10-Q/A 1 0001.txt AMENDMENT #1 FOR QUARTER ENDED SEPTEMBER 30, 2000 ================================================================================ UNITED STATES SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D. C. 20549 FORM 10-Q/A Amendment No. 1 [X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 2000 OR [_] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 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 [_] 17,493,468 shares of common stock $0.10 par value, issued and outstanding at November 8, 2000. ================================================================================ PLAINS RESOURCES INC. AND SUBSIDIARIES TABLE OF CONTENTS PAGE PART I. FINANCIAL INFORMATION CONSOLIDATED FINANCIAL STATEMENTS: Consolidated Balance Sheets: September 30, 2000 and December 31, 1999.......................... 3 Consolidated Statements of Operations: For the three and nine months ended September 30, 2000 and 1999... 4 Consolidated Statements of Cash Flows: For the nine months ended September 30, 2000 and 1999............. 5 Notes to Consolidated Financial Statements............................. 6 MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS............................... 22 PART II. OTHER INFORMATION............................................. 35 2 PLAINS RESOURCES INC. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (in thousands)
September 30, December 31, 2000 1999 --------------- --------------- (unaudited) ASSETS CURRENT ASSETS Cash and cash equivalents $ 9,866 $ 68,228 Accounts receivable and other current assets 411,539 521,948 Inventory 29,548 40,478 Assets held for sale (Note 4) - 141,486 ---------- ---------- Total current assets 450,953 772,140 ---------- ---------- PROPERTY AND EQUIPMENT Oil and natural gas properties - full cost method Subject to amortization 718,879 671,928 Not subject to amortization 55,436 52,031 Crude oil pipeline, gathering and terminal assets 465,247 458,502 Other property and equipment 9,061 7,706 ---------- ---------- 1,248,623 1,190,167 Less allowance for depreciation, depletion and amortization (429,874) (402,514) ---------- ---------- 818,749 787,653 ---------- ---------- OTHER ASSETS 102,179 129,767 ---------- ---------- $1,371,881 $1,689,560 ========== ========== LIABILITIES AND STOCKHOLDERS' EQUITY CURRENT LIABILITIES Accounts payable and other current liabilities $ 418,719 $ 546,393 Notes payable and other current obligations 511 109,880 ---------- ---------- Total current liabilities 419,230 656,273 BANK DEBT 13,000 137,300 BANK DEBT OF A SUBSIDIARY 292,000 259,450 SUBORDINATED DEBT 277,639 277,909 OTHER LONG-TERM DEBT 1,533 2,044 OTHER LONG-TERM LIABILITIES AND DEFERRED CREDITS 3,740 21,107 ---------- ---------- 1,007,142 1,354,083 ---------- ---------- MINORITY INTEREST 166,655 156,045 ---------- ---------- CUMULATIVE CONVERTIBLE PREFERRED STOCK, STATED AT LIQUIDATION PREFERENCE 137,721 138,813 ---------- ---------- NON-REDEEMABLE PREFERRED STOCK, COMMON STOCK AND OTHER STOCKHOLDERS' EQUITY Series D Cumulative Convertible Preferred Stock 23,300 23,300 Common Stock 1,814 1,792 Additional paid-in capital 132,782 130,027 Accumulated deficit (93,312) (114,500) Treasury stock, at cost (4,221) - ---------- ---------- 60,363 40,619 ---------- ---------- $ 1,371,881 $ 1,689,560 =========== ===========
See notes to consolidated financial statements. 3 PLAINS RESOURCES INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF OPERATIONS (in thousands, except per share data) (unaudited)
Three Months Ended Nine Months Ended September 30, September 30, ---------------------------- ---------------------------- 2000 1999 2000 1999 ------------- ------------- ------------- ------------ (restated) (restated) REVENUES Oil and natural gas sales $ 38,610 $ 34,654 $ 109,192 $ 80,985 Marketing, transportation, storage and terminalling revenues 703,944 1,098,506 2,347,826 2,416,116 Gain on sale of assets (Note 4) - - 48,188 - Interest and other income 689 359 7,278 666 -------- ---------- ---------- ---------- 743,243 1,133,519 2,512,484 2,497,767 -------- ---------- ---------- ---------- EXPENSES Production expenses 15,934 16,326 46,612 39,989 Marketing, transportation, storage and terminalling expenses 671,791 1,066,567 2,247,163 2,338,873 Unauthorized trading losses and related expenses (Note 3) 6,600 72,250 6,600 114,925 General and administrative 11,970 10,845 33,565 22,562 Depreciation, depletion and amortization 10,768 10,108 36,064 25,553 Interest expense 13,095 13,151 41,912 32,668 -------- ---------- ---------- ---------- 730,158 1,189,247 2,411,916 2,574,570 -------- ---------- ---------- ---------- Income (loss) before income taxes, minority interest and extraordinary item 13,085 (55,728) 100,568 (76,803) Minority interest 2,047 (23,786) 39,451 (32,014) -------- ---------- ---------- ---------- Income (loss) before income taxes and extraordinary item 11,038 (31,942) 61,117 (44,789) Income tax expense (benefit) Current 220 - 741 - Deferred 4,084 (11,895) 23,094 (16,465) -------- ---------- ---------- ---------- Income (loss) before extraordinary item 6,734 (20,047) 37,282 (28,324) Extraordinary item, net of tax benefit and minority interest - - (4,988) - -------- ---------- ---------- ---------- NET INCOME (LOSS) 6,734 (20,047) 32,294 (28,324) Less: cumulative preferred stock dividends 3,694 2,493 11,106 7,327 -------- ---------- ---------- ---------- NET INCOME (LOSS) AVAILABLE TO COMMON STOCKHOLDERS $ 3,040 $ (22,540) $ 21,188 $ (35,651) ======== ========== ========== ========== Basic earnings (loss) per share Income (loss) before extraordinary item $ 0.17 $ (1.30) $ 1.46 $ (2.09) Extraordinary item - - (0.28) - -------- ---------- ---------- ---------- Net income (loss) $ 0.17 $ (1.30) $ 1.18 $ (2.09) ======== ========== ========== ========== Diluted earnings (loss) per share Income (loss) before extraordinary item $ 0.16 $ (1.30) $ 1.26 $ (2.09) Extraordinary item - - (0.17) - -------- ---------- ---------- ---------- Net income (loss) $ 0.16 $ (1.30) $ 1.09 $ (2.09) ======== ========== ========== ==========
See notes to consolidated financial statements. 4 PLAINS RESOURCES INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (IN THOUSANDS) (UNAUDITED)
Nine Months Ended September 30, ----------------------------- 2000 1999 ------------- -------------- (restated) CASH FLOWS FROM OPERATING ACTIVITIES Net income (loss) $ 32,294 $ (28,324) Items not affecting cash flows from operating activities: Depreciation, depletion and amortization 36,064 25,553 Gain on sale of assets (Note 4) (48,188) - Minority interest in income of a subsidiary 32,484 (32,014) Deferred income taxes 19,904 (16,465) Noncash compensation expense 2,269 1,947 Other noncash items 10,634 1,221 Change in assets and liabilities from operating activities: Accounts receivable and other current assets 79,684 (159,561) Inventory 10,930 (37,551) Pipeline linefill (13,397) (3) Accounts payable and other current liabilities (137,204) 242,290 Other long-term liabilities and deferred credits (8,000) 10,873 ----------- -------- Net cash provided by operating activities 17,474 7,966 ----------- -------- CASH FLOWS FROM INVESTING ACTIVITIES Costs incurred in connection with acquisitions - (173,070) Payments for crude oil pipeline, gathering and terminal assets (6,859) (7,785) Payments for acquisition, exploration and development costs (49,850) (57,692) Payments for additions to other property and assets (2,205) (469) Proceeds from sale of assets (Note 4) 223,859 - ----------- -------- Net cash provided by (used in) investing activities 164,945 (239,016) ----------- -------- CASH FLOWS FROM FINANCING ACTIVITIES Proceeds from long-term debt 921,825 508,321 Proceeds from short-term debt 47,750 42,150 Principal payments of long-term debt (1,064,736) (286,132) Principal payments of short-term debt (106,469) (21,650) Purchase of treasury stock (4,221) - Proceeds from warrant exercise - 4,500 Costs incurred in connection with financing arrangements (6,500) (4,652) Preferred stock dividends paid (6,392) - Distributions to unitholders of subsidiary (21,966) (14,465) Other (72) 306 ----------- -------- Net cash provided by (used in) financing activities (240,781) 228,378 ----------- -------- Net decrease in cash and cash equivalents (58,362) (2,672) Cash and cash equivalents, beginning of period 68,228 6,544 ----------- -------- Cash and cash equivalents, end of period $ 9,866 $ 3,872 =========== ========
See notes to consolidated financial statements. 5 PLAINS RESOURCES INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) Note 1 -- Organization and Accounting Policies The consolidated financial statements include the accounts of Plains Resources Inc., our wholly owned subsidiaries and Plains All American Pipeline, L.P. ("PAA"), in which we have an approximate 54% ownership interest. Plains All American Inc., one of our wholly owned subsidiaries, serves as PAA's sole general partner. For financial statement purposes, the assets, liabilities and results of operations of PAA are included in our consolidated financial statements, with the public unitholders' interest reflected as a minority interest. The accompanying consolidated financial statements and related notes present our consolidated financial position as of September 30, 2000 and December 31, 1999, the results of our operations for the three and nine months ended September 30, 2000 and 1999, and cash flows for the nine months ended September 30, 2000 and 1999. The financial statements have been prepared in accordance with the instructions to interim reporting as prescribed by the Securities and Exchange Commission ("SEC"). For further information, refer to our Form 10-K/A for the year ended December 31, 1999, filed with the SEC. All adjustments, consisting only of normal recurring adjustments, that in the opinion of management were necessary for a fair statement of the results for the interim periods, have been reflected. All significant intercompany transactions have been eliminated. The results for the three and nine months ended September 30, 2000 are not necessarily indicative of the final results to be expected for the full year. Certain reclassifications have been made to prior periods to conform to the current period presentation. We evaluate the capitalized costs of our oil and natural gas properties on an ongoing basis and have utilized the most recently available information to estimate our reserves at September 30, 2000, 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. Accounting Pronouncements In June 1998, the Financial Accounting Standards Board ("FASB") issued Statement of Financial Accounting Standards ("SFAS") No. 133, Accounting for Derivative Instruments and Hedging Activities ("SFAS 133"). SFAS 133 was subsequently amended (i) in June 1999 by SFAS No. 137, Accounting for Derivative Instruments and Hedging Activities - Deferral of the effective date of FASB Statement No. 133 ("SFAS 137"), which deferred the effective date of SFAS 133 to fiscal years beginning after June 15, 2000; and (ii) in June 2000 by SFAS 138, "Accounting for Certain Derivative Instruments and Certain Hedge Activities," which amended certain provisions, inclusive of the definition of the normal purchase and sale exclusion. SFAS 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 so, the type of hedge transaction. For fair value hedge transactions in which we are hedging changes in the fair value of an asset, liability, or firm commitment, changes in the fair value of the derivative instrument will generally be offset in the income statement by changes in the fair value of the hedged item. For cash flow hedge transactions, in which we are 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 ineffective portion of all hedges will be recognized in earnings in the current period. We will adopt SFAS 133, as amended, effective January 1, 2001. We believe we have identified all instruments currently in place that will be subject to the requirements of SFAS 133, however, due to the complex nature of SFAS 133 and various interpretations regarding applications of SFAS 133 to certain instruments, we have not fully determined what impact the adoption of SFAS 133 would have on the consolidated balance sheets, statements of operations and cash flows. The FASB has formed a derivative implementation group which is addressing assessment and implementation matters regarding the application of SFAS 133 for consideration by the FASB. Adoption of this standard could increase volatility in earnings and retained earnings (deficit) through comprehensive income. 6 NOTE 2 -- INVENTORY AND OTHER ASSETS Inventory consists of the following (in thousands): September 30, December 31, 2000 1999 ------------- ------------ Crude oil $ 24,164 $ 35,664 Materials and supplies 5,384 4,814 -------- -------- $ 29,548 $ 40,478 ======== ======== Other assets consist of the following (in thousands): September 30, December 31, 2000 1999 --------------- -------------- Pipeline linefill $ 31,030 $ 17,633 Deferred tax asset 47,745 67,366 Land 8,853 8,853 Debt issue costs, net 12,000 26,530 Other, net 2,551 9,385 -------- -------- $102,179 $129,767 ======== ======== NOTE 3 -- UNAUTHORIZED TRADING LOSSES AND RESTATED FINANCIAL STATEMENTS In November 1999, we discovered that a former employee of PAA had engaged in unauthorized trading activity, resulting in losses of approximately $162.0 million ($174.0 million, including estimated associated costs and legal expenses at December 31, 1999). A full investigation into the unauthorized trading activities by outside legal counsel and independent accountants and consultants determined that the vast majority of the losses occurred primarily from March through November 1999, and that the impact warranted a restatement of previously reported financial information for 1999 and 1998. Because the financial statements of PAA are consolidated with our financial statements, adverse effects on the financial statements of PAA directly affect our consolidated financial statements. Consequently, the consolidated financial statements for 1999 appearing in this report were previously restated to reflect the unauthorized trading losses. During the third quarter of 2000, we recognized an additional $6.6 million charge for litigation related to the unauthorized trading losses (See Note 11). NOTE 4 -- ASSET DISPOSITIONS We initiated the sale of approximately 5.2 million barrels of crude oil linefill from the All American Pipeline in November 1999. This sale was completed in March 2000. The linefill was located in the segment of the All American Pipeline that extends from Emidio, California, to McCamey, Texas. Except for minor third party volumes, Plains Marketing L.P., one of PAA's subsidiaries, has been the sole shipper on this segment of the pipeline since its predecessor acquired the line from Goodyear in July 1998. Proceeds from the sale of the linefill were approximately $100.0 million, net of associated costs, and were used (1) to repay outstanding indebtedness under PAA's $65.0 million senior secured term credit facility entered into in December 1999 to fund short- term working capital requirements resulting from the unauthorized trading losses and (2) for general working capital purposes. We recognized a total gain of $44.6 million, of which $16.5 million was recorded in the fourth quarter of 1999. The amount of crude oil linefill for sale at December 31, 1999 was $37.9 million and is included in assets held for sale on the consolidated balance sheet at such date. On March 24, 2000, we completed the sale of the above referenced segment of the All American Pipeline to a unit of El Paso Energy Corporation for proceeds of approximately $124.0 million, which are net of associated transaction costs and estimated costs to remove certain equipment. We recognized a gain of approximately $20.1 million in connection with the sale in the first quarter of 2000. Proceeds from the sale were used to permanently reduce the All American Pipeline, L.P. term loan facility (see Note 6). The cost of the pipeline segment is included in assets held for sale on the consolidated balance sheet at December 31, 1999. 