude oil production levels). Approximately two thirds of the volumes subject to these arrangements will participate in price increases above the $15.00 floor price, subject to a ceiling limitation of $20.00 per barrel. The foregoing NYMEX WTI crude oil prices are before quality and location differentials. Management intends to continue to maintain hedging arrangements for a significant portion of its production. Such contracts may expose the Company to the risk of financial loss in certain circumstances. Year 2000 Year 2000 Issue. Some software applications, hardware and equipment and embedded chip systems identify dates using only the last two digits of the year. These products may be unable to distinguish between dates in the Year 2000 and dates in the year 1900. That inability (referred to as the "Year 2000" issue), if not addressed, could cause applications, equipment or systems to fail or provide incorrect information after December 31, 1999, or when using dates after December 31, 1999. This in turn could have an adverse effect on the Company, because the Company directly depends on its own applications, equipment and systems and indirectly depends on those of other entities with which the Company must interact. Compliance Program. In order to address the Year 2000 issues, the Company has implemented a Year 2000 project for all of its business units. A project team has been established to coordinate the six phases of this Year 2000 project to assure that key automated systems and related processes will remain functional through Year 2000. Those phases include: (i) awareness, (ii) assessment, (iii) remediation, (iv) testing, (v) implementation of the necessary modifications and (vi) contingency planning. The key automated systems consist of (a) financial systems applications, (b) hardware and equipment, (c) embedded chip systems and (d) third-party developed software. The evaluation of the Year 2000 issue includes the evaluation of the Year 2000 exposure of third parties material to the operations of the Company or any of its business units. The Company retained a Year 2000 consulting firm to review the operations of all of its business units and to assess the Page 15 of 19 impact of the Year 2000 issue on such operations. Such review has been completed and the consultant's recommendations are being utilized in the Year 2000 project. The Company's State of Readiness. The awareness phase of the Year 2000 project has begun with a corporate-wide awareness program which will continue to be updated throughout the life of the project. The portion of the assessment phase related to financial systems applications has been completed and the necessary modifications and conversions are underway. The portion of the assessment phase which will determine the nature and impact of the Year 2000 issue for hardware and equipment, embedded chip systems, and third-party developed software is substantially complete. The Company has retained a Year 2000 consulting firm which is currently identifying and evaluating field equipment which has embedded chip systems. The assessment phase of the project involves, among other things, efforts to obtain representations and assurances from third parties, including third party vendors, that their hardware and equipment, embedded chip systems, and software being used by or impacting the Company or any of its business units are or will be modified to be Year 2000 compliant. To date, the responses from such third parties are inconclusive. As a result, management cannot predict the potential consequences if these or other third parties are not Year 2000 compliant. The exposure associated with the Company's interaction with third parties is currently being evaluated. Management expects that the remediation, testing and implementation phases will be completed within the third quarter of 1999. Contingency Planning. As part of the Year 2000 project, the Company will seek to determine which of its business activities may be vulnerable to a Year 2000 disruption. Appropriate contingency plans will then be developed for each "at risk" business activity to provide an alternative means of functioning which minimizes the effect of the potential Year 2000 disruption, both internally and on those with whom it does business. Such contingency plans are expected to be completed by the fourth quarter of 1999. Costs to Address Year 2000 Compliance Issues. Through March 31, 1999, the Company has expended approximately $440,000 in its Year 2000 project, excluding costs borne by PAA. While the total cost to the Company of the Year 2000 project is still being evaluated, the Company currently estimates that the costs to be incurred in 1999 and 2000 associated with assessing, testing, modifying or replacing financial system applications, hardware and equipment, embedded chip systems and third party developed software is between $350,000 and $450,000. The Company expects to fund these expenditures with cash from operations or borrowings. Based upon these estimates, the Company does not expect the costs of its Year 2000 project to have a material adverse effect on its financial position, results of operation or cash flows. Risk of Non-Compliance. The major applications that pose the greatest Year 2000 risks for the Company if implementation of the Year 2000 compliance program is not successful are the Company's financial systems applications and the Company's SCADA computer systems and embedded chip systems in field equipment. The potential problems if the Year 2000 compliance program is not successful are disruptions of the Company's revenue gathering from and distribution to its customers and vendors and the inability to perform its other financial and accounting functions. Failures of embedded chip systems in field equipment of the Company or its customers could disrupt the Company's upstream exploitation, development, production and exploration activities and its midstream crude oil transportation, terminalling and storage activities and gathering and marketing activities. While the Company believes that its Year 2000 project will substantially reduce the risks associated with the Year 2000 issue, there can be no assurance that it will be successful in completing each and every aspect of the project on schedule, and if successful, the project will have the expected results. Due to the general uncertainity inherent in the Year 2000 issues, the Company cannot conclude that its failure or the failure of third parties to achieve Year 2000 compliance will not adversely affect its financial position, results of operations or cash flows. Page 16 of 19 Quantitative and Qualitative Disclosures about Market Risks The Company is exposed to various market risks, including volatility in crude oil and natural gas commodity prices and interest rates. To manage such exposure, the Company enters into various derivative transactions. The Company does not enter into derivative transactions for speculative trading purposes. Substantially all the Company's derivative contracts are exchange traded or with major financial institutions and the risk of credit loss is considered remote. The fair value of outstanding derivative commodity instruments and the change in fair value that would be expected from a 10 percent adverse price change are shown in the table below: Change in Fair Fair Value from 10% At March 31, 1999 Value Adverse Price Change -------------------------- ----------- -------------------- (in millions) Crude Oil Swaps $ 6.2 $ (5.9) Futures contracts (2.6) (4.9) At March 31, 1999, the discussion of the Company's interest rate risk has not changed materially from that presented in the Company's Annual Report on Form 10-K for the year ended December 31, 1998. Forward-Looking Statements and Associated Risks All statements, other than statements of historical facts, included in this report which address activities, events or developments that the Company expects or anticipates will or may occur in the future are forward-looking statements. Such forward-looking statements are subject to risks and uncertainties including, among other things, market conditions, drilling and operating hazards, uncertainties inherent in estimating oil and gas reserves and other factors discussed in the Company's Annual Report on Form 10-K for the year ended December 31, 1998. Page 17 of 19 PART II. OTHER INFORMATION Item 1 - Legal Proceedings None 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 - Exhibits and Reports on Form 8-K A. Exhibits 27. Financial Data Schedule B. Report on Form 8-K None Page 18 of 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: May 14, 1999 By: /s/ Cynthia A. Feeback ----------------------------- Cynthia A. Feeback, Controller; Assistant Treasurer and Principal Accounting Officer (Principal Accounting Officer) Page 19 of 19 EX-27 2 FINANCIAL DATA SCHEDULE
5 THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM PLAINS RESOURCES INC. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEET AS OF MARCH 31, 1999, AND CONSOLIDATED STATEMENT OF INCOME FOR THE THREE MONTHS ENDED MARCH 31, 1999, AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH FINANCIAL STATEMENTS. 3-MOS DEC-31-1999 JAN-01-1999 MAR-31-1999 889 0 161,742 0 28,826 193,921 1,059,037 382,382 1,004,981 194,674 462,721 90,517 22,277 1,689 49,669 1,004,981 476,902 476,971 447,959 455,129 0 0 8,753 4,207 1,641 2,566 0 0 0 2,566 .01 .01
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