7 NOTE 5 -- DEBT On May 8, 2000, PAA entered into new bank credit agreements. The borrower under the new facilities is Plains Marketing, L.P. PAA is a guarantor of the obligations under the credit facilities. The obligations are also guaranteed by the subsidiaries of Plains Marketing, L.P. PAA entered into the credit agreements in order to: . refinance the existing bank debt of Plains Marketing, L.P. and Plains Scurlock Permian, L.P. in conjunction with the merger of Plains Scurlock Permian, L.P. into All American Pipeline, L.P.; . refinance existing bank debt of All American Pipeline, L.P.; . repay us $114.0 million plus accrued interest of subordinated debt, and . provide additional flexibility for working capital, capital expenditures, and for other general corporate purposes. PAA's new bank credit agreements consist of: . a $400.0 million senior secured revolving credit facility. The revolving credit facility is secured by substantially all of PAA's assets and matures in April 2004. No principal is scheduled for payment prior to maturity. The revolving credit facility bears interest at PAA's option at either the base rate, as defined, plus an applicable margin, or LIBOR plus an applicable margin. PAA incurs a commitment fee on the unused portion of the revolving credit facility. At September 30, 2000, $292.0 million was outstanding on the revolving credit facility. . A $300.0 million senior secured letter of credit and borrowing facility, the purpose of which is to provide standby letters of credit to support the purchase and exchange of crude oil for resale and borrowings to finance crude oil inventory that has been hedged against future price risk. The letter of credit facility is secured by substantially all of PAA's assets and has a sublimit for cash borrowings of $100.0 million to purchase crude oil that has been hedged against future price risk. The letter of credit facility expires in April 2003. 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 of PAA's current assets and current liabilities (primarily inventory and accounts receivable and accounts payable related to the purchase and sale of crude oil). At September 30, 2000, approximately $79.5 million in letters of credit were outstanding under the letter of credit and borrowing facility. PAA's bank credit agreements prohibit distributions on, or purchases or redemptions of, units if any default or event of default is continuing. In addition, the agreements contain various covenants limiting PAA's ability to, among other things: . incur indebtedness; . grant liens; . sell assets; . make investments; . engage in transactions with affiliates; . enter into prohibited contracts; and . enter into a merger or consolidation. PAA's bank credit agreements treat a change of control as an event of default and also require PAA to maintain: . a current ratio (as defined) of 1.0 to 1.0; . a debt coverage ratio that is not greater that 4.0 to 1.0 for the period from March 31, 2000 to March 31, 2002 and subsequently 3.75 to 1.0; . an interest coverage ratio that is not less than 2.75 to 1.0; and . a debt to capital ratio of not greater than 0.65 to 1.0. At September 30, 2000, the carrying value of all variable rate bank debt of $305.0 million approximated the fair value and liquidation value at that date. The carrying value and fair value of the fixed rate debt was $277.0 million and $282.1 million, respectively, at that date. The carrying value and estimated fair value of redeemable preferred stock were $137.7 million and $198.3 million, respectively, at September 30, 2000. At December 31, 1999, the carrying value of all variable rate bank debt and the redeemable preferred stock of $506.1 million and $138.8 million, respectively, approximated the fair value and liquidation value at that date. The carrying value and fair value of the fixed rate debt was $277.5 million and $270.7 million, respectively, at that date. The fair value of fixed rate debt was based on quoted market prices based on trades of our subordinated debt. 8 Interest rate swaps and collars are used to hedge underlying debt obligations. These instruments hedge specific debt issuances and qualify for hedge accounting. The interest rate differential is reflected as an adjustment to interest expense over the life of the instruments. At September 30, 2000, we had interest rate swap and collar arrangements for an aggregate notional principal amount of $240.0 million, which positions had an aggregate value of approximately $0.6 million as of such date. These instruments are based on LIBOR and generally provide for a floor of 5% and a ceiling of 6.5% for $90.0 million of debt, a floor of 6% and a ceiling of 8% for $125.0 million of debt and 5.7% for $25.0 million of debt. NOTE 6 -- EXTRAORDINARY ITEM During the nine months ended September 30, 2000, we recognized extraordinary losses consisting primarily of unamortized debt issue costs, of $5.0 million (net of minority interest of $7.0 million and deferred tax of $3.2 million) related to PAA's early extinguishment of debt and refinancing of its credit agreements (see Notes 4 and 5). Note 7 -- Treasury Stock At September 30, 2000 and December 31, 1999, we had 46,600 shares of Series D Cumulative Convertible Preferred Stock, $1.00 par value, authorized, issued and outstanding. At September 30, 2000 and December 31, 1999, we had 50,000,000 shares of common stock, $0.10 par value, authorized. At September 30, 2000 and December 31, 1999, 18,139,727 shares and 17,924,050 shares, respectively, were issued and 17,880,827 shares and 17,924,050 shares, respectively, were outstanding. In June 2000, our Board of Directors authorized the repurchase of up to one million shares of our common stock. As of September 30, 2000, we had repurchased 258,900 common shares at a cost of $4.2 million. In October 2000, we repurchased an additional 606,000 common shares for approximately $11.5 million. On November 9, 2000, our Board authorized the repurchase of an additional one million shares. NOTE 8 -- EARNINGS PER SHARE The following is a reconciliation of the numerators and the denominators of the basic and diluted earnings (loss) per share computations for income (loss) from continuing operations before extraordinary items for the three and nine months ended September 30, 2000 and 1999 (in thousands, except per share amounts):
For the Three Months Ended September 30, --------------------------------------------------------------------------- 2000 1999 (restated) ----------------------------------- ------------------------------------- Income Shares Per Income Shares Per (Numera- (Denomi- Share (Numera- (Denomi- Share tor) nator) Amount tor) nator) Amount ---------- ---------- --------- ---------- ---------- ----------- Net income (loss) before extraordinary item $ 6,734 $(20,047) Less: preferred stock dividends (3,694) (2,493) -------- -------- Income (loss) available to common stockholders 3,040 17,970 $ 0.17 (22,540) 17,311 $ (1.30) ====== ======= Effect of dilutive securities: Convertible preferred stock - - - - Employee stock options and warrants - 968 - - -------- ------ -------- ------ Income (loss) available to common stockholders assuming dilution $ 3,040 18,938 $ 0.16 $(22,540) 17,311 $ (1.30) ======== ====== ====== ======== ====== ======= For the Nine Months Ended September 30, --------------------------------------------------------------------------- 2000 1999 (restated) ----------------------------------- ------------------------------------- Income Shares Per Income Shares Per (Numera- (Denomi- Share (Numera- (Denomi- Share tor) nator) Amount tor) nator) Amount ---------- ---------- --------- ---------- ---------- ----------- Net income (loss) before extraordinary item $ 37,282 $(28,324) Less: preferred stock dividends (11,106) (7,327) -------- -------- Income (loss) available to common stockholders 26,176 17,963 $ 1.46 (35,651) 17,040 $ (2.09) ====== ======= Effect of dilutive securities: Convertible preferred stock 11,106 10,862 - - Employee stock options and warrants - 800 - - -------- ------ -------- ------ Income (loss) available to common stockholders assuming dilution $ 37,282 29,625 $ 1.26 $(35,651) 17,040 $ (2.09) ======== ====== ====== ======== ====== =======
9 NOTE 9 -- OPERATING SEGMENTS Our 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 pipeline transportation, purchases and resales of crude oil at various points along the distribution chain and the leasing of certain terminalling and storage facilities. We evaluate performance based on gross margin, gross profit and income (loss) before income taxes, minority interest and extraordinary items.
(in thousands) (unaudited) Upstream Midstream Total ------------------------------------------------------------------------------------------------------------- For the Three Months Ended September 30, 2000 Revenues: External Customers $ 38,610 $ 703,944 $ 742,554 Intersegment (a) - 52,982 52,982 Other income (expense) 372 317 689 -------- ---------- ---------- Total revenues of reportable segments $ 38,982 $ 757,243 $ 796,225 ======== ========== ========== Segment gross margin (b) $ 22,676 $ 25,553 $ 48,229 Segment gross profit (c) 20,624 15,635 36,259 Segment income before income taxes, minority interest and extraordinary item 9,068 4,017 13,085 ------------------------------------------------------------------------------------------------------------- For the Three Months Ended September 30, 1999 (restated) Revenues: External Customers $ 34,654 $1,098,506 $1,133,160 Intersegment (a) - 29,302 29,302 Other income (expense) 29 330 359 -------- ---------- ---------- Total revenues of reportable segments $ 34,683 $1,128,138 $1,162,821 ======== ========== ========== Segment gross margin (b) $ 18,328 $ (40,311) $ (21,983) Segment gross profit (c) 16,777 (49,605) (32,828) Segment income (loss) before income taxes and minority interest 4,900 (60,628) (55,728) ------------------------------------------------------------------------------------------------------------- For the Nine Months Ended September 30, 2000 Revenues: External Customers $109,192 $2,347,826 $2,457,018 Intersegment (a) - 147,386 147,386 Gain on sale of assets - 48,188 48,188 Other income (expense) (3,633) 10,911 7,278 -------- ---------- ---------- Total revenues of reportable segments $105,559 $2,554,311 $2,659,870 ======== ========== ========== Segment gross margin (b) $ 62,580 $ 94,063 $ 156,643 Segment gross profit (c) 55,579 67,499 123,078 Segment income before income taxes, minority interest and extraordinary item 15,872 84,696 100,568 ------------------------------------------------------------------------------------------------------------- For the Nine Months Ended September 30, 1999 (restated) Revenues: External Customers $ 80,985 $2,416,116 $2,497,101 Intersegment (a) - 29,976 29,976 Other income (expense) 48 618 666 -------- ---------- ---------- Total revenues of reportable segments $ 81,033 $2,446,710 $2,527,743 ======== ========== ========== Segment gross margin (b) $ 40,996 $ (37,682) $ 3,314 Segment gross profit (c) 35,962 (55,210) (19,248) Segment income (loss) before income taxes and minority interest 3,726 (80,529) (76,803) -------------------------------------------------------------------------------------------------------------
a) Intersegment sales were conducted on an arm's length basis. b) Gross margin is calculated as revenues less cost of sales and operations. c) Gross profit is calculated as revenues less costs of sales and operations and general and administrative expenses. 10 NOTE 10 -- PREFERRED STOCK DIVIDENDS On April 1, 2000, we paid cash dividends of approximately $6.0 million on our Series D, F and G preferred stock. The dividends on the Series D preferred stock are for the period from January 1, 2000 through March 31, 2000. The Series F preferred stock was issued on December 15, 1999 and such dividend covers the period from that date through March 31, 2000. The dividends on the Series G preferred stock are for the period from October 1, 1999 through March 31, 2000. On July 19, 2000, we paid cash dividends of approximately $0.3 million on our Series D preferred stock covering the period from April 1, 2000 through June 30, 2000. On October 1, 2000, we paid cash dividends of approximately $7.0 million on our Series D, F and G preferred stock. The dividends on the Series D preferred stock are for the period from July 1, 2000 through September 30, 2000. The dividends on the Series F and G preferred stock are for the period from April 1, 2000 through September 30, 2000. NOTE 11 -- CONTINGENCIES Texas Securities Litigation. On November 29, 1999, a class action lawsuit was filed in the United States District Court for the Southern District of Texas entitled Di Giacomo v. Plains All American Pipeline, L.P. ("PAA"), et al. The suit alleged that PAA and certain of its general partner's officers and directors violated federal securities laws, primarily in connection with unauthorized trading by a former employee. An additional nineteen cases have been filed in the Southern District of Texas, some of which name the general partner and us as additional defendants. All of the federal securities claims are being consolidated into two actions. The first consolidated action is that filed by purchasers of our common stock and options, and is captioned Koplovitz v. Plains Resources Inc., et al. The second consolidated action is that filed by purchasers of PAA's common units, and is captioned Di Giacomo v. Plains All American Pipeline, L.P., et al. Plaintiffs alleged that the defendants were liable for securities fraud violations under Rule 10b-5 and Section 20(a) of the Securities Exchange Act of 1934 and for making false registration statements under Sections 11 and 15 of the Securities Act of 1933. We and PAA have reached an agreement in principle with representatives for the plaintiffs for the settlement of all of the federal securities actions. Aggregate amounts to be paid under the agreement in principle total approximately $29.5 million plus interest from October 1, 2000 through the date actual proceeds are remitted to representatives for the plaintiffs. Our insurance carrier has deposited $15.0 million to an escrow account to fund amounts payable under our insurance policies. The Boards of Directors of PAA and Plains Resources have formed special independent committees to review and approve final allocation of the settlement costs between PAA and us. Based on an estimate of such allocation, which allocation is currently under review by the committees, in the third quarter of 2000 we accrued an additional $6.6 million of litigation costs and related expenses, which reduced basic earnings per common share after minority interest and taxes for the three and nine months ended September 30, 2000 by $0.12 ($0.11 diluted) and $0.12 ($0.07 diluted), respectively. The settlement is subject to a number of conditions, including negotiation and finalization of a stipulation and agreement of settlement and related documentation, and approval of the United States District Court for the Southern District of Texas. The agreement in principle does not affect the Texas Derivative Litigation and Delaware Derivative Litigation described below. Texas Derivative Litigation. On July 11, 2000, a derivative lawsuit was filed in the United States District Court for the Southern District of Texas entitled Fernandez v. Plains All American Inc., et al., naming the general partner, its directors and certain of its officers as defendants. This lawsuit contains the same claims and seeks the same relief as the Delaware derivative litigation described below. A motion to dismiss was filed on behalf of the defendants on August 14, 2000. Delaware Derivative Litigation. On December 3, 1999, two derivative lawsuits were filed in the Delaware Chancery Court, New Castle County, entitled Susser v. Plains All American Inc., et al and Senderowitz v. Plains All American Inc., et al. These suits, and three others which were filed in Delaware subsequently, named the general partner, its directors and certain of its officers as defendants, and allege that the defendants breached the fiduciary duties that they owed to PAA and its unitholders by failing to monitor properly the activities of its employees. The court has consolidated all of the cases under the caption In Re Plains All American Inc. Shareholders Litigation, and has designated the complaint filed in Sussex v. Plains All American Inc. as the operative complaint in the consolidated action. A motion to dismiss was filed on behalf of the defendants on August 11, 2000. 11 The plaintiffs in the Delaware securities litigation seek that the defendants (1) account for all losses and damages allegedly sustained by Plains All American from the unauthorized trading losses, (2) establish and maintain effective internal controls ensuring that PAA's affiliates and persons responsible for its affairs do not engage in wrongful practices detrimental to Plains All American, (3) account for the plaintiffs' costs and expenses in litigation, including reasonable attorneys' fees, accountants' fees, and experts' fees and (4) provide the plaintiffs any additional relief as may be just and proper under the circumstances. We intend to vigorously defend the claims made against us in the Texas derivative litigation and the Delaware derivative litigation. However, there can be no assurance that we will be successful in our defense or that these lawsuits will not have a material adverse effect on our financial position, results of operations or cash flows. On July 9, 1987, Exxon Corporation ("Exxon") filed an interpleader action in the United States District Court for the Middle District of Florida, Exxon Corporation v. E. W. Adams, et al., Case Number 87-976-CIV-T-23-B. This action was filed by Exxon to interplead royalty funds as a result of a title controversy between certain mineral owners in a field in Florida. One group of mineral owners, John W. Hughes, et al. (the "Hughes Group"), filed a counterclaim against Exxon alleging fraud, conspiracy, conversion of funds, declaratory relief, federal and Florida RICO, breach of contract and accounting, as well as challenging the validity of certain oil and natural gas leases owned by Exxon, and seeking exemplary and treble damages. In March 1993, but effective November 1, 1992, Calumet Florida Inc. ("Calumet"), our wholly owned subsidiary, acquired all of Exxon's leases in the field affected by this lawsuit. In order to address those counterclaims challenging the validity of certain oil and natural gas leases, which constitute approximately 10% of the land underlying this unitized field, Calumet filed a motion to join Exxon as plaintiff in the subject lawsuit, which was granted July 29, 1994. In August 1994, the Hughes Group amended its counterclaim to add Calumet as a counter-defendant. Exxon and Calumet filed a motion to dismiss the counterclaims. On March 22, 1996, the Court granted Exxon's and Calumet's motion to dismiss the counterclaims alleging fraud, conspiracy, and federal and Florida RICO violations and challenging the validity of certain of our oil and natural gas leases but denied such motion as to the counterclaim alleging conversion of funds. Effective January 1, 2000, Calumet settled all of the Hughes claims against Calumet with a payment to the Hughes group of the total sum of $100,000. The remaining defendants filed a writ seeking to stay the trial but no relief was granted prior to the trial date. Trial was held on June 19, 2000. By final judgment dated August 18, 2000, the court dismissed all claims by the Hughes group and the remaining defendants against Calumet. The remaining defendants have appealed the judgment. We, in the ordinary course of business, are a claimant and/or a defendant in various other legal proceedings. Management does not believe that the outcome of these other legal proceedings, individually and in the aggregate, will have a materially adverse effect on our financial condition, results of operations or cash flows. Derivatives. We utilize derivative financial instruments to hedge our exposure to price volatility on crude oil. We have entered into various arrangements to fix the NYMEX crude oil spot price for a significant portion of our crude oil production. For the fourth quarter of 2000, we have entered into various arrangements which provide for us to receive an average minimum NYMEX WTI price of $16.25 per barrel on 18,500 barrels of oil per day. Approximately 10,000 barrels per day of these volumes will participate in price increases up to $19.75 per barrel. For 2001, we have entered into various arrangements, using a combination of swaps, collars and purchased puts and calls, which will provide for us to receive an average minimum NYMEX price of approximately $22.75 per barrel on 20,500 barrels per day with almost full market price participation up to an average of $27.00 per barrel. For 2002, we have entered into various arrangements that provide for us to receive an average minimum NYMEX WTI price of $23.00 per barrel on 10,000 barrels per day with full market price participation up to an average of $24.90 per barrel. Location and quality differentials attributable to our properties are not included in the foregoing prices. The agreements provide for monthly settlement based on the differential between the agreement price and the actual NYMEX crude oil price. Gains or losses are recognized in the month of related production and are included in crude oil and natural gas sales. Such contracts resulted in a reduction in revenues of $22.2 million and $56.7 million in the third quarter and first nine months of 2000, respectively. The unrealized loss at September 30, 2000, with respect to such contracts was $24.0 million. At September 30, 2000, our hedging activities included crude oil futures contracts maturing through 2001, covering approximately 6.9 million barrels of crude oil. Since such contracts are designated as hedges and correlate to price movements of crude oil, any gains or losses resulting from market changes will be largely offset by losses or gains on our hedged inventory or anticipated purchases of crude oil. Such contracts resulted in a reduction in revenues of $1.2 million in the third quarter of 2000 and an increase in revenues of $0.1 million in the nine months ended September 30, 2000. The unrealized loss at September 30, 2000, with respect to such contracts was $7.0 million. 12 NOTE 12 -- CONSOLIDATING FINANCIAL STATEMENTS The following financial information presents consolidating financial statements which include: . the parent company only ("Parent"); . the guarantor subsidiaries on a combined basis ("Guarantor Subsidiaries"); . the nonguarantor subsidiaries on a combined basis ("Nonguarantor Subsidiaries"); . elimination entries necessary to consolidate the Parent, the Guarantor Subsidiaries and the Nonguarantor Subsidiaries; and . Plains Resources Inc. on a consolidated basis. These statements are presented because our Series A-E subordinated notes are not guaranteed by PAA and our consolidated financial statements include the accounts of PAA. 13 PLAINS RESOURCES RESOURCES INC. AND SUBSIDIARIES CONDENSED CONSOLIDATING BALANCE SHEET (UNAUDITED) (IN THOUSANDS) SEPTEMBER 30, 2000
GUARANTOR NONGUARANTOR INTERCOMPANY PARENT SUBSIDIARIES SUBSIDIARIES ELIMINATIONS CONSOLIDATED ---------- ------------ ------------ ------------ ------------ ASSETS CURRENT ASSETS Cash and cash equivalents $ 5,168 $ 388 $ 4,310 $ - $ 9,866 Accounts receivable and other 17,576 11,050 382,913 - 411,539 Inventory - 7,261 22,287 - 29,548 --------- --------- -------- --------- ---------- Total current assets 22,744 18,699 409,510 - 450,953 --------- --------- -------- --------- ---------- PROPERTY AND EQUIPMENT 237,087 543,203 468,333 - 1,248,623 Less allowance for depreciation, depletion and amortization (217,335) (133,268) (23,885) (55,386) (429,874) --------- --------- -------- --------- ---------- 19,752 409,935 444,448 (55,386) 818,749 --------- --------- -------- --------- ---------- INVESTMENTS IN SUBSIDIARIES AND INTERCOMPANY ADVANCES 317,690 (222,305) (28,327) (67,058) - OTHER ASSETS 40,042 3,758 58,379 - 102,179 --------- --------- -------- --------- ---------- $ 400,228 $ 210,087 $884,010 $(122,444) $1,371,881 ========= ========= ======== ========= ========== LIABILITIES AND STOCKHOLDERS' EQUITY CURRENT LIABILITIES Accounts payable and other current liabilities $ 26,754 $ 42,953 $349,034 $ (22) $ 418,719 Notes payable and other current obligations - 511 - - 511 --------- --------- -------- --------- ---------- Total current liabilities 26,754 43,464 349,034 (22) 419,230 BANK DEBT 13,000 - - - 13,000 BANK DEBT OF A SUBSIDIARY - - 292,000 - 292,000 SUBORDINATED DEBT 277,639 - - - 277,639 OTHER LONG-TERM DEBT - 1,533 - - 1,533 OTHER LONG-TERM LIABILITIES 2,140 - 1,600 - 3,740 --------- --------- -------- --------- ---------- 319,533 44,997 642,634 (22) 1,007,142 --------- --------- -------- --------- ---------- MINORITY INTEREST (70,037) - 236,600 92 166,655 --------- --------- -------- --------- ---------- CUMULATIVE CONVERTIBLE PREFERRED STOCK, STATED AT LIQUIDATION PREFERENCE 137,721 - - - 137,721 --------- --------- -------- --------- ---------- NON-REDEEMABLE PREFERRED STOCK, COMMON STOCK AND OTHER STOCKHOLDERS' EQUITY Series D Cumulative Convertible Preferred Stock 23,300 - - - 23,300 Common Stock 1,814 78 - (78) 1,814 Additional paid-in capital 132,782 3,951 45,530 (49,481) 132,782 Retained earnings (accumulated deficit) (140,664) 161,061 (40,754) (72,955) (93,312) Treasury stock, at cost (4,221) - - - (4,221) --------- --------- -------- --------- ---------- 13,011 165,090 4,776 (122,514) 60,363 --------- --------- -------- --------- ---------- $ 400,228 $ 210,087 $884,010 $(122,444) $1,371,881 ========= ========= ======== ========= ==========
14 PLAINS RESOURCES INC. AND SUBSIDIARIES CONDENSED CONSOLIDATING BALANCE SHEET (IN THOUSANDS) DECEMBER 31, 1999
GUARANTOR NONGUARANTOR INTERCOMPANY PARENT SUBSIDIARIES SUBSIDIARIES ELIMINATIONS CONSOLIDATED ---------- ------------ ------------ ------------ ------------ ASSETS CURRENT ASSETS Cash and cash equivalents $ 9,241 $ 5,134 $ 53,853 $ - $ 68,228 Accounts receivable and other 1,808 11,221 508,919 - 521,948 Inventory - 5,652 34,826 - 40,478 Assets held for sale - - 141,486 - 141,486 --------- --------- ---------- --------- ---------- Total current assets 11,049 22,007 739,084 - 772,140 --------- --------- ---------- --------- ---------- PROPERTY AND EQUIPMENT 235,158 494,279 460,730 - 1,190,167 Less allowance for depreciation, depletion and amortization (215,463) (120,016) (11,649) (55,386) (402,514) --------- --------- ---------- --------- ---------- 19,695 374,263 449,081 (55,386) 787,653 --------- --------- ---------- --------- ---------- INVESTMENTS IN SUBSIDIARIES AND INTERCOMPANY ADVANCES 440,115 (224,598) (45,683) (169,834) - OTHER ASSETS 40,337 14,752 74,678 - 129,767 --------- --------- ---------- --------- ---------- $ 511,196 $ 186,424 $1,217,160 $(225,220) $1,689,560 ========= ========= ========== ========= ========== LIABILITIES AND STOCKHOLDERS' EQUITY CURRENT LIABILITIES Accounts payable and other current liabilities $ 23,700 $ 35,457 $ 487,212 $ 24 $ 546,393 Notes payable and other current obligations - 511 109,369 - 109,880 --------- --------- ---------- --------- ---------- Total current liabilities 23,700 35,968 596,581 24 656,273 BANK DEBT 137,300 - - - 137,300 BANK DEBT OF A SUBSIDIARY - - 259,450 - 259,450 SUBORDINATED DEBT 277,909 - 105,000 (105,000) 277,909 OTHER LONG-TERM DEBT - 2,044 - - 2,044 OTHER LONG-TERM LIABILITIES 1,954 - 19,153 - 21,107 --------- --------- ---------- --------- ---------- 440,863 38,012 980,184 (104,976) 1,354,083 --------- --------- ---------- --------- ---------- MINORITY INTEREST (70,037) - 226,082 - 156,045 --------- --------- ---------- --------- ---------- CUMULATIVE CONVERTIBLE PREFERRED STOCK, STATED AT LIQUIDATION PREFERENCE 138,813 - - - 138,813 --------- --------- ---------- --------- ---------- NON-REDEEMABLE PREFERRED STOCK, COMMON STOCK AND OTHER STOCKHOLDERS' EQUITY Series D Cumulative Convertible Preferred Stock 23,300 - - - 23,300 Common Stock 1,792 78 - (78) 1,792 Additional paid-in capital 130,027 3,952 43,261 (47,213) 130,027 Retained earnings (accumulated deficit) (153,562) 144,382 (32,367) (72,953) (114,500) --------- --------- ---------- --------- ---------- 1,557 148,412 10,894 (120,244) 40,619 --------- --------- ---------- --------- ---------- $ 511,196 $ 186,424 $1,217,160 $(225,220) $1,689,560 ========= ========= ========== ========= ==========
15 PLAINS RESOURCES INC. AND SUBSIDIARIES CONSOLIDATING STATEMENT OF OPERATIONS (UNAUDITED) (IN THOUSANDS) THREE MONTHS ENDED SEPTEMBER 30, 2000
GUARANTOR NONGUARANTOR INTERCOMPANY PARENT SUBSIDIARIES SUBSIDIARIES ELIMINATIONS CONSOLIDATED ---------- ------------ ------------ ------------ ------------ REVENUES Oil and natural gas sales $ 5 $38,198 $ - $ 407 $ 38,610 Marketing, transportation, storage and terminalling - - 756,926 (52,982) 703,944 Gain on sale of assets - - - - - Interest and other income 277 95 317 - 689 --------- --------- --------- -------- -------- 282 38,293 757,243 (52,575) 743,243 --------- --------- --------- -------- -------- EXPENSES Production expenses - 15,934 - - 15,934 Marketing, transportation, storage and terminalling - - 724,366 (52,575) 671,791 Unauthorized trading losses and related expenses - - 6,600 - 6,600 General and administrative 814 1,238 9,918 - 11,970 Depreciation, depletion and amortization 813 4,498 5,457 - 10,768 Interest expense 1,413 5,204 6,478 - 13,095 --------- --------- --------- -------- -------- 3,040 26,874 752,819 (52,575) 730,158 --------- --------- --------- -------- -------- Income (loss) before income taxes, minority interest and extraordinary item (2,758) 11,419 4,424 - 13,085 Minority interest - - 2,047 - 2,047 --------- --------- --------- -------- -------- Income (loss) before income taxes (2,758) 11,419 2,377 - 11,038 Income tax expense (benefit): Current (55) 228 47 - 220 Deferred (1,020) 4,225 879 - 4,084 --------- --------- --------- -------- -------- Income (loss) before extraordinary item (1,683) 6,966 1,451 - 6,734 Extraordinary item, net of tax benefit and minority interest - - - - - --------- --------- --------- -------- -------- NET INCOME (LOSS) (1,683) 6,966 1,451 - 6,734 Less: cumulative preferred stock dividends 3,694 - - - 3,694 --------- --------- --------- -------- -------- NET INCOME (LOSS) AVAILABLE TO COMMON STOCKHOLDERS $(5,377) $ 6,966 $ 1,451 $ - $ 3,040 ========= ========= ========= ======== ========
16 PLAINS RESOURCES RESOURCES INC. AND SUBSIDIARIES CONSOLIDATING STATEMENT OF OPERATIONS (UNAUDITED) (IN THOUSANDS) (RESTATED) THREE MONTHS ENDED SEPTEMBER 30, 1999
GUARANTOR NONGUARANTOR INTERCOMPANY PARENT SUBSIDIARIES SUBSIDIARIES ELIMINATIONS CONSOLIDATED ---------- ------------ ------------ ------------ ------------ REVENUES Oil and natural gas sales $ - $34,266 $ - $ 388 $ 34,654 Marketing, transportation, storage and terminalling - - 1,127,808 (29,302) 1,098,506 Interest and other income 17 12 330 - 359 --------- ------- ---------- -------- ---------- 17 34,278 1,128,138 (28,914) 1,133,519 --------- ------- ---------- -------- ---------- EXPENSES Production expenses - 16,326 - - 16,326 Marketing, transportation, storage and terminalling - - 1,095,481 (28,914) 1,066,567 Unauthorized trading losses and related expenses - - 72,250 - 72,250 General and administrative 338 1,213 9,294 - 10,845 Depreciation, depletion and amortization 538 4,835 4,735 - 10,108 Interest expense 2,194 4,338 6,619 - 13,151 --------- ------- ---------- -------- ---------- 3,070 26,712 1,188,379 (28,914) 1,189,247 --------- ------- ---------- -------- ---------- Income (loss) before income taxes and minority interest (3,053) 7,566 (60,241) - (55,728) Minority interest - - (23,786) - (23,786) --------- ------- ---------- -------- ---------- Income (loss) before income taxes (3,053) 7,566 (36,455) - (31,942) Income tax expense (benefit) Current (5,049) - 5,049 - - Deferred 6,232 (50) (18,077) - (11,895) --------- ------- ---------- -------- ---------- NET INCOME (LOSS) (4,236) 7,616 (23,427) - (20,047) Less: cumulative preferred stock dividends 2,493 - - - 2,493 --------- ------- ---------- -------- ---------- NET INCOME (LOSS) AVAILABLE TO COMMON STOCKHOLDERS $(6,729) $ 7,616 $ (23,427) $ - $ (22,540) ========= ======= ========== ======== ==========
17 PLAINS RESOURCES INC. AND SUBSIDIARIES CONSOLIDATING STATEMENT OF OPERATIONS (UNAUDITED) (IN THOUSANDS) NINE MONTHS ENDED SEPTEMBER 30, 2000
GUARANTOR NONGUARANTOR INTERCOMPANY PARENT SUBSIDIARIES SUBSIDIARIES ELIMINATIONS CONSOLIDATED ---------- ------------ ------------ ------------ ------------ REVENUES Oil and natural gas sales $ 5 $107,964 $ - $ 1,223 $ 109,192 Marketing, transportation, storage and terminalling - - 2,495,212 (147,386) 2,347,826 Gain on sale of assets - - 48,188 - 48,188 Interest and other income (expense) (767) 196 10,911 (3,062) 7,278 --------- ------- ---------- --------- ---------- (762) 108,160 2,554,311 (149,225) 2,512,484 --------- ------- ---------- --------- ---------- EXPENSES Production expenses - 46,612 - - 46,612 Marketing, transportation, storage and terminalling - - 2,393,326 (146,163) 2,247,163 Unauthorized trading losses and related expenses - - 6,600 - 6,600 General and administrative 1,876 5,125 26,564 - 33,565 Depreciation, depletion and amortization 2,488 13,252 20,324 - 36,064 Interest expense 7,568 15,828 21,578 (3,062) 41,912 --------- ------- ---------- --------- ---------- 11,932 80,817 2,468,392 (149,225) 2,411,916 --------- ------- ---------- --------- ---------- Income (loss) before income taxes, minority interest and extraordinary item (12,694) 27,343 85,919 - 100,568 Minority interest - - 39,451 - 39,451 --------- ------- ---------- --------- ---------- Income (loss) before income taxes (12,694) 27,343 46,468 - 61,117 Income tax expense (benefit): Current (203) 383 561 - 741 Deferred (5,465) 10,281 18,278 - 23,094 --------- ------- ---------- --------- ---------- Income (loss) before extraordinary item (7,026) 16,679 27,629 - 37,282 Extraordinary item, net of tax benefit and minority interest - - (4,988) - (4,988) --------- ------- ---------- --------- ---------- NET INCOME (LOSS) (7,026) 16,679 22,641 - 32,294 Less: cumulative preferred stock dividends 11,106 - - - 11,106 --------- ------- ---------- --------- ---------- NET INCOME (LOSS) AVAILABLE TO COMMON STOCKHOLDERS $(18,132) $16,679 $ 22,641 $ - $ 21,188 ========= ======= ========== ========= ==========
18 PLAINS RESOURCES INC. AND SUBSIDIARIES CONSOLIDATING STATEMENT OF OPERATIONS (UNAUDITED) (IN THOUSANDS) (RESTATED) NINE MONTHS ENDED SEPTEMBER 30, 1999
GUARANTOR NONGUARANTOR INTERCOMPANY PARENT SUBSIDIARIES SUBSIDIARIES ELIMINATIONS CONSOLIDATED ---------- ------------ ------------ ------------ ------------ REVENUES Oil and natural gas sales $ - $79,923 $ - $ 1,062 $ 80,985 Marketing, transportation, storage and terminalling - - 2,484,063 (67,947) 2,416,116 Interest and other income (expense) 14 34 618 - 666 --------- ------- ---------- --------- ---------- 14 79,957 2,484,681 (66,885) 2,497,767 --------- ------- ---------- --------- ---------- EXPENSES Production expenses - 39,989 - - 39,989 Marketing, transportation, storage and terminalling - - 2,405,758 (66,885) 2,338,873 Unauthorized trading losses and related expenses - - 114,925 - 114,925 General and administrative 1,226 3,809 17,527 - 22,562 Depreciation, depletion and amortization 1,798 12,349 11,406 - 25,553 Interest expense 4,807 13,329 14,532 - 32,668 --------- ------- ---------- --------- ---------- 7,831 69,476 2,564,148 (66,885) 2,574,570 --------- ------- ---------- --------- ---------- Income (loss) before income taxes and minority interest (7,817) 10,481 (79,467) - (76,803) Minority interest - - (32,014) - (32,014) --------- ------- ---------- --------- ---------- Income (loss) before income taxes (7,817) 10,481 (47,453) - (44,789) Income tax expense (benefit) Current (8,205) - 8,205 - - Deferred 9,244 - (25,709) - (16,465) --------- ------- ---------- --------- ---------- NET INCOME (LOSS) (8,856) 10,481 (29,949) - (28,324) Less: cumulative preferred stock dividends 7,327 - - - 7,327 --------- ------- ---------- --------- ---------- NET INCOME (LOSS) AVAILABLE TO COMMON STOCKHOLDERS $(16,183) $10,481 $ (29,949) $ - $ (35,651) ========= ======= ========== ========= ==========
19 PLAINS RESOURCES INC. AND SUBSIDIARIES CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS (UNAUDITED) (IN THOUSANDS) NINE MONTHS ENDED SEPTEMBER 30, 2000
GUARANTOR NONGUARANTOR INTERCOMPANY PARENT SUBSIDIARIES SUBSIDIARIES ELIMINATIONS CONSOLIDATED ---------- ------------ ------------ ------------ ------------ CASH FLOWS FROM OPERATING ACTIVITIES Net income (loss) $ (7,026) $ 16,679 $ 22,641 $ - $ 32,294 Adjustments to reconcile net income to net cash provided by (used in) operating activities: Depreciation, depletion, and amortization 2,488 13,252 20,324 - 36,064 Gain on sale of assets (Note 4] - - (48,188) - (48,188) Minority interest in income of a subsidiary - - 32,484 - 32,484 Deferred income tax (5,465) 10,281 15,088 - 19,904 Noncash compensation expense - - 2,269 - 2,269 Other noncash items 6,060 - 4,574 - 10,634 Change in assets and liabilities resulting from operating activities: Accounts receivable and other (15,768) 168 95,284 - 79,684 Inventory - (1,609) 12,539 - 10,930 Pipeline linefill - - (13,397) - (13,397) Accounts payable and other current liabilities 3,054 3,193 (143,451) - (137,204) Other long-term liabilities and deferred credits - - (8,000) - (8,000) ---------- ------------ ------------ ------------ ------------ NET CASH FLOWS PROVIDED BY (USED IN) OPERATING ACTIVITIES (16,657) 41,964 (7,833) - 17,474 ---------- ------------ ------------ ------------ ------------ CASH FLOWS FROM INVESTING ACTIVITIES Payments for crude oil pipeline, gathering and terminal assets - - (6,859) - (6,859) Payments for acquisition, exploration, and development costs (1,715) (48,135) - - (49,850) Payments for additions to other property and assets (213) (1,364) (628) - (2,205) Proceeds from sale of assets (Note 4) - - 223,859 - 223,859 ---------- ------------ ------------ ------------ ------------ NET CASH PROVIDED BIN) INVESTING ACTIVITIES (1,928) (49,499) 216,372 - 164,945 ---------- ------------ ------------ ------------ ------------ CASH FLOWS FROM FINANCING ACTIVITIES Advances/investments with affiliates 128,194 3,300 (131,494) - - Proceeds from long-term debt 127,025 - 794,800 - 921,825 Proceeds from short-term debt - - 47,750 - 47,750 Principal payments of long-term debt (251,325) (511) (812,900) - (1,064,736) Principal payments of short-term debt - - (106,469) - (106,469) Purchase of treasury stock (4,221) - - - (4,221) Costs incurred in connection with financing arrangements - - (6,500) - (6,500) Dividends paid (6,392) - - - (6,392) Distribution to unitholders 21,303 - (43,269) - (21,966) Other (72) - - - (72) ---------- ------------ ------------ ------------ ------------ NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES 14,512 2,789 (258,082) - (240,781) ---------- ------------ ------------ ------------ ------------ Net decrease in cash and cash equivalents (4,073) (4,746) (49,543) - (58,362) Cash and cash equivalents, beginning of period 9,241 5,134 53,853 - 68,228 ---------- ------------ ------------ ------------ ------------ Cash and cash equivalents, end of period $ 5,168 $ 388 $ 4,310 $ - $ 9,866 ========== ============ ============ ============ ============
20 PLAINS RESOURCES INC. AND SUBSIDIARIES CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS (UNAUDITED) (IN THOUSANDS) (RESTATED) NINE MONTHS ENDED SEPTEMBER 30, 1999
GUARANTOR NONGUARANTOR INTERCOMPANY PARENT SUBSIDIARIES SUBSIDIARIES ELIMINATIONS CONSOLIDATED ---------- ------------ ------------ ------------ ------------ CASH FLOWS FROM OPERATING ACTIVITIES Net income (loss) $ (8,856) $ 10,481 $ (29,949) $ - $ (28,324) Adjustments to reconcile net income to net cash provided by (used in) operating activities: Depreciation, depletion, and amortization 1,798 12,349 11,406 - 25,553 Minority interest in income of a subsidiary - - (32,014) - (32,014) Deferred income tax 9,244 - (25,709) - (16,465) Noncash compensation expense - - 1,947 - 1,947 Other noncash items 1,216 (211) 216 - 1,221 Change in assets and liabilities resulting from operating activities: Accounts receivable and other (1,056) (3,340) (155,165) - (159,561) Inventory - 216 (37,767) - (37,551) Pipeline linefill - - (3) - (3) Accounts payable and other current liabilities 5,590 (12,852) 249,352 200 242,290 Other long-term liabilities and deferred credits - - 10,873 - 10,873 ---------- ------------ ----------- ------------ ---------- NET CASH FLOWS PROVIDED BY (USED IN) OPERATING ACTIVITIES 7,936 6,643 (6,813) 200 7,966 ---------- ------------ ----------- ------------ ---------- CASH FLOWS FROM INVESTING ACTIVITIES Payment for acquisition of midstream assets - - (173,070) - (173,070) Payments for crude oil pipeline, gathering and terminal assets - - (7,785) - (7,785) Payments for acquisition, exploration, and development costs (4,223) (53,469) - - (57,692) Payments for additions to other property and assets 140 (340) (269) - (469) ---------- ------------ ----------- ------------ ---------- NET CASH USED IN INVESTING ACTIVITIES (4,083) (53,809) (181,124) - (239,016) ---------- ------------ ----------- ------------ ---------- CASH FLOWS FROM FINANCING ACTIVITIES Advances/investments with affiliates (76,165) 47,395 28,770 - - (Payment) proceeds from issuance of Class B Common Units (25,000) - 25,000 - - Proceeds from long-term debt 226,350 - 281,971 - 508,321 Proceeds from short-term debt - - 42,150 - 42,150 Principal payments of long-term debt (153,011) - (133,121) - (286,132) Principal payments of short-term debt - - (21,650) - (21,650) Proceeds from warrant exercise 4,500 - - - 4,500 Costs incurred in connection with financing arrangements (1,125) - (3,527) (4,652) Distribution to unitholders 20,154 - (34,619) - (14,465) Other 306 - - - 306 ---------- ------------ --------- ------- --------- NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES (3,991) 47,395 184,974 - 228,378 ---------- ------------ --------- --------- --------- Net increase (decrease) in cash and cash equivalents (138) 229 (2,963) 200 (2,672) Cash and cash equivalents, beginning of period 142 194 6,408 (200) 6,544 ---------- ------------ -------- --------- --------- Cash and cash equivalents, end of period $ 4 423 $ 3,445 $ - $ 3,872 ========== ============ ======== ========= =========
21 MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS General We are an independent energy company engaged in two related lines of business within the energy sector industry. Our first line of business, which we refer to as "upstream," acquires, exploits, develops, explores and produces crude oil and natural gas. Our second line of business, which we refer to as "midstream," is engaged in the marketing, transportation and terminalling of crude oil. We conduct this second line of business through our majority ownership in Plains All American Pipeline, L.P. ("PAA"). For financial statement purposes, the assets, liabilities and results of operations of PAA are included in our consolidated financial statements, with the public unitholders' interest reflected as a minority interest. Our upstream crude oil and natural gas activities are focused in California (in the Los Angeles Basin, the Arroyo Grande Field, and the Mt. Poso Field), offshore California (in the Point Arguello Field), the Sunniland Trend of South Florida and the Illinois Basin in southern Illinois. Our midstream activities are concentrated in California, Texas, Oklahoma, Louisiana and the Gulf of Mexico. UNAUTHORIZED TRADING LOSSES In November 1999, we discovered that a former employee of PAA had engaged in unauthorized trading activity, resulting in losses of approximately $162.0 million ($174.0 million, including estimated associated costs and legal expenses at December 31, 1999). Approximately $154.9 million of the unauthorized trading loss was recognized in 1999, with approximately $72.3 million and $114.9 million of this amount recognized in the three and nine months ended September 30, 1999, respectively. As a result, we have previously restated our 1999 financial information. During the third quarter of 2000, we recognized an additional $6.6 million charge for litigation related to the unauthorized trading losses (See Note 11 to the consolidated financial statements). RESULTS OF OPERATIONS Three Months Ended September 30, 2000 and 1999 For the three months ended September 30, 2000, we reported net income of $6.7 million, or $0.17 per basic share ($0.16 per diluted share) on total revenue of $743.2 million, as compared with a net loss of $20.0 million, or $1.30 per basic and diluted share on total revenue of $1.1 billion in the third quarter of 1999. Results for the three months ended September 30, 2000 and 1999 include the following special or nonrecurring items: 2000 . $6.6 million charge for litigation related to the unauthorized trading losses; and . $2.1 million of noncash compensation expense. 1999 . $72.3 million of unauthorized trading losses; . $1.9 million of noncash compensation expense; and . $1.0 million of restructuring expenses. Excluding the items noted above, we would have reported net income of approximately $9.6 million and $7.6 million for the three months ended September 30, 2000 and 1999, respectively. Adjusted EBITDA increased 9% in 2000 to $45.7 million from the $41.7 million reported in the third quarter of 1999. Adjusted EBITDA means earnings before interest expense, income taxes, depreciation, depletion and amortization and the nonrecurring items discussed above. Cash flow from operations after deducting minority interest (net income before noncash items) was $26.5 million and $23.9 million for the third quarters of 2000 and 1999, respectively. Cash flow from operations also excludes the nonrecurring items discussed above. Oil and natural gas sales. Oil and natural gas sales were $38.6 million for the third quarter of 2000, an approximate 11% increase from the 1999 third quarter amount of $34.7 million due to higher product prices ($6.4 million) which was partially offset by decreased production volumes ($2.5 million). 22 Marketing, transportation, storage and terminalling revenues. Marketing, transportation, storage and terminalling revenues decreased to $703.9 million for the third quarter of 2000 compared to the 1999 third quarter amount of $1.1 billion, due to higher crude oil prices which offset lower current year lease gathering and bulk purchase volumes and decreased pipeline margin revenues. Production expenses. Total production expenses decreased to $15.9 million from $16.3 million in the third quarter of 1999 primarily due to the sale of certain state of California emission credits, which are partially offset by increases in operating costs, primarily for electricity and natural gas for fuel. Marketing, transportation, storage and terminalling expenses. Marketing, transportation, storage and terminalling expenses decreased to $671.8 million in the third quarter of 2000 compared to $1.1 billion in the same quarter of 1999. The decrease is primarily due to lower current year lease gathering and bulk purchase volumes and a decrease in pipeline margin purchases partially offset by increased purchase costs as a result of higher crude oil prices. General and administrative. General and administrative expenses were $12.0 million for the third quarter of 2000 compared to $10.8 million for the third quarter of 1999. Our upstream and midstream activities accounted for approximately $0.5 million and $0.7 million, respectively, of the increase. Nonrecurring or special items Unauthorized trading losses. As previously discussed, we recognized losses from unauthorized trading and related expenses, including litigation settlement of approximately $6.6 million and $72.3 million in the third quarter of 2000 and 1999, respectively. Noncash compensation expense. We recognized noncash compensation expense of $2.1 million and $1.9 million in the third quarter of 2000 and 1999, respectively, related to the probable vesting of partnership units granted by PAA's general partner to certain officers and key employees of PAA's general partner and its affiliates. These amounts are included in general and administrative expense on the Consolidated Statements of Operations. The units granted are owned by the general partner and therefore, do not reflect an increase in the number of units of the partnership, nor a cash cost to PAA. Restructuring charge. A $1.0 million restructuring charge, primarily associated with personnel reduction, was incurred by PAA in the third quarter of 1999 and is included in marketing, transportation, storage and terminalling expenses. Upstream Results The following table reflects certain of our upstream operating information for the periods presented:
Three Months Ended September 30, ------------------------ 2000 1999 ---------- ----------- Average Daily Production Volumes (in thousands): Barrels of oil equivalent ("BOE") California onshore (approximately 91% oil) 15.4 15.9 Offshore California (100% oil) 3.9 4.5 Gulf Coast (100% oil) 2.3 2.9 Illinois Basin (100% oil) 2.8 3.0 ---------- ----------- Total (approximately 94% oil) 24.4 26.3 ========== =========== Unit Economics: Average sales price per BOE $ 17.20 $ 14.34 Production expense per BOE 7.10 6.75 ---------- ----------- Gross margin per BOE 10.10 7.59 Upstream G&A expense per BOE 0.91 0.64 ---------- ----------- Gross profit per BOE $ 9.19 $ 6.95 ========== ===========
23 Total oil equivalent production decreased approximately 7% to an average of 24,400 BOE per day as compared to the third quarter 1999 average of 26,300 BOE per day. Net daily production from our onshore California properties decreased to 15,400 barrels per day in the third quarter of 2000 compared to 15,900 barrels per day in the prior year period primarily due to natural decline and uplift volumes added by the capital program. Production volumes were also adversely impacted by electrical brownouts in the LA Basin and Arroyo Grande, high gas gathering system back-pressure in our Arroyo Grande Field and a change in reporting volumes associated with the Inglewood Gas Plant. Net daily production from our offshore California Point Arguello Unit decreased to 3,900 barrels per day in the third quarter of 2000 compared to 4,500 barrels per day in the prior year period. This decrease is due primarily to an increase in our MMS royalty burden rate beginning in July 2000, natural decline and curtailments arising from gas cycling between producing and injection wells. Net daily production for our Gulf Coast properties averaged approximately 2,300 barrels per day during the third quarter of 2000, compared to 2,900 barrels per day in the prior year period primarily due to mechanical problems and natural decline. Net daily production in the Illinois Basin averaged approximately 2,800 barrels per day during the third quarter of 2000, a decrease of approximately 7% compared to 3,000 barrels per day during the third quarter of 1999, due primarily to lower water injection levels, natural decline and the high demand for completion units which has delayed completion of newly drilled wells and routine well servicing. Our average product price was $17.20 per BOE, up 20% as compared to the 1999 third quarter average wellhead price of $14.34 per BOE. Our product price represents a combination of fixed-price and floating-price sales arrangements and incorporates location and quality discounts from the benchmark NYMEX price. The NYMEX benchmark WTI crude oil price averaged $31.66 per barrel during the third quarter of 2000, approximately 46% above the $21.71 per barrel amount in the prior year quarter. Our average product prices also include the effects of hedging transactions such as financial swap and collar arrangements and futures transactions. These transactions had the effect of decreasing our average price by $9.88 and $2.19 per BOE in the third quarter of 2000 and 1999, respectively. We maintained hedges on approximately 80% and 67% of our crude oil production in the third quarter of 2000 and 1999, respectively. Upstream unit gross margin (well-head revenue less production expenses) for the third quarter of 2000 was $10.10 per BOE, a 33% increase as compared to $7.59 per BOE reported for the third quarter of 1999. Average unit production expenses averaged $7.10 per BOE for the third quarter of 2000 as compared to the 1999 third quarter average of $6.75 per BOE. The increase in production expenses is primarily due to increased gas fuel costs, as well as general pressure throughout the service industry. Unit general and administrative expenses increased to $0.91 per BOE in the third quarter of 2000, compared to $0.64 per BOE in the prior year comparative quarter due to lower production volumes as well as increased costs. Total upstream general and administrative expense was $2.1 million during the third quarter of 2000 compared to $1.6 million in the third quarter of 1999. The increase is primarily attributable to increased overhead expenses related to our production and corporate activities, decreased capitalization of overhead costs and to increased legal and consulting fees. Total upstream DD&A remained constant at $5.3 million in the third quarter of 2000 as compared to the third quarter of 1999. An increase in our per unit DD&A rate was offset by lower production volumes. On a per unit basis, DD&A was $2.21 for the third quarter of 2000 compared to $2.10 in the 1999 comparative quarter. Midstream Results Excluding the unauthorized trading losses, gross margin from our midstream activities was $32.2 million in the third quarter of 2000 compared to $31.9 million in the third quarter of 1999. An analysis of these results is discussed below. The following table reflects certain of our midstream operating information for the periods presented (in thousands):
Three Months Ended September 30, ------------------------- 2000 1999 ----------- ------------ (restated) Operating Results: Gross margin: Pipeline $ 11,886 $ 14,539 Gathering and marketing and terminalling and storage 20,267 17,400 Unauthorized trading losses (6,600) (72,250) ----------- ------------ Total 25,553 (40,311) General and administrative expense (9,918) (9,294) ----------- ------------ Gross profit $ 15,635 $(49,605) =========== ============
Table continued on following page 24
Three Months Ended September 30, ------------------------- 2000 1999 ----------- ------------ Average Daily Volumes (MBbls/day): Pipeline Activities: All American Tariff activities 76 93 Margin activities 55 52 Other 100 106 ----------- ------------ Total 231 251 =========== ============ Lease gathering 233 318 Bulk purchases 28 181 ----------- ------------ Total 261 499 =========== ============ Terminal throughput 81 68 =========== ============ Storage leased to third parties, monthly average volumes (MBbls/month) 1,687 1,687 =========== ============
Pipeline Operations. Gross margin from pipeline operations was $11.9 million for the quarter ended September 30, 2000 compared to $14.5 million for the prior year quarter. Lower volumes shipped to West Texas as a result of the first quarter 2000 sale of the California to Texas segment of the All American Pipeline and movements to the Mojave station, which were discontinued in late 1999 after a new California pipeline was activated, account for the majority of the decrease. The margin between revenue and direct cost of crude purchased was $3.8 million for the quarter ended September 30, 2000 compared to $10.2 million for the prior year third quarter. Pipeline tariff revenues were approximately $11.4 million for the third quarter of 2000 compared to approximately $12.4 million for the same period in 1999, due to the sale of the All American Pipeline segment. Pipeline operations and maintenance expenses decreased to $4.3 million for the third quarter of 2000 compared to $7.1 million for the third quarter of 1999, also due to the disposition. Average daily pipeline volumes totaled 231,000 barrels per day and 251,000 barrels per day for the third quarter of 2000 and 1999, respectively. The volume decrease is primarily due to the discontinued movements to the Mojave station, as well as discontinued movements to West Texas as a result of the sale of the segment of the All American Pipeline. Volumes on the All American Pipeline decreased from an average of 145,000 barrels per day for the third quarter of 1999 to 131,000 barrels per day in the current year quarter due to the reasons discussed above. All American's tariff volumes attributable to offshore California production were about flat between the two periods. Tariff volumes shipped on the Scurlock and West Texas gathering systems averaged 100,000 barrels per day and 106,000 barrels per day during the third quarters of 2000 and 1999, respectively. Gathering and Marketing Activities and Terminalling and Storage Activities. Excluding the unauthorized trading losses, gross margin from gathering, marketing, terminalling and storage activities was approximately $20.3 million for the quarter ended September 30, 2000, a 17% increase as compared to $17.4 million in the prior year quarter, primarily due to an increase in our per- barrel margins due to the strong crude oil market. Gross revenues from these activities were approximately $610.7 million and $869.8 million in the third quarter of 2000 and 1999, respectively. The decreased revenues were primarily due to lower bulk purchase and lease gathering volumes, offset by higher crude prices. Lease gathering volumes decreased from an average of 318,000 barrels per day in the third quarter of 1999 to approximately 233,000 barrels per day in the current year period. Bulk purchase volumes decreased from approximately 181,000 barrels per day in the 1999 third quarter to approximately 28,000 barrels per day in the current year period. These decreases are primarily due to the phase out of a significant amount of low-margin activity subsequent to the discovery of the unauthorized trading losses. The gross margin impact from the reduced volumes between the third quarter of 1999 and the current year quarter was approximately $1.5 million. Lease gathering volumes averaged approximately 235,000 barrels per day and 229,000 barrels per day, respectively, for the first and second quarters of 2000, while bulk purchases averaged 29,000 barrels per day and 26,000 barrels per day for the same periods. These consecutive quarter comparisons are more indicative of a trend analysis than a comparison to the third quarter of 1999 due to the phase out of the low margin barrels. 25 Terminal throughput, which includes both our Cushing and Ingleside terminals, increased to 81,400 barrels per day from 67,900 barrels per day in the third quarter of last year, while storage leased to third parties was about flat with last year at 1.7 million barrels per month. Midstream general and administrative expenses were $9.9 million for the quarter ended September 30, 2000 compared to $9.3 million for the third quarter in 1999. The increase in 2000 is primarily due to consulting and accounting charges related to system modifications and enhancements and personnel-related costs. Midstream depreciation and amortization expense was $5.5 million for the quarter ended September 30, 2000, compared to $4.7 million for the third quarter of 1999. The increase reflects a reevaluation of certain criteria on which the depreciation of certain fixed assets was based prior to the implementation of a fixed asset reporting system in the third quarter of 2000. We estimate that depreciation and amortization expense will average approximately $4.6 million to $4.7 million per quarter in the future, based on our current property base. Nine Months Ended September 30, 2000 and 1999 For the nine months ended September 30, 2000, we reported net income of $32.3 million, or $1.18 per basic share ($1.09 per diluted share) on total revenue of $2.5 billion, as compared with a net loss of $28.3 million, or $2.09 per basic and diluted share on total revenue of $2.5 billion in the first nine months of 1999. Results for the nine months ended September 30, 2000 and 1999 include the following special or nonrecurring items: 2000 . a $28.1 million gain on the sale of crude oil linefill; . a $20.1 million gain on the sale of the segment of the All American Pipeline that extends from Emidio, California, to McCamey, Texas; . $6.6 million charge for litigation related to the unauthorized trading losses. . $4.4 million of previously deferred net gains on interest rate swap terminations recognized due to the early extinguishment of debt (net of minority interest, this net gain had a negligible effect on income before taxes); . an extraordinary loss of $5.0 million related to the early extinguishment of debt (net of minority interest and tax benefit); . amortization of $4.6 million of debt issue costs associated with facilities put in place during the fourth quarter of 1999; . $2.3 million of noncash compensation expense; and . $0.9 million gain recognized upon the transfer of 69,444 of our units in PAA to employees of the general partner upon the vesting of transaction unit grants. 1999 . $114.9 million of unauthorized trading losses; . $1.9 million of noncash compensation expense; and . $1.4 million of restructuring expenses. Excluding the items noted above, we would have reported net income of approximately $25.3 million and $14.4 million for the nine months ended September 30, 2000 and 1999, respectively. Adjusted EBITDA increased 36% in 2000 to $133.9 million from the $98.3 million reported in the first nine months of 1999. Cash flow from operations after deducting minority interest (net income before noncash items) was $75.1 million and $52.1 million in the first nine months of 2000 and 1999, respectively. Cash flow from operations also excludes the nonrecurring items discussed above. Oil and natural gas sales. Oil and natural gas sales were $109.2 million for the first nine months of 2000, an approximate 35% increase from the 1999 first nine months amount of $81.0 million due to higher product prices and increased production volumes, which contributed approximately $22.7 million and $5.5 million to the increase, respectively. Marketing, transportation, storage and terminalling revenues. Marketing, transportation, storage and terminalling revenues decreased to $2,347.8 million for the first nine months of 2000 from the 1999 amount of $2,416.1 million. The decrease is due primarily to lower current year volumes, partially offset by higher crude oil prices. Production expenses. Total production expenses increased to $46.6 million from $40.0 million in the first nine months of 2000 and 1999, respectively, primarily due to increased production volumes and increased fuel costs, as well as general pressure throughout the service industry, offset by the sale of certain state of California emission credits. 26 Marketing, transportation, storage and terminalling expenses. Marketing, transportation, storage and terminalling expenses decreased to $2,247.2 million in the first nine months of 2000 compared to $2,338.9 million in the same period in 1999. The decrease is primarily due lower current year volumes purchased, partially offset by higher crude oil prices. General and administrative. General and administrative expenses were $33.6 million for the first nine months of 2000 compared to $22.6 million for the first nine months of 1999. Our upstream and midstream activities accounted for approximately $2.0 million and $9.0 million, respectively, of the increase from 1999 to 2000. Depreciation, depletion and amortization. Primarily as a result of our mid- 1999 midstream acquisitions, increased amortization of debt issue costs related to facilities put in place during the fourth quarter of 1999 and increased upstream production levels, total DD&A for the first nine months of 2000 was $36.1 million as compared to $25.6 million for the first nine months of 1999. Interest expense. Interest expense for the first nine months of 2000 was $41.9 million, an increase of $9.2 million over the first nine months of 1999. The increase is primarily due to a higher average debt level in 2000 resulting from our 1999 midstream acquisitions and the unauthorized trading losses, as well as increased interest rates. Capitalized interest was approximately $3.2 million for the nine months ended September 30, 2000 and 1999. Nonrecurring items Unauthorized trading losses. As previously discussed, we recognized losses from unauthorized trading and related expenses, including litigation settlement of approximately $6.6 million and $114.9 million in the first nine months of 2000 and 1999, respectively. Gain on sale of linefill. We initiated the sale of 5.2 million barrels of crude oil linefill from the All American Pipeline in November 1999. The sale was completed in March 2000. We recognized a gain of $28.1 million in connection with the sale of the linefill in the first quarter of 2000. Gain on sale of pipeline segment. On March 24, 2000, we completed the sale of the segment of the All American Pipeline that extends from Emidio, California to McCamey, Texas to a unit of El Paso Energy Corporation for proceeds of approximately $124.0 million, which are net of associated transaction costs and estimated costs to remove certain equipment. We recognized a total gain of $20.1 million in connection with the sale in the first quarter of 2000. Early extinguishment of debt. During the nine months ended September 30, 2000, we recognized extraordinary losses, consisting primarily of unamortized debt issue costs, totaling $5.0 million (net of minority interest of $7.0 million and deferred tax of $3.2 million) related to the permanent reduction of the All American Pipeline, L.P. term loan facility and the refinancing of PAA's credit facilities. In addition, interest and other income for the nine months ended September 30, 2000 includes $4.4 million of net deferred gains from terminated interest rate swaps as a result of the debt extinguishments. Noncash compensation expense. We recognized noncash compensation expense of $2.3 million and $1.9 million for the nine months ended September 30, 2000 and 1999, respectively, related to the probable vesting of partnership units granted by PAA's general partner to certain officers and key employees of PAA's general partner and its affiliates. These amounts are included in general and administrative expense on the Consolidated Statements of Operations. The units granted are owned by the general partner and therefore, do not reflect an increase in the number of units of the partnership, nor a cash cost to PAA. Transaction grant gain. Upon the transfer of 69,444 of our units in PAA to employees of the general partner, a gain of $0.9 million was recognized which represented the difference between the market price on the date of vesting and our basis in the units. Restructuring charge. A $1.4 million restructuring charge, primarily associated with personnel reduction was incurred by PAA in the first quarter of 1999. Approximately $1.1 million is included in marketing, transportation, storage and terminalling expenses and approximately $0.3 million is included in general and administrative expenses. 27 Upstream Results The following table reflects certain of our upstream operating information for the periods presented:
Nine Months Ended September 30, ------------------------ 2000 1999 ---------- ----------- Average Daily Production Volumes (in thousands): Barrels of oil equivalent California onshore (approximately 91% oil) 15.1 15.5 Offshore California (100% oil) 4.2 1.5 Gulf Coast (100% oil) 2.2 2.7 Illinois Basin (100% oil) 2.8 3.1 ---------- ----------- Total (approximately 95% oil) 24.3 22.8 ========== =========== Unit Economics: Average sales price per BOE $ 16.40 $ 12.99 Production expense per BOE 7.00 6.41 ---------- ----------- Gross margin per BOE 9.40 6.58 Upstream G&A expense per BOE 1.05 0.81 ---------- ----------- Gross profit per BOE $ 8.35 $ 5.77 ========== ===========
Total oil equivalent production increased approximately 6% to an average of 24,300 BOE per day as compared to the first nine months 1999 average of 22,800 BOE per day. The increase is attributable to the offshore California Point Arguello Unit, which we acquired from Chevron in July 1999. Net daily production from our onshore California properties decreased to 15,100 barrels per day in the first nine months of 2000 compared to 15,500 barrels per day in the prior period primarily due to electrical brownouts in the LA Basin and Arroyo Grande and natural decline. Net daily production for our Gulf Coast properties averaged approximately 2,300 barrels per day during the first nine months of 2000, compared to 2,700 barrels per day in the prior period. The Gulf Coast production decrease is due to downtime as a result of mechanical problems and the effects of natural decline. Net daily production in the Illinois Basin averaged approximately 2,800 barrels per day during the first nine months of 2000, compared to 3,100 barrels per day during the first nine months of 1999, due primarily to lower water injection levels, natural decline and the high demand for completion units which has delayed completion of newly drilled wells and routine well servicing. Our average product price was $16.40 per BOE, up 26% as compared to the 1999 first nine months average wellhead price of $12.99 per BOE. Our product price represents a combination of fixed-price and floating-price sales arrangements and incorporates location and quality discounts from the benchmark NYMEX price. The NYMEX benchmark WTI crude oil price averaged $29.70 per barrel during the first nine months of 2000, approximately 70% above the $17.47 per barrel amount in the prior year period. Our average product prices also include the effects of hedging transactions such as financial swap and collar arrangements and futures transactions. These transactions had the effect of decreasing our average price by $8.55 per BOE and $0.22 per BOE in the first nine months of 2000 and 1999, respectively. We maintained hedges on approximately 81% and 61% of our crude oil production in the first nine months of 2000 and 1999, respectively. Upstream unit gross margin (well-head revenue less production expenses) for the first nine months of 2000 was $9.40 per BOE, a 43% increase as compared to $6.58 per BOE reported for the first nine months of 1999. Average unit production expenses averaged $7.00 per BOE for the first nine months of 2000, an approximate 9% increase over the 1999 first nine months average of $6.41 per BOE. The increase in production expenses is primarily due to increased gas fuel costs, as well as general pressure throughout the service industry. Unit general and administrative expenses increased to $1.05 per BOE in the first nine months of 2000, compared to $0.81 per BOE in the prior year comparative period. Total upstream general and administrative expense was $7.0 million during the first nine months of 2000 compared to $5.0 million in the first nine months of 1999. The increase is primarily attributable to increased overhead costs related to our production and corporate activities, decreased capitalization of overhead costs and to increased legal and consulting fees. 28 Total upstream DD&A was $15.7 million in the first nine months of 2000 compared to $14.1 million in the first nine months of 1999. The increase is primarily due to increased production volumes as well as an increase in our per unit DD&A rate. On a per unit basis, DD&A was $2.21 for the first nine months of 2000 compared to $2.10 in the 1999 comparative period. Midstream Results Excluding the unauthorized trading losses, gross margin from our midstream activities was $100.7 million in the first nine months of 2000 compared to $77.2 million in the first nine months of 1999. An analysis of these results is discussed below. The following table reflects certain of our midstream operating information for the periods presented (in thousands): Nine Months Ended September 30, ------------------------- 2000 1999 ----------- ------------ (restated) Operating Results: Gross Margin: Pipeline $ 37,802 $ 39,338 Gathering and marketing and terminalling and storage 62,861 37,905 Unauthorized trading losses (6,600) (114,925) ----------- ------------ Total 94,063 (37,682) General and administrative expense (26,564) (17,528) ----------- ------------ Gross profit $ 67,499 $ (55,210) =========== ============ Average Daily Volumes (barrels): Pipeline Activities: All American Tariff activities 74 106 Margin activities 57 54 Other 106 43 ----------- ------------ Total 237 203 =========== ============ Lease gathering 223 216 Bulk purchases 28 138 ----------- ------------ Total 251 354 =========== ============ Terminal throughput 64 75 =========== ============ Storage leased to third parties, monthly average volumes (MBbls/month) 1,489 1,920 =========== ============ Pipeline Operations. Gross margin from pipeline operations was $37.8 million for the nine months ended September 30, 2000 compared to $39.3 million for the prior year period. Increased margins from the Scurlock and West Texas gathering system acquisitions in mid-1999 were offset by lower tariff transport volumes and reduced margins on our pipeline merchant activity. Tariff volumes decreased due to lower production from Exxon's Santa Ynez Field and the Point Arguello Field, both offshore California, and the sale of the segment of the All American Pipeline. Margins from pipeline merchant activity were lower due to the sale of the segment of the All American Pipeline. The margin between revenue and direct cost of crude purchased was $14.0 million for the nine months ended September 30, 2000 compared to $22.9 million for the first nine months of the prior year. Pipeline tariff revenues were approximately $36.0 million for the first nine months of 2000 compared to approximately $36.5 million for the same period in 1999 as increases related to the Scurlock and West Texas gathering system acquisitions were partially offset by the sale of the segment of the All American Pipeline segment. Pipeline operations and maintenance expenses were approximately $12.2 million for the first nine months of 2000 compared to $20.1 million for the first nine months of 1999, also due to the acquisitions and disposition. 29 Average daily pipeline volumes totaled 237,000 barrels per day and 203,000 barrels per day for the first nine months of 2000 and 1999, respectively. Volumes on the All American Pipeline decreased from an average of 160,000 barrels per day for the first nine months of 1999 to 131,000 barrels per day in the current year period due to the reasons discussed above. All American's tariff volumes attributable to offshore California production were approximately 74,000 barrels per day for nine months ended September 30, 2000 compared to 81,000 barrels per day in the prior year period. Tariff volumes shipped on the Scurlock and West Texas gathering systems averaged 106,000 barrels per day and 43,000 barrels per day during the first nine months of 2000 and 1999, respectively. The 1999 period includes volumes for Scurlock effective May 1, 1999, and West Texas gathering system volumes effective July 1, 1999. Gathering and Marketing Activities and Terminalling and Storage Activities. Excluding the unauthorized trading losses, gross margin from gathering, marketing, terminalling and storage activities was approximately $62.9 million for the nine months ended September 30, 2000 compared to $37.9 million in the prior year period. The increase in gross margin is primarily due to an increase in lease gathering volumes as a result of the Scurlock acquisition and increased per barrel margins due to the strong crude oil market. Gross revenues from gathering, marketing, terminalling and storage activities were approximately $2.0 billion and $1.8 billion in the first nine months of 2000 and 1999, respectively, as increased revenues resulting from higher crude oil prices and lease gathering volumes were partially offset by decreased revenues from lower bulk purchase volumes. Lease gathering volumes increased from an average of 216,000 barrels per day for the first nine months of 1999 to approximately 223,000 barrels per day for the 2000 period due to the Scurlock acquisition, partially offset by a significant amount of low margin barrels that were phased out subsequent to the discovery of the trading losses. Bulk purchase volumes decreased from approximately 138,000 barrels per day for the first nine months of 1999 to approximately 28,000 barrels per day in the current year period, also due to the phase out of low margin barrels. The gross margin impact from the reduced volumes was approximately $6.0 million for the nine months ended September 30, 2000. Terminal throughput, which includes both our Cushing and Ingleside terminals, was 64,000 and 75,000 barrels per day for the nine months ended September 30, 2000 and 1999, respectively. Storage leased to third parties was 1.5 million barrels per month and 1.9 million barrels per month for the same periods, respectively. Midstream general and administrative expenses were $26.6 million for the nine months ended September 30, 2000, compared to $17.5 million for the first nine months of 1999. The increase in 2000 is primarily due to the Scurlock acquisition in May 1999 (approximately $5.7 million), consulting fees related to the trading loss investigation, consulting and accounting charges related to system modifications and enhancements and personnel-related costs. Midstream depreciation and amortization expense was $20.3 million for the nine months ended September 30, 2000, compared to $11.4 million for the first nine months of 1999. The increase is primarily due to the Scurlock and West Texas gathering system acquisitions in mid-1999, the previously discussed adjustments in connection with the implementation of a new fixed asset reporting system and increased amortization of debt issue costs associated with facilities put in place during the fourth quarter of 1999 due to the unauthorized trading losses. These increases were partially offset by decreased depreciation related to the segment of the All American Pipeline that was sold in the first quarter of 2000. LIQUIDITY AND CAPITAL RESOURCES Cash Flow Nine Months Ended September 30, ------------------------- (in millions) 2000 1999 -------------------------------------------------------------- (restated) Cash provided by (used in): Operating activities $ 17.5 $ 8.0 Investing activities 164.9 (239.0) Financing activities (240.8) 228.4 -------------------------------------------------------------- Operating Activities. Net cash provided by operating activities for the first nine months of 2000 decreased from the 1999 amount primarily due to amounts paid during the first quarter of 2000 for the 1999 unauthorized trading losses, partially offset by increased income before taxes between the two periods. 30 Investing Activities. Net cash provided by investing activities for the first nine months of 2000 included $223.9 million of proceeds from the sales of the segment of the All American Pipeline and pipeline linefill and approximately $49.9 million and $6.9 million of upstream and midstream capital expenditures, respectively. Financing activities. Net cash used in financing activities for the first nine months of 2000 resulted primarily from net payments of $201.6 million of short- term and long-term debt. Proceeds used to reduce debt primarily came from the asset sales discussed above. On April 1, 2000, we paid aggregate cash dividends of approximately $6.0 million on our Series D, F and G preferred stock. The dividends on the Series D preferred stock are for the period from January 1, 2000 through March 31, 2000. The Series F preferred stock was issued on December 15, 1999 and such dividend covers the period from that date through March 31, 2000. The dividends on the Series G preferred stock are for the period from October 1, 1999 through March 31, 2000. On July 19, 2000, we paid cash dividends of approximately $0.4 million on our Series D preferred stock covering the period from April 1, 2000 through June 30, 2000. On October 1, 2000, we paid aggregate cash dividends of approximately $7.0 million on our Series D, F and G preferred stock. The dividends on the Series D preferred stock are for the period from July 1, 2000 through September 30, 2000. The dividends on the Series F and G preferred stock are for the period from April 1, 2000 through September 30, 2000. Credit Facilities We have a $225.0 million revolving credit facility with a group of banks. The revolving credit facility is guaranteed by all of our upstream subsidiaries and is collateralized by our upstream oil and natural gas properties and those of the guaranteeing subsidiaries and the stock of all upstream subsidiaries. The borrowing base under the revolving credit facility at September 30, 2000, is $225.0 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 crude oil and natural gas loans to borrowers similar to our company. Our borrowing base may be affected from time to time by the performance of our oil and natural gas properties and changes in oil and natural gas prices. We incur 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, 2002, at which time the remaining outstanding balance converts to a term loan which is repayable in twelve equal quarterly installments commencing October 1, 2002, with a final maturity of July 1, 2005. The revolving credit facility bears interest, at our option of either LIBOR plus 1 3/8% or Base Rate (as defined therein). At September 30, 2000, there were letters of credit of $0.6 million and borrowings of $13.0 million outstanding on the revolving credit facility. The revolving credit facility contains covenants which, among other things, prohibit the payment of cash dividends on common stock, limit repurchases of common stock, limit the amount of consolidated debt, limit our ability to make certain loans and investments and provide that we must maintain a specified relationship between current assets and current liabilities. We are in compliance with the covenants contained in the revolving credit facility. At September 30, 2000, we could have borrowed the full $225.0 million available under the revolving credit facility. On May 8, 2000, PAA entered into new bank credit agreements. The borrower under the new facilities is Plains Marketing, L.P. PAA is a guarantor of the obligations under the credit facilities. The obligations are also guaranteed by the subsidiaries of Plains Marketing, L.P. PAA entered into the credit agreements in order to: . refinance the existing bank debt of Plains Marketing, L.P. and Plains Scurlock Permian, L.P. in conjunction with the merger of Plains Scurlock Permian, L.P. into All American Pipeline, L.P.; . refinance existing bank debt of All American Pipeline, L.P.; . repay us $114.0 million plus accrued interest of subordinated debt, and . provide additional flexibility for working capital, capital expenditures, and for other general corporate purposes. PAA's new bank credit agreements consist of: . a $400.0 million senior secured revolving credit facility. The revolving credit facility is secured by substantially all of PAA's assets and matures in April 2004. No principal is scheduled for payment prior to maturity. The revolving credit facility bears interest at PAA's option at either the base rate, as defined, plus an applicable margin, or LIBOR plus an applicable margin. PAA incurs a commitment fee on the unused portion of the revolving credit facility. At September 30, 2000, $292.0 million was outstanding on the revolving credit facility. 31 . A $300.0 million senior secured letter of credit and borrowing facility, the purpose of which is to provide standby letters of credit to support the purchase and exchange of crude oil for resale and borrowings to finance crude oil inventory that has been hedged against future price risk. The letter of credit facility is secured by substantially all of PAA's assets and has a sublimit for cash borrowings of $100 million to purchase crude oil that has been hedged against future price risk. The letter of credit facility expires in April 2003. 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 of PAA's current assets and current liabilities (primarily inventory and accounts receivable and accounts payable related to the purchase and sale of crude oil). At September 30, 2000, approximately $79.5 million in letters of credit were outstanding under the letter of credit and borrowing facility. PAA's bank credit agreements prohibit distributions on, or purchases or redemptions of, units if any default or event of default is continuing. In addition, the agreements contain various covenants limiting PAA's ability to, among other things: . incur indebtedness; . grant liens; . sell assets; . make investments; . engage in transactions with affiliates; . enter into prohibited contracts; and . enter into a merger or consolidation. PAA's bank credit agreements treat a change of control as an event of default and also require PAA to maintain: . a current ratio (as defined) of 1.0 to 1.0; . a debt coverage ratio that is not greater that 4.0 to 1.0 for the period from March 31, 2000 to March 31, 2002 and subsequently 3.75 to 1.0; . an interest coverage ratio that is not less than 2.75 to 1.0; and . a debt to capital ratio of not greater than 0.65 to 1.0. A default under PAA's bank credit agreements would permit the lenders to accelerate the maturity of the outstanding debt and to foreclose on the assets securing the credit facilities. As long as PAA is in compliance with its bank credit agreements, they do not restrict its ability to make distributions of "available cash" as defined in its partnership agreement. PAA is currently in compliance with the covenants in its bank credit agreements. At September 30, 2000, PAA could have borrowed the full $400.0 million under its secured revolving credit facility. Contingencies Since our announcement in November 1999 of PAA's losses resulting from unauthorized trading by a former employee, numerous class action lawsuits have been filed against PAA, certain of its general partner's officers and directors and in some of these cases, its general partner and us alleging violations of the federal securities laws. In addition, derivative lawsuits were filed against PAA's general partner, its directors and certain of its officers alleging the defendants breached the fiduciary duties owed to PAA and its unitholders by failing to monitor properly the activities of its traders. See Part II - "Other Information" - Item 1. - "Legal Proceedings." Although we maintain an inspection program designed to prevent and, as applicable, to detect and address releases of crude oil into the environment from our pipeline and storage operations, we may experience such releases in the future, or discover releases that were previously unidentified. Damages and liabilities incurred due to any future environmental releases from our assets may substantially affect our business. OUTLOOK Our upstream activities are affected by changes in crude oil prices, which historically have been volatile. The NYMEX benchmark WTI crude oil price averaged $29.70 per barrel during the first nine months of 2000, approximately 70% above the $17.47 per barrel in the first nine months of last year. Substantial future crude oil price declines would adversely affect our overall results, and therefore our liquidity. Furthermore, low crude oil prices could affect our ability to raise capital on favorable terms. In order to manage our exposure to commodity price risk, we have routinely hedged a portion of our crude oil production and intend to continue this practice. For the fourth quarter of 2000, we have entered into various arrangements which provide for us to receive an average minimum NYMEX WTI price of $16.25 per barrel on 18,500 barrels of oil per day. Approximately 10,000 barrels per day of these volumes will participate in price increases up to $19.75 per barrel. This 32 hedge position is equivalent to approximately 80% of our third quarter 2000 average daily crude oil volumes. At average third quarter prices we would realize an average NYMEX price of $18.50 per barrel for the hedged volumes. For 2001, we have entered into various arrangements, using a combination of swaps, collars and purchased puts and calls, which will provide for us to receive an average minimum NYMEX price of approximately $22.75 per barrel on 20,500 barrels per day (equivalent to 89% of third quarter 2000 crude oil production levels) with full market price participation up to an average of $27.00 per barrel. Utilizing third quarter 2000 production levels at market prices between $26.00 and $36.00 per barrel, we will receive between 100% to 89% of market price and at market prices over $36.00 per barrel, we will receive at least 89% of market price. For 2002, we have entered into various arrangements that provide for us to receive an average minimum NYMEX WTI price of $23.00 per barrel on 10,000 barrels per day (equivalent to 44% of third quarter 2000 production levels) with full market price participation up to an average of $24.90 per barrel. At market prices between $24.90 and $36.00 per barrel, we will receive between 100% and 92% of the market price and at market prices over $36.00 per barrel we will receive at least 92% of market price. The foregoing NYMEX WTI crude oil prices are before quality and location differentials and the cost of the year 2001 and 2002 hedges, which averaged approximately $0.80 and $0.70 per hedged barrel, respectively. Management intends to continue to maintain hedging arrangements for a significant portion of our production. Such contracts may expose us to the risk of financial loss in certain circumstances. There is upward pressure on operating expenses industry-wide due to increased fuel costs for both gas and electricity, as well as general pressure throughout the service industry. As is common with most merchant activities, our ability to generate a profit on our midstream margin activities is not tied to the absolute level of crude oil prices but is generated by the difference between the price paid and other costs incurred in the purchase of crude oil and the price at which we sell crude oil. The gross margin generated by tariff activities depends on the volumes transported on the pipeline and the level of the tariff charged, as well as the fixed and variable costs of operating the pipeline. These operations are affected by overall levels of supply and demand for crude oil. ACCOUNTING PRONOUNCEMENTS In June 1998, the Financial Accounting Standards Board ("FASB") issued Statement of Financial Accounting Standards ("SFAS") No. 133, Accounting for Derivative Instruments and Hedging Activities ("SFAS 133"). SFAS 133 was subsequently amended (i) in June 1999 by SFAS No. 137, Accounting for Derivative Instruments and Hedging Activities - Deferral of the effective date of FASB Statement No. 133 ("SFAS 137"), which deferred the effective date of SFAS 133 to fiscal years beginning after June 15, 2000; and (ii) in June 2000 by SFAS 138, "Accounting for Certain Derivative Instruments and Certain Hedge Activities," which amended certain provisions, inclusive of the definition of the normal purchase and sale exclusion. SFAS 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 so, the type of hedge transaction. For fair value hedge transactions in which we are hedging changes in the fair value of an asset, liability, or firm commitment, changes in the fair value of the derivative instrument will generally be offset in the income statement by changes in the fair value of the hedged item. For cash flow hedge transactions, in which we are 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 ineffective portion of all hedges will be recognized in earnings in the current period. We will adopt SFAS 133, as amended, effective January 1, 2001. We believe we have identified all instruments currently in place that will be subject to the requirements of SFAS 133, however, due to the complex nature of SFAS 133 and various interpretations regarding applications of SFAS 133 to certain instruments, we have not fully determined what impact the adoption of SFAS 133 would have on the consolidated balance sheets, statements of operations and cash flows. The FASB has formed a derivative implementation group which is addressing assessment and implementation matters regarding the application of SFAS 133 for consideration by the FASB. Adoption of this standard could increase volatility in earnings and retained earnings (deficit) through comprehensive income. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKS We are exposed to various market risks, including volatility in crude oil commodity prices and interest rates. To manage our exposure, we monitor our inventory levels, and our expectations of future commodity prices and interest rates when making decisions with respect to risk management. We do not enter into derivative transactions for speculative trading 33 purposes that would expose us to price risk. Substantially all of our derivative contracts are exchanged or traded with major financial institutions and the risk of credit loss is considered remote. Commodity Price Risk. The fair value of outstanding derivative commodity instruments and the change in fair value that would be expected from a 10 percent price increase are shown in the table below (in millions):
September 30, 2000 December 31, 1999 ------------------------- ------------------------- Effect of Effect of 10% 10% Fair Price Fair Price Value Change Value Change --------- -------- ------- ----------- Crude oil : Futures contracts $ 6.1 $ 4.9 $ - $(2.8) Swaps and options contracts (24.0) (15.3) (22.0) (6.2)
The fair values of the futures contracts are based on quoted market prices obtained from the NYMEX. The fair value of the swaps is estimated based on quoted prices from independent reporting services compared to the contract price of the swap and approximate the gain or loss that would have been realized if the contracts had been closed out at the dates indicated. All hedge positions offset physical positions exposed to the cash market; none of these offsetting physical positions are included in the above table. Price-risk sensitivities were calculated by assuming an across-the-board 10 percent increase in prices regardless of term or historical relationships between the contractual price of the instruments and the underlying commodity price. In the event of an actual 10 percent change in prompt month crude oil prices, the fair value of our derivative portfolio would typically change less than that shown in the table due to lower volatility in out-month prices. For the fourth quarter of 2000, we have entered into various arrangements which provide for us to receive an average minimum NYMEX WTI price of $16.25 per barrel on 18,500 barrels of oil per day. Approximately 10,000 barrels per day of these volumes will participate in price increases up to $19.75 per barrel. For 2001, we have entered into various arrangements, using a combination of swaps, collars and purchased puts and calls, which will provide for us to receive an average minimum NYMEX price of approximately $22.75 per barrel on 20,500 barrels per day with full market price participation up to an average of $27.00 per barrel. For 2002, we have entered into various arrangements that provide for us to receive an average minimum NYMEX WTI price of $23.00 per barrel on 10,000 barrels per day with full market price participation up to an average of $24.90 per barrel. Location and quality differentials attributable to our properties are not included in the foregoing prices. The agreements provide for monthly settlement based on the differential between the agreement price and the actual NYMEX crude oil price. Gains or losses are recognized in the month of related production and are included in crude oil and natural gas sales. Such contracts resulted in a reduction in revenues of $22.2 million and $56.7 million in the third quarter and first nine months of 2000, respectively. The unrealized loss at September 30, 2000, with respect to such contracts was $24.0 million. At September 30, 2000, our hedging activities included crude oil futures contracts maturing through 2001, covering approximately 6.9 million barrels of crude oil. Since such contracts are designated as hedges and correlate to price movements of crude oil, any gains or losses resulting from market changes will be largely offset by losses or gains on our hedged inventory or anticipated purchases of crude oil. Such contracts resulted in a reduction in revenues of $1.2 million in the third quarter of 2000 and an increase in revenues of $0.1 million in the nine months ended September 30, 2000. The unrealized loss at September 30, 2000, with respect to such contracts was $7.0 million. Interest Rate Risk. Our debt instruments are sensitive to market fluctuations in interest rates. Our variable rate debt bears interest at LIBOR plus the applicable margin. At September 30, 2000, the carrying value of all variable rate bank debt of $305.0 million approximated the fair value and liquidation value at that date. The carrying value and fair value of the fixed rate debt was $277.0 million and $282.1 million, respectively, at that date. The carrying value and estimated fair value of redeemable preferred stock were $137.7 million and $198.3 million, respectively, at September 30, 2000. At December 31, 1999, the carrying value of all variable rate bank debt and the redeemable preferred stock of $506.1 million and $138.8 million, respectively, approximated the fair value and liquidation value at that date. The carrying value and fair value of the fixed rate debt was $277.5 million and $270.7 million, respectively, at that date. The fair value of fixed rate debt was based on quoted market prices based on trades of our subordinated debt. Interest rate swaps and collars are used to hedge underlying debt obligations. These instruments hedge specific debt issuances and qualify for hedge accounting. The interest rate differential is reflected as an adjustment to interest expense over the life of the instruments. At September 30, 2000, we had interest rate swap and collar arrangements for an aggregate notional principal amount of $240.0 million, which positions had an aggregate value of approximately $0.6 million as of such date. These instruments are based on LIBOR and generally provide for a floor of 5% and a ceiling of 6.5% for $90.0 million of debt, a floor of 6% and a ceiling of 8% for $125.0 million of debt and 5.7% for $25.0 million of debt. 34 Forward-Looking Statements and Associated Risks All statements, other than statements of historical fact, included in this report are forward-looking statements, including, but not limited to, statements identified by the words "anticipate," "believe," "estimate," "expect," "plan," "intend" and "forecast" and similar expressions and statements regarding our business strategy, plans and objectives of our management for future operations. These statements reflect our current views with respect to future events, based on what we believe are reasonable assumptions. These statements, however, are subject to certain risks, uncertainties and assumptions, including, but not limited to: . uncertainties inherent in the exploration for and development and production of oil and gas and in estimating reserves;. . unexpected future capital expenditures (including the amount and nature thereof); . impact of crude oil price fluctuations; . the effects of competition; . the success of our risk management activities; . the availability (or lack thereof) of acquisition or combination opportunities; . the availability of adequate supplies of and demand for crude oil in areas of midstream operations; . the impact of current and future laws and governmental regulations; . environmental liabilities that are not covered by an indemnity or insurance, and . general economic, market or business conditions. If one or more of these risks or uncertainties materialize, or if underlying assumptions prove incorrect, actual results may vary materially from those in the forward-looking statements. Except as required by applicable securities laws, we do not intend to update these forward-looking statements and information. PART II. OTHER INFORMATION ITEM 1. LEGAL PROCEEDINGS Texas Securities Litigation. On November 29, 1999, a class action lawsuit was filed in the United States District Court for the Southern District of Texas entitled Di Giacomo v. Plains All American Pipeline, L.P. ("PAA"), et al. The suit alleged that PAA and certain of its general partner's officers and directors violated federal securities laws, primarily in connection with unauthorized trading by a former employee. An additional nineteen cases have been filed in the Southern District of Texas, some of which name the general partner and us as additional defendants. All of the federal securities claims are being consolidated into two actions. The first consolidated action is that filed by purchasers of our common stock and options, and is captioned Koplovitz v. Plains Resources Inc., et al. The second consolidated action is that filed by purchasers of PAA's common units, and is captioned Di Giacomo v. Plains All American Pipeline, L.P., et al. Plaintiffs alleged that the defendants were liable for securities fraud violations under Rule 10b-5 and Section 20(a) of the Securities Exchange Act of 1934 and for making false registration statements under Sections 11 and 15 of the Securities Act of 1933. We and PAA have reached an agreement in principle with representatives of the plaintiffs for the settlement of all of the federal securities actions. Aggregate amounts to be paid under the agreement in principle total approximately $29.5 million plus interest from October 1, 2000 through the date actual proceeds are remitted to representatives for the plaintiffs. Our insurance carrier has deposited $15.0 million to an escrow account to fund amounts payable under our insurance policies. The Boards of Directors of PAA and Plains Resources have formed special independent committees to review and approve final allocation of the settlement costs between PAA and us. Based on an estimate of such allocation, which allocation is currently under review by the committees, in the third quarter of 2000 we accrued an additional $6.6 million of litigation costs and related expenses, which reduced basic earnings per common share after minority interest and taxes for the three and nine months ended September 30, 2000 by $0.12 ($0.11 diluted) and $0.12 ($0.07 diluted), respectively. The settlement is subject to a number of conditions, including negotiation and finalization of a stipulation and agreement of settlement and related documentation, and approval of the United States District Court for the Southern District of Texas. The agreement in principle does not affect the Texas Derivative Litigation and Delaware Derivative Litigation described below. Texas Derivative Litigation. On July 11, 2000, a derivative lawsuit was filed in the United States District Court for the Southern District of Texas entitled Fernandez v. Plains All American Inc., et al., naming the general partner, its directors and certain of its officers as defendants. This lawsuit contains the same claims and seeks the same relief as the Delaware derivative litigation described below. A motion to dismiss was filed on behalf of the defendants on August 14, 2000. 35 Delaware Derivative Litigation. On December 3, 1999, two derivative lawsuits were filed in the Delaware Chancery Court, New Castle County, entitled Susser v. Plains All American Inc., et al and Senderowitz v. Plains All American Inc., et al. These suits, and three others which were filed in Delaware subsequently, named the general partner, its directors and certain of its officers as defendants, and allege that the defendants breached the fiduciary duties that they owed to PAA and its unitholders by failing to monitor properly the activities of its employees. The court has consolidated all of the cases under the caption In Re Plains All American Inc. Shareholders Litigation, and has designated the complaint filed in Sussex v. Plains All American Inc. as the operative complaint in the consolidated action. A motion to dismiss was filed on behalf of the defendants on August 11, 2000. The plaintiffs in the Delaware securities litigation seek that the defendants (1) account for all losses and damages allegedly sustained by Plains All American from the unauthorized trading losses, (2) establish and maintain effective internal controls ensuring that PAA's affiliates and persons responsible for its affairs do not engage in wrongful practices detrimental to Plains All American, (3) account for the plaintiffs' costs and expenses in litigation, including reasonable attorneys' fees, accountants' fees, and experts' fees and (4) provide the plaintiffs any additional relief as may be just and proper under the circumstances. We intend to vigorously defend the claims made against us in the Texas derivative litigation and the Delaware derivative litigation. However, there can be no assurance that we will be successful in our defense or that these lawsuits will not have a material adverse effect on our financial position, results of operations or cash flows. On July 9, 1987, Exxon Corporation ("Exxon") filed an interpleader action in the United States District Court for the Middle District of Florida, Exxon Corporation v. E. W. Adams, et al., Case Number 87-976-CIV-T-23-B. This action was filed by Exxon to interplead royalty funds as a result of a title controversy between certain mineral owners in a field in Florida. One group of mineral owners, John W. Hughes, et al. (the "Hughes Group"), filed a counterclaim against Exxon alleging fraud, conspiracy, conversion of funds, declaratory relief, federal and Florida RICO, breach of contract and accounting, as well as challenging the validity of certain oil and natural gas leases owned by Exxon, and seeking exemplary and treble damages. In March 1993, but effective November 1, 1992, Calumet Florida Inc. ("Calumet"), our wholly owned subsidiary, acquired all of Exxon's leases in the field affected by this lawsuit. In order to address those counterclaims challenging the validity of certain oil and natural gas leases, which constitute approximately 10% of the land underlying this unitized field, Calumet filed a motion to join Exxon as plaintiff in the subject lawsuit, which was granted July 29, 1994. In August 1994, the Hughes Group amended its counterclaim to add Calumet as a counter-defendant. Exxon and Calumet filed a motion to dismiss the counterclaims. On March 22, 1996, the Court granted Exxon's and Calumet's motion to dismiss the counterclaims alleging fraud, conspiracy, and federal and Florida RICO violations and challenging the validity of certain of our oil and natural gas leases but denied such motion as to the counterclaim alleging conversion of funds. Effective January 1, 2000, Calumet settled all of the Hughes claims against Calumet with a payment to the Hughes group of the total sum of $100,000. The remaining defendants filed a writ seeking to stay the trial but no relief was granted prior to the trial date. Trial was held on June 19, 2000. By final judgment dated August 18, 2000, the court dismissed all claims by the Hughes group and the remaining defendants against Calumet. The remaining defendants have appealed the judgment. We, in the ordinary course of business, are a claimant and/or a defendant in various other legal proceedings. Management does not believe that the outcome of these other legal proceedings, individually and in the aggregate, will have a materially adverse effect on our financial condition or results of operations. ITEMS 2, 3, 4 & 5 ARE NOT APPLICABLE AND HAVE BEEN OMITTED Item 6 - Exhibits and Reports on Form 8-K A. Exhibits 10.1 Seventh Amendment to Fourth Amended and Restated Credit Agreement, dated as of October 11, 2000 by and among Plains Resources Inc., First Union National Bank as Agent and the Lenders named therein. 27.1 Financial Data Schedule B. Reports on Form 8-K A Current Report on Form 8-K was filed on September 15, 2000, in connection with the announcement that Plains All American Pipeline, L.P. and Plains Resources Inc. had agreed in principle for the settlement of class action securities suits related to the unauthorized trading losses disclosed in November 1999. 36 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: January 18, 2001 By: /s/ Cynthia A. Feeback ---------------------- Cynthia A. Feeback, Vice President - Accounting and Assistant Treasurer (Principal Accounting Officer) 37